Vol. 76 Monday, 

No. 54 March 21, 2011 

Part IV 

Environmental Protection Agency 

40 CFR Part 63 

National Emission Standards for Hazardous Air Pollutants for Area 

Sources: Industrial, Commercial, and Institutional Boilers; Final Rule 


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15554 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2006–0790; FRL–9273–5] 

RIN 2060–AM44 

National Emission Standards for 

Hazardous Air Pollutants for Area 

Sources: Industrial, Commercial, and 

Institutional Boilers 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is promulgating national 

emission standards for control of 

hazardous air pollutants from two area 

source categories: Industrial boilers and 

commercial and institutional boilers. 

The final emission standards for control 

of mercury and polycyclic organic 

matter emissions from coal-fired area 

source boilers are based on the 

maximum achievable control 

technology. The final emission 

standards for control of hazardous air 

pollutants emissions from biomass-fired 

and oil-fired area source boilers are 

based on EPA’s determination as to 

what constitutes the generally available 

control technology or management 

practices. 

DATES: Effective Date: This final rule is 

effective on May 20, 2011. The 

incorporation by reference of certain 

publications listed in this final rule 

were approved by the Director of the 

Federal Register as of May 20, 2011. 

ADDRESSES: EPA established a docket 

under Docket ID No. EPA–HQ–OAR– 

2006–0790 for this action. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard 

copy at EPA’s Docket Center, Public 

Reading Room, EPA West Building, 

Room 3334, 1301 Constitution Ave., 

NW., Washington, DC. This Docket 

Facility is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

James Eddinger, Energy Strategies 

Group, Sector Policies and Programs 

Division, (D243–01), Office of Air 

Quality Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; Telephone number: (919) 541– 

5426; Fax number (919) 541–5450; email address: eddinger.jim@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

Btu British thermal unit 

CAA Clean Air Act 

CBI Confidential Business Information 

CEMS Continuous Emission Monitoring 

System 

CFR Code of Federal Regulations 

CO Carbon monoxide 

ERT Electronic Reporting Tool 

FR Federal Register 

GACT Generally Available Control 

Technology 

HAP Hazardous Air Pollutant 

HCl Hydrogen chloride 

ICR Information Collection Request 

kWh Kilowatt hour 

MACT Maximum Achievable Control 

Technology 

MMBtu/h Million Btu per hour 

NAICS North American Industry 

Classification System 

NESHAP National Emission Standards for 

Hazardous Air Pollutants 

NOX Nitrogen oxides 

NSPS New Source Performance Standards 

PM Particulate matter 

PM2.5 Fine particulate matter 

POM Polycyclic organic matter 

ppm Parts per million 

RCRA Resource Conservation and Recovery 

Act 

TBtu Trillion British thermal units 

tpy Tons per year 

SO2 Sulfur dioxide 

UPL Upper Prediction limit 

VOC Volatile organic compound 

Organization of This Document. The 

information 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 

A. What is the statutory authority and 

regulatory approach for this final rule? 

B. What source categories are affected by 

the standards? 

C. What is the relationship between this 

rule and other related national emission 

standards? 

D. How did we gather information for this 

rule? 

E. How are the area source boiler HAP 

addressed by this rule? 

F. What are the costs and benefits of this 

final rule? 

III. Summary of This Final Rule 

A. Do these standards apply to my source? 

B. What is the affected source? 

C. When must I comply with the final 

standards? 

D. What are the MACT and GACT 

standards? 

E. What are the Startup, Shutdown, and 

Malfunction (SSM) requirements? 

F. What are the initial compliance 

requirements? 

G. What are the continuous compliance 

requirements? 

H. What are the notification, recordkeeping 

and reporting requirements? 

I. Submission of Emissions Test Results to 

EPA 

IV. Summary of Significant Changes 

Following Proposal 

A. Changes to Subcategories 

B. Change From MACT to GACT for 

Biomass and Oil Subcategories 

C. MACT Floor UPL Methodology/ 

Emission Limits 

D. Clarification of Energy Assessment 

Requirements 

E. Revised Subcategory Limits 

F. Demonstrating Compliance 

G. Affirmative Defense 

H. Technical/Editorial Corrections 

V. Significant Area Source Public Comments 

and Rationale for Changes to Proposed 

Rule 

A. Legal and Applicability Issues 

B. CO Limits 

C. MACT Floor Analysis 

D. Beyond the Floor Analysis 

E. GACT Standards 

F. Subcategories 

G. Startup, Shutdown, and Malfunction 

H. Compliance Requirements 

I. Cost/Economic Impacts 

J. Title V Permitting Requirements 

VI. Relationship of this Action to CAA 

Section 112(c)(6) 

VII. Summary of the Impacts of This Final 

Rule 

A. What are the air impacts? 

B. What are the cost impacts? 

C. What are the economic impacts? 

D. What are the benefits? 

E. What are the water and solid waste 

impacts? 

F. What are the energy impacts? 

VIII. Statutory and Executive Order Review 

A. Executive Order 12866 and 13563: 

Regulatory Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act, as Amended 

by the Small Business Regulatory 

Enforcement Fairness Act of 1996 

D. Unfunded Mandates Reform Act of 1995 

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 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15555 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by the final 

standards include: 

Category NAICS 

code 1 Examples of regulated entities 

Any area source facility using a boiler as defined in this proposed rule .................................................... 321 Wood product manufacturing. 

11 Agriculture, greenhouses. 

311 Food manufacturing. 

327 Nonmetallic mineral product 

manufacturing. 

424 Wholesale trade, nondurable 

goods. 

531 Real estate. 

611 Educational services. 

813 Religious, civic, professional, 

and similar organizations. 

92 Public administration. 

722 Food services and drinking 

places. 

62 Health care and social assistance. 

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 

affected by this action. To determine 

whether your facility, company, 

business, organization, etc., is regulated 

by this action, you should examine the 

applicability criteria in 40 CFR 63.11193 

of subpart JJJJJJ (National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers Area Sources). If 

you have any questions regarding the 

applicability of this action to a 

particular entity, consult either the 

delegated regulatory authority for the 

entity or your EPA regional 

representative as listed in 40 CFR 63.13 

of subpart A (General Provisions). 

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 will also be available on the 

Worldwide Web (WWW) through the 

Technology Transfer Network (TTN). 

Following signature, a copy of the final 

action will be posted on the TTN’s 

policy and guidance page for newly 

proposed or promulgated rules at the 

following address: 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 CAA, 

judicial review of this final rule is 

available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit (the 

Court) by May 20, 2011. Under CAA 

section 307(d)(7)(B), only an objection 

to this final rule that was raised with 

reasonable specificity during the period 

for public comment can be raised during 

judicial review. CAA section 

307(d)(7)(B) also provides a mechanism 

for EPA 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, Environmental 

Protection Agency, Room 3000, Ariel 

Rios Building, 1200 Pennsylvania Ave., 

NW., Washington, DC 20460, with a 

copy to the person listed in the 

preceding FOR FURTHER GENERAL

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), 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. 

II. Background Information 

A. What is the statutory authority and 

regulatory approach for this final rule? 

Section 112(d) of the CAA requires us 

to establish NESHAP for both major and 

area sources of HAP that are listed for 

regulation under CAA section 112(c). A 

major source emits or has the potential 

to emit 10 tpy or more of any single 

HAP or 25 tpy or more of any 

combination of HAP. An area source is 

a HAP-emitting stationary source that is 

not a major source. 

Section 112(k)(3)(B) of the CAA calls 

for EPA to identify at least 30 HAP 

which, as the result of emissions from 

area sources, pose the greatest threat to 

public health in the largest number of 

urban areas. EPA implemented this 

provision in 1999 in the Integrated 

Urban Air Toxics Strategy (Strategy), (64 

FR 38715, July 19, 1999). Specifically, 

in the Strategy, EPA identified 30 HAP 

that pose the greatest potential health 

threat in urban areas, and these HAP are 

referred to as the ‘‘30 urban HAP.’’ CAA 

section 112(c)(3) requires EPA to list 

sufficient categories or subcategories of 

area sources to ensure that area sources 

representing 90 percent of the emissions 

of the 30 urban HAP are subject to 

regulation. A primary goal of the 

Strategy is to achieve a 75 percent 

reduction in cancer incidence 

attributable to HAP emitted from 

stationary sources. 

Under CAA section 112(d)(5), we may 

elect to promulgate standards or 

requirements for area sources ‘‘which 

provide for the use of generally 


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available control technologies [‘‘GACT’’] 

or management practices by such 

sources to reduce emissions of 

hazardous air pollutants.’’ Additional 

information on GACT is found in the 

Senate report on the legislation (Senate 

Report Number 101–228, December 20, 

1989), which describes GACT as: 

* * * methods, practices and techniques 

which are commercially available and 

appropriate for application by the sources in 

the category considering economic impacts 

and the technical capabilities of the firms to 

operate and maintain the emissions control 

systems. 

Consistent with the legislative history, 

we can consider costs and economic 

impacts in determining GACT, which is 

particularly important when developing 

regulations for source categories that 

may have many small businesses such 

as these. 

Determining what constitutes GACT 

involves considering the control 

technologies and management practices 

that are generally available to the area 

sources in the source category. We also 

consider the standards applicable to 

major sources in the analogous source 

category to determine if the control 

technologies and management practices 

are transferable and generally available 

to area sources. In appropriate 

circumstances, we may also consider 

technologies and practices at area and 

major sources in similar categories to 

determine whether such technologies 

and practices could be considered 

generally available for the area source 

categories at issue. Finally, as noted 

above, in determining GACT for a 

particular area source category, we 

consider the costs and economic 

impacts of available control 

technologies and management practices 

on that category. 

While GACT may be a basis for 

standards for most types of HAP emitted 

from area sources, CAA section 

112(c)(6) requires that EPA list 

categories and subcategories of sources 

assuring that sources accounting for not 

less than 90 percent of the aggregate 

emissions of each of seven specified 

HAP are subject to standards under 

CAA sections 112(d)(2) or (d)(4), which 

require the application of the more 

stringent MACT. The seven HAP 

specified in CAA section 112(c)(6) are as 

follows: Alkylated lead compounds, 

POM, hexachlorobenzene, mercury, 

polychlorinated biphenyls (PCBs), 

2,3,7,8-tetrachlorodibenzofurans, and 

2,3,7,8-tetrachlorodibenzo-p-dioxin. 

The CAA section 112(c)(6) list of 

source categories currently includes 

industrial coal combustion, industrial 

oil combustion, industrial wood 

combustion, commercial coal 

combustion, commercial oil 

combustion, and commercial wood 

combustion. (See 63 FR 17849, April 10, 

1998.) We listed these source categories 

under CAA section 112(c)(6) based on 

the source categories’ contribution of 

mercury and POM. In the 

documentation for the CAA section 

112(c)(6) listing, the commercial fuel 

combustion categories included 

institutional fuel combustion. (See 

‘‘1990 Emissions Inventory of Section 

112(c)(6) Pollutants, Final Report,’’ April 

1998.) As discussed in the preamble to 

the proposed rule, we concluded we 

only needed to address mercury 

emissions from the coal-fueled portion 

of these categories in order to ensure 

that 90 percent of the aggregate 

emissions of mercury would be subject 

to standards under CAA sections 

112(d)(2) or 112(d)(4). (See 75 FR 31898, 

June 4, 2010.) As discussed in this 

preamble, based on public comments 

received, we re-examined the emission 

inventory and the need to address POM 

emissions from the area source 

subcategories to meet the CAA section 

112(c)(6) 90 percent requirement, and 

concluded we only need to address 

POM emissions from the coal-fueled 

portion of these categories under CAA 

section 112(d)(2) or 112(d)(4). 

With this final rule and the major 

source boilers rule, we believe that we 

have subjected to regulation at least 90 

percent of the CAA section 112(c)(6) 

1990 emissions inventory for mercury 

and POM. Consequently, we are 

regulating coal-fired area source boilers 

under MACT because we need these 

sources to meet the 90 percent 

requirement for mercury and POM in 

CAA section 112(c)(6). 

The ‘‘MACT’’ required by CAA 

sections 112(d)(2) or 112(d)(4) can be 

based on the emissions reductions 

achievable through application of 

measures, processes, methods, systems, 

or techniques including, but not limited 

to: (1) Reducing the volume of, or 

eliminating emissions of, such 

pollutants through process changes, 

substitutions of materials, or other 

modifications; (2) enclosing systems or 

processes to eliminate emissions; (3) 

collecting, capturing, or treating such 

pollutants when released from a 

process, stack, storage or fugitive 

emission point; (4) design, equipment, 

work practices, or operational standards 

as provided in CAA section 112(h); or 

(5) a combination of the above. 

The MACT floor is the minimum 

control level allowed for NESHAP and 

is defined under CAA section 112(d)(3). 

For new sources, MACT based 

standards cannot be less stringent than 

the emission control achieved in 

practice by the best-controlled similar 

source, as determined by the 

Administrator. The MACT based 

standards for existing sources can be 

less stringent than standards for new 

sources, but they cannot be less 

stringent than the average emission 

limitation achieved by the best 

performing 12 percent of existing 

sources in the category or subcategory 

(for which the Administrator has 

emission information) for source 

categories and subcategories with 30 or 

more sources, or the best performing 5 

sources for categories and subcategories 

with fewer than 30 sources (CAA 

section 112(d)(3)(A) and (B)). 

Although emission standards are 

often structured in terms of numerical 

emissions limits, alternative approaches 

are sometimes necessary and authorized 

pursuant to CAA section 112. For 

example, in some cases, physically 

measuring emissions from a source may 

not be practicable due to technological 

and economic limitations. Section 

112(h) of the CAA authorizes the 

Administrator to promulgate a design, 

equipment, work practice, or 

operational standard, or combination 

thereof, consistent with the provisions 

of CAA sections 112(d) or (f), in those 

cases where, in the judgment of the 

Administrator, it is not feasible to 

prescribe or enforce an emission 

standard. Section 112(h)(2) of the CAA 

provides that the phrase ‘‘not feasible to 

prescribe or enforce an emission 

standard’’ includes ‘‘the situation in 

which the Administrator determines 

that * * * the application of 

measurement methodology to a 

particular class of sources is not 

practicable due to technological and 

economic limitations.’’ 

As noted above in this section of the 

preamble, we listed industrial coal 

combustion, industrial oil combustion, 

industrial wood combustion, 

commercial coal combustion, 

commercial oil combustion, and 

commercial wood combustion under 

CAA section 112(c)(6) based on the 

source categories’ contribution of 

mercury and POM. We listed these same 

categories under CAA section 112(c)(3) 

for their contribution of mercury, 

arsenic, beryllium, cadmium, lead, 

chromium, manganese, nickel, POM (as 

7-PAH (polynuclear aromatic 

hydrocarbons)), ethylene dioxide, and 

PCBs. 

We have developed final standards to 

reflect the application of MACT for 

mercury and POM from coal-fired area 

source boilers and have applied GACT 

for the urban HAP noted above for 

boilers firing other fuels and for urban 


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HAP (other than mercury and POM) 

from coal-fired area source boilers. 

B. What source categories are affected 

by the standards? 

The source categories affected by the 

standards are industrial boilers and 

commercial and institutional boilers. 

Both source categories were included in 

the area source list published on July 

19, 1999 (64 FR 38721). The inclusion 

of these two source categories on the 

CAA section 112(c)(3) area source 

category list is based on 1990 emissions 

data, as EPA used 1990 as the baseline 

year for that listing. We describe above 

in Section II.A of this preamble the 

pollutants that formed the basis of the 

listings. 

This rule applies to all existing and 

new industrial boilers, institutional 

boilers, and commercial boilers located 

at area sources. Boiler means an 

enclosed combustion device having the 

primary purpose of recovering thermal 

energy in the form of steam or hot water. 

The industrial boiler source category 

includes boilers used in manufacturing, 

processing, mining, refining, or any 

other industry. The commercial boiler 

source category includes boilers used in 

commercial establishments such as 

stores/malls, laundries, apartments, 

restaurants, and hotels/motels. The 

institutional boiler source category 

includes boilers used in medical centers 

(e.g., hospitals, clinics, nursing homes), 

educational and religious facilities (e.g., 

schools, universities, churches), and 

municipal buildings (e.g., courthouses, 

prisons). 

C. What is the relationship between this 

rule and other related national emission 

standards? 

This rule regulates industrial boilers 

and institutional/commercial boilers 

that are located at area sources of HAP. 

Today, in a parallel action, a NESHAP 

for industrial, commercial, and 

institutional boilers and process heaters 

located at major sources is being 

promulgated reflecting the application 

of MACT. The major source NESHAP 

regulates emissions of PM (as a 

surrogate for non-mercury metals), 

mercury, HCl (as a surrogate for acid 

gases), dioxins/furans, and CO (as a 

surrogate for non-dioxin organic HAP) 

from existing and new major source 

boilers. 

This rule covers boilers located at area 

source facilities. In addition to the major 

source MACT for boilers being issued 

today, the Agency is also issuing 

emission standards today pursuant to 

CAA section 129 for commercial and 

industrial solid waste incineration 

units. In a parallel action, EPA is 

finalizing a solid waste definition 

rulemaking pursuant to subtitle D of 

RCRA. That action is relevant to this 

proceeding because if an industrial, 

commercial, or institutional boiler 

located at an area source combusts 

secondary materials that are ‘‘solid 

waste,’’ as that term is defined by the 

Administrator under RCRA, those 

boilers would be subject to section 129 

of the CAA, not section 112. 

As background, in 2007, the United 

States Court of Appeals for the District 

of Columbia Circuit (DC Circuit) vacated 

the ‘‘CISWI Definitions Rule’’ (70 FR 

55568, September 22, 2005), which 

amended the definitions of ‘‘commercial 

and industrial solid waste incinerator 

(CISWI),’’ ‘‘commercial or industrial 

waste,’’ and ‘‘solid waste’’ in 40 CFR 60, 

subparts CCCC and DDDD, and which 

EPA issued pursuant to CAA section 

129. The Court found that the 

definitions in that rule were 

inconsistent with the CAA. Specifically, 

the Court held that the term ‘‘solid waste 

incineration unit’’ in CAA section 

129(g)(1) ‘‘unambiguously include[s] 

among the incineration units subject to 

its standards any facility that combusts 

any commercial or industrial solid 

waste material at all—subject to the four 

statutory exceptions identified [in CAA 

section 129(g)(1)].’’ NRDC v. EPA, 489 

F.3d at 1257–58. 

Based on the information available to 

the Agency, we determined that the 

boilers that are subject to this area 

source rule combust predominantly 

coal, oil, or biomass. We have further 

determined that the boilers subject to 

this rule may combust non-hazardous 

secondary materials that do not meet the 

definition of ‘‘solid waste’’ pursuant to 

the rulemaking of subtitle D of RCRA. A 

boiler located at an area source burning 

any secondary materials considered 

‘‘solid waste’’ would be considered a 

solid waste incineration unit subject to 

regulation under CAA section 129. In 

the final area source boiler rulemaking, 

EPA is providing specific language to 

ensure clarity regarding the necessary 

steps that must be followed for 

combustion units that begin combusting 

non-hazardous solid waste materials 

and become subject to section 129 

standards instead of section 112 

standards or combustion units that 

discontinue combustion of nonhazardous solid waste materials and 

become subject to section 112 standards 

instead of section 129 standards. 

Some of the affected sources subject 

to this rule may also be subject to the 

NSPS for industrial, commercial, and 

institutional boilers (40 CFR part 60, 

subparts Db and Dc). EPA codified these 

NSPS in 1986, and revised portions of 

them in 1999 and 2006. The two NSPS 

regulate emissions of PM, SO2, and NOX

from boilers constructed after June 19, 

1984. Sources subject to the NSPS that 

are located at area source facilities are 

also subject to this rule because this rule 

regulates HAP. In developing this rule, 

we have streamlined the monitoring and 

recordkeeping requirements to avoid 

duplicating requirements in the NSPS. 

D. How did we gather information for 

this rule? 

We gathered information for this rule 

from states’ boiler inspection lists, 

company Web sites, published 

literature, state permits, current state 

and federal regulations, and from an ICR 

conducted for the major source 

NESHAP. After proposal, we received 

additional emission test reports during 

the public comment period. 

We developed an initial nationwide 

population of area source boilers based 

on boiler inspector data-bases from 13 

states. The boiler inspector data-bases 

include steam boilers that are required 

to be inspected for safety or insurance 

purposes. We classified the area source 

boilers to NAICS codes based on the 

‘‘name’’ of the facility at which the boiler 

was located. However, many of the 

boilers in the boiler inspector data-base 

could not be readily assigned to an 

NAICS code and, thus, we did not 

categorize them. 

We reviewed state and other federal 

regulations that apply to the area 

sources in the source categories for 

information concerning existing HAP 

emission control approaches. For 

example, as noted above, the NSPS for 

small industrial, commercial, and 

institutional boilers in 40 CFR part 60, 

subpart Dc apply to boilers at some area 

sources. Similarly, permit requirements 

established by the Ohio, Illinois, 

Vermont, New Hampshire, and Maine 

air regulatory agencies apply to some 

area sources. We also reviewed 

standards for boilers at major sources 

that would be appropriate for and 

transferable to boilers at area sources. 

For example, we determined that 

management practices, such as, tuneups and operator training applicable to 

major source boilers are also feasible for 

boilers at area sources. 


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1 In National Lime Ass’n v. EPA, 233 F. 3d 625, 

633 (DC Cir. 2000), the court upheld EPA’s use of 

particulate matter as a surrogate for HAP metals. 

E. How are the area source boiler HAP 

addressed by this rule? 

As explained in Section II.A of this 

preamble, industrial coal combustion, 

industrial oil combustion, industrial 

wood combustion, commercial coal 

combustion, commercial oil 

combustion, and commercial wood 

combustion are listed under CAA 

section 112(c)(6) due to contributions of 

mercury and POM and these same 

categories are listed under CAA section 

112(c)(3) for their contribution of 

mercury, arsenic, beryllium, cadmium, 

lead, chromium, manganese, nickel, 

POM, ethylene dioxide, and PCB. 

With respect to the CAA section 

112(c)(3) pollutants, we used surrogates 

because, as explained in this section of 

the preamble, it was not practical to 

establish individual standards for each 

specific HAP. We grouped the CAA 

section 112(c)(3) pollutants, which 

formed the basis for the listing of these 

two source categories, into three 

common groupings: Mercury, nonmercury metallic HAP (arsenic, 

beryllium, cadmium, chromium, lead, 

manganese, and nickel), and organic 

HAP (POM, ethylene dichloride, and 

PCB). In general, the pollutants within 

each group have similar characteristics 

and can be controlled with the same 

techniques. 

For the non-mercury metallic HAP, 

we selected PM as a surrogate. The 

inherent variability and unpredictability 

of the non-mercury metal HAP 

compositions and amounts in fuel has a 

material effect on the composition and 

amount of non-mercury metal HAP in 

the emissions from the boiler. As a 

result, establishing individual 

numerical emissions limits for each 

non-mercury HAP metal species is 

difficult given the level of uncertainty 

about the individual non-mercury metal 

HAP compositions of the fuels that will 

be combusted. An emission 

characteristic common to all boilers is 

that the non-mercury metal HAP are a 

component of the PM contained in the 

fly ash emitted from the boiler. A 

sufficient correlation exists between PM 

and non-mercury metallic HAP to rely 

on PM as a surrogate for these HAP and 

for their control.1 Therefore, the same 

control techniques that would be used 

to control the fly-ash PM will control 

non-mercury metallic HAP. Emissions 

limits established to achieve control of 

PM will also achieve control of nonmercury metallic HAP. Furthermore, 

establishing separate standards for each 

individual HAP would impose costly 

and significantly more complex 

compliance and monitoring 

requirements and achieve little, if any, 

HAP emissions reductions beyond what 

would be achieved using the surrogate 

pollutant approach. 

For organic urban HAP, we selected 

CO as a surrogate for organic 

compounds, including POM, emitted 

from the various fuels burned in boilers. 

The presence of CO is an indicator of 

incomplete combustion. A high level of 

CO in emissions is a potential 

indication of elevated organic HAP 

emissions because organic HAP, like 

CO, are formed as a byproduct of 

combustion, and both would increase 

with an increase in the level of 

incomplete combustion. Monitoring 

equipment for CO is readily available, 

which is not the case for organic HAP. 

Also, it is significantly easier and less 

expensive to measure and monitor CO 

emissions than to measure and monitor 

emissions of each individual organic 

HAP. We considered other surrogates, 

such as total hydrocarbon (THC), but 

lacked data on emissions and permit 

limits for area source boilers. Therefore, 

using CO as a surrogate for organic 

urban HAP is a reasonable approach 

because minimizing CO emissions will 

result in minimizing organic urban HAP 

emissions. 

Based on these considerations, we are 

promulgating GACT standards for PM 

(as a surrogate for the individual urban 

metal HAP) for coal, biomass, and oilfired boilers and CO (as a surrogate 

pollutant for the individual urban 

organic HAP) for biomass-fired and oilfired boilers. We are also establishing 

MACT standards for mercury and for 

POM (using CO as a surrogate pollutant) 

for coal-fired boilers. The MACT 

standard for POM from coal-fired boilers 

would also be GACT for urban organic 

HAP other than POM. 

F. What are the costs and benefits of this 

final rule? 

EPA estimated the costs and benefits 

associated with the final rule, and the 

results are shown in the following table. 

For more information on the costs and 

benefits for this rule, see the Regulatory 

Impact Analysis (RIA). 

SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER AREA SOURCE RULE

IN 2014 

[Millions of 2008$] 1

3% Discount rate 7% Discount rate 

Final MACT/GACT Approach: Selected 

Total Monetized Benefits 2 ........................................................ $210 to $520 ........................................................................... $190 to $470 

Total Social Costs 3 .................................................................. $490 ......................................................................................... $490 

Net Benefits .............................................................................. ¥$280 to $30 .......................................................................... ¥$300 to ¥$20 

1,100 tons of carbon monoxide 

340 tons of HCl 

8 tons of HF 

90 pounds of mercury 

Non-monetized Benefits; .......................................................... 320 tons of other metals 

< 1 gram of dioxins/furans (TEQ) 

Health effects from SO2 exposure 

Ecosystem effects 

Visibility impairment 

Proposed MACT Approach: Alternative 

Total Monetized Benefits 2 ........................................................ $200 to $490 ........................................................................... $180 to $440 

Total Social Costs 3 .................................................................. $850 ......................................................................................... $850 


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SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER AREA SOURCE RULE

IN 2014—Continued 

[Millions of 2008$] 1

3% Discount rate 7% Discount rate 

Net Benefits .............................................................................. ¥$650 to ¥$360 .................................................................... ¥$670 to ¥$410 

Non-monetized Benefits ........................................................... 1,100 tons of carbon monoxide 

340 tons of HCl 

8 tons of HF 

90 pounds of mercury 

320 tons of other metals 

<1 gram of dioxins/furans (TEQ) 

Health effects from SO2 exposure 

Ecosystem effects 

Visibility impairment 

1All estimates are for the implementation year (2014), and are rounded to two significant figures. These results include units anticipated to 

come online and the lowest cost disposal assumption. 2The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of directly emitted PM2.5 and PM2.5 precursors such as SO2. It is important to note that the monetized benefits include many but not all health effects associated 

with PM2.5 exposure. Benefits are shown as a range from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that 

would support the development of differential effects estimates by particle type. These estimates include energy disbenefits valued at less than 

$1 million. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 

III. Summary of This Final Rule 

A. Do these standards apply to my 

source? 

This rule applies to you if you own 

or operate a boiler combusting solid 

fossil fuels, biomass, or liquid fuels 

located at an area source. The standards 

do not apply to boilers that are subject 

to another standard under 40 CFR part 

63 or to a standard developed under 

CAA section 129. 

This rule applies to you if you own 

or operate a boiler combusting natural 

gas, located at an area source, which 

switches to combusting solid fossil 

fuels, biomass, or liquid fuel after June 

4, 2010. 

B. What is the affected source? 

This final rule affects industrial 

boilers, institutional boilers, and 

commercial boilers. The affected source 

is the collection of all existing boilers 

within a subcategory located at an area 

source facility or each new boiler 

located at an area source facility. 

C. When must I comply with these 

standards? 

The owner or operator of an existing 

source subject to a work practice or 

management practice standard of a tuneup is required to comply with this final 

rule no later than March 21, 2012. The 

owner or operator of an existing source 

subject to emission limits or an energy 

assessment requirement is required to 

comply with this final rule no later than 

March 21, 2014. The owner or operator 

of a new source is required to comply 

on May 20, 2011 or upon startup of the 

facility, whichever is later. Owners and 

operators subject to 40 part CFR 60, 

subpart CCCC or subpart DDDD who 

cease combusting solid waste must be in 

compliance with this subpart on the 

effective date that the unit ceased 

combusting solid waste, consistent with 

40 CFR part 60, subpart CCCC or 

subpart DDDD. 

D. What are the MACT and GACT 

standards? 

Emission standards are in the form of 

numerical emission limits for new and 

existing area source boilers. The MACT 

emission limits for mercury and CO (as 

a surrogate for POM) are presented, 

along with the GACT emission limits for 

PM (as a surrogate for urban metals), in 

Table 1 of this preamble. The units are 

pounds of PM or mercury per million 

British thermal units (lb/MMBtu) and 

ppm for CO. 

TABLE 1—EMISSION LIMITS FOR AREA SOURCE BOILERS

Subcategory Heat input 

(MMBtu/h) Pollutants Emission limits 

New coal-fired boiler ...................................... ≥30 a. Particulate Matter ..................................... 0.03 lb per MMBtu of heat input. 

b. Mercury ..................................................... 0.0000048 lb per MMBtu of heat 

input. 

c. Carbon Monoxide ..................................... 400 ppm by volume on a dry basis 

corrected to 3 percent oxygen. 

≥10 and <30 a. Particulate Matter ..................................... 0.42 lb per MMBtu of heat input. 

b. Mercury ..................................................... 0.0000048 lb per MMBtu of heat 

input. 

c. Carbon Monoxide ..................................... 400 ppm by volume on a dry basis 

corrected to 3 percent oxygen. 

New biomass-fired boiler ............................... ≥30 Particulate Matter .......................................... 0.03 lb per MMBtu of heat input. 

≥10 and <30 Particulate Matter .......................................... 0.07 lb per MMBtu of heat input. 

New oil-fired boiler ......................................... ≥30 Particulate Matter .......................................... 0.03 lb per MMBtu of heat input. 

≥10 and <30 Particulate Matter .......................................... 0.03 lb per MMBtu of heat input. 

Existing coal-Fired boiler ............................... ≥10 a. Mercury ..................................................... 0.0000048 lb per MMBtu of heat 

input. 


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TABLE 1—EMISSION LIMITS FOR AREA SOURCE BOILERS—Continued 

Subcategory Heat input 

(MMBtu/h) Pollutants Emission limits 

b. Carbon Monoxide ..................................... 400 ppm by volume on a dry basis 

corrected to 7 percent oxygen. 

The emission limits for PM apply 

only to new boilers. The emission limits 

for mercury and CO apply only to 

boilers in the coal subcategory; the 

emission limits for existing area source 

boilers in the coal subcategory are 

applicable only to area source boilers 

that have a designed heat input capacity 

of 10 million MMBtu/h or greater. 

If your boiler burns any solid fossil 

fuel and no more than 15 percent 

biomass on a total fuel annual heat 

input basis, the boiler is in the coal 

subcategory. If your boiler burns at least 

15 percent biomass on a total fuel 

annual heat input basis, the unit is in 

the biomass subcategory. If your boiler 

burns any liquid fuel and is not in either 

the coal or the biomass subcategory, the 

unit is in the oil subcategory, except if 

the unit burns oil only during periods 

of gas curtailment. 

As allowed under CAA section 

112(h), a work practice standard is being 

promulgated for new and existing coalfired area source boilers with a designed 

heat input capacity of less than 10 

MMBtu/h. The work practice standard 

for new and existing coal-fired area 

source boilers requires the 

implementation of a tune-up program. 

We are also requiring all biomass-fired 

and oil-fired area source boilers to 

implement a tune-up program as a 

management practice. 

An additional standard is being 

promulgated for existing area source 

facilities having an affected boiler with 

a designed heat input capacity of 10 

MMBtu/h or greater that requires the 

performance of an energy assessment, 

by qualified personnel, on the boiler 

and its energy use systems to identify 

cost-effective energy conservation 

measures. 

E. What are the startup, shutdown, and 

malfunction (SSM) requirements? 

The United States Court of Appeals 

for the District of Columbia Circuit 

vacated portions of two provisions in 

EPA’s CAA section 112 regulations 

governing the emissions of HAP during 

periods of startup, shutdown, and 

malfunction (SSM). Sierra Club v. EPA, 

551 F.3d 1019 (DC Cir. 2008), cert. 

denied, 130 S. Ct. 1735 (U.S. 2010). 

Specifically, the Court vacated the SSM 

exemption contained in 40 CFR 

63.6(f)(1) and 40 CFR 63.6(h)(1), that are 

part of a regulation, commonly referred 

to as the ‘‘General Provisions Rule’’ (40 

CFR 63, subpart A), that EPA 

promulgated under CAA section 112 of 

the CAA. When incorporated into CAA 

section 112(d) regulations for specific 

source categories, these two provisions 

exempted sources from the requirement 

to comply with the otherwise applicable 

CAA section 112(d) emission standard 

during periods of SSM. 

Consistent with Sierra Club v. EPA, 

EPA has established standards in this 

rule that apply at all times. EPA has 

attempted to ensure that we have not 

incorporated into the regulatory 

language any provisions that are 

inappropriate, unnecessary, or 

redundant in the absence of an SSM 

exemption. 

In establishing the standards in this 

rule, EPA has taken into account startup 

and shutdown periods and, for the 

reasons explained below, has 

established different standards for those 

periods. 

EPA has revised this final rule to 

require sources to meet a work practice 

standard, including following the 

manufacturer’s recommended 

procedures for minimizing startup and 

shutdown periods, to demonstrate 

compliance with the emission limits for 

all subcategories of new and existing 

area source boilers (that would 

otherwise be subject to numeric 

emission limits) during periods of 

startup and shutdown. As discussed in 

Section V.G of this preamble, we 

considered whether performance 

testing, and therefore, enforcement of 

numeric emission limits, would be 

practicable during periods of startup 

and shutdown. With regards to 

performance testing, EPA determined 

that it is not technically feasible to 

complete stack testing—in particular, to 

repeat the multiple required test runs— 

during periods of startup and shutdown 

due to physical limitations and the short 

duration of startup and shutdown 

periods. Operating in startup and 

shutdown mode for sufficient time to 

conduct the required test runs could 

result in higher emissions than would 

otherwise occur. Based on these specific 

facts for the boilers and process heater 

source category, EPA has developed a 

separate standard for these periods, and 

we are finalizing work practice 

standards to meet this requirement. The 

work practice standard requires sources 

to minimize periods of startup and 

shutdown following the manufacturer’s 

recommended procedures, if available. 

If manufacturer’s recommended 

procedures are not available, sources 

must follow recommended procedures 

for a unit of similar design for which 

manufacturer’s recommended 

procedures are available. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner * * *’’ (40 CFR 63.2). EPA has 

determined that malfunctions should 

not be viewed as a distinct operating 

mode and, therefore, any emissions that 

occur at such times do not need to be 

factored into development of CAA 

section 112(d) standards, which, once 

promulgated, apply at all times. In 

Mossville Environmental Action Now v. 

EPA, 370 F.3d 1232, 1242 (DC Cir. 

2004), the court upheld as reasonable 

standards that had factored in 

variability of emissions under all 

operating conditions. However, nothing 

in section 112(d) or in case law requires 

that EPA anticipate and account for the 

innumerable types of potential 

malfunction events in setting emission 

standards. See, Weyerhaeuser v. Costle, 

590 F.2d 1011, 1058 (DC Cir. 1978) (‘‘In 

the nature of things, no general limit, 

individual permit, or even any upset 

provision can anticipate all upset 

situations. After a certain point, the 

transgression of regulatory limits caused 

by ‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase enforcement discretion, not for 

specification in advance by 

regulation.’’). 

Further, it is reasonable to interpret 

CAA section 112(d) as not requiring 

EPA to account for malfunctions in 

setting emissions standards. For 

example, we note that CAA section 112 

uses the concept of ‘‘best performing’’ 

sources in defining MACT, the level of 


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stringency that major source standards 

must meet. Applying the concept of 

‘‘best performing’’ to a source that is 

malfunctioning presents significant 

difficulties. The goal of best performing 

sources is to operate in such a way as 

to avoid malfunctions of their units. 

Similarly, although standards for area 

sources are generally not required to be 

set based on ‘‘best performers,’’ we 

believe that what is ‘‘generally available’’ 

should not be based on periods in 

which there is a ‘‘failure to operate.’’ 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 112(d) standards for 

area source boilers. As noted above, by 

definition, malfunctions are sudden and 

unexpected events and it would be 

difficult to set a standard that takes into 

account the myriad different types of 

malfunctions that can occur across all 

sources in the category. Moreover, 

malfunctions can vary in frequency, 

degree, and duration, further 

complicating standard setting. 

In the event that a source fails to 

comply with the applicable CAA section 

112(d) standards as a result of a 

malfunction event (see 40 CFR 63.2 

(definition of malfunction), EPA must 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. EPA would also consider 

whether the source’s failure to comply 

with the CAA section 112(d) standard 

was, in fact, ‘‘sudden, infrequent, not 

reasonably preventable’’ and was not 

instead ‘‘caused in part by poor 

maintenance or careless operation.’’ (See 

40 CFR 63.2 (definition of 

malfunction).) 

Finally, EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause an 

exceedance of the relevant emission 

standard. (See, e.g., State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(September 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions 

(February 15, 1983)). EPA is therefore 

adding to this final rule an affirmative 

defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions. (See 40 CFR 

63.11226 (defining ‘‘affirmative defense’’ 

to mean, in the context of an 

enforcement proceeding, a response or 

defense put forward by a defendant, 

regarding which the defendant has the 

burden of proof, and the merits of which 

are independently and objectively 

evaluated in a judicial or administrative 

proceeding).) We also have added other 

regulatory provisions to specify the 

elements that are necessary to establish 

this affirmative defense; the source must 

prove by a preponderance of the 

evidence that it has met all of the 

elements set forth in 63.11226. (See 40 

CFR 22.24.) The criteria ensure that the 

affirmative defense is available only 

where the event that causes an 

exceedance of the emission limit meets 

the narrow definition of malfunction in 

40 CFR 63.2 (sudden, infrequent, not 

reasonable preventable and not caused 

by poor maintenance and or careless 

operation). For example, to successfully 

assert the affirmative defense, the source 

must prove by a preponderance of the 

evidence that excess emissions ‘‘[w]ere 

caused by a sudden, infrequent, and 

unavoidable failure of air pollution 

control and monitoring equipment, 

process equipment, or a process to 

operate in a normal or usual manner 

* * *.’’ The criteria also are designed to 

ensure that steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with 40 CFR 63.11205(a), 

and to prevent future malfunctions. For 

example, the source must prove by a 

preponderance of the evidence that 

‘‘[r]epairs were made as expeditiously as 

possible when the applicable emission 

limitations were being exceeded * * *’’ 

and that ‘‘[a]ll possible steps were taken 

to minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health * * *.’’ 

In any judicial or administrative 

proceeding, the Administrator may 

challenge the assertion of the affirmative 

defense and, if the respondent has not 

met its burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with CAA section 113 of 

the CAA (see also 40 CFR 22.77). 

F. What are the initial compliance 

requirements? 

For new and existing area source 

boilers with applicable emission limits, 

you must conduct initial performance 

tests to determine compliance with the 

PM, mercury, and CO emission limits. 

The performance tests to demonstrate 

compliance with the mercury emission 

limit can be either a stack test, which 

also requires a fuel analysis, or only a 

fuel analysis. 

As part of the initial compliance 

demonstration, you must monitor 

specified operating parameters during 

the initial performance tests that 

demonstrate compliance with the PM, 

mercury, and CO emission limits for 

area source boilers. The test average 

establishes your site-specific operating 

levels. 

For owners or operators of existing 

and new coal-fired area source boilers 

having a heat input capacity of less than 

10 MMBtu/h and all existing and new 

biomass-fired and oil-fired area source 

boilers, you must submit to the 

delegated authority or EPA, as 

appropriate, documentation that a tuneup was conducted. 

For owners or operators of existing 

area source facilities having a boiler 

with a heat input capacity of 10 

MMBtu/h or greater and subject to this 

rule, you must submit to the delegated 

authority or EPA, as appropriate, 

documentation that the energy 

assessment was performed and the costeffective energy conservation measures 

identified. 

G. What are the continuous compliance 

requirements? 

If you demonstrate initial compliance 

with the emission limits by performance 

(stack) tests, then you must conduct 

stack tests every 3 years. Furthermore, 

to demonstrate continuous compliance 

with the PM, CO, and mercury emission 

limits, you must monitor and comply 

with the applicable site-specific 

operating limits. 

For area source boilers that must 

comply with the PM and mercury 

emission limits, you must continuously 

monitor opacity and maintain the 

opacity at or below 10 percent (daily 

block average) or: 

1. If the boiler is controlled with a 

fabric filter, the fabric filter may be 

continuously operated such that the 

alarm on the bag leak detection system 

does not sound more than 5 percent of 

the operating time during any 6-month 

period. 

2. If the boiler is controlled with an 

electrostatic precipitator (ESP), you 

must maintain the minimum voltage 

and secondary amperage (or total power 

input) of the ESP at or above the 

minimum operating limits established 

during the performance test. 

3. If the boiler is controlled with a wet 

scrubber, you must monitor pressure 

drop and liquid flow rate of the scrubber 

and maintain the daily block averages at 

or above the minimum operating limits 

established during the performance test. 

4. For boilers with sorbent or carbon 

injection systems which must comply 

with an applicable mercury emission 

limit, you must maintain the daily block 

averages at or above the minimum 

sorbent flow rate, as calculated 

according to 40 CFR 63.11221(a)(5). 


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If you elected to demonstrate initial 

compliance with the mercury emission 

limit by fuel analysis, as determined 

according to 40 CFR 63.11211(b), you 

must conduct a monthly fuel analysis 

and maintain the annual average at or 

below the limit indicated in Table 1 of 

this preamble. 

For boilers that demonstrate 

compliance with the PM and mercury 

emission limits by performance (stack) 

tests, you must maintain monthly fuel 

records that demonstrate that you 

burned no new fuel type or new mixture 

(monthly average) as set during the 

performance test. If you plan to burn a 

new fuel type or new mixture that is 

different from what was burned during 

the initial performance test, then you 

must conduct a new performance test to 

demonstrate continuous compliance 

with the PM emission limit and mercury 

emission limit. 

For boilers that must comply with the 

CO emission limits, you must 

continually monitor oxygen and 

maintain an oxygen concentration level, 

on a 30-day rolling average basis, at no 

less than 90 percent of the average 

oxygen concentration measured during 

the most recent performance test. 

Biomass and oil-fired boilers must 

meet the management practice 

standards defined in Table 2 to 40 CFR 

part 63, subpart JJJJJJ. 

H. What are the notification, 

recordkeeping and reporting 

requirements? 

All new and existing sources will be 

required to comply with some 

requirements of the General Provisions 

(40 CFR part 63, subpart A), which are 

identified in Table 6 to subpart JJJJJJ. 

The General Provisions include specific 

requirements for notifications, 

recordkeeping, and reporting. If 

performance tests are required under 

subpart JJJJJJ, then the notification and 

reporting requirements for performance 

tests in the General Provisions also 

apply. 

Each owner or operator is required to 

submit a notification of compliance 

status report, as required by 40 CFR 

63.9(h) of the General Provisions. 

Subpart JJJJJJ rule requires the owner or 

operator to include in the notification of 

compliance status report certifications 

of compliance with rule requirements. 

If your unit is subject to an emission 

limit, then you must prepare, by March 

1 of each year, an annual compliance 

certification report for the previous 

calendar year certifying the truth, 

accuracy and completeness of the 

notification and a statement of whether 

the source has complied with all the 

relevant standards and other 

requirements of this subpart. 

This rule requires records to 

demonstrate compliance with each 

emission limit, work practice standard, 

and management practice. These 

recordkeeping requirements are 

specified directly in the General 

Provisions to 40 CFR part 63. 

Records for applicable management 

practices must be maintained. 

Specifically, the owner or operator must 

keep records of the dates and the results 

of each boiler tune-up. 

Records are required for either 

continuously monitored parameter data 

for a control device, if a device is used 

to control the emissions, or continuous 

opacity monitoring system (COMS) data. 

Each owner and operator is required 

to keep the following records: 

(1) All reports and notifications 

submitted to comply with this final rule; 

(2) Continuous monitoring data as 

required in this final rule; 

(3) Each instance in which you did 

not meet each emission limit, work/ 

management practice, and operating 

limit (i.e., deviations from this final 

rule); 

(4) Monthly fuel use by each boiler 

including a description of the type(s) of 

fuel(s) burned, amount of each fuel type 

burned, and units of measure; 

(5) A copy of the results of all 

performance tests, energy assessments, 

opacity observations, performance 

evaluations, or other compliance 

demonstrations conducted to 

demonstrate initial or continuous 

compliance with this final rule; and 

(6) A copy of your site-specific 

monitoring plan developed for this final 

rule, if applicable. 

Records must be retained for at least 

5 years. In addition, monitoring plans, 

operating and maintenance plans, and 

other plans must be updated as 

necessary and kept for as long as they 

are still current. 

I. Submission of Emissions Test Results 

to EPA 

Compliance test data are necessary for 

many purposes including compliance 

determinations, development of 

emission factors, and determining 

annual emission rates. EPA has found it 

burdensome and time consuming to 

collect emission test data because of 

varied locations for data storage and 

varied data storage methods. 

One improvement that has occurred 

in recent years is the availability of 

stack test reports in electronic format as 

a replacement for bulky paper copies. 

In this action, we are taking a step to 

improve data accessibility for stack tests 

(and in the future continuous 

monitoring data). Boiler area sources are 

required to submit to WebFIRE (an EPA 

electronic data base) an electronic copy 

of stack test reports as well as process 

data. Data entry requires only access to 

the Internet and is expected to be 

completed by the stack testing company 

as part of the work that it is contracted 

to perform. 

Please note that the requirement to 

submit source test data electronically to 

EPA does not require any additional 

performance testing. In addition, when 

a facility submits performance test data 

to WebFIRE, there are no additional 

requirements for data compilation; 

instead, we believe industry will greatly 

benefit from improved emissions 

factors, fewer information requests, and 

better regulation development as 

discussed below. Because the 

information that is being reported is 

already required in the existing test 

methods and is necessary to evaluate 

the conformance to the test methods, 

facilities are already collecting and 

compiling these data. The Electronic 

Reporting Tool (ERT) was developed 

with input from stack testing 

companies, who already collect and 

compile performance test data 

electronically. One major advantage of 

submitting source test data through ERT 

is that it provides a standardized 

method to compile and store all the 

documentation required by subpart 

JJJJJJ. Another important benefit of 

submitting these data to EPA at the time 

the source test is conducted is that these 

data should reduce the effort involved 

in data collection activities in the future 

for these source categories. This results 

in a reduced burden on both affected 

facilities (in terms of reduced manpower 

to respond to data collection requests) 

and EPA (in terms of preparing and 

distributing data collection requests). 

Finally, another benefit of submitting 

these data to WebFIRE electronically is 

that these data will greatly improve the 

overall quality of the existing and new 

emissions factors by supplementing the 

pool of emissions test data upon which 

emissions factors are based and by 

ensuring that data are more 

representative of current industry 

operational procedures. A common 

complaint we hear from industry and 

regulators is that emissions factors are 

out-dated or not representative of a 

particular source category. Receiving 

recent performance test results would 

ensure that emissions factors are 

updated and more accurate. In 

summary, receiving these test data 

already collected for other purposes and 

using them in the emissions factors 

development program will save 


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industry, state/local/tribal agencies, and 

EPA time and money. 

As mentioned earlier, the electronic 

data-base that will be used is EPA’s 

WebFIRE, which is a Web site accessible 

through EPA’s TTN (technology transfer 

network). The WebFIRE Web site was 

constructed to store emissions test data 

for use in developing emission factors. 

A description of the WebFIRE data-base 

can be found at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main. 

The ERT will be able to transmit the 

electronic report through EPA’s Central 

Data Exchange (CDX) network for 

storage in the WebFIRE data base. 

Although ERT is not the only electronic 

interface that can be used to submit 

source test data to the CDX for entry 

into WebFIRE, it makes submittal of 

data very straightforward and easy. A 

description of the ERT can be found at 

http://www.epa.gov/ttn/chief/ert/ 

ert_tool.html. 

The ERT can be used to document the 

conduct of stack tests for various 

pollutants including PM, mercury, 

dioxin/furan, and HCl. Presently, the 

ERT does not accept opacity data or 

CEMS data. 

IV. Summary of Significant Changes 

Following Proposal 

A. Changes to Subcategories 

We have redefined the coal, biomass 

and oil subcategories for area source 

boilers to clarify the fuel-type inputs 

that would define each subcategory. The 

proposed rule defined the biomass 

subcategory to include any boiler that 

burns any amount of biomass, either 

alone or in combination with a liquid or 

gaseous fuel. This definition excluded 

boilers that burned biomass with coal; 

boilers burning greater than 10 percent 

coal on an annual fuel heat input basis 

were defined under the coal-fired 

subcategory. This final rule defines the 

biomass subcategory to include any 

boiler that burns at least 15 percent of 

biomass on an annual heat input basis. 

Similarly, the proposed rule defined 

the oil subcategory to include any boiler 

that burns any liquid fuel either alone 

or in combination with gaseous fuels, 

and excluded boilers that burned solid 

fuels. We have revised this final rule to 

define the oil subcategory to include 

any boiler that burns any liquid fuel and 

is not in either the biomass or coal 

subcategory. 

The coal subcategory in this final rule 

has been revised to include any boiler 

combusting any solid fossil fuels and no 

more than 15 percent biomass. This 

final rule defines solid fossil fuels to 

include, but not limited to, coal, 

petroleum coke, and tire derived fuel 

(TDF). 

B. Change From MACT to GACT for 

Biomass and Oil Subcategories 

The proposed rule set MACT-based 

emission limits for CO (as a surrogate 

pollutant for the individual urban 

organic HAP) from new and existing 

biomass-fired and oil-fired boilers. For 

POM from area source boilers classified 

as biomass-fired or oil-fired, as well as 

with respect to other urban HAP besides 

POM, we have revised this final rule 

standards to reflect GACT for these two 

area source subcategories (see Section 

V.D of this preamble). We are 

implementing management practice 

standards, as allowed by CAA section 

112(d)(5), for control of POM from new 

and existing area source boilers in the 

biomass and oil subcategories. The 

management practice standard requires 

the implementation of a tune-up 

program. 

C. MACT Floor UPL Methodology/ 

Emission Limits 

At proposal, we used a 99 percent 

UPL calculation to determine 

variability. In this final rule, we have 

determined that 99 percent UPL is 

appropriate for fuel based HAP and a 

99.9 percent UPL is appropriate for 

combustion dependent HAP (i.e., CO). 

We have modified our assumptions 

when results of the skewness and 

kurtosis tests result in a tie between 

normal and log-normal calculations, or 

when there is not enough data to 

complete the skewness and kurtosis 

tests, to choose the log-normal results. 

We have also revised the UPL 

calculation to convert log-normally 

distributed data to an arithmetic mean 

instead of a geometric mean. Further, for 

fuel based HAP (i.e., mercury), we have 

implemented an additional fuel 

variability factor in the emission limits. 

D. Clarification of Energy Assessment 

Requirements 

The proposed rule required owners 

and operators of existing area source 

boilers with a heat input capacity of 

10 MMBtu/h and greater to have an 

energy assessment performed by a 

qualified professional. The proposed 

rule defined an energy assessment as an 

‘‘in-depth assessment of a facility to 

identify immediate and long-term 

opportunities to save energy, focusing 

on the steam and process heating 

systems which involves a thorough 

examination of potential savings from 

energy efficiency improvements, waste 

minimization and pollution prevention, 

and productivity improvement.’’ The 

requirements for the energy assessment, 

defined in Table 3 of the proposed rule, 

included visually inspecting the boiler 

system, establishing operating 

characteristics and energy system 

specifications, identifying the boiler’s 

major energy consuming systems, listing 

major energy conservation measures, 

and a comprehensive report detailing 

the ways to improve efficiency, the cost 

of specific improvements, and the 

benefits associated with such. 

This final rule requires an energy 

assessment for all existing boilers with 

a heat input capacity of 10 MMBtu/h or 

greater, and clarifies the definition of 

energy assessment with respect to the 

requirements of Table 3 of this final 

rule. The revised definition provides a 

maximum duration for performing the 

energy assessment and defines the 

evaluation requirements for each boiler 

system and energy use system. These 

requirements are based on the total 

annual heat input of the affected boilers. 

This final rule requires an energy 

assessment for facilities with affected 

boilers using less than 0.3 trillion Btu 

per year heat input to be one day in 

length maximum. The boiler system and 

energy use system accounting for at 

least 50 percent of the energy output 

from the boilers must be evaluated to 

identify energy savings opportunities 

within the limit of performing a one-day 

energy assessment. An energy 

assessment for a facility with affected 

boilers using 0.3 to 1 TBtu/year must be 

three days in length maximum. From 

these boilers, the boiler system and any 

energy use system accounting for at 

least 33 percent of the energy output 

will be evaluated, within the limit of 

performing a three day energy 

assessment. For facilities with affected 

boilers using greater than 1 TBtu/year 

heat input, the energy assessment must 

comprise the boiler system and any 

energy use system accounting for at 

least 20 percent of the energy output to 

identify energy savings opportunities. 

We have also added a definition for 

‘‘energy use systems’’ to clarify the 

components, in addition to the boiler 

system, which must be considered 

during the energy assessment. 

E. Revised Subcategory Limits 

The proposed rule set emission limits 

for PM (as a surrogate for the individual 

urban metal HAP) for all new area 

source boilers and CO (as a surrogate 

pollutant for the individual urban 

organic HAP) for all new area source 

boilers and for existing area source 

boilers with a heat input capacity of 

10 MMBtu/h or greater. The proposed 

rule also set emission limits for mercury 

from new and existing coal-fired boilers. 


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In this final rule, the emission limits 

for mercury and CO have been revised 

for existing coal-fired boilers with a heat 

input capacity greater than 10 MMBtu/ 

h. The MACT emission limits for the 

coal subcategory have been revised 

based on the revised MACT floor 

approach (see Section V of this 

preamble). Existing boilers in the 

biomass and oil subcategories are not 

required to meet emission limits for CO 

in this final rule; these units must meet 

the management practice standards of 

implementing a boiler tune-up program. 

In this final rule, the PM emission 

limits for new area source boilers have 

been revised based on the size category. 

For new boilers in the coal, biomass, 

and oil subcategories with a heat input 

capacity less than 10 MMBtu/h, GACT 

is a management practice of a tune-up. 

For new boilers between 10 and 30 

MMBtu/h heat input, the PM limit has 

been revised to reflect the performance 

of GACT, which is a multiclone. The 

emission limits for mercury and CO 

have been revised for new coal-fired 

boilers with a heat input capacity 

greater than 10 MMBtu/h. New boilers 

in the biomass and oil subcategories are 

not required to meet emission limits for 

CO; these units must meet the 

management practice standards of a 

tune-up. 

Table 2 of this preamble summarizes 

the revised emission limits for each 

pollutant for each subcategory. 

TABLE 2—REVISED EMISSION LIMITS FOR SUBPART JJJJJJ 

Subcategory Heat input 

(MMBtu/hr) Pollutant Proposed emission limit Final emission limit 

New coal-fired boiler ........ ≥30 Particulate Matter ............ 0.03 lb per MMBtu of heat input ... 0.03 lb per MMBtu of heat input 

Mercury ........................... 0.000003 lb per MMBtu of heat 

input.

0.0000048 lb per MMBtu of heat 

input 

Carbon Monoxide ............ 310 ppm by volume on a dry 

basis corrected to 7 percent oxygen 

400 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

≥10 and <30 Particulate Matter ............ 0.03 lb per MMBtu of heat input 0.42 lb per MMBtu of heat input 

Mercury ........................... 0.000003 lb per MMBtu of heat 

input.

0.0000048 lb per MMBtu of heat 

input 

Carbon Monoxide ............ 310 ppm by volume on a dry 

basis corrected to 7 percent oxygen 

400 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

New biomass-fired boiler ≥30 Particulate Matter ............ 0.03 lb per MMBtu of heat input ... 0.03 lb per MMBtu of heat input 

Carbon Monoxide ............ 100 ppm by volume on a dry 

basis corrected to 7 percent oxygen.

Management Practice Standards 

(see Table 2 to subpart JJJJJJ) 

≥10 and <30 Particulate Matter ............ 0.03 lb per MMBtu of heat input ... 0.07 lb per MMBtu of heat input 

Carbon Monoxide ............ 100 ppm by volume on a dry 

basis corrected to 7 percent oxygen.

Management Practice Standards 

(see Table 2 to subpart JJJJJJ) 

New oil-fired boiler ........... ≥30 Particulate Matter ............ 0.03 lb per MMBtu of heat input ... 0.03 lb per MMBtu of heat input 

Carbon Monoxide ............ 1 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

Management Practice Standards 

(see Table 2 to subpart JJJJJJ) 

≥10 and <30 Particulate Matter ............ 0.03 lb per MMBtu of heat input ... 0.03 lb per MMBtu of heat input 

Carbon Monoxide ............ 1 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

Management Practice Standards 

(see Table 2 to subpart JJJJJJ) 

Existing coal-Fired boiler ≥10 Mercury ........................... 0.000003 lb per MMBtu of heat 

input.

0.0000048 lb per MMBtu of heat 

input 

Carbon Monoxide ............ 310 ppm by volume on a dry 

basis corrected to 7 percent oxygen 

400 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

Existing biomass-fired 

boiler.

Carbon Monoxide ............ 160 ppm by volume on a dry 

basis corrected to 7 percent oxygen 

Management Practice Standards 

(see Table 2 to subpart JJJJJJ) 

Existing coal-fired boiler .. Carbon Monoxide ............ 2 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

Management Practice Standards 

(see Table 2 to subpart JJJJJJ) 

F. Demonstrating Compliance 

We have revised the compliance dates 

for existing affected sources according 

to the applicable provisions for each 

affected source (e.g., work practice 

standards, emission limits, management 

practice standards, and/or an energy 

assessment). Under the proposed rule, 

owners and operators of existing sources 

would have had to comply with this 

final rule within 3 years following 

March 21, 2011. This final rule requires 

that if you own or operate an existing 

source subject to a work practice or 

management practice standard of a tuneup, you must comply with this final rule 

no later than March 21, 2012. If you 

own or operate an existing source 

subject to an emission limit or an energy 

assessment requirement, you must 

comply with this final rule no later than 

March 21, 2014. Under the proposed 

rule, the owner or operator of a new 

source would have been required to 

comply on the date of publication of the 

final rule or upon startup of the facility, 

which ever was later. Because this rule 

is subject to the Congressional Review 

Act, the owner or operator of a new 

source is required to comply on May 20, 

2011 or upon startup of the facility, 

whichever is later. 

Additionally, we have clarified the 

compliance requirements for 

commercial and industrial solid waste 

incineration units subject to 40 CFR part 

60, subpart CCCC or subpart DDDD that 

cease combusting solid waste and 

become subject to Subpart JJJJJJ. Owners 

and operators of commercial and 

industrial solid waste incineration units 

must be in compliance with this subpart 

on the effective date of the waste to fuel 

switch (at least 12 months from the date 

that the owner or operator ceased 


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combusting solid waste), if the effective 

date is after the applicable compliance 

dates discussed above. 

We have also revised the proposed 

continuous compliance requirements to 

be consistent with changes to the 

emission limits in this final rule, and 

are no longer requiring CO CEMS for 

biomass, oil, and coal-fired units. For 

new and existing coal units with a heat 

input capacity greater than 10 MMBtu/ 

h, we are requiring stack testing every 

3 years to demonstrate compliance with 

the CO emission limits. Because boilers 

in the biomass and oil subcategories are 

only required to meet the management 

practice standards in Table 2 of 40 CFR 

part 63, subpart JJJJJJ, no testing for CO 

emissions is required for these units. 

G. Affirmative Defense 

We have added provisions to this 

final rule to include an affirmative 

defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions. Consistent with 

Sierra Club v. EPA, EPA has established 

standards in this rule that apply at all 

times. However, in response to an action 

to enforce the standards set forth in 40 

CFR 63.11201, you may assert an 

affirmative defense for exceedances of 

such standards that are caused by 

malfunction, as defined at 40 CFR 63.2. 

(See 40 CFR 63.11226 (defining 

‘‘affirmative defense’’ to mean, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding). The 

included provisions specify the 

elements that are necessary to establish 

an affirmative defense for periods of 

malfunction, including evidence and 

notification requirements that must be 

prepared by the source. 

H. Technical/Editorial Corrections 

In this final action, we are making a 

number of technical corrections and 

clarifications to subpart JJJJJJ. These 

changes improve the clarity and 

procedures for implementing the 

emission limitations to affected sources. 

We are also clarifying several 

definitions to help affected sources 

determine their applicability. We have 

modified some of the regulatory 

language that we proposed based on 

public comments. 

We made several changes to the initial 

compliance demonstration 

requirements. We revised 40 CFR 

63.11211(a) to clarify that sources using 

a second fuel only for start up, 

shutdown, and/or transient flame 

stability are still considered to be 

sources using a single fuel. We deleted 

40 CFR 63.11210(b) to remove the 

requirement that boilers with a heat 

input capacity above 100 MMBtu/h are 

required to demonstrate compliance by 

conducting a performance evaluation of 

their CO CEMS. 

We made a change to the monitoring 

requirements in 40 CFR 63.11225 (40 

CFR 63.11224 in the proposed rule). We 

deleted paragraph (e) to remove the 

requirement that boilers having a heat 

input capacity of 100 MMBtu/h and 

subject to a CO limit install a CO CEMS. 

In response to comments asking for 

clarification, we have added definitions 

to 40 CFR 63.11237 for ‘‘Annual heat 

input basis,’’ ‘‘Energy use system,’’ ‘‘Hot 

water heater,’’ ‘‘Minimum scrubber 

pressure drop,’’ ‘‘Minimum voltage or 

amperage,’’ ‘‘Qualified energy assessor,’’ 

and ‘‘Solid fossil fuel.’’ We have also 

revised several definitions in that 

section based on public comments. For 

example, we revised the definition of 

‘‘Boiler’’ to describe what is meant by the 

term ‘‘controlled flame combustion’’ as 

used in that definition. 

Several of the definitions in 40 CFR 

64.11237 were revised to clarify the 

types of equipment to which different 

standards apply. For example, the 

definition of ‘‘Waste heat boiler’’ was 

revised to remove the criteria that 50 

percent of total rated heat input capacity 

had to be from supplemental burners. 

We also revised the definition of 

‘‘Natural gas’’ to include gas derived 

from naturally occurring mixtures found 

in geological formations as long as the 

principal constituent is methane, 

consistent with the definition provided 

in 40 CFR part 60 subpart Db. A 

definition of propane was also 

incorporated into the definition of 

natural gas. 

V. Significant Area Source Public 

Comments and Rationale for Changes to 

Proposed Rule 

This section contains a brief summary 

of major comments and responses. EPA 

received many comments on this 

subpart covering numerous topics. 

EPA’s responses to all comments, 

including those below, can be found in 

the comment response document for 

Area Source Industrial, Commercial, 

and Institutional Boilers in the docket. 

A. Legal and Applicability Issues 

Section 112(c)(6) of the CAA 

Comment: Some commenters stated 

that EPA misinterpreted the statute in 

using MACT instead of GACT for area 

sources. These commenters argued that 

the statute allows for setting a standard 

under CAA section 112(d)(2) that can be 

satisfied using the alternative GACT 

procedure specified in CAA section 

112(d)(5) to meet the 112(c)(6) 

requirements. 

Response: We disagree with the 

comment that the CAA gives EPA 

discretion to promulgate GACT 

standards pursuant to section 112(d)(5) 

for area source categories required to be 

regulated under section 112(c)(6). 

Section 112(c)(6) of the CAA explicitly 

requires that ‘‘sources accounting for not 

less than 90 per centum of the aggregate 

emissions of each [pollutant specified in 

this provision] are subject to standards 

under subsection 112(d)(2) or (d)(4) 

* * *.’’ (Emphasis added). The plain 

language of section 112(c)(6) requires 

that the Agency set standards under 

section 112(d)(2) or (d)(4). There is no 

ambiguity in this language and thus the 

legislative history cited by the 

commenter is irrelevant. As such, the 

Agency is appropriately setting 

standards for the sources at issue 

pursuant to section 112(d)(2). 

The commenter argues that section 

112(d)(5) trumps the very specific 

language in section 112(c)(6). We 

disagree. Congress unambiguously 

required the Agency to set standards for 

these persistent, bioaccumulative HAP 

under section 112(d)(2) or (d)(4). Had 

Congress wanted us to permit EPA to 

issue GACT standards for the 112(c)(6) 

HAP, it would have said that EPA could 

issue standards under section 112(d), as 

it did in section 112(k)(3)(B) of the Act, 

noting that area sources shall be subject 

to standards issued pursuant to 

‘‘subsection (d) of this section.’’ Congress 

could not have been more precise in 

section 112(c)(6), and we reject the 

commenter’s interpretation. 

EPA has consistently maintained that 

standards under section 112(d)(2) or 

(d)(4) are required for the pollutants 

listed in section 112(c)(6). In this case, 

we are setting a section 112(d)(2) MACT 

standard for mercury and CO (as a 

surrogate for POM) for coal-fired area 

source boilers, which are the 112(c)(6) 

pollutants that form the basis for the 

listing of the source category at issue 

here. 

Comment: One commenter argued 

that EPA did not provide justification 

for its decision that mercury and POM 

must be regulated pursuant to CAA 

section 112(c)(6) at area source boilers 

to satisfy the requirements that 90 

percent of nationwide emissions of 

these pollutants must be reduced. The 

commenter further stated that the 

proposed rule and supporting 

documentation provide no rational basis 

or adequate factual justification for the 

need to regulate area source POM or 


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2When justifying its use in the 1998 inventory, 

we said that EPA would undertake an effort to 

develop a robust inventory for EOM sources to feed 

into the CAA section 112(c)(6) inventory. Had more 

data been gathered, perhaps EOM would have 

proved to be a more useful indicator of POM. 

However, the anticipated inventory was not 

developed. 

mercury emissions to satisfy CAA 

section 112(c)(6). Specifically, the 

commenter stated that neither the 

proposed rule nor the MACT floor 

memo provide data that support the 

proposed determination that 90.3 

percent of the 1990 emissions inventory 

for mercury is already subject to 

regulation. In contrast, another 

commenter said that, once a category is 

listed under CAA section 112(c)(6), the 

only procedure available to EPA for 

refraining from promulgating a MACTbased standard for the category is to 

remove the category from the CAA 

section 112(c) list through the use of 

CAA section 112(c)(9), regardless of 

whether the category is needed to meet 

the 90 percent requirement in CAA 

section 112(c)(6). 

Response: The statute does not limit 

EPA’s discretion as to how it fulfills its 

obligations under CAA section 

112(c)(6). To the extent that the 

commenters seek to challenge whether 

EPA has selected appropriate categories 

to meet its obligations under CAA 

section 112(c)(6) or whether EPA has 

met the requirement in CAA section 

112(c)(6) to regulate categories emitting 

at least 90 percent of the specified 

pollutants (in this case, mercury and 

POM), such challenges should not be 

reviewed in the context of a review of 

an individual NESHAP. Rather, if 

review is appropriate, it should be in 

the context of an EPA finding that it has 

fulfilled its obligations under CAA 

section 112(c)(6), and an accounting by 

the agency of how it reached the 90 

percent threshold for each pollutant. 

Nevertheless, the docket for this 

rulemaking contains a spreadsheet that 

demonstrates our belief that we have 

met the 90 percent requirement for POM 

and for mercury with this final rule. 

While we are promulgating GACTbased provisions at this time for 

mercury and POM from biomass-fired 

and oil-fired area source boilers, note 

that we have not removed or ‘‘delisted’’ 

oil-fired and biomass-fired area source 

boilers by this action. We are not 

promulgating MACT-based regulations 

at this time because they are 

unnecessary to meet the requirements of 

CAA section 112(c)(6). 

Comment: Comments received 

suggested EOM was not appropriate for 

representing POM emissions. The 

commenters noted a drawback to using 

EOM as a surrogate for POM is the 

limited amount of data available to 

quantify emissions and the few EOM 

inventories or emission factors in 

existence. Commenters also stated that 

EOM includes other extractible organics 

in addition to the PAHs. The 

commenters suggest that the reasonable 

assumption is that any observed health 

effects come from the PAH fraction and 

since EOM includes compounds other 

than PAH, it should not be used as a 

surrogate for POM. 

Response: This issue primarily affects 

whether biomass-fired and oil-fired 

boilers are needed to meet the CAA 

section 112(c)(6) requirements. EPA has 

considered commenter input and 

revised the final rule based on our reexamination of our section 112(c)(6) 

baseline inventory for POM. As we 

noted in the proposed rule, we 

reexamine the inventory associated with 

the original listing as we learn more 

about the source category in the rule 

development process (75 FR 31904). 

Based on a re-examination of the 

emission inventory in light of 

comments, we have determined that we 

only need to address the coal-fired 

portion of the area source segments of 

these categories under CAA section 

112(c)(6) in order to meet the 90 percent 

threshold requirement of that provision 

for both mercury and POM. 

As discussed in the preamble to the 

June 2010 proposed rule (75 FR 31896), 

we have determined that we must 

regulate mercury and POM from coalfired area source boilers in order to meet 

the requirements in CAA section 

112(c)(6), and we are establishing 

MACT-based limits for mercury and 

POM (using CO as a surrogate) for this 

subcategory. We are implementing work 

practice standards, as allowed by CAA 

section 112(h), for control of mercury 

and POM from new and existing area 

source boilers in the coal subcategory 

with a designed heat input capacity less 

than 10 MMBtu/h. 

In the CAA section 112(c)(6) source 

listing, we used three indicators (7– 

PAH, 16–PAH, and extractable organic 

matter (EOM)) to represent POM 

emissions and compiled three separate 

baseline inventories for POM, one for 

each indicators. In light of the comment 

described above regarding EOM, we reexamined our three section 112(c)(6) 

baseline inventories for POM. For the 

reason stated below, we have decided to 

use only the baseline inventory for 16– 

PAH in determining the 90 percent 

threshold under section 112(c)(6). 

We agree with the commenters who 

have identified data gaps in our 

knowledge of what source categories are 

emitting EOM. While we have data on 

16–PAH emissions for 94 categories, we 

only have available data on EOM 

emissions for 18 source categories. The 

lack of available data on EOM emission 

creates a distorted picture of the relative 

contributions of source categories for 

which there are available EOM data. 

The lack of source categories making up 

the total EOM inventory makes the 

relative contribution of the few 

categories that do have data 

unrealistically inflated.2 We therefore 

cannot say with confidence that by 

using the baseline inventory for EOM 

we are capturing 90 percent of the 

baseline POM emissions, as required by 

section 112(c)(6). Similarly, we have 

data on 7–PAH for 32 categories, 

considerably fewer than the 94 

categories for which we have 16–PAH 

data. Because the 16–PAH inventory 

allows for the most accurate 

representation of the universe of 

categories that emit POM, we have 

decided to use that baseline inventory 

for determining the 90 percent threshold 

for POM under section 112(c)(6). Based 

on the baseline inventory for 16–PAH, 

regulating POM emissions from area 

source biomass and oil boilers are not 

needed to meet the CAA section 

112(c)(6) obligations. Thus, POM 

emissions from area source boilers in 

the biomass and oil subcategories can be 

regulated under GACT, instead of 

MACT. 

With respect to mercury and POM 

from area source boilers classified as 

biomass-fired or oil-fired, as well as 

with respect to other urban HAP besides 

POM, we have revised the final rule 

standards to reflect GACT for these two 

area source subcategories (see Section 

IV.B of this preamble). We are 

implementing management practice 

standards, as allowed by CAA section 

112(d)(5), for control of POM from new 

and existing area source boilers in the 

biomass and oil subcategories. The 

management practice standard for new 

and existing area source boilers requires 

the implementation of a tune-up 

program. 

As stated previously in the preamble 

to the June 2010 proposed rule, we 

determined that the control technologies 

currently used by facilities in the source 

category to reduce non-mercury metallic 

HAP and PM (multiclone, fabric filters, 

and ESP) are generally available and 

cost effective for new area source 

boilers. Additionally, these controls are 

commonly required by state and other 

federal regulations that apply to the area 

source boilers in the source category. 

Therefore, we are establishing numeric 

emission limits representing GACT for 

all new area source boilers with a heat 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15567 

input capacity greater than 10 MMBtu/ 

h (using PM as a surrogate). 

Emission Standards for HAP Other Than 

Mercury 

Comment: One commenter stated that 

CAA section 112(c)(6) provides that 

EPA must ‘‘list categories and 

subcategories of sources assuring that 

sources accounting for not less than 90 

percent of each [enumerated] pollutant 

are subject to standards under 

subsection (d)(2) or (d)(4) of this 

section.’’ The commenter also stated that 

the DC Circuit has held repeatedly that 

when EPA sets standards for a category 

or subcategory of sources under section 

112(d)(2), EPA has a statutory duty to 

set emission standards for each HAP 

that the sources in that category or 

subcategory emit. The commenter 

concluded that when EPA sets 

standards for area source boilers under 

section 112(d)(2), as section 112(c)(6) 

requires it to do, EPA must set section 

112(d)(2) emission standards for all the 

HAP that area source boilers emit. 

The commenter said that EPA appears 

to believe that because area source 

boilers are needed only to reach the 

section 112(c)(6) requirement of 90 

percent for mercury and POM and not 

for the other pollutants enumerated in 

section 112(c)(6), EPA’s only obligation 

under section 112(c)(6) is to set section 

112(d)(2) standards for mercury and 

POM. The commenter said that section 

112(c)(6) expressly requires EPA to 

issue section 112(d)(2) standards for the 

‘‘sources’’ in the categories listed under 

section 112(c)(6), not some subset of the 

pollutants that those sources emit, and 

that section 112(d)(2) standards must 

include emission standards for each 

HAP that a source category emits. The 

commenter continued by stating that 

nothing in the CAA exempts EPA from 

this requirement. The commenter 

concluded that, had Congress wished to 

give EPA discretion to set standards for 

only some of the pollutants emitted by 

a category listed under section 112(c)(6), 

it would have done so expressly. 

Response: EPA disagrees with the 

comment that, even though EPA lists a 

category under section 112(c)(6) due to 

the emissions of one or more HAP 

specified in that section, EPA must 

issue emission standards for all HAP 

(including HAP not listed in section 

112(c)(6)) that sources in that category 

emit. The commenter cited in support 

the opinion by the United States Court 

of Appeals for the DC Circuit in 

National Lime Ass’n v. EPA, 233 F.3d 

625, 633–634 (DC Cir. 2000)). The part 

of the National Lime opinion referenced 

in the comment dealt with EPA’s failure 

to set emission standards for certain 

HAP emitted by major sources of 

cement manufacturing because the 

Agency found no sources using control 

technologies for those HAP. In rejecting 

EPA’s argument, the court stated that 

EPA has ‘‘a statutory obligation to set 

emission standards for each listed 

HAP.’’ Id. at 634. The Court noted the 

list of HAP in section 112(b) and stated 

that section 112(d)(1) requires that EPA 

‘‘promulgate regulations establishing 

emission standards for each category or 

subcategory of major sources * * * of 

hazardous air pollutants listed for 

regulation * * *’’ Id. (Emphasis added). 

For the reasons stated below, we do not 

believe that today’s final rule is 

controlled by or otherwise conflicts 

with the National Lime decision. 

National Lime did not involve section 

112(c)(6). That provision is ambiguous 

as to whether standards for listed source 

categories must address all HAP or only 

the section 112(c)(6) HAP for which the 

source category was listed. Section 

112(c)(6) requires that ‘‘sources 

accounting for not less than 90 per 

centum of the aggregate emissions of 

each such [specific] pollutant are 

subject to standards under subsection 

(d)(2) or (d)(4).’’ This language can 

reasonably be read to mean standards 

for the section 112(c)(6) HAP or 

standards for all HAP emitted by the 

source. Under either reading, the source 

would be subject to a section 112(d)(2) 

or (d)(4) standard. 

The commenter insists that once a 

section 112(d)(2) standard comes into 

play, all HAP must be controlled (per 

National Lime). But this result is not 

compelled by the pertinent provision, 

section 112(c)(6). That provision is 

obviously intended to ensure controls 

for specific persistent, bioaccumulative 

HAP, and this purpose is served by a 

reading which compels regulation under 

section 112(d)(2) only of the HAP for 

which a source category is listed under 

section 112(c)(6), rather than for all 

HAP. 

The facts here support the 

reasonableness of EPA’s approach. Area 

source boilers are included in source 

categories listed under section 112(c)(6) 

for regulation under section 112(d)(2) 

solely due to its mercury and POM 

emissions. There is special statutory 

sensitivity to regulation of area source 

categories in section 112. For example, 

an area source category may be listed for 

regulation under section 112 if EPA 

makes an adverse effects finding 

pursuant to Section 112(c)(3) or if EPA 

determines that the area source category 

is needed to meet its section 112(c)(3) 

obligations to regulate urban HAP or its 

section 112(c)(6) obligations to regulate 

certain persistent bioaccumulative HAP. 

Moreover, to the extent EPA lists an area 

source category pursuant to section 

112(c)(3) (whether that finding is based 

on adverse effects to human health or 

the environment or a finding that the 

source is needed to meet the 90 percent 

requirement in section 112(c)(3)), the 

statute gives EPA discretion to set GACT 

standards for such sources (42 U.S.C. 

7412(d)(5)). 

EPA does not interpret section 112 

(c)(6) to create a means of automatically 

compelling regulation of all HAP 

emitted by area sources unrelated to the 

core object of section 112(c)(6), which is 

control of the specific persistent, 

bioaccumulative HAP, and thereby 

bypassing these otherwise applicable 

preconditions to setting section 112(d) 

standards for area sources. Nor does 

National Lime address the issue, since 

the case dealt exclusively with major 

sources (233 F. 3d at 633). 

Consequently, EPA disagrees with the 

comment that it is compelled to 

promulgate section 112(d)(2) MACT 

standards for all HAP emitted by area 

source boilers. 

Beyond-the-Floor Option 

We are promulgating the proposed 

standard requiring the performance of 

an energy assessment for existing area 

source facilities having an affected 

boiler with a designed heat input 

capacity of 10 MMBtu/h or greater. This 

final rule requires the performance of an 

energy assessment, by qualified 

personnel, on the boiler and its energy 

use systems to identify cost-effective 

energy conservation measures. As 

discussed in the June 2010 proposed 

rule, an energy assessment provides 

valuable information on improving 

energy efficiency. Owners and operators 

are encouraged, but not required, to use 

the results of the energy assessment to 

increase the energy-efficiency and costefficiency of their boiler system. 

In the proposed rule, the energy 

assessment requirement was a beyondthe-floor option for the MACT-based 

mercury and CO emission standards 

because additional emission reductions 

would be realized as the results of these 

energy assessments, if implemented. In 

this final rule, the energy assessment 

requirement is both a beyond-the-floor 

control for the MACT-based standards 

for the coal subcategory and a GACT for 

the biomass and oil subcategory because 

energy assessments are generally 

available and have already been 

performed at numerous facilities. 

The principal arguments against an 

energy assessment requirement are: (1) 

EPA lacks authority to impose 

requirements on portions of the source 

that are not designated as part of the 


srobinson on DSKHWCL6B1PROD with RULES4
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3Case studies and success stories highlighting 

energy savings achieved by companies that have 

participated in Save Energy Now energy 

assessments and used Industrial Technologies 

Program software tools to improve energy efficiency 

can be found at http://www1.eere.energy.gov/ 

industry/saveenergynow/case_studies.html and at 

the Department of Energy’s Energy Assessment 

Centers Database http://iac.rutgers.edu/database. 

affected source, such as non-emitting 

energy using systems at a facility; (2) 

EPA has not quantified the reductions 

associated with the energy assessment 

requirement, therefore it cannot be 

‘‘beyond the floor;’’ and (3) the bare 

requirement to perform an audit without 

being required to implement its findings 

is not a standard under CAA section 

112(d). 

With respect to the first argument, we 

have carefully limited the requirement 

to perform an energy assessment to 

specific portions of the source that 

directly affect emissions from the 

affected boiler, as indicated by the 

revised definition of an energy 

assessment in section 63.11237 of 

subpart JJJJJJ. The emissions that are 

being controlled come from the affected 

source. For coal-fired units, the process 

changes resulting from a change in an 

energy using system will reduce the 

volume of emissions at the affected 

source. For biomass-fired and oil-fired 

area sources, better management 

practices at energy using systems will 

reduce the emissions of HAP from the 

affected source by reducing fuel 

consumption and the HAP released 

through combustion of fuel. In either 

case, the requirement controls the 

emissions of the affected source. 

With respect to the second argument, 

the energy assessment will generate 

emission reductions through the 

reduction in fuel use beyond those 

required by the floor. While the precise 

quantity of emission reductions will 

vary from source to source and cannot 

be precisely estimated, the requirement 

is clearly directionally sound and thus 

consistent with the requirement to 

examine beyond the floor controls. By 

definition, any emission reduction 

would be cost effective or else it would 

not be implemented. 

Finally, with respect to the third 

argument, the requirement to perform 

the energy audit is, of course, a 

requirement that can be enforced and 

thus a standard. As noted, while we do 

not know the precise reductions that 

will occur at individual sources, the 

record indicates that energy assessments 

reduce fuel consumption and that 

parties will implement 

recommendations from an auditor that 

they believe are prudent.3 Therefore, the 

requirement to perform an energy 

assessment can both be enforced and 

will result in emission reductions. 

Section 112(h) of the CAA 

Comment: Commenters stated that 

setting work practice standards in lieu 

of emission standards for area source 

boilers with a heat input capacity less 

than 10 MMBtu/h is unlawful and 

arbitrary. Commenters cited EPA’s 

determination with respect to the 

technical and economic limitations on 

the enforcement of emission standards 

for boilers with heat input capacity less 

than 10 MMBtu/h, and stated that these 

limitations do not satisfy CAA section 

112(h) conditions for setting work 

practice standards in lieu of emission 

standards. Some commenters argued 

that the technical limitations of 

measuring PM using Method 5, as 

discussed in the preamble to the 

proposed June 2010 rule, do not apply 

to mercury and CO. Other commenters 

remarked that the absence of sampling 

ports and stacks at area source boilers 

does not provide a basis for a technical 

or economic limitation, stating that 

sources are able to work around this 

issue. Multiple commenters said that 

the lack of measuring ports (which can 

affect retrofitting new boiler 

installations into existing buildings), 

other design requirements for efficient 

exhaust from smaller boilers, and the 

inapplicability of approved test methods 

would make measurement technically 

and economically impractical for both 

existing and new sources. Commenters 

specifically cited CAA section 112(h)(1) 

and (2), which allows the agency to 

prescribe work practice standards only 

if it is ‘‘not feasible to prescribe or 

enforce an emission standard * * * due 

to technological or economic 

limitations.’’ 

Response: EPA disagrees with 

commenters. As discussed in the 

preamble to the June 2010 proposed 

rule, CAA section 112(h) authorizes the 

Administrator to promulgate ‘‘a design, 

equipment, work practice, or 

operational standard, or combination 

thereof,’’ consistent with the provisions 

of CAA sections 112(d) or (f), in those 

cases where, in the judgment of the 

Administrator, it is not feasible to 

prescribe or enforce an emission 

standard. CAA section 112(h)(2)(B) 

further defines the term ‘‘not feasible’’ to 

mean when ‘‘the application of 

measurement technology to a particular 

class of sources is not practicable due to 

technological and economic 

limitations.’’ We have elected to 

implement work practice standards for 

coal-fired boilers with a heat input 

capacity of less than 10 MMBtu/h 

because we have determined that the 

standard reference methods for 

measuring emissions of mercury, CO (as 

a surrogate for POM), and PM (as a 

surrogate for urban non-mercury metals) 

are not applicable for sampling small 

diameter (less than 12 inches) stacks. 

Furthermore, through the comment 

process, we have learned that common, 

very small boilers (less than 5 MMBtu/ 

h) typically exhaust through vents and 

not stacks, and that the installation of 

ports into small diameter vents for 

smaller boilers would likely interfere 

with the functionality of exhaust 

systems for new and existing boilers. 

Because many existing area source 

boilers with a capacity below 10 

MMBtu/h generally have stacks with 

diameters less than 12 inches, and 

because many area source boilers do not 

currently have sampling ports or a 

platform for accessing the exhaust stack, 

we have determined that the testing and 

monitoring costs that area source boiler 

facilities would incur to demonstrate 

compliance with the proposed emission 

limits would present an excessive 

burden for smaller sources. Thus, we are 

establishing work practice standards to 

limit the emissions of mercury and CO 

(as a surrogate for POM) for existing and 

new coal-fired area source boilers 

having a heat input capacity of less than 

10 MMBTU/h. 

De minimis Levels 

Comment: Several commenters stated 

that EPA should establish a de minimis 

heat input level (less than 1 MMBtu/h 

heat input capacity) below which area 

sources are not subject to regulation or 

only subject to work practice standards. 

These commenters referenced water 

heaters and small comfort heating units 

that are not used in industrial, 

commercial, or institutional processes 

but instead used to provide hot water 

for personal use or seasonal comfort 

heating. Other commenters noted that 

State rules that require work practice 

requirements for boilers all have a lower 

limit on applicability of typically 1 to 5 

MMBtu/h; these commenters stated that 

EPA has provided no basis for applying 

work practice standards to boilers of 

this size. 

Response: EPA must establish 

standards for each category or 

subcategory of major sources and area 

sources of HAP listed pursuant to CAA 

section 112(c). EPA may distinguish 

among classes, types, and size in 

establishing such standards but the 

standards established must be 

applicable to new and existing sources 

of HAP within the category. However, 

we agree with the commenters that the 

categories of boiler covered by this rule 

are industrial boilers, commercial 


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4European Wood-Heating Technology Survey: An 

Overview of Combustion Principles and the Energy 

and Emissions Performance Characteristics of 

Commercially Available Systems in Austria, 

Germany, Denmark, Norway, and Sweden; Final 

Report; Prepared for the New York State Energy 

Research and Development Authority; NYSERDA 

Report 10–01; April 2010. 

boilers, and institutional boilers. In the 

proposed rule, we did not list hot water 

heaters as exempted as we did in the 

proposed Boiler MACT for major 

sources. As stated in the preamble to the 

proposed Boiler MACT, hot water 

heaters meet the definition of a boiler 

but are more appropriately described as 

residential-type boilers, not industrial, 

commercial, or institutional boilers 

because their output is intended for 

personal use rather than for use in an 

industrial, commercial, or institutional 

process. The primary reason for 

exempting hot water heaters in the 

Boiler MACT was that hot water heaters 

are not part of the listed source category. 

Because hot water heaters generally use 

natural gas and gas-fired boilers were 

not part of the area source category, we 

did not include a similar exemption in 

the proposed rule. To be consistent with 

the Boiler MACT, we have included in 

this final rule a similar exemption and 

definition for hot water heaters. 

B. CO Limits 

Comment: Multiple commenters 

argued that EPA’s determination of 

using CO as a surrogate for POM is 

inappropriate. Several of these 

commenters reiterated that there is no 

reliable correlation between CO and 

POM. Some commenters stated that CO 

is not an appropriate surrogate for POM 

or organic HAP at lower CO emission 

levels. For instance, one commenter 

stated that while there is a linear 

correlation between decreasing CO and 

decreasing HAP at higher levels, once 

CO values fall under 100 ppm, further 

reduction of CO does not provide any 

substantial correlating reduction of 

HAP. Other commenters stated that CO 

is an inadequate surrogate for POM 

because there is no POM invariably 

present in CO; likewise, commenters 

stated that because CO and POM have 

different mechanisms of formation and 

reduction, CO cannot be considered as 

a reliable surrogate. 

Several commenters suggested total 

hydrocarbon (THC) as a better surrogate, 

stating that THC levels are often more 

stable and less reactive to load swings 

than CO. Commenters noted that THC 

has been used as a surrogate for organic 

HAP emissions in other regulatory 

efforts, including the hazardous waste 

incinerator MACT. 

Response: EPA acknowledges 

commenters’ concerns. Based on new 

data received during the public 

comment period, we have re-examined 

our analysis and revised the final 

standards for CO. As previously 

discussed, this final rule only 

establishes CO emission limits for coalfired boilers pursuant to CAA section 

112(c)(6). We are implementing 

management practice standards, as 

allowed by CAA section 112(d)(5), for 

control of CO from new and existing 

area source boilers in the biomass and 

oil subcategories. Additionally, for the 

coal subcategory, we have revised the 

final CO emission limits to ensure a 

more accurate correlation between POM 

and CO levels. EPA is aware of one 

European study 4 that finds the 

correlation between CO and POM (or 

organic HAP, in general) is weaker at 

lower CO concentrations (less than 100 

ppmv) but we did not have the 

opportunity to examine the data relied 

on by the study and no data supporting 

this supposition were submitted as part 

of the public comments. We have 

revised the final standards (400 ppm) 

based on 99.9 percent UPL as discussed 

in Section IV.C of this preamble. EPA 

believes that CO is a reliable surrogate 

for POM at this emission level. EPA 

considered using THC as a surrogate for 

POM, however, we did not have 

available THC data for area sources. 

Comment: Several commenters 

expressed concern with respect to the 

proposed CO limits. Some commenters 

stated that the proposed CO limits are 

unachievable for some units, including 

liquid-fired boilers. Commenters further 

stated that meeting the CO limits would 

be more burdensome for area sources 

than major sources. Specifically, many 

commenters argued that the CO limits 

are unfeasible from a measurement, 

operability, and cost standpoint, 

particularly when considered 

simultaneously with other limits (NOX,

VOC). Some commenters expressed 

concern that prioritizing CO reduction 

may promote boiler inefficiency and 

result in higher emissions of NOX. 

Other commenters suggested that the 

CO emission limits should be 

determined using long-term CEMS data 

to account for natural variability in CO 

emissions. Commenters also offered 

alternatives for control of POM. One 

commenter suggested that EPA consider 

cleaner fuels or end of stack 

technologies for control, such as fabric 

filters and scrubbers that capture POM 

and POM-precursors. 

Response: As discussed above, this 

final rule establishes MACT-based 

emission limits for CO only for new and 

existing coal-fired boilers. In this final 

rule, area source boilers in the biomass 

and oil-fired subcategories are not 

required to meet CO emission limits; 

these boilers are instead required to 

meet the management practice standard 

which consists of a tune-up. The MACTbased CO emission limits are still 

required for coal-fired area source 

boilers in order to meet our obligation 

under CAA section 112(c)(6). Based on 

the available CO data and the revised 

UPL calculation methodology, the final 

CO emission limits for coal-fired area 

source boilers are higher than the 

proposed limits which should provide 

more assurance that the limit can be 

achieved at all times. EPA notes that the 

available dataset did not include 

sufficient long-term CEMS data for area 

sources to be used to set a limit. 

Therefore, we have established the CO 

standards based on the data provided 

using the revised UPL methodology to 

account for variability over the 

operating cycle of typical industrial, 

commercial, and institutional boilers. 

We also considered other appropriate 

control options for sources in each 

subcategory, including switching to 

clean fuels and end of stack 

technologies. We considered whether 

fuel switching could be technically 

achieved by boilers in the subcategory 

considering the existing design of 

boilers and the availability of various 

types of fuel. We determined that fuel 

switching was not an appropriate 

control technology based on the overall 

effect of fuel switching on HAP 

emissions and the technical and design 

considerations discussed previously in 

the preamble to the proposed June 2010 

rule (75 FR 31896). This determination 

is discussed in the memorandum 

‘‘Development of Fuel Switching Costs 

and Emission Reductions for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters National Emission 

Standards for Hazardous Air 

Pollutants—Area Source’’ located in the 

docket. Additionally, EPA did not 

identify add-on control technologies 

available for control of CO in use at area 

source boilers. 

C. MACT Floor Analysis 

Pollutant-by-Pollutant Approach 

Comment: Several commenters argued 

that the pollutant-by-pollutant approach 

used by EPA is not appropriate. 

Commenters rejected the pollutant-bypollutant approach on the basis that 

both PM and CO emission limits are not 

achievable even for the best performing 

sources. These commenters argued that 

because the proposed area source MACT 

standards rely on a different set of best 

performing sources for each separate 

HAP standard, no single source is in the 


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15570 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

population of units for both the PM and 

CO emission limits, and therefore, the 

approach does not reflect the 

performance of the best performing 

boilers. Rather, commenters asserted 

that the proposed limits were 

unrealistic, unnecessarily stringent, and 

unachievable. Commenters further 

stated that the provisions of CAA 

sections 112(d)(1), (2), and (3) of the 

CAA require that standards must be 

based on actual sources, and cannot be 

the product of pollutant-by-pollutant 

‘‘cherry-picking.’’ Commenters stated 

that EPA does not have the authority to 

‘‘distinguish’’ units and sources by 

individual pollutant. Other commenters 

stated that EPA must set limits for each 

HAP that the sources in the subcategory 

emit, and not solely mercury or POM. 

These commenters stated that to ignore 

the emitted HAP violates the CAA and 

the court order. 

Response: EPA is mindful that MACT 

floors must reflect achieved 

performance. EPA is also mindful that 

that costs cannot be considered by EPA 

in ascertaining the level of the MACT 

floor. See, e.g., Brick MACT, 479 F. 3d 

at 880–81, 882–83; NRDC v. EPA, 489 F. 

3d 1364, 1376 (DC Cir. 2007) (‘‘Plywood 

MACT’’); see also Cement Kiln Recycling 

Coalition v. EPA, 255 F. 3d 855, 861–62 

(DC Cir. 2001) (‘‘achievability’’ 

requirement of CAA section 112(d)(2) 

cannot override the requirement that 

floors be calculated on the basis of what 

best performers actually achieved). 

EPA has carefully developed data for 

each standard, assessing both 

technological controls and HAP inputs 

in doing so. The MACT floor variability 

methodology is discussed in a later 

response. 

Among all boilers at area sources, 

only new and existing coal-fired ones 

will need to meet MACT-based limits. 

Nevertheless, it is true that at least some 

coal-fired area source boilers will need 

to install controls to meet these 

standards, and that these controls have 

significant costs. This is part of the 

expected MACT process where, by 

definition, the averaged performance of 

the very best performers sets the 

minimum level of the standard. The 

Agency believes that it has followed the 

statute and applicable case law in 

developing its floor methodology. 

Although industry commenters 

maintain these sources cannot meet the 

standards, which are predicated on their 

own performance without adding 

controls, this contention lacks a basis in 

the record. For mercury, 6 of the 7 

boilers for which EPA has emissions 

data are meeting the MACT floor 

standards for mercury. For CO, 13 of the 

16 boilers in the MACT pool meet the 

promulgated standard. In those 

instances where commenters provided 

actual data on these plants’ 

performance, EPA took the information 

into account in developing the final 

standards. Indeed, EPA adjusted all of 

the standards based on actual data 

presented. We have emissions data on a 

limited number of area source units. 

The available information does indicate 

that at least one unit meets both the 

final PM and CO emission limits. 

Dataset for the MACT Floor Analysis 

Comment: Commenters stated 

numerous objections to the dataset used 

for the MACT floor analysis. Some 

commenters stated that it is 

inappropriate to apply limits from data 

submitted as part of the major source 

industrial boiler MACT ICR to area 

sources. Commenters objected to EPA’s 

assertion that boilers at area sources are 

similar in size and operation to major 

source boilers; one commenter noted 

that EPA did not use test data from area 

source facilities to set major source 

floors. 

Other commenters stated that the 

emission limits are significantly flawed 

because they are based on inadequate 

data and not representative of the units 

in the source category. These 

commenters stated that the data 

collected is insufficient because it 

represents the performance of less than 

1 percent of almost 183,000 existing 

area source boilers, particularly given 

that EPA based the analysis on the top 

12 percent of units for which data were 

available. Commenters further stated 

that there was insufficient data available 

to establish appropriate boiler-type 

subcategories. 

Some commenters expressed that EPA 

must include emissions data collected 

by state and local permitting authorities 

in establishing the MACT floor; these 

commenters stated that these data are 

more objective than the newer industry 

testing and are also necessary to fill in 

‘‘gaps’’ in the existing data. Other 

commenters requested that certain data 

should be excluded from the MACT 

floor analysis. For instance, some 

commenters stated that non-detect data 

should be excluded or that the analysis 

should be adjusted to account for the 

capabilities of the test methods. These 

commenters stated that the non-detect 

data results in an unreasonably low 

MACT floor; some commenters stated 

that the proposed limits are in some 

cases below the detection capability of 

the required test method. Commenters 

also stated that EPA has not justified 

using three times the detection level in 

its analysis. These commenters stated 

that this method biases the results 

towards higher HAP emissions, results 

in a hypothetical standard that is 

unrealistic and not determined as 

required by statute. 

Response: EPA acknowledges 

commenters’ concerns. As mentioned 

elsewhere in this preamble, EPA is 

required to establish MACT floor levels 

using existing emissions information. 

For all data sets, the final emission 

limits are based on the available data 

and EPA’s assessment of variability. 

Since proposal we have received 

updated data on certain boilers and 

used that data to revise our emission 

estimates from the best performing 

sources. We re-evaluated the 

information available for the area source 

category and revised the proposed 

MACT-based CO emission limits such 

that they only apply to boilers in the 

coal subcategory. As discussed above, 

based on information received during 

the public comment period, we 

determined that regulating POM 

emissions from area source biomass and 

oil boilers is not needed to meet our 

CAA section 112(c)(6) obligations; we 

only need to regulate coal-fired area 

source boilers under section 112(d)2) to 

meet the 90 percent requirement set 

forth in CAA section 112(c)(6) for POM. 

The emissions limits for CO for coalfired boilers were based on the available 

information from the ICR and state 

operating permits, as well as that 

received in comments. 

EPA disagrees with commenters who 

stated that we excluded emissions data 

collected by state and local permitting 

authorities in establishing the MACT 

floor. The available state permits 

obtained for coal-fired area source 

boilers limiting CO emissions were for 

11 units located in Ohio (3 units), and 

Illinois (8 units). We also obtained CO 

emission data from five coal-fired area 

source boilers as part of the information 

collection effort for the major source 

NESHAP. Even though the latter data 

were gathered in the course of collecting 

data on major sources, the emission data 

on these five boilers is from emission 

sources in the area source coal-fired 

boiler subcategory. 

With respect to non-detect data, EPA 

considered and accounted for nondetect data when conducting the MACT 

analysis for mercury for existing and 

new coal-fired boilers in this final rule. 

EPA developed a methodology to 

account for the imprecision introduced 

by incorporating non-detect data into 

the MACT floor calculation. At very low 

emission levels where emissions tests 

result in non-detect values, the inherent 

imprecision in the pollutant 

measurement method has a large 

influence on the reliability of the data 


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5American Society of Mechanical Engineers, 

Reference Method Accuracy and Precision 

(ReMAP): Phase 1, Precision of Manual Stack 

Emission Measurements, CRTD Vol. 60, February 

2001. 

underlying the MACT floor emission 

limit. Because of sample and emission 

matrix effects, laboratory techniques, 

sample size, and other factors, method 

detection levels normally vary from test 

to test for any specific test method and 

pollutant measurement. The confidence 

level that a value, measured at the 

detection level is greater than zero, is 

about 99 percent. The expected 

measurement imprecision for an 

emissions value occurring at or near the 

method detection level is about 40 to 50 

percent. Pollutant measurement 

imprecision decreases to a consistent 

level of 10 to 15 percent for values 

measured at a level about three times 

the method detection level.5

One approach that we believe can be 

applied to account for measurement 

variability in this situation starts with 

defining a method detection level that is 

representative of the data used in the 

data pool. The first step in this approach 

would be to identify the highest testspecific method detection level reported 

in a data set that is also equal to or less 

than the average emission calculated for 

the data set. This approach has the 

advantage of relying on the data 

collected to develop the MACT floor 

emission limit, while to some degree, 

minimizing the effect of a test(s) with an 

inordinately high method detection 

level (e.g., the sample volume was too 

small, the laboratory technique was 

insufficiently sensitive or the procedure 

for determining the detection level was 

other than that specified). 

The second step is to determine the 

value equal to three times the 

representative method detection level 

and compare it to the calculated MACT 

floor emission limit. If three times the 

representative method detection level 

were less than the calculated MACT 

floor emission limit, we would conclude 

that measurement variability is 

adequately addressed, and we would 

not adjust the calculated MACT floor 

emission limit. If, on the other hand, the 

value equal to three times the 

representative method detection level 

were greater than the calculated MACT 

floor emission limit, we would conclude 

that the calculated MACT floor emission 

limit does not account entirely for 

measurement variability. Therefore, we 

revised the approach we used for the 

proposal and, for the final rule, we used 

the value equal to 3 times the method 

detection level in place of the calculated 

MACT floor emission limit to ensure 

that the MACT floor emission limit for 

mercury accounts for measurement 

variability and imprecision. 

Variability 

Comment: Numerous commenters 

stated that the floor methodology used 

by EPA is unlawful. Some commenters 

criticized EPA’s application of the UPL 

to all the test results for all sources in 

the top twelve percent. These 

commenters stated that while EPA can 

consider variability in estimating an 

individual source’s performance over 

time, it cannot account for differences in 

performance between sources. 

Specifically, these commenters stated 

that EPA may only account for 

differences in performance between 

sources except as CAA section 112(d)(3) 

provides, by averaging the emission 

levels achieved by the sources in the top 

12 percent. Commenters stated that the 

UPL is not equivalent to the ‘‘average’’ 

emission level. For instance, some 

commenters stated that the methodology 

for the mercury and CO emission limits 

for new coal fired units does not reflect 

the emission levels achieved by the 

single best performing source; these 

commenters stated that the proposed 

method results in higher emission levels 

for new sources than the average level 

of the best 12 percent. 

Commenters further stated that EPA 

erred by relying on the 99 percent UPL 

only to reflect variability. Some 

commenters stated that EPA must 

collect and consider data on additional 

variability, such as that related to 

variable fuel quality or longer term 

variability, to supplement its analysis. 

These commenters stated that the shortterm test data are not representative of 

long-term operation of a unit nor are 

they likely to reflect the ‘‘worst 

reasonably foreseeable circumstances’’ a 

unit may experience. Other commenters 

stated that EPA should use the upper 

tolerance limit (UTL) in lieu of the UPL; 

these commenters claimed that the UTL 

is more appropriate for situations where 

the available data does not represent the 

entire population. 

Response: EPA disagrees with 

commenters and believes that the final 

emission limits appropriately account 

for variability. The Court has recognized 

that EPA may consider variability in 

estimating the degree of emission 

reduction achieved by the bestperforming sources and in setting 

MACT floors that the best performing 

sources can expect to meet ‘‘every day 

and under all operating conditions’’. See 

Mossville Environmental Action Now v. 

EPA, 370 F.3d 1232, 1241–42 (DC Cir 

2004). Furthermore, CAA section 

112(d)(3) includes a provision stating 

that the MACT floor for existing sources 

cannot be less stringent than ‘‘the 

average emission limitation achieved by 

the best-performing 12 percent of the 

existing sources (for which the 

Administrator has emissions 

information).’’ We see no statutory 

prohibition in considering inter-source 

variability of the best performing 

sources (which is all our floor 

calculation does, by considering the 

pooled variability of the best performing 

sources). Section 112(d)(3) of the CAA 

does not specify any single method of 

ascertaining an average. Considering the 

average variability among the group of 

best performing sources is well within 

the language of the provision (and was 

upheld in Chemical Manufacturers 

Association v. EPA; see 870 F. 2d at 

228). The commenters’ argument that 

‘‘average’’ can only mean average of 

emission levels achieved in 

performance tests of an individual unit 

is inconsistent with the holding in 

Mossville, 370 F. 3d at 1242, that EPA 

must account for variability in 

developing MACT floors and that 

individual performance tests do not by 

themselves account for such variability. 

Therefore, we believe that it is 

reasonable and necessary to account for 

inter-source variability of the best 

performing sources by taking the pooled 

average of the best performing sources’ 

variability. This is an aspect of 

identifying the average performance of 

those sources. 

Furthermore, EPA is confident that 

the UPL is an appropriate statistical tool 

to use in determining variability when 

there is a limited sampling of the source 

category. EPA has considered comments 

regarding suggested alternatives to the 

UPL statistic, such as the upper 

tolerance limit (UTL). Whereas a 

confidence interval covers a population 

parameter with a stated confidence, that 

is, a certain proportion of the time, a 

tolerance interval covers a fixed 

proportion of the population with a 

stated confidence. That is, confidence 

limits are limits within which we expect 

a given population parameter, such as 

the mean, to lie; statistical tolerance 

limits are limits within which we expect 

a stated proportion of the population to 

lie. Given this definition, the 99 percent 

UTL represents the value which we can 

expect 99 percent of the measurements 

to fall below 99 percent of the time in 

repeated sampling. In other words, if we 

were to obtain another set of emission 

observations from the floor sources, we 

can be 99 percent confident that 99 

percent of these measurements will fall 

below a specified level. Since you must 

calculate the sample percentile, and the 

sample sizes for the area source boiler 


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6Bhaumik, D. K. and R. D. Gibbons. 2004. An 

Upper Prediction Limit for the Arithmetic Mean of 

a Lognormal Random Variable. May 1, 2004. 

Technometrics 46(2): 239–248. doi:10.1198/ 

004017004000000284 

floor data are small, the 99th percentile 

is underestimated. Therefore, EPA notes 

that the UTL should only be used where 

one can calculate a sample percentile, 

e.g., where there is a sample size of at 

least 100. On the other hand, a 

prediction interval for a future 

observation is an interval that will, with 

a specified degree of confidence, 

contain the next (or some other prespecified) randomly selected 

observation from a population. In other 

words, the prediction interval estimates 

what future values will be, based upon 

present or past background samples 

taken. The UPL represents the value 

which we can expect the mean of 3 

future observations (3-run average) to 

fall below, based upon the results of the 

independent sample of size n from the 

same population. Given the above 

considerations, EPA notes that only the 

UPL adequately gets at the notion of 

average emissions for a small sample 

size. 

EPA has revised its default selection 

of data distributions consistent with its 

guidance document ‘‘Data Quality 

Assessment: Statistical Methods for 

Practitioners EPA QA/G–9S’’. This 

document indicates that most 

environmental data is lognormally 

distributed, so EPA has modified its 

assumptions when the results of the 

skewness and kurtosis tests result in a 

tie, or when there is not enough data to 

complete the skewness and kurtosis 

tests. With respect to the methods used 

to compute the UPL for a dataset that is 

determined to be lognormally 

distributed, EPA also considered the 

commenters suggested revisions to the 

calculations in order to avoid skewing 

the UPL by calculating the UPL of an 

arithmetic mean instead of the UPL of 

a geometric mean. To adjust the 

calculation EPA considered a scale bias 

correction approach as well as a new 

UPL equation based on a Bhaumik and 

Gibbons 2004 paper, which calculates 

‘‘An Upper Prediction Limit for the 

Arithmetic Mean of a Lognormal 

Random Variable 6’’. Given data 

availability, EPA selected the Bhaumik 

and Gibbons 2004 approach which 

addresses commenters concerns with 

the proposed computations. 

Additionally, EPA has determined 

that 99 percent UPL is appropriate for 

fuel based HAP, and a 99.9 percent UPL 

is appropriate for CO. For fuel-based 

HAP the 99 percent confidence level is 

consistent with other recent 

rulemakings (75 FR 54975). Further, as 

commenters have noted elsewhere, the 

sample sizes were limited and EPA 

determined that a level of 99 percent is 

a good compromise and represents 

emission levels that are protective of 

human health and the environment. 

Given that the subcategories had limited 

data to establish the floor calculations, 

EPA determined it was inappropriate to 

use a confidence level lower than 99 

percent. Further, for fuel based HAP 

mercury, EPA has implemented an 

additional fuel variability analysis. 

Additionally, there are well established 

control measures currently used on 

units in the source category (fabric 

filters for PM and mercury) that serve to 

mitigate, to some degree, the variability 

in emissions that can be expected. 

Given these additional considerations 

for fuel-based HAP, but recognizing the 

emission limits must be met at all times 

yet are based on short term stack test 

data, EPA selected the 99 percent 

confidence level. For CO, EPA 

considered both quantitative and 

qualitative comments received during 

the public comment period on how CO 

emissions vary with load, fuel mixes 

and other routine operating conditions. 

After considering these comments EPA 

determined that a 99.9 percent 

confidence level for CO would better 

account for some of these fluctuations. 

Finally, EPA notes that where 

appropriate, we have accounted for 

variable fuel quality. EPA first took fuel 

into consideration, among other boiler 

design factors when it divided the 

source category into subcategories. EPA 

is aware that differences between given 

types of units, and fuel, can affect 

technical feasibility of applying 

emission control techniques. As noted 

in the preamble to the June 2010 

proposed rule, EPA attempted to assess 

the impact of fuel variability for 

development of the mercury standard. 

However, no fuel analysis data from 

boilers in the top 12 percent were 

available for assessing the impact of fuel 

variability on mercury emissions. EPA 

realizes that mercury is a fuel 

dependent HAP, and that the amount of 

mercury emitted from the boiler 

depends on the amount of mercury 

contained in the fuel. For this final rule, 

we have implemented a fuel variability 

factor into the mercury emission limit 

by determining a factor relating the 

highest mercury content to the average 

mercury content in coal that may be 

used at sources comprising the best 12 

percent of sources. We also note that 

fuel usage can be reduced by improving 

the combustion efficiency of the boiler. 

Therefore, in the development of the 

final standards, we are establishing 

requirements for larger existing boilers 

(greater than 10 MMBtu/h heat input 

capacity) to conduct an energy 

assessment, and smaller boilers (both 

existing and new boilers with a heat 

input capacity less than 10 MMBtu/h) to 

meet a work practice or management 

practice requirements of a tune-up, in 

order to improve combustion efficiency. 

D. Beyond the Floor Analysis 

Comment: Several commenters 

objected to EPA’s beyond-the-floor 

determination for new area source 

boilers. Many of these commenters 

stated that the beyond the floor 

approach must consider fuel switching 

as an option. Other commenters 

objected to EPA’s beyond-the-floor 

determination for existing boilers, 

specifically stating that EPA should 

require existing facilities to either 

comply with emission limits for larger 

units, or require fuel switching to the 

cleanest fuel in their class (fuel type). 

Commenters noted that while EPA 

identified substantial emissions 

reductions for mercury and POM from 

switching coal-fired boilers to natural 

gas, EPA failed to rationalize why fuelswitching is not a technically feasible or 

economically achievable option. 

Commenters debated EPA’s stated 

concerns regarding fuel availability and 

curtailment, arguing that there is 

sufficient capacity to meet the expected 

increased demand for natural gas. 

Furthermore, these commenters stated 

that the potential increases in metallic 

HAP emissions from fuel-switching 

were minor and should be considered in 

light of overall reductions for POM. 

Response: EPA has considered this 

comment and concluded that fuel 

switching is not an appropriate option 

for the beyond the floor level of control. 

EPA originally considered whether fuel 

switching would be an appropriate 

control option for sources in each 

subcategory under the proposed rule, 

including the feasibility of fuel 

switching to other fuels used in the 

subcategory and to fuels from other 

subcategories. This consideration 

included determining whether 

switching fuels would achieve lower 

HAP emissions. We also gave 

consideration to whether fuel switching 

could be technically achieved by boilers 

in the subcategory considering the 

existing design of boilers and the 

availability of various types of fuel. 

After considering these factors, we 

determined that fuel switching was not 

an appropriate control technology for 

purposes of determining the MACT 

floor level or beyond the floor level of 

control for any subcategory. This 

decision is based on the overall effect of 


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fuel switching on HAP emissions, 

technical and design considerations 

discussed previously in the preamble to 

the proposed June 2010 rule (75 FR 

31896), and concerns about fuel 

availability. This determination is 

discussed in the memorandum 

‘‘Development of Fuel Switching Costs 

and Emission Reductions for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters National Emission 

Standards for Hazardous Air 

Pollutants—Area Source’’ located in the 

docket. 

Energy Assessments 

Comment: Several commenters 

disagreed with EPA’s determination to 

require energy assessments as a beyond 

the floor option. Commenters 

specifically stated that EPA cannot 

require an energy assessment because an 

assessment is not an emission standard 

and there is no proven relationship 

between HAP emissions and the 

assessment. Other commenters argued 

that the proposed requirements for an 

energy assessment were not stringent 

enough; these commenters stated that an 

energy assessment cannot impose 

standards more stringent than the 

MACT floor. For instance, one 

commenter argued that if EPA did not 

require implementation of the energy 

assessment findings, no reductions in 

fuel use or HAP would result. The 

commenter further asserted that even an 

implemented energy assessment would 

not reduce HAP emissions consistent 

with the requirements of CAA section 

112(d)(2). One commenter specifically 

stated that by only considering energy 

audits, EPA did not consider the full 

range of potential emission measures. 

Other commenters argued that EPA 

does not have the authority to require an 

energy assessment, and that the 

proposed requirements were ‘‘too broad’’ 

or ‘‘too intrusive.’’ Commenters were 

concerned that the energy assessment 

would include not only the affected 

source, but also the entire facility, 

which EPA does not have the authority 

to regulate. 

Response: EPA disagrees with 

commenters that state that EPA does not 

have the authority to require an energy 

assessment. An energy assessment is an 

appropriate beyond-the-floor control 

technology because it is one of the 

measures identified in CAA section 

112(d)(2). CAA section 112(d)(2) states 

that ‘‘Emission standards promulgated 

* * * and applicable to new or existing 

sources * * * is achievable * * * 

through application of measures, 

processes, methods, systems or 

techniques including, but not limited to 

measures which— 

(A) Reduce the volume of, or 

eliminate emissions of, such pollutants 

through process changes, substitution of 

materials or other modifications, * * * 

(D) Are design, equipment, work 

practice, or operational standards 

(including requirements for operator 

training or certification) as provided in 

subsection (h), or 

(E) Are a combination of the above.’’ 

The purpose of an energy assessment 

is to identify energy conservation 

measures (such as, process changes or 

other modifications to the facility) that 

can be implemented to reduce the 

facility energy demand which would 

result in reduced fuel use. Reduced fuel 

use will result in a corresponding 

reduction in HAP, and non-HAP, 

emissions. Thus, an energy assessment, 

in combination with the MACT 

emission limits will result in the 

maximum degree of reduction in 

emissions as required by CAA section 

112(d)(2). 

It is not EPA’s intent to require an 

energy assessment for the entire facility; 

the energy assessment is only applied to 

existing boilers and their energy use 

systems located at area sources. EPA 

acknowledges that the proposed 

definition for ‘‘energy assessment’’ is 

unclear, and we have revised this final 

rule to clarify the definition with 

respect to the requirements of Table 3 of 

subpart JJJJJJ (see 40 CFR 63.11237). In 

order to account for variability among 

boiler systems and energy use systems 

and to ensure that affected sources can 

adequately comply with the 

requirements, we have distinguished the 

requirements for the energy assessment 

based on the heat input use of the 

affected source. We have also added a 

definition for ‘‘energy use systems’’ to 

clarify the components for each boiler 

system and energy use system which 

must be considered during the energy 

assessment, including elements such as 

combustion management, thermal 

energy recovery, energy resource 

selection, and the steam end-use 

management of each affected boiler. 

These revisions clarify that an energy 

assessment is only required for those 

portions of the facility using the energy 

generated from the affected boiler 

system. 

Additionally, a facility may elect, but 

is not required, to implement the costeffective energy conservation measures 

identified in the energy assessment. 

Because we lack information on 

whether implementation of the 

conservation measures will prove costeffective or economically feasible for 

facilities, we are allowing the owner or 

operator to determine the 

implementation of energy conservation 

measures identified in the energy 

assessment. EPA notes that the cost of 

an energy assessment is minimal, in 

most cases, compared to the cost for 

testing and monitoring to demonstrate 

compliance with an emission limit. 

Furthermore, the costs of any energy 

conservation improvement for the 

owner or operator will be offset, at least 

in part, by the cost savings in lower fuel 

costs. Therefore, after considering the 

structure of the requirement, the 

incentives it presents, and the likely 

behavior of sources, it is our judgment 

that sources will find it cost-effective to 

implement the conservation measures 

identified in the energy assessment, and 

we have elected to promulgate 

requirements for an energy assessment 

for all existing boilers with a heat input 

capacity greater than 10 MMBtu/h as a 

beyond the floor option or GACT. 

EPA disagrees with commenters that 

state that the option for an energy 

assessment included in the June 2010 

proposed rule is not stringent enough. 

An energy assessment refers to a process 

which involves a thorough examination 

of potential savings from energy 

efficiency improvements, pollution 

prevention, and productivity 

improvement. It leads to the reduction 

of pollutants through process changes 

and other efficiency modifications. 

Improving energy efficiency reduces 

negative impacts on the environment as 

well as operating and maintenance 

costs; improvements in energy 

efficiency result in decreased fuel use 

which results in a corresponding 

decrease in emissions (both HAP and 

non-HAP) from the boiler. The revised 

definitions of ‘‘energy assessment’’ and 

‘‘energy use systems,’’ as discussed 

above, have been expanded to include 

the specific components that must be 

considered for an energy assessment. 

These changes elucidate the in-depth 

nature of the energy assessment, which 

requires identifying all energy 

conservation measures appropriate for a 

facility given its operating parameters. 

EPA proposed the energy assessment 

as a beyond the floor option for existing 

area source boilers having a heat input 

capacity of greater than 10 MMBtu/h, 

rather than focusing on smaller boilers. 

We also examined other emission 

measures currently in place. EPA did 

not have sufficient information to 

determine if requiring an energy 

assessment for area boilers with a heat 

input capacity of less than 

10 MMBtu/h is economically feasible. 

For boilers with a heat input capacity 

less than 10 MMBtu/h, the data that we 

have suggests that area source boilers 

typically conduct boiler tune-ups. We 

also examined work practices listed in 


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15574 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

7Case studies and success stories highlighting 

energy savings achieved by companies that have 

participated in energy assessments can be found at 

http://www1.eere.energy.gov/industry/ 

saveenergynow/case_studies.html and at the 

Department of Energy’s Energy Assessment Centers 

Database http://iac.rutgers.edu/database. 

state regulations for area source boilers 

with a heat input capacity less than 10 

MMBtu/h. These regulations included 

tune-ups (10 states), operator training 

(one state), periodic inspections (two 

states), and operation in accordance 

with manufacturer specifications (one 

state). 

When energy assessments have been 

undertaken in the past, they typically 

result in 10 to 15 percent reduction in 

fuel use, according to the Department of 

Energy who has conducted energy 

assessment at selected manufacturing 

facilities.7 While the efficiency gains 

may be somewhat less when the 

assessment is mandated for a source 

rather than voluntary, the absence of a 

requirement to implement the particular 

findings of the assessment should still 

result in measures being implemented 

that are cost-effective for the source and 

in emission reductions over and above 

what is otherwise required by MACT 

and other GACT measures. Therefore, 

we elected to promulgate requirements 

for an energy assessment for all existing 

boilers with a heat input capacity 

greater than 10 MMBtu/h, and require 

area source boilers in the biomass and 

oil subcategories with a heat input 

capacity of greater than 10 MMBtu/h to 

meet the management practice standard 

of a tune-up. These requirements 

represent the generally available and 

cost-effective pollution reduction 

measures that are already required or in 

place. 

E. GACT Standards 

Comment: Commenters stated that the 

GACT standards should consist of work 

practice standards, rather than numeric 

emission limits. One commenter 

specifically stated that in order to 

reduce the burden on small facilities 

operating boilers, EPA should establish 

work practice standards for CO instead 

of emission limits, referencing 

requirements from the state of New 

Jersey. Other commenters stated that the 

emission limits and testing procedures 

proposed for new boilers impose 

onerous capital and annual costs on 

potential project owners, which 

typically include schools, small 

businesses, hospitals, and other 

institutions in rural areas. Some 

commenters stated that the CO emission 

limits were not achievable for small 

boilers over a range of operating 

periods, and that EPA should consider 

work practice standards in order to 

account for load variability. 

Response: CAA section 112(d)(5) 

allows the Administrator, with respect 

to area sources, to promulgate standards 

which provide for the use of generally 

available control technologies or 

management practices to reduce 

emissions of HAP. Therefore, with 

respect to mercury and POM from area 

source boilers classified as biomassfired or oil-fired, as well as with respect 

to other urban HAP besides POM, we 

have developed standards that reflect 

GACT for these two area source 

categories. 

While the June 2010 proposed rule 

(75 FR 31896) set numeric MACT 

standards for CO (as a surrogate 

pollutant for the individual urban 

organic HAP) and mercury, and numeric 

GACT emission limits for PM (as a 

surrogate for the individual urban metal 

HAP), EPA has revised the standards for 

area source boilers classified in the 

biomass and oil subcategories. Rather 

than require a numeric MACT emission 

limit for POM, new and existing area 

source boilers in the biomass or oil 

subcategories must meet the 

requirements of GACT, which are 

management practice standards as 

described in Table 2 of 40 CFR part 63, 

subpart JJJJJJ. 

However, for the purposes of 

regulating PM from new area source 

boilers, EPA has determined that the 

GACT standards should consist of 

numeric emission limits. PM is used as 

a surrogate for urban metals, which we 

are required to regulate pursuant to 

CAA section 112(c)(6). The data that we 

have available suggests that the control 

technologies currently used by facilities 

in the source category for reduction of 

non-mercury metallic HAP and PM are 

multiclones, which are generally used at 

area sources using solid fuel. We 

previously determined during the 

development of the June 2010 proposed 

rule that these controls are generally 

available and cost effective for new area 

source boilers. Additionally, we noted 

that new area source boilers with heat 

input capacity of 30 MMBtu/h or greater 

are subject to the NSPS for boilers 

(either subpart Db or Dc of 40 CFR part 

60), which regulate emissions of PM and 

require performance testing. 

Furthermore, new coal-fired area source 

boilers with heat input capacity of 10 

MMBtu/h or greater will likely require 

a PM control device to comply with the 

proposed mercury MACT standard and 

required performance testing. Therefore, 

a numerical limit for PM consistent with 

the devices required to meet mercury 

MACT should be generally achievable. 

EPA has also revised the PM emission 

limits for area source boilers with a heat 

input capacity between 10 and 30 

MMBtu/h; these limits have been 

revised to reflect the performance of 

GACT, which are multiclones. The PM 

GACT limits were calculated as the 

average of the data from units using 

GACT technology. EPA has determined 

that the promulgated numeric emission 

limits for PM are appropriate GACT 

standards for new area source boilers 

with a heat input capacity greater than 

10 MMBtu/h. For new boilers with a 

heat input capacity less than 10 

MMBtu/h, GACT is a management 

practice of a tune-up because, as 

previously discussed, there are 

technical and economic limitations of 

conducting PM testing on boilers with 

small diameter stacks. 

Tune-Ups 

Comment: Several commenters 

expressed concern regarding proposed 

work practice standards for existing area 

source boilers, including the 

requirement of a tune-up for control of 

POM and mercury. Commenters stated 

that tune-ups aimed at reducing CO may 

increase NOX emissions, reduce 

combustion efficiency, and/or increase 

fuel use. Commenters noted that many 

typical tune-up requirements, including 

states’ requirements, are aimed at 

minimization of NOX. and not CO. 

These commenters stated that the 

proposed tune-up requirements could 

violate the state tune-up requirements 

due to increases of NOX. Multiple 

commenters requested that EPA specify 

that tune-ups consider optimizing 

efficiency and limiting increases of 

NOX, and not only require minimizing 

CO. 

Other commenters requested that EPA 

allow the use of portable instruments to 

measure CO for the tune-up 

requirements. Several commenters 

requested that EPA clarify that, for the 

tune-up procedures, gases do not have 

to be measured using EPA Reference 

Methods. These commenters indicated 

that requiring EPA Methods would 

increase the cost burden for small 

facilities. 

Response: EPA disagrees with 

commenters and is requiring tune-ups 

as a work practice standard for coalfired area source boilers with a heat 

input capacity less than 10 MMBtu/h 

and as a management practice standard 

for all biomass-fired and oil-fired area 

source boilers. EPA acknowledges that 

that a tune-up designed to specifically 

decrease CO emissions from an area 

source boiler would potentially increase 

emissions of NOX. However, it was not 

EPA’s intent to require that area source 


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boilers be specifically tuned for the 

reduction of CO emissions, but rather to 

require good combustion practices 

(GCP) by ensuring that area source 

boilers are tuned to manufacturer’s 

specifications. As discussed in the 

preamble to the June 2010 proposed 

rule, boilers may be, at best, 85 percent 

efficient, and untuned boilers may have 

combustion efficiencies of 60 percent or 

lower. Furthermore, as the combustion 

efficiency decreases, fuel usage 

increases to maintain energy output 

resulting in increased emissions. A 

tune-up performed to the 

manufacturer’s specifications would 

ensure the highest energy efficiency and 

reduce fuel usage, which will ultimately 

reduce HAP emissions. As commenters 

noted, the tune-up requirements 

specified by area source boiler 

manufacturers are generally aimed at 

reducing NOX and would not increase 

emissions of NOX. The tune-up 

provisions incorporated in this final 

rule for area source boilers require that 

the owner or operator measure the 

concentration in the effluent stream of 

CO in ppm, by volume, dry basis 

(ppmvd), before and after adjustments 

are made to the boiler. EPA does not 

specify the instrument that must be 

used for measuring these 

concentrations, and allows owners and 

operators to choose the method of 

measurement. Therefore, EPA agrees 

with commenters that portable 

instruments are permissible for this 

purpose. 

F. Subcategories 

Comment: Several commenters raised 

concerns regarding the subcategories 

defined by EPA in the development of 

the proposed rule. Multiple commenters 

argued that the proposed subcategories 

are unlawful and arbitrary because they 

are not based on different classes, types, 

or sizes. At least one commenter 

specifically stated that the proposed 

subcategorization defied the explicit 

recommendation of the Small Entity 

Representatives (SERs) to the Small 

Business Advocacy Review (SBAR) 

Panel, which recommended that ‘‘EPA 

should subcategorize based on fuel type, 

boiler type, duty cycle, and location.’’ 

Many of these commenters suggested 

subcategories based on limited use, type 

of biomass (wood, bark, agricultural 

residue, moisture level) and/or coal 

(bituminous, anthracite), boiler design 

(stoker, fluidized bed, or suspension), 

heat input capacity smaller than 1 

MMBtu/h, and combustion of secondary 

materials. Other commenters 

recommended that the same 

subcategories applied to major sources 

should be used for area sources. 

Response: EPA disagrees with 

commenters. Section 112(d)(1) of the 

CAA states ‘‘the Administrator may 

distinguish among classes, types, and 

sizes of sources within a category or 

subcategory’’ in establishing emission 

standards. Thus, we have discretion in 

determining appropriate subcategories 

based on classes, types, and sizes of 

sources. We used this discretion in 

developing subcategories for the boiler 

area source category. Through 

subcategorization, we are able to define 

subsets of similar emission sources 

within a source category if differences 

in emissions characteristics, technical 

feasibility of applying emission control 

techniques, or opportunities for 

pollution prevention exist within the 

source category. The design, operating, 

and emissions information that EPA 

reviewed during the area source 

rulemaking indicates the need to 

subcategorize based on boiler design 

which is based on the fuel type. EPA 

continues to believe that this 

subcategorization is appropriate. As 

noted in the preamble to the June 2010 

proposed rule, boiler systems are 

designed for specific fuel types (e.g., 

coal, biomass, oil or a mixture/ 

combination) and will encounter 

problems if a fuel or mixture with 

characteristics other than those 

originally specified is fired. EPA has 

noted that emissions from boilers 

burning coal, biomass, and oil will also 

differ, and that HAP formation, 

including emissions of metals and 

mercury, is dependent upon the 

composition of the fuel. Organic HAP, 

on the other hand, are formed from 

incomplete combustion, which are a 

function of time, turbulence, and 

temperature, and are influenced by the 

design of the boiler and dependent in 

part on the type of fuel being burned. 

Because these different types of boilers 

have different emission characteristics 

which may influence the feasibility and 

effectiveness of emission control, we 

believe that subcategorizing them by 

fuel type is appropriate. 

Additionally, EPA notes that we lack 

sufficient emissions data for area source 

boilers to develop limits for additional 

subcategories. We have elected to 

establish different subcategories for the 

major and area source rulemakings, as 

major source boilers have a different 

scale of operation and often different 

combustor designs. There is also more 

detailed emissions data available for the 

major source category, which favors the 

development of more specific 

subcategories. Because we lack the same 

level of detail for the area source 

category, EPA has determined that it 

would be inappropriate to establish the 

same subcategories for major and area 

source boilers. 

We believe that area source boilers are 

generally designed to burn a standard 

fuel type and less capable of switching 

fuel type as some major source boilers. 

However, as was done for the major 

source NESHAP, we have redefined 

how to determine the appropriate 

subcategory. Instead of considering 

whether the boiler is designed to 

combust at least 10 percent coal as the 

first step (as proposed), the first step in 

determining the appropriate subcategory 

is to consider the percentage of biomass 

that is combusted in the boiler.ies are 

determine. 

In addition, as discussed in the 

comments below, we have established a 

small units subcategory for each type of 

fuel (area source boilers with a heat 

input capacity of less than 10 MMBtu/ 

h), and see no further need for smaller 

subcategories. We have also adjusted the 

definition for each fuel subcategory to 

account for the combustion of secondary 

materials. The definitions have been 

clarified to specify that the fuel 

subcategories are based on the fuel that 

the boiler is designed to combust, rather 

than the actual fuel that the boiler is 

combusting. 

Finally, as discussed earlier in this 

section, we have revised the MACT and 

GACT limits for the coal, oil, and 

biomass subcategories in this final rule. 

Existing oil and biomass-fired boilers 

are no longer required to meet emission 

limits, and are only required to meet 

management practice standards under 

this final rule. Furthermore, coal-fired 

boilers with a heat input capacity of less 

than 10 MMBtu/h are only required to 

meet work practice standards. While 

more stringent limits under this final 

rule may have required subcategories 

based on the size of the unit, EPA has 

determined that the subcategories 

chosen are reasonable based on the 

applicable requirements of this final 

rule. 

Combustion of Secondary Fuels 

Comment: Multiple commenters 

sought clarity for the combustion of 

secondary materials and/or alternative 

fuels within the proposed subcategories 

for area source boilers. Several of these 

commenters requested clarification of 

the defined fuels for the biomass, coal, 

and oil-fired subcategories, as well as 

additional clarification regarding gasfired boilers. Some commenters stated 

that EPA’s determination that the 

boilers subject to this rule do not 

combust any non-hazardous secondary 

materials is erroneous, and that to not 


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consider standards for units burning 

secondary materials would be unlawful. 

Many commenters recommended that 

EPA classify boilers based on 

predominant use of a particular fuel; 

several commenters recommended 

redefining the subcategories to allow 

minimal burning of other fuels or for 

further clarification. For instance, some 

commenters expressed concern 

regarding ‘‘combination boilers’’ (boilers 

that co-fire coal in an amount greater 

than 10 percent heat input basis with at 

least 10 percent biomass), which do not 

cleanly fit into either the coal-fired 

boiler subcategory or the biomass-fired 

boiler subcategory. Other commenters 

argued that the definition of gas-fired 

boilers should allow for units burning 

less than 10 percent liquid fuels. Many 

of the commenters suggested alternative 

definitions for the proposed 

subcategories or provided alternative 

thresholds. 

Alternatively, there were some 

commenters who expressed concern 

regarding the use of alternative fuels. 

Commenters specifically stated that 

allowing 10 percent alternative fuel use, 

or use of multiple alternatives from year 

to year, would create significant 

enforcement issues for states without 

detailed requirements for tracking, 

recordkeeping, and reporting. 

Response: EPA has considered these 

comments and revised the subcategories 

based on a revised MACT floor 

approach. As discussed in Section IV.A 

of this preamble, we have redefined the 

coal, biomass and oil subcategories for 

area source boilers to clarify the fuel 

inputs that define each subcategory. 

While the subcategories under the 

proposed rule accounted for secondary 

materials such as biomass, liquid or 

gaseous fuels combusted in combination 

with traditional fuels, we wished to 

clarify each subcategory in order to 

account for the combustion of an array 

of secondary fuels. Area source boilers 

combusting coal, biomass or oil may 

also combust secondary materials as 

part of their fuel mix. It was not our 

intent to exclude boilers combusting 

these non-hazardous secondary 

materials that do not meet the definition 

of ‘‘solid waste’’ from the coal, biomass 

or oil-fired subcategories. Therefore, we 

have revised the definition for each 

subcategory to account for the 

combustion of these non-hazardous 

secondary materials. 

For instance, the proposed rule 

limited the coal subcategory to boilers 

combusting coal or coal in combination 

with biomass, liquid, or gaseous fuels. 

We have redefined the coal subcategory 

to include boilers that burn any solid 

fossil fuel and no more than 15 percent 

biomass on an annual heat input basis. 

‘‘Solid fossil fuels’’ has been defined to 

include, but not limited to, coal, 

petroleum coke, coal refuse, and tire 

derived fuel (TDF). Similarly, we have 

revised the biomass subcategory to 

account for boilers that may burn 

biomass and secondary materials. The 

biomass subcategory includes boilers 

combusting at least 15 percent of 

biomass. This definition differentiates 

these primarily biomass-fired boilers 

from the coal subcategory. Additionally, 

the oil subcategory has been revised to 

include boilers that burn any liquid fuel 

but are not included in either the coal 

or biomass subcategories. 

Based on new data submitted during 

the public comment period, EPA has 

determined that area source boilers may 

combust secondary materials. Data 

submitted indicates that as much as 15 

percent of secondary materials, or 

alternative traditional fuel, may be 

mixed without causing problems with 

boiler operations. We wished to 

differentiate boilers combusting greater 

than 15 percent of biomass from the 

remaining subcategories, as these fuels 

will have higher rates of organic HAP 

due to the higher moisture content of 

biomass compared to fossil fuel. The 

revised definitions for the coal, biomass 

and oil subcategories clarify this by 

establishing the fuel type and the input 

ratio of each fuel type combusted. 

Therefore, the revised definitions more 

accurately reflect EPA’s intent to 

include and account for boilers 

combusting secondary materials in the 

coal, biomass, and oil subcategories and 

the effect of biomass on the combustion 

process. 

Comment: A number of commenters 

requested that EPA provide exemptions 

for specific unit types, including limited 

use boilers, recovery boilers, hot water 

heaters, boilers firing ultra low sulfur #2 

fuel oil, and boilers with a heat input 

capacity of less than 1 MMBtu/h. Other 

commenters stated that EPA is not 

justified in providing an exemption for 

gas-fired boilers. 

Response: As noted in Section VII of 

the proposed June 2010 rule, in the 

Federal Register notice ‘‘Source 

Category Listing for Section 112(d)(2) 

Rulemaking Pursuant to Section 

112(c)(6) Requirements,’’ (63 FR 17838, 

17849), Table 2 (1998), EPA identified 

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ ‘‘Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion,’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ as source categories 

‘‘subject to regulation’’ for purposes of 

CAA section 112(c)(6). Notably, gasfired units are not included in the 

source category listing for area source 

boilers. Without such a listing, EPA 

cannot address gas-fired boilers in this 

regulation. We have also included in 

this final rule an exemption for hot 

water heaters because these units are, as 

defined in this final rule, considered 

residential boilers. In addition, recovery 

boilers would be exempt because they 

are regulated under another section 112 

MACT standard (See 40 CRF part 63, 

subpart MM). 

Conversely, EPA is required to set 

standards for other unit types, including 

limited use boilers and boilers firing 

ultra low sulfur fuel oil. These boilers 

are included in the source category 

listing for CAA section 112(d)(2) and 

emit the pollutants identified in CAA 

section 112(c)(3). As discussed above, 

EPA has set appropriate MACT and 

GACT limits to boilers based on fuel 

type and size, including area source 

boilers with a heat input capacity of less 

than 10 MMBtu/h. EPA also notes that 

waste heat boilers have been excluded 

from the definition of boiler. 

G. Startup, Shutdown, and Malfunction 

Comment: Several commenters stated 

that a separate standard must be 

developed for periods of startup and 

shutdown. Commenters stated that 

requiring emission limits during SSM 

directly conflicts with the requirement 

that MACT be achievable and is 

technically feasible; therefore EPA 

could not require emission limits during 

periods of SSM. Some commenters 

requested a separate standard for CO for 

startup; at least one commenter 

specifically stated that many area source 

boilers must operate under conditions 

driven by safety considerations, 

operational concerns, and warranty 

requirements that would likely generate 

unavoidable increases in CO emissions 

during startup and shutdown. The 

commenter therefore concluded that 

requiring a CO emission limit during 

startup and shutdown would not only 

be technically unachievable, but would 

promote unsafe and improper operation. 

Several commenters suggested that work 

practice standards are more appropriate 

than emission limits, citing a lack of 

relevant data for periods of SSM. Other 

commenters specifically objected to 

EPA’s decision to base the SSM 

requirements on data from the proposed 

major source NESHAP for industrial, 

commercial, and institutional boilers 

and stated that the data from the 

proposed major source rule cannot be 

applied to area sources. 

Response: EPA has considered these 

comments and has revised this final rule 

to incorporate a work practice standard 


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for periods of startup and shutdown. As 

part of the development of the proposed 

rule, we reviewed the cost information 

for CO CEMS provided by commenters 

on the NESHAP for major source boilers 

and determined that requiring CO CEMS 

for units with heat input capacities 

greater or equal to 100 MMBtu/hr was 

reasonable. However, EPA has revised 

this final rule to only require emission 

limits for mercury and CO for coal-fired 

boilers. Furthermore, we are only 

requiring sources to perform a work 

practice standard, following the 

manufacturer’s recommended 

procedures, to demonstrate compliance 

with the emission limits for area source 

coal-fired boilers during periods of 

startup and shutdown. Based on the 

available dataset for facilities in the 

affected area source category, EPA 

determined that there are currently no 

existing coal-fired boilers with a heat 

input capacity greater than 100 MMBtu/ 

h located at area sources. Coal-fired 

boilers with a heat input capacity of 

greater than 50 MMBtu/h are generally 

major sources of HAP. Therefore, 

requiring CEMS for boilers of this size 

is unnecessary for the defined source 

category. 

In lieu of CEMS, we also considered 

whether requirements for performance 

testing would be feasible for area source 

boilers during periods of startup and 

shutdown. Upon review of these 

requirements, EPA determined that it is 

not feasible to require stack testing—in 

particular, to complete the multiple 

required test runs—during periods of 

startup and shutdown due to physical 

limitations and the short duration of 

startup and shutdown periods. 

Therefore, a separate standard must be 

developed for these periods. 

In regards to malfunctions, EPA had 

previously determined in the 

development of the proposed rule that 

malfunctions should not be viewed as a 

distinct operating mode and, therefore, 

any emissions that occur at such times 

do not need to be factored into 

development of CAA section 112(d) 

standards, which, once promulgated, 

apply at all times. As discussed in 

Section III.E of this preamble, EPA has 

added to this final rule an affirmative 

defense for civil penalties for 

exceedances of numerical emission 

limits that are caused by malfunctions. 

Therefore, as allowed under CAA 

section 112(h), we are requiring a work 

practice standard for all coal-fired area 

source boilers during periods of startup 

and shutdown. The work practice 

standard requires following the boiler 

manufacturer’s specifications for 

periods of startup and shutdown. 

H. Compliance Requirements 

Rationale for Demonstrating Compliance 

Comment: Several commenters 

expressed concern that, given the large 

numbers of boilers that would be 

affected by the proposed rule and the 

limited capacity of existing vendors, 

contractors, and engineers, a 3-year time 

period would not be sufficient to allow 

completion of all of the required 

modifications. 

Response: EPA has re-evaluated the 

compliance dates for this final rule 

following the revised MACT and GACT 

standards. We have revised the initial 

compliance dates for existing affected 

sources according to the applicable 

provisions for each affected source (e.g., 

work practice or management practice 

standards, emission limits, and/or an 

energy assessment), as discussed in 

Section VI.E of this preamble. EPA has 

determined that existing sources subject 

to a work practice standard of a tune-up 

must comply with this final rule no later 

than one year after publication of this 

final rule. We have determined that one 

year is adequate time for affected 

sources to meet the work practice or 

management practice standard, which 

includes a tune-up based on the 

manufacturer’s recommendations. 

Existing sources subject to an emission 

limit or an energy assessment 

requirement are required to comply 

with this final rule no later than 3 years 

after publication of the final rule. 

Section 112(i)(3)(B) allows EPA, on a 

case-by-case basis to grant an extension 

permitting an existing source up to one 

additional year to comply with 

standards if such additional period is 

necessary for the installation of controls. 

The EPA feels that this provision is 

sufficient for those sources where the 3- 

year deadline would not provide 

adequate time to retrofit as necessary to 

comply with the requirements of the 

standard. 

Comment: Commenters objected to 

proposed requirements to use CEMS 

and in some circumstances COMS. 

Commenters stated that these 

requirements are extremely burdensome 

on area sources considering the testing 

requirements and costs, and that the 

requirements for CO CEMS for units less 

than 100 MMBtu/h are too onerous. 

Commenters noted that many units at 

this size in the industrial and 

institutional sector do not operate 

frequently; therefore the cost of 

installing CO CEMS was not justified for 

units with such limited operation. Other 

commenters argued that requiring 

boilers to test for CO poses a significant 

regulatory burden. Several commenters 

stated that the proposed testing 

frequency was burdensome. 

Response: EPA has considered these 

comments, and we have revised the 

proposed continuous compliance 

requirements to not require a CO CEMS 

for area source boilers. Per the revised 

MACT and GACT determinations, this 

final rule only requires emission limits 

for mercury and CO for coal-fired units. 

Therefore, for new and existing coal 

units with a heat input capacity greater 

than 10 MMBtu/h, we are requiring 

stack testing every 3 years to 

demonstrate compliance with the CO 

emission limits. In the development of 

the proposed rule, we reviewed the cost 

information for CO CEMS provided by 

commenters on the NESHAP for major 

source boilers and determined that 

requiring CO CEMS for units with heat 

input capacities greater or equal to 100 

MMBtu/h was reasonable. However, 

based on a review of the available 

dataset for facilities in the affected area 

source category, we have determined 

that there are currently no existing coalfired boilers with a heat input capacity 

greater than 100 MMBtu/h located at 

area sources. Therefore, requiring CEMS 

for coal-fired boilers of this size is 

unnecessary for the defined source 

category. Additionally, boilers in the 

biomass and oil subcategories with a 

heat input capacity greater than 10 

MMBtu/h are not required to meet 

emission limits for CO in this final rule; 

these boilers are subject to the 

management practice standards in Table 

2 of 40 CFR part 63, subpart JJJJJJ, and 

therefore, no CO testing is required for 

these units. 

I. Cost/Economic Impacts 

Comment: Multiple commenters 

stated that the economic impacts of the 

proposed rule were significantly 

underestimated. Many commenters 

stated that the CO limits would require 

costly controls, and specifically, that the 

cost of particulate control for biomass 

boilers was severely underestimated. 

Other commenters stated that EPA made 

erroneous assumptions in performing 

the cost calculations. For instance, one 

commenter stated that EPA does not 

have enough data to support the 

assumption that fabric filters alone will 

be sufficient for area source coal-fired 

boilers to meet the proposed mercury 

limit. 

Response: In light of changes to this 

final rule, EPA believes that these 

concerns are no longer an issue. We 

have revised the costs estimates for this 

final rule to reflect EPA’s determination 

of the final MACT standards for coalfired boilers and GACT standards for 

biomass and oil-fired boilers. For 


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instance, EPA is only requiring 

particulate emission limits for new 

boilers with a heat input capacity of 

greater than 10 MMBtu/h; smaller 

boilers must only meet the management 

practice standard of a tune-up. These 

changes have significantly decreased the 

costs presented in the proposed June 

2010 rule. Additionally, commenters 

provided additional cost information 

during the public comment period; EPA 

has incorporated this information into 

the analysis for this final rule. Based on 

this re-analysis, EPA has determined 

that fabric filter controls are generally 

available and cost effective for new area 

source boilers. As noted previously, 

new area source boilers with a heat 

input capacity of 30 MMBtu/h or greater 

are subject to the NSPS for boilers 

(either subpart Db or Dc of 40 CFR part 

60), which regulate emissions of PM and 

require performance testing. 

Furthermore, new coal-fired area source 

boilers will likely require a PM control 

device to comply with the proposed 

mercury MACT standard and required 

performance testing. We determined in 

the context of the major source 

rulemaking, and from further analysis of 

new data submitted during the public 

comment period, that fabric filters are 

the most effective technology employed 

by industrial, commercial, and 

institutional boilers for controlling 

mercury and particulate emissions. 

Therefore, EPA has determined it is 

appropriate and cost-effective to 

estimate the cost of compliance based 

on fabric filters for new area source 

boilers. 

Comment: Some commenters stated 

that this final rule would have 

substantial impacts on rural 

communities. Commenters noted that 

many rural communities rely upon or 

significantly benefit from the use of 

biomass boilers for energy at 

manufacturing facilities, schools and 

hospitals. These commenters stated that 

the proposed rule will negatively impact 

both boiler owners and fuel suppliers in 

these communities. Similarly, other 

commenters stated that this final rule 

would have a significant adverse impact 

on the use of biomass renewable energy 

throughout the economy. 

Response: In light of the changes 

made to the final regarding biomassfired area source boilers, we believe 

these concerns are no longer an issue. In 

the final rule, existing biomass area 

source boilers are only subject to the 

management practice of a tune-up and 

only existing biomass-fired area source 

boilers with a heat input capacity of 10 

MMBtu/h or greater are required to have 

an energy assessment performed. There 

are no testing or monitoring 

requirements in this final rule for 

existing biomass-fired area source 

boilers. For a typical existing biomassfired boilers, this change resulted in 

reducing the annualized cost of 

compliance from about $420,000 to 

about $2,200. 

New biomass-fired area source boilers 

with a heat input capacity of 10 

MMBtu/h or greater are only subject to 

a PM emission limit which requires a 

PM test be conducted once every 3 

years. 

J. Title V Permitting Requirements 

In response to comments received and 

after further evaluation of the record, 

EPA has decided to exempt all area 

sources subject to this subpart from title 

V permitting. In evaluating the record, 

we have determined that observations 

and data we have relied upon in other 

rulemakings for distinguishing between 

sources that became synthetic area 

sources due to controls and other 

synthetic and natural area sources did 

not necessarily apply to this source 

category. Therefore, we lack sufficient 

information at this juncture to 

distinguish the sources which have 

applied controls to boilers in order to 

become area sources from other 

synthetic and natural area sources. As a 

result, the rationale for exempting most 

area sources subject to this rule as 

explained in the proposal preamble (see 

pages 31910 to 31913) is also now 

relevant for sources which we proposed 

to permit. Thus, no area sources subject 

to this subpart are required to obtain a 

title V permit as a result of being subject 

to this subpart. 

A source subject to this subpart may 

be subject to title V permitting for 

another reason or reasons, e.g., being 

located at a major source. If more than 

one requirement triggers a source’s 

obligation to apply for a title V permit, 

the 12-month timeframe for submitting 

a title V application is triggered by the 

requirement which first causes the 

source to be subject to title V. See 40 

CFR 70.3(a) and (b) or 71.3(a) and (b). 

VI. Relationship of This Action to CAA 

Section 112(c)(6) 

CAA section 112(c)(6) requires EPA to 

identify categories of sources of seven 

specified pollutants to assure that 

sources accounting for not less than 90 

percent of the aggregate emissions of 

each such pollutant are subject to 

standards under CAA section 112(d)(2) 

or 112(d)(4). EPA has identified 

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion,’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ as source categories that 

emit two of the seven CAA section 

112(c)(6) pollutants: POM and mercury. 

(The POM emitted is composed of 16 

polyaromatic hydrocarbons (PAH).) In 

the Federal Register notice, Source 

Category Listing for Section 112(d)(2) 

Rulemaking Pursuant to Section 

112(c)(6) Requirements, 63 FR 17838, 

17849, Table 2 (April 10, 1998), EPA 

identified ‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion,’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ as source categories 

‘‘subject to regulation’’ for purposes of 

CAA section 112(c)(6) with respect to 

the CAA section 112(c)(6) pollutants 

that these units emit. 

Specifically, as by-products of 

combustion, the formation of POM is 

effectively reduced by the combustion 

and post-combustion practices required 

to comply with the CAA section 112 

standards. Any POM that does form 

during combustion is further controlled 

by the various post-combustion 

controls. The add-on PM control 

systems (fabric filter) used to reduce 

mercury and/or PM emissions further 

reduce emissions of these organic 

pollutants, as is evidenced by 

performance data. Specifically, the 

emission tests obtained at currently 

operating major source boilers show that 

the MACT regulations for coal-fired area 

source boilers will reduce Hg emissions 

by about 86 percent. It is, therefore, 

reasonable to conclude that POM 

emissions from coal-fired area source 

boilers will be substantially controlled. 

In lieu of establishing numerical 

emissions limits for pollutants such as 

POM, we regulate surrogate substances. 

While we have not identified specific 

numerical limits for POM, we believe 

CO serves as an effective surrogate for 

this HAP, because CO, like POM, is 

formed as a product of incomplete 

combustion. 

Consequently, we have concluded 

that the emissions limits for CO 

function as a surrogate for control of 

POM, such that it is not necessary to 

establish numerical emissions limits for 

POM with respect to coal-fired area 

source boilers to satisfy CAA section 

112(c)(6). 

To further address POM and mercury 

emissions, this rule also includes an 

energy assessment provision that 

encourages modifications to the facility 

to reduce energy demand that lead to 

these emissions. 


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VII. Summary of the Impacts of This 

Final Rule 

A. What are the air impacts? 

Table 3 of this preamble illustrates, 

for each subcategory, the estimated 

emissions reductions achieved by this 

rule (i.e., the difference in emissions 

between an area source boiler controlled 

to the MACT/GACT level of control and 

boilers at the current baseline) for new 

and existing sources. Nationwide 

emissions of total HAP (HCl, hydrogen 

fluoride, non-mercury metals, mercury, 

and VOC (for organic HAP) will be 

reduced by about 667 tpy for existing 

units and 74 tpy for new units. 

Emissions of mercury will be reduced 

by about 88 pounds per year for existing 

units and by about 9 pounds per year for 

new units. Emissions of filterable PM 

will be reduced by about 2,300 tpy for 

existing units and 280 tpy for new units. 

Emissions of non-mercury metals (i.e., 

antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, 

nickel, and selenium) will be reduced 

by about 280 tpy for existing units and 

will be reduced by 40 tpy for new units. 

Additionally, EPA has estimated that 

conducting an biennial tune-up will 

likely reduce emissions of organic HAP 

as a result of improved combustion and 

reduced fuel use. POM reductions are 

represented by 7–PAH, a group of 

polycyclic aromatic hydrocarbons. EPA 

estimates that the work practices, 

management practices, and CO emission 

limits may reduce emissions of 7–PAH 

by 8 tpy for existing units and by 1 tpy 

for new units. A discussion of the 

methodology used to estimate baseline 

emissions and emissions reductions is 

presented in ‘‘Estimation of Impacts for 

Industrial, Commercial, and 

Institutional Boilers Area Source 

NESHAP’’ in the docket. 

TABLE 3—SUMMARY OF HAP EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES (TPY) 

Source Subcategory PM 

Non mercury metals a

Mercury POM b

Existing Units .................................................... Coal .................................................................. 1,092 4 0.003 0.2 

Biomass ............................................................ 815 11 0.003 5 

Oil ..................................................................... 349 269 0.04 3 

New Units ......................................................... Coal .................................................................. 7 0.03 0.0001 0.02 

Biomass ............................................................ 121 2 0.0002 0.5 

Oil ..................................................................... 149 36 0.004 0.5 

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. 

bPOM is represented by total emissions of polycyclic aromatic hydrocarbons (7–PAH). It is assumed that compliance with work practice standard and management practice will reduce fuel usage by 1 percent, which may reduce emissions of 7–PAH by an equivalent amount. 

B. What are the cost impacts? 

To estimate the national cost impacts 

of this rule for existing sources, EPA 

developed several model boilers and 

determined the cost of control for these 

model boilers. EPA assigned a model 

boiler to each existing unit based on the 

fuel, size, and current controls. The 

analysis considered all air pollution 

control equipment currently in 

operation at existing boilers. Model 

costs were then assigned to all existing 

units that could not otherwise meet the 

proposed standards. The resulting total 

national cost impact of this rule for 

existing units is $487 million dollars in 

total annualized costs. The total 

annualized costs (new and existing) for 

installing controls, conducting biennial 

tune-ups and an energy assessment, and 

implementing testing and monitoring 

requirements is $535 million. Table 4 of 

this preamble shows the total 

annualized cost impacts for each 

subcategory. 

TABLE 4—SUMMARY OF ANNUAL COSTS FOR NEW AND EXISTING SOURCES

Source Subcategory 

Estimated/ 

projected 

No. of 

affected 

units 

Total 

annualized cost 

(TAC) 

($10 6/yr) a

Existing Units ................................................................. Coal ............................................................................... 3,710 37 

Biomass ......................................................................... 10,958 24 

Oil .................................................................................. 168,003 374 

Facility Energy Assessment .......................................... All ................................................................................... .................... 52 

New Units b .................................................................... Coal ............................................................................... 155 0 .4 

Biomass ......................................................................... 200 2 .6 

Oil .................................................................................. 6,424 45 

aTAC does not include fuel savings from improving combustion efficiency. 

b Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013). 

Using Department of Energy 

projections on fuel expenditures, as well 

as the history of installation dates of 

area source boilers in the dataset, the 

number of additional boilers that could 

be potentially constructed was 

estimated. The resulting total national 

cost impact of this proposed rule on 

new sources by the third year, 2013, is 

$48 million dollars in total annualized 

costs. When accounting for a 1 percent 

fuel savings resulting from 

improvements to combustion efficiency, 

the total national cost impact on new 

sources is ¥$3.6 million. 

A discussion of the methodology used 

to estimate cost impacts is presented in 

the memorandum, ‘‘Estimation of 

Impacts for Industrial, Commercial, and 

Institutional Boilers Area Source 

NESHAP’’ in the Docket. 

C. What are the economic impacts? 

The economic impact analysis (EIA) 

that is included in the RIA shows that 

the expected prices for industrial sectors 

could be 0.01 percent higher and 


srobinson on DSKHWCL6B1PROD with RULES4
15580 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

8Roman et al., 2008. Expert Judgment Assessment 

of the Mortality Impact of Changes in Ambient Fine 

Particulate Matter in the U.S. Environ. Sci. 

Technol., 42, 7, 2268—2274. 

domestic production may fall by less 

than 0.01 percent. Because of higher 

domestic prices, imports may rise by 

less than 0.01 percent. Energy prices 

will not be affected. 

Social costs are estimated to be also 

$0.49 billion in 2008 dollars. This is 

estimated to made up of a $0.24 billion 

loss in domestic consumer surplus, a 

$0.25 billion loss in domestic producer 

surplus, a $0.004 billion increase in rest 

of the world surplus, and a $0.003 

billion net loss associated with new 

source costs and fuel savings not 

modeled in a way that can be used to 

attribute it to consumers and producers. 

EPA performed a screening analysis 

for impacts on small entities by 

comparing compliance costs to sales/ 

revenues (e.g., sales and revenue tests). 

EPA’s analysis found the tests were 

typically higher for small entities 

included in the screening analysis. EPA 

has prepared an Initial Regulatory 

Flexibility Analysis (IRFA) that 

discusses alternative regulatory or 

policy options that minimize this final 

rule’s small entity impacts. It includes 

key information about key results from 

the Small Business Advocacy Review 

(SBAR) panel. The IRFA is discussed in 

section 5.2 of the report ‘‘Regulatory 

Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers and Process Heater’’ 

located in the docket. EPA has also 

prepared A Final Regulatory Flexibility 

Analysis (FRFA) that is found in section 

5 of the RIA. 

In addition to estimating this rule’s 

social costs and benefits, EPA has 

estimated the employment impacts of 

the final rule. We expect that the rule’s 

direct impact on employment will be 

small. We have not quantified the rule’s 

indirect or induced impacts. For further 

explanation and discussion of our 

analysis, see Chapter 4 of the RIA. 

D. What are the benefits? 

The benefit categories associated with 

the emission reduction anticipated for 

this rule can be broadly categorized as 

those benefits attributable to reduced 

exposure to hazardous air pollutants 

(HAPs) and those attributable to 

exposure to other pollutants. Because 

we were unable to monetize the benefits 

associated with reducing HAPs, all 

monetized benefits reflect 

improvements in ambient PM2.5 and 

ozone concentrations. This results in an 

underestimate of the total monetized 

benefits. We estimated the total 

monetized benefits of this final 

regulatory action to be $210 million to 

$520 million (2008$, 3 percent discount 

rate) in the implementation year (2014). 

The monetized benefits at a 7 percent 

discount rate are $190 million to $470 

million (2008$). Using alternate 

relationships between PM2.5 and 

premature mortality supplied by 

experts, higher and lower benefits 

estimates are plausible, but most of the 

expert-based estimates fall between 

these two estimates.8 A summary of the 

monetized benefits estimates at discount 

rates of 3 percent and 7 percent are 

provided in Table 6 of this preamble. A 

summary of the avoided health benefits 

are provided in Table 7 of this 

preamble. 

TABLE 6—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER AREA SOURCE RULE

[Millions of 2008$] 1

Pollutant 

Emissions 

reductions 

(tons) 

Total monetized benefits 

(at 3% 

discount rate) 

Total monetized benefits 

(at 7% 

discount rate) 

Direct PM2.5 .................................................................................................................................... 678 $79 to $190 $72 to $180 

SO2 ................................................................................................................................................. 3,197 130 to 320 120 to 290 

Total ........................................................................................................................................ 210 to 520 190 to 470 

1All estimates are for the implementation year (2014), and are rounded to two significant figures so numbers may not sum across rows. All 

fine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included. These estimates do not include energy disbenefits valued at less than $1 million. These benefits reflect existing boilers and 6,779 new boilers anticipated to come online by 2014. 

TABLE 7—SUMMARY OF THE AVOIDED HEALTH INCIDENCES FOR THE FINAL BOILER MACT 

Avoided 

health 

incidences 

Avoided Premature Mortality ...................................................................................................................................................................... 24 to 61 

Avoided Morbidity: 

Chronic Bronchitis ............................................................................................................................................................................... 17 

Acute Myocardial Infarction ................................................................................................................................................................. 40 

Hospital Admissions, Respiratory ........................................................................................................................................................ 6 

Hospital Admissions, Cardiovascular .................................................................................................................................................. 13 

Emergency Room Visits, Respiratory ................................................................................................................................................. 21 

Acute Bronchitis ................................................................................................................................................................................... 38 

Work Loss Days ......................................................................................................................................................................................... 3,200 

Asthma Exacerbation .................................................................................................................................................................................. 420 

Minor Restricted Activity Days .................................................................................................................................................................... 19,000 

Lower Respiratory Symptoms .................................................................................................................................................................... 460 

Upper Respiratory Symptoms .................................................................................................................................................................... 350 

Note: All estimates are for the implementation year (2014), and are rounded to two significant figures and whole numbers. All fine particles are 

assumed to have equivalent health effects. Benefits from reducing HAP are not included. These benefits reflect existing boilers and 6,779 new 

boilers anticipated to come online by 2014. 


srobinson on DSKHWCL6B1PROD with RULES4
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15581 

9U.S. Environmental Protection Agency, 2010. 

RIA for the Proposed Federal Transport Rule. 

Prepared by Office of Air and Radiation. June. 

Available on the Internet at http://www.epa.gov/ttn/ 

ecas/regdata/RIAs/proposaltrria_final.pdf. 

10Pope et al, 2002. ‘‘Lung Cancer, 

Cardiopulmonary Mortality, and Long-term 

Exposure to Fine Particulate Air Pollution.’’ Journal 

of the American Medical Association. 287:1132– 

1141. 

11Laden et al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173:667–672. 

These quantified benefits estimates 

represent the human health benefits 

associated with reducing exposure to 

PM2.5. The PM reductions are the result 

of emission limits on PM as well as 

emission limits on other pollutants, 

including HAP. To estimate the human 

health benefits, we used the 

environmental Benefits Mapping and 

Analysis Program (BenMAP) model to 

quantify the changes in PM2.5-related 

health impacts and monetized benefits 

based on changes in air quality. This 

approach is consistent with the recently 

proposed Transport Rule RIA.9

For this final rule, we have expanded 

and updated the analysis since the 

proposal in several important ways. 

Using the Comprehensive Air Quality 

Model with extensions (CAMx) model, 

we are able to provide boiler sectorspecific air quality impacts attributable 

to the emission reductions anticipated 

from this final rule. We believe that this 

modeling provides estimates that are 

more appropriate for characterizing the 

health impacts and monetized benefits 

from boilers than the generic benefitper-ton estimates used for the proposal 

analysis. 

To generate the boiler sector-specific 

benefit-per-ton estimates, we used 

CAMx to convert emissions of direct 

PM2.5 and PM2.5 precursors into changes 

in ambient PM2.5 levels and BenMAP to 

estimate the changes in human health 

associated with that change in air 

quality. Finally, the monetized health 

benefits were divided by the emission 

reductions to create the boiler sectorspecific benefit-per-ton estimates. These 

models assume that all fine particles, 

regardless of their chemical 

composition, are equally potent in 

causing premature mortality because 

there is no clear scientific evidence that 

would support the development of 

differential effects estimates by particle 

type. Directly emitted PM2.5 and SO2 are 

the dominant PM2.5 precursors affected 

by this rule. Even though we assume 

that all fine particles have equivalent 

health effects, the benefit-per-ton 

estimates vary between precursors 

because each ton of precursor reduced 

has a different propensity to form PM2.5. 

For example, SO2 has a lower benefitper-ton estimate than direct PM2.5

because it does not directly transform 

into PM2.5, and because sulfate particles 

formed from SO2 emissions can 

transport many miles, including over 

areas with low populations. Direct PM2.5

emissions convert directly into ambient 

PM2.5, thus, to the extent that emissions 

occur in population areas, exposures to 

direct PM2.5 will tend to be higher, and 

monetized health benefits will be higher 

than for SO2 emissions. 

Furthermore, CAMx modeling allows 

us to model the reduced mercury 

deposition that would occur as a result 

of the estimated reductions of mercury 

emissions. Although we are unable to 

model mercury methylation and human 

consumption of mercury-contaminated 

fish, the mercury deposition maps 

provide an improved qualitative 

characterization of the mercury benefits 

associated with this final rulemaking. 

For context, it is important to note 

that the magnitude of the PM benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised EPA to 

consider a variety of assumptions, 

including estimates based on both 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

For this rule, we cite two key empirical 

studies, one based on the American 

Cancer Society cohort study 10 and the 

extended Six Cities cohort study.11 In 

the RIA for this rule, which is available 

in the docket, we also include benefits 

estimates derived from expert 

judgments and other assumptions. 

EPA strives to use the best available 

science to support our benefits analyses. 

We recognize that interpretation of the 

science regarding air pollution and 

health is dynamic and evolving. After 

reviewing the scientific literature and 

recent scientific advice, we have 

determined that the no-threshold model 

is the most appropriate model for 

assessing the mortality benefits 

associated with reducing PM2.5

exposure. Consistent with this recent 

advice, we are replacing the previous 

threshold sensitivity analysis with a 

new LML assessment. While an LML 

assessment provides some insight into 

the level of uncertainty in the estimated 

PM mortality benefits, EPA does not 

view the LML as a threshold and 

continues to quantify PM-related 

mortality impacts using a full range of 

modeled air quality concentrations. 

Most of the estimated PM-related 

benefits in this rule would accrue to 

populations exposed to higher levels of 

PM2.5. Using the Pope, et al., (2002) 

study, 79 percent of the population is 

exposed at or above the LML of 7.5 μg/ 

m3. Using the Laden, et al., (2006) 

study, 34 percent of the population is 

exposed above the LML of 10 μg/m3. It 

is important to emphasize that we have 

high confidence in PM2.5-related effects 

down to the lowest LML of the major 

cohort studies. This fact is important, 

because as we estimate PM-related 

mortality among populations exposed to 

levels of PM2.5 that are successively 

lower, our confidence in the results 

diminishes. However, our analysis 

shows that the great majority of the 

impacts occur at higher exposures. 

It should be emphasized that the 

monetized benefits estimates provided 

above do not include benefits from 

several important benefit categories, 

including reducing other air pollutants, 

ecosystem effects, and visibility 

impairment. The benefits from reducing 

other pollutants have not been 

monetized in this analysis, including 

reducing 1,100 tons of CO, 340 tons of 

HCl, 8 tons of HF, 90 pounds of 

mercury, and 320 tons of other metals 

each year. Specifically, we were unable 

to estimate the benefits associated with 

HAPs that would be reduced as a result 

of this rule due to data, resource, and 

methodology limitations. Challenges in 

quantifying the HAP benefits include a 

lack of exposure-response functions, 

uncertainties in emissions inventories 

and background levels, the difficulty of 

extrapolating risk estimates to low 

doses, and the challenges of tracking 

health progress for diseases with long 

latency periods. Although we do not 

have sufficient information or modeling 

available to provide monetized 

estimates for this rulemaking, we 

include a qualitative assessment of the 

health effects of these air pollutants in 

the RIA for this rule, which is available 

in the docket. 

In addition, the monetized benefits 

estimates provided in Table 6 do not 

reflect the disbenefits associated with 

increased electricity usage from 

operation of the control devices. We 

estimate that the increases in emissions 

of CO2 would have disbenefits valued at 

less than $1 million at a 3 percent 

discount rate (average). CO2-related 

disbenefits were calculated using the 

social cost of carbon, which is discussed 

further in the RIA. However, these 

disbenefits do not change the rounded 

total monetized benefits. In the RIA, we 

also provide the monetized CO2

disbenefits using discount rates of 5 

percent (average), 2.5 percent (average), 

and 3 percent (95th percentile). 


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15582 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

This analysis does not include the 

type of detailed uncertainty assessment 

found in the 2006 PM2.5 NAAQS RIA or 

2008 Ozone NAAQS RIA. However, the 

benefits analyses in these RIAs provide 

an indication of the sensitivity of our 

results to various assumptions, 

including the use of alternative 

concentration-response functions and 

the fraction of the population exposed 

to low PM2.5 levels. 

For more information on the benefits 

analysis, please refer to the RIA for this 

final rule that is available in the docket. 

E. What are the water and solid waste 

impacts? 

EPA estimated that no additional 

water usage would result from the 

MACT floor level of control or GACT 

requirement. The fabric filter, 

multiclone, or combustion control 

devices used to meet the standards of 

this rule do not require any water to 

operate, nor do they generate any 

wastewater. 

EPA estimated the additional solid 

waste that would result from this rule to 

be 1,800 tpy for existing sources due to 

the dust and fly ash captured by 

mercury and PM control devices. The 

cost of handling the additional solid 

waste generated from existing sources is 

$75,700 per year. For new sources 

installed by 2013, the EPA estimated the 

additional solid waste that would result 

from this rule to be 540 tpy for new 

sources due to the dust and fly ash 

captured by mercury and PM control 

devices. The cost of handling the 

additional solid waste generated from 

new sources is $22,900 per year. These 

costs are also accounted for in the 

control costs estimates. 

A discussion of the methodology used 

to estimate impacts is presented in 

‘‘Estimation of Impacts for Industrial, 

Commercial, and Institutional Boilers 

Area Source NESHAP’’ in the Docket. 

F. What are the energy impacts? 

EPA expects an increase of 

approximately 25 million kWh in 

national annual energy usage from 

existing sources as a result of this rule. 

The increase results from the electricity 

required to operate control devices 

installed to meet this rule, such as fabric 

filters. Additionally, for new sources 

installed by 2013, EPA expects an 

increase of approximately 8 million 

kWh in national annual energy usage in 

order to operate the control devices. 

The Department of Energy has 

conducted energy assessments at 

selected manufacturing facilities and 

reports that facilities can reduce fuel/ 

energy use by 10 to 15 percent by using 

best practices to increase their energy 

efficiency. Additionally, the EPA 

expects work practice standards, such as 

boiler tune-ups, and combustion 

controls such as new replacement 

burners, will improve the efficiency of 

boilers. EPA estimates existing area 

source facilities can save 20 trillion Btu 

of fuel each year. For new sources 

online by 2013, the EPA estimates 2.3 

trillion BTU per year of fuel can be 

conserved. This fuel savings estimate 

includes only those fuel savings 

resulting from liquid and coal fuels and 

it is based on the assumption that the 

work practice standards will achieve 1 

percent improvement in efficiency. 

VIII. Statutory and Executive Order 

Review 

A. Executive Order 12866 and 13563: 

Regulatory Planning and Review 

Under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 

1993) and 13563 (76 FR 3821, January 

21, 2011), this action is an 

‘‘economically significant regulatory 

action’’ because it is likely to have an 

annual effect on the economy of $100 

million or more or adversely affect in a 

material way the economy, a sector of 

the economy, productivity, competition, 

jobs, the environment, public health or 

safety, or state, local, or tribal 

governments or communities. 

Accordingly, EPA submitted this action 

to OMB for review under EO 12866 and 

any changes in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

In addition, EPA prepared an analysis 

of the potential costs and benefits 

associated with this action. This 

analysis is contained in the Regulatory 

Impact Analysis (RIA) report. For more 

information on the costs and benefits for 

this rule, see the following table. 

SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER AREA SOURCE RULE IN

2014 

[Millions of 2008$] 1

3% Discount rate 7% Discount rate 

Final MACT/GACT Approach: Selected 

Total Monetized Benefits 2 ............................................................................................................................. $210 to $520 $190 to $470 

Total Social Costs 3 ....................................................................................................................................... $490 $490 

Net Benefits ................................................................................................................................................... ¥$280 to $30 ¥$300 to ¥$20 

1,100 tons of carbon monoxide 

340 tons of HCl 

8 tons of HF 

90 pounds of mercury 

Non-monetized Benefits ................................................................................................................................ 320 tons of other metals 

<1 gram of dioxins/furans (TEQ) 

Health effects from SO2 exposure 

Ecosystem effects 

Visibility impairment 

Proposed MACT Approach: Alternative 

Total Monetized Benefits 2 ............................................................................................................................. $200 to $490 $180 to $440 

Total Social Costs 3 ....................................................................................................................................... $850 $850 

Net Benefits ................................................................................................................................................... ¥$650 to ¥$360 ¥$670 to ¥$410 

Non-monetized Benefits ................................................................................................................................ 1,100 tons of carbon monoxide 

340 tons of HCl 

8 tons of HF 

90 pounds of mercury 

320 tons of other metals 


srobinson on DSKHWCL6B1PROD with RULES4
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15583 

SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER AREA SOURCE RULE IN

2014—Continued 

[Millions of 2008$] 1

3% Discount rate 7% Discount rate 

<1 gram of dioxins/furans (TEQ) 

Health effects from SO2 exposure 

Ecosystem effects 

Visibility impairment 

1All estimates are for the implementation year (2014), and are rounded to two significant figures. These results include units anticipated to 

come online and the lowest cost disposal assumption. 2The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of directly emitted PM2.5 and PM2.5 precursors such as SO2. It is important to note that the monetized benefits include many but not all health effects associated 

with PM2.5 exposure. Benefits are shown as a range from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that 

would support the development of differential effects estimates by particle type. These estimates include energy disbenefits valued at less than 

$1 million. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule have been 

submitted for approval to 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 ICR document 

prepared by EPA has been assigned EPA 

ICR number 2253.01. The recordkeeping 

and reporting requirements in this rule 

are based on the information collection 

requirements in EPA’s NESHAP General 

Provisions (40 CFR part 63, subpart A). 

The recordkeeping and reporting 

requirements in the General Provisions 

are mandatory pursuant to CAA section 

114 (42 U.S.C. 7414). All information 

other than emissions data submitted to 

EPA pursuant to the information 

collection requirements for which a 

claim of confidentiality is made is 

safeguarded according to CAA section 

114(c) and EPA’s implementing 

regulations at 40 CFR part 2, subpart B. 

This NESHAP would require 

applicable one-time notifications 

according to the NESHAP General 

Provisions. Facility owners or operators 

are required to include compliance 

certifications for the work practices and 

management practices in their 

Notifications of Compliance Status. 

Recordkeeping is required to 

demonstrate compliance with emission 

limits, work practices, management 

practices, monitoring, and applicability 

provisions. New affected facilities are 

required to comply with the 

requirements for startup, shutdown, and 

malfunction reports and to submit a 

compliance report if a deviation 

occurred during the semiannual 

reporting period. 

When a malfunction occurs, sources 

must report them according to the 

applicable reporting requirements of 

this Subpart JJJJJJ. An affirmative 

defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions is available to a 

source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 

(sudden, infrequent, not reasonably 

preventable and not caused by poor 

maintenance and or careless operation) 

and where the source took necessary 

actions to minimize emissions. In 

addition, the source must meet certain 

notification and reporting requirements. 

For example, the source must prepare a 

written root cause analysis and submit 

a written report to the Administrator 

documenting that it has met the 

conditions and requirements for 

assertion of the affirmative defense. 

To provide the public with an 

estimate of the relative magnitude of the 

burden associated with an assertion of 

the affirmative defense position adopted 

by a source, EPA provides an 

administrative adjustment to this ICR 

that shows what the notification, 

recordkeeping and reporting 

requirements associated with the 

assertion of the affirmative defense 

might entail. EPA’s estimate for the 

required notification, reports and 

records, including the root cause 

analysis, totals $3,141 and is based on 

the time and effort required of a source 

to review relevant data, interview plant 

employees, and document the events 

surrounding a malfunction that has 

caused an exceedance of an emission 

limit. The estimate also includes time to 

produce and retain the record and 

reports for submission to EPA. EPA 

provides this illustrative estimate of this 

burden because these costs are only 

incurred if there has been a violation 

and a source chooses to take advantage 

of the affirmative defense. 

The annual monitoring, reporting, and 

recordkeeping burden for this collection 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $407 million. This 

includes 2.7 million labor hours per 

year at a cost of $254 million and total 

non-labor capital costs of $153 million 

per year. This estimate includes initial 

and triennial performance tests, 

conducting and documenting an energy 

assessment, conducting and 

documenting a tune-up, semiannual 

excess emission reports, maintenance 

inspections, developing a monitoring 

plan, notifications, and recordkeeping. 

Monitoring, testing, tune-up and energy 

assessment costs were also included in 

the cost estimates presented in the 

control cost impacts estimates in 

Section VII.B of this preamble. The total 

burden for the federal government 

(averaged over the first 3 years after the 

effective date of the standard) is 

estimated to be 286,000 hours per year 

at a total labor cost of $13 million per 

year. 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 the collection displays a 

currently valid OMB control number. 

The OMB control numbers for EPA’s 

regulations in 40 CFR part 63 are listed 

in 40 CFR part 9. When this ICR is 

approved by OMB, the Agency will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 


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15584 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

C. Regulatory Flexibility Act, as 

Amended by the Small Business 

Regulatory Enforcement Fairness Act of 

1996 

Pursuant to section 603 of the RFA, 

EPA prepared an initial regulatory 

flexibility analysis (IRFA) for the 

proposed rule and convened a Small 

Business Advocacy Review Panel to 

obtain advice and recommendations of 

representatives of the regulated small 

entities. A detailed discussion of the 

Panel’s advice and recommendations is 

found in the final Panel Report (Docket 

ID No. EPA–HQ–OAR–2002–0058– 

0797). A summary of the Panel’s 

recommendations is also presented in 

the preamble to the proposed rule at 75 

FR 32044–32045 (June 4, 2010). In the 

proposed rule, EPA included provisions 

consistent with four of the Panel’s 

recommendations. As required by 

section 604 of the RFA, we also 

prepared a final regulatory flexibility 

analysis (FRFA) the final rule. 

The rule is intended to reduce 

emissions of HAP as required under 

section 112 of the CAA. Section II.A of 

this preamble describes the reasons that 

EPA is finalizing this action. 

Many significant issues were raised 

during the public comment period, and 

EPA’s responses to those comments are 

presented in section V of this preamble 

or in the response to comments 

document contained in the docket. 

Significant changes to the rule that 

resulted from the public comments are 

described in section IV of the final rule’s 

preamble. 

The primary comments on the IRFA 

were provided by SBA, with the 

remainder of the comments generally 

supporting SBA’s comments. Those 

comments applicable to the proposal 

regarding area source boilers included 

the following: EPA should have adopted 

additional subcategories, including the 

following: Unit design type (e.g. 

fluidized bed, stoker, fuel cell, 

suspension burner), duty cycle, 

geographic location, boiler size, burner 

type (with and without low-NOX

burners), and hours of use (limited use); 

EPA should have minimized facility 

monitoring and reporting requirements; 

EPA should not have proposed the 

energy audit requirement; and EPA’s 

proposed emissions standards are too 

stringent. 

In response to the comments on the 

IRFA and other public comments, EPA 

made the following changes to the final 

rule. EPA is promulgating management 

practice standards requiring the 

implementation of a boiler tune-up 

program for area source boilers in the 

biomass and oil subcategories instead of 

the proposed CO emission limits. This 

change will significantly reduce the 

monitoring and testing costs for existing 

and new biomass-fired and oil-fired area 

source boilers. EPA also decreased 

monitoring and testing costs for coalfired area source boilers by eliminating 

the CO CEMS requirement for boilers 

greater than 100 MMBtu/h. The final 

rule also includes work practice 

standards or management practice 

standards, instead of emission limits, for 

new area source boilers less than 10 

MMBtu/h. Finally, EPA is finalizing 

emission limits that are less stringent 

than the proposed limits. The emission 

limit changes are largely due to the 

changes in data corrections and 

incorporation of new data into the floor 

calculations. Additional details on the 

changes discussed in this paragraph are 

included in sections IV and V of the 

final rule’s preamble. 

Table 5 of this preamble summarizes 

the EPA estimates of the number of area 

source facilities expected to be affected 

by the area source rule. EPA does not 

have sufficient information to estimate 

the number of small entities expected to 

be covered by the area source rule. 

As discussed in section 5.1 of the RIA 

for this rule, using these cost data and 

the Census estimates of average 

establishment receipts, a substantial 

number of SUSB NAICS/enterprise 

categories have ratios over 3%. The 

following types of representative small 

area source public facilities would have 

cost-to-revenue ratios exceeding 1 

percent but below 3 percent: Other 

public facilities (ratio >1.7 percent) and 

churches (ratio = 1.5 percent). 

TABLE 5—ESTIMATED AFFECTED FACILITIES USING 13 STATE BOILER INSPECTOR INVENTORY: AREA

SOURCES

SIC 

Total number 

of affected 

facilities in 

SIC Code 

01 .......................................... 0 

02 .......................................... 247 

07 .......................................... 0 

09 .......................................... 0 

14 .......................................... 83 

16 .......................................... 0 

17 .......................................... 247 

20 .......................................... 5,733 

23 .......................................... 83 

24 .......................................... 2,676 

26 .......................................... 0 

40 .......................................... 329 

41 .......................................... 0 

42 .......................................... 83 

43 .......................................... 0 

44 .......................................... 0 

45 .......................................... 0 

47 .......................................... 0 

TABLE 5—ESTIMATED AFFECTED FACILITIES USING 13 STATE BOILER INSPECTOR INVENTORY: AREA

SOURCES—Continued 

SIC 

Total number 

of affected 

facilities in 

SIC Code 

48 .......................................... 741 

50 .......................................... 165 

51 .......................................... 247 

52 .......................................... 0 

53 .......................................... 494 

54 .......................................... 0 

55 .......................................... 801 

56 .......................................... 0 

57 .......................................... 0 

58 .......................................... 905 

59 .......................................... 288 

60 .......................................... 329 

64 .......................................... 0 

65 .......................................... 2,878 

70 .......................................... 4,893 

72 .......................................... 2,138 

73 .......................................... 165 

75 .......................................... 1,606 

76 .......................................... 0 

79 .......................................... 1,151 

80 .......................................... 15,293 

81 .......................................... 0 

82 .......................................... 33,303 

83 .......................................... 0 

84 .......................................... 165 

86 .......................................... 3,330 

87 .......................................... 666 

91 to 98 ................................ 5,098 

Unknown ............................... 576 

The information collection activities 

in this ICR include initial and triennial 

stack tests, fuel analyses, operating 

parameter monitoring, continuous 

oxygen monitoring for all coal-fired area 

source boilers greater than 10 MMBtu/ 

h, certified energy assessments for area 

source facilities having a boiler greater 

than 10 MMBtu/h, biennial tune-ups, 

preparation of a startup, shutdown, 

malfunction plan (SSMP), preparation 

of a site-specific monitoring plan and a 

site-specific fuel monitoring plan, onetime and periodic reports, and the 

maintenance of records. Based on 13 

states’ inventories of boilers, there are 

an estimated 92,000 existing facilities 

with affected boilers. It is estimated that 

53 percent are located in the private 

sector and the remaining 47 percent are 

located in the public sector. Of these, 

only about 0.3 percent of the area source 

facilities are subject to emission limits 

and the testing and monitoring 

requirements in the final rule. A table 

included in the FRFA summarizes the 

types and number of each type of small 

entities expected to be affected by the 

area source rule. 

The Agency expects that persons with 

knowledge of .pdf software, spreadsheet 

and relational database programs will be 


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necessary in order to prepare the report 

or record. Based on experience with 

previous emission stack testing, we 

expect most facilities to contract out 

preparation of the reports associated 

with emission stack testing, including 

creation of the Electronic Reporting 

Tool submittal which will minimize the 

need for in depth knowledge of 

databases or spreadsheet software at the 

source. We also expect affected sources 

will need to work with web-based 

applicability tools and flowcharts to 

determine the requirements applicable 

to them, knowledge of the heat input 

capacity and fuel use of the combustion 

units at each facility will be necessary 

in order to develop the reports and 

determine initial applicability to the 

rule. Affected facilities will also need 

skills associated with vendor selection 

in order to identify service providers 

that can help them complete their 

compliance requirements, as necessary. 

While EPA did make significant 

changes based on public comment, EPA 

is maintaining, but clarifying, the energy 

assessment requirement. Some changes 

to the energy assessment requirement 

that will reduce costs for small entities 

include a the following provisions: The 

energy assessment for facilities with 

affected boilers using less than 0.3 

trillion Btu per year heat input will be 

one day in length maximum. The boiler 

system and energy use system 

accounting for at least 50 percent of the 

energy output will be evaluated to 

identify energy savings opportunities, 

within the limit of performing a one-day 

energy assessment; and the energy 

assessment for facilities with affected 

boilers using 0.3 to 1.0 trillion Btu per 

year will be 3 days in length maximum. 

The boiler system and any energy use 

system accounting for at least 33 percent 

of the energy output will be evaluated 

to identify energy savings opportunities, 

within the limit of performing a 3-day 

energy assessment. In addition, the final 

rule allows facilities to use a previously 

completed energy assessment to satisfy 

the energy assessment requirement. 

As required by section 212 of 

SBREFA, EPA also is preparing a Small 

Entity Compliance Guide to help small 

entities comply with this rule. Small 

entities will be able to obtain a copy of 

the Small Entity Compliance guide at 

the following Web site: http:// 

www.epa.gov/ttn/atw/boiler/ 

boilerpg.html. 

D. Unfunded Mandates Reform Act of 

1995 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on state, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

we generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘federal mandates’’ that may result 

in expenditures to state, local, and tribal 

governments, in the aggregate, or to the 

private sector, of $100 million or more 

in any 1 year. Before promulgating a 

rule for which a written statement is 

needed, section 205 of the UMRA 

generally requires us to identify and 

consider a reasonable number of 

regulatory alternatives and adopt the 

least costly, most cost-effective or least 

burdensome alternative that achieves 

the objectives of this final rule. The 

provisions of section 205 do not apply 

when they are inconsistent with 

applicable law. Moreover, section 205 

allows us to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with this final 

rule an explanation why that alternative 

was not adopted. Before we establish 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, we must develop a small 

government agency plan under section 

203 of the UMRA. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of regulatory proposals 

with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this rule 

contains 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 1 year. 

Accordingly, we have prepared a 

written statement entitled ‘‘Unfunded 

Mandates Reform Act Analysis for the 

Boiler Area Source NESHAP’’ under 

section 202 of the UMRA which is 

summarized below. 

1. Statutory Authority 

As discussed in Section I of this 

preamble, the statutory authority for this 

rulemaking is CAA section 112. Title III 

of the CAA was enacted to reduce 

nationwide air toxic emissions. Section 

112(b) of the CAA lists the 188 

chemicals, compounds, or groups of 

chemicals deemed by Congress to be 

HAP. These toxic air pollutants are to be 

regulated by NESHAP. 

Section 112(d) of the CAA requires us 

to establish NESHAP for both major and 

area sources of HAP that are listed for 

regulation under CAA section 112(c). 

CAA section 112(k)(3)(B) calls for EPA 

to identify at least 30 HAP which, as the 

result of emissions from area sources, 

pose the greatest threat to public health 

in the largest number of urban areas. 

CAA section 112(c)(3) requires EPA to 

list sufficient categories or subcategories 

of area sources to ensure that area 

sources representing 90 percent of the 

emissions of the 30 urban HAP are 

subject to regulation. 

Under CAA section 112(d)(5), we may 

elect to promulgate standards or 

requirements for area sources based on 

GACT used by those sources to reduce 

emissions of HAP. Determining what 

constitutes GACT involves considering 

the control technologies and 

management practices that are generally 

available to the area sources in the 

source category. We also consider the 

standards applicable to major sources in 

the analogous source category and, as 

appropriate, the control technologies 

and management practices at area and 

major sources in similar categories, to 

determine if the standards, technologies, 

and/or practices are transferable and 

generally available to area sources. In 

determining GACT for a particular area 

source category, we consider the costs 

and economic impacts of available 

control technologies and management 

practices on that category. 

While GACT may be a basis for 

standards for most types of HAP emitted 

from area source, CAA section 112(c)(6) 

requires that source categories 

accounting for emissions of the HAP 

listed in CAA section 112(c)(6) be 

subject to standards under CAA section 

112(d)(2) for the listed pollutants. Thus, 

CAA section 112(c)(6) requires that 

emissions of each listed HAP for the 

listed categories be subject to MACT 

regulation. The CAA section 112(c)(6) 

list of source categories includes 

industrial boilers and institutional/ 

commercial boilers. Within these two 

source categories, coal combustion, oil 

combustion, and wood combustion have 

been on the CAA section 112(c)(6) list 

because of emissions of mercury and 

POM. We currently believe that 

regulation of coal-fired boilers will 

ensure that we fulfill our obligation 

under CAA section 112(c)(6) with 

respect to mercury and POM reductions. 

Consequently, we deem it reasonable to 

regulate the coal-fired boilers under 

MACT, rather than the biomass and oilfired boilers, to obtain additional 

mercury and POM reductions towards 

achieving the CAA section 112(c)(6) 


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obligation. We are regulating biomassfired and oil-fired boilers under GACT. 

This NESHAP will apply to all 

existing and new industrial boilers, 

institutional boilers, and commercial 

boilers located at area sources. In 

compliance with section 205(a) of the 

UMRA, we identified and considered a 

reasonable number of regulatory 

alternatives. Additional information on 

the costs and environmental impacts of 

these regulatory alternatives is 

presented in the docket. 

The emission limits for existing area 

source boilers are only applicable to 

area source boilers that have a designed 

heat input capacity of 10 MMBtu/h or 

greater. The regulatory alternative upon 

which the standards are based 

represents the MACT floor for the listed 

CAA section 112(c)(6) pollutants 

(mercury and POM) for coal-fired units 

and GACT for the other urban HAP 

which formed the basis for the listing of 

these two area source categories. The 

standards will require new coal-fired 

boilers to meet MACT-based emission 

limits for mercury and CO (as a 

surrogate for POM) and GACT-based 

emission limits for PM (as a surrogate 

for urban metals). New biomass and oilfired boilers will be required to meet 

GACT for CO, which are tune-ups, and 

GACT-based emission limits for PM. 

Existing large coal-fired boilers will be 

required to meet MACT-based emission 

limits for mercury and CO for coal-fired 

units, and existing large biomass and 

oil-fired boilers will be subject to GACT, 

which is a tune-up. As allowed under 

CAA section 112(h), a work practice 

standard requiring the implementation 

of a tune-up program is being 

established for existing and new area 

source boilers with a designed heat 

input capacity of less than 10 MMBtu/ 

h. An additional ‘‘beyond-the-floor’’ 

standard is being established for 

existing area source facilities having an 

affected boiler with a heat input 

capacity of 10 MMBtu/h or greater that 

requires the performance of an energy 

assessment on the boiler and the facility 

to identify cost-effective energy 

conservation measures. 

2. Social Costs and Benefits 

The regulatory impact analysis 

prepared for this final rule including the 

Agency’s assessment of costs and 

benefits, is detailed in the ‘‘Regulatory 

Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters’’ in the docket. Based on 

estimated compliance costs associated 

with this final rule and the predicted 

change in prices and production in the 

affected industries, the estimated social 

costs of this final rule are $0.49 billion 

(2008 dollars). 

It is estimated that 3 years after 

implementation of this final rule, HAP 

will be reduced by hundreds of tons, 

including reductions in metallic HAP 

including mercury, hydrochloric acid, 

hydrogen fluoride, and several other 

organic HAP from area source boilers. 

Studies have determined a relationship 

between exposure to these HAP and the 

onset of cancer; however, the Agency is 

unable to provide a monetized estimate 

of the HAP benefits at this time. In 

addition, there are reductions in PM2.5

and in SO2 that will occur, including 

678 tons of PM2.5 and 3,197 tons of SO2. 

These reductions occur within 3 years 

after the implementation of the 

regulation and are expected to continue 

throughout the life of the affected 

sources. The major health effect 

associated with reducing PM2.5 and 

PM2.5 precursors (such as SO2) is a 

reduction in premature mortality. Other 

health effects associated with PM2.5

emission reductions include avoiding 

cases of chronic bronchitis, heart 

attacks, asthma attacks, and work-lost 

days (i.e., days when employees are 

unable to work). While we are unable to 

monetize the benefits associated with 

the HAP emissions reductions, we are 

able to monetize the benefits associated 

with the PM2.5 and SO2 emissions 

reductions. For SO2.5 and PM2.5, we 

estimated the benefits associated with 

health effects of PM but were unable to 

quantify all categories of benefits 

(particularly those associated with 

ecosystem and visibility effects). Our 

estimates of the monetized benefits in 

2013 associated with the 

implementation of this final rule range 

from $0.21 billion (2008 dollars) to 

$0.52 billion (2008 dollars) when using 

a 3 percent discount rate (or from $0.19 

billion (2008 dollars) to $0.47 billion 

(2008 dollars) when using a 7 percent 

discount rate. The general approach 

used to value benefits is discussed in 

more detail in Section VII.D of this 

preamble. For more detailed 

information on the benefits estimated 

for the rulemaking, refer to the RIA in 

the docket. 

3. Future and Disproportionate Costs 

The Unfunded Mandates Reform Act 

requires that we estimate, where 

accurate estimation is reasonably 

feasible, future compliance costs 

imposed by this final rule and any 

disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of this final rule are discussed in 

Section VII.C of this preamble. 

We do not believe that there will be 

any disproportionate budgetary effects 

of this final rule on any particular areas 

of the country, state or local 

governments, types of communities 

(e.g., urban, rural), or particular industry 

segments. See the results of the 

‘‘Economic Impact Analysis of the 

Proposed Industrial Boilers and Process 

Heaters NESHAP,’’ the results of which 

are discussed in Section VII.C of this 

preamble. 

4. Effects on the National Economy 

The Unfunded Mandates Reform Act 

requires that we estimate the effect of 

the proposed rule on the national 

economy. To the extent feasible, we 

must estimate the effect on productivity, 

economic growth, full employment, 

creation of productive jobs, and 

international competitiveness of the 

U.S. goods and services, if we determine 

that accurate estimates are reasonably 

feasible and that such effect is relevant 

and material. 

The nationwide economic impact of 

this final rule is presented in the 

Economic Impact Analysis chapter 

(Section 4) of the RIA in the docket. 

This analysis provides estimates of the 

effect of this final rule on some of the 

categories mentioned above. The results 

of the economic impact analysis are 

summarized in Section VII.C of this 

preamble. The results show that there 

will be a small impact on prices and 

output (less than 0.01 percent). In 

addition, there should be little impact 

on energy markets (in this case, coal, 

natural gas, petroleum products, and 

electricity). Hence, the potential impacts 

on the categories mentioned above 

should be small. 

5. Consultation With Government 

Officials 

The Unfunded Mandates Reform Act 

requires that we describe the extent of 

the Agency’s prior consultation with 

affected state, local, and tribal officials, 

summarize the officials’ comments or 

concerns, and summarize our response 

to those comments or concerns. In 

addition, section 203 of the UMRA 

requires that we develop a plan for 

informing and advising small 

governments that may be significantly 

or uniquely impacted by a proposal. 

Consistent with the intergovernmental 

consultation provisions of section 204 of 

the UMRA, EPA has initiated 

consultations with governmental 

entities affected by this rule. EPA 

invited the following 10 national 

organizations representing state and 

local elected officials to a meeting held 

on March 24, 2010 in Washington, DC: 

(1) National Governors Association; (2) 


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National Conference of State 

Legislatures, (3) Council of State 

Governments, (4) National League of 

Cities, (5) U.S. Conference of Mayors, (6) 

National Association of Counties, (7) 

International City/County Management 

Association, (8) National Association of 

Towns and Townships, (9) County 

Executives of America, and (10) 

Environmental Council of States. These 

10 organizations of elected state and 

local officials have been identified by 

EPA as the ‘‘Big 10’’ organizations 

appropriate to contact for purpose of 

consultation with elected officials. The 

purposes of the consultation were to 

provide general background on the 

proposal, answer questions, and solicit 

input from state/local governments. 

During the meeting, officials expressed 

uncertainty with regard to how boilers 

owned/operated by state and local 

entities would be impacted, as well as 

with regard to the potential burden 

associated with implementing this final 

rule on state and local entities. To that 

end, officials requested and EPA 

provided (1) model boiler costs, (2) 

inventory of area source boilers (coal, 

oil, biomass only) for the 13 states for 

which we have an inventory, and (3) 

information on potential size of boilers 

used for various facility types and sizes. 

EPA has not received additional 

questions or requests from state or local 

officials. 

Consistent with section 205, EPA 

identified and considered a reasonable 

number of regulatory alternatives. 

Because an initial screening analysis for 

impact on small entities indicated a 

likely significant impact for substantial 

numbers, EPA convened a SBAR Panel 

to obtain advice and recommendation of 

representatives of the small entities that 

potentially would be subject to the 

requirements of this final rule. As part 

of that process, EPA considered several 

options. Those options included 

establishing emission limits, 

establishing work practice standards, 

and establishing work practice 

standards and requiring an energy 

assessment. The regulatory alternative 

selected is a combination of the options 

considered and includes provisions 

regarding each of the SBAR Panel’s 

recommendations for area source 

boilers. The recommendations regard 

the use of subcategories, work practice 

standards, and compliance costs (see 

section IX.C of this preamble for more 

detail on the RFA). 

EPA determined subcategories based 

on boiler type to be appropriate because 

different types of units have different 

emission characteristics which may 

affect the feasibility and effectiveness of 

emission control. Thus, this final rule 

identifies three subcategories of area 

source boilers: (1) Boilers designed for 

coal firing, (2) boilers designed for 

biomass firing, and (3) boilers designed 

for oil firing. 

The emission limits for existing and 

new area source boilers are only 

applicable to area source boilers that 

have a designed heat input capacity of 

10 MMBtu/h or greater. A work practice 

standard (for mercury from coal-fired 

boilers and for POM from all boilers) or 

management practice (for all other HAP, 

including mercury from biomass-fired 

and oil-fired boilers) requiring the 

implementation of a tune-up program is 

being established for existing area 

source boilers with a designed heat 

input capacity of less than 10 MMBtu/ 

h. The regulatory alternative upon 

which the standards are based 

represents the MACT floor for mercury 

and POM (CO is used as a surrogate for 

POM) for coal-fired boilers, and GACT 

for the other urban HAP (PM is used as 

a surrogate for urban HAP metals and 

CO is used as a surrogate for urban 

organic pollutants) for new coal, 

biomass, and oil-fired boilers. An 

additional ‘‘beyond-the-floor’’ standard 

is being established for existing area 

source facilities having an affected 

boiler with a heat input capacity of 10 

MMBtu/h or greater that requires the 

performance of an energy assessment on 

the boiler and the facility to identify 

cost-effective energy conservation 

measures. 

The use of surrogate pollutants will 

result in reduced compliance costs 

because testing is only required for the 

surrogate pollutants (i.e., CO and PM) 

versus for the HAP (i.e., POM and 

metals). The work practice standard/ 

management practice also will result in 

reduced compliance costs with respect 

to monitoring/testing for the smaller 

existing area source boilers. EPA’s 

exemption of area source facilities from 

title V permit requirements also will 

reduce burden on area source boiler 

facilities. 

This rule is not subject to the 

requirements of section 203 of the 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

While some small governments may 

have boilers that will be affected by this 

final rule, EPA’s analysis shows that 

other public facilities that are located at 

area source facilities owned by small 

entities will not have cost-to-revenue 

ratios exceeding 10 percent. Hospitals’ 

and schools’ revenue tests fall below 1 

percent. Because this final rule’s 

requirements apply equally to boilers 

owned and/or operated by governments 

and to boilers owned and/or operated by 

private entities, there will be no 

requirements that uniquely apply to 

such governments or impose any 

disproportionate impacts on them. 

E. Executive Order 13132: Federalism 

Under Executive Order 13132, EPA 

may not issue an action that has 

federalism implications, that imposes 

substantial direct compliance costs, and 

that is not required by statute, unless 

the federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by state and 

local governments, or EPA consults with 

state and local officials early in the 

process of developing the proposed 

action. 

EPA has concluded that this action 

may have federalism implications, 

because it may impose substantial direct 

compliance costs on state or local 

governments, and the federal 

government will not provide the funds 

necessary to pay those costs. 

Accordingly, EPA provides the 

following federalism summary impact 

statement as required by section 6(b) of 

Executive Order 13132. 

Based on the estimates in EPA’s RIA 

for today’s action, the regulatory option 

may have federalism implications 

because the action may impose 

approximately $276 million in annual 

direct compliance costs on an estimated 

57,000 state or local governments. Boiler 

inventories for the health services, 

educational services, and governmentowned buildings sectors from 13 States 

were used to estimate the nationwide 

number of potentially impacted state or 

local governments. Because the 

inventories for these sectors include 

privately owned and federal government 

owned facilities, the estimate may 

include many facilities that are not state 

or local government owned. Table 8 of 

this preamble presents estimates of the 

number of potentially impacted state 

and local governments and their 

potential annual compliance costs for 

each of the three sectors. In addition to 

an estimate of the total number of 

potentially impacted facilities, estimates 

for facilities with small boilers and for 

facilities with large boilers are 

presented. Small boilers (boilers with 

heat input capacity of less than 10 

MMBtu/h) will be subject to a work 

practice standard or management 

practice that requires a boiler tune-up 

every 2 years. Large coal-fired boilers 

(boilers with heat input capacity of 10 

MMBtu/h or greater) will be subject to 

emission limits for mercury and CO. 

Large biomass and oil-fired boilers will 

be subject to a biennial boiler tune-up 

requirement for CO. All facilities with 


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large boilers will be required to conduct 

a one-time energy assessment. 

TABLE 8—STATE AND LOCAL GOVERNMENTS POTENTIALLY IMPACTED BY THE STANDARDS FOR BOILERS AT AREA SOURCE

FACILITIES

Sector 

Number of potentially impacted 

facilities Annual compliance costs to meet standards 

($) 

Total Small Large 

Health Services ......................................... 17,206 15,293 1,913 $84 million. 

Educational Services ................................ 34,052 33,303 749 159 million. 

Government-Owned Buildings .................. 5,796 5,098 698 33 million. 

Total ................................................... 57,054 53,694 3,360 276 million. 

EPA consulted with state and local 

officials in the process of developing the 

action to permit them to have 

meaningful and timely input into its 

development. EPA met with 10 national 

organizations representing state and 

local elected officials to provide general 

background on the proposed rule, 

answer questions, and solicit input from 

state/local governments. The UMRA 

discussion in Section IX.D of this 

preamble includes a description of the 

consultation. As required by section 8(a) 

of Executive Order 13132, EPA included 

a certification from its Federalism 

Official stating that EPA had met the 

Executive Order’s requirements in a 

meaningful and timely manner, when it 

sent the draft of this final action to OMB 

for review pursuant to Executive Order 

12866. A copy of this certification has 

been included in the public version of 

the official record for this final action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). This final rule imposes 

requirements on owners and operators 

of specified area sources and not tribal 

governments. We do not know of any 

industrial, commercial, or institutional 

boilers owned or operated by Indian 

tribal governments. However, if there 

are any, the effect of this final rule on 

communities of tribal governments 

would not be unique or 

disproportionate to the effect on other 

communities. Thus, Executive Order 

13175 does not apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 because the Agency does 

not believe the environmental health 

risks or safety risks addressed by this 

action present a disproportionate risk to 

children. In addition, this action is not 

subject to Executive Order 13045 

because this final rule is based solely on 

technology performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant energy 

action’’ as defined in Executive Order 

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. We 

estimate no significant changes for the 

energy sector for price, production, or 

imports. For more information on the 

estimated energy effects, please refer to 

Section VI of this preamble. The 

analysis is available in the public 

docket. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Pub. L. 104–113, 

Section 12(d), 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. The VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures, and business practices) that 

are developed or adopted by VCS 

bodies. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency does not 

use available and applicable VCS. 

This final rule involves technical 

standards. EPA cites the following 

standards in this final rule: EPA 

Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 

10, 10A, 10B, 17, 19, 29 of 40 CFR part 

60; 101A of 40 CFR part 61; and 

voluntary consensus standards: 

American Society of Mechanical 

Engineers (ASME) PTC 19 (manual 

methods only), American Society for 

Testing and Materials (ASTM) D6522– 

00, ASTM D6784–02, ASTM D2234/ 

D2234M–10, ASTM D6323–98, ASTM 

D2013–04, ASTM D5198–92, ASTM 

D5865–04, ASTM E711–87, ASTM 

D3173–03, ASTM E871–82, and ASTM 

D6722–01. 

Consistent with the NTTAA, EPA 

conducted searches to identify 

voluntary consensus standards in 

addition to these EPA methods. No 

applicable voluntary consensus 

standards were identified as alternatives 

for EPA Methods 2F, 2G, 5D, and 19. 

The search and review results are in the 

docket for this rule. 

The search for emissions 

measurement procedures identified 16 

other voluntary consensus standards. 

EPA determined that these 16 standards 

identified for measuring emissions of 

the HAP or surrogates subject to 

emission standards in this rule were 

impractical alternatives to EPA test 

methods for the purposes of this rule. 

Therefore, EPA did not adopt these 

standards for this purpose. The reasons 

for the determinations for the 16 

methods can be found in the docket to 

this rule. 

Table 4 to subpart JJJJJJ of this rule 

lists the testing methods included in the 

regulation. Under 40 CFR 63.7(f) and 

63.8(f) of the General Provisions, a 

source may apply to EPA for permission 

to use alternative test methods or 

alternative monitoring requirements in 

place of any required testing methods, 

performance specifications, or 

procedures. 


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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 (EJ). Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make EJ 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, low-income, and tribal 

populations in the United States. 

This action establishes national 

emission standards for industrial, 

commercial, and institutional boilers 

that are area sources. The industrial 

boiler source category includes boilers 

used in manufacturing, processing, 

mining, refining, or any other industry. 

The commercial boiler source category 

includes boilers used in commercial 

establishments such as stores/malls, 

laundries, apartments, restaurants, 

theatres, and hotels/motels. The 

institutional boiler source category 

includes boilers used in medical centers 

(e.g., hospitals, clinics, nursing homes), 

educational and religious facilities (e.g., 

schools, universities, places of worship), 

and municipal buildings (e.g., 

courthouses, arts centers, prisons). 

There are approximately 92,000 

facilities affected by this final rule, most 

of which are small entities. By the 

defined nature of the category, many of 

these sources are located in close 

proximity to residential areas, 

commercial centers, and other locations 

where large numbers of people live and 

work. 

Due to the large number of these 

sources, their nation-wide dispersal, 

and the absence of site specific 

coordinates, EPA is unable to examine 

the distributions of exposures and 

health risks attributable to these sources 

among different socio-demographic 

groups for this rule, or to relate the 

locations of expected emission 

reductions to the locations of current 

poor air quality. However, this final rule 

is anticipated to have substantial 

emissions reductions of toxic air 

pollutants (see Table 2 of this 

preamble), some of which are potential 

carcinogens, neurotoxins, and 

respiratory irritants. This final rule will 

also result in reductions in criteria 

pollutants such as CO, PM, SO2, as well 

as ozone precursors. 

Because of the close proximity of 

these source categories to people, the 

substantial emission reductions of air 

toxics resulting from the 

implementation of this rule is 

anticipated to have health benefits for 

all persons living or going near these 

types of sources. (Please refer to the RIA 

for this rulemaking, which is available 

in the docket.) For example, there will 

be reductions of mercury emissions 

which will reduce potential exposures 

due to the atmospheric deposition of 

mercury for populations such as 

subsistence fisherman. In addition, 

there will be reductions in other air 

toxics which can cause adverse health 

effects such as ozone precursors that 

contribute to ‘‘smog.’’ EPA has 

determined that this rule will not have 

disproportionately high and 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 and adverse 

human health or environmental effects 

on any population, including any 

minority, low-income, or tribal 

populations. 

EPA defines ‘‘Environmental Justice’’ 

to include meaningful involvement of 

all people regardless of race, color, 

national origin, or income with respect 

to the development, implementation, 

and enforcement of environmental laws, 

regulations, and polices. To promote 

meaningful involvement, EPA has 

developed an EJ communication 

strategy to ensure that interested 

communities have access to this rule, 

are aware of its content, and have an 

opportunity to comment. In addition, 

state and federal permitting 

requirements will provide state and 

local governments and communities the 

opportunity to provide their comments 

on the permit conditions associated 

with permitting these sources. 

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 this final rule must 

submit a rule report, which includes a 

copy of this final rule, to each House of 

the Congress and to the Comptroller 

General of the United States. EPA will 

submit a report containing this 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 this final 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 a ‘‘major rule’’ as defined by 5 

U.S.C. 804(2). This rule will be effective 

May 20, 2011. 

List of Subjects in 40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Intergovernmental relations, 

Incorporation by reference, Reporting 

and recordkeeping requirements. 

Dated: February 21, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 63 of 

the Code of Federal Regulations is 

amended as follows: 

PART 63—[AMENDED] 

■ 1. The authority citation for part 63 

continues to read as follows: 

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

Subpart A—[Amended] 

■ 2. Section 63.14 is amended by: 

■ a. Revising paragraphs (b)(27), (b)(35), 

(b)(39) through (44), (b)(47) through 

(52), (b)(57), (b)(61), (b)(64), and (i)(1). 

■ b. Removing and reserving paragraphs 

(b)(45), (b)(46), (b)(55), (b)(56), (b)(58) 

through (60), and (b)(62). 

■ c. Adding paragraphs (b)(66) through 

(68). 

■ d. Adding paragraphs (p) and (q). 

§ 63.14 Incorporation by reference. 

* * * * * 

(b) * * * 

(27) ASTM D6522–00, Standard Test 

Method for Determination of Nitrogen 

Oxides, Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, IBR approved for 

§ 63.9307(c)(2). 

* * * * * 

(35) ASTM D6784–02 (Reapproved 

2008) Standard Test Method for 

Elemental, Oxidized, Particle-Bound 

and Total Mercury in Flue Gas 

Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method), 

approved April 1, 2008, IBR approved 

for table 1 to subpart DDDDD of this 

part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD, table 12 

to subpart DDDDD of this part, and table 

4 to subpart JJJJJJ of this part. 

* * * * * 

(39) ASTM Method D388–05, 

Standard Classification of Coals by 

Rank, approved September 15, 2005, 

IBR approved for § 63.7575 and 

§ 63.11237. 


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(40) ASTM D396–10 Standard 

Specification for Fuel Oils, approved 

October 1, 2010, IBR approved for 

§ 63.7575. 

(41) ASTM Method D1835–05, 

Standard Specification for Liquefied 

Petroleum (LP) Gases, approved April 1, 

2005, IBR approved for § 63.7575 and 

§ 63.11237. 

(42) ASTM D2013/D2013M–09 

Standard Practice for Preparing Coal 

Samples for Analysis, approved 

November 1, 2009, IBR approved for 

table 6 to subpart DDDDD of this part 

and table 5 to subpart JJJJJJ of this part. 

(43) ASTM D2234/D2234M–10 

Standard Practice for Collection of a 

Gross Sample of Coal, approved January 

1, 2010, IBR approved for table 6 to 

subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part. 

(44) ASTM D3173–03 (Reapproved 

2008) Standard Test Method for 

Moisture in the Analysis Sample of Coal 

and Coke, approved February 1, 2008, 

IBR approved for table 6 to subpart 

DDDDD of this part and table 5 to 

subpart JJJJJJ of this part. 

* * * * * 

(47) ASTM D5198–09 Standard 

Practice for Nitric Acid Digestion of 

Solid Waste, approved February 1, 2009, 

IBR approved for table 6 to subpart 

DDDDD of this part and table 5 to 

subpart JJJJJJ of this part. 

(48) ASTM D5865–10a Standard Test 

Method for Gross Calorific Value of Coal 

and Coke, approved May 1, 2010, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

(49) ASTM D6323–98 (Reapproved 

2003), Standard Guide for Laboratory 

Subsampling of Media Related to Waste 

Management Activities, approved 

August 10, 2003, IBR approved for table 

6 to subpart DDDDD of this part and 

table 5 to subpart JJJJJJ of this part. 

(50) ASTM E711–87 (Reapproved 

2004) Standard Test Method for Gross 

Calorific Value of Refuse-Derived Fuel 

by the Bomb Calorimeter, approved 

August 28, 1987, IBR approved for table 

6 to subpart DDDDD of this part and 

table 5 to subpart JJJJJJ of this part. 

(51) ASTM E776–87 (Reapproved 

2009) Standard Test Method for Forms 

of Chlorine in Refuse-Derived Fuel, 

approved July 1, 2009, IBR approved for 

table 6 to subpart DDDDD of this part. 

(52) ASTM E871–82 (Reapproved 

2006) Standard Test Method for 

Moisture Analysis of Particulate Wood 

Fuels, approved November 1, 2006, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

* * * * * 

(57) ASTM D6721–01 (Reapproved 

2006) Standard Test Method for 

Determination of Chlorine in Coal by 

Oxidative Hydrolysis Microcoulometry, 

approved April 1, 2006, IBR approved 

for table 6 to subpart DDDDD of this 

part. 

* * * * * 

(61) ASTM D6722–01 (Reapproved 

2006) Standard Test Method for Total 

Mercury in Coal and Coal Combustion 

Residues by the Direct Combustion 

Analysis, approved April 1, 2006, IBR 

approved for Table 6 to subpart DDDDD 

and Table 5 to subpart JJJJJJ of this part. 

* * * * * 

(64) ASTM D6522–00 (Reapproved 

2005), Standard Test Method for 

Determination of Nitrogen Oxides, 

Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, approved October 1, 2005, 

IBR approved for table 4 to subpart 

ZZZZ of this part, table 5 to subpart 

DDDDD of this part, and table 4 to 

subpart JJJJJJ of this part. 

* * * * * 

(66) ASTM D4084–07 Standard Test 

Method for Analysis of Hydrogen 

Sulfide in Gaseous Fuels (Lead Acetate 

Reaction Rate Method), approved June 

1, 2007, IBR approved for table 6 to 

subpart DDDDD of this part. 

(67) ASTM D5954–98 (Reapproved 

2006), Test Method for Mercury 

Sampling and Measurement in Natural 

Gas by Atomic Absorption 

Spectroscopy, approved December 1, 

2006, IBR approved for table 6 to 

subpart DDDDD of this part. 

(68) ASTM D6350–98 (Reapproved 

2003) Standard Test Method for 

Mercury Sampling and Analysis in 

Natural Gas by Atomic Fluorescence 

Spectroscopy, approved May 10, 2003, 

IBR approved for table 6 to subpart 

DDDDD of this part. 

(i) * * * 

(1) ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses [Part 

10, Instruments and Apparatus],’’ IBR 

approved for §§ 63.309(k)(1)(iii), 

63.865(b), 63.3166(a)(3), 

63.3360(e)(1)(iii), 63.3545(a)(3), 

63.3555(a)(3), 63.4166(a)(3), 

63.4362(a)(3), 63.4766(a)(3), 

63.4965(a)(3), 63.5160(d)(1)(iii), 

63.9307(c)(2), 63.9323(a)(3), 

63.11148(e)(3)(iii), 63.11155(e)(3), 

63.11162(f)(3)(iii) and (f)(4), 

63.11163(g)(1)(iii) and (g)(2), 

63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 

table 5 to subpart DDDDD of this part, 

table 1 to subpart ZZZZZ of this part, 

and table 4 to subpart JJJJJJ of this part. 

* * * * * 

(p) The following material is available 

from the U.S. Environmental Protection 

Agency, 1200 Pennsylvania Avenue, 

NW., Washington, DC 20460, (202) 272– 

0167, http://www.epa.gov. 

(1) National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for 

Integrated Iron and Steel Plants— 

Background Information for Proposed 

Standards, Final Report, EPA–453/R– 

01–005, January 2001, IBR approved for 

§ 63.7491(g). 

(2) Office Of Air Quality Planning 

And Standards (OAQPS), Fabric Filter 

Bag Leak Detection Guidance, EPA–454/ 

R–98–015, September 1997, IBR 

approved for § 63.7525(j)(2) and 

§ 63.11224(f)(2). 

(3) SW–846–3020A, Acid Digestion of 

Aqueous Samples And Extracts For 

Total Metals For Analysis By GFAA 

Spectroscopy, Revision 1, July 1992, in 

EPA Publication No. SW–846, Test 

Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third 

Edition, IBR approved for table 6 to 

subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part. 

(4) SW–846–3050B, Acid Digestion of 

Sediments, Sludges, And Soils, Revision 

2, December 1996, in EPA Publication 

No. SW–846, Test Methods for 

Evaluating Solid Waste, Physical/ 

Chemical Methods, Third Edition, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

(5) SW–846–7470A, Mercury In 

Liquid Waste (Manual Cold-Vapor 

Technique), Revision 1, September 

1994, in EPA Publication No. SW–846, 

Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD of this part and table 

5 to subpart JJJJJJ of this part. 

(6) SW–846–7471B, Mercury In Solid 

Or Semisolid Waste (Manual ColdVapor Technique), Revision 2, February 

2007, in EPA Publication No. SW–846, 

Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD of this part and table 

5 to subpart JJJJJJ of this part. 

(7) SW–846–9250, Chloride 

(Colorimetric, Automated Ferricyanide 

AAI), Revision 0, September 1986, in 

EPA Publication No. SW–846, Test 

Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third 

Edition, IBR approved for table 6 to 

subpart DDDDD of this part. 

(q) The following material is available 

for purchase from the International 


srobinson on DSKHWCL6B1PROD with RULES4
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15591 

Standards Organization (ISO), 1, ch. de 

la Voie-Creuse, Case postale 56, CH– 

1211 Geneva 20, Switzerland, +41 22 

749 01 11, http://www.iso.org/iso/ 

home.htm. 

(1) ISO 6978–1:2003(E), Natural Gas— 

Determination of Mercury—Part 1: 

Sampling of Mercury by Chemisorption 

on Iodine, First edition, October 15, 

2003, IBR approved for table 6 to 

subpart DDDDD of this part. 

(2) ISO 6978–2:2003(E), Natural gas— 

Determination of Mercury—Part 2: 

Sampling of Mercury by Amalgamation 

on Gold/Platinum Alloy, First edition, 

October 15, 2003, IBR approved for table 

6 to subpart DDDDD of this part. 

■ 3. Part 63 is amended by adding 

subpart JJJJJJ to read as follows: 

Subpart JJJJJJ—National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers Area Sources 

Sec. 

What This Subpart Covers 

63.11193 Am I subject to this subpart? 

63.11194 What is the affected source of this 

subpart? 

63.11195 Are any boilers not subject to this 

subpart? 

63.11196 What are my compliance dates? 

Emission Limits, Work Practice Standards, 

Emission Reduction Measures, and 

Management Practices 

63.11200 What are the subcategories of 

boilers? 

63.11201 What standards must I meet? 

General Compliance Requirements 

63.11205 What are my general requirements 

for complying with this subpart? 

Initial Compliance Requirements 

63.11210 What are my initial compliance 

requirements and by what date must I 

conduct them? 

63.11211 How do I demonstrate initial 

compliance with the emission limits? 

63.11212 What stack tests and procedures 

must I use for the performance tests? 

63.11213 What fuel analyses and 

procedures must I use for the 

performance tests? 

63.11214 How do I demonstrate initial 

compliance with the work practice 

standard, emission reduction measures, 

and management practice? 

Continuous Compliance Requirements 

63.11220 When must I conduct subsequent 

performance tests? 

63.11221 How do I monitor and collect data 

to demonstrate continuous compliance? 

63.11222 How do I demonstrate continuous 

compliance with the emission limits? 

63.11223 How do I demonstrate continuous 

compliance with the work practice and 

management practice standards? 

63.11224 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

63.11225 What are my notification, 

reporting, and recordkeeping 

requirements? 

63.11226 How can I assert an affirmative 

defense if I exceed an emission limit 

during a malfunction? 

Other Requirements and Information 

63.11235 What parts of the General 

Provisions apply to me? 

63.11236 Who implements and enforces 

this subpart? 

63.11237 What definitions apply to this 

subpart? 

Table 1 to Subpart JJJJJJ of Part 63—Emission 

Limits 

Table 2 to Subpart JJJJJJ of Part 63—Work 

Practice Standards 

Table 3 to Subpart JJJJJJ of Part 63—Operating 

Limits for Boilers With Emission Limits 

Table 4 to Subpart JJJJJJ of Part 63— 

Performance (Stack) Testing 

Requirements 

Table 5 to Subpart JJJJJJ of Part 63—Fuel 

Analysis Requirements 

Table 6 to Subpart JJJJJJ of Part 63 — 

Establishing Operating Limit 

Table 7 to Subpart JJJJJJ of Part 63— 

Demonstrating Continuous Compliance 

Table 8 to Subpart JJJJJJ of Part 63— 

Applicability of General Provisions to 

Subpart JJJJJJ 

Subpart JJJJJJ—National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers Area Sources 

What This Subpart Covers 

§ 63.11193 Am I subject to this subpart? 

You are subject to this subpart if you 

own or operate an industrial, 

commercial, or institutional boiler as 

defined in § 63.11237 that is located at, 

or is part of, an area source of hazardous 

air pollutants (HAP), as defined in 

§ 63.2, except as specified in § 63.11195. 

§ 63.11194 What is the affected source of 

this subpart? 

(a) This subpart applies to each new, 

reconstructed, or existing affected 

source as defined in paragraphs (a)(1) 

and (2) of this section. 

(1) The affected source is the 

collection of all existing industrial, 

commercial, and institutional boilers 

within a subcategory (coal, biomass, 

oil), as listed in § 63.11200 and defined 

in § 63.11237, located at an area source. 

(2) The affected source of this subpart 

is each new or reconstructed industrial, 

commercial, or institutional boiler 

within a subcategory, as listed in 

§ 63.11200 and as defined in § 63.11237, 

located at an area source. 

(b) An affected source is an existing 

source if you commenced construction 

or reconstruction of the affected source 

on or before June 4, 2010. 

(c) An affected source is a new source 

if you commenced construction or 

reconstruction of the affected source 

after June 4, 2010 and you meet the 

applicability criteria at the time you 

commence construction. 

(d) A boiler is a new affected source 

if you commenced fuel switching from 

natural gas to solid fossil fuel, biomass, 

or liquid fuel after June 4, 2010. 

(e) If you are an owner or operator of 

an area source subject to this subpart, 

you are exempt from the obligation to 

obtain a permit under 40 CFR part 70 or 

part 71 as a result of this subpart. You 

may, however, be required to obtain a 

title V permit due to another reason or 

reasons. See 40 CFR 70.3(a) and (b) or 

71.3(a) and (b). Notwithstanding the 

exemption from title V permitting for 

area sources under this subpart, you 

must continue to comply with the 

provisions of this subpart. 

§ 63.11195 Are any boilers not subject to 

this subpart? 

The types of boilers listed in 

paragraphs (a) through (g) of this section 

are not subject to this subpart and to any 

requirements in this subpart. 

(a) Any boiler specifically listed as, or 

included in the definition of, an affected 

source in another standard(s) under this 

part. 

(b) Any boiler specifically listed as an 

affected source in another standard(s) 

established under section 129 of the 

Clean Air Act. 

(c) A boiler required to have a permit 

under section 3005 of the Solid Waste 

Disposal Act or covered by subpart EEE 

of this part (e.g., hazardous waste 

boilers). 

(d) A boiler that is used specifically 

for research and development. This 

exemption does not include boilers that 

solely or primarily provide steam (or 

heat) to a process or for heating at a 

research and development facility. This 

exemption does not prohibit the use of 

the steam (or heat) generated from the 

boiler during research and development, 

however, the boiler must be 

concurrently and primarily engaged in 

research and development for the 

exemption to apply. 

(e) A gas-fired boiler as defined in this 

subpart. 

(f) A hot water heater as defined in 

this subpart. 

(g) Any boiler that is used as a control 

device to comply with another subpart 

of this part, provided that at least 50 

percent of the heat input to the boiler is 

provided by the gas stream that is 

regulated under another subpart. 

§ 63.11196 What are my compliance 

dates? 

(a) If you own or operate an existing 

affected boiler, you must achieve 


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compliance with the applicable 

provisions in this subpart as specified in 

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

section. 

(1) If the existing affected boiler is 

subject to a work practice or 

management practice standard of a tuneup, you must achieve compliance with 

the work practice or management 

standard no later than March 21, 2012. 

(2) If the existing affected boiler is 

subject to emission limits, you must 

achieve compliance with the emission 

limits no later than March 21, 2014. 

(3) If the existing affected boiler is 

subject to the energy assessment 

requirement, you must achieve 

compliance with the energy assessment 

requirement no later than March 21, 

2014. 

(b) If you start up a new affected 

source on or before May 20, 2011, you 

must achieve compliance with the 

provisions of this subpart no later than 

May 20, 2011. 

(c) If you start up a new affected 

source after May 20, 2011, you must 

achieve compliance with the provisions 

of this subpart upon startup of your 

affected source. 

(d) If you own or operate an 

industrial, commercial, or institutional 

boiler and would be subject to this 

subpart except for the exemption in 

§ 63.11195(b) for commercial and 

industrial solid waste incineration units 

covered by 40 CFR part 60, subpart 

CCCC or subpart DDDD, and you cease 

combusting solid waste, you must be in 

compliance with this subpart on the 

effective date of the waste to fuel 

switch. 

Emission Limits, Work Practice 

Standards, Emission Reduction 

Measures, and Management Practices 

§ 63.11200 What are the subcategories of 

boilers? 

The subcategories of boilers are coal, 

biomass, and oil. Each subcategory is 

defined in § 63.11237. 

§ 63.11201 What standards must I meet? 

(a) You must comply with each 

emission limit specified in Table 1 to 

this subpart that applies to your boiler. 

(b) You must comply with each work 

practice standard, emission reduction 

measure, and management practice 

specified in Table 2 to this subpart that 

applies to your boiler. An energy 

assessment completed on or after 

January 1, 2008 that meets the 

requirements in Table 2 to this subpart 

satisfies the energy assessment portion 

of this requirement. 

(c) You must comply with each 

operating limit specified in Table 3 to 

this subpart that applies to your boiler. 

(d) These standards apply at all times. 

General Compliance Requirements 

§ 63.11205 What are my general 

requirements for complying with this 

subpart? 

(a) At all times you must operate and 

maintain any affected source, including 

associated air pollution control 

equipment and monitoring equipment, 

in a manner consistent with safety and 

good air pollution control practices for 

minimizing emissions. The general duty 

to minimize emissions does not require 

you to make any further efforts to 

reduce emissions if levels required by 

this standard have been achieved. 

Determination of whether such 

operation and maintenance procedures 

are being used will be based on 

information available to the 

Administrator that may include, but is 

not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

(b) You can demonstrate compliance 

with any applicable mercury emission 

limit using fuel analysis if the emission 

rate calculated according to 

§ 63.11211(c) is less than the applicable 

emission limit. Otherwise, you must 

demonstrate compliance using stack 

testing. 

(c) If you demonstrate compliance 

with any applicable emission limit 

through performance stack testing and 

subsequent compliance with operating 

limits (including the use of continuous 

parameter monitoring system), with a 

CEMS, or with a COMS, you must 

develop a site-specific monitoring plan 

according to the requirements in 

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

section for the use of any CEMS, COMS, 

or continuous parameter monitoring 

system. This requirement also applies to 

you if you petition the EPA 

Administrator for alternative monitoring 

parameters under § 63.8(f). 

(1) For each continuous monitoring 

system required in this section 

(including CEMS, COMS, or continuous 

parameter monitoring system), you must 

develop, and submit to the delegated 

authority for approval upon request, a 

site-specific monitoring plan that 

addresses paragraphs (c)(1)(i) through 

(vi) of this section. You must submit 

this site-specific monitoring plan, if 

requested, at least 60 days before your 

initial performance evaluation of your 

CMS. This requirement to develop and 

submit a site specific monitoring plan 

does not apply to affected sources with 

existing monitoring plans that apply to 

CEMS and COMS prepared under 

Appendix B to part 60 of this chapter 

and which meet the requirements of 

§ 63.11224. 

(i) Installation of the continuous 

monitoring system sampling probe or 

other interface at a measurement 

location relative to each affected process 

unit such that the measurement is 

representative of control of the exhaust 

emissions (e.g., on or downstream of the 

last control device); 

(ii) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems; and 

(iii) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations). 

(iv) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii); 

(v) Ongoing data quality assurance 

procedures in accordance with the 

general requirements of § 63.8(d); and 

(vi) Ongoing recordkeeping and 

reporting procedures in accordance with 

the general requirements of § 63.10(c) 

(as applicable in Table 8 to this 

subpart), (e)(1), and (e)(2)(i). 

(2) You must conduct a performance 

evaluation of each CMS in accordance 

with your site-specific monitoring plan. 

(3) You must operate and maintain 

the CMS in continuous operation 

according to the site-specific monitoring 

plan. 

Initial Compliance Requirements 

§ 63.11210 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) You must demonstrate initial 

compliance with each emission limit 

specified in Table 1 to this subpart that 

applies to you by either conducting 

performance (stack) tests, as applicable, 

according to § 63.11212 and Table 4 to 

this subpart or, for mercury, conducting 

fuel analyses, as applicable, according 

to § 63.11213 and Table 5 to this 

subpart. 

(b) For existing affected boilers that 

have applicable emission limits, you 

must demonstrate initial compliance no 

later than 180 days after the compliance 

date that is specified in § 63.11196 and 

according to the applicable provisions 

in § 63.7(a)(2). 

(c) For existing affected boilers that 

have applicable work practice 

standards, management practices, or 

emission reduction measures, you must 

demonstrate initial compliance no later 

than the compliance date that is 

specified in § 63.11196 and according to 

the applicable provisions in § 63.7(a)(2). 

(d) For new or reconstructed affected 

sources, you must demonstrate initial 


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compliance no later than 180 calendar 

days after March 21, 2011 or within 180 

calendar days after startup of the source, 

whichever is later, according to 

§ 63.7(a)(2)(ix). 

(e) For affected boilers that ceased 

burning solid waste consistent with 

§ 63.11196(d), you must demonstrate 

compliance within 60 days of the 

effective date of the waste-to-fuel 

switch. If you have not conducted your 

compliance demonstration for this 

subpart within the previous 12 months, 

you must complete all compliance 

demonstrations before you commence or 

recommence combustion of solid waste. 

§ 63.11211 How do I demonstrate initial 

compliance with the emission limits? 

(a) For affected boilers that 

demonstrate compliance with any of the 

emission limits of this subpart through 

performance (stack) testing, your initial 

compliance requirements include 

conducting performance tests according 

to § 63.11212 and Table 4 to this 

subpart, conducting a fuel analysis for 

each type of fuel burned in your boiler 

according to § 63.11213 and Table 5 to 

this subpart, establishing operating 

limits according to § 63.11222, Table 6 

to this subpart and paragraph (b) of this 

section, as applicable, and conducting 

continuous monitoring system (CMS) 

performance evaluations according to 

§ 63.11224. For affected boilers that 

burn a single type of fuel, you are 

exempted from the compliance 

requirements of conducting a fuel 

analysis for each type of fuel burned in 

your boiler. For purposes of this 

subpart, boilers that use a supplemental 

fuel only for startup, unit shutdown, 

and transient flame stability purposes 

still qualify as affected boilers that burn 

a single type of fuel, and the 

supplemental fuel is not subject to the 

fuel analysis requirements under 

§ 63.11213 and Table 5 to this subpart. 

(b) You must establish parameter 

operating limits according to paragraphs 

(b)(1) through (4) of this section. 

(1) For a wet scrubber, you must 

establish the minimum liquid flowrate 

and pressure drop as defined in 

§ 63.11237, as your operating limits 

during the three-run performance stack 

test. If you use a wet scrubber and you 

conduct separate performance stack 

tests for particulate matter and mercury 

emissions, you must establish one set of 

minimum scrubber liquid flowrate and 

pressure drop operating limits. If you 

conduct multiple performance stack 

tests, you must set the minimum liquid 

flowrate and pressure drop operating 

limits at the highest minimum values 

established during the performance 

stack tests. 

(2) For an electrostatic precipitator 

operated with a wet scrubber, you must 

establish the minimum voltage and 

secondary amperage (or total electric 

power input), as defined in § 63.11237, 

as your operating limits during the 

three-run performance stack test. (These 

operating limits do not apply to 

electrostatic precipitators that are 

operated as dry controls without a wet 

scrubber.) 

(3) For activated carbon injection, you 

must establish the minimum activated 

carbon injection rate, as defined in 

§ 63.11237, as your operating limit 

during the three-run performance stack 

test. 

(4) The operating limit for boilers 

with fabric filters that demonstrate 

continuous compliance through bag leak 

detection systems is that a bag leak 

detection system be installed according 

to the requirements in § 63.11224, and 

that each fabric filter must be operated 

such that the bag leak detection system 

alarm does not sound more than 5 

percent of the operating time during a 

6-month period. 

(c) If you elect to demonstrate 

compliance with an applicable mercury 

emission limit through fuel analysis, 

you must conduct fuel analyses 

according to § 63.11213 and Table 5 to 

this subpart and follow the procedures 

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

section. 

(1) If you burn more than one fuel 

type, you must determine the fuel type, 

or mixture, you could burn in your 

boiler that would result in the 

maximum emission rates of mercury. 

(2) You must determine the 90th 

percentile confidence level fuel mercury 

concentration of the composite samples 

analyzed for each fuel type using 

Equation 1 of this section. 

Where: 

P90 = 90th percentile confidence level 

mercury concentration, in pounds per 

million Btu. 

mean = Arithmetic average of the fuel 

mercury concentration in the fuel 

samples analyzed according to 

§ 63.11213, in units of pounds per 

million Btu. 

SD = Standard deviation of the mercury 

concentration in the fuel samples 

analyzed according to § 63.11213, in 

units of pounds per million Btu. 

t = t distribution critical value for 90th 

percentile (0.1) probability for the 

appropriate degrees of freedom (number 

of samples minus one) as obtained from 

a Distribution Critical Value Table. 

(3) To demonstrate compliance with 

the applicable mercury emission limit, 

the emission rate that you calculate for 

your boiler using Equation 1 of this 

section must be less than the applicable 

mercury emission limit. 

§ 63.11212 What stack tests and 

procedures must I use for the performance 

tests? 

(a) You must conduct all performance 

tests according to § 63.7(c), (d), (f), and 

(h). You must also develop a sitespecific test plan according to the 

requirements in § 63.7(c). 

(b) You must conduct each stack test 

according to the requirements in Table 

4 to this subpart. 

(c) You must conduct performance 

stack tests at the representative 

operating load conditions while burning 

the type of fuel or mixture of fuels that 

have the highest emissions potential for 

each regulated pollutant, and you must 

demonstrate initial compliance and 

establish your operating limits based on 

these performance stack tests. For 

subcategories with more than one 

emission limit, these requirements 

could result in the need to conduct 

more than one performance stack test. 

Following each performance stack test 

and until the next performance stack 

test, you must comply with the 

operating limit for operating load 

conditions specified in Table 3 to this 

subpart. 

(d) You must conduct a minimum of 

three separate test runs for each 

performance stack test required in this 

section, as specified in § 63.7(e)(3) and 

in accordance with the provisions in 

Table 4 to this subpart. 

(e) To determine compliance with the 

emission limits, you must use the F– 

Factor methodology and equations in 

sections 12.2 and 12.3 of EPA Method 

19 of appendix A–7 to part 60 of this 

chapter to convert the measured 

particulate matter concentrations and 

the measured mercury concentrations 

that result from the initial performance 

test to pounds per million Btu heat 

input emission rates. 


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15594 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

§ 63.11213 What fuel analyses and 

procedures must I use for the performance 

tests? 

(a) You must conduct fuel analyses 

according to the procedures in 

paragraphs (b) and (c) of this section 

and Table 5 to this subpart, as 

applicable. You are not required to 

conduct fuel analyses for fuels used for 

only startup, unit shutdown, and 

transient flame stability purposes. You 

are required to conduct fuel analyses 

only for fuels and units that are subject 

to emission limits for mercury in Table 

1 of this subpart. 

(b) At a minimum, you must obtain 

three composite fuel samples for each 

fuel type according to the procedures in 

Table 5 to this subpart. Each composite 

sample must consist of a minimum of 

three samples collected at 

approximately equal intervals during a 

test run period. 

(c) Determine the concentration of 

mercury in the fuel in units of pounds 

per million Btu of each composite 

sample for each fuel type according to 

the procedures in Table 5 to this 

subpart. 

§ 63.11214 How do I demonstrate initial 

compliance with the work practice 

standard, emission reduction measures, 

and management practice? 

(a) If you own or operate an existing 

or new coal-fired boiler with a heat 

input capacity of less than 10 million 

Btu per hour, you must conduct a 

performance tune-up according to 

§ 63.11223(b) and you must submit a 

signed statement in the Notification of 

Compliance Status report that indicates 

that you conducted a tune-up of the 

boiler. 

(b) If you own or operate an existing 

or new biomass-fired boiler or an 

existing or new oil-fired boiler, you 

must conduct a performance tune-up 

according to § 63.11223(b) and you must 

submit a signed statement in the 

Notification of Compliance Status report 

that indicates that you conducted a 

tune-up of the boiler. 

(c) If you own or operate an existing 

affected boiler with a heat input 

capacity of 10 million Btu per hour or 

greater, you must submit a signed 

certification in the Notification of 

Compliance Status report that an energy 

assessment of the boiler and its energy 

use systems was completed and submit, 

upon request, the energy assessment 

report. 

(d) If you own or operate a boiler 

subject to emission limits in Table 1 of 

this subpart, you must minimize the 

boiler’s startup and shutdown periods 

following the manufacturer’s 

recommended procedures, if available. 

If manufacturer’s recommended 

procedures are not available, you must 

follow recommended procedures for a 

unit of similar design for which 

manufacturer’s recommended 

procedures are available. You must 

submit a signed statement in the 

Notification of Compliance Status report 

that indicates that you conducted 

startups and shutdowns according to the 

manufacturer’s recommended 

procedures or procedures specified for a 

boiler of similar design if 

manufacturer’s recommended 

procedures are not available. 

Continuous Compliance Requirements 

§ 63.11220 When must I conduct 

subsequent performance tests? 

(a) If your boiler has a heat input 

capacity of 10 million Btu per hour or 

greater, you must conduct all applicable 

performance (stack) tests according to 

§ 63.11212 on an triennial basis, unless 

you follow the requirements listed in 

paragraphs (b) through (d) of this 

section. Triennial performance tests 

must be completed no more than 37 

months after the previous performance 

test, unless you follow the requirements 

listed in paragraphs (b) through (d) of 

this section. 

(b) You can conduct performance 

stack tests less often for particulate 

matter or mercury if your performance 

stack tests for the pollutant for at least 

3 consecutive years show that your 

emissions are at or below 75 percent of 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions. In this case, you do not have 

to conduct a performance stack test for 

that pollutant for the next 2 years. You 

must conduct a performance stack test 

during the third year and no more than 

37 months after the previous 

performance stack test. 

(c) If your boiler continues to meet the 

emission limit for particulate matter or 

mercury, you may choose to conduct 

performance stack tests for the pollutant 

every third year if your emissions are at 

or below 75 percent of the emission 

limit, and if there are no changes in the 

operation of the affected source or air 

pollution control equipment that could 

increase emissions, but each such 

performance stack test must be 

conducted no more than 37 months after 

the previous performance test. 

(d) If you have an applicable CO 

emission limit, you must conduct 

triennial performance tests for CO 

according to § 63.11212. Each triennial 

performance test must be conducted 

between no more than 37 months after 

the previous performance test. 

(e) If you demonstrate compliance 

with the mercury emission limit based 

on fuel analysis, you must conduct a 

fuel analysis according to § 63.11213 for 

each type of fuel burned monthly. If you 

plan to burn a new type of fuel or fuel 

mixture, you must conduct a fuel 

analysis before burning the new type of 

fuel or mixture in your boiler. You must 

recalculate the mercury emission rate 

using Equation 1 of § 63.11211. The 

recalculated mercury emission rate must 

be less than the applicable emission 

limit. 

§ 63.11221 How do I monitor and collect 

data to demonstrate continuous 

compliance? 

(a) You must monitor and collect data 

according to this section. 

(b) You must operate the monitoring 

system and collect data at all required 

intervals at all times the affected source 

is operating except for periods of 

monitoring system malfunctions or outof-control periods, repairs associated 

with monitoring system malfunctions or 

out-of-control periods (see section 

63.8(c)(7) of this part), and required 

monitoring system quality assurance or 

quality control activities including, as 

applicable, calibration checks and 

required zero and span adjustments. A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

You are required to effect monitoring 

system repairs in response to 

monitoring system malfunctions or outof-control periods and to return the 

monitoring system to operation as 

expeditiously as practicable. 

(c) You may not use data recorded 

during monitoring system malfunctions 

or out-of-control periods, repairs 

associated with monitoring system 

malfunctions or out-of-control periods, 

or required monitoring system quality 

assurance or control activities in 

calculations used to report emissions or 

operating levels. You must use all the 

data collected during all other periods 

in assessing the operation of the control 

device and associated control system. 

(d) Except for periods of monitoring 

system malfunctions or out-of-control 

periods, repairs associated with 

monitoring system malfunctions or outof-control periods, and required 

monitoring system quality assurance or 

quality control activities including, as 

applicable, calibration checks and 

required zero and span adjustments, 


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failure to collect required data is a 

deviation of the monitoring 

requirements. 

§ 63.11222 How do I demonstrate 

continuous compliance with the emission 

limits? 

(a) You must demonstrate continuous 

compliance with each emission limit 

and operating limit in Tables 1 and 3 to 

this subpart that applies to you 

according to the methods specified in 

Table 7 to this subpart and to 

paragraphs (a)(1) through (4) of this 

section. 

(1) Following the date on which the 

initial compliance demonstration is 

completed or is required to be 

completed under §§ 63.7 and 63.11196, 

whichever date comes first, you must 

continuously monitor the operating 

parameters. Operation above the 

established maximum, below the 

established minimum, or outside the 

allowable range of the operating limits 

specified in paragraph (a) of this section 

constitutes a deviation from your 

operating limits established under this 

subpart, except during performance 

tests conducted to determine 

compliance with the emission and 

operating limits or to establish new 

operating limits. Operating limits are 

confirmed or reestablished during 

performance tests. 

(2) If you have an applicable mercury 

or PM emission limit, you must keep 

records of the type and amount of all 

fuels burned in each boiler during the 

reporting period to demonstrate that all 

fuel types and mixtures of fuels burned 

would result in lower emissions of 

mercury than the applicable emission 

limit (if you demonstrate compliance 

through fuel analysis), or result in lower 

fuel input of mercury than the 

maximum values calculated during the 

last performance stack test (if you 

demonstrate compliance through 

performance stack testing). 

(3) If you have an applicable mercury 

emission limit and you plan to burn a 

new type of fuel, you must determine 

the mercury concentration for any new 

fuel type in units of pounds per million 

Btu, using the procedures in Equation 1 

of § 63.11211 based on supplier data or 

your own fuel analysis, and meet the 

requirements in paragraphs (a)(3)(i) or 

(ii) of this section. 

(i) The recalculated mercury emission 

rate must be less than the applicable 

emission limit. 

(ii) If the mercury concentration is 

higher than mercury fuel input during 

the previous performance test, then you 

must conduct a new performance test 

within 60 days of burning the new fuel 

type or fuel mixture according to the 

procedures in § 63.11212 to demonstrate 

that the mercury emissions do not 

exceed the emission limit. 

(4) If your unit is controlled with a 

fabric filter, and you demonstrate 

continuous compliance using a bag leak 

detection system, you must initiate 

corrective action within 1 hour of a bag 

leak detection system alarm and operate 

and maintain the fabric filter system 

such that the alarm does not sound 

more than 5 percent of the operating 

time during a 6-month period. You must 

also keep records of the date, time, and 

duration of each alarm, the time 

corrective action was initiated and 

completed, and a brief description of the 

cause of the alarm and the corrective 

action taken. You must also record the 

percent of the operating time during 

each 6-month period that the alarm 

sounds. In calculating this operating 

time percentage, if inspection of the 

fabric filter demonstrates that no 

corrective action is required, no alarm 

time is counted. If corrective action is 

required, each alarm is counted as a 

minimum of 1 hour. If you take longer 

than 1 hour to initiate corrective action, 

the alarm time is counted as the actual 

amount of time taken to initiate 

corrective action. 

(b) You must report each instance in 

which you did not meet each emission 

limit and operating limit in Tables 1 and 

3 to this subpart that apply to you. 

These instances are deviations from the 

emission limits in this subpart. These 

deviations must be reported according 

to the requirements in § 63.11225. 

§ 63.11223 How do I demonstrate 

continuous compliance with the work 

practice and management practice 

standards? 

(a) For affected sources subject to the 

work practice standard or the 

management practices of a tune-up, you 

must conduct a biennial performance 

tune-up according to paragraphs (b) of 

this section and keep records as 

required in § 63.11225(c) to demonstrate 

continuous compliance. Each biennial 

tune-up must be conducted no more 

than 25 months after the previous tuneup. 

(b) You must conduct a tune-up of the 

boiler biennially to demonstrate 

continuous compliance as specified in 

paragraphs (b)(1) through (7) of this 

section. 

(1) As applicable, inspect the burner, 

and clean or replace any components of 

the burner as necessary (you may delay 

the burner inspection until the next 

scheduled unit shutdown, but you must 

inspect each burner at least once every 

36 months). 

(2) Inspect the flame pattern, as 

applicable, and adjust the burner as 

necessary to optimize the flame pattern. 

The adjustment should be consistent 

with the manufacturer’s specifications, 

if available. 

(3) Inspect the system controlling the 

air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and 

functioning properly. 

(4) Optimize total emissions of carbon 

monoxide. This optimization should be 

consistent with the manufacturer’s 

specifications, if available. 

(5) Measure the concentrations in the 

effluent stream of carbon monoxide in 

parts per million, by volume, and 

oxygen in volume percent, before and 

after the adjustments are made 

(measurements may be either on a dry 

or wet basis, as long as it is the same 

basis before and after the adjustments 

are made). 

(6) Maintain onsite and submit, if 

requested by the Administrator, biennial 

report containing the information in 

paragraphs (b)(6)(i) through (iii) of this 

section. 

(i) The concentrations of CO in the 

effluent stream in parts per million, by 

volume, and oxygen in volume percent, 

measured before and after the tune-up of 

the boiler. 

(ii) A description of any corrective 

actions taken as a part of the tune-up of 

the boiler. 

(iii) The type and amount of fuel used 

over the 12 months prior to the biennial 

tune-up of the boiler. 

(7) If the unit is not operating on the 

required date for a tune-up, the tune-up 

must be conducted within one week of 

startup. 

(c) If you own or operate an existing 

or new coal-fired boiler with a heat 

input capacity of 10 million Btu per 

hour or greater, you must minimize the 

boiler’s time spent during startup and 

shutdown following the manufacturer’s 

recommended procedures and you must 

submit a signed statement in the 

Notification of Compliance Status report 

that indicates that you conducted 

startups and shutdowns according to the 

manufacturer’s recommended 

procedures. 

§ 63.11224 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) If your boiler is subject to a carbon 

monoxide emission limit in Table 1 to 

this subpart, you must install, operate, 

and maintain a continuous oxygen 

monitor according to the procedures in 

paragraphs (a)(1) through (6) of this 

section by the compliance date specified 

in § 63.11196. The oxygen level shall be 

monitored at the outlet of the boiler. 


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15596 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

(1) Each monitor must be installed, 

operated, and maintained according to 

the applicable procedures under 

Performance Specification 3 at 40 CFR 

part 60, appendix B, and according to 

the site-specific monitoring plan 

developed according to paragraph (c) of 

this section. 

(2) You must conduct a performance 

evaluation of each CEMS according to 

the requirements in § 63.8(e) and 

according to Performance Specification 

3 at 40 CFR part 60, appendix B. 

(3) Each CEMS must complete a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. 

(4) The CEMS data must be reduced 

as specified in § 63.8(g)(2). 

(5) You must calculate and record the 

12-hour block average concentrations. 

(6) For purposes of calculating data 

averages, you must use all the data 

collected during all periods in assessing 

compliance, excluding data collected 

during periods when the monitoring 

system malfunctions or is out of control, 

during associated repairs, and during 

required quality assurance or control 

activities (including, as applicable, 

calibration checks and required zero 

and span adjustments). Monitoring 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. Any period for which 

the monitoring system malfunctions or 

is out of control and data are not 

available for a required calculation 

constitutes a deviation from the 

monitoring requirements. Periods when 

data are unavailable because of required 

quality assurance or control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments) do not constitute 

monitoring deviations. 

(b) If you are using a control device 

to comply with the emission limits 

specified in Table 1 to this subpart, you 

must maintain each operating limit in 

Table 3 to this subpart that applies to 

your boiler as specified in Table 7 to 

this subpart. If you use a control device 

not covered in Table 3 to this subpart, 

or you wish to establish and monitor an 

alternative operating limit and 

alternative monitoring parameters, you 

must apply to the United States 

Environmental Protection Agency (EPA) 

Administrator for approval of 

alternative monitoring under § 63.8(f). 

(c) If you demonstrate compliance 

with any applicable emission limit 

through stack testing and subsequent 

compliance with operating limits, you 

must develop a site-specific monitoring 

plan according to the requirements in 

paragraphs (c)(1) through (4) of this 

section. This requirement also applies to 

you if you petition the EPA 

Administrator for alternative monitoring 

parameters under § 63.8(f). 

(1) For each continuous monitoring 

system (CMS) required in this section, 

you must develop, and submit to the 

EPA Administrator for approval upon 

request, a site-specific monitoring plan 

that addresses paragraphs (b)(1)(i) 

through (iii) of this section. You must 

submit this site-specific monitoring plan 

(if requested) at least 60 days before 

your initial performance evaluation of 

your CMS. 

(i) Installation of the CMS sampling 

probe or other interface at a 

measurement location relative to each 

affected unit such that the measurement 

is representative of control of the 

exhaust emissions (e.g., on or 

downstream of the last control device). 

(ii) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems. 

(iii) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations). 

(2) In your site-specific monitoring 

plan, you must also address paragraphs 

(b)(2)(i) through (iii) of this section. 

(i) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

§ 63.8(c)(1), (3), and (4)(ii). 

(ii) Ongoing data quality assurance 

procedures in accordance with the 

general requirements of § 63.8(d). 

(iii) Ongoing recordkeeping and 

reporting procedures in accordance with 

the general requirements of § 63.10(c), 

(e)(1), and (e)(2)(i). 

(3) You must conduct a performance 

evaluation of each CMS in accordance 

with your site-specific monitoring plan. 

(4) You must operate and maintain 

the CMS in continuous operation 

according to the site-specific monitoring 

plan. 

(d) If you have an operating limit that 

requires the use of a CMS, you must 

install, operate, and maintain each 

continuous parameter monitoring 

system according to the procedures in 

paragraphs (d)(1) through (5) of this 

section. 

(1) The continuous parameter 

monitoring system must complete a 

minimum of one cycle of operation for 

each successive 15-minute period. You 

must have a minimum of four 

successive cycles of operation to have a 

valid hour of data. 

(2) Except for monitoring 

malfunctions, associated repairs, and 

required quality assurance or control 

activities (including, as applicable, 

calibration checks and required zero 

and span adjustments), you must 

conduct all monitoring in continuous 

operation at all times that the unit is 

operating. A monitoring malfunction is 

any sudden, infrequent, not reasonably 

preventable failure of the monitoring to 

provide valid data. Monitoring failures 

that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. 

(3) For purposes of calculating data 

averages, you must not use data 

recorded during monitoring 

malfunctions, associated repairs, out of 

control periods, or required quality 

assurance or control activities. You 

must use all the data collected during 

all other periods in assessing 

compliance. Any period for which the 

monitoring system is out-of-control and 

data are not available for a required 

calculation constitutes a deviation from 

the monitoring requirements. 

(4) Determine the 12-hour block 

average of all recorded readings, except 

as provided in paragraph (d)(3) of this 

section. 

(5) Record the results of each 

inspection, calibration, and validation 

check. 

(e) If you have an applicable opacity 

operating limit under this rule, you 

must install, operate, certify and 

maintain each continuous opacity 

monitoring system (COMS) according to 

the procedures in paragraphs (e)(1) 

through (7) of this section by the 

compliance date specified in § 63.11196. 

(1) Each COMS must be installed, 

operated, and maintained according to 

Performance Specification 1 of 40 CFR 

part 60, appendix B. 

(2) You must conduct a performance 

evaluation of each COMS according to 

the requirements in § 63.8 and 

according to Performance Specification 

1 of 40 CFR part 60, appendix B. 

(3) As specified in § 63.8(c)(4)(i), each 

COMS 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. 

(4) The COMS data must be reduced 

as specified in § 63.8(g)(2). 

(5) You must include in your sitespecific monitoring plan procedures and 

acceptance criteria for operating and 

maintaining each COMS according to 

the requirements in § 63.8(d). At a 

minimum, the monitoring plan must 

include a daily calibration drift 

assessment, a quarterly performance 

audit, and an annual zero alignment 

audit of each COMS. 

(6) You must operate and maintain 

each COMS according to the 

requirements in the monitoring plan 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15597 

and the requirements of § 63.8(e). 

Identify periods the COMS is out of 

control including any periods that the 

COMS fails to pass a daily calibration 

drift assessment, a quarterly 

performance audit, or an annual zero 

alignment audit. 

(7) You must determine and record all 

the 1-hour block averages collected for 

periods during which the COMS is not 

out of control. 

(f) If you use a fabric filter bag leak 

detection system to comply with the 

requirements of this subpart, you must 

install, calibrate, maintain, and 

continuously operate the bag leak 

detection system as specified in 

paragraphs (f)(1) through (8) of this 

section. 

(1) You must install and operate a bag 

leak detection system for each exhaust 

stack of the fabric filter. 

(2) Each bag leak detection system 

must be installed, operated, calibrated, 

and maintained in a manner consistent 

with the manufacturer’s written 

specifications and recommendations 

and in accordance with EPA–454/R–98– 

015 (incorporated by reference, see 

§ 63.14). 

(3) The bag leak detection system 

must be certified by the manufacturer to 

be capable of detecting particulate 

matter emissions at concentrations of 10 

milligrams per actual cubic meter or 

less. 

(4) The bag leak detection system 

sensor must provide output of relative 

or absolute particulate matter loadings. 

(5) The bag leak detection system 

must be equipped with a device to 

continuously record the output signal 

from the sensor. 

(6) The bag leak detection system 

must be equipped with an audible or 

visual alarm system that will activate 

automatically when an increase in 

relative particulate matter emissions 

over a preset level is detected. The 

alarm must be located where it is easily 

heard or seen by plant operating 

personnel. 

(7) For positive pressure fabric filter 

systems that do not duct all 

compartments of cells to a common 

stack, a bag leak detection system must 

be installed in each baghouse 

compartment or cell. 

(8) Where multiple bag leak detectors 

are required, the system’s 

instrumentation and alarm may be 

shared among detectors. 

§ 63.11225 What are my notification, 

reporting, and recordkeeping 

requirements? 

(a) You must submit the notifications 

specified in paragraphs (a)(1) through 

(a)(5) of this section to the delegated 

authority. 

(1) You must submit all of the 

notifications in §§ 63.7(b): 63.8(e) and 

(f); 63.9(b) through (e); and 63.9(g) and 

(h) that apply to you by the dates 

specified in those sections. 

(2) As specified in § 63.9(b)(2), you 

must submit the Initial Notification no 

later than 120 calendar days after May 

20, 2011 or within 120 days after the 

source becomes subject to the standard. 

(3) If you are required to conduct a 

performance stack test you must submit 

a Notification of Intent to conduct a 

performance test at least 60 days before 

the performance stack test is scheduled 

to begin. 

(4) You must submit the Notification 

of Compliance Status in accordance 

with § 63.9(h) no later than 120 days 

after the applicable compliance date 

specified in § 63.11196 unless you must 

conduct a performance stack test. If you 

must conduct a performance stack test, 

you must submit the Notification of 

Compliance Status within 60 days of 

completing the performance stack test. 

In addition to the information required 

in § 63.9(h)(2), your notification must 

include the following certification(s) of 

compliance, as applicable, and signed 

by a responsible official: 

(i) ‘‘This facility complies with the 

requirements in § 63.11214 to conduct 

an initial tune-up of the boiler.’’ 

(ii) ‘‘This facility has had an energy 

assessment performed according to 

§ 63.11214(c).’’ 

(iii) For an owner or operator that 

installs bag leak detection systems: 

‘‘This facility has prepared a bag leak 

detection system monitoring plan in 

accordance with § 63.11224 and will 

operate each bag leak detection system 

according to the plan.’’ 

(iv) For units that do not qualify for 

a statutory exemption as provided in 

section 129(g)(1) of the Clean Air Act: 

‘‘No secondary materials that are solid 

waste were combusted in any affected 

unit.’’ 

(5) If you are using data from a 

previously conducted emission test to 

serve as documentation of conformance 

with the emission standards and 

operating limits of this subpart 

consistent with § 63.7(e)(2)(iv), you 

must submit the test data in lieu of the 

initial performance test results with the 

Notification of Compliance Status 

required under paragraph (a)(4) of this 

section. 

(b) You must prepare, by March 1 of 

each year, and submit to the delegated 

authority upon request, an annual 

compliance certification report for the 

previous calendar year containing the 

information specified in paragraphs 

(b)(1) through (4) of this section. You 

must submit the report by March 15 if 

you had any instance described by 

paragraph (b)(3) of this section. For 

boilers that are subject only to a 

requirement to conduct a biennial tuneup according to § 63.11223(a) and not 

subject to emission limits or operating 

limits, you may prepare only a biennial 

compliance report as specified in 

paragraphs (b)(1) through (4) of this 

section, instead of a semi-annual 

compliance report. 

(1) Company name and address. 

(2) Statement by a responsible official, 

with the official’s name, title, phone 

number, e-mail address, and signature, 

certifying the truth, accuracy and 

completeness of the notification and a 

statement of whether the source has 

complied with all the relevant standards 

and other requirements of this subpart. 

(3) If the source experiences any 

deviations from the applicable 

requirements during the reporting 

period, include a description of 

deviations, the time periods during 

which the deviations occurred, and the 

corrective actions taken. 

(4) The total fuel use by each affected 

boiler subject to an emission limit, for 

each calendar month within the 

reporting period, including, but not 

limited to, a description of the fuel, 

whether the fuel has received a nonwaste determination by you or EPA 

through a petition process to be a nonwaste under § 241.3(c), whether the 

fuel(s) were processed from discarded 

non-hazardous secondary materials 

within the meaning of § 241.3, and the 

total fuel usage amount with units of 

measure. 

(c) You must maintain the records 

specified in paragraphs (c)(1) through 

(5) of this section. 

(1) As required in § 63.10(b)(2)(xiv), 

you must keep a copy of each 

notification and report that you 

submitted to comply with this subpart 

and all documentation supporting any 

Initial Notification or Notification of 

Compliance Status that you submitted. 

(2) You must keep records to 

document conformance with the work 

practices, emission reduction measures, 

and management practices required by 

§ 63.11214 as specified in paragraphs 

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

(i) Records must identify each boiler, 

the date of tune-up, the procedures 

followed for tune-up, and the 

manufacturer’s specifications to which 

the boiler was tuned. 

(ii) Records documenting the fuel 

type(s) used monthly by each boiler, 

including, but not limited to, a 

description of the fuel, including 

whether the fuel has received a nonwaste determination by you or EPA, and 

the total fuel usage amount with units 


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of measure. If you combust nonhazardous secondary materials that have 

been determined not to be solid waste 

pursuant to § 241.3(b)(1), you must keep 

a record which documents how the 

secondary material meets each of the 

legitimacy criteria. If you combust a fuel 

that has been processed from a 

discarded non-hazardous secondary 

material pursuant to § 241.3(b)(4), you 

must keep records as to how the 

operations that produced the fuel 

satisfies the definition of processing in 

§ 241.2. If the fuel received a non-waste 

determination pursuant to the petition 

process submitted under § 241.3(c), you 

must keep a record that documents how 

the fuel satisfies the requirements of the 

petition process. 

(3) For sources that demonstrate 

compliance through fuel analysis, a 

copy of all calculations and supporting 

documentation that were done to 

demonstrate compliance with the 

mercury emission limits. Supporting 

documentation should include results of 

any fuel analyses. You can use the 

results from one fuel analysis for 

multiple boilers provided they are all 

burning the same fuel type. 

(4) Records of the occurrence and 

duration of each malfunction of the 

boiler, or of the associated air pollution 

control and monitoring equipment. 

(5) Records of actions taken during 

periods of malfunction to minimize 

emissions in accordance with the 

general duty to minimize emissions in 

§ 63.11205(a), including corrective 

actions to restore the malfunctioning 

boiler, air pollution control, or 

monitoring equipment to its normal or 

usual manner of operation. 

(6) You must keep the records of all 

inspection and monitoring data required 

by §§ 63.11221 and 63.11222, and the 

information identified in paragraphs 

(c)(6)(i) through (vi) of this section for 

each required inspection or monitoring. 

(i) The date, place, and time of the 

monitoring event. 

(ii) Person conducting the monitoring. 

(iii) Technique or method used. 

(iv) Operating conditions during the 

activity. 

(v) Results, including the date, time, 

and duration of the period from the time 

the monitoring indicated a problem to 

the time that monitoring indicated 

proper operation. 

(vi) Maintenance or corrective action 

taken (if applicable). 

(7) If you use a bag leak detection 

system, you must keep the records 

specified in paragraphs (c)(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 system 

settings. 

(iii) The date and time of all bag leak 

detection system alarms, and for each 

valid alarm, the time you initiated 

corrective action, the corrective action 

taken, and the date on which corrective 

action was completed. 

(d) Your records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). As specified in 

§ 63.10(b)(1), you must keep each record 

for 5 years following the date of each 

recorded action. You must keep each 

record onsite for at least 2 years after the 

date of each recorded action according 

to § 63.10(b)(1). You may keep the 

records off site for the remaining 3 

years. 

(e) As of January 1, 2012 and within 

60 days after the date of completing 

each performance test, as defined in 

§ 63.2, conducted to demonstrate 

compliance with this subpart, you must 

submit relative accuracy test audit (i.e., 

reference method) data and performance 

test (i.e., compliance test) data, except 

opacity data, electronically to EPA’s 

Central Data Exchange (CDX) by using 

the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFIRE database. 

(f) If you intend to commence or 

recommence combustion of solid waste, 

you must provide 30 days prior notice 

of the date upon which you will 

commence or recommence combustion 

of solid waste. The notification must 

identify: 

(1) The name of the owner or operator 

of the affected source, the location of the 

source, the boiler(s) that will commence 

burning solid waste, and the date of the 

notice. 

(2) The currently applicable 

subcategory under this subpart. 

(3) The date on which you became 

subject to the currently applicable 

emission limits. 

(4) The date upon which you will 

commence combusting solid waste. 

(g) If you intend to switch fuels, and 

this fuel switch may result in the 

applicability of a different subcategory 

or a switch out of subpart JJJJJJ due to 

a switch to 100 percent natural gas, you 

must provide 30 days prior notice of the 

date upon which you will switch fuels. 

The notification must identify: 

(1) The name of the owner or operator 

of the affected source, the location of the 

source, the boiler(s) that will switch 

fuels, and the date of the notice. 

(2) The currently applicable 

subcategory under this subpart. 

(3) The date on which you became 

subject to the currently applicable 

standards. 

(4) The date upon which you will 

commence the fuel switch. 

§ 63.11226 How can I assert an affirmative 

defense if I exceed an emission limit during 

a malfunction? 

In response to an action to enforce the 

standards set forth in paragraph 

§ 63.11201 you may assert an affirmative 

defense to a claim for civil penalties for 

exceedances of numerical emission 

limits that are caused by malfunction, as 

defined at § 63.2. Appropriate penalties 

may be assessed, however, if you fail to 

meet your burden of proving all of the 

requirements in the affirmative defense. 

The affirmative defense shall not be 

available for claims for injunctive relief. 

(a) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in paragraph 

(b) of this section, and must prove by a 

preponderance of evidence that: 

(1) The excess emissions: 

(i) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner, and 

(ii) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(iv) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(2) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; and 

(3) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; and 

(4) If the excess emissions resulted 

from a bypass of control equipment or 

a process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(5) All possible steps were taken to 

minimize the impact of the excess 


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emissions on ambient air quality, the 

environment and human health; and 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(7) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(8) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(b) Notification. The owner or 

operator of the facility experiencing an 

exceedance of its emission limit(s) 

during a malfunction shall notify the 

Administrator by telephone or facsimile 

(FAX) transmission as soon as possible, 

but no later than two business days after 

the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standard in 

§ 63.11201 to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedance. 

Other Requirements and Information 

§ 63.11235 What parts of the General 

Provisions apply to me? 

Table 8 to this subpart shows which 

parts of the General Provisions in 

§§ 63.1 through 63.15 apply to you. 

§ 63.11236 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by EPA or a delegated 

authority such as your state, local, or 

tribal agency. If the EPA Administrator 

has delegated authority to your state, 

local, or tribal agency, then that agency 

has the authority to implement and 

enforce this subpart. You should contact 

your EPA Regional Office to find out if 

implementation and enforcement of this 

subpart is delegated to your state, local, 

or tribal agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local, or tribal agency under 40 

CFR part 63, subpart E, the authorities 

contained in paragraphs (c) of this 

section are retained by the EPA 

Administrator and are not transferred to 

the state, local, or tribal agency. 

(c) The authorities that cannot be 

delegated to state, local, or tribal 

agencies are specified in paragraphs 

(c)(1) through (5) of this section. 

(1) Approval of an alternative nonopacity emission standard and work 

practice standards in § 63.11223(a). 

(2) Approval of alternative opacity 

emission standard under § 63.6(h)(9). 

(3) Approval of major change to test 

methods under § 63.7(e)(2)(ii) and (f). A 

‘‘major change to test method’’ is defined 

in § 63.90. 

(4) Approval of a major change to 

monitoring under § 63.8(f). A ‘‘major 

change to monitoring’’ is defined in 

§ 63.90. 

(5) Approval of major change to 

recordkeeping and reporting under 

§ 63.10(f). A ‘‘major change to 

recordkeeping/reporting’’ is defined in 

§ 63.90. 

§ 63.11237 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act, in § 63.2 

(the General Provisions), and in this 

section as follows: 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Annual heat input basis means the 

heat input for the 12 months preceding 

the compliance demonstration. 

Bag leak detection system means a 

group of instruments that is capable of 

monitoring particulate matter loadings 

in the exhaust of a fabric filter (i.e., 

baghouse) in order to detect bag failures. 

A bag leak detection system includes, 

but is not limited to, an instrument that 

operates on electrodynamic, 

triboelectric, light scattering, light 

transmittance, or other principle to 

monitor relative particulate matter 

loadings. 

Biomass means any biomass-based 

solid fuel that is not a solid waste. This 

includes, but is not limited to, wood 

residue and wood products (e.g., trees, 

tree stumps, tree limbs, bark, lumber, 

sawdust, sander dust, chips, scraps, 

slabs, millings, and shavings); animal 

manure, including litter and other 

bedding materials; vegetative 

agricultural and silvicultural materials, 

such as logging residues (slash), nut and 

grain hulls and chaff (e.g., almond, 

walnut, peanut, rice, and wheat), 

bagasse, orchard prunings, corn stalks, 

coffee bean hulls and grounds. This 

definition of biomass is not intended to 

suggest that these materials are or are 

not solid waste. 

Biomass subcategory includes any 

boiler that burns at least 15 percent 

biomass on an annual heat input basis. 

Boiler means an enclosed device 

using controlled flame combustion in 

which water is heated to recover 

thermal energy in the form of steam or 

hot water. Controlled flame combustion 

refers to a steady-state, or near steadystate, process wherein fuel and/or 

oxidizer feed rates are controlled. Waste 

heat boilers are excluded from this 

definition. 

Boiler system means the boiler and 

associated components, such as, the 

feedwater system, the combustion air 

system, the boiler fuel system (including 

burners), blowdown system, combustion 

control system, steam system, and 

condensate return system. 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, or lignite by the American 

Society for Testing and Materials in 

ASTM D388 (incorporated by reference, 

see § 63.14), coal refuse, and petroleum 

coke. For the purposes of this subpart, 

this definition of ‘‘coal’’ includes 

synthetic fuels derived from coal 

including, but not limited to, solventrefined coal, coal-oil mixtures, and coalwater mixtures. Coal derived gases are 

excluded from this definition. 

Coal subcategory includes any boiler 

that burns any solid fossil fuel and no 

more than 15 percent biomass on an 

annual heat input basis. 

Commercial boiler means a boiler 

used in commercial establishments such 

as hotels, restaurants, and laundries to 

provide electricity, steam, and/or hot 

water. 

Deviation (1) Deviation means any 

instance in which an affected source 

subject to this subpart, or an owner or 

operator of such a source: 

(i) Fails to meet any requirement or 

obligation established by this subpart 

including, but not limited to, any 

emission limit, operating limit, or work 

practice standard; 


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(ii) Fails to meet any term or 

condition that is adopted to implement 

an applicable requirement in this 

subpart and that is included in the 

operating permit for any affected source 

required to obtain such a permit; or 

(2) A deviation is not always a 

violation. The determination of whether 

a deviation constitutes a violation of the 

standard is up to the discretion of the 

entity responsible for enforcement of the 

standards. 

Dry scrubber means an add-on air 

pollution control system that injects dry 

alkaline sorbent (dry injection) or sprays 

an alkaline sorbent (spray dryer) to react 

with and neutralize acid gas in the 

exhaust stream forming a dry powder 

material. Sorbent injection systems in 

fluidized bed boilers are included in 

this definition. A dry scrubber is a dry 

control system. 

Electrostatic precipitator (ESP) means 

an add-on air pollution control device 

used to capture particulate matter by 

charging the particles using an 

electrostatic field, collecting the 

particles using a grounded collecting 

surface, and transporting the particles 

into a hopper. An electrostatic 

precipitator is a dry control system, 

except when it is operated with a wet 

scrubber. 

Energy assessment means the 

following only as this term is used in 

Table 3 to this subpart: 

(1) Energy assessment for facilities 

with affected boilers using less than 0.3 

trillion Btu (TBtu) per year heat input 

will be one day in length maximum. 

The boiler system and energy use 

system accounting for at least 50 percent 

of the affected boiler(s) energy output 

will be evaluated to identify energy 

savings opportunities, within the limit 

of performing a one day energy 

assessment. 

(2) Energy assessment for facilities 

with affected boilers and process heaters 

using 0.3 to 1 TBtu/year will be three 

days in length maximum. The boiler 

system(s) and any energy use system(s) 

accounting for at least 33 percent of the 

affected boiler(s) energy output will be 

evaluated to identify energy savings 

opportunities, within the limit of 

performing a 3-day energy assessment. 

(3) Energy assessment for facilities 

with affected boilers and process heaters 

using greater than 1.0 TBtu/year, the 

boiler system(s) and any energy use 

system(s) accounting for at least 20 

percent of the affected boiler(s) energy 

output will be evaluated to identify 

energy savings opportunities. 

Energy use system includes, but not 

limited to, process heating; compressed 

air systems; machine drive (motors, 

pumps, fans); process cooling; facility 

heating, ventilation, and airconditioning (HVAC) systems; hot 

heater systems;, building envelop; and 

lighting. 

Equivalent means the following only 

as this term is used in Table 5 to this 

subpart: 

(1) An equivalent sample collection 

procedure means a published voluntary 

consensus standard or practice (VCS) or 

EPA method that includes collection 

of a minimum of three composite fuel 

samples, with each composite 

consisting of a minimum of three 

increments collected at approximately 

equal intervals over the test period. 

(2) An equivalent sample compositing 

procedure means a published VCS or 

EPA method to systematically mix and 

obtain a representative subsample (part) 

of the composite sample. 

(3) An equivalent sample preparation 

procedure means a published VCS or 

EPA method that: Clearly states that the 

standard, practice or method is 

appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate 

sample preparation standard, practice or 

method for the pollutant in the chosen 

VCS or EPA determinative or analytical 

method. 

(4) An equivalent procedure for 

determining heat content means a 

published VCS or EPA method to obtain 

gross calorific (or higher heating) value. 

(5) An equivalent procedure for 

determining fuel moisture content 

means a published VCS or EPA method 

to obtain moisture content. If the sample 

analysis plan calls for determining 

mercury using an aliquot of the dried 

sample, then the drying temperature 

must be modified to prevent vaporizing 

this metal. On the other hand, if metals 

analysis is done on an ‘‘as received’’ 

basis, a separate aliquot can be dried to 

determine moisture content and the 

mercury concentration mathematically 

adjusted to a dry basis. 

(6) An equivalent mercury 

determinative or analytical procedure 

means a published VCS or EPA method 

that clearly states that the standard, 

practice, or method is appropriate for 

mercury and the fuel matrix and has a 

published detection limit equal or lower 

than the methods listed in Table 5 to 

this subpart for the same purpose. 

Fabric filter means an add-on air 

pollution control device used to capture 

particulate matter by filtering gas 

streams through filter media, also 

known as a baghouse. A fabric filter is 

a dry control system. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the EPA Administrator, 

including the requirements of 40 CFR 

part 60 and 40 CFR part 61, 

requirements within any applicable 

state implementation plan, and any 

permit requirements established under 

§§ 52.21 or under 51.18 and § 51.24. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

not limited to, bituminous coal, subbituminous coal, lignite, anthracite, 

biomass, distillate oil, residual oil. 

Individual fuel types received from 

different suppliers are not considered 

new fuel types. 

Gaseous fuels includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, refinery 

gas, hydrogen, and biogas. 

Gas-fired boiler includes any boiler 

that burns gaseous fuels not combined 

with any solid fuels, burns liquid fuel 

only during periods of gas curtailment, 

gas supply emergencies, or periodic 

testing on liquid fuel. Periodic testing of 

liquid fuel shall not exceed a combined 

total of 48 hours during any calendar 

year. 

Heat input means heat derived from 

combustion of fuel in a boiler and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or returned condensate. 

Hot water heater means a closed 

vessel with a capacity of no more than 

120 U.S. gallons in which water is 

heated by combustion of gaseous or 

liquid fuel and is withdrawn for use 

external to the vessel at pressures not 

exceeding 160 psig, including the 

apparatus by which the heat is 

generated and all controls and devices 

necessary to prevent water temperatures 

from exceeding 210 degrees Fahrenheit 

(99 degrees Celsius). 

Industrial boiler means a boiler used 

in manufacturing, processing, mining, 

and refining or any other industry to 

provide steam, hot water, and/or 

electricity. 

Institutional boiler means a boiler 

used in institutional establishments 

such as medical centers, research 

centers, and institutions of higher 

education to provide electricity, steam, 

and/or hot water. 

Liquid fuel means, but not limited to, 

petroleum, distillate oil, residual oil, 

any form of liquid fuel derived from 

petroleum, used oil, liquid biofuels, and 

biodiesel. 

Minimum activated carbon injection 

rate means load fraction (percent) 

multiplied by the lowest 1-hour average 

activated carbon injection rate measured 

according to Table 6 to this subpart 

during the most recent performance 

stack test demonstrating compliance 

with the applicable emission limits. 

Minimum oxygen level means the 

lowest 1-hour average oxygen level 


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measured according to Table 6 of this 

subpart during the most recent 

performance stack test demonstrating 

compliance with the applicable CO 

emission limit. 

Minimum PM scrubber pressure drop 

means the lowest 1-hour average PM 

scrubber pressure drop measured 

according to Table 6 to this subpart 

during the most recent performance 

stack test demonstrating compliance 

with the applicable emission limit. 

Minimum sorbent flow rate means the 

boiler load (percent) multiplied by the 

lowest 2-hour average sorbent (or 

activated carbon) injection rate 

measured according to Table 6 to this 

subpart during the most recent 

performance stack test demonstrating 

compliance with the applicable 

emission limits. 

Minimum voltage or amperage means 

the lowest 1-hour average total electric 

power value (secondary voltage × 

secondary current = secondary electric 

power) to the electrostatic precipitator 

measured according to Table 6 to this 

subpart during the most recent 

performance stack test demonstrating 

compliance with the applicable 

emission limits. 

Natural gas means: 

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane 

including intermediate gas streams 

generated during processing of natural 

gas at production sites or at gas 

processing plants; or 

(2) Liquefied petroleum gas, as 

defined by the American Society for 

Testing and Materials in ASTM D1835 

(incorporated by reference, see § 63.14). 

(3) A mixture of hydrocarbons that 

maintains a gaseous state at ISO 

conditions. Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 34 and 43 

megajoules (MJ) per dry standard cubic 

meter (910 and 1,150 Btu per dry 

standard cubic foot). 

(4) Propane or propane-derived 

synthetic natural gas. Propane means a 

colorless gas derived from petroleum 

and natural gas, with the molecular 

structure C3H8. 

Oil subcategory includes any boiler 

that burns any liquid fuel and is not in 

either the biomass or coal subcategories. 

Gas-fired boilers that burn liquid fuel 

during periods of gas curtailment, gas 

supply emergencies, or for periodic 

testing not to exceed 48 hours during 

any calendar year are not included in 

this definition. 

Opacity means the degree to which 

emissions reduce the transmission of 

light and obscure the view of an object 

in the background. 

Particulate matter (PM) means any 

finely divided solid or liquid material, 

other than uncombined water, as 

measured by the test methods specified 

under this subpart, or an alternative 

method. 

Performance testing means the 

collection of data resulting from the 

execution of a test method used (either 

by stack testing or fuel analysis) to 

demonstrate compliance with a relevant 

emission standard. 

Period of natural gas curtailment or 

supply interruption means a period of 

time during which the supply of natural 

gas to an affected facility is halted for 

reasons beyond the control of the 

facility. The act of entering into a 

contractual agreement with a supplier of 

natural gas established for curtailment 

purposes does not constitute a reason 

that is under the control of a facility for 

the purposes of this definition. An 

increase in the cost or unit price of 

natural gas does not constitute a period 

of natural gas curtailment or supply 

interruption. 

Qualified energy assessor means: 

(1) someone who has demonstrated 

capabilities to evaluate a set of the 

typical energy savings opportunities 

available in opportunity areas for steam 

generation and major energy using 

systems, including, but not limited to: 

(i) Boiler combustion management. 

(ii) Boiler thermal energy recovery, 

including 

(A) Conventional feed water 

economizer, 

(B) Conventional combustion air 

preheater, and 

(C) Condensing economizer. 

(iii) Boiler blowdown thermal energy 

recovery. 

(iv) Primary energy resource selection, 

including 

(A) Fuel (primary energy source) 

switching, and 

(B) Applied steam energy versus 

direct-fired energy versus electricity. 

(v) Insulation issues. 

(vi) Steam trap and steam leak 

management. 

(vi) Condensate recovery. 

(viii) Steam end-use management. 

(2) Capabilities and knowledge 

includes, but is not limited to: 

(i) Background, experience, and 

recognized abilities to perform the 

assessment activities, data analysis, and 

report preparation. 

(ii) Familiarity with operating and 

maintenance practices for steam or 

process heating systems. 

(iii) Additional potential steam 

system improvement opportunities 

including improving steam turbine 

operations and reducing steam demand. 

(iv) Additional process heating system 

opportunities including effective 

utilization of waste heat and use of 

proper process heating methods. 

(v) Boiler-steam turbine cogeneration 

systems. 

(vi) Industry specific steam end-use 

systems. 

Responsible official means 

responsible official as defined in § 70.2. 

Solid fossil fuel includes, but not 

limited to, coal, petroleum coke, and 

tire derived fuel. 

Waste heat boiler means a device that 

recovers normally unused energy and 

converts it to usable heat. Waste heat 

boilers are also referred to as heat 

recovery steam generators. 

Work practice standard means any 

design, equipment, work practice, or 

operational standard, or combination 

thereof, which is promulgated pursuant 

to section 112(h) of the Clean Air Act. 

TABLE 1 TO SUBPART JJJJJJ OF PART 63—EMISSION LIMITS

[As stated in § 63.11201, you must comply with the following applicable emission limits:] 

If your boiler is in this subcategory For the following 

pollutants. . . 

You must achieve less than or equal to the following 

emission limits, except during periods of startup and 

shutdown. . . 

1. New coal-fired boiler with heat input capacity of 30 

million Btu per hour or greater.

a. Particulate Matter ........... 0.03 lb per MMBtu of heat input. 

b. Mercury .......................... 0.0000048 lb per MMBtu of heat input. 

c. Carbon Monoxide ........... 400 ppm by volume on a dry basis corrected to 3 percent oxygen. 

2. New coal-fired boiler with heat input capacity of between 10 and 30 million Btu per hour.a. Particulate Matter ........... 0.42 lb per MMBtu of heat input. 


srobinson on DSKHWCL6B1PROD with RULES4
15602 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 1 TO SUBPART JJJJJJ OF PART 63—EMISSION LIMITS—Continued 

[As stated in § 63.11201, you must comply with the following applicable emission limits:] 

If your boiler is in this subcategory For the following 

pollutants. . . 

You must achieve less than or equal to the following 

emission limits, except during periods of startup and 

shutdown. . . 

b. Mercury .......................... 0.0000048 lb per MMBtu of heat input. 

c. Carbon Monoxide ........... 400 ppm by volume on a dry basis corrected to 3 percent oxygen. 

3. New biomass-fired boiler with heat input capacity of 

30 million Btu per hour or greater.

a. Particulate Matter ........... 0.03 lb per MMBtu of heat input. 

4. New biomass fired boiler with heat input capacity of 

between 10 and 30 million Btu per hour.

a. Particulate Matter ........... 0.07 lb per MMBtu of heat input. 

5. New oil-fired boiler with heat input capacity of 10 million Btu per hour or greater.a. Particulate Matter ........... 0.03 lb per MMBtu of heat input. 

6. Existing coal (units with heat input capacity of 10 million Btu per hour or greater).a. Mercury .......................... 0.0000048 lb per MMBtu of heat input. 

b. Carbon Monoxide ........... 400 ppm by volume on a dry basis corrected to 3 percent oxygen. 

TABLE 2 TO SUBPART JJJJJJ OF PART 63—WORK PRACTICE STANDARDS, EMISSION REDUCTION MEASURES, AND

MANAGEMENT PRACTICES

[As stated in § 63.11201, you must comply with the following applicable work practice standards, emission reduction measures, and management 

practices:] 

If your boiler is in this subcategory. . . You must meet the following. . . 

1. Existing or new coal, new biomass, and new 

oil (units with heat input capacity of 10 million 

Btu per hour or greater).

Minimize the boiler’s startup and shutdown periods following the manufacturer’s recommended 

procedures. If manufacturer’s recommended procedures are not available, you must follow 

recommended procedures for a unit of similar design for which manufacturer’s recommended procedures are available. 

2. Existing or new coal (units with heat input capacity of less than 10 million Btu per hour).Conduct a tune-up of the boiler biennially as specified in § 63.11223. 

3. Existing or new biomass or oil ....................... Conduct a tune-up of the boiler biennially as specified in § 63.11223. 

4. Existing coal, biomass, or oil (units with heat 

input capacity of 10 million Btu per hour and 

greater).

Must have a one-time energy assessment performed by a qualified energy assessor. An energy assessment completed on or after January 1, 2008, that meets or is amended to meet 

the energy assessment requirements in this table satisfies the energy assessment requirement. The energy assessment must include: 

(1) A visual inspection of the boiler system, 

(2) An evaluation of operating characteristics of the facility, specifications of energy using 

systems, operating and maintenance procedures, and unusual operating constraints, 

(3) Inventory of major systems consuming energy from affected boiler(s), 

(4) A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage, 

(5) A list of major energy conservation measures, 

(6) A list of the energy savings potential of the energy conservation measures identified, 

(7) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments. 

TABLE 3 TO SUBPART JJJJJJ OF PART 63—OPERATING LIMITS FOR BOILERS WITH EMISSION LIMITS

[As stated in § 63.11201, you must comply with the applicable operating limits:] 

If you demonstrate compliance with applicable 

emission limits using . . . You must meet these operating limits. . . 

1. Fabric filter control .......................................... a. Maintain opacity to less than or equal to 10 percent opacity (daily block average); OR 

b. Install and operate a bag leak detection system according to § 63.11224 and operate the 

fabric filter such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during each 6-month period. 

2. Electrostatic precipitator control ..................... a. Maintain opacity to less than or equal to 10 percent opacity (daily block average); OR 

b. Maintain the secondary power input of the electrostatic precipitator at or above the lowest 1- 

hour average secondary electric power measured during the most recent performance test 

demonstrating compliance with the particulate matter emission limitations. 

3. Wet PM scrubber control ................................ Maintain the pressure drop at or above the lowest 1-hour average pressure drop across the 

wet scrubber and the liquid flow-rate at or above the lowest 1-hour average liquid flow rate 

measured during the most recent performance test demonstrating compliance with the PM 

emission limitation. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15603 

TABLE 3 TO SUBPART JJJJJJ OF PART 63—OPERATING LIMITS FOR BOILERS WITH EMISSION LIMITS—Continued 

[As stated in § 63.11201, you must comply with the applicable operating limits:] 

If you demonstrate compliance with applicable 

emission limits using . . . You must meet these operating limits. . . 

4. Dry sorbent or carbon injection control .......... Maintain the sorbent or carbon injection rate at or above the lowest 2-hour average sorbent 

flow rate measured during the most recent performance test demonstrating compliance with 

the mercury emissions limitation. When your boiler operates at lower loads, multiply your 

sorbent or carbon injection rate by the load fraction (e.g., actual heat input divided by the 

heat input during performance stack test, for 50 percent load, multiply the injection rate operating limit by 0.5). 

5. Any other add-on air pollution control type .... This option is for boilers that operate dry control systems. Boilers must maintain opacity to 

less than or equal to 10 percent opacity (daily block average). 

6. Fuel analysis ................................................... Maintain the fuel type or fuel mixture (annual average) such that the mercury emission rates 

calculated according to § 63.11211(b) is less than the applicable emission limits for mercury. 

7. Performance stack testing .............................. For boilers that demonstrate compliance with a performance stack test, maintain the operating 

load of each unit such that is does not exceed 110 percent of the average operating load recorded during the most recent performance stack test. 

8. Continuous Oxygen Monitor ........................... Maintain the oxygen level at or above the lowest 1-hour average oxygen level measured during the most recent CO performance stack test. 

TABLE 4 TO SUBPART JJJJJJ OF PART 63—PERFORMANCE (STACK) TESTING REQUIREMENTS

[As stated in § 63.11212, you must comply with the following requirements for performance (stack) test for affected sources:] 

To conduct a performance test for the following 

pollutant. . . You must. . . Using. . . 

1. Particulate Matter ........................................... a. Select sampling ports location and the 

number of traverse points.

Method 1 in appendix A–1 to part 60 of this 

chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G in appendix A–2 to part 

60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B in appendix A–2 to part 60 

of this chapter, or ASTM D6522–00 (Reapproved 2005),a or ANSI/ASME PTC 

19.10–1981. a

d. Measure the moisture content of the stack 

gas.

Method 4 in appendix A–3 to part 60 of this 

chapter. 

e. Measure the particulate matter emission 

concentration.

Method 5 or 17 (positive pressure fabric filters 

must use Method 5D) in appendix A–3 and 

A–6 to part 60 of this chapter and a minimum 1 dscm of sample volume per run. 

f. Convert emissions concentration to lb/ 

MMBtu emission rates.

Method 19 F-factor methodology in appendix 

A–7 to part 60 of this chapter. 

2. Mercury .......................................................... a. Select sampling ports location and the 

number of traverse points.

Method 1 in appendix A–1 to part 60 of this 

chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G in appendix A–2 to part 

60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B in appendix A–2 to part 60 

of this chapter, or ASTM D6522–00 (Reapproved 2005) ,a or ANSI/ASME PTC 

19.10–1981. a

d. Measure the moisture content of the stack 

gas.

Method 4 in appendix A–3 to part 60 of this 

chapter. 

e. Measure the mercury emission concentration.Method 29, 30A, or 30B in appendix A–8 to 

part 60 of this chapter or Method 101A in 

appendix B to part 61 of this chapter or 

ASTM Method D6784–02.a Collect a minimum 2 dscm of sample volume with Method 29 of 101A per run. Use a minimum run 

time of 2 hours with Method 30A. 

f. Convert emissions concentration to lb/ 

MMBtu emission rates.

Method 19 F-factor methodology in appendix 

A–7 to part 60 of this chapter. 

3. Carbon Monoxide ........................................... a. Select the sampling ports location and the 

number of traverse points.

Method 1 in appendix A–1 to part 60 of this 

chapter. 

b. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B in appendix A–2 to part 60 

of this chapter, or ASTM D6522–00 (Reapproved 2005),a or ANSI/ASME PTC 

19.10–1981.a

c. Measure the moisture content of the stack 

gas.

Method 4 in appendix A–3 to part 60 of this 

chapter. 


srobinson on DSKHWCL6B1PROD with RULES4
15604 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 4 TO SUBPART JJJJJJ OF PART 63—PERFORMANCE (STACK) TESTING REQUIREMENTS—Continued 

[As stated in § 63.11212, you must comply with the following requirements for performance (stack) test for affected sources:] 

To conduct a performance test for the following 

pollutant. . . You must. . . Using. . . 

d. Measure the carbon monoxide emission 

concentration.

Method 10, 10A, or 10B in appendix A–4 to 

part 60 of this chapter or ASTM D6522–00 

(Reapproved 2005) a and a minimum 1 hour 

sampling time per run. 

a Incorporated by reference, see § 63.14. 

TABLE 5 TO SUBPART JJJJJJ OF PART 63—FUEL ANALYSIS REQUIREMENTS

[As stated in § 63.11213, you must comply with the following requirements for fuel analysis testing for affected sources:] 

To conduct a fuel analysis for the following pollutant . . . You must. . . Using . . . 

1. Mercury .......................................................... a. Collect fuel samples .................................... Procedure in § 63.11213(b) or ASTM D2234/ 

D2234M a (for coal) or ASTM D6323 a (for 

biomass) or equivalent. 

b. Compose fuel samples ................................ Procedure in § 63.11213(b) or equivalent. 

c. Prepare composited fuel samples ............... EPA SW–846–3050Ba (for solid samples) or 

EPA SW–846–3020Aa (for liquid samples) 

or ASTM D2013/D2013M a (for coal) or 

ASTM D5198 a (for biomass) or equivalent. 

d. Determine heat content of the fuel type ...... ASTM D5865 a (for coal) or ASTM E711 a (for 

biomass) or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 a or ASTM E871 a or equivalent. 

f. Measure mercury concentration in fuel sample ASTM D6722 a (for coal) or EPA SW–846– 

7471Ba (for solid samples) or EPA SW– 

846–7470Aa (for liquid samples) or equivalent. 

g. Convert concentrations into units of lb/ 

MMBtu of heat content 

a Incorporated by reference, see § 63.14. 

TABLE 6 TO SUBPART JJJJJJ OF PART 63—ESTABLISHING OPERATING LIMITS

[As stated in § 63.11211, you must comply with the following requirements for establishing operating limits:] 

If you have an 

applicable emission 

limit for . . . 

And your operating 

limits are based 

on . . . 

You must. . . Using. . . According to the following requirements 

1. Particulate matter 

or mercury.

a. Wet scrubber operating parameters.i. Establish a site-specific minimum pressure drop and minimum flow rate operating limit according to § 63.11211(b).(1) Data from the 

pressure drop and 

liquid flow rate monitors and the particulate matter or mercury performance 

stack test.

(a) You must collect pressure drop and liquid 

flow-rate data every 15 minutes during the 

entire period of the performance stack 

tests; 

(b) Determine the average pressure drop 

and liquid flow-rate 

for each individual 

test run in the threerun performance 

stack test by computing the average 

of all the 15-minute 

readings taken during each test run..

b. Electrostatic precipitator operating 

parameters (option 

only for units that 

operate wet scrubbers).

i. Establish a site-specific minimum secondary electric 

power according to 

§ 63.11211(b).

(1) Data from the secondary electric 

power monitors during the particulate 

matter or mercury 

performance stack 

test.

(a) You must collect secondary electric 

power input data every 15 minutes during 

the entire period of the performance stack 

tests; 

(b) Determine the secondary electric power 

input for each individual test run in the 

three-run performance stack test by computing the average of all the 15-minute 

readings taken during each test run. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15605 

TABLE 6 TO SUBPART JJJJJJ OF PART 63—ESTABLISHING OPERATING LIMITS—Continued 

[As stated in § 63.11211, you must comply with the following requirements for establishing operating limits:] 

If you have an 

applicable emission 

limit for . . . 

And your operating 

limits are based 

on . . . 

You must. . . Using. . . According to the following requirements 

2. Mercury .................. a. Activated carbon injection.i. Establish a site-specific minimum activated carbon injection rate operating 

limit according to 

§ 63.11211(b).

(1) Data from the activated carbon rate 

monitors and mercury performance 

stack tests.

(a) You must collect activated carbon injection rate data every 15 minutes during the 

entire period of the performance stack 

tests; 

(b) Determine the average activated carbon 

injection rate for each individual test run in 

the three-run performance stack test by 

computing the average of all the 15-minute 

readings taken during each test run. 

(c) When your unit operates at lower loads, 

multiply your activated carbon injection 

rate by the load fraction (e.g., actual heat 

input divided by heat input during performance stack test, for 50 percent load, multiply the injection rate operating limit by 

0.5) to determine the required injection 

rate. 

3. Carbon monoxide .. a. Oxygen .................. i. Establish a unit-specific limit for minimum oxygen level 

according to 

§ 63.11211(b).

(1) Data from the oxygen monitor specified in § 63.11224(a).(a) You must collect oxygen data every 15 

minutes during the entire period of the performance stack tests; 

(b) Determine the average oxygen concentration for each individual test run in 

the three-run performance stack test by 

computing the average of all the 15-minute 

readings taken during each test run. 

TABLE 7 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

[As stated in § 63.11222, you must show continuous compliance with the emission limitations for affected sources according to the following:] 

If you must meet the following operating 

limits. . . You must demonstrate continuous compliance by. . . 

1. Opacity ............................................................ a. Collecting the opacity monitoring system data according to § 63.11224(e) and § 63.11221; 

and 

b. Reducing the opacity monitoring data to 6-minute averages; and 

c. Maintaining opacity to less than or equal to 10 percent (daily block average). 

2. Fabric filter bag leak detection operation ....... Installing and operating a bag leak detection system according to § 63.11224 and operating 

the fabric filter such that the requirements in § 63.11222(a)(4) are met. 

3. Wet scrubber pressure drop and liquid flowrate.a. Collecting the pressure drop and liquid flow rate monitoring system data according to 

§§ 63.11224 and 63.11221; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average pressure drop and liquid flow-rate at or above the operating limits established during the performance test according to § 63.1140. 

4. Dry scrubber sorbent or carbon injection rate a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber 

according to §§ 63.11224 and 63.11220; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average sorbent or carbon injection rate at or above the minimum 

sorbent or carbon injection rate as defined in § 63.11237. 

5. Electrostatic precipitator secondary amperage and voltage, or total power input.a. Collecting the secondary amperage and voltage, or total power input monitoring system 

data for the electrostatic precipitator according to §§ 63.11224 and 63.11220; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average secondary amperage and voltage, or total power input at 

or above the operating limits established during the performance test according to 

§ 63.11214. 

6. Fuel pollutant content ..................................... a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to § 63.11214 as applicable; and 

b. Keeping monthly records of fuel use according to § 63.11222. 

7. Oxygen content .............................................. a. Continuously monitor the oxygen content in the combustion exhaust according to 

§ 63.11224. 

b. Maintain the 12-hour average oxygen content at or above the operating limit established 

during the most recent carbon monoxide performance test. 


srobinson on DSKHWCL6B1PROD with RULES4
15606 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 8 TO SUBPART JJJJJJ OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART JJJJJJ 

[As stated in § 63.11235, you must comply with the applicable General Provisions according to the following:] 

General provisions cite Subject Does it apply? 

§ 63.1 ....................................................................................... Applicability ............................................ Yes. 

§ 63.2 ....................................................................................... Definitions .............................................. Yes. Additional terms defined in 

§ 63.11237. 

§ 63.3 ....................................................................................... Units and Abbreviations ........................ Yes. 

§ 63.4 ....................................................................................... Prohibited Activities and Circumvention Yes. 

§ 63.5 ....................................................................................... Preconstruction Review and Notification 

Requirements.

No 

§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c), (f)(2)–(3), (g), (i), (j) ......... Compliance with Standards and Maintenance Requirements.Yes. 

§ 63.6(e)(1)(i) ........................................................................... General Duty to minimize emissions ..... No. See § 63.11205 for general duty requirement. 

§ 63.6(e)(1)(ii) .......................................................................... Requirement to correct malfunctions 

ASAP.

No. 

§ 63.6(e)(3) .............................................................................. SSM Plan ............................................... No. 

§ 63.6(f)(1) ............................................................................... SSM exemption ..................................... No. 

§ 63.6(h)(1) .............................................................................. SSM exemption ..................................... No. 

§ 63.6(h)(2) to (9) .................................................................... Determining compliance with opacity 

emission standards.

Yes. 

§ 63.7(a), (b), (c), (d) , (e)(2)–(e)(9), (f), (g), and (h) .............. Performance Testing Requirements ...... Yes. 

§ 63.7(e)(1) .............................................................................. Performance testing .............................. No. See § 63.11210. 

§ 63.8(a), (b), (c)(1), (c)(1)(ii), (c)(2) to (c)(9), (d)(1) and 

(d)(2), (e),(f), and (g).

Monitoring Requirements ...................... Yes. 

§ 63.8(c)(1)(i) ........................................................................... General duty to minimize emissions 

and CMS operation.

No. 

§ 63.8(c)(1)(iii) ......................................................................... Requirement to develop SSM Plan for 

CMS.

No. 

§ 63.8(d)(3) .............................................................................. Written procedures for CMS .................. Yes, except for the last sentence, 

which refers to an SSM plan. SSM 

plans are not required. 

§ 63.9 ....................................................................................... Notification Requirements ..................... Yes. 

§ 63.10(a) and (b)(1) ............................................................... Recordkeeping and Reporting Requirements.Yes. 

§ 63.10(b)(2)(i) ......................................................................... Recordkeeping of occurrence and duration of startups or shutdowns.No. 

§ 63.10(b)(2)(ii) ........................................................................ Recordkeeping of malfunctions ............. No. See § 63.11225 for recordkeeping 

of (1) occurrence and duration and 

(2) actions taken during malfunctions. 

§ 63.10(b)(2)(iii) ....................................................................... Maintenance records ............................. Yes. 

§ 63.10(b)(2)(iv) and (v) .......................................................... Actions taken to minimize emissions 

during SSM.

No. 

§ 63.10(b)(2)(vi) ....................................................................... Recordkeeping for CMS malfunctions ... Yes. § 63.10(b)(2)(vii) to (xiv) .......................................................... Other CMS requirements ...................... Yes. 

§ 63.10(b)(3) ............................................................................ Recordkeeping requirements for applicability determinations.No. 

§ 63.10(c)(1) to (9) .................................................................. Recordkeeping for sources with CMS ... Yes. 

§ 63.10(c)(10) .......................................................................... Recording nature and cause of malfunctions.No. See § 63.11225 for malfunction recordkeeping requirements. 

§ 63.10(c)(11) .......................................................................... Recording corrective actions ................. No. See § 63.11225 for malfunction recordkeeping requirements. 

§ 63.10(c)(12) and (13) ........................................................... Recordkeeping for sources with CMS ... Yes. 

§ 63.10(c)(15) .......................................................................... Allows use of SSM plan ........................ No. 

§ 63.10(d)(1) and (2) ............................................................... General reporting requirements ............ Yes. 

§ 63.10(d)(3) ............................................................................ Reporting opacity or visible emission 

observation results.

No. 

§ 63.10(d)(4) ............................................................................ Progress reports under an extension of 

compliance.

Yes. 

§ 63.10(d)(5) ............................................................................ SSM reports ........................................... No. See § 63.11225 for malfunction reporting requirements. 

§ 63.10(e) and (f) ..................................................................... ................................................................ Yes. 

§ 63.11 ..................................................................................... Control Device Requirements ............... No. 

§ 63.12 ..................................................................................... State Authority and Delegation ............. Yes. 

§ 63.13–63.16 .......................................................................... Addresses, Incorporation by Reference, 

Availability of Information, Performance Track Provisions.

Yes. 

§ 63.1(a)(5), (a)(7)–(a)(9), (b)(2), (c)(3)–(4), (d), 63.6(b)(6), 

(c)(3), (c)(4), (d), (e)(2), (e)(3)(ii), (h)(3), (h)(5)(iv), 

63.8(a)(3), 63.9(b)(3), (h)(4), 63.10(c)(2)–(4), (c)(9).

Reserved ............................................... No. 

[FR Doc. 2011–4493 Filed 3–18–11; 8:45 am] 

BILLING CODE 6560–50–P 


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