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 or 

fuel analyses? 

63.11221 Is there a minimum amount of monitoring data I must 

obtain? 

63.11222 How do I demonstrate continuous compliance with the 

emission limits? 

63.11223 How do I demonstrate continuous compliance with the 

work practice standards and management practices? 

63.11224 What are my monitoring, installation, operation, and 
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maintenance requirements? 

63.11225 What are my notification, reporting, and recordkeeping 

requirements? 

§63.11226 Affirmative Defense for Violation of Emission 

Standards During 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 

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) 
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of this section. 

(1) The affected source of this subpart is the collection 

of all existing industrial, commercial, and institutional 

boilers within a subcategory, 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 of the affected source after June 4, 2010, and the 

boiler meets the applicability criteria at the time you commence 

construction. 

 (d) An affected source is a reconstructed source if the 

boiler meets the reconstruction criteria as defined in §63.2, 

you commenced reconstruction after June 4, 2010, and the boiler 

meets the applicability criteria at the time you commence 

reconstruction. 

 (e) An existing dual-fuel fired boiler meeting the 

definition of gas-fired boiler, as defined in §63.11237, that 

meets the applicability requirements of this subpart after June 
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4, 2010 due to a fuel switch from gaseous fuel to solid fossil 

fuel, biomass, or liquid fuel is considered to be an existing 

source under this subpart as long as the boiler was designed to 

accommodate the alternate fuel. 

 (f) 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 (k) 

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 
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this part (e.g., hazardous waste boilers), unless such units do 

not combust hazardous waste and combust comparable fuels. 

 (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, or part 60, part 61, or part 

65 of this chapter provided that at least 50 percent of the 

average annual heat input during any 3 consecutive calendar 

years to the boiler is provided by regulated gas streams that 

are subject to another standard. 

(h) Temporary boilers as defined in this subpart. 

(i) Residential boilers as defined in this subpart. 

(j) Electric boilers as defined in this subpart. 

 (k) An electric utility steam generating unit (EGU) as 

defined in this subpartcovered by subpart UUUUU of this part. 

§63.11196 What are my compliance dates? 
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 (a) If you own or operate an existing affected boiler, you 

must achieve 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 tune-up, you must 

achieve compliance with the work practice or management standard 

no later than March 21, 2014. 

 (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, 
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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 as specified in 

§§60.2145(a)(2) and (3) of subpart CCCC or §§60.2710(a)(2) and 

(3) of subpart DDDD. 

Emission Limits, Work Practice Standards, Emission Reduction 

Measures, and Management Practices

§63.11200 What are the subcategories of boilers? 

 The subcategories of boilers, as defined in §63.11237 are: 

 (a) Coal. 

 (b) Biomass. 

 (c) Oil. 

 (d) Seasonal boilers. 

 (e) Oil-fired boilers with heat input capacity of equal to 

or less than 5 million British thermal units (Btu) per hour. 

 (f) Boilers with an oxygen trim system that maintains an 

optimum air-to-fuel ratio that would otherwise be subject to a 

biennial tune-up. 

 (g) Limited-use boilers. 

§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, 
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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 or 

is amended to meet the energy assessment requirements in Table 2 

to this subpart satisfies the energy assessment requirement. A 

facility that operates under an energy management program 

established through energy management systems compatible with 

ISO 50001, that includes the affected units, also satisfies the 

energy assessment 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 the affected boiler 

is operating, except during periods of startup and shutdown as 

defined in §63.11237, during which time you must comply only 

with Table 2 to this subpart. 

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 
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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 must demonstrate compliance with all applicable 

emission limits using performance stack testing, fuel analysis, 

or a continuous monitoring system (CMS), including a continuous 

emission monitoring system (CEMS), a continuous opacity 

monitoring system (COMS), or a continuous parameter monitoring 

system (CPMS), where applicable. You may demonstrate compliance 

with the 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 CPMS), 

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 CPMS. This requirement also applies to you if you 
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petition the EPA Administrator for alternative monitoring 

parameters under §63.8(f). 

(1) For each CMS required in this section (including CEMS, 

COMS, or CPMS), you must develop, and submit to the 

Administrator 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 CEMS or COMS operated according 

to the performance specifications under appendix B to part 60 of 

this chapter and that meet the requirements of §63.11224. 

(i) Installation of the CMS 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). 
Page 11 of 109

 (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 with 

the applicable emission limits no later than 180 days after the 
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compliance date that is specified in §63.11196 and according to 

the applicable provisions in §63.7(a)(2), except as provided in 

paragraph (j) of this section. 

 (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), 

except as provided in paragraph (j) of this section. 

 (d) For new or reconstructed affected boilers that have 

applicable emission limits, you must demonstrate initial 

compliance with the applicable emission limits no later than 180 

days after March 21, 2011 or within 180 days after startup of 

the source, whichever is later, according to §63.7(a)(2)(ix). 

(e) For new or reconstructed oil-fired boilers that combust 

only oil that contains no more than 0.50 weight percent sulfur 

or a mixture of 0.50 weight percent sulfur oil with other fuels 

not subject to a PM emission limit under this subpart and that 

do not use a post-combustion technology (except a wet scrubber) 

to reduce particulate matter (PM) or sulfur dioxide emissions, 

you are not subject to the PM emission limit in Table 1 of this 

subpart providing you monitor and record on a monthly basis the 

type of fuel combusted. If you intend to burn a new type of fuel 

or fuel mixture that does not meet the requirements of this 
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paragraph, you must conduct a performance test within 60 days of 

burning the new fuel. 

 (f) For new or reconstructed affected boilers that have 

applicable work practice standards or management practices, you 

are not required to complete an initial performance tune-up, but 

you are required to complete the applicable biennial or 5-year 

tune-up as specified in §63.11223 no later than 25 months or 61 

months, respectively, after the initial startup of the new or 

reconstructed affected source. 

 (g) For affected boilers that ceased burning solid waste 

consistent with §63.11196(d), and for which your initial 

compliance date has passed, you must demonstrate compliance 

within 60 days of the effective date of the waste-to-fuel switch

as specified in §60.2145(a)(2) and (3) of subpart CCCC or 

§60.2710(a)(2) and (3) of subpart DDDD. If you have not 

conducted your compliance demonstration for this subpart within 

the previous 12 months, you must complete all compliance 

demonstrations for this subpart before you commence or 

recommence combustion of solid waste. 

(h) For affected boilers that switch fuels or make a 

physical change to the boiler that results in the applicability 

of a different subcategory within subpart JJJJJJ or the boiler 

becoming subject to subpart JJJJJJ, you must demonstrate 

compliance within 180 days of the effective date of the fuel 
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switch or the physical change. Notification of such changes must 

be submitted according to §63.11225(g). 

(i) For boilers located at existing major sources of HAP 

that limit their potential to emit (e.g., make a physical change 

or take a permit limit) such that the existing major source 

becomes an area source, you must comply with the applicable 

provisions as specified in paragraphs (i)(1) through (3) of this 

section. 

(1) Any such existing boiler at the existing source must 

demonstrate compliance with subpart JJJJJJ within 180 days of 

the later of March 21, 2014 or upon the existing major source 

commencing operation as an area source. 

(2) Any new or reconstructed boiler at the existing source 

must demonstrate compliance with subpart JJJJJJ within 180 days 

of the later of March 21, 2011 or startup. 

(3) Notification of such changes must be submitted 

according to §63.11225(g). 

(j) For existing affected boilers that have not operated on 

solid fossil fuel, biomass, or liquid fuel between the effective 

date of the rule and the compliance date that is specified for 

your source in §63.11196, you must comply with the applicable 

provisions as specified in paragraphs (j)(1) through (3) of this 

section. 
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(1) You must complete the initial compliance demonstration, 

if subject to the emission limits in Table 1 to this subpart, as 

specified in paragraphs (a) and (b) of this section, no later 

than 180 days after the re-start of the affected boiler on solid 

fossil fuel, biomass, or liquid fuel and according to the 

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

(2) You must complete the initial performance tune-up, if 

subject to the tune-up requirements in §63.11223, by following 

the procedures described in §63.11223(b) no later than 30 days 

after the re-start of the affected boiler on solid fossil fuel, 

biomass, or liquid fuel. 

(3) You must complete the one-time energy assessment, if 

subject to the energy assessment requirements specified in Table 

2 to this subpart, no later than the compliance date specified 

in §63.11196. 

§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 
Page 16 of 109

§63.11222 , Table 6 to this subpart and paragraph (b) of this 

section, as applicable, and conducting 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 

scrubber liquid flow rate and minimum scrubber pressure drop as 

defined in §63.11237, as your operating limits during the threerun performance stack test. If you use a wet scrubber and you 

conduct separate performance stack tests for PM and mercury 

emissions, you must establish one set of minimum scrubber liquid 

flow rate and pressure drop operating limits. If you conduct 

multiple performance stack tests, you must set the minimum 

scrubber liquid flow rate and pressure drop operating limits at 

the highest minimum values established during the performance 

stack tests. 
Page 17 of 109

(2) For an electrostatic precipitator operated with a wet 

scrubber, you must establish the minimum total secondary 

electric power (secondary voltage and secondary current), as 

defined in §63.11237, as your operating limits during the threerun performance stack test. 

(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 
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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. 

P90 = mean + (SD * t) (Eq. 1) 

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 
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requirements in Table 4 to this subpart. Boilers that use a CEMS 

for carbon monoxide (CO) are exempt from the initial CO 

performance testing in Table 4 to this subpart and the oxygen 

concentration operating limit requirement specified in Table 3 

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 PM concentrations and the 
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measured mercury concentrations that result from the initial 

performance test to pounds per million Btu heat input emission 

rates. 

§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? 
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 (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

§63.11210(c) or (f), as applicable, and §63.11223(b). andIf you 

own or operate an existing coal-fired boiler with a heat input 

capacity of less than 10 million Btu per hour, you must submit a 

signed statement in the Notification of Compliance Status report 

that indicates that you conducted an initial 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 §63.11210(c) or (f), as 

applicable, and §63.11223(b). andIf you own or operate an 

existing biomass-fired boiler or existing oil-fired boiler, you 

must submit a signed statement in the Notification of Compliance 

Status report that indicates that you conducted an initial tuneup 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 according to Table 2 to 

this subpart and that the assessment is an accurate depiction of 

your facility at the time of the assessment or that the maximum 
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number of on-site technical hours specified in the definition of 

energy assessment applicable to the facility has been expended. 

 (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 or 

fuel analyses? 

 (a) If your boiler has a heat input capacity of 10 million 

British thermal units per hour or greater, you must conduct all 

applicable performance (stack) tests according to §63.11212 on 

an triennial basis, except as specified in paragraphs (b) 

through (d) of this section. Triennial performance tests must be 

completed no more than 37 months after the previous performance 
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test. 

 (b) When demonstrating initial compliance with the PM 

emission limit, if your boiler’s performance test results show 

that your PM emissions are equal to or less than half of the PM 

emission limit, you do not need to conduct further performance 

tests for PM but must continue to comply with all applicable 

operating limits and monitoring requirements. If your initial 

performance test results show that your PM emissions are greater 

than half of the PM emission limit, you must conduct subsequent 

performance tests as specified in paragraph (a) of this section. 

(c) 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 as 

specified in paragraphs (c)(1) and (2) of this section. 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. 

(1) When demonstrating initial compliance with the mercury 

emission limit, if the mercury constituents in the fuel or fuel 

mixture are measured to be equal to or less than half of the 

mercury emission limit, you do not need to conduct further fuel 
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analysis sampling but must continue to comply with all 

applicable operating limits and monitoring requirements. 

 (2) When demonstrating initial compliance with the mercury 

emission limit, if the mercury constituents in the fuel or fuel 

mixture are greater than half of the mercury emission limit, you 

must conduct quarterly sampling. 

 (d) For existing affected boilers that have not operated 

on solid fossil fuel, biomass, or liquid fuel since the previous 

compliance demonstration and more than 3 years have passed since 

the previous compliance demonstration, you must complete your 

subsequent compliance demonstration no later than 180 days after 

the re-start of the affected boiler on solid fossil fuel, 

biomass, or liquid fuel. 

§63.11221 Is there a minimum amount of monitoring data I must 

obtain? 

 (a) You must monitor and collect data according to this 

section and the site-specific monitoring plan required by 

§63.11205(c). 

 (b) You must operate the monitoring system and collect 

data at all required intervals at all times the affected source 

is operating and compliance is required, except for periods of 

monitoring system malfunctions or out-of-control periods, (see 

§63.8(c)(7) of this part), repairs associated with monitoring 

system malfunctions or out-of-control periods, and required 
Page 25 of 109

monitoring system quality assurance or quality control 

activities including, as applicable, calibration checks, 

required zero and span adjustments and scheduled CMS maintenance 

as defined in your site-specific monitoring plan. 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 complete monitoring system repairs in response to 

monitoring system malfunctions or out-of-control periods and to 

return the monitoring system to operation as expeditiously as 

practicable. 

(c) You may not use data collected during periods of 

startup and shutdown, monitoring system malfunctions or out-ofcontrol periods, repairs associated with monitoring system 

malfunctions or out-of-control periods, or required monitoring 

system quality assurance or quality control activities in 

calculations used to report emissions or operating levels. Any 

such periods must be reported according to the requirements in 

§63.11225. 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 monitoring system out-of-control periods, repairs associated 
Page 26 of 109

with monitoring system malfunctions or monitoring system out-ofcontrol periods, and required monitoring system quality 

assurance or quality control activities (including, as 

applicable, calibration checks, required zero and span 

adjustments, and scheduled CMS maintenance as defined in your 

site-specific monitoring plan), 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 
Page 27 of 109

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. toIf you have 

an applicable mercury emission limit, you must 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 
Page 28 of 109

§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 
Page 29 of 109

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 performance tune-up according to paragraphs (b) of 

this section and keep records as required in §63.11225(c) to 

demonstrate continuous compliance. You must conduct the tune-up 

while burning the type of fuel (or fuels in the case of boilers 

that routinely burn two types of fuels at the same time) that 

provided the majority of the heat input to the boiler over the 

12 months prior to the tune-up.

 (b) Except as specified in paragraphs (c) through (f) of 

this section, 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. Each biennial tune-up must be 

conducted no more than 25 months after the previous tune-up. For 

a new or reconstructed boiler, the first biennial tune-up must 

be no later than 25 months after the initial startup of the new 

or reconstructed boiler. 

 (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, 
Page 30 of 109

not to exceed 36 months from the previous inspection). Units that 

produce electricity for sale may delay the burner inspection 

until the first outage, not to exceed 36 months from the 

previous inspection. 

 (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 (you may delay the inspection until the 

next scheduled unit shutdown, not to exceed 36 months from the 

previous inspection). Units that produce electricity for sale 

may delay the inspection until the first outage, not to exceed 

36 months from the previous inspection. 

 (4) Optimize total emissions of CO. This optimization 

should be consistent with the manufacturer’s specifications, if 

available, and with any nitrogen oxide requirement to which the 

unit is subject. 

 (5) Measure the concentrations in the effluent stream of 

CO 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). Measurements 
Page 31 of 109

may be taken using a portable CO analyzer. 

 (6) Maintain onsite and submit, if requested by the 

Administrator, a 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 at high fire or typical operating load, 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 tune-up of the boiler, but only if the unit was 

physically and legally capable of using more than one type of 

fuel during that period. Units sharing a fuel meter may estimate 

the fuel use by each unit. 

 (7) If the unit is not operating on the required date for 

a tune-up, the tune-up must be conducted within 30 days of 

startup. 

(c) Boilers with an oxygen trim system that maintains an 

optimum air-to-fuel ratio that would otherwise be subject to a 

biennial tune-up must conduct a tune-up of the boiler every 5 

years as specified in paragraphs (b)(1) through (7) of this 

section. Each 5-year tune-up must be conducted no more than 61 

months after the previous tune-up. For a new or reconstructed 
Page 32 of 109

boiler with an oxygen trim system, the first 5-year tune-up must 

be no later than 61 months after the initial startup. You may 

delay the burner inspection specified in paragraph (b)(1) of 

this section and inspection of the system controlling the airto-fuel ratio specified in paragraph (b)(3) of this section 

until the next scheduled unit shutdown, but you must inspect 

each burner and system controlling the air-to-fuel ratio at 

least once every 72 months. 

(d) Seasonal boilers must conduct a tune-up every 5 years 

as specified in paragraphs (b)(1) through (7) of this section. 

Each 5-year tune-up must be conducted no more than 61 months 

after the previous tune-up. For a new or reconstructed seasonal 

boiler, the first 5-year tune-up must be no later than 61 months 

after the initial startup. You may delay the burner inspection 

specified in paragraph (b)(1) of this section and inspection of 

the system controlling the air-to-fuel ratio specified in 

paragraph (b)(3) of this section until the next scheduled unit 

shutdown, but you must inspect each burner and system 

controlling the air-to-fuel ratio at least once every 72 months. 

Seasonal boilers are not subject to the emission limits in Table 

1 to this subpart or the operating limits in Table 3 to this 

subpart. 

(e) Oil-fired boilers with a heat input capacity of equal 

to or less than 5 million Btu per hour must conduct a tune-up 
Page 33 of 109

every 5 years as specified in paragraphs (b)(1) through (7) of 

this section. Each 5-year tune-up must be conducted no more than 

61 months after the previous tune-up. For a new or reconstructed 

oil-fired boiler with a heat input capacity of equal to or less 

than 5 million Btu per hour, the first 5-year tune-up must be no 

later than 61 months after the initial startup. You may delay 

the burner inspection specified in paragraph (b)(1) of this 

section and inspection of the system controlling the air-to-fuel 

ratio specified in paragraph (b)(3) of this section until the 

next scheduled unit shutdown, but you must inspect each burner 

and system controlling the air-to-fuel ratio at least once every 

72 months. 

 (f) Limited-use boilers must conduct a tune-up every 5 

years as specified in paragraphs (b)(1) through (7) of this 

section. Each 5-year tune-up must be conducted no more than 61 

months after the previous tune-up. For a new or reconstructed 

limited-use boiler, the first 5-year tune-up must be no later 

than 61 months after the initial startup. You may delay the 

burner inspection specified in paragraph (b)(1) of this section 

and inspection of the system controlling the air-to-fuel ratio 

specified in paragraph (b)(3) of this section until the next 

scheduled unit shutdown, but you must inspect each burner and 

system controlling the air-to-fuel ratio at least once every 72 

months. Limited-use boilers are not subject to the emission 
Page 34 of 109

limits in Table 1 to this subpart, the energy assessment 

requirements in Table 2 to this subpart, or the operating limits 

in Table 3 to this subpart. 

 (g) 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. 

§63.11224 What are my monitoring, installation, operation, and 

maintenance requirements? 

(a) If your boiler is subject to a CO emission limit in 

Table 1 to this subpart, you must either install, operate, and 

maintain a CEMS for CO and oxygen according to the procedures in 

paragraphs (a)(1) through (6) of this section, or install, 

calibrate, operate, and maintain an oxygen analyzer system, as 

defined in §63.11237, according to the manufacturer’s 
Page 35 of 109

recommendations and paragraphs (a)(7) and (d) of this section, 

as applicable, by the compliance date specified in §63.11196. 

Where a certified CO CEMS is used, the CO level shall be 

monitored at the outlet of the boiler, after any add-on controls 

or flue gas recirculation system and before release to the 

atmosphere. Boilers that use a CO CEMS are exempt from the 

initial CO performance testing and oxygen concentration 

operating limit requirements specified in §63.11211(a) of this 

subpart. Oxygen monitors and oxygen trim systems must be 

installed to monitor oxygen in the boiler flue gas, boiler 

firebox, or other appropriate intermediate location. 

(1) Each CO CEMS must be installed, operated, and 

maintained according to the applicable procedures under 

Performance Specification 4, 4A, or 4B at 40 CFR part 60, 

appendix B, and each oxygen CEMS must be installed, operated, 

and maintained according to Performance Specification 3 at 40 

CFR part 60, appendix B. Both the CO and oxygen CEMS must also 

be installed, operated, and maintained according to the sitespecific 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 Specifications 3 and 4, 4A, or 4B at 40 CFR part 60, 

appendix B. 
Page 36 of 109

(3) Each CEMS must complete a minimum of one cycle of 

operation (sampling, analyzing, and data recording) every 15 

minutes. You must have CEMS data values from a minimum of four 

successive cycles of operation representing each of the four 15-

minute periods in an hour, or at least two 15-minute data values 

during an hour when CEMS calibration, quality assurance, or 

maintenance activities are being performed, to have a valid hour 

of data. 

(4) The CEMS data must be reduced as specified in 

§63.8(g)(2). 

(5) You must calculate hourly averages, corrected to 3 

percent oxygen, from each hour of CO CEMS data in parts per 

million CO concentrations and determine the 10-day rolling 

average of all recorded readings, except as provided in 

§63.11221(c). Calculate a 10-day rolling average from all of the 

hourly averages collected for the 10-day operating period using 

Equation 2 of this section. 

10-day average = 

∑ ு௣௩௜ ೙

೔సభ

௡ (Eq.2)

Where: 

Hpvi = the hourly parameter value for hour i 

n = the number of valid hourly parameter values 

collected over 10 boiler operating days 

(6) For purposes of collecting CO data, you must operate 

the CO CEMS as specified in §63.11221(b). For purposes of 

calculating data averages, you must use all the data collected 
Page 37 of 109

during all periods in assessing compliance, except that you must 

exclude certain data as specified in §63.11221(c). Periods when 

CO data are unavailable may constitute monitoring deviations as 

specified in §63.11221(d). 

(7) You must operate the oxygen analyzer system at or above 

the minimum oxygen level that is established as the operating 

limit according to Table 6 to this subpart when firing the fuel 

or fuel mixture utilized during the most recent CO performance 

stack test. If your facility is not required to conduct a CO 

performance stack test, you must set the oxygen level to the 

oxygen concentration measured during the most recent tune-up to 

optimize CO to manufacturer’s specifications and you must 

operate the oxygen analyzer system at or above that level. 

Operation of oxygen trim systems to meet these requirements 

shall not be done in a manner which compromises furnace safety. 

 (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 
Page 38 of 109

§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 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 (c)(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 
Page 39 of 109

criteria (e.g., calibrations). 

 (2) In your site-specific monitoring plan, you must also 

address paragraphs (c)(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 CPMS 

according to the procedures in paragraphs (d)(1) through (4) of 

this section. 

 (1) The CPMS must complete a minimum of one cycle of 

operation every 15 minutes. You must have data values from a 

minimum of four successive cycles of operation representing each 

of the four 15-minute periods in an hour, or at least two 15-

minute data values during an hour when CMS calibration, quality 
Page 40 of 109

assurance, or maintenance activities are being performed, to 

have a valid hour of data. 

(2) You must calculate hourly arithmetic averages from 

each hour of CPMS data in units of the operating limit and 

determine the 30-day rolling average of all recorded readings, 

except as provided in §63.11221(c). Calculate a 30-day rolling 

average from all of the hourly averages collected for the 30-day 

operating period using Equation 3 of this section. 

30-day average = 

∑ ு௣௩௜ ೙

೔సభ

௡

 (Eq.3) 

Where: 

Hpvi = the hourly parameter value for hour i 

n = the number of valid hourly parameter values 

 collected over 30 boiler operating days 

 (3) For purposes of collecting data, you must operate the 

CPMS as specified in §63.11221(b). For purposes of calculating 

data averages, you must use all the data collected during all 

periods in assessing compliance, except that you must exclude 

certain data as specified in §63.11221(c). Periods when CPMS 

data are unavailable may constitute monitoring deviations as 

specified in §63.11221(d). 

 (4) 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 
Page 41 of 109

each COMS according to the procedures in paragraphs (e)(1) 

through (8) 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 site-specific 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 and the requirements of 

§63.8(e). You must identify periods the COMS is out of control 
Page 42 of 109

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 calculate and record 6-minute averages from 

the opacity monitoring data and determine and record the daily 

block average of recorded readings, except as provided in 

§63.11221(c). 

 (8) For purposes of collecting opacity data, you must 

operate the COMS as specified in §63.11221(b). For purposes of 

calculating data averages, you must use all the data collected 

during all periods in assessing compliance, except that you must 

exclude certain data as specified in §63.11221(c). Periods when 

COMS data are unavailable may constitute monitoring deviations 

as specified in §63.11221(d). 

(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 
Page 43 of 109

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 or 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? 
Page 44 of 109

 (a) You must submit the notifications specified in 

paragraphs (a)(1) through (5) of this section to the 

administrator. 

 (1) You must submit all of the notifications in §§63.7(b): 

63.8(e) and (f); and 63.9(b) through (e), (g) and (h) that apply 

to you by the dates specified in those sections except as 

specified in paragraphs (a)(2) and (4) of this section. 

 (2) An Initial Notification must be submitted no later 

than January 20, 2014 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 

no later than 120 days after the applicable compliance date 

specified in §63.11196 unless you own or operate a new boiler 

subject only to a requirement to conduct a biennial or 5-year 

tune-up or you must conduct a performance stack test. If you own 

or operate a new boiler subject to a requirement to conduct a 

tune-up, you are not required to prepare and submit a 

Notification of Compliance Status for the tune-up. If you must 

conduct a performance stack test, you must submit the 

Notification of Compliance Status within 60 days of completing 
Page 45 of 109

the performance stack test. You must submit the Notification of 

Compliance Status in accordance with paragraphs (a)(4)(i) and 

(vi) of this section. The Notification of Compliance Status must 

include the information and certification(s) of compliance in 

paragraphs (a)(4)(i) through (v) of this section, as applicable, 

and signed by a responsible official. 

 (i) You must submit the information required in 

§63.9(h)(2), except the information listed in §63.9(h)(2)(i)(B), 

(D), (E) and (F). If you conduct any performance tests or CMS 

performance evaluations, you must submit that data as specified 

in paragraph (e) of this section. If you conduct any opacity or 

visible emission observations, or other monitoring procedures or 

methods, you must submit that data to the Administrator at the 

appropriate address listed in §63.13. 

 (ii) “This facility complies with the requirements in 

§63.11214 to conduct an initial tune-up of the boiler.” 

 (iii) “This facility has had an energy assessment 

performed according to §63.11214(c).” 

 (iv) For units that install bag leak detection systems: 

“This facility complies with the requirements in §63.11224(f).” 

(v) 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.” 
Page 46 of 109

(vi) The notification must be submitted electronically 

using the Compliance and Emissions Data Reporting Interface 

(CEDRI) that is accessed through EPA’s Central Data Exchange 

(CDX) (www.epa.gov/cdx). However, if the reporting form specific 

to this subpart is not available in CEDRI at the time that the 

report is due, the written Notification of Compliance Status 

must be submitted to the Administrator at the appropriate 

address listed in §63.13. 

 (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, you 

must include in the Notification of Compliance Status the date 

of the test and a summary of the results, not a complete test 

report, relative to this subpart. 

(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 the energy assessment 

requirement and/or a requirement to conduct a biennial or 5-year 

tune-up according to §63.11223(a) and not subject to emission 

limits or operating limits, you may prepare only a biennial or 
Page 47 of 109

5-year compliance report as specified in paragraphs (b)(1) and 

(2) of this section. 

 (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. 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 

§63.11223 to conduct a biennial or 5-year tune-up, as 

applicable, of each boiler.” 

(ii) 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.” 

(iii) “This facility complies with the requirement in 

§63.11214(d) and §63.11223(g) to minimize the boiler’s time 

spent during startup and shutdown and to conduct 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.” 
Page 48 of 109

(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 non-waste determination by 

you or EPA through a petition process to be a non-waste 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 (7) 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 and §63.11223 as specified in 

paragraphs (c)(2)(i) through (vi) of this section. 

 (i) Records must identify each boiler, the date of tune-
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up, the procedures followed for tune-up, and the manufacturer’s 

specifications to which the boiler was tuned. 

 (ii) For operating units that combust non-hazardous 

secondary materials that have been determined not to be solid 

waste pursuant to §241.3(b)(1) of this chapter, you must keep a 

record which documents how the secondary material meets each of 

the legitimacy criteria under §241.3(d)(1). If you combust a 

fuel that has been processed from a discarded non-hazardous 

secondary material pursuant to §241.3(b)(4) of this chapter, you 

must keep records as to how the operations that produced the 

fuel satisfies the definition of processing in §241.2 and each of 

the legitimacy criteria in §241.3(d)(1) of this chapter. If the 

fuel received a non-waste determination pursuant to the petition 

process submitted under §241.3(c) of this chapter, you must keep 

a record that documents how the fuel satisfies the requirements 

of the petition process. For operating units that combust nonhazardous secondary materials as fuel per §241.4, you must keep 

records documenting that the material is a listed non-waste 

under §241.4(a). 

(iii) For each boiler required to conduct an energy 

assessment, you must keep a copy of the energy assessment 

report. 

(iv) For each boiler subject to an emission limit in Table 

1 to this subpart, you must also keep records of monthly fuel 
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use by each boiler, including the type(s) of fuel and amount(s) 

used. For each new oil-fired boiler that meets the requirements 

of §63.11210(e), you must keep records, on a monthly basis, of 

the type of fuel combusted.

(v) For each boiler that meets the definition of seasonal 

boiler, you must keep records of days of operation per year. 

(vi) For each boiler that meets the definition of limiteduse boiler, you must keep a copy of the federally enforceable 

permit that limits the annual capacity factor to less than or 

equal to 10 percent and records of fuel use for the days the 

boiler is operating. 

 (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 
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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 
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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. You must keep each record for 

5 years following the date of each recorded action. You must 

keep each record onsite or be accessible from a central location 

by computer or other means that instantly provide access at the 

site for at least 2 years after the date of each recorded 

action. You may keep the records off site for the remaining 3 

years. 

 (e)(1) Within 60 days after the date of completing each 

performance test (defined in §63.2) as required by this subpart 

you must submit the results of the performance tests, including 

any associated fuel analyses, required by this subpart to EPA’s 

WebFIRE database by using CEDRI that is accessed through EPA’s 

CDX (www.epa.gov/cdx). Performance test data must be submitted 

in the file format generated through use of EPA’s Electronic 

Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data 

collected using test methods on the ERT website are subject to 

this requirement for submitting reports electronically to 

WebFIRE. Owners or operators who claim that some of the 

information being submitted for performance tests is 
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confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: Group Leader, Measurement Policy 

GroupWebFIRE Administrator, MD C404-02, 4930 Old Page Rd., 

Durham, NC 27703. The same ERT file with the CBI omitted must 

be submitted to EPA via CDX as described earlier in this 

paragraph. At the discretion of the delegated authority, you 

must also submit these reports, including CBI, to the delegated 

authority in the format specified by the delegated authority. 

For any performance test conducted using test methods that are 

not listed on the ERT website, the owner or operator shall 

submit the results of the performance test in paper submissions 

to the Administrator at the appropriate address listed in 

§63.13. 

(e)(2) Within 60 days after the date of completing each 

CEMS performance evaluation test as defined in §63.2, you must 

submit relative accuracy test audit (RATA) data to EPA’s CDX by 

using CEDRI in accordance with paragraph (e)(1) of this section. 

Only RATA pollutants that can be documented with the ERT (as 

listed on the ERT website) are subject to this requirement. For 

any performance evaluations with no corresponding RATA 
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pollutants listed on the ERT website, the owner or operator 

shall submit the results of the performance evaluation in paper 

submissions to the Administrator at the appropriate address 

listed in §63.13. 

(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 have switched fuels or made a physical change 

to the boiler and the fuel switch or change resulted in the 

applicability of a different subcategory within subpart JJJJJJ, 

in the boiler becoming subject to subpart JJJJJJ, or in the 

boiler switching out of subpart JJJJJJ due to a fuel change to 

100 percent natural gasthat results in the boiler meeting the 

definition of gas-fired boiler, as defined in §63.11237, or you 
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have taken a permit limit that resulted in you beingbecoming

subject to subpart JJJJJJ or no longer being subject to subpart 

JJJJJJ, you must provide notice of the date upon which you 

switched fuels, made the physical change, or took a permit limit 

within 30 days of the change. 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 have 

switched fuels, were physically changed, or took a permit limit, 

and the date of the notice. 

(2) The date upon which the fuel switch, physical change, 

or permit limit occurred. 

§63.11226 Affirmative Defense for Violation of Emission 

Standards during Malfunction 

In response to an action to enforce the standards set forth 

in §63.11201 you may assert an affirmative defense to a claim 

for civil penalties for violations of such standards that are 

caused by malfunction, as defined at 40 CFR §63.2. Appropriate 

penalties may be assessed 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) Assertion of affirmative defense. To establish the 

affirmative defense in any action to enforce such a standard, 

you must timely meet the reporting requirements in paragraph (b) 
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of this section, and must prove by a preponderance of evidence 

that: 

(1) The violation: 

(i) Was caused by a sudden, infrequent, and unavoidable 

failure of air pollution control 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) Was not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and 

(2) Repairs were made as expeditiously as possible when a 

violation occurred; and 

 (3) The frequency, amount and duration of the violation 

(including any bypass) were minimized to the maximum extent 

practicable; and 

 (4) If the violation 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 violation on ambient air quality, the environment, and human 
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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 violation were 

documented by properly signed, contemporaneous operating logs; 

and 

(8) At all times, the affected source 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 violation resulting 

from the malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering judgment, 

the amount of any emissions that were the result of the 

malfunction. 

(b) Report. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the 

Administrator with all necessary supporting documentation, that 

it has met the requirements set forth in paragraph (a) of this 

section. This affirmative defense report shall be included in 

the first periodic compliance, deviation report or excess 

emission report otherwise required after the initial occurrence 
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of the violation of the relevant standard (which may be the end 

of any applicable averaging period). If such compliance, 

deviation report or excess emission report is due less than 45 

days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second 

compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant 

standard. 

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 

an administrator 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) 
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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 non-opacity 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: 

 10-day rolling average means the arithmetic mean of all 

valid hours of data from 10 successive operating days, except 
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for periods of startup and shutdown and periods when the unit is 

not operating. 

 30-day rolling average means the arithmetic mean of all 

valid hours of data from 30 successive operating days, except 

for periods of startup and shutdown and periods when the unit is 

not operating. 

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 capacity factor means the ratio between the actual 

heat input to a boiler from the fuels burned during a calendar 

year and the potential heat input to the boiler had it been 

operated for 8,760 hours during a year at the maximum steady 

state design heat input capacity.

 Annual heat input means the heat input for the 12 months 

preceding the compliance demonstration. 

 Bag leak detection system means a group of instruments that 

are 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 
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principle to monitor relative particulate matter loadings. 

 Biodiesel means a mono-alkyl ester derived from biomass and 

conforming to ASTM D6751–11b, Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels 

(incorporated by reference, see §63.14). 

 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 any 

biomass and is not in the coal subcategory. 

 Boiler means an enclosed device using controlled flame 

combustion in which water is heated to recover thermal energy in 

the form of steam and/or external-use hot water. Controlled 

flame combustion refers to a steady-state, or near steady-state, 

process wherein fuel and/or oxidizer feed rates are controlled. 

A device combusting solid waste, as defined in §241.3 of this 
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chapter, is not a boiler unless the device is exempt from the 

definition of a solid waste incineration unit as provided in 

section 129(g)(1) of the Clean Air Act. Waste heat boilers, 

process heaters, and autoclaves are excluded from the definition 

of Boiler. 

 Boiler system means the boiler and associated components, 

such as, the feedwater systems, combustion air systems, fuel 

systems (including burners), blowdown systems, combustion 

control systems, steam systems, and condensate return systems, 

directly connected to and serving the energy use systems. 

 Calendar year means the period between January 1 and 

December 31, inclusive, for a given year. 

 Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, 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, 

solvent-refined coal, coal-oil mixtures, and coal-water 

mixtures. Coal derived gases and liquids 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. 
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 Commercial boiler means a boiler used in commercial 

establishments such as hotels, restaurants, and laundries to 

provide electricity, steam, and/or hot water. 

 Common stack means the exhaust of emissions from two or 

more affected units through a single flue. Affected units with a 

common stack may each have separate air pollution control 

systems located before the common stack, or may have a single 

air pollution control system located after the exhausts come 

together in a single flue. 

 Daily block average means the arithmetic mean of all valid 

emission concentrations or parameter levels recorded when a unit 

is operating measured over the 24-hour period from 12 am 

(midnight) to 12 am (midnight), except for periods of startup 

and shutdown and periods when the unit is not operating. 

 Deviation (1) 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 applicable requirement or obligation 

established by this subpart including, but not limited to, any 

emission limit, operating limit, or work practice standard; or 

 (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. 
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 (2) A deviation is not always a violation. 

Distillate oil means fuel oils that contain 0.05 weight 

percent nitrogen or less and comply with the specifications for 

fuel oil numbers 1 and 2, as defined by the American Society of 

Testing and Materials in ASTM D396 (incorporated by reference, 

see §63.14) or diesel fuel oil numbers 1 and 2, as defined by 

the American Society for Testing and Materials in ASTM D975 

(incorporated by reference, see §63.14), kerosene, and biodiesel 

as defined by the American Society of Testing and Materials in 

ASTM D6751-11b (incorporated by reference, see §63.14). 

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 used as control devices in fluidized bed 

boilers and process heaters are included in this definition. A 

dry scrubber is a dry control system. 

Electric boiler means a boiler in which electric heating 

serves as the source of heat. Electric boilers that burn gaseous 

or liquid fuel during periods of electrical power curtailment or 

failure are included in this definition. 

Electric utility steam generating unit (EGU) means a fossil 

fuel-fired combustion unit of more than 25 megawatts that serves 

a generator that produces electricity for sale. A fossil fuel-
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fired unit that cogenerates steam and electricity and supplies 

more than one-third of its potential electric output capacity 

and more than 25 megawatts electrical output to any utility 

power distribution system for sale is considered an electric 

utility steam generating unit. To be “capable of combusting” 

fossil fuels, an EGU would need to have these fuels allowed in 

their operating permits and have the appropriate fuel handling 

facilities on-site or otherwise available (e.g., coal handling 

equipment, including coal storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In addition, fossil 

fuel-fired EGU means any EGU that fired fossil fuel for more 

than 10.0 percent of the average annual heat input in any 3 

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year after April 16, 

2015. 

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 usually a dry control system. 

Energy assessment means the following for the emission 

units covered by this subpart: 
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(1) The energy assessment for facilities with affected 

boilers with less than 0.3 trillion Btu per year (TBtu/year) 

heat input capacity will be 8 on-site technical labor hours in 

length maximum, but may be longer at the discretion of the owner 

or operator of the affected source. The boiler system(s) and any 

on-site energy use system(s) accounting for at least 50 percent 

of the affected boiler(s) energy (e.g., steam, hot water, or 

electricity) production, as applicable, will be evaluated to 

identify energy savings opportunities, within the limit of 

performing an 8-hour energy assessment. 

(2) The energy assessment for facilities with affected 

boilers with 0.3 to 1 TBtu/year heat input capacity will be 24 

on-site technical labor hours in length maximum, but may be 

longer at the discretion of the owner or operator of the 

affected source. The boiler system(s) and any on-site energy use 

system(s) accounting for at least 33 percent of the affected 

boiler(s) energy (e.g., steam, hot water, or electricity) 

production, as applicable, will be evaluated to identify energy 

savings opportunities, within the limit of performing a 24-hour 

energy assessment. 

(3) The energy assessment for facilities with affected 

boilers with greater than 1.0 TBtu/year heat input capacity will 

be up to 24 on-site technical labor hours in length for the first 

TBtu/year plus 8 on-site technical labor hours for every 
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additional 1.0 TBtu/year not to exceed 160 on-site technical 

hours, but may be longer at the discretion of the owner or 

operator of the affected source. The boiler system(s) and any 

on-site energy use system(s) accounting for at least 20 percent 

of the affected boiler(s) energy (e.g., steam, hot water, or 

electricity) production, as applicable, will be evaluated to 

identify energy savings opportunities. 

(4) The on-site energy use system(s) serving as the basis 

for the percent of affected boiler(s) energy production, as 

applicable, in paragraphs (1), (2), and (3) of this definition 

may be segmented by production area or energy use area as most 

logical and applicable to the specific facility being assessed 

(e.g., product X manufacturing area; product Y drying area; 

Building Z). 

Energy management program means a program that includes a 

set of practices and procedures designed to manage energy use 

that are demonstrated by the facility’s energy policies, a 

facility energy manager and other staffing responsibilities, 

energy performance measurement and tracking methods, an energy 

saving goal, action plans, operating procedures, internal 

reporting requirements, and periodic review intervals used at 

the facility. Facilities may establish their program through 

energy management systems compatible with ISO 50001. 

Energy use system (1) Includes the following systems 
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located on the site of the affected boiler that use energy 

provided by the boiler: 

(i) Process heating; compressed air systems; machine drive 

(motors, pumps, fans); process cooling; facility heating, 

ventilation, and air-conditioning systems; hot heater systems;, 

building envelop; and lighting; or 

(ii) Other systems that use steam, hot water, process heat, 

or electricity, provided by the affected boiler. 

(2) Energy use systems are only those systems using energy 

clearly produced by affected boilers. 

 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 
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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 
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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, but 

not limited to, the requirements of 40 CFR parts 60, 61, 63, and 

65, requirements within any applicable state implementation 

plan, and any permit requirements established under 40 CFR 52.21 

or under 40 CFR 51.18 and 40 CFR 51.24. 

Fluidized bed boiler means a boiler utilizing a fluidized 

bed combustion process that is not a pulverized coal boiler. 

 Fluidized bed combustion means a process where a fuel is 

burned in a bed of granulated particles, which are maintained in 

a mobile suspension by the forward flow of air and combustion 

products. 

Fossil fuel means natural gas, oil, coal, and any form of 

solid, liquid, or gaseous fuel derived from such material.

 Fuel type means each category of fuels that share a common 

name or classification. Examples include, but are not limited 

to, bituminous coal, sub-bituminous 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, 
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hydrogen, and biogas. 

 Gas-fired boiler includes any boiler that burns gaseous 

fuels not combined with any solid fuels and burns liquid fuel 

only during periods of gas curtailment, gas supply interruption, 

startups, or for periodic testing, maintenance, or operator 

training on liquid fuel. Periodic testing, maintenance, or 

operator training onof 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, returned condensate, or 

exhaust gases from other sources such as gas turbines, internal 

combustion engines, kilns. 

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, liquid, or biomass fuel and hot water is 

withdrawn for use external to the vessel. Hot water boilers 

(i.e., not generating steam) combusting gaseous, liquid, or 

biomass fuel with a heat input capacity of less than 1.6 million 

Btu per hour are included in this definition. The 120 U.S. 

gallon capacity threshold to be considered a hot water heater is 

independent of the 1.6 million Btu per hour heat input capacity 

threshold for hot water boilers. Hot water heater also means a 

tankless unit that provides on-demand hot water. 
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Hourly average means the arithmetic average of at least 

four CMS data values representing the four 15-minute periods in 

an hour, or at least two 15-minute data values during an hour 

when CMS calibration, quality assurance, or maintenance 

activities are being performed. 

 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, but not limited to, medical centers, 

nursing homes, research centers, institutions of higher 

education, elementary and secondary schools, libraries, 

religious establishments, and governmental buildings to provide 

electricity, steam, and/or hot water. 

 Limited-use boiler means any boiler that burns any amount 

of solid or liquid fuels and has a federally enforceable average

annual capacity factor of no more than 10 percent. 

 Liquid fuel includes, but is not limited to, distillate 

oil, residual oil, any form of liquid fuel derived from 

petroleum, used oil meeting the specification in 40 CFR 279.11, 

liquid biofuels, biodiesel, and vegetable oil, and comparable 

fuels as defined under 40 CFR 261.38. 

 Load fraction means the actual heat input of a boiler 

divided by heat input during the performance test that 
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established the minimum sorbent injection rate or minimum 

activated carbon injection rate, expressed as a fraction (e.g., 

for 50 percent load the load fraction is 0.5). For boilers that 

co-fire natural gas with a solid or liquid fuel, the load 

fraction is determined by the actual heat input of the solid or 

liquid fuel divided by heat input of the solid or liquid fuel 

fired during the performance test (e.g., if the performance test 

was conducted at 100 percent solid fuel firing, for 100 percent 

load firing 50 percent solid fuel and 50 percent natural gas, 

the load fraction is 0.5).

Minimum activated carbon injection rate means load fraction 

multiplied by the lowest hourly 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 limit. 

Minimum oxygen level means the lowest hourly average oxygen 

level measured according to Table 6 to this subpart during the 

most recent performance stack test demonstrating compliance with 

the applicable carbon monoxide emission limit. 

Minimum scrubber liquid flow rate means the lowest hourly 

average scrubber liquid flow rate (e.g., to the particulate 

matter scrubber) measured according to Table 6 to this subpart 

during the most recent performance stack test demonstrating 

compliance with the applicable emission limit. 
Page 74 of 109

Minimum scrubber pressure drop means the lowest hourly 

average 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 injection rate means: 

(1) The load fraction multiplied by the lowest hourly 

average sorbent injection rate for each sorbent measured 

according to Table 6 to this subpart during the most recent 

performance stack test demonstrating compliance with the 

applicable emission limits; or 

(2) For fluidized bed combustion, the lowest average ratio 

of sorbent to sulfur measured during the most recent performance 

test. 

Minimum total secondary electric power means the lowest 

hourly average total secondary electric power determined from 

the values of secondary voltage and secondary current 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; 

or 
Page 75 of 109

 (2) Liquefied petroleum gas, as defined by the American 

Society for Testing and Materials in ASTM D1835 (incorporated by 

reference, see §63.14); or 

(3) A mixture of hydrocarbons that maintains a gaseous 

state at ISO conditions (i.e., a temperature of 288 Kelvin, a 

relative humidity of 60 percent, and a pressure of 101.3 

kilopascals). Additionally, natural gas must either be composed 

of at least 70 percent methane by volume or have a gross 

calorific value between 35 and 41 megajoules (MJ) per dry 

standard cubic meter (950 and 1,100 Btu per dry standard cubic 

foot); or 

(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 only during periods of 

gas curtailment, gas supply interruptions, startups, or for 

periodic testing are not included in this definition. Periodic 

testing on liquid fuel shall not exceed a combined total of 48 

hours during any calendar year. 

 Opacity means the degree to which emissions reduce the 

transmission of light and obscure the view of an object in the 

background. 
Page 76 of 109

Operating day means a 24-hour period between 12 midnight 

and the following midnight during which any fuel is combusted at 

any time in the boiler unit. It is not necessary for fuel to be 

combusted for the entire 24-hour period. 

Oxygen analyzer system means all equipment required to 

determine the oxygen content of a gas stream and used to monitor 

oxygen in the boiler flue gas, boiler firebox, or other 

appropriate intermediate location. This definition includes 

oxygen trim systems. 

 Oxygen trim system means a system of monitors that is used 

to maintain excess air at the desired level in a combustion 

device over its operating load range. A typical system consists 

of a flue gas oxygen and/or carbon monoxide monitor that 

automatically provides a feedback signal to the combustion air 

controller or draft controller. 

 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 approved 

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 gas curtailment or supply interruption means a 
Page 77 of 109

period of time during which the supply of gaseous fuel to an 

affected boiler is restricted or 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 due to 

normal market fluctuations not during periods of supplier 

delivery restriction does not constitute a period of natural gas 

curtailment or supply interruption. On-site gaseous fuel system 

emergencies or equipment failures qualify as periods of supply 

interruption when the emergency or failure is beyond the control 

of the facility. 

 Process heater means an enclosed device using controlled 

flame, and the unit’s primary purpose is to transfer heat 

indirectly to a process material (liquid, gas, or solid) or to a 

heat transfer material (e.g., glycol or a mixture of glycol and 

water) for use in a process unit, instead of generating steam. 

Process heaters are devices in which the combustion gases do not 

come into direct contact with process materials. Process heaters 

include units that heat water/water mixtures for pool heating, 

sidewalk heating, cooling tower water heating, power washing, or 

oil heating. 

 Qualified Energy Assessor means: 
Page 78 of 109

 (1) Someone who has demonstrated capabilities to evaluate 

energy savings opportunities 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 feedwater 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. 

(vii) 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. 
Page 79 of 109

(vi) Industry specific steam end-use systems. 

Regulated gas stream means an offgas stream that is routed 

to a boiler for the purpose of achieving compliance with a 

standard under another subpart of this part or part 60, part 61, 

or part 65 of this chapter. 

Residential boiler means a boiler used to provide heat 

and/or hot water and/or as part of a residential combined heat 

and power system. This definition includes boilers located at an 

institutional facility (e.g., university campus, military base, 

church grounds) or commercial/industrial facility (e.g., farm) 

used primarily to provide heat and/or hot water for: 

(1) A dwelling containing four or fewer families, or 

(2) A single unit residence dwelling that has since been 

converted or subdivided into condominiums or apartments. 

Residual oil means crude oil, fuel oil that does not comply 

with the specifications under the definition of distillate oil, 

and all fuel oil numbers 4, 5, and 6, as defined by the American 

Society of Testing and Materials in ASTM D396–10 (incorporated 

by reference, see §63.14(b)). 

 Responsible official means responsible official as defined 

in §70.2. 

Seasonal boiler means a boiler that undergoes a shutdown 

for a period of at least 7 consecutive months (or 210 

consecutive days) each 12-month period due to seasonal 
Page 80 of 109

conditions, except for periodic testing. Periodic testing shall 

not exceed a combined total of 15 days during the 7-month 

shutdown. This definition only applies to boilers that would 

otherwise be included in the biomass subcategory or the oil 

subcategory. 

 Shutdown means the period in which cessation of operation 

of a boiler is initiated for any purpose. Shutdown begins when 

the boiler no longer makes useful thermal energy (such as either 

when none of the steam or heat hot water)from the boiler is 

supplied for heating, cooling, or process purposes and/or 

producinggenerates electricity, or for any other purpose, or at 

the point ofwhen no fuel is being firedfed toin the boiler, 

whichever is earlier. Shutdown ends when there isthe boiler no 

longer makes useful thermal energy (such as steam and noor hot 

waterheat) for heating, cooling, or process purposes or 

generates electricity, being supplied and no fuel is being 

combustedfired in the boiler. 

 Solid fossil fuel includes, but is not limited to, coal, 

coke, petroleum coke, and tire-derived fuel. 

Solid fuel means any solid fossil fuel or biomass or biobased solid fuel. 

Startup means:

(1) eEither the first-ever firing of fuel in a boiler for 

the purpose of supplying steam or heat for heating and/or 
Page 81 of 109

producing electricity, or for any other purpose, or the firing 

of fuel in a boiler after a shutdown event for any purpose. 

Startup ends when any of the steam or heat from the boiler is 

supplied for heating and/or producing electricity, or for any 

other purpose., or 

(2) The period in which operation of a boiler is initiated 

for any purpose. Startup begins with either the first-ever 

firing of fuel in a boiler for the purpose of supplying useful 

thermal energy (such as steam or hot water) for heating, cooling 

or process purposes, or producing electricity, or the firing of 

fuel in a boiler for any purpose after a shutdown event. Startup 

ends four hours after when the boiler makes useful thermal 

energy (such as steam or hot water) for heating, cooling, or 

process purposes, or generates electricity, whichever is 

earlier.

Temporary boiler means any gaseous or liquid fuel boiler 

that is designed to, and is capable of, being carried or moved 

from one location to another by means of, for example, wheels, 

skids, carrying handles, dollies, trailers, or platforms. A 

boiler is not a temporary boiler if any one of the following 

conditions exists: 

(1) The equipment is attached to a foundation. 

(2) The boiler or a replacement remains at a location 

within the facility and performs the same or similar function 
Page 82 of 109

for more than 12 consecutive months, unless the regulatory 

agency approves an extension. An extension may be granted by the 

regulating agency upon petition by the owner or operator of a 

unit specifying the basis for such a request. Any temporary 

boiler that replaces a temporary boiler at a location within the 

facility and performs the same or similar function will be 

included in calculating the consecutive time period unless there 

is a gap in operation of 12 months or more. 

(3) The equipment is located at a seasonal facility and 

operates during the full annual operating period of the seasonal 

facility, remains at the facility for at least 2 years, and 

operates at that facility for at least 3 months each year. 

(4) The equipment is moved from one location to another 

within the facility but continues to perform the same or similar 

function and serve the same electricity, steam, and/or hot water 

system in an attempt to circumvent the residence time 

requirements of this definition. 

Tune-up means adjustments made to a boiler in accordance 

with the procedures outlined in §63.11223(b). 

Useful thermal energy means energy (i.e., steam or hot 

water) that meets the minimum operating temperature and/or 

pressure required by any energy use system that uses energy 

provided by the affected boiler.

Vegetable oil means oils extracted from vegetation. 
Page 83 of 109

 Voluntary Consensus Standards (VCS) mean technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. EPA/Office of Air 

Quality Planning and Standards, by precedent, has only used VCS 

that are written in English. Examples of VCS bodies are: 

American Society of Testing and Materials (ASTM 100 Barr Harbor 

Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–

B2959, (800) 262–1373, http://www.astm.org), American Society of 

Mechanical Engineers (ASME ASME, Three Park Avenue, New York, NY 

10016–5990, (800) 843–2763, http://www.asme.org), International 

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), Standards Australia (AS Level 

10, The Exchange Centre, 20 Bridge Street, Sydney, GPO Box 476, 

Sydney NSW 2001, + 61 2 9237 6171 http://www.stadards.org.au), 

British Standards Institution (BSI, 389 Chiswick High Road, 

London, W4 4AL, United Kingdom, +44 (0)20 8996 9001, 

http://www.bsigroup.com), Canadian Standards Association (CSA 

5060 Spectrum Way, Suite 100, Mississauga, Ontario L4W 5N6, 

Canada, 800-463-6727, http://www.csa.ca), European Committee for 

Standardization (CEN CENELEC Management Centre Avenue Marnix 17 

B-1000 Brussels, Belgium +32 2 550 08 11, 

http://www.cen.eu/cen), and German Engineering Standards (VDI 
Page 84 of 109

VDI Guidelines Department, P.O. Box 10 11 39 40002, Duesseldorf, 

Germany, +49 211 6214-230, http://www.vdi.eu). The types of 

standards that are not considered VCS are standards developed 

by: the United States, e.g. , California (CARB) and Texas 

(TCEQ); industry groups, such as American Petroleum Institute 

(API), Gas Processors Association (GPA), and Gas Research 

Institute (GRI); and other branches of the U.S. government, 

e.g., Department of Defense (DOD) and Department of 

Transportation (DOT). This does not preclude EPA from using 

standards developed by groups that are not VCS bodies within 

their rule. When this occurs, EPA has done searches and reviews 

for VCS equivalent to these non-EPA methods. 

 Waste heat boiler means a device that recovers normally 

unused energy (i.e., hot exhaust gas) and converts it to usable 

heat. Waste heat boilers are also referred to as heat recovery 

steam generators. Waste heat boilers are heat exchangers 

generating steam from incoming hot exhaust gas from an 

industrial (e.g., thermal oxidizer, kiln, furnace) or power 

(e.g., combustion turbine, engine) equipment. Duct burners are 

sometimes used to increase the temperature of the incoming hot 

exhaust gas. 

 Wet scrubber means any add-on air pollution control device 

that mixes an aqueous stream or slurry with the exhaust gases 

from a boiler to control emissions of particulate matter or to 
Page 85 of 109

absorb and neutralize acid gases, such as hydrogen chloride. A 

wet scrubber creates an aqueous stream or slurry as a byproduct 

of the emissions control process. 

 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 

boilers with 

heat input 

capacity of 

30 million 

British 

thermal units 

per hour 

(MMBtu/hr) or 

greater that 

do not meet 

the 

definition of 

limited-use 

boiler

a. PM 

(filterable) 

3.0E-02 pounds (lb) per 

million British thermal 

units (MMBtu) of heat 

input. 

b. Mercury 2.2E-05 lb per MMBtu of 

heat input. 

c. CO 420 parts per million 

(ppm) by volume on a 

dry basis corrected to 

3 percent oxygen (3-run 

average or 10-day 

rolling average). 

2. New coal-fired 

boilers with 

heat input 

capacity of 

a. PM 

(filterable) 

4.2E-01 lb per MMBtu of 

heat input. 

b. Mercury 2.2E-05 lb per MMBtu of 

heat input. 
Page 86 of 109

between 10 

and 30 

MMBtu/hr that 

do not meet 

the 

definition of 

limited-use 

boiler 

c. CO 420 ppm by volume on a 

dry basis corrected to 

3 percent oxygen (3-run 

average or 10-day 

rolling average). 

3. New biomassfired boilers 

with heat 

input 

capacity of 

30 MMBtu/hr 

or greater 

that do not 

meet the 

definition of 

seasonal 

boiler or 

limited-use 

boiler 

a. PM 

(filterable) 

3.0E-02 lb per MMBtu of 

heat input. 

4. New biomass 

fired boilers 

with heat 

input 

capacity of 

between 10 

and 30 

MMBtu/hr that 

do not meet 

the 

definition of 

seasonal 

boiler or 

limited-use 

boiler 

a. PM 

(filterable) 

7.0E-02 lb per MMBtu of 

heat input. 
Page 87 of 109

5. New oil-fired 

boilers with 

heat input 

capacity of 

10 MMBtu/hr 

or greater 

that do not 

meet the 

definition of 

seasonal 

boiler or 

limited-use 

boiler 

a. PM 

(filterable) 

3.0E-02 lb per MMBtu of 

heat input. 

6. Existing coalfired boilers 

with heat 

input 

capacity of 

10 MMBtu/hr 

or greater 

that do not 

meet the 

definition of 

limited-use 

boiler 

a. Mercury 2.2E-05 lb per MMBtu of 

heat input. 

b. CO 420 ppm by volume on a 

dry basis corrected to 

3 percent oxygen (3-run 

average or 10-day 

rolling average). 

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-fired, new 

biomass-fired, or 

new oil-fired 

boilers (units with 

heat input capacity 

of 10 MMBtu/hr or 

greater) 

Minimize the boiler’s startup and 

shutdown periods and conduct 

startups and shutdowns according 

to 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 
Page 88 of 109

procedures are available. 

2. Existing coalfired boilers with 

heat input capacity 

of less than 10 

MMBtu/hr that do not 

meet the definition 

of limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio 

Conduct an initial tune-up as 

specified in §63.11214, and 

conduct a tune-up of the boiler 

biennially as specified in 

§63.11223. 

3. New coal-fired 

boilers with heat 

input capacity of 

less than 10 

MMBtu/hr that do not 

meet the definition 

of limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio 

Conduct a tune-up of the boiler 

biennially as specified in 

§63.11223. 

4. Existing oilfired boilers with 

heat input capacity 

greater than 5 

MMBtu/hr that do not 

meet the definition 

of seasonal boiler 

or limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio 

Conduct an initial tune-up as 

specified in §63.11214, and 

conduct a tune-up of the boiler 

biennially as specified in 

§63.11223. 

5. New oil-fired 

boilers with heat 

input capacity 

greater than 5 

MMBtu/hr that do not 

meet the definition 

of seasonal boiler 

or limited-use 

boiler, or use an 

Conduct a tune-up of the boiler 

biennially as specified in §63.11223. 
Page 89 of 109

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio 

6. Existing biomassfired boilers that 

do not meet the 

definition of 

seasonal boiler or 

limited-use boiler, 

or use an oxygen 

trim system that 

maintains an optimum 

air-to-fuel ratio 

Conduct an initial tune-up as 

specified in §63.11214, and conduct a 

tune-up of the boiler biennially as 

specified in §63.11223. 

7. New biomass-fired 

boilers that do not 

meet the definition 

of seasonal boiler 

or limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio 

Conduct a tune-up of the boiler 

biennially as specified in §63.11223. 

8. Existing seasonal 

boilers 

Conduct an initial tune-up as 

specified in §63.11214, and conduct a 

tune-up of the boiler every 5 years 

as specified in §63.11223. 

9. New seasonal 

boilers 

Conduct a tune-up of the boiler every 

5 years as specified in §63.11223. 

10. Existing 

limited-use boilers 

Conduct an initial tune-up as 

specified in §63.11214, and conduct a 

tune-up of the boiler every 5 years 

as specified in §63.11223. 

11. New limited-use 

boilers 

Conduct a tune-up of the boiler every 

5 years as specified in §63.11223. 

12. Existing oilfired boilers with 

heat input capacity 

of equal to or less 

than 5 MMBtu/hr 

Conduct an initial tune-up as 

specified in §63.11214, and conduct a 

tune-up of the boiler every 5 years 

as specified in §63.11223. 

13. New oil-fired 

boilers with heat 

input capacity of 

equal to or less 

than 5 MMBtu/hr 

Conduct a tune-up of the boiler every 

5 years as specified in §63.11223. 

14. Existing coal- Conduct an initial tune-up as 
Page 90 of 109

fired, biomassfired, or oil-fired 

boilers with an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio that would 

otherwise be subject 

to a biennial tuneup 

specified in §63.11214, and conduct a 

tune-up of the boiler every 5 years 

as specified in §63.11223. 

15. New coal-fired, 

biomass-fired, or 

oil-fired boilers 

with an oxygen trim 

system that 

maintains an optimum 

air-to-fuel ratio 

that would otherwise 

be subject to a 

biennial tune-up 

Conduct a tune-up of the boiler every 

5 years as specified in §63.11223. 

16. Existing coalfired, biomassfired, or oil-fired 

boilers (units with 

heat input capacity 

of 10 MMBtu/hr and 

greater), not 

including limiteduse boilers 

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.

Energy assessor approval 

and qualification requirements are 

waived in instances where past or 

amended energy assessments are used 

to meet the energy 

assessment requirements. A facility 

that operateds under an energy 

management program developed 

according to the ENERGY STAR 

guidelines for energy management or 

compatible with ISO 50001 for at 

least one year between January 1, 

2008, and the compliance date 

specified in §63.11196 that includes 

the affected units also satisfies the 

energy assessment requirement. The 

energy assessment must include the 

following with extent of the 

evaluation for items (1) to (4) 
Page 91 of 109

appropriate for the on-site technical 

hours listed in §63.11237: 

 (1) A visual inspection of the 

boiler system, 

 (2) An evaluation of operating 

characteristics of the affected 

boiler systems, specifications of 

energy use systems, operating and 

maintenance procedures, and unusual 

operating constraints, 

 (3) An inventory of major energy 

use systems consuming energy from 

affected boiler(s) and which are 

under control of the boiler owner or 

operator, 

 (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 that are within 

the facility’s control, 

 (6) A list of the energy savings 

potential of the energy conservation 

measures identified, and 

 (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 except during periods of 

startup and shutdown...

1. Fabric filter 

control 

a. Maintain opacity to less than 

or equal to 10 percent opacity 
Page 92 of 109

(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 30-day rolling 

average total secondary electric 

power of the electrostatic 

precipitator at or above the 

minimum total secondary electric 

power as defined in §63.11237. 

3. Wet scrubber control Maintain the 30-day rolling 

average pressure drop across the 

wet scrubber at or above the 

minimum scrubber pressure drop as 

defined in §63.11237 and the 30-

day rolling average liquid flow 

rate at or above the minimum 

scrubber liquid flow rate as 

defined in §63.11237. 

4. Dry sorbent or 

activated carbon 

injection control 

Maintain the 30-day rolling 

average sorbent or activated 

carbon injection rate at or above 

the minimum sorbent injection rate

or minimum activated carbon 

injection rate as defined in 

§63.11237. When your boiler 

operates at lower loads, multiply 

your sorbent or activated carbon 

injection rate by the load 

fraction (e.g., actual heat input 

divided by the heat input during 

the performance stack test,; for 

50 percent load, multiply the 

injection rate operating limit by 

0.5). 
Page 93 of 109

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(c) are 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 it 

does not exceed 110 percent of the 

average operating load recorded 

during the most recent performance 

stack test. 

8. Oxygen analyzer 

system 

For boilers subject to a CO 

emission limit that demonstrate 

compliance with an oxygen analyzer 

system as specified in 

§63.11224(a), maintain the 30-day 

rolling average oxygen level at or 

above the minimum oxygen level as 

defined in §63.11237. This 

requirement does not apply to 

units that install an oxygen trim 

system since these units will set 

the trim system to the level 

specified in §63.11224(a)(7). 

 

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...
Page 94 of 109

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 flowrate 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 

19.10-1981a. 

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 A6 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 flowrate of the stack gas. 

Method 2, 2F, or 2G 

in appendix A-2 to 

part 60 of this 

chapter. 
Page 95 of 109

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 

19.10-1981a. 

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 D6784-02a. 

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 

19.10-1981a. 
Page 96 of 109

c. Measure the moisture 

content of the stack 

gas. 

Method 4 in 

appendix A-3 to 

part 60 of this 

chapter. 

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/D2234Ma (for coal) 

or ASTM D6323a (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/D2013Ma (for coal) 

or ASTM D5198a (for 

biomass) or equivalent. 
Page 97 of 109

d. Determine heat 

content of the 

fuel type. 

ASTM D5865a (for coal) 

or ASTM E711a (for 

biomass) or equivalent. 

e. Determine 

moisture 

content of the 

fuel type. 

ASTM D3173a or ASTM 

E871a or equivalent. 

f. Measure mercury 

concentration 

in fuel sample. 

ASTM D6722a (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: 
Page 98 of 109

If you have 

an 

applicable 

emission 

limit for 

. . . 

And your 

operating 

limits are 

based on 

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

According to the 

following 

requirements 

1. PM or 

mercury 

a. Wet 

scrubber 

operating 

parameters. 

Establish 

site-specific 

minimum 

scrubber 

pressure drop 

and minimum 

scrubber 

liquid flow 

rate 

operating 

limits 

according to 

§63.11211(b).

Data from the 

pressure drop 

and liquid 

flow rate 

monitors and 

the PM or 

mercury 

performance 

stack tests. 

(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 

three-run 

performance 

stack test by 

computing the 

average of all 

the 15-minute 

readings taken 

during each test 

run. 

 b. 

Electrostatic 

precipitator 

operating 

parameters. 

Establish a 

site-specific 

minimum total 

secondary 

electric 

power 

operating 

limit 

according to 

§63.11211(b).

Data from the 

secondary 

electric 

power 

monitors and 

the PM or 

mercury 

performance 

stack tests. 

(a) You must 

collect 

secondary 

electric power 

data every 15 

minutes during 

the entire 

period of the 

performance 

stack tests; 
Page 99 of 109

If you have 

an 

applicable 

emission 

limit for 

. . . 

And your 

operating 

limits are 

based on 

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

According to the 

following 

requirements 

 (b) Determine 

the average 

total secondary 

electric power 

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. 

2. Mercury Dry sorbent 

or activated 

carbon 

injection 

rate 

operating 

parameters. 

Establish a 

site-specific 

minimum 

sorbent or 

activated 

carbon 

injection 

rate 

operating 

limit 

according to 

§63.11211(b).

Data from the 

sorbent or 

activated 

carbon 

injection 

rate monitors 

and the 

mercury 

performance 

stack tests. 

(a) You must 

collect sorbent 

or activated 

carbon injection 

rate data every 

15 minutes 

during the 

entire period of 

the performance 

stack tests; 
Page 100 of 109

If you have 

an 

applicable 

emission 

limit for 

. . . 

And your 

operating 

limits are 

based on 

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

According to the 

following 

requirements 

 (b) Determine 

the average 

sorbent or 

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. 
Page 101 of 109

If you have 

an 

applicable 

emission 

limit for 

. . . 

And your 

operating 

limits are 

based on 

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

According to the 

following 

requirements 

 (c) When your 

unit operates at 

lower loads, 

multiply your 

sorbent or 

activated carbon 

injection rate 

by the load 

fraction, as 

defined in 

§63.11237,(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. CO Oxygen. Establish a 

unit-specific 

limit for 

minimum 

oxygen level.

Data from the 

oxygen 

analyzer 

system 

specified in 

§63.11224(a). 

(a) You must 

collect oxygen 

data every 15 

minutes during 

the entire 

period of the 

performance 

stack tests; 
Page 102 of 109

If you have 

an 

applicable 

emission 

limit for 

. . . 

And your 

operating 

limits are 

based on 

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

According to the 

following 

requirements 

 (b) Determine 

the average 

hourly 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. 

4. Any 

pollutant 

for which 

compliance 

is 

demonstrated 

by a 

performance 

stack test. 

Boiler 

operating 

load. 

Establish a 

unit-specific

limit for 

maximum 

operating 

load 

according to 

§63.11212(c).

Data from the 

operating 

load monitors 

(fuel feed 

monitors or 

steam 

generation 

monitors). 

(a) You must 

collect 

operating 

load data (fuel 

feed rate or 

steam generation

data) every 15 

minutes during 

the entire 

period of the 

performance 

test. 

(b) Determine 

the average 

operating load 

by computing 

the hourly 

averages using 

all of the 15-

minute readings 

taken during 

each performance 

test. 
Page 103 of 109

If you have 

an 

applicable 

emission 

limit for 

. . . 

And your 

operating 

limits are 

based on 

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

According to the 

following 

requirements 

(c) Determine 

the average 

of the three 

test run 

averages during 

the performance 

test, and 

multiply 

this by 1.1 (110

percent) as your 

operating limit.

Table 7 to Subpart JJJJJJ 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(f) 

and operating the fabric filter such that 

the requirements in §63.11222(a)(4) are met.
Page 104 of 109

If you must meet 

the following 

operating limits . 

. . 

You must demonstrate continuous compliance 

by . . . 

3. Wet Scrubber 

Pressure Drop and 

Liquid Flow Rate 

 

 

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 30-day rolling 

averages; and 

c. Maintaining the 30-day rolling average 

pressure drop and liquid flow rate at or 

above the minimum pressure drop and minimum 

liquid flow rate according to §63.11211. 

4. Dry Scrubber 

Sorbent or 

Activated Carbon 

Injection Rate 

 

 

a. Collecting the sorbent or activated 

carbon injection rate monitoring system data 

for the dry scrubber according to §§63.11224

and 63.11221; and 

b. Reducing the data to 30-day rolling 

averages; and 

c. Maintaining the 30-day rolling average 

sorbent or activated carbon injection rate 

at or above the minimum sorbent or activated 

carbon injection rate according to 

§63.11211. 

5. Electrostatic 

Precipitator Total 

Secondary Electric 

Power 

 

 

a. Collecting the total secondary electric 

power monitoring system data for the 

electrostatic precipitator according to 

§§63.11224 and 63.11221; and 

b. Reducing the data to 30-day rolling 

averages; and 

c. Maintaining the 30-day rolling average 

total secondary electric power at or above 

the minimum total secondary electric power 

according to §63.11211. 

6. Fuel Pollutant 

Content 

 

a. Only burning the fuel types and fuel 

mixtures used to demonstrate compliance with 

the applicable emission limit according to 

§63.11213 as applicable; and 

b. Keeping monthly records of fuel use 

according to §§63.11222(a)(2) and 
Page 105 of 109

If you must meet 

the following 

operating limits . 

. . 

You must demonstrate continuous compliance 

by . . . 

63.11225(b)(4). 

7. Oxygen content a. Continuously monitoring the oxygen 

content of flue gas according to §63.11224 

(This requirement does not apply to units 

that install an oxygen trim system since 

these units will set the trim system to the 

level specified in §63.11224(a)(7); and 

b. Reducing the data to 30-day rolling 

averages; and 

c. Maintaining the 30-day rolling average 

oxygen content at or above the minimum 

oxygen level established during the most 

recent CO performance test. 

8. CO emissions a. Continuously monitoring the CO 

concentration in the combustion exhaust 

according to §§63.11224 and 63.11221; and 

b. Correcting the data to 3 percent oxygen, 

and reducing the data to 1-hour averages; 

and 

c. Reducing the data from the hourly 

averages to 10-day rolling averages; and 

d. Maintaining the 10-day rolling average CO 

concentration at or below the applicable 

emission limit in Table 1 to this subpart. 

9. Boiler operating 

load 

a. Collecting operating load data (fuel feed 

rate or steam generation data) every 15 

minutes; and 

 b. Reducing the data to 30-day rolling 

averages; and 

 c. Maintaining the 30-day rolling average at 

or below the operating limit established 

during the performance test according to 

§63.11212(c) and Table 6 to this subpart. 

Table 8 to Subpart JJJJJJ of Part 63 — Applicability of 
Page 106 of 109

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. 
Page 107 of 109

§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, excluding the 

information required in 

§63.9(h)(2)(i)(B), (D), (E) 

and (F). See §63.11225. 

§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. 
Page 108 of 109

§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. 
Page 109 of 109

§63.10(e) Additional 

reporting 

requirements for 

sources with CMS 

Yes. 

§63.10(f) Waiver of 

recordkeeping or 

reporting 

requirements 

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.