15608 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2002–0058; FRL–9272–8] 

RIN 2060–AQ25 

National Emission Standards for 

Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: On September 13, 2004, 

under authority of section 112 of the 

Clean Air Act, EPA promulgated 

national emission standards for 

hazardous air pollutants for new and 

existing industrial/commercial/ 

institutional boilers and process heaters. 

On June 19, 2007, the United States 

Court of Appeals for the District of 

Columbia Circuit vacated and remanded 

the standards. 

In response to the Court’s vacatur and 

remand, EPA is, in this action, 

establishing emission standards that 

will require industrial/commercial/ 

institutional boilers and process heaters 

located at major sources to meet 

hazardous air pollutants standards 

reflecting the application of the 

maximum achievable control 

technology. This rule protects air 

quality and promotes public health by 

reducing emissions of the hazardous air 

pollutants listed in section 112(b)(1) of 

the Clean Air Act. 

DATES: This final rule is effective on 

May 20, 2011. The incorporation by 

reference of certain publications listed 

in this rule is approved by the Director 

of the Federal Register as of May 20, 

2011. 

ADDRESSES: EPA established a single 

docket under Docket ID No. EPA–HQ– 

OAR–2002–0058 for this action. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through http:// 

www.regulations.gov or in hard copy at 

EPA’s Docket Center, Public Reading 

Room, EPA West Building, Room 3334, 

1301 Constitution Avenue, NW., 

Washington, DC 20004. This Docket 

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

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1741. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Brian Shrager, Energy Strategies Group, 

Sector Policies and Programs Division, 

(D243–01), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; Telephone number: (919) 541– 

7689; Fax number (919) 541–5450; Email address: shrager.brian@epa.gov. 

SUPPLEMENTARY INFORMATION: The 

information presented in this preamble 

is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this 

document? 

C. Judicial Review 

II. Background Information 

A. What is the statutory authority for this 

final rule? 

B. EPA’s Response to the Vacatur 

C. What is the relationship between this 

final rule and other combustion rules? 

D. What are the health effects of pollutants 

emitted from industrial/commercial/ 

institutional boilers and process heaters? 

E. What are the costs and benefits of this 

final rule? 

III. Summary of this Final Rule 

A. What is the source category regulated by 

this final rule? 

B. What is the affected source? 

C. What are the pollutants regulated by this 

final rule? 

D. What emission limits and work practice 

standards must I meet? 

E. What are the requirements during 

periods of startup, shutdown, and 

malfunction? 

F. What are the testing and initial 

compliance requirements? 

G. What are the continuous compliance 

requirements? 

H. What are the notification, recordkeeping 

and reporting requirements? 

I. Submission of Emissions Test Results to 

EPA 

IV. Summary of Significant Changes Since 

Proposal 

A. Applicability 

B. Subcategories 

C. Emission Limits 

D. Work Practices 

E. Energy Assessment Requirements 

F. Requirements During Startup, 

Shutdown, and Malfunction 

G. Testing and Initial Compliance 

H. Continuous Compliance 

I. Notification, Recordkeeping and 

Reporting 

J. Technical/Editorial Corrections 

K. Other 

V. Major Source Public Comments and 

Responses 

A. MACT Floor Analysis 

B. Beyond the Floor 

C. Rationale for Subcategories 

D. Work Practices 

E. New Data/Technical Corrections to Old 

Data 

F. Startup, Shutdown, and Malfunction 

Requirements 

G. Health Based Compliance Alternatives 

H. Biased Data Collection From Phase II 

Information Collection Request Testing 

I. Issues Related to Carbon Monoxide 

Emission Limits 

J. Cost Issues 

K. Non-Hazardous Secondary Materials 

VI. Impacts of This Final Rule 

A. What are the air impacts? 

B. What are the water and solid waste 

impacts? 

C. What are the energy impacts? 

D. What are the cost impacts? 

E. What are the economic impacts? 

F. What are the benefits of this final rule? 

G. What are the secondary air impacts? 

VII. Relationship of Final Action to Section 

112(c)(6) of the Clean Air Act 

VIII. Statutory and Executive Order Reviews 

A. Executive Orders 12866 and 13563: 

Regulatory Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act as Amended 

by the Small Business Regulatory 

Enforcement Fairness Act of 1996, 5 

U.S.C. 601 et seq. 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by the final 

standards include: 

Category NAICS code 1 Examples of potentially regulated entities 

Any industry using a boiler or process heater as defined in the 

final rule.

211 ................... Extractors of crude petroleum and natural gas. 


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Category NAICS code 1 Examples of potentially regulated entities 

321 ................... Manufacturers of lumber and wood products. 

322 ................... Pulp and paper mills. 

325 ................... Chemical manufacturers. 

324 ................... Petroleum refineries, and manufacturers of coal products. 

316, 326, 339 ... Manufacturers of rubber and miscellaneous plastic products. 

331 ................... Steel works, blast furnaces. 

332 ................... Electroplating, plating, polishing, anodizing, and coloring. 

336 ................... Manufacturers of motor vehicle parts and accessories. 

221 ................... Electric, gas, and sanitary services. 

622 ................... Health services. 

611 ................... Educational services. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

affected by this action. To determine 

whether your facility, company, 

business, organization, etc., would be 

regulated by this action, you should 

examine the applicability criteria in 40 

CFR 63.7485 of subpart DDDDD 

(National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for 

Industrial, Commercial, and Institution 

Boilers and Process Heaters). If you have 

any questions regarding the 

applicability of this action to a 

particular entity, consult either the air 

permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 63.13 of subpart A 

(General Provisions). 

B. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this action 

will also be available on the Worldwide 

Web (WWW) through the Technology 

Transfer Network (TTN). Following 

signature, a copy of the action will be 

posted on the TTN’s policy and 

guidance page for newly proposed or 

promulgated rules at the following 

address: http://www.epa.gov/ttn/oarpg/. 

The TTN provides information and 

technology exchange in various areas of 

air pollution control. 

C. Judicial Review 

Under the Clean Air Act (CAA) 

section 307(b)(1), judicial review of this 

final rule is available only by filing a 

petition for review in the U.S. Court of 

Appeals for the District of Columbia 

Circuit by May 20, 2011. Under CAA 

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

to this final rule that was raised with 

reasonable specificity during the period 

for public comment can be raised during 

judicial review. This section also 

provides a mechanism for us to convene 

a proceeding for reconsideration, ‘‘[i]f 

the person raising an objection can 

demonstrate to EPA that it was 

impracticable to raise such objection 

within [the period for public comment] 

or if the grounds for such objection 

arose after the period for public 

comment (but within the time specified 

for judicial review) and if such objection 

is of central relevance to the outcome of 

this rule.’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, 

Environmental Protection Agency, 

Room 3000, Ariel Rios Building, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004, with a copy to the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

II. Background Information 

A. What is the statutory authority for 

this final rule? 

Section 112(d) of the CAA requires 

EPA to set emissions standards for 

hazardous air pollutants (HAP) emitted 

by major stationary sources based on the 

performance of the maximum 

achievable control technology (MACT). 

The MACT standards for existing 

sources must be at least as stringent as 

the average emissions limitation 

achieved by the best performing 12 

percent of existing sources (for which 

the Administrator has emissions 

information) or the best performing 5 

sources for source categories with less 

than 30 sources (CAA section 

112(d)(3)(A) and (B)). This level of 

minimum stringency is called the 

MACT floor. For new sources, MACT 

standards must be at least as stringent 

as the control level achieved in practice 

by the best controlled similar source 

(CAA section 112(d)(3)). EPA also must 

consider more stringent ‘‘beyond-thefloor’’ control options. When 

considering beyond-the-floor options, 

EPA must consider not only the 

maximum degree of reduction in 

emissions of HAP, but must take into 

account costs, energy, and nonair 

environmental impacts when doing so. 

With respect to alkylated lead 

compounds; polycyclic organic matter 

(POM); hexachlorobenzene; mercury 

(Hg); polychlorinated biphenyls; 2,3,7,8- 

tetrachlorodibenzofurans; and 2,3,7,8- 

tetrachlorodibenzo-p-dioxin, the CAA 

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

categories and subcategories of sources 

assuring that sources accounting for not 

less than 90 percent of the aggregate 

emissions of each such pollutant are 

subject to standards under subsection 

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

established under CAA section 112(d)(2) 

must reflect the performance of MACT. 

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ ‘‘Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion,’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ are listed as source 

categories for regulation pursuant to 

CAA section 112(c)(6) due to emissions 

of POM and Hg (63 FR 17838, 17848, 

April 10, 1998). In the documentation 

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

fuel combustion categories included 

institutional fuel combustion (‘‘1990 

Emissions Inventory of Section 112(c)(6) 

Pollutants, Final Report,’’ April 1998). 

CAA section 129(a)(1)(A) requires 

EPA to establish specific performance 

standards, including emission 

limitations, for ‘‘solid waste incineration 

units’’ generally, and, in particular, for 

‘‘solid waste incineration units 

combusting commercial or industrial 

waste’’ (section 129(a)(1)(D)). Section 

129 defines ‘‘solid waste incineration 

unit’’ as ‘‘a distinct operating unit of any 

facility which combusts any solid waste 

material from commercial or industrial 

establishments or the general public.’’ 


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15610 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

Section 129(g)(1). Section 129 also 

provides that ‘‘solid waste’’ shall have 

the meaning established by EPA 

pursuant to its authority under the 

Resource Conservation and Recovery 

Act. Section 129(g)(6). 

In Natural Resources Defense Council 

v. EPA, 489 F. 3d 1250, 1257–61 (D.C. 

Cir. 2007), the court vacated the 

Commercial and Industrial Solid Waste 

Incineration (CISWI) Definitions Rule, 

70 FR 55568 (September 22, 2005), 

which EPA issued pursuant to CAA 

section 129(a)(1)(D). In that rule, EPA 

defined the term ‘‘commercial or 

industrial solid waste incineration unit’’ 

to mean a combustion unit that 

combusts ‘‘commercial or industrial 

waste.’’ The CISWI definitions rule 

defined ‘‘commercial or industrial 

waste’’ to mean waste combusted at a 

unit that does not recover thermal 

energy from the combustion for a useful 

purpose. Under these definitions, only 

those units that combusted commercial 

or industrial waste and were not 

designed to, or did not operate to, 

recover thermal energy from the 

combustion would be subject to section 

129 standards. The District of Columbia 

Circuit (DC Circuit) rejected the 

definitions contained in the CISWI 

Definitions Rule and interpreted the 

term ‘‘solid waste incineration unit’’ in 

CAA section 129(g)(1) ‘‘to 

unambiguously include among the 

incineration units subject to its 

standards any facility that combusts any 

commercial or industrial solid waste 

material at all—subject to the four 

statutory exceptions identified in [CAA 

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

F.3d 1250, 1257–58. A more detailed 

discussion of this decision, as well as 

other court decisions relevant to today’s 

action, can be found in the June 4, 2010, 

preamble to the proposed rule. See 75 

FR 32009. 

CAA section 129 covers any facility 

that combusts any solid waste; CAA 

section 129(g)(6) directs the Agency to 

the Resource Conservation and 

Recovery Act (RCRA) in terms of the 

definition of solid waste. In this Federal 

Register, EPA is issuing a definition of 

solid waste for purposes of Subtitle D of 

RCRA. If a unit combusts solid waste, it 

is subject to CAA section 129 of the Act, 

unless it falls within one of the four 

specified exceptions in CAA section 

129(g). 

The solid waste definitional 

rulemaking under RCRA is being 

finalized in a parallel action and is 

relevant to this proceeding because 

some industrial, commercial, or 

institutional boilers and process heaters 

combust secondary materials as 

alternative fuels. If industrial, 

commercial, or institutional boilers or 

process heaters combust secondary 

materials that are solid waste under the 

final definitional rule, those units 

would be subject to emission standards 

issued under section 129. The units 

subject to this final rule include those 

industrial, commercial, or institutional 

boilers and process heaters that do not 

combust solid waste, as well as boilers 

and process heaters that combust solid 

waste but qualify for one of the statutory 

exclusions contained in section 

129(g)(1). EPA recognizes that it has 

imperfect information on the exact 

nature of the secondary materials which 

boilers and process heaters combust, 

including, for example, how much 

processing of such materials occurs, if 

any. We used the information currently 

available to the Agency to determine 

which units combust solid waste 

materials and, therefore, are subject to 

CAA section 129, and which units do 

not combust solid waste (or qualify for 

an exclusion from section 129) and, 

therefore, are subject to CAA section 

112. 

B. EPA’s Response to the Vacatur 

A description of EPA’s information 

collection efforts and a description of 

the development of EPA’s proposed 

response to the NRDC v. EPA mandate 

is contained in the preamble to the 

proposed rule. See 75 FR 32010–32011. 

After consideration of public comments 

on the proposed rule, we have made 

appropriate revisions to the final rule, 

and a description of the major changes 

is provided in this preamble. The 

changes reflect EPA’s consideration of 

public comments and the consideration 

of additional information and emissions 

data provided through the public 

comment process. The changes also 

reflect adjustments to the definition of 

non-hazardous solid waste as set forth 

in a parallel final action. That final rule 

contains some revisions to the 

definition of non-hazardous solid waste 

proposed by EPA in June 2010. 

Accordingly, the population of 

combustion units subject to CAA 

section 129 (because they combust solid 

waste) and the population of boilers and 

process heaters subject to CAA section 

112 (because they do not combust solid 

waste) were established considering the 

final solid waste definition issued 

today. We used the updated inventories 

and all available data, as appropriate, to 

develop the final standards for boilers 

and process heaters under CAA section 

112 and, in a separate parallel action, 

the final standards for commercial and 

industrial solid waste incineration units 

covered by CAA section 129. We used 

all of the appropriate information 

available to the Administrator to 

calculate the MACT floors, set emission 

limits, and evaluate the emission 

impacts of various regulatory options for 

these final rulemakings. 

C. What is the relationship between this 

final rule and other combustion rules? 

This final rule addresses the 

combustion of non-solid waste materials 

in boilers and process heaters located at 

major sources of HAP. If an owner or 

operator of an affected source subject to 

these standards were to start combusting 

a solid waste (as defined by the 

Administrator under RCRA), the 

affected source would cease to be 

subject to this action and would instead 

be subject to regulation under CAA 

section 129. A rulemaking under CAA 

section 129 is being finalized in a 

parallel action and is relevant to this 

action because it would apply to boilers 

and process heaters that combust any 

solid waste and are located at a major 

source. In this final boiler rulemaking, 

EPA is providing specific language to 

ensure clarity regarding the necessary 

steps that must be followed for 

combustion units that begin combusting 

non-hazardous solid waste materials 

and become subject to section 129 

standards instead of section 112 

standards or combustion units that 

discontinue combustion of nonhazardous solid waste materials and 

become subject to section 112 standards 

instead of section 129 standards. 

In addition to combustion units that 

may switch between the section 112 

boiler standards and the section 129 

incinerator standards, there are certain 

instances where boilers and process 

heaters are already regulated under 

other MACT standards. In such cases, 

the boilers and process heaters that are 

already subject to another MACT 

standard are not subject to the boiler 

standards. 

In 1986, EPA codified new source 

performance standards (NSPS) for 

industrial boilers (40 CFR part 60, 

subparts Db and Dc) and portions of 

those standards were revised in 1999 

and 2006. The NSPS regulates emissions 

of particulate matter (PM), sulfur 

dioxide (SO2), and nitrogen oxide (NOX) 

from boilers constructed after June 19, 

1984. Sources subject to the NSPS will 

also be subject to the final CAA section 

112(d) standards for boilers and process 

heaters because the section 112(d) 

standards regulate HAP emissions while 

the NSPS do not. However, in 

developing this final rule, we 

considered the monitoring 

requirements, testing requirements, and 

recordkeeping requirements of the NSPS 

to avoid duplicating requirements. 


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1See Memorandum ‘‘Methodology for Estimating 

Impacts from Industrial, Commercial, Institutional 

Boilers and Process Heaters at Major Sources of Hazardous Air Pollutant Emissions’’ located in the 

docket. 

D. What are the health effects of 

pollutants emitted from industrial/ 

commercial/institutional boilers and 

process heaters? 

This final rule protects air quality and 

promotes the public health by reducing 

emissions of some of the HAP listed in 

CAA section 112(b)(1). As noted above, 

emissions data collected during 

development of the rule show that 

hydrogen chloride (HCl) emissions 

represent the predominant HAP emitted 

by industrial, commercial, and 

institutional (ICI) boilers, accounting for 

69 percent of the total HAP emissions.1

ICI boilers and process heaters also emit 

lesser amounts of hydrogen fluoride, 

accounting for about 21 percent of total 

HAP emissions, and metals (arsenic, 

beryllium, cadmium, chromium, cobalt, 

lead, manganese (Mn), Hg, nickel, and 

selenium) accounting for about 6 

percent of total HAP emissions. Organic 

HAP (formaldehyde, POM, 

acetaldehyde, benzene) account for 

about 4 percent of total HAP emissions. 

Exposure to these HAP, depending on 

exposure duration and levels of 

exposures, can be associated with a 

variety of adverse health effects. These 

adverse health effects may include, for 

example, irritation of the lung, skin, and 

mucus membranes, effects on the 

central nervous system, damage to the 

kidneys, and alimentary effects such as 

nausea and vomiting. We have classified 

two of the HAP as human carcinogens 

(arsenic and chromium VI) and four as 

probable human carcinogens (cadmium, 

lead, dioxins/furans, and nickel). We do 

not know the extent to which the 

adverse health effects described above 

occur in the populations surrounding 

these facilities. However, to the extent 

the adverse effects do occur, this final 

rule would reduce emissions and 

subsequent exposures. 

E. What are the costs and benefits of this 

final rule? 

EPA estimated the costs and benefits 

associated with the final rule, and the 

results are shown in the following table. 

For more information on the costs and 

benefits for this rule, see the Regulatory 

Impact Analysis (RIA). 

SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER MACT IN 2014 

[Millions of 2008$] 

3% Discount rate 7% Discount rate 

Selected 

Total Monetized Benefits 2 .................................................... $22,000 to $54,000 .............................................................. $20,000 to $49,000 

Total Social Costs 3 ............................................................... $1,500 .................................................................................. $1,500 

Net Benefits ........................................................................... $20,500 to $52,500 .............................................................. $18,500 to $47,500 

Non-monetized Benefits ........................................................ 112,000 tons of CO, 30,000 tons of HCl, 820 tons of HF, 

2,800 pounds of Hg.

2,700 tons of other metals, 23 grams of dioxins/furans 

(TEQ), Health effects from SO2 exposure, Ecosystem 

effects, Visibility impairment.

Alternative 

Total Monetized Benefits 2 .................................................... $18,000 to $43,000 .............................................................. $16,000 to $39,000 

Total Social Costs 3 ............................................................... $1,900 .................................................................................. $1,900 

Net Benefits ........................................................................... $16,100 to $41,100 .............................................................. $14,100 to $37,100 

Non-monetized Benefits ........................................................ 112,000 tons of CO, 22,000 tons of HCl, 620 tons of HF, 

2,400 pounds of Hg, 2,600 tons of other metals, 23 

grams of dioxins/furans (TEQ), Health effects from SO2

exposure, Ecosystem effects, Visibility impairment.

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

come online and the lowest cost disposal assumption. 2The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of directly emitted PM2.5 and PM2.5 precursors such as SO2, as well as reducing exposure to ozone through reductions of VOCs. It is important to note that the 

monetized benefits include many but not all health effects associated with PM2.5 exposure. Benefits are shown as a range from Pope et al. 

(2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type. These estimates include energy disbenefits valued at $23 million for the selected option and $35 million for the alternative option. 

Ozone benefits are valued at $3.6 to $15 million for both options. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 

III. Summary of This Final Rule 

This section summarizes the 

requirements of this action. Section IV 

below provides a summary of the 

significant changes to this final rule 

following proposal. 

A. What is the source category regulated 

by this final rule? 

ICI boilers and process heaters located 

at major sources of HAP are regulated by 

this final rule. Waste heat boilers and 

boilers and process heaters that combust 

solid waste, except for specific 

exceptions to the definition of a solid 

waste incineration unit outlined in 

section 129(g)(1), are not subject to this 

final rule. 

B. What is the affected source? 

This final rule affects industrial 

boilers, institutional boilers, commercial 

boilers, and process heaters. A process 

heater is defined as a unit in which the 

combustion gases do not directly come 

into contact with process material or 

gases in the combustion chamber (e.g., 

indirect fired). A boiler is defined as an 

enclosed device using controlled flame 

combustion and having the primary 

purpose of recovering thermal energy in 

the form of steam or hot water. 


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2Heat input means heat derived from combustion 

of fuel in a boiler or process heater and does not 

include the heat derived from preheated 

combustion air, recirculated flue gases or exhaust 

from other sources (such as stationary gas turbines, 

internal combustion engines, and kilns). 

C. What are the pollutants regulated by 

this final rule? 

This final rule regulates HCl (as a 

surrogate for acid gas HAP), PM (as a 

surrogate for non-Hg HAP metals), 

carbon monoxide (CO) (as a surrogate 

for non-dioxin/furan organic HAP), Hg, 

and dioxin/furan emissions from boilers 

and process heaters. 

D. What emission limits and work 

practice standards must I meet? 

You must meet the emission limits 

presented in Table 1 of this preamble. 

This final rule includes 15 

subcategories. Emission limits are 

established for new and existing sources 

for each of the subcategories, which are 

based on unit design. 

Metallic HAP (regulated using PM as 

a surrogate), HCl, and Hg are ‘‘fuel-based 

pollutants’’ that are a direct result of 

contaminants in the fuels that are 

combusted. For those pollutants, if your 

new or existing unit combusts at least 

10 percent solid fuel on an annual basis, 

your unit is subject to emission limits 

that are based on data from all of the 

solid fuel-fired combustor designs. If 

your new or existing unit combusts at 

least 10 percent liquid fuel and less than 

10 percent solid fuel and your facility is 

located in the continental United States, 

your unit is subject to the liquid fuel 

emission limits for the fuel-based 

pollutants. If your facility is located 

outside of North America (referred to as 

a non-continental unit for the remainder 

of the preamble and in this final rule) 

and your new or existing unit combusts 

at least 10 percent liquid fuel and less 

than 10 percent solid fuel, your unit is 

subject to the non-continental liquid 

fuel emission limits for the fuel-based 

pollutants. Finally, for the fuel-based 

pollutants, if your unit combusts 

gaseous fuel that does not qualify as a 

‘‘Gas 1’’ fuel, your unit is subject to the 

Gas 2 emission limits in Table 1 of this 

preamble. If your unit is a Gas 1 unit 

(that is, it combusts only natural gas, 

refinery gas, or equivalent fuel (other 

gas that qualifies as Gas 1 fuel)), with 

limited exceptions for gas curtailments 

and emergencies, your unit is subject to 

a work practice standard that requires 

an annual tune-up in lieu of emission 

limits. 

For the combustion-based pollutants, 

CO (used as a surrogate for non-dioxin 

organic HAP) and dioxin/furan, your 

unit is subject to the emission limits for 

the design-based subcategories shown in 

Table 1 of this preamble. If your new or 

existing boiler or process heater burns at 

least 10 percent biomass on an annual 

average heat input 2 basis, the unit is in 

one of the biomass subcategories. If your 

new or existing boiler or process heater 

burns at least 10 percent coal, on an 

annual average heat input basis, and 

less than 10 percent biomass, on an 

annual average heat input basis, the unit 

is in one of the coal subcategories. If 

your facility is located in the 

continental United States and your new 

or existing boiler or process heater 

burns at least 10 percent liquid fuel 

(such as distillate oil, residual oil) and 

less than 10 percent coal and less than 

10 percent biomass, on an annual 

average heat input basis, your unit is in 

the liquid subcategory. If your noncontinental new or existing boiler or 

process heater burns at least 10 percent 

liquid fuel (such as distillate oil, 

residual oil) and less than 10 percent 

coal and less than 10 percent biomass, 

on an annual average heat input basis, 

your unit is in the non-continental 

liquid subcategory. Finally, for the 

combustion-based pollutants, if your 

unit combusts gaseous fuel that does not 

qualify as a ‘‘Gas 1’’ fuel, your unit is 

subject to the Gas 2 emission limits in 

Table 1. If your unit combusts only 

natural gas, refinery gas, or equivalent 

fuel (other gas that qualifies as Gas 1 

fuel), with limited exceptions for gas 

curtailment and emergencies, your unit 

is subject to a work practice standard 

that requires an annual tune-up in lieu 

of emission limits. 

TABLE 1—EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS

[Pounds per million British thermal units] 

Subcategory 

Particulate 

matter 

(PM) 

Hydrogen 

chloride 

(HCl) 

Mercury 

(Hg) 

Carbon 

monoxide 

(CO) 

(ppm @3% 

oxygen) 

Dioxin/furan 

(TEQ) 

(ng/dscm) 

Existing—Coal Stoker .................................................. 0 .039 0 .035 0 .0000046 270 0 .003 

Existing—Coal Fluidized Bed ...................................... 0 .039 0 .035 0 .0000046 82 0 .002 

Existing—Pulverized Coal ............................................ 0 .039 0 .035 0 .0000046 160 0 .004 

Existing—Biomass Stoker/other .................................. 0 .039 0 .035 0 .0000046 490 0 .005 

Existing—Biomass Fluidized Bed ................................ 0 .039 0 .035 0 .0000046 430 0 .02 

Existing—Biomass Dutch Oven/Suspension Burner ... 0 .039 0 .035 0 .0000046 470 0 .2 

Existing—Biomass Fuel Cells ...................................... 0 .039 0 .035 0 .0000046 690 4 

Existing—Biomass Suspension/Grate ......................... 0 .039 0 .035 0 .0000046 3,500 0 .2 

Existing—Liquid ........................................................... 0 .0075 0 .00033 0 .0000035 10 4 

Existing—Gas 2 (Other Process Gases) ..................... 0 .043 0 .0017 0 .000013 9 .0 0 .08 

Existing—non-continental liquid ................................... 0 .0075 0 .00033 0 .00000078 160 4 

New—Coal Stoker ....................................................... 0 .0011 0 .0022 0 .0000035 6 0 .003 

New—Coal Fluidized Bed ............................................ 0 .0011 0 .0022 0 .0000035 18 0 .002 

New—Pulverized Coal ................................................. 0 .0011 0 .0022 0 .0000035 12 0 .003 

New—Biomass Stoker ................................................. 0 .0011 0 .0022 0 .0000035 160 0 .005 

New—Biomass Fluidized Bed ..................................... 0 .0011 0 .0022 0 .0000035 260 0 .02 

New—Biomass Dutch Oven/Suspension Burner ........ 0 .0011 0 .0022 0 .0000035 470 0 .2 

New—Biomass Fuel Cells ........................................... 0 .0011 0 .0022 0 .0000035 470 0 .003 

New—Biomass Suspension/Grate ............................... 0 .0011 0 .0022 0 .0000035 1,500 0 .2 

New—Liquid ................................................................. 0 .0013 0 .00033 0 .00000021 3 0 .002 

New—Gas 2 (Other Process Gases) .......................... 0 .0067 0 .0017 0 .0000079 3 0 .08 

New—non-continental liquid ........................................ 0 .0013 0 .00033 0 .00000078 51 0 .002 


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The emission limits in Table 1 apply 

only to new and existing boilers and 

process heaters that have a designed 

heat input capacity of 10 million British 

thermal units per hour (MMBtu/hr) or 

greater. We also are providing optional 

output-based standards in this final 

rule. Pursuant to CAA section 112(h), 

we are requiring a work practice 

standard for four particular classes of 

boilers and process heaters: New and 

existing units that have a designed heat 

input capacity of less than 10 MMBtu/ 

hr, and new and existing units in the 

Gas 1 (natural gas/refinery gas) 

subcategory and in the metal process 

furnaces subcategory. The work practice 

standard for these boilers and process 

heaters requires the implementation of a 

tune-up program as described in section 

III.F of this preamble. 

We are also finalizing a beyond-thefloor standard for all existing major 

source facilities having affected boilers 

or process heaters that would require 

the performance of a one-time energy 

assessment, as described in section III.F 

of this preamble, by qualified personnel, 

on the affected boilers and facility to 

identify any cost-effective energy 

conservation measures. 

E. What are the requirements during 

periods of startup, shutdown, and 

malfunction? 

Consistent with Sierra Club v. EPA, 

EPA has established standards in this 

final rule that apply at all times. In 

establishing the standards in this final 

rule, EPA has taken into account startup 

and shutdown periods and, for the 

reasons explained below, has 

established different standards for those 

periods. 

EPA has revised this final rule to 

require sources to meet a work practice 

standard, which requires following the 

manufacturer’s recommended 

procedures for minimizing periods of 

startup and shutdown, for all 

subcategories of new and existing 

boilers and process heaters (that would 

otherwise be subject to numeric 

emission limits) during periods of 

startup and shutdown. As discussed in 

Section V.F of this preamble, we 

considered whether performance 

testing, and therefore, enforcement of 

numeric emission limits, would be 

practicable during periods of startup 

and shutdown. EPA determined that it 

is not technically feasible to complete 

stack testing—in particular, to repeat the 

multiple required test runs—during 

periods of startup and shutdown due to 

physical limitations and the short 

duration of startup and shutdown 

periods. Therefore, we have established 

the separate work practice standard for 

periods of startup and shutdown. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

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

determined that malfunctions should 

not be viewed as a distinct operating 

mode and, therefore, any emissions that 

occur at such times do not need to be 

factored into development of CAA 

section 112(d) standards, which, once 

promulgated, apply at all times. In 

Mossville Environmental Action Now v. 

EPA, 370 F.3d 1232, 1242 (D.C. Cir. 

2004), the court upheld as reasonable 

standards that had factored in 

variability of emissions under all 

operating conditions. However, nothing 

in section 112(d) or in case law requires 

that EPA anticipate and account for the 

innumerable types of potential 

malfunction events in setting emission 

standards. See, Weyerhaeuser v. Costle, 

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

the nature of things, no general limit, 

individual permit, or even any upset 

provision can anticipate all upset 

situations. After a certain point, the 

transgression of regulatory limits caused 

by ‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

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

specification in advance by regulation.’’) 

Further, it is reasonable to interpret 

section 112(d) as not requiring EPA to 

account for malfunctions in setting 

emissions standards. For example, we 

note that Section 112 uses the concept 

of ‘‘best performing’’ sources in defining 

MACT, the level of stringency that 

major source standards must meet. 

Applying the concept of ‘‘best 

performing’’ to a source that is 

malfunctioning presents significant 

difficulties. The goal of best performing 

sources is to operate in such a way as 

to avoid malfunctions of their units. 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 112(d) standards for 

boilers and process heaters. As noted 

above, by definition, malfunctions are 

sudden and unexpected events and it 

would be difficult to set a standard that 

takes into account the myriad different 

types of malfunctions that can occur 

across all sources in the category. 

Moreover, malfunctions can vary in 

frequency, degree, and duration, further 

complicating standard setting. 

In the event that a source fails to 

comply with the applicable CAA section 

112(d) standards as a result of a 

malfunction event, EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. EPA would also consider 

whether the source’s failure to comply 

with the CAA section 112(d) standard 

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

reasonably preventable’’ and was not 

instead ‘‘caused in part by poor 

maintenance or careless operation.’’ 40 

CFR 63.2 (definition of malfunction). 

Finally, EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause an 

exceedance of the relevant emission 

standard. (See, e.g., State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(Sept. 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (Feb. 

15, 1983)). EPA is, therefore, adding to 

this final rule an affirmative defense to 

civil penalties for exceedances of 

numerical emission limits that are 

caused by malfunctions. See 40 CFR 

63.7575 (defining ‘‘affirmative defense’’ 

to mean, in the context of an 

enforcement proceeding, a response or 

defense put forward by a defendant, 

regarding which the defendant has the 

burden of proof, and the merits of which 

are independently and objectively 

evaluated in a judicial or administrative 

proceeding.). We also have added other 

regulatory provisions to specify the 

elements that are necessary to establish 

this affirmative defense; the source must 

prove by a preponderance of the 

evidence that it has met all of the 

elements set forth in 63.7501. (See 40 

CFR 22.24). The criteria ensure that the 

affirmative defense is available only 

where the event that causes an 

exceedance of the emission limit meets 

the narrow definition of malfunction in 

40 CFR 63.2 (sudden, infrequent, not 

reasonably preventable and not caused 

by poor maintenance and or careless 

operation). For example, to successfully 

assert the affirmative defense, the source 

must prove by a preponderance of the 

evidence that excess emissions ‘‘[w]ere 

caused by a sudden, infrequent, and 

unavoidable failure of air pollution 

control and monitoring equipment, 


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15614 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

process equipment, or a process to 

operate in a normal or usual manner 

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

ensure that steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with section 63.7500(a)(3) 

and to prevent future malfunctions. For 

example, the source must prove by a 

preponderance of the evidence that 

‘‘[r]epairs were made as expeditiously as 

possible when the applicable emission 

limitations were being exceeded * * *’’ 

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

to minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health * * *.’’ 

In any judicial or administrative 

proceeding, the Administrator may 

challenge the assertion of the affirmative 

defense and, if the respondent has not 

met its burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with Section 113 of the 

CAA (see also 40 CFR 22.77). 

F. What are the testing and initial 

compliance requirements? 

We are requiring that the owner or 

operator of a new or existing boiler or 

process heater must conduct 

performance tests to demonstrate 

compliance with all applicable emission 

limits. Affected units would be required 

to conduct the following compliance 

tests where applicable: 

(1) Conduct initial and annual stack 

tests to determine compliance with the 

PM emission limits using EPA Method 

5 or 17. 

(2) Conduct initial and annual stack 

tests to determine compliance with the 

Hg emission limits using EPA method 

29 or ASTM–D6784–02 (Ontario Hydro 

Method). 

(3) Conduct initial and annual stack 

tests to determine compliance with the 

HCl emission limits using EPA Method 

26A or EPA Method 26 (if no entrained 

water droplets in the sample). 

(4) Use EPA Method 19 to convert 

measured concentration values to 

pound per million Btu values. 

(5) Conduct initial and annual test to 

determine compliance with the CO 

emission limits using EPA Method 10. 

(6) Conduct initial test to determine 

compliance with the dioxin/furan 

emission limits using EPA Method 23. 

As part of the initial compliance 

demonstration, we are requiring that 

you monitor specified operating 

parameters during the initial 

performance tests that you would 

conduct to demonstrate compliance 

with the PM, Hg, HCl, CO, and dioxin/ 

furan emission limits. You must 

calculate the average hourly parameter 

values measured during each test run 

over the three run performance test. The 

lowest or highest hourly average of the 

three test run values (depending on the 

parameter measured) for each applicable 

parameter would establish the sitespecific operating limit. The applicable 

operating parameters for which 

operating limits would be required to be 

established are based on the emissions 

limits applicable to your unit as well as 

the types of add-on controls on the unit. 

The following is a summary of the 

operating limits that we are requiring to 

be established for the various types of 

the following units: 

(1) For boilers and process heaters 

with wet PM scrubbers, you must 

measure pressure drop and liquid flow 

rate of the scrubber during the 

performance test, and calculate the 

average hourly values during each test 

run. The lowest hourly average 

determined during the three test runs 

establishes your minimum site-specific 

pressure drop and liquid flow rate 

operating levels. 

(2) If you are complying with an HCl 

emission limit using a wet acid gas 

scrubber, you must measure pH and 

liquid flow rate of the scrubber sorbent 

during the performance test, and 

calculate the average hourly values 

during each test run of the performance 

test for HCl and determine the lowest 

hourly average of the pH and liquid 

flow rate for each test run for the 

performance test. This establishes your 

minimum pH and liquid flow rate 

operating limits. 

(3) For boilers and process heaters 

with sorbent injection, you must 

measure the sorbent injection rate for 

each acid gas sorbent used during the 

performance tests for HCl and for 

activated carbon for Hg and dioxin/ 

furan and calculate the hourly average 

for each sorbent injection rate during 

each test run. The lowest hourly average 

measured during the performance tests 

becomes your site-specific minimum 

sorbent injection rate operating limit. If 

different acid gas sorbents and/or 

injection rates are used during the HCl 

test, the lowest hourly average value for 

each sorbent becomes your site-specific 

operating limit. When your unit 

operates at lower loads, multiply your 

sorbent injection rate by the load 

fraction (operating heat input divided 

by the average heat input during your 

last compliance test for the appropriate 

pollutant) to determine the required 

parameter value. 

(4) For boilers and process heaters 

with fabric filters not subject to PM 

Continuous Emission Monitoring 

System (CEMS) or continuous 

compliance with an opacity limit (i.e., 

COMS), the 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 any 6-month period unless 

a CEMS is installed to measure PM. 

(5) For boilers and process heaters 

with electrostatic precipitators (ESP) not 

subject to PM CEMS or continuous 

compliance with an opacity limit (i.e., 

COMS) and you must measure the 

secondary voltage and secondary 

current of the ESP collection fields 

during the Hg and PM performance test. 

You then calculate the average total 

secondary electric power value from 

these parameters for each test run. The 

lowest average total secondary electric 

power measured during the three test 

runs establishes your site-specific 

minimum operating limit for the ESP. 

(6) For boilers and process heaters 

that choose to demonstrate compliance 

with the Hg emission limit on the basis 

of fuel analysis, you are required to 

measure the Hg content of the inlet fuel 

that was burned during the Hg 

performance test. This value is your 

maximum fuel inlet Hg operating limit. 

(7) For boilers and process heaters 

that choose to demonstrate compliance 

with the HCl emission limit on the basis 

of fuel analysis, you are required to 

measure the chlorine content of the inlet 

fuel that was burned during the HCl 

performance test. This value is your 

maximum fuel inlet chlorine operating 

limit. 

(8) For boilers and process heaters 

that are subject to a CO emission limit 

and a dioxin/furan emission limit, you 

are required to measure the oxygen 

concentration in the flue gas during the 

initial CO and dioxin/furan performance 

test. The lowest hourly average oxygen 

concentration measured during the most 

recent performance test is your 

operating limit, and your unit must 

operate at or above your operating limit 

on a 12-hour block average basis. 

These operating limits do not apply to 

owners or operators of boilers or process 

heaters having a heat input capacity of 

less than 10 MMBtu/hr or boilers or 

process heaters of any size which 

combust natural gas or other clean gas, 

metal process furnaces, or limited use 

units, as discussed in section IV.D.3 of 

this preamble. Instead, owners or 

operators of such boilers and process 

heaters shall submit to the delegated 

authority or EPA, as appropriate, if 

requested, documentation that a tune-up 

meeting the requirements of this final 

rule was conducted. In order to comply 

with the work practice standard, a tuneup procedure must include the 

following: 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15615 

(1) Inspect the burner, and clean or 

replace any components of the burner as 

necessary, 

(2) Inspect the flame pattern and make 

any adjustments to the burner necessary 

to optimize the flame pattern consistent 

with the manufacturer’s specifications, 

(3) Inspect the system controlling the 

air-to-fuel ratio, and ensure that it is 

correctly calibrated and functioning 

properly, 

(4) Optimize total emissions of CO 

consistent with the manufacturer’s 

specifications, 

(5) Measure the concentration in the 

effluent stream of CO in parts per 

million by volume dry (ppmvd), before 

and after the adjustments are made, 

(6) Submit to the delegated authority 

or EPA an annual report containing the 

concentrations of CO in the effluent 

stream in ppmvd, and oxygen in percent 

dry basis, measured before and after the 

adjustments of the boiler, a description 

of any corrective actions taken as a part 

of the combustion adjustment, and the 

type and amount of fuel used over the 

12 months prior to the annual 

adjustment. 

Further, all owners or operators of 

major source facilities having boilers 

and process heaters subject to this final 

rule are required to submit to the 

delegated authority or EPA, as 

appropriate, documentation that an 

energy assessment was performed, by a 

qualified energy assessor, and the costeffective energy conservation measures 

indentified. 

G. What are the continuous compliance 

requirements? 

To demonstrate continuous 

compliance with the emission 

limitations, we are requiring the 

following: 

(1) For units combusting coal, 

biomass, or residual fuel oil (i.e., No 4, 

5 or 6 fuel oil) with heat input 

capacities of less than 250 MMBtu/hr 

that do not use a wet scrubber, we are 

requiring that opacity levels be 

maintained to less than 10 percent 

(daily average) for existing and new 

units with applicable emission limits. 

Or, if the unit is controlled with a fabric 

filter, instead of continuous monitoring 

of opacity, the fabric filter must be 

continuously operated such that the bag 

leak detection system alarm does not 

sound more than 5 percent of the 

operating time during any 6-month 

period (unless a PM CEMS is used). 

(2) For units combusting coal, 

biomass, or residual oil with heat input 

capacities of 250 MMBtu/hr or greater, 

we are requiring that PM CEMS be 

installed and operated and that PM 

levels (monthly average) be maintained 

below the applicable PM limit. 

(3) For boilers and process heaters 

with wet PM scrubbers, we are requiring 

that you monitor pressure drop and 

liquid flow rate of the scrubber and 

maintain the 12-hour block averages at 

or above the operating limits established 

during the performance test to 

demonstrate continuous compliance 

with the PM emission limits. 

(4) For boilers and process heaters 

with wet acid gas scrubbers, you must 

monitor the pH and liquid flow rate of 

the scrubber and maintain the 12-hour 

block average at or above the operating 

limits established during the most 

recent performance test to demonstrate 

continuous compliance with the HCl 

emission limits. 

(5) For boilers and process heaters 

with dry scrubbers, we are requiring 

that you continuously monitor the 

sorbent injection rate and maintain it at 

or above the operating limits, which 

include an adjustment for load, 

established during the performance 

tests. When your unit operates at lower 

loads, multiply your sorbent injection 

rate by the load fraction (operating load 

divided by the load during your last 

compliance test for the appropriate 

pollutant) to determine the required 

parameter value. 

(6) For boilers and process heaters 

having heat input capacities of less than 

250 MMBtu/hr with an ESP, we are 

requiring that you monitor the voltage 

and current of the ESP collection plates 

and maintain the 12-hour block total 

secondary electric power averages at or 

above the operating limits established 

during the Hg or PM performance test. 

(7) For units that choose to comply 

with either the Hg emission limit or the 

HCl emission limit based on fuel 

analysis rather than on performance 

testing, you must maintain monthly fuel 

records that demonstrate that you 

burned no new fuels or fuels from a new 

supplier such that the Hg content or the 

chlorine content of the inlet fuel was 

maintained at or below your maximum 

fuel Hg content operating limit or your 

chlorine content operating limit set 

during the performance tests. If you 

plan to burn a new fuel, a fuel from a 

new mixture, or a new supplier’s fuel 

that differs from what was burned 

during the initial performance tests, 

then you must recalculate the maximum 

Hg input and/or the maximum chlorine 

input anticipated from the new fuels 

based on supplier data or own fuel 

analysis, using the methodology 

specified in Table 6 of this final rule. If 

the results of recalculating the inputs 

exceed the average content levels 

established during the initial test then, 

you must conduct a new performance 

test(s) to demonstrate continuous 

compliance with the applicable 

emission limit. 

(8) For all boilers and process heaters, 

except those that are exempt from the 

incinerator standards under section 129 

because they are qualifying facilities 

burning a homogeneous waste stream, 

you must maintain records of fuel use 

that demonstrate that your fuel was not 

solid waste. 

(9) For boilers and process heaters 

with an oxygen monitor installed for 

this final rule, you must maintain an 

oxygen concentration level, on a 12- 

hour block average basis, no less than 

lowest hourly average oxygen 

concentration measured during the most 

recent performance test. 

(10) For boilers and process heaters 

that demonstrate compliance using a 

performance test. You must maintain an 

operating load no greater than 110 

percent of the operating load established 

during the performance test. 

If an owner or operator would like to 

use a control device other than the ones 

specified in this section to comply with 

this final rule, the owner/operator 

should follow the requirements in 40 

CFR 63.8(f), which presents the 

procedure for submitting a request to 

the Administrator to use alternative 

monitoring. 

H. What are the notification, 

recordkeeping and reporting 

requirements? 

All new and existing sources are 

required to comply with certain 

requirements of the General Provisions 

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

identified in Table 10 of this final rule. 

The General Provisions include specific 

requirements for notifications, 

recordkeeping, and reporting. 

Each owner or operator is required to 

submit a notification of compliance 

status report, as required by § 63.9(h) of 

the General Provisions. This final rule 

requires the owner or operator to 

include in the notification of 

compliance status report certifications 

of compliance with rule requirements. 

Semiannual compliance reports, as 

required by § 63.10(e)(3) of subpart A, 

are required only for semiannual 

reporting periods when a deviation from 

any of the requirements in the rule 

occurred, or any process changes 

occurred and compliance certifications 

were reevaluated. 

This final rule requires records to 

demonstrate compliance with each 

emission limit and work practice 

standard. These recordkeeping 

requirements are specified directly in 

the General Provisions to 40 CFR part 


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15616 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

63, and are identified in Table 10. 

Owners or operators of sources with 

units with heat input capacity of less 

than 10 MMBtu/hr, units combusting 

natural gas or other clean gas, metal 

process furnaces, limited use units, and 

temporary use units must keep records 

of the dates and the results of each 

required boiler tune-up. 

Records of either continuously 

monitored parameter data for a control 

device if a device is used to control the 

emissions or CEMS data are required. 

You are required to keep the 

following records: 

(1) All reports and notifications 

submitted to comply with this final rule. 

(2) Continuous monitoring data as 

required in this final rule. 

(3) Each instance in which you did 

not meet each emission limit and each 

operating limit (i.e., deviations from this 

final rule). 

(4) Daily hours of operation by each 

source. 

(5) Total fuel use by each affected 

source electing to comply with an 

emission limit based on fuel analysis for 

each 30-day period along with a 

description of the fuel, the total fuel 

usage amounts and units of measure, 

and information on the supplier and 

original source of the fuel. 

(6) Calculations and supporting 

information of chlorine fuel input, as 

required in this final rule, for each 

affected source with an applicable HCl 

emission limit. 

(7) Calculations and supporting 

information of Hg fuel input, as required 

in this final rule, for each affected 

source with an applicable Hg emission 

limit. 

(8) A signed statement, as required in 

this final rule, indicating that you 

burned no new fuel type and no new 

fuel mixture or that the recalculation of 

chlorine input demonstrated that the 

new fuel or new mixture still meets 

chlorine fuel input levels, for each 

affected source with an applicable HCl 

emission limit. 

(9) A signed statement, as required in 

this final rule, indicating that you 

burned no new fuels and no new fuel 

mixture or that the recalculation of Hg 

fuel input demonstrated that the new 

fuel or new fuel mixture still meets the 

Hg fuel input levels, for each affected 

source with an applicable Hg emission 

limit. 

(10) A copy of the results of all 

performance tests, fuel analysis, opacity 

observations, performance evaluations, 

or other compliance demonstrations 

conducted to demonstrate initial or 

continuous compliance with this final 

rule. 

(11) A copy of your site-specific 

monitoring plan developed for this final 

rule as specified in 63 CFR 63.8(e), if 

applicable. 

We are also requiring that you submit 

the following reports and notifications: 

(1) Notifications required by the 

General Provisions. 

(2) Initial Notification no later than 

120 calendar days after you become 

subject to this subpart, even if you 

submitted an initial notification for the 

vacated standards that were 

promulgated in 2004. 

(3) Notification of Intent to conduct 

performance tests and/or compliance 

demonstration at least 60 calendar days 

before the performance test and/or 

compliance demonstration is scheduled. 

(4) Notification of Compliance Status 

60 calendar days following completion 

of the performance test and/or 

compliance demonstration. 

(5) Compliance reports semi-annually. 

I. Submission of Emissions Test Results 

to EPA 

EPA must have performance test data 

and other compliance data to conduct 

effective reviews of CAA Section 112 

and 129 standards, as well as for many 

other purposes including compliance 

determinations, emissions factor 

development, and annual emissions rate 

determinations. In conducting these 

required reviews, we have found it 

ineffective and time consuming not only 

for us but also for regulatory agencies 

and source owners and operators to 

locate, collect, and submit emissions 

test data because of varied locations for 

data storage and varied data storage 

methods. One improvement that has 

occurred in recent years is the 

availability of stack test reports in 

electronic format as a replacement for 

cumbersome paper copies. 

In this action, we are taking a step to 

improve data accessibility. Owners and 

operators of ICI boilers located at major 

source facilities will be required to 

submit to EPA an electronic copy of 

reports of certain performance tests 

required under this final rule. Data will 

be collected through an electronic 

emissions test report structure called the 

Electronic Reporting Tool (ERT) that 

will be used by the staff as part of the 

emissions testing project. The ERT was 

developed with input from stack testing 

companies who generally collect and 

compile performance test data 

electronically and offices within State 

and local agencies which perform field 

test assessments. The ERT is currently 

available, and access to direct data 

submittal to EPA’s electronic emissions 

database (WebFIRE) is scheduled to 

become available by December 31, 2011. 

The requirement to submit source test 

data electronically to EPA will not 

require any additional performance 

testing and will apply to those 

performance tests conducted using test 

methods that are supported by ERT. The 

ERT contains a specific electronic data 

entry form for most of the commonly 

used EPA reference methods. The Web 

site listed below contains a listing of the 

pollutants and test methods supported 

by ERT. In addition, when a facility 

submits performance test data to 

WebFIRE, there will be no additional 

requirements for emissions test data 

compilation. Moreover, we believe 

industry will benefit from development 

of improved emissions factors, fewer 

follow-up information requests, and 

better regulation development as 

discussed below. The information to be 

reported is already required for the 

existing test methods and is necessary to 

evaluate the conformance to the test 

method. 

One major advantage of collecting 

source test data through the ERT is that 

it provides a standardized method to 

compile and store much of the 

documentation required to be reported 

by this final rule while clearly stating 

what testing information we require. 

Another important benefit of submitting 

these data to EPA at the time the source 

test is conducted is that it will 

substantially reduce the effort involved 

in data collection activities in the 

future. Specifically, because EPA would 

already have adequate source category 

data to conduct residual risk 

assessments or technology reviews, 

there would likely be fewer or less 

substantial data collection requests (e.g., 

CAA Section 114 letters). This results in 

a reduced burden on both affected 

facilities (in terms of reduced manpower 

to respond to data collection requests) 

and EPA (in terms of preparing and 

distributing data collection requests). 

State/local/Tribal agencies may also 

benefit in that their review may be more 

streamlined and accurate because the 

States will not have to re-enter the data 

to assess the calculations and verify the 

data entry. Finally, another benefit of 

submitting these data to WebFIRE 

electronically is that these data will 

improve greatly the overall quality of 

the existing and new emissions factors 

by supplementing the pool of emissions 

test data upon which the emissions 

factor is based and by ensuring that data 

are more representative of current 

industry operational procedures. A 

common complaint we hear from 

industry and regulators is that emissions 

factors are outdated or not 

representative of a particular source 

category. Receiving and incorporating 


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data for most performance tests will 

ensure that emissions factors, when 

updated, represent accurately the most 

current operational practices. In 

summary, receiving test data already 

collected for other purposes and using 

them in the emissions factors 

development program will save 

industry, State/local/Tribal agencies, 

and EPA time and money and work to 

improve the quality of emissions 

inventories and related regulatory 

decisions. 

As mentioned earlier, the electronic 

data base that will be used is EPA’s 

WebFIRE, which is a database accessible 

through EPA’s TTN. The WebFIRE 

database was constructed to store 

emissions test and other data for use in 

developing emissions factors. A 

description of the WebFIRE data base 

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

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

Source owners and operators will be 

able to transmit data collected via the 

ERT through EPA’s Central Data 

Exchange (CDX) network for storage in 

the WebFIRE data base. Although ERT 

is not the only electronic interface that 

can be used to submit source test data 

to the CDX for entry into WebFIRE, it 

makes submittal of data very 

straightforward and easy. A description 

of the ERT can be found at http:// 

www.epa.gov/ttn/chief/ert/ert_tool.html. 

Source owners and operators must 

register with the CDX system to obtain 

a user name and password before being 

able to submit data to the CDX. The 

CDX registration page can be found at: 

https://cdx.epa.gov/SSL/CDX/ 

regwarning.asp?Referer=registration. If 

they have a current CDX account (e.g., 

they submit reports for EPA’s Toxic 

Release Inventory Program to the CDX), 

then the existing user name and 

password can be used to log in to the 

CDX. 

IV. Summary of Significant Changes 

Since Proposal 

A. Applicability 

Since proposal, several changes to the 

applicability of this final rule have been 

made. First, at proposal, we excluded all 

units that combust solid waste from the 

standards, but we have extended the 

coverage of this final rule to boilers and 

process heaters that combust solid waste 

but are exempt, by statute, from section 

129 incinerator rules because they are 

qualifying small power producers or 

cogeneration units that combust a 

homogeneous waste stream. This final 

rule continues to exclude other waste 

burning units. This is a clarifying 

change that is consistent with the intent 

of the proposed rule to establish 

emissions standards for all boilers and 

process heaters that are not solid waste 

incineration units subject to regulation 

under section 129. 

The proposed rule definition of coal 

was revised to include all types of 

fossil-based fuels in the coal definition. 

The final coal definition is: ‘‘Coal means 

all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite 

by the American Society for Testing and 

Materials in ASTM D388–991, 

‘‘Standard Specification for 

Classification of Coals by Rank’’ 

(incorporated by reference, see 

§ 63.14(b)), coal refuse, and petroleum 

coke. For the purposes of this subpart, 

this definition of ‘‘coal’’ includes 

synthetic fuels derived from coal for the 

purpose of creating useful heat, 

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

excluded from this definition.’’ 

Similarly, for biomass, the definition of 

biomass fuel was revised to include any 

potential biomass-based fuels. This is 

also a clarifying change consistent with 

the intent of the proposed rule as 

described above. The final definition is: 

‘‘Biomass or bio-based solid fuel means 

any solid biomass-based fuel that is not 

a solid waste. This may include, but is 

not limited to, the following materials: 

Wood residue; wood products (e.g., 

trees, tree stumps, tree limbs, bark, 

lumber, sawdust, sanderdust, 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 fuel is not 

intended to suggest that these materials 

are or not solid waste.’’ 

The proposed rule included a 

definition of waste heat boiler that 

excluded from the definition units with 

supplemental burners that are designed 

to supply 50 percent or more of the total 

rated heat input capacity. The final 

definition was revised to include all 

waste heat boilers. The final definition 

is: ‘‘Waste heat boiler means a device 

that recovers normally unused energy 

and converts it to usable heat. Waste 

heat boilers are also referred to as heat 

recovery steam generators.’’ Similarly, 

the waste heat process heater definition 

was revised to read as follows: ‘‘Waste 

heat process heater means an enclosed 

device that recovers normally unused 

energy and converts it to usable heat. 

Waste heat process heaters are also 

referred to as recuperative process 

heaters.’’ These changes were made in 

order to exempt the types of units 

intended at proposal. 

The proposed rule exempted blast 

furnace gas fuel-fired boiler or process 

heaters, and defined these units as units 

combusting 90 percent or more of its 

total heat input from blast furnace gas. 

We have changed the requirement to 90 

percent or more of its total volume of 

gas in this final rule. This change was 

made so that the units that were 

intended to be exempted from this final 

rule would be exempted. The wording 

of the proposed exemption did not 

exempt units that were intended to be 

exempted because the heating value of 

blast furnace gas is not as high as that 

of natural gas. 

The proposed rule exempted units 

that are an affected source in another 

MACT standard. We amended this 

language to include any unit that is part 

of the affected source subject to another 

MACT standard. We also exempted any 

unit that is used as a control device to 

comply with another MACT standard, 

provided that at least 50 percent of the 

heat input is provided by the gas stream 

that is regulated under another MACT 

standard. This change was made in 

order to encourage the recovery of 

energy from high heating value gases 

that would otherwise be flared. 

B. Subcategories 

In the proposed rule, for the fueldependent HAP (metals, Hg, acid gases), 

we identified the following five basic 

unit types as subcategories: (1) Units 

designed to burn coal, (2) units designed 

to burn biomass, (3) units designed to 

burn liquid fuel, (4) units designed to 

burn natural gas/refinery gas, and (5) 

units designed to burn other process 

gases. In this final rule, for fueldependent HAP, we combined the 

subcategories for units designed to 

combust coal and biomass into a 

subcategory for units designed to burn 

solid fuels. We changed the subcategory 

for units designed to burn natural gas/ 

refinery gas to a subcategory for units 

that burn natural gas, refinery gas, and 

other clean gas. We also added 

subcategories for non-continental liquid 

units and limited-use units. 

As described in the preamble to the 

proposed rule, within the basic unit 

types there are different designs and 

combustion systems that, while having 

a minor effect on fuel-dependent HAP 

emissions, have a much larger effect on 

pollutants whose emissions depend on 

the combustion conditions in a boiler or 

process heater. In the case of boilers and 

process heaters, the combustion-related 

pollutants are the organic HAP. In the 

proposed rule, we identified the 


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following 11 subcategories for organic 

HAP: (1) Pulverized coal units; (2) 

stokers designed to burn coal; (3) 

fluidized bed units designed to burn 

coal; (4) stokers designed to burn 

biomass; (5) fluidized bed units 

designed to burn biomass; (6) 

suspension burners/dutch ovens 

designed to burn biomass; (7) fuel cells 

designed to burn biomass; (8) units 

designed to burn liquid fuel; (9) units 

designed to burn natural gas/refinery 

gas; (10) units designed to burn other 

gases; and (11) metal process furnaces. 

In this final rule, we added 

subcategories for biomass suspension/ 

grate units, non-continental liquid units, 

and limited-use units. 

C. Emission Limits 

The proposed rule included 

numerical emission limits for PM, Hg, 

HCl, CO, and dioxin/furan, and limits 

for those same pollutants are included 

in this final rule. Unlike the proposed 

rule, we included a compliance 

alternative in the final rule to allow 

owners and operators of existing 

affected sources to demonstrate 

compliance on an output-basis instead 

of on a heat input basis. Compliance 

with the alternate output-based 

emission limits would require 

measurement of boiler operating 

parameters associated with the mass 

rate of emissions and energy outputs. If 

you elect to comply with the alternate 

output-based emission limits, you must 

use equations provided in the final rule 

to demonstrate that emissions from the 

applicable units do not exceed the 

output-based emission limits specified 

in the final rule. If you use this 

compliance alternative using the 

emission credit approach, you must also 

establish a benchmark, calculate and 

document the emission credits 

generated from energy conservation 

measures implemented, and develop 

and submit the implementation plan no 

later than 180 days before the date that 

the facility intends to demonstrate 

compliance. 

D. Work Practices 

This final rule includes work practice 

standards for most of the same units for 

which we proposed work practice 

standards, including new and existing 

units in the Gas 1 subcategory, existing 

units with heat input capacity less than 

10 MMBtu/hr, and new and existing 

metal process furnaces. In addition to 

those subcategories for which we 

proposed work practices, this final rule 

includes work practices for all units 

during periods of startup and shutdown, 

new units with heat input capacity less 

than 10 MMBtu/hr, limited use units, 

and units combusting other clean gases. 

Other clean gases are gases, other than 

natural gas and refinery gas (as defined 

in this final rule), that meet contaminant 

level specifications that are provided in 

the final rule. 

E. Energy Assessment Requirements 

In this final rule, we have expanded 

the definition of energy assessment with 

respect to the requirements of Table 3 of 

this final rule, by providing a duration 

for performing the energy assessment 

and defining the evaluation 

requirements for each boiler system and 

energy use system. These requirements 

are based on the total annual heat input 

to the affected boilers and process 

heaters. 

This final rule requires an energy 

assessment for facilities with affected 

boilers and process heaters using less 

than 0.3 trillion Btu per year (TBtu/y) 

heat input to be one day in length 

maximum. The boiler system and 

energy use system accounting for at 

least 50 percent of the energy output 

from these units must be evaluated to 

identify energy savings opportunities 

within the limit of performing a one day 

energy assessment. An energy 

assessment for a facility with affected 

boilers and process heaters using 0.3 to 

1 TBtu/year must be three days in 

length maximum. From these boilers, 

the boiler system and any energy use 

system accounting for at least 33 percent 

of the energy output will be evaluated, 

within the limit of performing a three 

day energy assessment. For facilities 

with affected boilers and process heaters 

using greater than 1 TBtu/year heat 

input, the energy assessment must 

address the boiler system and any 

energy use system accounting for at 

least 20 percent of the energy output to 

identify energy savings opportunities. 

The expanded definition for energy 

assessment clarifies the duration and 

requirements for each energy 

assessment for various units based on 

energy use. We have also added a 

definition for steam and process heating 

systems to clarify the components for 

each boiler system which must be 

considered during the energy 

assessment, including elements such as 

combustion management, thermal 

energy recovery, energy resource 

selection, and the steam end-use 

management of each affected boiler. 

Lastly, we have clarified the 

requirement in Table 3 to evaluate 

facility energy management practices as 

part of the energy assessment and a 

definition of an energy management 

program was added. The use of the 

ENERGY STAR Facility Energy 

Assessment Matrix as part of this review 

is recommended, but it was removed as 

a requirement in Table 3. The definition 

of an energy management program 

added to the rule is consistent with the 

ENERGY STAR Guidelines for Energy 

Management that can be referenced for 

further guidance. ENERGY STAR 

provides a variety of tools and resources 

that support energy management 

programs. For more information, visit 

http://www.energystar.gov. 

F. Requirements During Startup, 

Shutdown, and Malfunction 

For startup, shutdown, and 

malfunction (SSM), the requirements 

have changed since proposal. For 

periods of startup and shutdown, EPA is 

finalizing work practice standards, 

which require following manufacturers 

specifications for minimizing periods of 

startup and shutdown, in lieu of 

numeric emission limits. For 

malfunctions, EPA added affirmative 

defense language to this final rule for 

exceedances of the numerical emission 

limits that are caused by malfunctions. 

G. Testing and Initial Compliance 

The first significant change to the 

testing and initial compliance 

requirements is that units greater than 

100 MMBtu/hr must comply with the 

CO limits using a stack test rather than 

CO CEMS. EPA also added optional 

output-based limits that promote energy 

efficient boiler operation. Another 

significant change is that for units 

combusting gaseous fuels other than 

natural gas or refinery gas, in order to 

qualify for the Gas 1 subcategory work 

practice standard, the gases that will be 

combusted must be certified to meet the 

contaminant levels specified for Hg and 

hydrogen sulfide (H2S) in this final rule. 

Finally, EPA has changed the dioxin/ 

furan testing requirement to a one-time 

compliance demonstration due to the 

low dioxin/furan emissions 

demonstrated by the vast majority of 

sources that have tested for dioxin/ 

furan. 

H. Continuous Compliance 

The only significant change to the 

continuous compliance requirements is 

for monitoring of CO. Rather than using 

CO CEMS, as proposed, units will be 

required to continuously monitor and 

record the oxygen level in their flue gas 

during the initial compliance test and 

establish an operating limit that requires 

that the unit operate at an oxygen 

percentage of at least 90 percent of the 

operating limit on a 12-hour block 

average basis. Units will be required to 

continuously monitor oxygen to ensure 

continuous compliance. 


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I. Notification, Recordkeeping, and 

Reporting 

In this final action, we are requiring 

that owners or operators of boilers that 

choose to commence or recommence 

combustion of solid waste must provide 

30 days notice of the date upon which 

the source will commence or 

recommence combustion of solid waste. 

The notification must identify the name 

of the owner or operator of the affected 

source, the location of the source, the 

boiler(s) or process heater(s) that will 

commence burning solid waste, and the 

date of the notice; the currently 

applicable subcategory under this 

subpart; the date on which the unit 

became subject to the currently 

applicable emission limits; and the date 

upon which the unit will commence or 

recommence combusting solid waste. 

For each limited-use unit, owners or 

operators must monitor and record the 

operating hours on a monthly basis for 

the unit. This will ensure that units 

qualify for the limited-use subcategory. 

We also added a requirement that 

sources keep records of operating load 

in order to demonstrate continuous 

compliance with the operating load 

operating limit. 

When malfunctions occur, owners or 

operators must keep records of the 

occurrence and duration of each 

malfunction of the boiler or process 

heater, or of the associated air pollution 

control and monitoring equipment, as 

well as records of actions taken during 

periods of malfunction to minimize 

emissions, including corrective actions 

to restore the malfunctioning boiler or 

process heater, air pollution control, or 

monitoring equipment to its normal or 

usual manner of operation. 

Finally, for facilities that elect to use 

emission credits from energy 

conservation measures to demonstrate 

compliance, owners or operators must 

keep a copy of the Implementation Plan 

required in this rule and copies of all 

data and calculations used to establish 

credits. 

J. Technical/Editorial Corrections 

In this final action, we are making a 

number of technical corrections and 

clarifications to subpart DDDDD. These 

changes improve the clarity and 

procedures for implementing the 

emission limitations to affected sources. 

We are also clarifying several 

definitions to help affected sources 

determine their applicability. We have 

modified some of the regulatory 

language that we proposed based on 

public comments. 

In several places throughout the 

subpart, including the associated tables, 

we have corrected the cross-references 

to other sections and paragraphs of the 

subpart. 

We revised 40 CFR 63.7485 to clarify 

that for the purposes of subpart DDDDD, 

a major source of HAP is as defined in 

40 CFR 63.2, except that for oil and gas 

facilities a major source of HAP is as 

defined in 40 CFR 63.761 (40 CFR part 

63, subpart HH, National Emission 

Standards for Hazardous Air Pollutants 

from Oil and Natural Gas Production 

Facilities). This change was made 

because facilities subject to subpart HH 

contain units that will be subject to 

subject DDDDD. 

The word ‘‘specifically’’ was removed 

from § 63.7491(i) in order to clarify the 

exclusion for boilers and process heaters 

regulated by other HAP regulations. 

We revised 40 CFR 63.7505(c) to 

clarify that performance testing is 

needed only if a boiler or process heater 

is subject to an applicable emission 

limit listed in Table 2. 

We made several changes to the initial 

compliance demonstration 

requirements. We revised 40 CFR 

63.7510(a) to clarify that sources using 

a second fuel only for start up, shut 

down, and/or transient flame stability 

are still considered to be sources using 

a single fuel. We revised 40 CFR 

63.7510(c) to clarify that boilers and 

process heaters with a heat input 

capacity below 10 MMBtu per hour are 

not required to conduct a performance 

test for CO because they are not subject 

to a numerical emission limit for CO. In 

40 CFR 63.7510(d), we clarified that 

boilers and process heaters that use a 

CEMS for PM are exempt from the 

performance testing and operating limit 

requirements specified in 40 CFR 

63.7510(a) because the CEMS 

demonstrates continuous compliance. 

We revised 40 CFR 63.7510(c) and (d) to 

clarify that compliance for those 

provisions does not apply to units 

burning natural gas or refinery gas. 

We changed the performance testing 

requirements in 40 CFR 63.7515(b), (c), 

and (d) to state that performance testing 

for a given pollutant may be performed 

every 3 years, instead of annually, if 

measured emissions during 2 

consecutive annual performance tests 

are less than 75 percent of the 

applicable emission limit. 

In 40 CFR 63.7515(e), we clarified that 

boilers and process heaters with a heat 

input capacity below 10 MMBtu per 

hour are required to conduct tune-ups 

biennially, while larger natural gas and 

other Gas 1 units are required to 

conduct annual tune-ups. 

We revised 40 CFR 63.7515(f) to 

clarify that monthly fuel analyses are 

required only for fuel types for which 

emission limits apply. 

We made several changes to 40 CFR 

63.7520 to clarify the performance 

testing requirements. We revised 

paragraph (c) to clarify that performance 

tests must be conducted at 

representative operating load 

conditions, instead of at the maximum 

normal operating load. Language was 

also added to this section and to Table 

4 to subpart DDDDD to establish an 

operating limit for the boiler or process 

heater and clarified that the operating 

load must not exceed 110 percent of the 

load used during the performance test. 

We revised paragraph (d) to clarify that 

compliance with operating limits using 

a continuous parameter monitoring 

systems are based on the 4-hour block 

averages of the data collected by the 

continuous parameter monitoring 

systems. 

In 40 CFR 63.7522, we made several 

changes to the provisions for using 

emissions averaging. In paragraph (a), 

we clarified that average emissions must 

be ‘‘* * * not more than 90 percent of 

the applicable emission limit.’’ We also 

added a sentence to clarify that new 

boilers and process heaters may not be 

included in an emissions average used 

to demonstrate compliance according to 

that section. Equations 2 and 3 were 

revised to correct the discount factor 

from 0.9 to 1.1 because the actual 

emissions are multiplied by the 

discount factor. We also revised 

paragraph (c) to clarify that the deadline 

to establish emission caps to 

demonstrate compliance with the 

emission averaging option is 60 days 

after the publication of the final rule as 

referenced in paragraph (g)(2)(i), and 

revised paragraph (g) to clarify that 

facilities are required to submit an 

implementation plan as referenced in 

§ 63.7522(g)(1). 

We made several clarifying changes to 

the monitoring requirements in 40 CFR 

63.7525. We revised paragraph (a) to 

clarify that only boilers or process 

heaters subject to a CO limit are 

required to install a continuous oxygen 

monitoring system. We adopted 

language from § 63.7525(d)(2) to 

§ 63.7525(a)(6) to clarify what 

constitutes a deviation. In 40 CFR 

63.7525(c)(7), we clarified that owners/ 

operators are required to determine 6- 

minute and daily block averages 

excluding data from periods in which 

the continuous opacity monitoring 

system is out of control. 

The initial compliance provisions in 

40 CFR 63.7530(b) were revised to 

clarify that facilities are exempted from 

the initial compliance requirements of 

conducting a fuel analysis if only one 


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15620 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

fuel type is used. We revised 40 CFR 

63.7530(d) to clarify that units less than 

10 MMBtu per hour are required to 

submit a signed statement with the 

Notification of Compliance Status report 

that indicates a tune-up has been 

conducted. 

We revised 40 CFR 63.7540(a)(9)(i) to 

remove the reference to Procedure 2 in 

Appendix F to 40 CFR part 60; 

Procedure 2 specifies the ongoing QA/ 

QC requirements for PM CEMS after 

certification and is correctly referenced 

in paragraph (a)(9)(iii) of that section. 

We revised the notification 

requirements in 40 CFR 63.7545 to 

clarify that notifications should be 

submitted to the delegated authority, 

and to clarify that the Notification of 

Intent to conduct a performance test 

must be submitted 60 days before the 

test is scheduled to begin. 

The reporting requirements originally 

in 40 CFR 63.7550(g) and (g)(1) through 

(g)(3) are more correctly considered 

notification requirements, so they were 

moved to § 63.7545(e)(8). 

In response to comments asking for 

clarification, we have added definitions 

to 40 CFR 63.7575 for ‘‘Calendar year,’’ 

‘‘Operating day,’’ ‘‘Refinery gas,’’ and 

‘‘Valid hourly average.’’ We have also 

revised several definitions in that 

section based on public comments. For 

example, we revised the definition of 

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

term ‘‘controlled flame combustion’’ as 

used in that definition; revised ‘‘metal 

processing furnace’’ to include 

homogenizing furnaces; revised the 

definitions of ‘‘dry scrubber,’’ 

‘‘electrostatic precipitator,’’ and ‘‘fabric 

filter,’’ to indicate that these are all 

considered dry control systems. The 

definition of ‘‘wet scrubber’’ was revised 

to clarify that, ‘‘A wet scrubber creates 

an aqueous stream or slurry as a 

byproduct of the emissions control 

process.’’ 

The definition of ‘‘Tune-up’’ was 

removed from 40 CFR 63.7575 because 

all of the requirements for a tune-up are 

provided in the rule language at 40 CFR 

63.7540(a)(10), making the definition 

unnecessary. 

Several of the definitions in 40 CFR 

64.7575 were revised to clarify the types 

of equipment to which different 

standards apply. For example, the 

definition of ‘‘Temporary boiler’’ was 

revised to include additional criteria 

that could be used to identify temporary 

boilers from permanently installed 

units. The definition of ‘‘Unit designed 

to burn oil subcategory’’ was revised to 

exclude periods of gas curtailment and 

gas supply emergency from the 48-hour 

limit on liquid fuel combustion. 

Likewise, the definition of ‘‘Period of 

natural gas curtailment’’ was revised to 

clarify that contractual agreements for 

curtailed gas usage or fluctuations in 

price do not constitute periods of gas 

curtailment under the scope of this 

regulation. The definition of ‘‘Waste heat 

boiler’’ was revised to remove the 

criteria that 50 percent of total rated 

heat input capacity had to be from waste 

gases. We also revised the definition of 

‘‘Natural gas’’ to include gas derived 

from naturally occurring mixtures found 

in geological formations as long as the 

principal constituent is methane, 

consistent with the definition provided 

in 40 CFR part 60 subpart Db. A 

definition of propane, was also 

incorporated into the definition of 

natural gas. 

Several changes were made to the 

tables to subpart DDDDD as a result of 

the public comments on the proposed 

rule. 

In Tables 1 and 2, the references to 

‘‘Other gases’’ were revised to ‘‘Gas 2’’ to 

clarify that units burning natural gas, 

refinery gas, or other clean gases are not 

subject to emission limitations. The 

emission limits in these two tables were 

also revised to include averaging times 

for those pollutants for which 

measurements are taken with a 

continuous emission monitor. 

In Table 3, the references to 

‘‘§ 63.11202 and § 63.11203’’ in the table 

heading were revised to correctly 

reference 40 CFR 63.7540. The text in 

the first and second column of Table 3 

was revised to clarify that the 

requirements apply to both boilers and 

process heaters. A new row was added 

to clarify that work practice standards 

apply to new boilers or process heaters 

with a rated heat input capacity less 

than 10 MMBtu per hour. Language was 

also added to clarify that the energy 

assessment is a one-time requirement 

for existing boilers and process heaters. 

Additionally, new language was added 

clarifying the evaluation of the facility’s 

energy management program as part of 

the energy assessment. 

In Table 4, operating limits for pH 

added to Item 1 for wet scrubbers, as 

specified in 40 CFR 63.7530(b)(3)(i). 

Item 5 revised to clarify that ‘‘Any other 

control type’’ only means add-on airpollution control devices. The operating 

limits were also revised to clarify which 

units and control combinations were 

required to install and operate a bag leak 

detection system, to install and operate 

a continuous opacity monitor, or to 

monitor voltage and amperage of an 

ESP. These changes removed the 

appearance that some units would need 

to do more than one type of monitoring 

for control of PM. This table was also 

revised to include a row for an operating 

limit for unit operating load for those 

units that demonstrate compliance 

using a performance test. 

Table 5 was revised to include EPA 

Method 23 as the accepted method for 

measuring dioxin/furan. A new Table 11 

was also added to document the toxic 

equivalency factors that should be used 

to demonstrate compliance with the 

toxic equivalents (TEQ) emission limits. 

Table 7 was revised to include dry 

scrubbers and activated carbon injection 

used to comply with Hg or dioxin/furan 

emission limitations, and to include 

procedures for determining the 

corresponding operating limit 

requirements. Procedures were also 

added for determining the operating 

limit for unit operating load for units 

that demonstrate compliance through 

performance testing. Finally, this table 

was revised to clarify how the operating 

limits should be determined for wet 

scrubbers and for ESPs operated with 

wet scrubbers. 

Table 8 was revised to correct certain 

cross-references to 40 CFR 63.7530, and 

to include procedures for demonstrating 

continuous compliance with the 

operating limit for unit operating load. 

Table 9 was revised to correct crossreferences to 40 CFR 63.7550(c) and 

Table 3 for work practice standards. 

Language in Item 1.c. revised to more 

clearly match the language in 40 CFR 

63.7530(d) and (e), and Item 1.c. was 

split into Items 1.c. and 1.d. 

K. Other 

The definition of a boiler and the 

definition of a process heater have been 

revised to include units that combust 

solid waste but are exempt, by statute, 

from section 129. This change was 

necessary in order to provide coverage 

of units that would otherwise be exempt 

from any requirements. The revised 

definitions read as follows: 

Boiler means an enclosed device 

using controlled flame combustion and 

having the primary purpose of 

recovering thermal energy in the form of 

steam or 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 40 CFR 241.3, is not 

a boiler unless the device is exempt 

from the definition of a solid waste 

incineration unit as provided in CAA 

section 129(g)(1). Waste heat boilers are 

excluded from this definition. 

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 for use in a process unit, 


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instead of generating steam. Process 

heaters are devices in which the 

combustion gases do not directly come 

into contact with process materials. For 

purposes of this subpart, a device 

combusting solid waste, as defined in 40 

CFR 241.3, is not a process heater unless 

the device is exempt from the definition 

of a solid waste incineration unit as 

provided in CAA section 129(g)(1). 

Process heaters do not include units 

used for comfort heat or space heat, food 

preparation for on-site consumption, or 

autoclaves. 

As a result of new data received for 

the floor calculations, revised treatment 

of low reported CO data to consider 

measurement error, and a new 

subcategorization scheme, some of the 

final CO limits for new sources in Table 

1 of this final rule are more stringent 

than proposed, as are some of the other 

limits for certain subcategories (e.g., PM 

and Hg for liquid fuel units, and PM and 

HCl for solid fuel units when compared 

to the proposed new source limits for 

the proposed biomass/bio-based fuel 

subcategory). Where a final limit is more 

stringent than proposed, 40 CFR 63.6 of 

subpart A (General Provisions), requires 

that new sources that commenced 

construction between proposal and 

promulgation be allowed to comply 

with the proposed limits for 3 years (i.e., 

up to the existing source compliance 

date) and then comply with the final 

limits for new sources listed in Table 1 

of this final rule. In this final rule we 

have added a new Table 12 to outline 

the emission limits applicable to 

sources that commenced construction 

between proposal and promulgation and 

updated the rule language to provide 

instructions on which limits apply to 

them for the 3 year period after this final 

rule is published. These sources have 

the option to comply with Table 1 

(final) limits from the start, if they 

choose. 

V. Major Source Public Comments and 

Responses 

A. MACT Floor Analysis 

1. Pollutant-by-Pollutant Approach 

Comment: Many commenters raised 

concerns about the way EPA determined 

the MACT floors using a pollutant-bypollutant approach. Commenters 

contended that such a methodology 

produced limits that are not achievable 

in combination, and as such, the limits 

do not comport with the intent of the 

statute or the recent court decision 

(NRDC v. EPA, 2007). Commenters 

argue that while the Court’s 2007 

decision in NRDC v. EPA vacating the 

first ICI boiler and process heater MACT 

standard directed EPA to consider 

individual HAPs, it did not direct EPA 

to establish a separate floor for each 

HAP. Commenters further added that 

the Clean Air Act (CAA) directs EPA to 

set standards based on the overall 

performance of ‘‘sources’’ and sections 

112(d)(1), (2), and (3) specify that 

emissions standards be established on 

the ‘‘in practice’’ performance of a 

‘‘source’’ in the category or subcategory. 

If Congress had intended for EPA to 

establish MACT floor levels considering 

the achievable emission limits of 

individual HAPs, it could have worded 

112(d)(3) to refer to the best-performing 

sources ‘‘for each pollutant.’’ Many 

commenters added that EPA’s discretion 

in setting standards is limited to 

distinguishing among classes, types, and 

sizes of sources. However, Congress 

limited EPA’s authority to parse units 

and sources with similar design and 

types but it does not allow EPA to 

‘‘distinguish’’ units and sources by 

individual pollutant as proposed in this 

rule [Sierra Club v. EPA, 551 F.3d 1019, 

1028 (D.C. Cir. 2008)]. By calculating 

each MACT floor independently of the 

other pollutants, the combination of 

HAP limits results in a set of standards 

that only a hypothetical ‘‘best 

performing’’ unit could achieve. 

Many commenters who criticized the 

pollutant-by-pollutant approach also 

filed comments on other rules such as 

the recent Portland Cement NESHAP 

and the NSPS and Emission Guidelines 

for Hospital/Medical Infectious Waste 

Incinerators (HMIWI). Some 

commenters expressed concern that 

EPA used a similar pollutant-bypollutant approach in the HMIWI 

rulemaking and that rulemaking is being 

challenged before the D.C. Circuit. 

Commenters also submitted a variety of 

suggestions on calculating a multipollutant approach. Some commenters 

suggested that human health be 

considered by weighting pollutants 

according to relative-toxicity and then 

ranking the units in each subcategory 

according to their weighted emission 

totals in order to identify the best 

performing 12 percent of sources for all 

pollutants. 

Response: We disagree with the 

commenters who believe MACT floors 

cannot be set on a pollutant-bypollutant basis. Contrary to the 

commenters’ suggestion, section 

112(d)(3) does not mandate a total 

facility approach. A reasonable 

interpretation of section 112(d)(3) is that 

MACT floors may be established on a 

HAP-by-HAP basis, so that there can be 

different pools of best performers for 

each HAP. Indeed, as illustrated below, 

the total facility approach not only is 

not compelled by the statutory language 

but can lead to results so arbitrary that 

the approach may simply not be legally 

permissible. 

Section 112(d)(3) is ambiguous as to 

whether the MACT floor is to be based 

on the performance of an entire source 

or on the performance achieved in 

controlling particular HAP. Congress 

specified in section 112(d)(3) the 

minimum level of emission reduction 

that could satisfy the requirement to 

adopt MACT. For new sources, this 

floor level is to be ‘‘the emission control 

that is achieved in practice by the best 

controlled similar source.’’ For existing 

sources, the floor level is to be ‘‘the 

average emission limitation achieved by 

the best performing 12 percent of the 

existing sources’’ for categories and 

subcategories with 30 or more sources, 

or ‘‘the average emission limitation 

achieved by the best performing 5 

sources’’ for categories and subcategories 

with fewer than 30 sources. 

Commenters point to the statute’s 

reference to the best performing 

‘‘sources,’’ and claim that Congress 

would have specifically referred to the 

best performing sources ‘‘for each 

pollutant’’ if it intended for EPA to 

establish MACT floors separately for 

each HAP. EPA disagrees. The language 

of the Act does not address whether 

floor levels can be established HAP-byHAP or by any other means. The 

reference to ‘‘sources’’ does not lead to 

the assumption the commenters make 

that the best performing sources can 

only be the best-performing sources for 

the entire suite of regulated HAP. 

Instead, the language can be reasonably 

interpreted as referring to the source as 

a whole or to performance as to a 

particular HAP. Similarly, the reference 

in the new source MACT floor provision 

to ‘‘emission control achieved by the 

best controlled similar source’’ can mean 

emission control as to a particular HAP 

or emission control achieved by a 

source as a whole. 

Industry commenters also stressed 

that section 112(d) requires that floors 

be based on actual performance from 

real facilities, pointing to such language 

as ‘‘existing source’’, ‘‘best performing’’, 

and ‘‘achieved in practice’’. EPA agrees 

that this language refers to sources’ 

actual operation, but again the language 

says nothing about whether it is 

referring to performance as to individual 

HAP or to single facility’s performance 

for all HAP. Industry commenters also 

said that Congress could have mandated 

a HAP-by-HAP result by using the 

phrase ‘‘for each HAP’’ at appropriate 

points in section 112(d). The fact that 

Congress did not do so does not compel 

any inference that Congress was subsilentio mandating a different result 


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3See Petitioners Brief in Medical Waste Institute 

et al. v. EPA, No. 09–1297 (D.C. Cir.) pointing out, 

in this context, that ‘‘the best performers for some 

pollutants are the worst performers for others’’ (p. 

34) and ‘‘[s]ome of the best performer for certain 

pollutants are among the worst performers for 

others.’’ 

4Since industry commenters argued that the 

statute can only be read to allow floors to be 

determined on a single source basis, commenters 

offered no view of why their reading could be 

viewed as reasonable in light of the statute’s goals 

and objectives. It is not evident how any statutory 

goal is promoted by an interpretation that allows 

floors to be determined in a manner likely to result 

in floors reflecting emissions from worst or 

mediocre performers. 

when it left the provision ambiguous on 

this issue. The argument that MACT 

floors set HAP-by-HAP are based on the 

performance of a hypothetical facility, 

so that the limitations are not based on 

those achieved in practice, just re-begs 

the question of whether section 

112(d)(3) refers to whole facilities or 

individual HAP. All of the limitations in 

the floors in this rule of course reflect 

sources’ actual performance and were 

achieved in practice. Finally, there are 

a number of existing units that meet all 

of the final existing source emission 

limits. 

Commenters also point to EPA’s 

subcategorization authority, and claim 

that because Congress authorized EPA 

to distinguish among classes, types, and 

sizes of units, EPA cannot distinguish 

units by individual pollutant, as they 

allege EPA did in the proposed rule. 

However, that statutory language 

addresses EPA’s authority to 

subcategorize sources within a source 

category prior to setting standards, 

which EPA has done for boilers and 

process heaters. EPA is not 

distinguishing within each subcategory 

based on HAP emitted. Rather, it is 

establishing emissions standards based 

on the emissions limits achieved by 

units in each subcategory. Therefore, 

EPA’s subcategorization authority is 

irrelevant to the question of how EPA 

establishes MACT floor standards once 

it has made the decision to distinguish 

among sources and create subcategories. 

EPA’s long-standing interpretation of 

the Act is that the existing and new 

source MACT floors are to be 

established on a HAP-by-HAP basis. 

One reason for this interpretation is that 

a whole plant approach could yield 

least common denominator floors—that 

is floors reflecting mediocre or no 

control, rather than performance which 

is the average of what best performers 

have achieved. See 61 FR at 173687 

(April 19, 1996); 62 FR at 48363–64 

(September 15, 1997) (same approach 

adopted under the very similar language 

of section 129(a)(2)). Such an approach 

would allow the performance of sources 

that are outside of the best-performing 

12 percent for certain pollutants to be 

included in the floor calculations for 

those same pollutants, and it is even 

conceivable that the worst performing 

source for a pollutant could be 

considered a best performer overall, a 

result Congress could not have 

intended. Inclusion of units that are 

outside of the best performing 12 

percent for particular pollutants would 

lead to emission limits that do not meet 

the requirements of the statute. 

For example, if the best performing 12 

percent of facilities for HAP metals were 

also the worst performing units for 

organics, the floor for organics or metals 

would end up not reflecting best 

performance. In such a situation, EPA 

would have to make some type of value 

judgment as to which pollutant 

reductions are most critical to decide 

which sources are best controlled.3

Such value judgments are antithetical to 

the direction of the statute at the MACT 

floor-setting stage. Commenters 

suggested that a multi-pollutant 

approach could be implemented by 

weighting pollutants according to 

relative toxicity and calculating 

weighted emissions totals to use as a 

basis for identifying and ranking best 

performers. This suggested approach 

would require EPA to essentially 

prioritize the regulated HAP based on 

relative risk to human health of each 

pollutant, where risk is a criterion that 

has no place in the establishment of 

MACT floors, which are required by 

statute to be based on technology. 

The central purpose of the amended 

air toxic provisions was to apply strict 

technology-based emission controls on 

HAPs. See, e.g., H. Rep. No. 952, 101st 

Cong. 2d sess. 338. The floor’s specific 

purpose was to assure that 

consideration of economic and other 

impacts not be used to ‘‘gut the 

standards. While costs are by no means 

irrelevant, they should by no means be 

the determining factors. There needs to 

be a minimum degree of control in 

relation to the control technologies that 

have already been attained by the best 

existing sources.’’ A Legislative History 

of the Clean Air Act Vol. II at 2897 

(statement of Rep. Collins). An 

interpretation that the floor level of 

control must be limited by the 

performance of devices that only control 

some of these pollutants effectively 

‘‘guts the standards’’ by including worse 

performers in the averaging process, 

whereas EPA’s interpretation promotes 

the evident Congressional objective of 

having the floor reflect the average 

performance of best performing sources. 

Since Congress has not spoken to the 

precise question at issue, and the 

Agency’s interpretation effectuates 

statutory goals and policies in a 

reasonable manner, its interpretation 

must be upheld. See Chevron v. NRDC, 

467 U.S. 837 (1984).4

It is true that legislative history can 

sometimes be so clear as to give clear 

meaning to what is otherwise 

ambiguous statutory text. As just 

explained, EPA’s HAP-by-HAP 

approach fulfills the evident statutory 

purpose and is supported by the most 

pertinent legislative history. A few 

industry commenters nonetheless 

indicated that a HAP-by-HAP approach 

is inconsistent with legislative history to 

section 112(d), citing to page 169 of the 

Senate Report. Since this Report was to 

a version of the bill which did not 

include a floor provision at all (much 

less the language at issue here), it is of 

no relevance. National Lime II, 233 F. 

3d at 638. 

Industry commenters also noted that 

EPA retains the duty to investigate and, 

if justifiable, to adopt beyond the floor 

standards, so that potential least 

common denominator floors resulting 

from the whole facility approach would 

not have to ‘‘gut the standards.’’ That 

EPA may adopt more stringent 

standards based on what is ‘‘achievable’’ 

after considering costs and other factors 

is irrelevant to how EPA is required to 

set MACT floors. MACT floors must be 

based on the emission limitation 

achieved by the best performing 12 

percent of existing sources, and, for new 

sources, on the level achieved by the 

best controlled similar source, and EPA 

must make this determination without 

consideration of cost. At best, standards 

reflecting a beyond-the-floor level of 

performance will have to be costjustified; at worst, standards will remain 

at levels reflecting mediocre 

performance. Under either scenario, 

Congress’ purpose in requiring floors is 

compromised. 

EPA notes, however, that if optimized 

performance for different HAPs is not 

technologically possible due to 

mutually inconsistent control 

technologies (for example, metals 

performance decreases if organics 

reduction is optimized), then this would 

have to be taken into account by EPA in 

establishing a floor (or floors). The 

Senate Report indicates that if certain 

types of otherwise needed controls are 

mutually exclusive, EPA is to optimize 

the part of the standard providing the 

most environmental protection. S. Rep. 

No. 228, 101st Cong. 1st sess. 168 

(although, as noted, the bill 

accompanying this Report contained no 

floor provisions). It should be 


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emphasized, however, that ‘‘the fact that 

no plant has been shown to be able to 

meet all of the limitations does not 

demonstrate that all the limitations are 

not achievable.’’ Chemical 

Manufacturers Association v. EPA, 885 

F. 2d at 264 (upholding technologybased standards based on best 

performance for each pollutant by 

different plants, where at least one plant 

met each of the limitations but no single 

plant met all of them). 

All available data for boilers and 

process heaters indicate that there is no 

technical problem achieving the floor 

levels contained in this final rule for 

each HAP simultaneously, using the 

MACT floor technology. Data 

demonstrating a technical conflict in 

meeting all of the limits have not been 

provided, and, in addition, there are a 

number of units that meet all of the final 

existing source emission limits. 

2. Minimum Number of Units To Set 

New Source Floors 

Comment: Many commenters 

indicated that section 112 requires that 

data from a minimum of 5 units is 

required to set MACT floors for existing 

sources. Commenters noted that EPA’s 

use of less than 5 units for subcategories 

with greater than 30 units is a legalistic 

reading of section 112 that could result 

in such absurd results as using 5 units 

to set MACT floors for a subcategory 

with 29 units and data for only 10 units, 

but using a single unit to set MACT 

floors for a subcategory with 31 units 

and data for only 10 units. 

Response: EPA does not agree that 

section 112(d)(3) mandates a minimum 

of 5 sources in all instances, 

notwithstanding the incongruity of 

having less data to establish floors for 

larger source categories than is 

mandated for smaller ones. The literal 

language of the provision appears to 

compel this result. Section 112(d)(3) 

states that for categories and 

subcategories with at least 30 sources, 

the MACT floor for existing sources 

shall be no less stringent than the 

average emission limitation achieved by 

the best-performing twelve percent of 

the sources for which the Administrator 

has emissions information. The plain 

language of this provision requires that, 

for subcategories with at least 30 

sources but where the Administrator 

only has emissions information on a 

small number of units, the floor can be 

no less stringent than the average 

emission limitation achieved by the 

best-performing twelve percent of those 

sources. 

3. Treatment of Detection Levels 

Comment: When setting the MACT 

floors, non-detect values are present in 

many of the datasets from best 

performing units. Commenters provided 

input on how these non-detect values 

should be treated in the MACT floor 

analysis. Some commenters agreed that 

it is appropriate to keep the detection 

levels as reported; while certain 

commenters suggested that the detection 

levels should be replaced using a value 

of half the method detection limit 

(MDL). Many other commenters stated 

that data that are below the detection 

limit should not be used in setting the 

floors, and these data should be 

replaced with a higher value including 

either the MDL, limit of quantitation 

(LOQ), practical quantitation limit 

(PQL), or reporting limit (RL) for the 

purposes of the MACT floor 

calculations. Other commenters stated 

all non-detect values should be 

excluded from the floor analysis, or all 

values should be treated as 0. Some 

commenters stated it is necessary to 

keep the data as reported because 

changing values would lead to an 

upward bias. Additional commenters 

agreed with this basic premise, but 

suggested that replacing non-detect data 

with a value of half the MDL is 

appropriate while still minimizing the 

bias. They noted that treating 

measurements below the MDL as 

occurring at the MDL is statistically 

incorrect and violates the statute’s ‘‘shall 

not be less stringent than’’ requirement 

for MACT floors. One commenter also 

provided a reference for a statistical 

method based on a log-normal 

distribution of the data which estimated 

the ‘‘maximum likelihood’’ of data 

values; this result is slightly higher than 

half the MDL. Some commenters stated 

that it is necessary to substitute the 

MDL value when performing the MACT 

floor calculations. With MDL defined as 

the lowest concentration that can be 

distinguished from the blank at a 

defined level of statistical significance, 

this is an appropriate value. If MDL 

values are not reported, one commenter 

suggested an approach for estimating an 

MDL equivalent value, but recognized 

that the background laboratory and test 

report files may not be available to EPA 

in order to derive these estimates. Most 

commenters representing industry and 

industry trade groups argued that either 

LOQ or PQL values should replace nondetects. The LOQ is defined as the 

smallest concentration of the analyte 

which can be measured. These 

commenters contended that the LOQ 

leads to a quantifiable amount of the 

substance with an acceptable level of 

uncertainty. A few commenters 

provided calculations showing some of 

the proposed MACT floors were below 

the LOQ. Additionally, some of these 

commenters stated that using LOQ or 

PQL values also incorporates additional 

sources of random and inherent 

sampling error throughout the testing 

process, which is necessary. These 

errors occur during sample collection, 

sample recovery, and sample analysis; 

MDL values only account for method 

specific (e.g., instrument) errors. These 

commenters contended that the three 

times the MDL approach discussed in 

the proposal accounts for some 

measurement errors but does not 

account for these unavoidable sampling 

errors. The commenters also noted that 

an LOQ is calculated as 3.18 times the 

MDL, and PQL is calculated as 5–10 

times the MDL. Many of the 

commenters in support of using either 

an LOQ or PQL value ultimately 

believed a work practice is more 

appropriate where a MACT floor limit is 

below either of these two values. They 

cited 112(h)(1) which allows work 

practices under 112(h)(2) if ‘‘the 

application of measurement 

methodology to a particular class of 

sources is not practicable due to 

technological and economic 

limitations’’. These commenters stated 

that the inability of sources to 

accurately measure a pollutant at the 

level of the MACT floor qualifies as 

such a technological limitation that 

warrants a work practice standard. 

Where the proposed MACT floor is 

below the LOQ or PQL then that source 

category has a technological 

measurement limitation. A few 

commenters suggested RL values should 

be used when developing the floor 

limits. They stated that the RL is the 

lowest level at which the entire 

analytical system gives reliable signals 

and includes an acceptable calibration 

point. They added that use of an 

acceptable calibration point is critical in 

showing that numbers are real versus 

multiplying the MDL by various factors. 

Several commenters stated that all 

non-detect values should be excluded 

from MACT floor calculations. They 

believed that excluding all non-detect 

values would eliminate any potential 

errors or accuracy issues related to 

testing for compliance. Due to 

inconsistencies of the MDL value 

reported for non-detect data, one 

commenter suggested treating all such 

values as zero. This would provide a 

consistent approach for setting the floor 

as well as determining compliance. 

Issues discussed by a multitude of 

commenters were that a wide range of 

detection limit values were reported and 


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5American Society of Mechanical Engineers, 

Reference Method Accuracy and Precision 

(ReMAP): Phase 1, Precision of Manual Stack 

Emission Measurements, CRTD Vol. 60, February 

2001. 

that data from Phase I and Phase II 

information collection requests (ICR) are 

inconsistent. For all non-detect data, 

facilities participating in the Phase II 

ICR were instructed to report a detection 

limit, but this resulted in a variety of 

interpretations by the laboratories who 

reported data. As such, commenters 

provided examples where detected 

values were lower than non-detect 

values, and in some cases measured 

values were reported lower than typical 

method detection limits. Many of the 

commenters stated it is critical that EPA 

conduct a thorough quality review of 

the data to determine if non-detect 

values have been appropriately flagged 

and to normalize the data on a 

consistent basis. One commenter 

presented an example dataset and the 

potential implications of the treatment 

of non-detect data for Hg emissions in 

the biomass subcategory. This 

commenter noted that a number of the 

units with Phase I tests would no longer 

be considered top performers if their 

data were made consistent with the 

Phase II criteria. Several commenters 

provided remarks for EPA’s proposed 

method of three times the MDL as an 

option for setting limits. A few 

commenters in support noted that this 

approach provided a reasonable method 

to account for data variability as it took 

into account more than just analytical 

instrument precision. Many other 

commenters argued that this method 

results in limits which are too low, 

namely that it is still lower than the 

LOQ value which they are in favor of as 

a substitute for any reported non-detect 

data. On the contrary, some other 

commenters disagreed with this method 

and claimed that it would lead to results 

which introduce a high bias in the floor 

setting process. A few contended that 

multiplying by 3 would introduce a 300 

percent error into the floor, resulting in 

a floor that is less stringent than 

required by the Act. Others suggested 

that the MDL values are antiquated and 

already too high and thus it is not 

appropriate to multiply them by three. 

Also, a few commenters suggested 

multiplying the MDL by three would 

not reflect the actual lower emissions 

achieved by any source and as such is 

unlawful under section 112(d). 

Response: After consideration of the 

various comments related to treatment 

of detection limits in the development 

of MACT floors, EPA’s approach for this 

final rule is as follows. While 

commenters suggested using values less 

than the MDL, such values have not 

been demonstrated to have been met 

during the corresponding test run. 

Therefore, EPA concluded that it is not 

appropriate, for development of MACT 

floors, to use any value less than the 

MDL. EPA also disagrees with 

comments that emission levels at or 

near the MDLs are appropriate levels to 

use for standard setting without 

consideration of measurement 

imprecision, because the actual 

performance of sources may differ 

significantly from the measured values 

or the MDL. Accordingly, for the boiler 

and process heater source category, 

which includes many sources with 

emission levels at or near the MDL for 

the various pollutants, EPA concluded 

that measurement imprecision was a 

significant factor that should be 

included in the development of 

emission limits. To determine an 

appropriate methodology, EPA 

examined the contribution of test 

method measurement imprecision to the 

variability of a set of emissions data. 

One element of variability is associated 

with method detection capabilities and 

a second is a function of the 

measurement value. Measurement 

imprecision is proportionally highest for 

values measured below or near a 

method’s detection level and 

proportionally decreasing for values 

measured above the method detection 

level. 

The probability procedures applied in 

calculating the floor or an emissions 

limit inherently and reasonably account 

for emissions data variability including 

measurement imprecision when the 

database represents multiple tests from 

multiple emissions units for which all 

of the data are measured significantly 

above the method detection level. That 

is less true when the database includes 

emissions occurring below method 

detection capabilities and are reported 

as the method detection level values. 

EPA’s guidance to respondents for 

reporting pollutant emissions used to 

support the data collection specified the 

criteria for determining test-specific 

method detection levels. Those criteria 

insure that there is only about a 1 

percent probability of an error in 

deciding that the pollutant measured at 

the method detection level is present 

when in fact it was absent. Such a 

probability is also called a false positive 

or the alpha, Type I, error. Because of 

sample and emissions matrix effects, 

laboratory techniques, sample size, and 

other factors, method detection levels 

normally vary from test to test for any 

specific test method and pollutant 

measurement. The expected 

measurement imprecision for an 

emissions value occurring at or near the 

method detection level is about 40 to 50 

percent. Pollutant measurement 

imprecision decreases to a consistent 

relative 10 to 15 percent for values 

measured at a level about three times 

the method detection level.5

Also in accordance with our 

guidance, source owners identified 

emissions data which were measured 

below the method detection level and 

reported those values as equal to the 

method detection level as determined 

for that test. An effect of reporting data 

in this manner is that the resulting 

database is truncated at the lower end 

of the measurement range (i.e., no 

values reported below the test-specific 

method detection level). A floor or 

emissions limit based on a truncated 

database or otherwise including values 

measured near the method detection 

level may not adequately account for 

measurement imprecision contribution 

to the data variability. That is, an 

emission limit set based on the use of 

the MDL to represent data below the 

MDL may be significantly different than 

the actual levels achieved by the best 

performing units due to the imprecision 

of the measurements. This fact, 

combined with the low levels of 

emissions measured from many of the 

best performing units, led EPA to 

develop a procedure to account for the 

contribution of measurement 

imprecision to data variability. 

We applied the following procedures 

to account for the effect of measurement 

imprecision associated with a database 

that includes method detection level 

data. The first step was to define a 

method detection level that is 

representative of the data used in 

establishing the floor or emissions limit 

and that also minimizes the influence of 

an outlier test-specific method detection 

level value. We reviewed each 

pollutant-specific data set to identify the 

highest test-specific method detection 

level reported that was also equal to or 

less than the average emissions level 

(i.e., unadjusted for probability 

confidence level) calculated for the data 

set. We believe that this approach is 

representative of the data collected to 

develop the floor or emissions limit 

while to some degree minimizing the 

effect of a test(s) with an inordinately 

high method detection level (e.g., the 

sample volume was too small, the 

laboratory technique was insufficiently 

sensitive, or the procedure for 

determining the detection level was 

other than that specified). 

The second step in the process is to 

calculate three times the representative 


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6 Ibid. 

method detection level 6 and compare 

that value to the calculated floor or 

emissions limit. If three times the 

representative method detection level 

were less than the calculated floor or 

emissions limit calculated from the 

upper prediction limit (UPL), we would 

conclude that measurement variability 

was adequately addressed because the 

measurement inprecision at that level is 

a consistent 10 to 15 percent. The 

calculated floor or emissions limit 

would need no adjustment. If, on the 

other hand, the value equal to three 

times the representative method 

detection level were greater than the 

UPL-based emission limit, we would 

conclude that the calculated floor or 

emission limit does not account entirely 

for measurement variability. If 

indicated, we substituted the value 

equal to three times the representative 

method detection level to apply as the 

adjusted floor or emissions limit. This 

adjusted value would ensure 

measurement variability is adequately 

addressed in the floor or the emissions 

limit. 

In response to comments that EPA 

should have used the PQL, RL, or LOQ 

values in place of non-detect values, we 

disagree that use of those values is 

appropriate for calculating the MACT 

floors for two reasons. First, these terms 

are not defined statistically or 

consistently from method to method but 

are relatively arbitrary multiples (e.g., 3 

times, 5 times, or 10 times) of the MDL. 

In some cases, a RL, LOQ, or PQL is a 

value determined based on a laboratoryspecific procedure and not standardized 

by the method. We could not apply data 

arbitrarily adjusted or subject to 

laboratory-specific variables in 

establishing the floor. Second, we used 

a value equal to three times a 

representative MDL to compare with the 

floor and to adjust the applicable 

emissions limit, if necessary. We believe 

that using a value equal to three times 

the MDL sufficiently accounts for 

measurement uncertainty for the 

purposes of establishing compliance 

and there is no need to try to define or 

apply a PQL, LOQ, or RL for this 

purpose. 

4. Instrument Span for CO 

Comment: Many commenters stated 

that the reported data and limits for CO 

are within the error range of analyzers 

and CO CEMS. For Method 10, the 

calibrated analyzers have an error of ±2 

percent of the instrument span, with 

spans ranging from 50 parts per million 

(ppm) to 1000 ppm or greater. As such, 

at a minimum there is a potential error 

of 1 ppm to 20 ppm (2 percent of 50 

ppm and 1000 ppm, respectively) while 

the liquid and other process gas 

categories have floor limits set at 1 ppm. 

Similarly, commenters noted that CO 

CEMS have an allowable drift of 5 

percent of the span, with similar span 

ranges as Method 10. Commenters 

questioned the technical feasibility of 

complying with such low limits given 

the range in span values and suggested 

that EPA should review the data and 

establish more appropriate limits in 

consideration of measurement precision 

concerns. 

Response: EPA agrees with the 

comment that many of the CO 

measurements are within the error range 

of analyzers, and EPA has taken steps to 

mitigate the potential bias of such 

measurements. The resulting emission 

limits represent a level of performance 

that has been demonstrated to be 

achieved by the average of the best 

performing 12 percent of sources while 

considering variability introduced by 

imprecision of the CO analyzers. As 

explained below, our assessment 

indicated that the site-specific estimated 

measurement errors in some cases may 

be higher than some of the reported 

emissions levels. Therefore, for each 

emission test used in the MACT floor 

calculations we substituted the sitespecific estimated measurement error 

for reported values below those values 

in order to ensure the quality of the data 

used to set the floors. 

In response to the comments received, 

we reviewed the quality of the data 

relative to information provided for 

each emissions test. Method 10 is 

structured such that we can assess 

measurement data quality relative to the 

calibration span of the instrument (see 

http://www.epa.gov/ttn/emc/promgate/ 

method10r06.pdf and http:// 

www.epa.gov/ttn/emc/promgate/ 

method7E.pdf). For example, the 

allowable calibration error, system bias, 

and drift requirements are directly 

proportional to the site-specific 

instrument calibration span (i.e., ± 2.0 

percent of the calibration span value). 

For instrument calibration span values 

of 25 ppmv and less, the allowable 

calibration error, bias, or drift values are 

each ± 0.5 ppmv. 

We can estimate the equivalent of the 

method detection level for a 

measurement with an instrumental test 

method (e.g., EPA Methods 3A, 6C, 7E, 

and 10) using a square root formula and 

these allowable data quality criteria. For 

example, in the case of a calibration 

span value of 25 ppmv, the square root 

formula (i.e., square root of the sum of 

the squares) would indicate a value of 

0.9 ppmv. Consistent with the 

methodology we applied for noninstrumental methods, discussed in the 

previous comment response where we 

established limits no less than 3 times 

the MDL in order to avoid a large degree 

of measurement imprecision, this 

estimated measurement error value 

would translate to a limit of 3.0 ppmv 

(rounded up from 2.7 ppmv). For tests 

done with calibration spans of greater 

than 25 ppmv, the corresponding 

estimated measurement error would be 

greater. For example, the estimated 

measurement error using the square root 

formula for a calibration span of 100 

ppmv would be about 4 ppmv which 

would translate to a limit of 12 ppmv. 

For a calibration span of 1000 ppmv, the 

estimated measurement error would be 

35 ppmv or a limit of about 100 ppmv. 

5. Achievability of Limits 

Comment: Several commenters were 

concerned that only small subsets of 

sources in each subcategory have 

emissions stack test data. These 

commenters added that less data means 

the pool from which the best performing 

12 percent of the existing sources are 

drawn is smaller and, therefore, the 

actual number of sources used to 

determine the MACT floor is smaller. 

The commenters suggested that EPA 

should collect more data or provide 

assurances that the limited available 

data are representative for each 

subcategory. Commenters suggested that 

EPA could supplement testing data with 

‘‘emissions information’’ such as fuel 

records, production records and 

associated emission factors, commercial 

warranties and guarantees. 

Commenters raised concerns that 

existing units would have difficulty 

demonstrating compliance with the 

MACT floor limits. They suggested best 

performers with advanced air pollution 

control technologies should not be 

required to install additional add-on 

equipment to meet the emission limits. 

Commenters requested that EPA assess 

how many existing boilers and process 

heaters in each subcategory will be able 

to meet the standards without taking 

any further control measures. Several 

commenters contacted manufacturers 

regarding a retrofit project for their 

boilers and process heaters and they 

noted that manufacturers were 

unwilling to guarantee a retrofit would 

meet the limits. 

Similarly, commenters raised 

concerns that new units would have 

even more difficulty demonstrating 

compliance with the MACT floor limits. 

These commenters had difficulty 

identifying a single source whose 

emissions testing data demonstrated 

they could achieve all of the MACT 


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floors for new sources in combination. 

Several commenters contacted boiler 

and process heater manufacturers; all 

were unable to offer commercial 

emissions guarantees that a new unit 

would meet the proposed limits. Some 

commenters raised concerns about the 

impacts of these stringent new unit 

floors including: Deterring sources from 

upgrading to new boilers as efficiency 

gains provided by a new unit would be 

offset by extensive controls and 

threatening fuel diversity. 

Some commenters expressed concern 

that EPA had not properly evaluated 

whether there are technically feasible 

means of achieving the MACT floors. 

The commenters contended that the 

approach does not identify reasons why 

best performing sources achieve 

emissions levels reflected in the test 

data and they suggested that the intent 

of the MACT floor standard setting 

process is to discover effective control 

techniques so that other performers in 

the source category could emulate those 

techniques, reduce their emissions, and 

achieve similar emission levels. 

Commenters added that EPA has not 

adequately considered air pollution 

control device (APCD) conflicts with 

one another or compatibility of controls 

on certain boilers. Additionally, 

choosing to optimize controls for one 

pollutant may preclude optimization of 

controls for another pollutant e.g., 

minimizing CO in the combustion 

system is opposed to minimizing NOX

in most boiler burners. 

Response: As mentioned elsewhere in 

this preamble, EPA is required to 

establish MACT floor levels based on 

emissions limits achieved by sources for 

which emissions information is 

available to the Administrator. EPA has 

revised the proposed MACT floors as 

well as the proposed subcategories, as 

explained above. EPA also examined 

several ways in which it might be able 

to use other types of emissions 

information in addition to actual 

emissions measurements. However, EPA 

concluded that there was no appropriate 

method of using different types of 

information in a manner that could be 

incorporated into the variability 

analyses. EPA first assessed the 

potential for estimating emissions for 

sources that lacked actual emissions 

data through the use of emission factors. 

However, the emission factors lack any 

degree of variability. Therefore, the use 

of such data in this rulemaking would 

have distorted the data variability in 

many cases, leading to standards that 

were more stringent than those 

developed using emissions data only 

and that likely underestimated actual 

variability. EPA also considered 

whether it could otherwise estimate 

emissions of sources that did not 

provide emissions data. However, EPA 

concluded that such estimations were 

not possible without the development of 

a technically appropriate approach to 

evaluate relevant information, and 

commenters did not provide any such 

approaches. EPA’s approach provides 

MACT floors that are consistent with 

the requirements of section 112, because 

the floors are based on the average 

emissions performance of the best 

performers for which the Administrator 

has emissions information that is 

appropriate to use in setting the floors. 

EPA agrees with commenters who 

note that many of the data sets are 

small. However, stakeholders were 

encouraged to provide additional data, 

and EPA significantly revised some of 

the proposed emission limits based on 

new test data. We received little or no 

additional data for some subcategories 

for which data sets were small at 

proposal. For all data sets, the final 

emission limits are based on the 

available data and reflect EPA’s 

assessment of variability. Moreover, 

after consideration of the comments on 

the achievability of the emission limits, 

EPA performed additional analyses and 

detailed examinations of the data and 

developed revised limits that are based 

on what has been demonstrated to be 

achieved in practice. As described in 

more detail in the docket memorandum 

entitled ‘‘Revised MACT Floor Analysis 

(2011) for the Industrial, Commercial, 

and Institutional Boilers and Process 

Heaters National Emission Standards for 

Hazardous Air Pollutants—Major 

Source,’’ EPA has made adjustments to 

treatment of non-detect values, the 

statistical methodology, and monitoring 

requirements, and also incorporated 

new data and data corrections into our 

analyses. Accordingly, the final 

emission limits better reflect the 

performance of the MACT floor units 

than the proposed limits. EPA notes that 

for each subcategory, there are existing 

units that are meeting the MACT floor 

limits or are expected to meet the limits 

through application of available control 

technology. 

Finally, in response to comments 

about low CO limits conflicting with a 

unit’s ability to meet NOX requirements, 

EPA does not have specific information 

on the NOX limits and NOX emissions 

for most of the units that will be subject 

to the standard. However, the CO limits 

have been revised as discussed 

elsewhere in this preamble, and 

compliance is based on a full load test, 

while periods of startup and shutdown 

are subject to a work practice standard. 

To the extent that units cannot meet the 

CO floor and maintain NOX at the 

required level, oxidation catalysts can 

be used to reduce CO without an 

increase in NOX. EPA has included 

costs for these controls for many units 

in the cost analysis, although data on 

NOX requirements were not sufficient to 

allow NOX to be part of the analyses. 

Commenters did not provide any data 

supporting claims that any of the other 

emission limits or projected control 

devices would interfere with a source’s 

ability to meet any of the other emission 

limits. 

6. Comments on Technical Approaches 

Comment: Several commenters 

offered suggestions for adjusting the 

treatment of data from common stacks. 

Commenters suggested that it is 

improper to count the data twice if two 

boilers, in the same subcategory, 

exhaust through a common stack. A test 

conducted on the common stack does 

not represent the actual emissions from 

a single boiler, but rather reflects 

emissions from the combined 

simultaneous operation of the two 

boilers and their associated control 

device(s). The commenters contended 

that it is impossible to claim the test 

result would be exactly the same for 

each boiler and they added that if a 

common stack test turns out to be in the 

lowest 12 percent in a subcategory, 

counting it twice distorts the average of 

the best performers and skews the 

variability calculations. Commenters 

also noted that it is also not appropriate 

to divide emissions evenly between 

each boiler. Instead these commenters 

suggested that EPA use the data from 

common stacks only a single time in the 

MACT floor ranking and UPL 

calculations. 

Response: EPA’s current approach is 

a reasonable approach for comingled 

emissions, particularly in light of the 

limited dataset available for some 

subcategories, because EPA can not 

accurately separate the fraction of the 

emissions that came from the 

combustion units and process emission 

points that are comingled in the same 

stack. Applying the emissions equally to 

multiple units exhausting through a 

common stack accurately represents the 

emissions of those units on average. 

Further, although the use of a data point 

twice may dampen variability, the 

inclusion of an extra unit in the floor 

has the opposite effect on the overall 

emission limit by increasing the 

denominator of the floor calculation. 

Either method could be used, but the 

results would not differ significantly. 

Furthermore, for existing sources, 

MACT cannot be less stringent than the 

average emission limitation achieved by 


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the best performing 12 percent of 

existing sources (for which emission 

information is available). If EPA ignored 

boilers that exhaust through a common 

stack, it would be ignoring available 

emissions information that is relevant to 

setting the MACT floor standards. 

Comment: Some commenters raised 

concerns that the MACT floor 

methodology doesn’t adequately address 

the inherent variability with respect to 

operating conditions and control device 

performance. Operational variability can 

include warm-ups, shutdowns, load 

swings, and variations in fuel quality. 

They contended that emissions data 

relied upon in the proposal were 

produced during reference method 

performance testing under very limited 

operating conditions and with a very 

limited variation in potential fuel 

quality. Other commenters raised 

concerns that EPA has not properly 

acknowledged the impact of fuel quality 

on emissions. One commenter urged 

caution to EPA when considering 

variability to generate compliance 

margins that are palatable to industry; 

suggesting that this concept is not 

incorporated in the statute. 

Response: EPA is mindful of the need 

to account for sources’ variability in 

assessing sources’ performance when 

developing technology-based standards. 

EPA reviewed subcategory floor 

calculations in light of these comments 

and believes that the two-step MACT 

floor analysis process adequately 

addresses: (1) Performance testing 

variability and (2) fuel analysis 

variability estimations. EPA revised the 

MACT floor calculations in light of data 

submitted during and after the public 

comment period and also modified the 

approaches used at proposal for various 

aspects of the floor calculations. 

EPA first took fuel into consideration, 

to the extent it is reflected in differences 

in boiler design, when we divided the 

source category into subcategories. EPA 

is aware that differences between given 

types of units, and fuel, can affect 

technical feasibility of applying 

emission control techniques, and has 

addressed this concern in the final rule. 

For a fuel based pollutant, such as PM, 

performance testing must be conducted 

under representative full load operating 

conditions, which, along with the 

parameter monitoring requirements, 

provides an assurance that the standards 

are being met at all times. For Hg and 

HCl, we modified the fuel based 

variability analysis in consideration of 

comments received on this approach. 

The first modification to the analysis 

was the introduction of a solid fuel 

subcategory, which includes any unit 

burning at least 10 percent, on an 

annual heat input basis, of any coal, 

fossil solid, biomass, or bio-based solid 

fuel. Given the wide variety in fuel 

types that compose the floor, the 

statistical analysis accounts for some of 

the inter-unit variability for different 

fuel types identified to be in the floor. 

The second modification was the 

development of a fuel variability factor 

(FVF). The FVF calculations were 

similar to the calculations used at 

proposal, but they were simplified to 

remove the control efficiency 

calculation and the method for 

identifying outliers in the data was also 

adjusted. The revised FVF analysis 

calculated a ratio for all fuel analysis 

data points for units in the top 12 

percent for existing units and the top 

performing unit for new units in each 

subcategory. This ratio compared the 

reported fuel analysis data, converted to 

units of lb/MMBtu, to the emission test 

outlet data, converted to units of lb/ 

MMBtu, during the stack tests. At 

proposal we conducted an outlier 

analysis of only the maximum ratios for 

each unit, but we revised the outlier 

analysis to consider all of the ratios 

from top performers within each 

subcategory. We then defined and 

identified outliers using the test of 3 

times the standard deviation and 3 

minus the standard deviation for all of 

the ratios in the subcategory. After 

removing outliers, the remaining 

maximum ratio for each subcategory 

was identified and multiplied by the 99 

percent UPL. 

For a discussion of how EPA 

considered other non-fuel variability 

operations, such as boiler load, see 

response to the comments provided 

under ‘‘What did we do with the CO 

Limits’’. 

Comment: Several commenters argued 

that it is inappropriate to rank units 

according to the minimum stack test 

since any boiler can experience a good 

compliance test if conditions are 

favorable. Many of these commenters 

suggested that EPA should instead rank 

the data on the average of all stack tests. 

Another commenter suggested that the 

different emission levels achieved by 

different sources are just differences in 

performance and basing the ranking on 

the average would be more appropriate. 

This commenter suggested that at a 

minimum, the data used to rank and the 

data used as inputs into the MACT floor 

upper prediction limit calculation 

should be consistent. 

Response: In this final rule, EPA has 

reasonably determined that the bestcontrolled source is the source with the 

lowest stack test. EPA selected the 

lowest stack test as a measure of best 

performer because many units had only 

a single test available, and the 

comparison of average performance 

from two or more tests is not directly 

comparable to a single test 

measurement. However, all emission 

tests of acceptable quality were used to 

assess variability. As such, all data were 

considered in the floor analyses. EPA 

recognizes that each stack test data 

point represents a true assessment of the 

emissions for a combustor at a given 

point in time. However, where units had 

more than one test available, EPA also 

considers these other tests to be 

representative of the unit and relevant 

to assess run-to-run and test-to-test 

variability in the MACT floor UPL 

calculation. EPA did screen and remove 

certain test data from the MACT floor 

calculations if that data were not 

deemed representative of current 

operating conditions. 

7. Statistical Approach 

There were several comments made 

on specific aspects of the statistical 

variability analysis including 

suggestions for the appropriate 

confidence interval, appropriate 

statistic, and EPA’s methods for 

determining the distribution of the 

dataset. The specific comments and EPA 

responses are outlined below. 

Comment: Industry, industry 

representatives, and environmental 

advocacy groups had different 

perspectives on the appropriateness of 

the proposed 99 percent UPL. 

Commenters from environmental 

advocacy groups requested a lower UPL 

with suggestions ranging between 50 to 

95 percent. One commenter stated that 

EPA over-counts for the potential for 

future variability by using the 99 

percent UPL for the entire data set and 

it does not adequately account for all 

variability, such as how unit 

maintenance and operator training may 

limit upward variability’s effect on 

emission levels, and requests that EPA 

explain and justify the selection of the 

99 percent UPL as opposed to the 90 or 

95 percent UPL. Another commenter 

stated that most statistical analyses use 

90 or 95 percent confidence intervals 

and prediction intervals. The 

commenter also claimed that 99 percent 

is overly conservative and results in 

twice as much HAP emissions and 

reduced health benefits compared to a 

lower UPL. Consequently the 

commenter stated a lower UPL would 

better withstand judicial review. One 

commenter mentioned that there is 

precedent for setting limits based on the 

90th percentile and cited a 2006 

analysis where EPA determined the best 

demonstrated technology, which found 

Hg reductions based on 90th percentile 


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and deemed the 90th percentile 

‘‘reasonable’’ because of how compliance 

was to be determined and the high Hg 

content of the fuel used when the 

emissions data were collected. These 

commenters also suggested that EPA did 

not provide adequate rationale for 

selecting the 99th percentile instead of 

the 50th. These commenters noted that 

civil enforcement of environmental 

standards is based on a ‘‘preponderance 

of the evidence’’ which merely requires 

that a violation be more likely than not. 

Commenters from industry and 

industry representatives advocated for a 

higher UPL. Commenters requested that 

EPA increase the UPL to 99.9 percent in 

order to better encompass unit 

emissions variability and represent a 

manageable risk. Industry, like 

environmental advocacy groups, also 

requested that EPA take into account 

operator training and its effect on 

emissions. The commenters claimed 

that operators are compelled to set 

emissions targets lower than limits to 

create a compliance margin which helps 

avoid violations and their 

consequences. Commenters also cited 

recent consideration of a 99.9 percent 

UPL in the proposed HMIWI MACT 

rule. Commenters claimed that since the 

HMIWI database consisted of a small 

dataset, it was unlikely full variability 

was observed and thus EPA had no 

valid statistical basis for the decisions to 

use 99 percent in the final HWIMI rule. 

The commenters suggested similar data 

limitations in the boiler dataset and 

argued that the 99.9 percent UPL should 

be used to allow more of a margin for 

all operating conditions and sample 

collection variation due to the limited 

data for the boiler MACT rule. 

Response: In this final rule, EPA has 

reasonably determined that 99 percent 

UPL is appropriate for fuel based HAP, 

and dioxin/furan, and a 99.9 percent 

UPL is appropriate for CO. For fuelbased HAP the 99 percent confidence 

level is consistent with other recent 

rulemakings. See 75 FR 54975. Many of 

the subcategories had limited data to 

establish the MACT floor calculations 

and EPA determined it was 

inappropriate to use a confidence level 

lower than 99 percent to set the 

standard because doing so would result 

in limits that the best performers would 

be expected to exceed, while this final 

rule requires that units meet the limits 

at all times. Finally, for the fuel-based 

pollutants, there are well established 

control measures currently used on 

units in the source category (fabric 

filters for PM and Hg and wet or dry 

scrubbers for HCl) that serve to mitigate, 

to some degree, the variability in 

emissions that can be expected. Given 

this additional consideration for fuelbased HAP, but recognizing the 

emission limits must be met at all times 

yet are based on short term stack test 

data, EPA selected the 99 percent 

confidence level. A lower confidence 

level would result in emission limits 

that even the best performing sources 

would be expected to exceed. 

For CO, EPA considered several 

comments from industry and States, 

which provided both quantitative and 

qualitative comments on how CO 

emissions vary with load, fuel mixes 

and other routine operating conditions. 

After considering these comments EPA 

determined that a 99.9 percent 

confidence level for CO would better 

account for some of these fluctuations. 

While a good deal of CO data are 

available, at least for some of the 

subcategories, the data show highly 

variable emissions that can result from 

situations beyond the control of the 

operator, such as fuel moisture content 

after a rain event, elevated moisture in 

the air, and fuel feed issues or 

inconsistency in the fuel. The higher 

confidence level selected for CO is 

intended to reflect the high degree of 

variability in the emissions. For dioxin/ 

furan, we also are maintaining the 99 

percent UPL. Although much of the 

uncertainty associated with dioxin/ 

furan testing will be mitigated by the 

requirement in EPA Method 23 to report 

non-detect values as zero for 

compliance purposes, the dioxin 

emission limits remain quite low and 

the 99 percent UPL provides a high 

degree of confidence that the best 

performing units will be able to meet 

the standards. 

Comment: Several commenters also 

addressed concerns with how EPA 

determined the distribution of the 

dataset. Many commenters stated that 

normal distribution theory has been 

incorrectly applied to positively skewed 

or log normally distributed emissions 

data. Based on this, commenters 

claimed that sample means, and 

consequently the 99 percent UPL 

calculation, were incorrectly 

determined. Commenters suggested that 

sample means should be computed 

based on the arithmetic mean of 

lognormal distribution. One commenter 

requested that EPA consider using nonnormal distributions or non-parametric 

methods in the analysis. Two 

commenters noted that the technique 

used by EPA based on logarithmic 

transformation underestimates the 

prediction limit for the mean and 

requested that EPA use the 2004 

Bhaumik and Gibbons procedure for 

computing the UPL for log-normally 

distributed data. Three commenters 

stated that EPA is not following its own 

guidance document, Data Quality 

Assessment: Statistical Methods for 

Practitioners EPA QA/G–9S, for 

determining whether or not a data set is 

normally distributed and should explain 

the reasons for not doing so. The 

commenters then go on to request that 

EPA follow its guidance documents 

which recommend use other tests aside 

from the skewness and kurtosis tests 

when data are limited or if critical test 

values are not available. 

Response: EPA appreciates the 

detailed suggestions for alternative 

approaches to determine the dataset and 

it has revised its default selection of 

data distributions consistent with its 

guidance document Data Quality 

Assessment: Statistical Methods for 

Practitioners EPA QA/G–9S. This 

document indicates that most 

environmental data are lognormally 

distributed, so EPA has modified its 

assumptions when the results of the 

skewness and kurtosis tests result in a 

tie, or when there are not enough data 

to complete the skewness and kurtosis 

tests. Some of the commenters suggested 

that more advanced tests are necessary 

to determine the dataset, such as the 

Shapiro-Wilkes test. These tests needs a 

sample size of 50 or more, and would 

not be appropriate for many of the small 

sample sizes used to compute the 

MACT floor UPL. 

With respect to the methods used to 

compute the UPL for a dataset that is 

determined to be lognormally 

distributed, EPA also considered the 

commenters suggested revisions to the 

calculations in order to avoid skewing 

the UPL by calculating the UPL of an 

arithmetic mean instead of the UPL of 

a geometric mean. To adjust the 

calculation EPA considered a scale bias 

correction approach as well as a new 

UPL equation based on a Bhaumik and 

Gibbons 2004 paper, which calculates 

‘‘An Upper Prediction Limit for the 

Arithmetic Mean of a Lognormal 

Random Variable’’. Given data 

availability, EPA selected the Bhaumik 

and Gibbons 2004 approach which 

addresses commenters concerns with 

the proposed computations. 

Comment: Several commenters 

suggested alternatives to the UPL 

statistics such as upper tolerance limit 

(UTL), upper limit (UL) and upper 

confidence limit (UCL). Several 

commenters stated that EPA’s UPL 

calculation was flawed and did not fully 

account for variability. Commenters 

then suggested that if the proposed UPL 

approach was maintained EPA should 

adopt the modified UPL equation in the 

Portland cement NESHAP. Commenters 

argued that this statistic would 


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represent floors achieved in practice 

and account for total variability instead 

of EPA’s proposed UPL statistic based 

on sample variability. Several 

commenters claimed the data set was 

limited and suggested that EPA should 

use the UTL when data available do not 

represent the entire population. One 

commenter claimed that the upper UCL 

used in the HMIWI MACT rule was not 

a true prediction limit because it did not 

adjust the standard deviation for the 

number of test runs in the future 

compliance average and it should not be 

used in the boiler MACT rule. 

Response: EPA considered these 

comments and reviewed each of the 

separate statistics. Because statistics is a 

tool and many statistical approaches 

could be considered valid, EPA 

considered the comments and adjusted 

the approach used to provide a 

reasonable and technically correct 

statistical methodology. MACT floors 

for existing sources must reflect the 

average emission limitation achieved by 

the best-performing 12 percent of 

existing sources. As explained below, 

only the UCL and UPL adequately get at 

the notion of average emissions. Use of 

the UPL is also consistent with other 

recent rulemakings. See 75 FR 54975. 

In general, confidence intervals are 

used to quantify one’s knowledge of a 

parameter or some other characteristic 

of a population based on a random 

sample from that population. The most 

frequently used type of confidence 

interval is the one that contains the 

population mean. Given this definition, 

the 99 percent UCL represents the value 

which we can expect the mean of the 

population to fall below 99 percent of 

the time in repeated sampling. Whereas 

a confidence interval covers a 

population parameter with a stated 

confidence, that is, a certain proportion 

of the time, there is also a way to cover 

a fixed proportion of the population 

with a stated confidence. Such an 

interval is called a tolerance interval. 

Confidence limits are limits within 

which we expect a given population 

parameter, such as the mean, to lie. 

Statistical tolerance limits are limits 

within which we expect a stated 

proportion of the population to lie. 

Given these definitions, the 99 percent 

UTL represents the value which we can 

expect 99 percent of the measurements 

to fall below 99 percent of the time in 

repeated sampling. In other words, if we 

were to obtain another set of emission 

observations from the five sources, we 

can be 99 percent confident that 99 

percent of these measurements will fall 

below a specified level. Since you must 

calculate the sample percentile, and the 

sample sizes for the boiler MACT floor 

data are small, the 99th percentile is 

underestimated. The UTL should only 

be used where one can calculate a 

sample percentile, e.g., where there is a 

sample size of at least 100, and we do 

not have that many sources represented 

in any MACT floor. 

In contrast to a confidence interval or 

a tolerance interval, a prediction 

interval for a future observation is an 

interval that will, with a specified 

degree of confidence, contain the next 

(or some other pre-specified) randomly 

selected observation from a population. 

In other words, the prediction interval 

estimates what future values will be, 

based upon present or past background 

samples taken. Given this definition, the 

UPL represents the value which we can 

expect the mean of 3 future observations 

(3-run average) to fall below, based 

upon the results of the independent 

sample of size n from the same 

population. Finally, the upper limit 

(UL) is roughly equivalent to the 

percentile of the actual data distribution 

for the sample. The UL does not have 

a robust statistical foundation. Basically, 

the UL formulation assumes that the 

data: (1) Represent the population rather 

than a random sample from that 

population, and (2) are normally 

distributed. The data used to develop 

the MACT floors for this rule do not 

represent the entire population for any 

subcategory, and most of the data sets 

are not normally distributed. For these 

reasons, EPA concluded that it is not 

appropriate to use the UL in setting the 

MACT floor limits. 

Comment: Some commenters 

suggested that EPA’s UPL approach fails 

to accomplish predicting the level of 

performance achieved by the best 

performing sources under all operating 

conditions, not because of a poor 

statistical framework but because of an 

inadequate database. These commenters 

added that as a result, the inputs into 

the UPL equations are not representative 

of a distribution of values that reflect all 

operating conditions. 

Response: Section 112(d) of the Act 

requires EPA to base MACT floor 

standards for existing sources on the 

average emission limitation achieved by 

the best performing 12 percent of 

existing sources for which EPA has 

emissions information. EPA has 

incorporated new data and data 

corrections received during the public 

comment period. EPA also has 

considered the requests for further 

subcategorization of the source category 

in light of limits on the dataset that 

caution against over-partitioning of the 

database. The revised analysis is based 

on all emission stack test data of 

appropriate quality available to EPA, 

and the UPL approach provides as 

complete a picture of variability as 

possible given the limited data 

available. 

Comment: Some commenters 

questioned whether the statistical 

approach met EPA’s legal obligations 

under Section 112 of the CAA. One 

commenter stated that in order to 

withstand judicial review, the UPL 

should be calculated based on the best 

6 percent of sources instead of the best 

12 percent in order to establish a floor 

that would require 94 percent of sources 

to reduce emissions. One commenter 

stated that the courts did not endorse 

the proposed UPL procedure and that its 

appropriateness should be reviewed. 

The commenter goes on to say that on 

a statistical and technical basis, the UPL 

procedure is antithetical to the 

instruction in Section 112(d)(3)(A) and 

contradicts the strong endorsement of 

the high floor implementation as the 

best reading of the statutory language. 

Response: While the commenter is 

correct that the entire MACT floor data 

pool was used in the calculation of the 

UPL, EPA notes that statistics is a tool 

that is used to estimate variability and 

it is entirely appropriate to consider the 

variability within the best forming 12 

percent of sources in developing 

emission limits based on the average 

performance of those sources. As far as 

the concept that the floors should 

require 94 percent of the sources to 

reduce emissions, that is not what is 

required by the statute. Rather, the 

statute requires that the MACT floor 

standards for existing sources be no less 

stringent than the average emission 

limitation achieved by the best 

performing 12 percent of existing 

sources for which EPA has emissions 

information. For example, if a category 

had 100 units and the performance of 

the best 50 of those units was the same, 

the emission limits would be based on 

those 50 units and they all would be 

projected to meet the limits. While this 

is a hypothetical scenario, it illustrates 

that there is no specific percentage of 

sources that must reduce emissions in 

order for the MACT floor limits to be 

consistent with the statutory 

requirement. 

Comment: One commenter suggested 

that EPA should incorporate different 

statistical methods according to the 

amount and type of data available in 

each subcategory instead of a one-sizefits-all approach. This commenter also 

suggested that the approach taken by 

EPA must be validated by looking at the 

result it creates and examining whether 

the end result is reasonable. The 

commenter suggested applying a simple 

test to identify whether the resulting 


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floor requires a substantial majority of 

each subcategory to make some degree 

of emission reduction. 

Response: EPA has revised its 

statistical approach to include a mixed 

use of confidence levels, as discussed 

above, as well as a mix of statistical 

tools to consider the distribution of the 

datasets and what types of data are used 

as inputs into the floor analysis. For 

example, the MACT floor computations 

for Hg emissions from liquid fuel units 

were modified to consider data from 

both fuel analysis and stack test results. 

EPA appreciates the suggestion for 

validating the results of the statistical 

computations and has determined that 

the final floor levels require a significant 

number of sources to make some degree 

of emission reduction. However, EPA 

also notes that the number of sources 

that will need to achieve some degree of 

emissions reduction from current levels 

is not the statutory basis for establishing 

emissions standards under section 

112(d), as noted above. 

Comment: One commenter 

representing manufacturers of 

monitoring and control technologies 

suggested that statistical variability 

should not be incorporated into the 

floor computations for CO and Hg. This 

commenter suggested that EPA base the 

floors on the straight averages of each 

data set. 

Other commenters suggested that 

emissions variability is not statistical 

but instead based on different operating 

conditions of individual units. The 

commenters added that the variability of 

each unit should be averaged based on 

individual units and then used to 

establish UPL calculations instead of 

assessing a UPL based on individual 

tests or test runs. 

Response: The UPL calculation is a 

statistical formula designed to estimate 

a MACT floor level that is equivalent to 

the average of the best performing 

sources based on future compliance 

tests. If we did not account for 

variability in this manner and instead 

set the limit based solely on the average 

(mean) performance, then these units 

could exceed the limit half the time or 

more. The MACT floors for existing 

sources must reflect the average 

emission limitation achieved by the 

best-performing 12 percent of existing 

sources. Therefore, it is appropriate to 

consider statistical variability in order 

to ensure that units could meet the 

floors at all times. EPA agrees with the 

commenter that the variability of 

emissions is not solely statistical, but 

also represents some operational 

variability that may occur between 

different tests at the same unit (intraunit variability) as well as different tests 

at different units (inter-unit variability) 

in the floor. Since the floor calculations 

represent the average of the bestperforming 12 percent of existing 

sources, it is reasonable for EPA to use 

an appropriate statistical analysis to 

assess the impact both intra-unit and 

inter-unit variability have on the 

emissions profiles. 

8. Alternative Units for Emission Limits 

Comment: Several commenters from 

industry, State agencies, and 

environmental non-governmental 

organizations submitted a variety of 

alternatives to the concentration-based 

and mass-based MACT floor limits. 

Some commenters suggested emission 

reductions or removal efficiencies. 

These commenters cited regulatory 

precedence for a percent reduction limit 

in 40 CFR part 60 subpart Db, the New 

Source Performance Standards for 

Industrial, Commercial Institutional 

Boilers as well as New Source 

Performance Standards and Emission 

Guidelines for Large and Small 

Municipal Waste Combustors (40 CFR 

part 60 subparts Ca, Cb, Ea and Eb). 

Several other commenters suggested 

that EPA adopt an alternative outputbased emissions standard to promote 

boiler efficiency improvements as a 

pollution prevention technique. One 

commenter called attention to several 

previous examples of output-based 

standards in recent air regulations, 

including the New Source Performance 

Standard for Electric Utility Steam 

Generating Units (40 CFR part 60 

subpart Da) which includes an outputbased emissions standard for Hg, PM, 

SO2, and NOX) as well as the New 

Source Performance Standard for 

Industrial Commercial Institutional 

Boilers (40 CFR part 60 subpart Db) 

which includes an output-based 

emissions standard for NOX. This 

commenter also provided examples of 

output-based emissions regulations in 

12 states, including 4 that regulate nonelectricity thermal output, such as from 

combined heat and power systems. 

Many commenters encouraged EPA to 

investigate opportunities to develop and 

implement output-based emissions 

standards for ICI facilities. Some 

commenters tied in the appropriateness 

of output-based standards to the 

Agency’s other pollution prevention 

techniques included in the proposal, 

such as the energy assessments. The 

commenter added that by providing an 

output-based regulatory option, the user 

will have further incentive to 

implement energy efficiency 

opportunities identified during the 

energy assessment. 

Response: With respect to the 

commenters’ request for the 

development of percent reduction 

standards, sufficient data were not 

available to determine the percent 

reduction from the best performing 

units. In order to determine such 

standards, we would need emissions 

data from testing conducted at both the 

APCD inlet and outlet for the best 

performing sources, or at least for a 

reasonable number of best performing 

sources. However, we only have APCD 

inlet and outlet data for one pollutant 

(PM) for two subcategories, and based 

on this overwhelming lack of data 

available to calculate percent reduction 

standards, EPA did not pursue this 

option. We do agree with the 

commenters that output-based standards 

would provide incentives for 

implementation of energy conservation 

measures identified in an energy 

assessment. This final rule includes a 

compliance alternative that allows 

owners and operators of existing 

affected sources to demonstrate 

compliance on an output-basis. This 

alternate output-based limit will 

promote energy efficiency in industrial, 

commercial, and institutional steamgenerating facilities, and are equivalent 

to the MACT emissions limits that are 

in heat-input format. EPA has 

established pollution prevention as one 

of its highest priorities. One of the 

opportunities for pollution prevention 

lies in simply using energy efficient 

technologies to minimize the generation 

of emissions. Therefore, as part of EPA’s 

general policy of encouraging the use of 

flexible compliance approaches where 

they can be properly monitored and 

enforced, we are including alternate 

output-based emission limits in this 

final rule. The alternate output-based 

emission limits provide sources the 

flexibility to comply in the least costly 

manner while still maintaining 

regulation that is workable and 

enforceable. We investigated ways to 

promote energy efficiency in boilers by 

changing the manner in which we 

regulate flue gas emissions. The 

alternate output-based emission limits 

further this goal without reducing the 

stringency of the emissions standards. 

Traditionally, boiler emissions have 

been regulated on the basis of boiler 

input energy (lb of pollutant/MMBtu 

heat input). However, input-based 

limitations allow units with low 

operating efficiency to emit more of 

each pollutant per output (steam or 

electricity) produced than more efficient 

units. Considering two units of equal 

capacity, under current regulations, the 

less efficient unit will emit more 


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pollutants because it uses more fuel to 

produce the same amount of output 

(steam or electricity) than a more 

efficient unit. One way to regulate mass 

emissions and encourage plant 

efficiency is to express the emission 

standards in terms of output energy. 

Thus, output-based emission standards 

provide a regulatory incentive to 

enhance unit operating efficiency and 

reduce emissions. An example of such 

an output-based standard is the NOX

standard under the New Source 

Performance Standards (subpart Da) for 

electric utility boilers. 

The criteria used for selecting a 

specific output-based format were based 

on the following: (1) Provide flexibility 

in promotion of plant efficiency; (2) 

permit measurement of parameters 

related to stack emissions and plant 

efficiency, on a continuous basis; and 

(3) be suitable for equitable application 

on a variety of facility configurations. 

The output-based option of mass of 

pollutant emitted per boiler energy 

output (lb/MMBtu energy output) meets 

all three criteria. The majority of ICI 

boilers produce steam only for process 

operation or heating and, in this case, 

the energy output of the boiler is the 

energy content of the boiler steam 

output. For those ICI boilers that supply 

steam to generate, or cogenerate, 

electricity, the boiler’s energy output 

can include both electrical and thermal 

(process steam) outputs. There are also 

some industrial boilers that only 

generate electricity. Technologies are 

readily available to measure these 

energy outputs, and they currently are 

measured routinely in many industrial 

plants. Therefore, emission limits based 

on this format can be applied equitably 

on a variety of facility configurations. 

Based on this analysis, an emission 

limit format based on mass of pollutant 

emissions per energy output was 

selected for the alternate output-based 

standards. 

In the case of a boiler that produces 

steam for process or heating only (no 

power generation), the lb/MMBtu 

output-based emission limit is based on 

the mass rate of emissions from the 

boiler and the energy content in terms 

of MMBtu of the boiler steam output. At 

cogeneration facilities (also known as 

combined heat and power (CHP)), 

energy output includes both electricity 

and process steam. The steam from the 

boiler is first used to generate 

electricity. The thermal energy (steam) 

exiting the electricity generating 

equipment is then used for a variety of 

useful purposes, such as manufacturing 

processes, space heating and cooling, 

water heating, and drying. The 

electricity output and the useful energy 

present in the steam exiting the turbine 

must both be accounted for in 

determining the overall energy output 

from the boiler and converted to a 

common basis of lb/MMBtu consistent 

with the output-based standard for 

steam-only units. 

The efficiency and associated 

environmental benefits of CHP result 

from avoiding emissions from the 

generation of electricity at a central 

station power plant. The avoided 

emissions at most times are from a lessefficient unit that consequently also has 

higher emissions. Consequently, the 

electricity output of the CHP facility in 

kWh should be valued at the equivalent 

heat rate of the avoided central station 

power, nominally 10,000 Btu/kWh. 

Therefore, the lb/MMBtu output-based 

emission limit used for compliance with 

a CHP boiler is based on the mass rate 

of emissions from the boiler and a total 

energy output, which is the sum of the 

energy content of the steam exiting the 

turbine and sent to process in MMBtu 

and the energy of the electricity 

generated converted to MMBtu at a rate 

of 10,000 Btu per kWh generated (10 

MMBtu per MWh). 

Compliance with the alternative 

output-based emission limits would 

require continuous measurement of 

boiler operating parameters associated 

with the mass rate of emissions and 

energy outputs. In the case of boilers 

producing steam for process use or 

heating only (no power generation), the 

boiler steam output flow conditions 

would have to be measured to 

determine the energy content of the 

boiler steam output. In the case of CHP 

plants, where process steam and 

electricity are output products, methods 

would have to be provided to measure 

electricity output and the flow 

conditions of the steam exiting the 

electrical generating equipment and 

going to process uses. These conditions 

will determine the energy content of the 

steam going to process uses. 

Instrumentation already exists in many 

facilities to conduct these measurements 

since the instrumentation is required to 

support normal facility operation. 

Consequently, compliance with the 

alternate output-based emission limits is 

not expected to require any additional 

instrumentation in many facilities. 

However, additional signal input wiring 

and programming is expected to be 

required to convert the above 

measurements into the compliance 

format (lb/MMBtu energy). 

Since the June 4, 2010, proposal, we 

obtained steam data (flow, temperature, 

and pressure) from the best performing 

units that made up the MACT floor at 

proposal. In determining alternate 

equivalent output-based emission 

limits, we first determined for each of 

the best performing units the Btu output 

of the steam and then calculated the 

boiler efficiency for each of the boilers 

having available steam/heat input data. 

Boiler efficiency is defined as steam Btu 

output divided by fuel Btu input. Next, 

we determined the average boiler 

efficiency factor for each subcategory 

from the best performing units in that 

subcategory. We then applied the 

average boiler efficiency factor to the 

final MACT limits that are in the current 

format of lb/MMBtu heat input to 

develop the alternate output-based 

limits. The efficiency factor approach 

was selected because the alternative of 

converting all the reported data in the 

database to an output-basis would 

require extensive data gathering and 

analyses. Applying an average boiler 

efficiency factor, based on the 

individual boiler efficiency of the best 

performing units, essentially converts 

the heat input-based limits to outputbased emission limits. 

The alternate output-based emission 

limits in this final rule do not lessen the 

stringency of the MACT floor limits and 

would provide flexibility in compliance 

and cost and energy savings to owners 

and operators. We also have ensured 

that the alternate emission limits can be 

implemented and enforced, will be clear 

to sources, and most importantly, will 

be no less stringent than 

implementation of the MACT floor 

limits. 

B. Beyond the Floor 

1. Energy Assessment Requirement 

Comment: In the proposal preamble, 

we solicited comments on various 

aspects of the energy assessment 

requirement. The proposed standards 

included the requirement to perform an 

energy assessment to identify costeffective energy conservation measures. 

Since there was insufficient information 

to determine if also making the 

implementation of cost-effective 

measures a requirement was 

economically feasible, we requested 

comment on this point. We also 

specifically requested comment on: (1) 

Whether our estimates of the assessment 

costs are correct; (2) is there adequate 

access to certified assessors; (3) are there 

organizations other than for certifying 

energy engineers; (4) are online tools 

adequate to inform the facility’s 

decision to make efficiency upgrades; 

(5) is the definition of ‘‘cost-effective’’ 

appropriate in this context since it refers 

to payback of energy saving investments 

without regard to the impact on HAP 

reduction; (6) what rate of return should 


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be used; and (7) are there other 

guidelines for energy management 

beside ENERGY STAR’s that would be 

appropriate. The energy assessment 

requirement has been revised in this 

final rule and alternate equivalent 

output-based emission limits have been 

incorporated into this final rule as an 

alternative means of complying with the 

emission limits in final rule. The 

alternate output-based emission limits 

allow a facility implementing energy 

conservation measures that result in 

decreased fuel use to comply with that 

emission limit by applying emission 

credits earned from the implementation 

of the energy conservation measure. 

Commenters stated that EPA should 

provide a clear, statutory-based 

definition of ‘‘Boiler,’’ and the scope of 

the required energy assessment. 

Commenters also stated that if EPA 

includes an energy assessment 

requirement in this final rule, it should 

regulate only the emission source over 

which it has § 112 authority to regulate. 

The ‘‘boiler’’ logically includes the 

combustion unit (the emissions source) 

and closely associated equipment, from 

flame to last heat recovery. EPA should 

adopt this definition of ‘‘boiler system,’’ 

which reflects the extent of its section 

112 authority. 

Commenters also recommended that 

an energy assessment previously 

conducted of a facility that has not had 

significant changes to the boilers and 

associated equipment should be 

acceptable for initial compliance. 

Energy performance of facilities strongly 

depends on equipment configuration, 

equipment performance, and fuels fired. 

If these do not change from the time an 

energy assessment was conducted to the 

time the Initial Compliance energy 

assessment report is submitted, the 

report would be representative of an 

accurate depiction of the facility. 

Several commenters supported the 

use of energy assessments as a ‘‘beyond 

the floor’’ control measure and 

advocated for output-based standards 

(noting that such an approach is 

critically important to encourage CHP 

since input-based emissions regulations 

fail to credit CHP systems for their 

greater efficiency, reducing the 

incentive for CHP to be installed and 

used throughout U.S. industry). 

Moreover, since this final boiler rule 

will apply to a wide variety of 

manufacturing facilities in multiple 

sectors producing a variety of final 

products, normalizing pollutant output 

per useful energy output is a good way 

to ensure all affected facilities can be 

assessed on similar baselines. Several 

commenters also applauded recognition 

of energy efficiency measures to achieve 

pollution reductions and encouraged 

EPA to continue to view energy 

efficiency investments favorably. Some 

commenters criticized EPA’s failure to 

require implementation of findings of 

the energy assessments. 

Response: We agree that EPA should 

provide a clear definition of what the 

energy assessment should encompass. 

However, we disagree that the energy 

assessment should be limited to only 

the boiler and associated equipment, 

and in fact the proposed rule included 

a broader scope. EPA has properly 

exercised the authority granted to it 

pursuant to CAA section 112(d)(2) 

which states that ‘‘Emission standards 

promulgated * * * and applicable to 

new or existing sources shall require the 

maximum degree of reduction in [HAP] 

emissions that the Administrator 

determines * * * is achievable * * * 

through application of measures, 

processes, methods, systems or 

techniques including, but not limited to 

measures which * * * reduce the 

volume of, or eliminate emissions of, 

such pollutants through process 

changes, substitution of materials or 

other modifications * * *.’’ The energy 

assessment requirement is squarely 

within the scope of this authority. The 

purpose of an energy assessment is to 

identify energy conservation measures 

(such as process changes or other 

modifications to the facility) that can be 

implemented to reduce the facility 

energy demand from the affected boiler, 

which would result in reduced fuel use. 

Reduced fuel use will result in a 

corresponding reduction in HAP, and 

non-HAP, emissions from the affected 

boiler. 

We agree that the scope of the 

required energy assessment presented in 

the proposed rule needs to be clarified 

and we have done this in this final rule. 

In the proposed Boiler MACT, the 

intended scope of the energy assessment 

did extend beyond the affected boiler. 

The energy assessment included a 

requirement that a facility energy 

management program be developed. The 

energy assessment was intended to be 

broader than the affected boiler and 

process heater and included other 

systems or processes that used the 

energy from the boiler and process 

heater. We disagree that the scope of the 

energy assessment should be limited to 

the boiler and directly associated 

components such as the feed water 

system, combustion air system, fuel 

system (including burners), blow down 

system, combustion control system, and 

heat recovery of the combustion fuel 

gas. Including all of the energy using 

systems in the energy assessment can 

result in decreased fuel use that results 

in emission reductions, the result 

articulated in 112(d)(2). We have 

included in this final rule a definition 

of what the energy assessment should 

include for various size fuel consuming 

facilities. We also have included a 

definition of the qualified assessors who 

must be used to conduct those energy 

assessments. We have clarified the 

requirement that the energy assessment 

include a review of the facility’s energy 

management program and identify 

recommendations for improvements 

that are consistent with the definition of 

an energy management program. A 

definition of an energy management 

program that is compatible with the 

ENERGY STAR Guidelines for Energy 

Management and other similar 

approaches was added. 

We also agree that a facility should be 

exempt from the requirement to conduct 

an energy assessment if an energy 

assessment has recently been 

conducted. We have revised the final 

rule to allow facilities to comply with 

the requirement by submitting an energy 

assessment that has been conducted 

within 3 years prior to the promulgation 

date of this final rule. 

Comment: The principle arguments 

against an energy assessment 

requirement are: (1) EPA lacks authority 

to impose requirements on portions of 

the source that are not designated as 

part of the affected source, such as nonemitting energy using systems at a 

facility; (2) EPA has not quantified the 

reductions associated with the energy 

assessment requirement, therefore it 

cannot be ‘‘beyond the floor;’’ and (3) the 

bare requirement to perform an audit 

without being required to implement its 

findings is not a standard under CAA 

section 112(d). 

Response: With respect to the first 

argument, we have carefully limited the 

requirement to perform an energy audit 

to specific portions of the source that 

directly affect emissions from the 

affected source. The emissions that are 

being controlled come from the affected 

source. The process changes resulting 

from a change in an energy using system 

will reduce the volume of emissions at 

the affected source by reducing fuel 

consumption and the HAP released 

through combustion of fuel. The 

requirement controls the emissions of 

the affected source and, as explained 

above, is within the scope of EPA’s 

authority under section 112(d)(2). 

With respect to the second argument, 

the energy assessment will generate 

emission reductions through the 

reduction in fuel use beyond those 

reductions required by the floor. While 

the precise quantity of emission 

reductions will vary from source to 


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source and cannot be precisely 

estimated, the requirement is clearly 

directionally sound and thus consistent 

with the requirement to examine 

beyond the floor controls. By definition, 

any emission reduction would be cost 

effective or else it would not be 

implemented. 

Finally, with respect to the third 

argument, the requirement to perform 

the energy audit is, of course, a 

requirement that can be enforced and 

thus a standard. As noted, while we do 

not know the precise reductions that 

will occur at individual sources, the 

record indicates that energy assessments 

reduce fuel consumption and that 

parties will implement 

recommendations from an auditor that 

they believe are prudent. Therefore, the 

requirement to perform an energy 

assessment can both be enforced and 

will result in emission reductions. 

We agree that EPA should provide a 

clear definition of what the energy 

assessment should encompass. 

However, we disagree that the energy 

assessment should be limited to only 

the boiler and associated equipment. 

EPA has properly exercised the 

authority granted to it pursuant to CAA 

section 112(d)(2) which states that 

‘‘Emission standards promulgated * * * 

and applicable to new or existing 

sources shall require the maximum 

degree of reduction in [HAP] emissions 

that the Administrator determines 

* * * is achievable * * * through 

application of measures, processes, 

methods, systems or techniques 

including, but not limited to measures 

which * * * reduce the volume of, or 

eliminate emissions of, such pollutants 

through process changes, substitution of 

materials or other modifications * * *.’’ 

The purpose of an energy assessment is 

to identify energy conservation 

measures (such as, process changes or 

other modifications to the facility) that 

can be implemented to reduce the 

facility energy demand from the affected 

boiler which would result in reduced 

fuel use. Reduced fuel use will result in 

a corresponding reduction in HAP, and 

non-HAP, emissions from the affected 

boiler. Reducing the energy demand 

from the plant’s energy using systems 

can result in additional reductions in 

fuel use and associated emissions from 

the affected boilers. We agree that the 

scope of the required energy assessment 

needs to be clarified. However, in the 

proposed Boiler MACT, the intended 

scope of the energy assessment did 

extend beyond the affected boiler. The 

energy assessment did include a 

requirement that a facility energy 

management program be developed. The 

energy assessment was intended to be 

broader than the affected boiler and 

process heater and included other 

systems or processes that used the 

energy from the boiler and process 

heater. We disagree that the scope of the 

energy assessment should be limited to 

the boiler and directly associated 

components such as the feed water 

system, combustion air system, fuel 

system (including burners), blow down 

system, combustion control system, and 

heat recovery of the combustion fuel 

gas. Including the facility’s energy using 

systems and energy management 

practices in the energy assessment can 

identify measures that result in 

decreased fuel use and related emission 

reductions. We have included in this 

final rule a definition of what the energy 

assessment should include for various 

size fuel consuming facilities. We also 

have included a definition of the 

qualified assessors who must be used to 

conduct those energy assessments. 

We also agree that a facility should be 

exempt from the requirement to conduct 

an energy assessment if an energy 

assessment had recently been 

conducted. We have revised this final 

rule to allow facilities to comply with 

the requirement by submitting an energy 

assessment that had been conducted 

within 3 years prior to the promulgation 

date of this final rule. 

C. Rationale for Subcategories 

Many commenters stated that EPA 

should have proposed more 

subcategories, while others believed that 

too many subcategories were proposed. 

Many different issues were raised, and 

some of the key issues that led to 

changes in the rule include: The need 

for a limited use subcategory for boilers 

that operate for only a small percentage 

of hours during a year; the unique 

suspension/grate design of units that 

combust bagasse; the need for a noncontinental liquid fuel subcategory for 

island units that have limited fuel 

options and other unique 

circumstances; and the appropriate 

subcategory for mixed fuel units. The 

comments and EPA responses are 

provided below. 

1. Limited Use Subcategory 

Comment: Industry representatives 

and State and local governments argued 

that limited use units are significantly 

different from steady-state units and 

requested that they have their own 

subcategory. Commenters requested 

various thresholds for a limited-use 

subcategory including 10 percent 

annual capacity factor or 1,000 hours of 

operation per year. Several commenters 

stated that due to their function, limited 

use boilers spend a larger percentage of 

time in startup, shutdown, or other 

reduced-efficiency operating conditions 

than either base-loaded or loadfollowing (continuously operated) units. 

Operating more frequently in these 

conditions makes emissions profiles of 

limited use units very different from 

sources which operate in more efficient 

steady-state modes. Based on this, 

commenters claimed it would be 

technically infeasible for limited-use 

units to meet the proposed emission 

limits. 

In addition to technical reasoning, 

commenters also submitted requests for 

a limited-use subcategory on the basis of 

regulatory precedent, citing the 2010 

RICE MACT and 2004 vacated Boiler 

MACT. Several commenters requested a 

subcategory and work practices similar 

to those in the Stationary RICE 

NESHAP. Several other commenters 

also stated that the subcategory was 

warranted because it was included in 

the previous Boiler MACT rule. These 

commenters argued that EPA had not 

provided any justification for 

eliminating the subcategory in the 

proposed rule. Some of these 

commenters also stated that the 

recordkeeping requirements that were 

proposed in Section 63.7555(d)(3) for 

limited-use boilers and process heaters 

should be the only requirement for these 

units. 

The majority of commenters that 

requested a limited use subcategory also 

requested for EPA to adopt a work 

practice standard for limited use units 

and not subject the subcategory to 

emissions testing or monitoring. 

Commenters argued that EPA has 

acknowledged that there is no proven 

control technology for organic HAP 

emissions from limited use units. 

Limited use units, such as emergency 

and backup boilers, cannot be tested 

effectively due to their limited operating 

schedules. Based on existing test 

methods, which require a unit to 

operate in a steady state, limited use 

units would have to operate for the sole 

purpose of emissions testing. One 

commenter claimed that the proposed 

rule performance testing would require, 

not including startup and stabilization, 

operating at least 15 additional hours of 

per year, or 24 hours per year if testing 

for all pollutants is required. 

Commenters also noted that because the 

operation of these units is neither 

predictable nor routine over a 30 day 

period, back-up boilers would not 

benefit from 30-day emissions 

averaging. Commenters argued that 

establishing numerical standards for 

limited use units is contrary to the goals 

of the CAA and will lead to creating 


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emissions for the sole purpose of 

demonstrating compliance. 

Many commenters also mentioned the 

economic impacts of a numerical limit 

on limited-use units and requested work 

practice standards. Commenters stated 

that it would not be cost effective to 

install controls on units that operate at 

10 percent capacity or less annually. 

They claimed that the additional 

controls would produce minimal 

emission reductions and would result in 

the shutdown of limited-use units. 

Several commenters claimed that the 

current distinction between natural gas 

and oil-fired limited-use units is 

unnecessary, and that additional 

requirements for oil-fired units do not 

produce environmental benefits. 

Commenters recommended that EPA 

create a separate subcategory for limited 

use, oil-fired boilers and suggest that the 

work practice standard proposed for 

gas-fired boilers be applied in lieu of 

emissions standards for these units. 

Other commenters stated that the 

limited use subcategory should include 

new/reconstructed limited use units as 

well as existing units for all fuel 

categories. One commenter 

recommended a tiered approach and 

stated that for very limited use boilers, 

EPA should establish a standard with no 

additional controls or requirements, 

other than monitoring annual hours of 

operation. They defined very limited 

use as <500 hours of operation per year. 

Response: EPA agrees that a 

subcategory for limited use units is 

appropriate for many of the reasons 

stated by the commenters. The fact that 

the nature of these units is such that 

they operate for unpredictable periods 

of time, limited hours, and at less than 

full load in many cases has lead EPA to 

determine that limited use units are a 

unique class of unit based on the unique 

way in which they are used and EPA is 

including a subcategory for these units 

in the final rule. The unpredictable 

operation of this class of units makes 

emission testing for the suite of 

pollutants being regulated 

impracticable. In order to test the units, 

they would need to be operated 

specifically to conduct the emissions 

testing because the nature and duration 

of their use does not allow for the 

required emissions testing. As 

commenters noted, such testing and 

operation of the unit when it is not 

needed is also economically 

impracticable, and would lead to 

increased emissions and combustion of 

fuel that would not otherwise be 

combusted. Therefore, we are regulating 

these units with a work practice 

standard that requires a biennial tuneup, which will limit HAP by ensuring 

that these units operate at peak 

efficiency during the limited hours that 

they do operate. 

2. Combination Grate/Suspension Firing 

Comment: Several commenters 

requested EPA further subcategorize 

boilers and process heaters according to 

combustor design. Three industry and 

collective trade group representatives 

requested EPA consider adding a 

bagasse boiler subcategory. These 

commenters claimed that bagasse 

boilers are different from other biomass 

boilers based on both fuel type and 

boiler design. The commenter suggested 

four factors EPA should consider when 

establishing similar sources or 

subcategories: (1) Do the units in the 

category have comparable emissions; (2) 

are the units structurally similar in 

design; (3) are the units structurally 

similar in size; and, (4) are the units 

capable of installing the same control 

technology. The commenter elaborated 

on the fuel density and moisture of 

bagasse fuel and highlights the unique 

combustor design needed to heat and 

evaporate the moisture from the fuel 

using a combination of suspension and 

grate firing. Several commenters 

requested that EPA set separate 

subcategories for organic HAP (or CO) 

and for metal HAP and PM for bagasse 

boilers (between 48 to 55 percent 

moisture), suspension burners designed 

to burn dry biomass (defined as less 

than 30 percent moisture), suspension 

burners designed to burn wet biomass 

(greater than 30 percent moisture), and 

Dutch ovens. 

One commenter also requested that 

the regulatory definition of bagasse 

boiler be altered to take into account 

that bagasse boilers are hybrid 

suspension and grate/floor-fired boilers 

uniquely designed to dry and burn 

bagasse. The commenter goes on to 

explain that the majority of drying and 

combustion take place in suspension 

and the combustion is completed on the 

grate or floor. The boilers are designed 

to have high heat release rates and high 

excess air rates which are to evaporate 

high fuel moisture content and this 

design impacts CO, PM, and organic 

HAP formation. Under the proposal, 

most bagasse-fired boilers would be 

categorized as ‘‘suspension burners/ 

dutch ovens designed to burn biomass.’’ 

However, the commenter claimed that 

the CO limit for this subcategory was 

driven largely by emissions data from 

units which fire dry biomass (i.e., less 

than 20 to 30 percent moisture fuel) that 

do not need to undergo this initial 

drying process, since the fuel is already 

dry enough to combust. The commenter 

elaborated that emissions of organic 

HAP and PM from these dry biomass 

suspension boilers are much different 

than boilers that must use a 

combination of suspension firing and 

grate firing in order to achieve complete 

combustion of a wet fuel such as 

bagasse. 

One commenter went on the say that 

EPA has inappropriately subcategorized 

suspension burners/dutch ovens 

designed to burn biomass as a single 

subcategory. Hybrid suspension/gratefloor burners are designed such that the 

wet fuel first undergoes drying and then 

combustion in suspension within the 

furnace, with any remaining unburned 

fuel falling onto the grate to complete 

combustion. Another commenter also 

provided technical design elements to 

highlight the differences between dutch 

ovens, suspension burners, and the 

above mentioned hybrid suspension 

grate burners. This commenter indicated 

that dutch ovens have two chambers. 

Solid fuel is dropped down into a 

refractory lined chamber where drying 

and gasification take place in the fuel 

pile. Gases pass over a wall into the 

second chamber where combustion is 

completed. Dutch ovens are capable of 

burning high moisture fuels such as 

bark, but have low thermal efficiency 

and are unable to respond rapidly to 

changes in steam demand. On the 

contrary, suspension burners combust 

fine, dry fuels such as sawdust and 

sander dust in suspension. Rapid 

changes in combustion rate are possible 

with this firing method. This 

commenter added that some dutch oven 

units located at particleboard, 

hardboard, and medium density 

fiberboard plants were misclassified and 

there are less than 30 true dry-fired 

suspension burners in operation, and 

only a small handful of true dutch oven 

boilers. 

Response: EPA agrees that for 

combustion-related pollutants (used as a 

surrogate for organic HAP emissions), 

the design differences for hybrid 

suspension grate boilers (also referred to 

as comination suspension/grate boilers) 

are significant, and that combustion 

conditions in these types of units are 

not similar to those in dutch ovens or 

true suspension burners that combust 

fine, dry fuels. Therefore, EPA has 

added a hybrid suspension grate boiler 

subcategory for CO and dioxin/furan 

emissions. However, the differences 

discussed by the commenters with 

respect to PM are less indicative of the 

design of the boiler and more indicative 

of the types of air pollution controls that 

are used. In keeping with the 

subcategorization approach being used 

for this final rule, these units, and all 

other solid fuel units, will be included 


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in a subcategory for units combusting 

solid fuels for PM, Hg, and HCl. 

3. Non-Continental Units 

Comment: Commenters from affected 

island refineries and trade groups 

representing the petroleum and refining 

sectors requested additional fuel oil 

burning flexibility in this final rule and 

stated that work practice standards are 

more appropriate for fuel oil burning at 

refineries and other remote locations 

without access to natural gas. 

Commenters also submitted technical 

issues justifying the creation of a noncontinental or remote location 

subcategory. One commenter stated that 

most oil combustion in the petroleum 

sector is in locations that are islands or 

in more remote parts of the United 

States. Island and remote facilities 

cannot physically access natural gas 

pipelines, making burning liquid fuels 

unavoidable. The option of crude oil 

shipments would be impractical 

because the ships are limited by size 

and what is manageable by load/ 

discharge ports. The commenter also 

claims that in the time it would take a 

crude ship to arrive, the refinery would 

have produced the amount of crude in 

the shipment. Further, while some units 

at a facility are designed to burn refinery 

fuel gas, the fuel gas produced at a 

refinery is less than the energy required 

to operate the refinery. These noncontinental facilities are also limited to 

the fuel quality provided by their nearby 

crude slate used in the refining process. 

That commenter goes on to say that 

these refineries produce their fuel, the 

HAP metals content of the fuel used 

(particularly residual fuel oil) is a direct 

result of the crude slate used on site. 

The commenter submitted trace metals 

from various crudes to show that the 

content varies substantially between 

crude oils being used on site. 

Another commenter provided the 

following distinctions for noncontinental units: A striking example of 

fuel system differences for noncontinental units is daily variation in 

fuel gas production due to ambient 

temperature fluctuations between night 

and mid-day or resulting from tropical 

rainfall events, coupled with fin fan 

cooling systems that are used because of 

the lack of fresh water available in an 

island without freshwater lakes or 

streams. The fuel system experiences a 

large daily variation in refinery fuel gas 

due to changes in ambient air 

temperature. These changes occur as a 

day-night swing in the refinery or any 

time there is a significant rain storm. As 

the ambient air temperature decreases, 

the amount of propane, butane and 

heavier molecules in the fuel gas 

decreases, as those compounds 

condense out. This results in a change 

in volume and composition (energy 

content) of the refinery fuel gas 

produced which, in the case of rainfall 

events, occurs very quickly and 

unpredictably. This temperature 

variation occurs more frequently than at 

a mainland refinery because: The 

method of cooling on gas compressors 

and distillation column overheads 

systems is ambient air fin fan coolers 

(water with cooling towers is not used 

like a stateside refinery because fresh 

water is not available other than by 

desalination); the refinery fuel gas 

system contains miles of aboveground 

piping (long lines are affected by rain 

and weather conditions); refinery fuel 

gas contains more propane and butane 

than would natural gas from a pipeline 

(which condense at closer to ambient 

temperatures than methane or ethane); 

the make-up fuel system for the refinery 

is not a natural gas pipeline as at a 

stateside refinery. A natural gas pipeline 

can handle changes in refinery fuel gas 

produced because natural gas delivery 

systems are usually large enough to 

handle changes. A temperature change 

of 10 to 15 degrees or a rain storm that 

quickly wets the air fin fans/piping will 

change the volume and composition 

(energy content) of the refinery fuel gas 

produced and also impacts CO 

emissions. 

In addition to the technical 

limitations described above, one 

commenter cited other EPA air 

regulations that have provided separate 

standards or subcategories for noncontinental units. For example, 40 CFR 

part 60 subparts Db and KKKK include 

separate standards for ‘‘non-continental’’ 

units and the 2010 CISWI proposal had 

a subcategory for smaller remote 

facilities because of inherent design and 

operating constraints. 

Another commenter mentions that the 

inability to obtain natural gas removes 

the option of being able to burn only 

gaseous fuels as a compliance strategy 

and burning fuel oil as a supplemental 

fuel makes complying with this 

proposed MACT unfairly onerous. 

Response: EPA agrees that the unique 

considerations faced by non-continental 

refineries warrant a separate 

subcategory for these units. However, 

data were only provided for CO and Hg, 

and, in the absence of data for the other 

pollutants, EPA is adopting the same 

limits that were developed for liquid 

units, because liquid units are the most 

similar units for which data are 

available. EPA assumed that while the 

commenter focused on changes in 

refinery gas, that the commenters 

concern was with liquid fuel-fired units 

whose performance is impacted by the 

co-firing of refinery gas. Regardless, it is 

clear that the unique design of this type 

of unit warrants a separate subcategory 

because design constraints would not 

enable the sources to meet the same 

standards, particularly for CO, as 

stateside units. 

4. Combination Fuel Units 

Comment: Several industries and 

industry representatives in addition to 

some State and local governments 

argued that combination fuel units are 

significantly different from units in 

single fuel subcategories. These 

commenters focused on three types of 

combination fuel units. The first, which 

the majority of comments focused on, 

was biomass and coal co-fired units. 

Commenters stated that classifying units 

that burned 90 percent biomass in the 

coal subcategory if it fired at least 10 

percent heat input coal penalizes and 

discourages the use of biomass. One 

commenter claimed that they were 

unaware of any available control 

technology with the capability of 

reducing emissions from its biomassfired boilers from their current levels to 

the level proposed for the coal stoker 

subcategory. Commenters stated that in 

order to meet the organic HAP limits for 

coal, they would have to switch from 

biomass to more coal or abandon cofiring projects. According to the 

commenter this result was contrary to 

state Renewable Portfolio Standards and 

general national renewable energy 

policy. 

The second type of combination unit 

commenters discussed was units that 

co-fire gas and liquid fuels. Many 

commenters argued that combination oil 

and gas fired units are of a completely 

different design than EPA contemplated 

in setting its standards and cannot be 

fairly included in the same subcategory 

with other dedicated gas or oil fired 

units. Commenters elaborated that the 

main design difference was due to 

combustion techniques which require 

the heater/boiler firebox configuration 

to compromise between the needs of oil 

fuel and gas fuel, making it impossible 

to maximize combustion efficiency or 

minimize NOX emissions. Commenters 

also noted that these units were not 

considered in development of the 

MACT standards, and claimed that they 

are well known in the burner industry 

and referenced in standard literature. 

The third type of combination unit, 

one commenter mentioned, was a 

subcategory for units co-firing biomass 

with any solid fuel. Commenters 

claimed that by failing to recognize the 

wide verity of fuel inputs and thus the 

variation in fuel quality (i.e., BTU and 


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15636 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

moisture content) and emissions, EPA 

was penalizing facilities that use 

multiple fuel streams. The commenter 

went on to request that EPA establish 

emission limits that reflect the variation 

in fuels and fuel quality in these 

combination units. 

Several commenters disagreed with 

the EPA statement that boilers are 

designed to burn only one fuel and that 

unit will encounter operational 

problems if another fuel type is fired at 

more than 10 percent heat input. 

Commenters stated that some boilers are 

specifically designed to burn a 

combination of fuels, and to burn them 

in varying quantities. Commenters 

elaborated that such boilers are not able 

to reach full load on any single fuel and 

that EPA has incorrectly presumed that 

all boilers are designed based on a 

primary fuel. Some commenters 

identified that many of the boilers used 

as the basis of the proposed MACT floor 

emission limits co-fire different fuel 

types. One commenter stated that if 

most units are designed to burn a 

primary fuel and will encounter 

problems if the 10 percent threshold is 

exceeded, then EPA has proposed 

MACT standards that will apply to 

boilers that by their nature are 

‘‘encountering problems’’ due to their 

fuel mix. The commenter requested that 

EPA addresses this inconsistency. 

Many commenters noted that 

emissions profiles vary with the fuel 

which made it very difficult to establish 

a typical emissions profile. Commenters 

also explained that combination fuel 

boilers must often adapt to process 

steam demands and thus experience 

frequent load swings and fuel input 

adjustments that cause significant 

variation in CO emission levels. 

Commenters also mentioned that 

control compatibility should be 

considered for multi-fuel boilers 

because they have inherently different 

control needs depending on the fuels 

being fired. Commenters went on to say 

that current limits are based on control 

equipment that is optimized for one 

HAP or fuel but the affect of other HAP 

and fuels or even another control would 

result in unknown performance and 

compatibility with other fuel types. 

Several commenters also had 

concerns regarding enforcement and 

compliance of combination fuel units. 

One commenter requested that EPA 

more specifically address the 

‘‘enforceability’’ of the ‘‘designed to 

burn’’ classification and more clearly 

consider the implications of the multifuel boiler operation on testing 

considerations. Another commenter 

stated that expressing limits as 

applicable to units ‘‘designed to burn’’ 

certain fuels was problematic and 

should be changed to ‘‘permitted to 

burn’’ because a State permit could limit 

the type of fuels combusted at a unit 

that may have originally been designed 

to burn other fuel types. Other 

commenters claimed that the fuel 

subcategory should be determined by 

the actual quantity of fuel burned not 

what the unit is designed to burn. Some 

questions that commenters requested 

clarification on were: If compliance tests 

would be required under different fuel 

firing conditions, can units with CEMS 

switch limits depending on what fuel is 

being combusted, if ‘‘designed to 

combust’’ is not maintained would 

actual fuel burned or fuel the unit is 

permitted to burn determine the 

subcategory, what would the annual 

performance test be if in the middle of 

the year a unit goes from having burned 

only one type of fuel to only another 

type the rest of the year. 

Several solutions were suggested for 

addressing combination boilers. Some 

commenters requested that combination 

boilers have their own subcategory. 

Several other industry commenters 

suggested that EPA modify the 

subcategory definitions and 

applicability so that combination fuel 

units burning more than 10 percent coal 

with biomass would be regulated under 

the coal subcategory for fuel-based HAP 

and units burning more than 10 percent 

biomass with coal would be regulated 

under the biomass subcategory for 

combustion-based HAP. A more general 

solution proposed, for all types of 

combination fuel units, was that if a 

facility combusts more than one fuel 

type, it must meet the lowest applicable 

emission limit for all of the fuel types 

actually burned. Some commenters also 

requested the development of a formula 

based approach similar to that of the 

boiler NSPS SO2 limits that considers 

the mix of fuel fired rather than 

assuming one fuel dictates the emission 

limitations. 

Some commenters were concerned 

that determination of MACT floor limits 

should be based only on data obtained 

while firing 100 percent of the affected 

fuel category and recommended that 

EPA either exclude all test runs where 

a unit was co-firing or adjust the data 

accordingly to remove the co-firing bias. 

Response: In response to the variety of 

comments regarding combination fuel 

boilers, EPA has revised the 

subcategories in order to simplify 

implementation, improve the flexibility 

of units in establishing and changing 

fuel mixtures, promote combustion of 

cleaner fuels, and provide MACT 

standards that are enforceable and 

consistent with the requirements of 

section 112. For the combination liquid 

and gas-fired units, while the 

commenters provided some insights on 

these units, the data available to EPA 

regarding any distinctions between 

these units and units designed to burn 

liquid only were insufficient to provide 

a justification for changing the approach 

for these units. For combined fuel units 

that combust solid fuels, due to the 

many potential combinations and 

percentages of solid fuels that are or can 

be combusted, for the fuel-based 

pollutants, EPA selected the option of 

combining the subcategories for solid 

fuels into a single solid fuel 

subcategory. For the fuel-based 

pollutants, this alleviates the concerns 

regarding changes in fuel mixtures, 

promotion of combustion of dirtier 

fuels, and the implementation and 

compliance concerns. For combustionbased pollutants (CO and dioxin/furan), 

we maintained the proposed 

subcategories and added a few 

additional subcategories, as discussed 

elsewhere in this preamble, based on 

public comment. One change we are 

finalizing is that to determine the 

appropriate subcategory, instead of 

considering whether the unit is 

designed to combust at least 10 percent 

coal as the first step (as proposed), the 

first step in determining the appropriate 

subcategory is to consider the 

percentage of biomass that is combusted 

in the unit. 

The subcategories for the combustionbased pollutants are now determined in 

the following manner. If your new or 

existing boiler or process heater burns at 

least 10 percent biomass on an annual 

average heat input basis, the unit is in 

one of the biomass subcategories. If your 

new or existing boiler or process heater 

burns at least 10 percent coal and less 

than 10 percent biomass, on an annual 

average heat input basis, the unit is in 

one of the coal subcategories. If your 

facility is located in the continental 

United States and your new or existing 

boiler or process heater burns at least 10 

percent liquid fuel (such as distillate oil, 

residual oil) and less than 10 percent 

coal and less than 10 percent biomass, 

on an annual average heat input basis, 

your unit is in the liquid subcategory. If 

your non-continental new or existing 

boiler or process heater burns at least 10 

percent liquid fuel (such as distillate oil, 

residual oil) and less than 10 percent 

coal and less than 10 percent biomass, 

on an annual average heat input basis, 

your unit is in the non-continental 

liquid subcategory. Finally, for the 

combustion-based pollutants, if your 

unit combusts gaseous fuel that does not 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15637 

qualify as a ‘‘Gas 1’’ fuel, your unit is in 

the Gas 2 subcategory. 

D. Work Practices 

1. Gas 1 Work Practices 

Comment: Several industry and 

industry trade group commenters 

expressed general support for the 

adoption of work practice standards for 

natural gas and refinery gas (Gas 1) fired 

boilers and process heaters. Many of 

these commenters stated that work 

practice standards will minimize HAP 

emissions in a cost effective manner. 

Commenters, including industry 

representatives and one government 

agency, submitted several technical 

justifications that supported the 

proposed work practice standards for 

natural gas and refinery gas units. Many 

of these commenters stated that Gas 1 

units contribute a negligible amount of 

the total emissions from the source 

category. One commenter stated that 

based on a review of air permits issued 

for natural gas-fired units over the last 

10 years no HAP emissions were 

identified at rates which required the 

State to set emission limits. Further, 

many commenters indicated that no 

currently-available control technology 

or technique has been indentified to 

achieve numeric limits for natural gas 

units. Others went on to argue that tuneups actually represent the only ‘‘floor’’ 

technology currently in use at boilers 

and process heaters in the Gas 1 

subcategory. One commenter stated that 

design characteristics of these units, and 

hence the emissions-reduction 

potentials of annual tune-ups, vary 

widely and no single emission rate or 

even percentage of emission reduction 

could be translated into a numerical 

limit. 

Several commenters argued that work 

practice standards were justified based 

on the technical infeasibility of 

emissions testing and the accuracy of 

testing results from gas units. These 

commenters stated that most of the 

emission test data were close to 

detection limits or in some cases 

indistinguishable from ambient air near 

the lowest detect levels, thus preventing 

the limits from being enforced or 

reliably measured. Others argued that 

the application of EPA test methods to 

measure emissions from natural gas 

units results in unreliable data given 

that the emissions are low and below 

what the test methods can detect, 

causing repeat tests or significantly 

lengthening the periods for the tests, 

which in turn increase the cost of 

testing. 

On the contrary, one of the 

environmental advocacy group 

commenters stated that EPA exempted 

natural gas-fired units from CO limits 

without any discussion or analysis. This 

commenter argued that nothing in the 

rulemaking docket showed that 

measurement would be technically 

infeasible and identified CO emission 

test results from over 160 natural gasfired units in the NACAA database. 

Further, the commenter suggested that 

federal, State and local authorities have 

routinely required CO to be measured at 

gas fired units since CO is a criteria 

pollutant under the CAA. 

In addition to technical reasoning, 

many industry and industry 

representative commenters also 

supported the adoption of work practice 

standards on the basis of legal precedent 

and authority under the CAA. 

Commenters stated that EPA derives its 

authority to use work practices in lieu 

of numeric emission limitations from 

two different statutory provisions: The 

narrowly construed provisions of 112(h) 

and the broad authority under 112(d) as 

defined in section 302(k). Additionally, 

one commenter stated that work 

practice standards for Gas 1 units are 

consistent with the D.C. Circuit’s 

opinion in Sierra Club v. EPA on the 

Brick MACT standard, which provided 

guidance on the criteria EPA must meet 

to justify the application of section 

112(h) work practices, only if measuring 

emission levels is technologically or 

economically impracticable. 

Many commenters also cited 

economic justifications supporting the 

proposed work practices for Gas 1 units. 

These comments included claims that 

work practice standards avoid economic 

harm to the manufacturing sector, and 

they added that the cost to control each 

unit would be extremely burdensome 

with minimal benefits to the 

environment. These commenters 

suggested that any type of control 

beyond a tune-up would be a beyondthe-floor option and the complex 

controls needed to achieve such low 

emission levels would fail the costbenefit determination needed to justify 

a beyond-the-floor option. 

On the contrary, two environmental 

advocacy groups submitted comments 

opposing EPA’s rationale for exempting 

Gas 1 units from CO limits on the basis 

of cost. The commenters argued that the 

only economic defense of work practice 

standards that would be justified was if 

economic limitations rendered the 

measurement of emissions 

‘‘impracticable.’’ Further, the 

commenters suggested that many of 

these Gas 1 units would require more 

than a tune-up to achieve comparable 

reductions to those estimated if a 

numeric MACT floor standard was 

required. 

Another commenter representing the 

coal industry also disagreed with EPA’s 

use of a public policy rationale to justify 

a work practice for Gas 1 units instead 

of demonstrating that a work practice 

meets the requirements under section 

112(h). The commenter argued that cost 

considerations were not relevant in a 

MACT floor analysis and they noted 

that the per unit costs of complying 

with MACT standards for gas units are 

lower than the cost for coal units. 

Many commenters from industry, 

industry trade groups, universities, and 

State agencies agreed that emission 

limits would provide a disincentive to 

operate or switch to natural gas and 

refinery gas fired units. Commenters 

claimed that if limits for Gas 1 were 

adopted, units would switch from 

natural gas to electric systems powered 

by coal. Commenters stated that EPA 

correctly concluded that imposing 

emission limitations on gas-fired boilers 

would create a disincentive for 

switching to gas from oil, coal, or 

biomass as a control technique and 

would create an incentive for facilities 

to switch away from gas to other fuels. 

A commenter from a private coal 

company indicated that EPA’s concerns 

that establishing a MACT floor limit for 

Gas 1 units would incentivize fuel 

switching to coal or other fuels 

contradict EPA’s rejection of fuel 

switching as a MACT floor alternative. 

The commenter added that if EPA 

rejected fuel switching because of its 

costliness and lack of a net emissions 

benefit, EPA should want to discourage 

coal units from converting to natural gas 

rather than promoting fuel switching to 

natural gas. This commenter also 

claimed that establishing a work 

practice standard for only Gas 1 units 

discriminated in favor of the use of 

natural gas and against the use of coal. 

The commenter argued that such a 

policy rationale invokes considerations 

that are not relevant in setting MACT 

floor standards and suggested that such 

a rationale is in violation of both CAA 

and the Equal Protection Clause of the 

Constitution. This commenter added 

that the only relevant statutory factor 

under 112(h) to help EPA determine 

where to apply a work practice standard 

was whether the hazardous air pollutant 

cannot be emitted through a conveyance 

designed and constructed to emit or 

capture that pollutant, whether the use 

of such a conveyance would be 

inconsistent with law, or whether the 

application of measurement 

methodology is not practicable due to 

technological and economic limitations. 


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Response: EPA has determined that it 

is not feasible to prescribe numerical 

emissions standards for Gas 1 units 

because the application of measurement 

methodology is not practicable due to 

technological and economic limitations. 

Therefore, EPA is finalizing the work 

practice standards for Gas 1 units. The 

commenters correctly point out that the 

measured emissions from these units are 

routinely below the detection limits of 

EPA test methods, and, as such, EPA 

considers it impracticable to reliably 

measure emissions from these units. 

Even CO, which commenters correctly 

point out was tested at many natural gas 

and refinery gas-fired units, was below 

the level EPA considers to be a reliable 

measurement for more than 80 percent 

of the test runs that were conducted on 

Gas 1 units. The case for other 

pollutants is even more compelling as 

the majority of measurements are so low 

as to cast doubt on the true levels of 

emissions that were measured during 

the tests. Of the 48 test runs for HCl, 98 

percent were below three times the 

maximum reported measurement 

detection level; similarly, 100 percent of 

the Hg runs, and 45 percent of the PM 

data were below three times the 

maximum reported measurement 

detection level. It is unusual to see 

numbers near the detection limit for PM 

since the ‘‘detection’’ involves a 

comparatively simple (compared to 

other test methods) weighing procedure, 

and the overall result indicates that the 

emissions are very close to zero. All of 

the dioxin tests had multiple non-detect 

isomers. Overall, the available test 

methods are greatly challenged, to the 

point of providing results that are 

questionable for all of the pollutants, 

when testing natural gas units. Because 

of these technological limitations that 

render it impracticable to measure 

emissions from Gas 1 units, EPA is also 

unable to establish the actual 

performance of the best performers as 

well as sources outside of the top 

performing 12 percent. The inability to 

accurately measure emissions from Gas 

1 units and the related economic 

impracticability associated with 

measuring levels that are so low that 

even carefully conducted tests do not 

accurately measure emissions warrant 

setting a work practice standard under 

CAA section 112(h). EPA is establishing 

a requirement to implement a tune-up 

program as described in Section III.D of 

this preamble. As noted by many 

commenters, the tune-up program is an 

effective HAP emissions limitation 

technology. The requirement of an 

annual tune-up will allow these units to 

continue to combust the cleanest fuels 

available for boilers while minimizing 

emissions to the same degree that is 

consistent with the operating practices 

of the best performing units in the 

subcategory. 

2. Combining Gas 1 and Gas 2 

Subcategories 

Comment: Several commenters 

requested consolidation of the Gas 1 and 

Gas 2 subcategories into a single gasfired subcategory. The majority of 

commenters supported this concept by 

suggesting that there is very little 

difference between emissions from the 

top performing sources in each of the 

two gas subcategories. One commenter 

specifically argued that in most cases 

the mean emission levels for Gas 2 fuels 

are within range and confidence 

intervals for individual Gas 1 fuels and 

that the differences in fuel 

characteristics do not have a first order 

impact on HAP emissions. The 

commenter reported on 

communications with a facility in the 

database firing a heavy recycle liquid 

and natural gas fuel combination, which 

indicated that this unit is a liquid fuel 

boiler and they provided an analysis of 

the dataset without this heavy recycle 

data where the confidence intervals for 

the remaining landfill gas, biogas/ 

natural gas, and coke oven gas all 

overlap that for Gas 1 fuels. The 

commenter also claimed that if 12 

outliers from two process gas facilities 

are eliminated, the remaining 232 of 244 

CO data points within Gas 2 fuel group 

compare favorably with, even lower 

than, CO levels from Gas 1 fuels. 

Another commenter stated that pilot 

scale and field data studies have 

concluded that emissions of organic 

HAP from gaseous fuels are not 

significantly affected by fuel type. 

In lieu of a single gas subcategory, 

several of the commenters requested 

that the Gas 1 subcategory be expanded 

to include gases similar to natural gas 

and refinery gas. These commenters 

argued, much like the commenters 

advocating for a single gas-fired 

subcategory, that units fired with 

process gases generated in chemical 

plants, pulp and paper plants, iron and 

steel plants, and similar operations 

should be included in the Gas 1 

subcategory because the emissions data 

show very little difference in 

performance. One commenter stated 

that most of the Gas 2 fuels, including 

all 9 of the data points used in the 

proposed floor calculations, are from 

chemical plants. The commenter added 

that at a minimum, chemical plant 

process gas should be grouped with 

refinery gas in Gas 1 and a new floor 

made for Gas 2. One commenter noted 

that EPA did not gather information on 

composition or heating value in the 

Phase 1 ICR survey to justify placing 

chemical process gases in a separate 

subcategory from natural gas and 

refinery gas. Another commenter 

submitted combustion properties of 

refinery gas and petrochemical gas in 

order to argue that they are very similar 

in composition and should be 

categorized with natural gas in the Gas 

1 category. 

In order to accomplish this expansion 

of the Gas 1 subcategory, many 

commenters also addressed the 

definition of natural gas and refinery 

gas. One commenter simply stated that 

all gases derived from hydrocarbon 

sources should be classified under the 

Gas 1 subcategory. Another commenter 

suggested the definition of refinery gas 

in 40 CFR part 63 subpart CC for the 

Petroleum Refineries NESHAP should 

be used in this final rule. The 

commenter went on to say that such 

gases from petrochemical processes 

have similar compositions to those 

stated in the Subpart CC definition (e.g. 

methane, hydrogen, light hydrocarbons, 

and other components) that are used as 

fuel in boilers and process heaters and 

thus should be subcategorized as Gas 1. 

One commenter stated that the 

definition of natural gas should be 

consistent across federal air regulations 

and suggested that the definition of 

natural gas should be edited to be 

consistent with the definition provided 

in 40 CFR Part 60 Subpart Db. Another 

commenter requested that the definition 

of Gas 1 include any boiler or process 

heater burning at least 90 percent 

natural gas, refinery gas, or process offgases with metals and sulfur content 

equal or less than those in natural gas. 

Many other commenters argued that 

in general the definition of natural gas 

needs to be broadened to account for 

non-geological origins of natural gas 

such as landfill gas, biogas, and 

synthetic gas in order to promote the 

use of these renewable fuels. This 

commenter went on to state that the Gas 

1 subcategory excludes biogas and 

process off gases that have no metals 

and very comparable combustion 

characteristics to that of natural gas or 

refinery gas. One commenter argued that 

landfill gas (LFG) should be included in 

Gas 1 with the work practice approach 

because placing it in the Gas 2 

subcategory conflicts with EPA Landfill 

Methane Outreach Program goals. The 

commenter goes on to say that there is 

no assurance that all limits can be 

achieved with control technologies and 

installation of controls will be 

prohibitively expensive and thus LFG 

projects will be stopped or replaced 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15639 

with natural gas. A few commenters 

suggested that EPA did not have enough 

data on combustion of anaerobic 

digester gas to differentiate it from 

natural gas. One commenter requested 

confirmation that biogas under the 

proposed rule would be subject to Gas 

2 emission limits. Another commenter 

requested that EPA separate and clearly 

define gaseous fuels derived from 

biomass and noted that depending on 

the source these fuels can contain 

chlorine or Hg and constituents that 

lead to the formation of dioxins and 

furans. With respect to syngas, one 

commenter suggested that EPA adopt a 

definition similar to that used in the 40 

CFR part 60 subpart YYYY standards for 

stationary combustion turbines. The 

commenter noted that if the purity of 

syngas was a concern, a solution would 

be to require the syngas to meet 

minimum specifications in part 261 of 

the hazardous waste regulations. 

Another commenter requested that 

Integrated Gas Combined Cycle units 

that use a gasifier to convert coal to gas 

and remove impurities before 

combustion be classified under the Gas 

1 subcategory. 

Three commenters specifically argued 

for the inclusion of propane fired boilers 

within the Gas 1 subcategory. One 

commenter stated that if propane meets 

the specifications of ASTM D1835–03a 

or other specification types like the Gas 

Processors Association Standard 2140– 

92 it should be included within the Gas 

1 definition. Another commenter 

requested clarification that boilers firing 

liquefied petroleum gas (LPG) or 

propane-derived synthetic natural gas 

(SNG) as a backup fuel are still 

classified as Gas 1 boilers. The 

commenter argued that propane or LPG 

is mixed with air to make SNG and 

should be considered natural gas for the 

purposes of this final rule. 

Several commenters specifically 

requested that hydrogen plant tail gas or 

similar process gases that are derived 

from natural gas be included in the Gas 

1 subcategory. Commenters argued that 

hydrogen fuels do not contain HAP and 

subcategorizing the fuel as Gas 2 

subjects the units to limits that would 

achieve no further reduction of HAP but 

require extensive performance testing, 

recordkeeping, fuel analysis and 

monitoring requirements. One 

commenter submitted historical facility 

data from a unit firing byproduct 

hydrogen and the commenter claimed 

that the fuel is cleaner burning than 

natural gas. One commenter suggested 

an 8 percent by volume minimum 

hydrogen content in hydrogen-fueled 

process gases as a criterion for 

consideration as a Gas 1 fuel. The 

commenter mentioned that this 

percentage is based on a 1998 EPA 

document that established a minimum 

hydrogen content by volume for nonassisted flare combustion efficiency. 

If a separate Gas 2 subcategory 

remains in the rule, many other 

commenters requested that work 

practices be extended to the Gas 2 

subcategory based on the claim that gasfired units, relative to units firing other 

fuels, have the lowest emissions and 

pose the lowest risk of all the 

subcategories. Thus, the use of gas 

should be encouraged rather than 

discouraged. Some commenters argued 

that as a consequence of establishing 

limits for Gas 2 fuels, some plant sites 

currently designed to use Gas 2 streams 

for energy efficient operations will be 

forced to dispose of process off-gases in 

other types of combustion sources such 

as flares. The commenters added that 

such disposal would result in 

essentially the same emissions from 

combustion of the Gas 2 stream using a 

flare (as opposed to combusting the fuel 

in a boiler) and additional emissions 

from consumption of natural gas that 

would be used in lieu of the Gas 2 fuel. 

Overall, the standard as proposed for 

Gas 2 units would result in increased 

emissions of all pollutants and lower 

fuel efficiency. 

Response: EPA has determined that to 

the extent that process gases are 

comparable to natural gas and refinery 

gas, combustion of those gases in boilers 

and process heaters should be subject to 

the same standards as combustion of 

natural gas and refinery gas. Boilers that 

combust other gaseous fuels that have 

comparable emissions levels to Gas 1 

units are similar in class and type to Gas 

1 units because they share common 

design, operation, and emissions 

characteristics. Therefore, we are 

providing a mechanism by which units 

that combust gaseous fuels other than 

natural gas and refinery gas can 

demonstrate that they are similar to Gas 

1 units and will therefore be subject to 

the standards for Gas 1 units. EPA 

originally examined the possibility of 

basing such a demonstration on levels of 

mercury and chlorine content in the 

gases, but no information was available 

regarding the chlorine content of natural 

gas or refinery gas, and no proven test 

methods were identified to quantify 

chlorine content of natural gas. 

Therefore, EPA is requiring a 

demonstration that other gases have 

levels of H2S and Hg that are no higher 

than those found in Gas 1 units. Natural 

gas purity is commonly defined 

considering the sulfur content of the 

gas, in the form of H2S. Sweet natural 

gas, which is considered pipeline 

quality gas, contains no more than 4 

ppmv H2S. Information on Hg levels 

typical of natural gas was available 

through literature, and domestic natural 

gas Hg concentrations range up to about 

40 micrograms per cubic meter. Using 

H2S and Hg concentration as parameters 

for establishing equivalent 

contamination levels to natural gas, EPA 

is providing a fuel specification that can 

be used by facilities to qualify Gas 2 

units for the Gas 1 standards. The fuel 

specification would also allow facilities 

to perform pre-combustion gas cleanup 

in order to qualify Gas 2 units for the 

Gas 1 standards. Boilers using process 

gases that do not meet the fuel 

specification and are not processed to 

meet the contaminant levels must meet 

the emissions limits for Gas 2 units. 

3. Dioxin/Furan Emission Limits or 

Work Practices 

Comment: Many commenters 

disagreed with the proposed dioxin/ 

furan emission limits. Some 

commenters noted that a large majority 

of the dioxin/furan test data are nondetect values. As such, under section 

112(h)(2)(b) of the CAA, the commenters 

noted that EPA has the authority to 

establish work practice standards when 

‘‘the application of measurement 

methodology to a particular class of 

sources is not practicable due to 

technological and economic 

limitations.’’ Other commenters stated 

that dioxin/furan formation in industrial 

boilers is not well understood and it 

would not be possible to duplicate the 

emissions from the facilities tested 

during the Phase II ICR that were used 

as the basis of the limit. One commenter 

indicated they will undergo preliminary 

research on the dioxin/furan removal 

efficiency of ESP and scrubbers, but 

much additional research is needed. 

Several commenters also added that 

there are no demonstrated technologies 

that would allow the units to reduce 

their emissions below the limit. 

Furthermore, control device vendors 

commented that they would not be able 

to guarantee their equipment will be 

able to control dioxin/furan for the 

affected boilers and process heaters due 

to lack of practical experience on boilers 

and process heaters. They also noted 

that most industry experience in 

controlling dioxin/furan is for waste-toenergy plants where concentrations of 

these pollutants are much higher than 

the reported Phase II ICR testing results. 

Many commenters believe EPA is not 

authorized to regulate the entire dioxin/ 

furan class as is currently proposed. 

They noted that in the section 112 HAP 

list only two compounds are specifically 

named, dibenzofuran and 1,3,7,8 TCDD, 


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and the MACT floor must be limited to 

those two and not all 17 congeners. 

Furthermore, some commenters stated 

that neither the initial EPA source 

category list (EPA–450/3–91–030) or the 

2004 Boiler MACT rule identified 

dioxin/furan as a pollutant to be 

regulated. 

Some commenters stated that 

regulating dioxin/furan emissions from 

these boilers and process heaters is not 

necessary because they are not a 

significant source of emissions. They 

noted that dioxin/furan emissions are 

significantly higher in units that burn 

chlorinated wastes and only those 

applicable rules (e.g. CISWI and 

Municipal Waste Combustors) should 

focus on regulating dioxin/furan. 

Having a limit in this Boiler MACT 

would only cause undue burden with 

minimal environmental impact. Given 

the uncertainties surrounding dioxin/ 

furan emissions, a few commenters 

suggested EPA should do a thorough 

review prior to finalizing limits for this 

final rule to determine how this source 

category affects public health. It is 

suggested that EPA review the following 

questions: What portions of the annual 

total dioxin/furan emissions are 

contributed by this source category; 

what are the other major sources of 

dioxin/furan throughout the country; 

what are the current conditions for 

dioxin/furan exposure throughout the 

U.S.; have levels been going down or 

changing and if so by how much; and, 

could reductions be achieved more 

effectively by examining other sources 

of dioxin/furan? 

In lieu of a specific dioxin/furan limit, 

many commenters suggested that CO 

should be used as a surrogate and 

meeting the CO limit would reduce 

dioxin/furan. While EPA stated in the 

preamble to the proposed rule that it is 

not appropriate to use CO as a surrogate, 

these commenters stated that the 

precursors to dioxin/furan formation are 

produced by incomplete combustion 

and thus dioxin/furan formation itself is 

indirectly related to the combustion 

process similar to the other organic HAP 

CO is currently used as a surrogate for. 

Another commenter suggested that 

control of other HAP such as Hg will 

provide adequate incidental control and 

reduction of dioxin/furan and the cost 

of separately monitoring dioxin/furan is 

not warranted taking into consideration 

the cost of achieving such emission 

reductions, energy requirements, and 

environmental impacts as required by 

Section 112(d)(2) of the CAA. 

On the contrary, another commenter 

suggested that EPA correctly recognized 

that dioxin/furan can be formed outside 

of the combustion unit, not as part of 

the combustion process, and so sets 

separate standards for these 

carcinogens. 

Several commenters provided specific 

comments on a lack of data available for 

boilers burning bagasse in a combined 

suspension and grate firing design. 

As an alternative to the limits, many 

commenters offered suggestions for a 

work practice standard to minimize 

dioxin/furan emissions. These 

comments focused on creating boilerspecific plans for implementing good 

combustion practices along with an 

operations and maintenance plan. 

Additionally, boiler operators could 

maintain a minimum temperature at the 

outlet of PM control devices to 

minimize dioxin/furan formation. 

Response: In response to the 

comments that EPA is not authorized to 

regulate the dioxin/furan class as 

proposed, the commenters are incorrect. 

While dibenzofuran and 2,3,7,8 TCDD 

are two of the HAP listed in section 112, 

all dioxin and furan compounds are 

considered to be POM and, as such, EPA 

has the authority to regulate these 

compounds under section 112. The riskrelated questions suggested by 

commenters are not applicable to 

establishment of the MACT floor 

standards under section 112(d), which 

are to be based on the average emissions 

performance of the best performing 

units for which the Administrator has 

emissions information. EPA received a 

number of comments on dioxin and 

furan emission limits regarding the 

ability of the test method to measure the 

typically low levels of emissions that 

are emitted from boilers and process 

heaters. 

Commenters stated that the emissions 

were so low that they could not be 

measured, and therefore work practice 

standards, rather than emission limits, 

should be finalized for dioxin/furan for 

all subcategories. EPA disagrees. While 

emissions were below detectable levels 

in many tests for a large portion of the 

dioxin/furan isomers, virtually every 

test detected some level of dioxin/furan. 

Furthermore, some of the emission tests 

detected most or all isomers at some 

level. Dioxin/furan emissions can be 

precisely measured for at least some 

units in each subcategory except for Gas 

1. Therefore, except for the Gas 1 

subcategory, which is addressed 

elsewhere in this preamble, the 

statutory test for establishment of work 

practice standards—i.e., that 

measurement of emissions is 

impracticable due to technological and 

economic limitations—is not met. 

In order to make sure that the 

emission limits are set at a level that can 

be measured, EPA used the ‘‘three times 

MDL’’ approach (discussed elsewhere in 

this preamble) as a minimum level at 

which a dioxin/furan emission limit is 

set. Rather than finalizing work practice 

standards, but recognizing that 

emissions tend to be very low compared 

to more significant sources of dioxin 

such as incinerators, EPA’s approach to 

dioxin requires an initial compliance 

test to demonstrate that the units meet 

the dioxin/furan standard, and no 

additional compliance testing. 

Following a test demonstrating 

compliance with the emission limit, 

provided that the unit’s design is not 

modified in a manner inconsistent with 

good combustion practices, the oxygen 

level must be monitored, and the 12- 

hour block average must be maintained 

at or above 90 percent of the level 

established during the initial 

compliance test in order to provide an 

assurance of good combustion. Another 

important point to mention is that the 

dioxin/furan test method, EPA Method 

23, requires that for compliance 

purposes, non-detect values should be 

counted as zero. Therefore, for purposes 

of compliance, the concern about not 

being able to meet the standards because 

of the contribution of non-detect values 

is moot. 

4. Work Practices for Small Units 

Comment: Many commenters stated 

EPA should treat new small units in the 

same manner as existing small units; for 

boilers and process heaters with a 

design capacity less than 10 MMBtu/hr, 

a work practice standard should be 

implemented instead of numerical 

limits. These commenters stated that the 

same technical and economic 

conditions under section 112(h) for 

existing units still held true for new 

units. New small boilers and process 

heaters (less than 10 mmBtu/hr) are 

typically designed like comparable 

existing units with small diameter 

stacks, or wall vents and no stack. These 

vents and small stacks do not allow for 

accurate application of standard EPA 

test methods required to demonstrate 

compliance with emission limits, and 

larger stacks would decrease the 

efficiencies of the units. They continued 

that while there are some savings in 

adding the controls and monitoring 

equipment during original construction, 

those savings were minor in comparison 

to the cost of the control and monitoring 

equipment itself. One commenter noted 

that the annual performance tests are 

over three times the cost of the boiler. 

In addition, other commenters stated 

that the D.C. Circuit has upheld EPA’s 

discretion to have insignificant emission 

sources exempt from regulations, and 

small units meet this condition. 


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Several of the commenters who 

supported work practice standards for 

small units also believed the size 

threshold should change. A few 

commenters suggested the size should 

be lowered to 5 MMBtu/hr, while most 

contended that the size threshold 

should be raised to 20, 25, or 30 

MMBtu/hr. Those commenters who 

wanted the threshold raised noted that 

even boilers as large as 30 MMBtu/hr 

experience the same economic 

implications on their facilities. Some 

commenters also noted that 40 CFR part 

60 subpart Dc New Source Performance 

Standards have work practice standards 

for units less than 30 MMBtu/hr. One 

State agency commented that the 

proposed rule established stringent 

emission limits for new small units. The 

commenter argued that a tiered 

approach should be used which 

required higher emission limits for new 

small units. 

Conversely, some commenters agreed 

with EPA’s proposed method of making 

the limits applicable to new small units. 

They noted that new boilers can be built 

with stacks appropriate for testing, or 

can have temporary stack extensions 

built for testing. One commenter added 

that it is not uncommon for new small 

boilers to vent exhaust into existing 

larger stacks that would allow for 

testing. 

Response: We agree that the design of 

new and existing small units precludes 

the use of the suite of test methods 

required by this final rule. As pointed 

out by commenters, new small boilers 

and process heaters (less than 10 

mmBtu/hr) are typically designed like 

comparable existing units with small 

diameter stacks, or wall vents and no 

stack. These vents and small stacks do 

not allow for accurate measurement of 

emissions using the standard EPA test 

methods required to demonstrate 

compliance with emission limits, and 

larger stacks would decrease the 

efficiencies of the units. Changes in 

stack diameters or addition of stacks in 

lieu of wall vents can impact 

efficiencies of boilers and can require 

significant redesign of boiler systems, 

which imposes significant economic 

limitations. Therefore, EPA has 

concluded that work practice standards 

are appropriate for new and existing 

small units because the measurement of 

emissions is impracticable due to 

technological and economic limitations. 

E. New Data/Technical Corrections to 

Old Data 

Comment: Many commenters 

identified shortcomings in EPA’s 

emissions database, and multiple 

corrections were submitted to EPA both 

through the public comment process 

and through e-mail communication with 

the ICR Combustion Survey team. 

Commenters also submitted new data 

directly to the ICR Combustion Survey 

Team and through the public comment 

process. 

Response: EPA has incorporated all 

technical corrections and new data 

submitted since proposal. The 

corrections and new data are described 

in detail in a memorandum in the 

docket entitled ‘‘Handling and 

Processing of Corrections and New Data 

in the EPA ICR Databases.’’ 

F. Startup, Shutdown, and Malfunction 

Requirements 

Comment: Numerous commenters 

raised concerns that insufficient data are 

currently available to establish emission 

standards for SSM events. Due to 

inherent limitations with measurement 

methods/technologies, which often 

require steady state conditions, 

emissions testing data and CEMS 

provide limited insight into SSM events, 

therefore combustor variability during 

these periods has been underestimated. 

To address these data limitations, 

several commenters suggested that EPA 

should collect additional data that 

represent SSM events within each 

subcategory. One commenter had 

specific ideas for data collection 

including collecting SSM data from 

CEMS installed at the facilities 

previously included in the ICR survey 

and using portable analyzers to evaluate 

SSM emissions during future 

compliance testing. Many other 

commenters suggested that it would be 

infeasible to collect additional data 

given the test method limitations and 

suggested that a compliance work 

practice alternative be provided during 

periods of SSM. Commenters suggested 

that work practices should be sitespecific, not be overly prescriptive, with 

the goal of minimizing the emissions 

during SSM periods. Other commenters 

suggested that EPA adopt an alternative 

to regulating emissions during SSM 

events and cited 40 CFR part 63 subpart 

ZZZZ, which states that startup time 

must be minimized. 

Several commenters expressed 

separate concerns for EPA’s treatment of 

malfunction events. Many commenters 

suggested that malfunction events 

should be excluded from emission 

limits and many submitted alternatives 

to including these periods. One 

commenter supported a limited 

allowance for malfunction periods 

where EPA defines the term 

‘‘malfunction’’ and precisely identifies 

events requiring an immediate and 

complete shutdown. Another 

commenter suggested EPA should 

require facilities to develop and 

implement work practice standards to 

reduce malfunctions and minimize 

pollutants emitted during these periods. 

A third commenter asked that EPA 

replicate California permits which 

include a specific provision for 

malfunction. 

Many industry commenters 

recognized that the proposal preamble 

included a statement indicating that 

EPA promised to address periods of 

equipment malfunction by considering 

other information before enforcing 

exceedance of operating limits. 

However, the commenters suggested 

that this promise does not prevent EPA, 

a State, or a plaintiff in a citizen suit 

from determining that an exceedance 

during a malfunction constitutes a 

violation. These commenters preferred 

EPA to develop explicit compliance 

alternatives for malfunctions in the rule 

language. 

Several commenters contended that 

EPA failed to recognize the inherent 

limitations in the technology and 

operating conditions used to reduce 

emissions during SSM. One commenter 

referenced a case (Portland Cement 

Ass’n v. Ruckelshaus (D.C. Cir. 1973)) 

where the court acknowledged that 

‘‘startup’’ and ‘‘upset’’ conditions due to 

plant or emission device malfunction 

are an inescapable aspect of industrial 

life and that allowance must be 

accounted for in the standards. Aside 

from meeting emission limits, 

commenters provided examples of other 

operating parameters that are affected 

during SSM including: Elevated oxygen 

levels, air pollution control device 

operating parameters such as sorbent 

injection rates or ESP voltage, and fuel 

feed rates, among others. Commenters 

also raised concerns that applying limits 

during startups will require sources to 

decide between safety and 

environmental compliance by 

encouraging sources to try to shorten the 

startup period. For example, some 

commenters noted that decreasing the 

warm-up period could cause 

metallurgical and refractory stresses on 

the boiler. One commenter indicated 

that EPA’s proposed rule had 

unnecessarily disregarded the special 

circumstance, an affirmative defense, of 

excess emissions allowed in a 

September 20, 1999, EPA policy memo 

about State Implementation Plans (SIP). 

The commenter added that affirmative 

defense provisions have recently been 

approved into several states SIP (e.g., 

Colorado [71 FR at 8959] and New 

Mexico [74 FR at 46912]). Both the 

Colorado SIP and the New Mexico SIP 

contain an affirmative defense for excess 


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emissions during periods of startup and 

shutdown. 

Response: EPA has considered these 

comments and has revised this final rule 

to incorporate a work practice standard 

for periods of startup and shutdown. 

Information provided on the amount of 

time required for startup and shutdown 

of boilers and process heaters indicates 

that the application of measurement 

methodology for these sources using the 

required procedures, which would 

require more than 12 continuous hours 

in startup or shutdown mode to satisfy 

all of the sample volume requirements 

in the rule, is impracticable. Upon 

review of this information, EPA 

determined that it is not feasible to 

require stack testing—in particular, to 

complete the multiple required test 

runs—during periods of startup and 

shutdown due to physical limitations 

and the short duration of startup and 

shutdown periods. Operating in startup 

and shutdown mode for sufficient time 

to conduct the required test runs could 

result in higher emissions than would 

otherwise occur. Based on these specific 

facts for the boilers and process heater 

source category, EPA has developed a 

separate standard for these periods, and 

we are finalizing work practice 

standards to meet this requirement. The 

work practice standard requires sources 

to minimize periods of startup and 

shutdown following the manufacturer’s 

recommended procedures, if available. 

If manufacturer’s recommended 

procedures are not available, sources 

must follow recommended procedures 

for a unit of similar design for which 

manufacturer’s recommended 

procedures are available. 

Regarding comments on treatment of 

malfunctions, the discussion of EPA’s 

position on malfunctions in the section 

of this preamble entitled ‘‘What are the 

requirements during periods of startup, 

shutdown, and malfunction’’ provides 

details related to this response. 

Essentially, EPA has determined that 

malfunctions should not be viewed as a 

distinct operating mode and, therefore, 

any emissions that occur at such times 

do not need to be factored into 

development of CAA section 112(d) 

standards, which, once promulgated, 

apply at all times. In the event that a 

source fails to comply with the 

applicable CAA section 112(d) 

standards as a result of a malfunction 

event, EPA would determine an 

appropriate response based on, among 

other things, the good faith efforts of the 

source to minimize emissions during 

malfunction periods, including 

preventative and corrective actions, as 

well as root cause analyses to ascertain 

and rectify excess emissions. EPA 

would also consider whether the 

source’s failure to comply with the CAA 

section 112(d) standard was, in fact, 

‘‘sudden, infrequent, not reasonably 

preventable’’ and was not instead 

‘‘caused in part by poor maintenance or 

careless operation.’’ 40 CFR 63.2 

(definition of malfunction). 

Finally, EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause an 

exceedance of the relevant emission 

standard. (See, e.g., State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(Sept. 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (Feb. 

15, 1983)). EPA is, therefore, adding to 

this final rule an affirmative defense, as 

requested by public comment, to civil 

penalties for exceedances of numerical 

emission limits that are caused by 

malfunctions. 

G. Health Based Compliance 

Alternatives 

Comment: In the proposed rule, EPA 

considered whether it was appropriate 

to exercise its discretionary authority to 

establish health-based emission limits 

(HBEL) under section 112(d)(4) for HCl 

and other acid gases and proposed not 

to adopt such limits, citing, among other 

things, information gaps regarding 

facility-specific emissions of acid gases, 

co-located sources of acid gases and 

their cumulative impacts, potential 

environmental impacts of acid gases, 

and the significant co-benefits expected 

from the adoption of the conventional 

MACT standard. Comments were 

received both supporting this position 

and refuting it. Several commenters 

suggested legal, regulatory and scientific 

reasons for why HBEL or health-based 

compliance alternatives (HBCA) for HCl 

and Mn might be appropriate for this 

MACT standard. With respect to legal 

concerns, industry commenters 

indicated that section 112(d)(4) of the 

CAA establishes a mechanism for EPA 

to exclude facilities from certain 

pollution control regulations and 

circumstances when these facilities can 

demonstrate that emissions do not pose 

a health risk. Commenters cited a Senate 

Report that influenced development of 

112(d)(4), where Congress recognized 

that, ‘‘For some pollutants a MACT 

emissions limitation may be far more 

stringent than is necessary to protect 

public health and the environment.’’ 

[Footnote: S. Rep. No. 101–128 (1990) at 

171]. Commenters also cited regulatory 

precedence for addressing HCl as a 

threshold pollutant, including the 

Hazardous Waste Combustors and the 

Chemical Recovery Combustion Sources 

at Kraft, Soda, Sulfite, and Stand-Alone 

Semichemical Pulp Mills NESHAP. 

Commenters requested that EPA 

incorporate the flexibility afforded by 

112(d)(4) and allow sources reasonable 

means for demonstrating that their 

respective emissions do not warrant 

further control. Industry commenters 

also cited the 2004 vacated Boiler 

MACT as precedence for HBCA for both 

HCl and Mn. The commenters 

contended that EPA failed to explain 

why the health based emissions 

limitations it established in the 2004 

Boiler MACT and the justification 

provided for those limitations should 

now be reversed. The commenters also 

cited a 2006 court briefing where EPA 

vigorously defended the HBCA included 

in the 2004 rule when it was challenged 

in the D.C. Circuit [Final Brief For 

Respondent United States 

Environmental Protection Agency, D.C. 

Cir. Case No. 04–1385 (Dec. 4, 2006) at 

59–65, 69.]. 

Citizen groups also commented that 

on August 6, 2010, EPA adopted a 

NESHAP for Portland Cement plants. In 

its final rule EPA specifically rejected 

adoption of risk-based exemptions for 

HCl and Mn. The commenter argues 

there are no differences sufficient to 

warrant a reversal of that decision in the 

Boiler MACT standard. Citizen groups 

also raised concerns that health risk 

information cited by EPA for HCl, 

hydrogen fluoride, hydrogen cyanide, 

and Mn does not establish ‘‘an ample 

margin of safety’’ and, therefore, no 

health threshold should be established. 

The commenters believe risk-based 

exemptions at levels less stringent than 

the MACT floor are prone to lawsuits 

that could potentially further delay 

implementation of the Boiler MACT. 

Co-Located Source Issues 

Many commenters responded to EPA 

comment solicitation on how it should 

‘‘appropriately’’ simulate all reasonable 

facility/exposure situations. 

Commenters contended that boilers can 

be located among a wide variety of 

industrial facilities, which makes 

predicting and assessing all possible 

mixtures of HCl and other emitted air 

pollutants difficult. These simulations 

would require the consideration of 

emissions from nearby facilities for the 

almost 15,500 boilers affected by this 

final rule. Commenters also 

characterized defining of exposure 

situations as challenging, for example 

PM can serve as ‘‘carriers’’ to bring the 

adhered HAP deep within the lung, 

where the HAP can interact with the 

respiratory system directly or be leached 


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off of the particle surface and become 

available systemically. These 

commenters argue that the questions 

posed by the Agency in the preamble to 

the proposed rule illustrate why the 

MACT standard setting is and should be 

the default requirement in the 1990 

Clean Air Act, rather than ‘‘healthbased’’ standard-setting under section 

112(d)(4). 

Some commenters disagreed with 

using a hazard quotient (HQ) approach 

to establish a risk-based standard 

because the HQ would not account for 

potential toxicological interactions. The 

commenter noted that an HQ approach 

incorrectly assumes the different acid 

gases affect health through the same 

health endpoint, rather than assuming 

that the gases interact in an additive 

fashion. This commenter suggested that 

a hazard index approach, as described 

in EPA’s ‘‘Guideline for the Health Risk 

Assessment of Chemical Mixtures’’ 

would be more appropriate. 

Industry commenters dispute that 

emissions from other sources or source 

categories should be considered when 

developing an HBCA and they argued 

that Congress expected EPA to consider 

the effect of co-located facilities during 

the 112(f) residual risk program instead 

of under 112(d). Commenters added that 

there is no prior EPA precedent for 

considering co-located facilities from a 

different source category during the 

same 112 rulemaking. Commenters also 

provided examples where co-located 

sources and source categories are not a 

concern, such as small municipal 

utilities that do not operate co-located 

HAP sources within their fence line and 

are not located in heavily populated 

urban areas where other HAP sources 

are common due to zoning. 

Representatives of the small municipal 

utility industry suggested that concerns 

of co-located HAP sources should not be 

used to arbitrarily deny health-based 

relief already approved on a site-specific 

basis. 

Co-Benefits of Controlling HCl and Mn 

Several commenters disputed EPA’s 

consideration of non-HAP collateral 

emissions reductions in setting MACT 

standards. They contended that EPA’s 

sole support for its ‘‘collateral benefits’’ 

theory is legislative history—the Senate 

Report that accompanied Senate Bill 

1630 in 1989 and noted that the D.C. 

Circuit rejected this use of this theory 

since the Senate Report referred to an 

earlier version of the statute that was 

ultimately not enacted. Instead 

commenters suggested that other 

components of the CAA, such as the 

National Ambient Air Quality Standards 

(NAAQS), are more appropriate avenues 

for mitigating emissions of criteria 

pollutants. Some commenters in the 

biomass industry noted that even if cobenefits of non-HAP were considered 

relevant to the analysis, the nominal cobenefits of reducing SO2 emissions from 

biomass units would be limited due to 

the low inlet sulfur levels of this fuel. 

Several other commenters suggested it 

is impossible to assess an established 

health threshold for HCl such that a 

112(d)(4) standard could be set without 

evaluating the collateral benefits of a 

MACT standard. And, as described in 

the recently finalized cement kiln 

MACT rule, setting technology-based 

standards for HCl will result in 

significant reductions in the emissions 

of other pollutants, including SO2, Hg, 

and PM. The commenter added that 

these reductions will provide enormous 

health and environmental benefits, 

which would not be experienced if 

section 112(d)(4) standards had been 

finalized. These commenters contended 

that HCl and other dangerous acid gases 

produced by commercial and industrial 

boilers pose substantial risks to 

industrial workers, as well as 

surrounding communities, and must be 

limited by the strict conventional MACT 

standards. 

Cost Impacts of HBCA 

Several commenters indicated that the 

current economic climate requires EPA 

to balance economic and environmental 

interests and they indicated that HBCA 

would help target investments into 

solving true health threats where limits 

are no more stringent or less stringent 

than needed to protect public health. 

Many commenters provided compliance 

cost savings if an HBCA is included in 

this final rule. For example, 

representatives of one industry 

estimated aggregated capital savings in 

excess of $100 million just for the small 

facilities in the pulp & paper sector. 

Some commenters stressed the 

importance of an HBCA options for 

small entities affected by the 

regulations. Several other commenters 

suggested that EPA should estimate the 

costs and environmental effects of the 

HBCA option compared to a 

conventional MACT standard in order 

to make an informed decision on the 

adoption of an HBCA. 

Response: After considering the 

comments received, some of which 

supported adoption of an emissions 

standard under section 112(d)(4) and 

some of which opposed such a standard, 

EPA has decided not to adopt an 

emissions standard based on its 

authority under section 112(d)(4) in the 

final rule. EPA first notes that the 

Agency’s authority under section 

112(d)(4) is discretionary. That 

provision states that EPA ‘‘may’’ 

consider established health thresholds 

when setting emissions standards under 

section 112(d). By the use of the term 

‘‘may,’’ Congress clearly intended to 

allow EPA to decide not to consider a 

health threshold even for pollutants 

which have an established threshold. As 

explained in the preamble to the 

proposed rule, it is appropriate for EPA 

to consider relevant factors when 

deciding whether to exercise its 

discretion under section 112(d)4). EPA 

has considered the public comments 

received and is not adopting an 

emissions standard under section 

112(d)(4) for the reasons explained 

below. 

First, as explained in the preamble to 

the proposed rule, EPA continues to 

believe that the potential cumulative 

public health and environmental effects 

of acid gas emissions from boilers and 

other acid gas sources located near 

boilers supports the Agency’s decision 

not to exercise its discretion under 

section 112(d)(4). EPA requested in the 

preamble to the proposed rule 

information regarding facility-specific 

emissions of acid gases from boilers as 

well as sources which may be co-located 

with boilers. In particular, information 

concerning the variation of acid gas 

emission rates that can be expected from 

the various subcategories of units was 

identified as a significant data gap. 

Additional data were not provided 

during the comment period, and the 

data already in hand regarding these 

emissions are not sufficient to support 

the development of emissions standards 

for any of the boilers subcategories 

under section 112(d) that take into 

account the health threshold for acid 

gases, particularly given that the Act 

requires EPA’s consideration of health 

thresholds under section 112(d)(4) to 

protect public health with an ample 

margin of safety. In addition, the 

concerns expressed by EPA in the 

proposal regarding the potential 

environmental impacts and the 

cumulative impacts of acid gases on 

public health were not assuaged by the 

comments received. 

EPA also received comments 

recommending not only that EPA 

establish emissions standards for acid 

gases pursuant to section 112(d)(4), but 

that it do so by excluding specific 

facilities from complying with 

emissions limits if the facility 

demonstrates that its emissions do not 

pose a health risk. EPA does not believe 

that a plain reading of the statute 

supports the establishment of such an 

approach. While section 112(d)(4) 

authorizes EPA to consider the level of 


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7EPA notes the support of commenter 2898 in 

this regard. 

the health threshold for pollutants 

which have an established threshold, 

that threshold may be considered ‘‘when 

establishing emissions standards under 

[section 112(d).]’’ Therefore, EPA must 

still establish emissions standards under 

section 112(d) even if it chooses to 

exercise its discretion to consider an 

established health threshold. 

As explained in the preamble to the 

proposed rule, EPA also considered the 

co-benefits of setting a conventional 

MACT standard for HCl. EPA 

considered the comments received on 

this issue and continues to believe that 

the co-benefits are significant and 

provide an additional basis for the 

Administrator to conclude that it is not 

appropriate to exercise her discretion 

under section 112(d)(4). EPA disagrees 

with the commenters who stated that it 

is not appropriate to consider non-HAP 

benefits in deciding whether to invoke 

section 112(d)(4). Although MACT 

standards may directly regulate only 

HAPs and not criteria pollutants, 

Congress did recognize, in the 

legislative history to section 112(d)(4), 

that MACT standards would have the 

collateral benefit of controlling criteria 

pollutants as well and viewed this as an 

important benefit of the air toxics 

program. See S. Rep. No. 101–228, 101st 

Cong. 1st sess. at 172. EPA consequently 

does not accept the argument that it 

cannot consider reductions of criteria 

pollutants, for example in determining 

whether to take or not take certain 

discretionary actions, such as whether 

to adopt a risk-based standard under 

section 112(d)(4). There appears to be 

no valid reason that, where EPA has 

discretion in what type of standard to 

adopt, EPA must ignore controls which 

further the health and environmental 

outcomes at which section 112(d) of the 

Act is fundamentally aimed because 

such controls not only reduce HAP 

emissions but emissions of other air 

pollutants as well.7 Thus, the issue 

being addressed is not whether to 

regulate non-HAP under section 112(d) 

or whether to consider other air quality 

benefits in setting section 112(d)(2) 

standards—neither of which EPA is 

doing—but rather whether to make the 

discretionary choice to regulate certain 

HAP based on the MACT approach and 

whether EPA must put blinders on and 

ignore collateral environmental benefits 

when choosing whether or not to 

exercise that discretion. EPA knows of 

no principle in law or common sense 

that precludes it from doing so. 

Finally, EPA is not adopting an HBEL 

for manganese, as some commenters 

recommended. EPA did not propose or 

solicit comment on the adoption of an 

HBEL for manganese emissions, and 

since the final rule regulates PM as a 

surrogate for HAP metals and therefore 

does not establish a specific emissions 

limit for manganese, there is no reason 

to consider whether it would be 

appropriate to exercise section 112(d)(4) 

authority for manganese. 

H. Biased Data Collection From Phase II 

Information Collection Request Testing 

Comment: Many commenters noted 

that in selecting units for the Phase II 

testing, EPA targeted only those units 

whose data EPA determined it would 

need to set the MACT floor. The 

commenters contended that the targeted 

units were generally better performing 

units so the proposed limits reflect 

performance of the best 12 percent of 

the best rather than performance of the 

best 12 percent of the entire population 

as Congress intended. Further, they 

added that this skewed dataset led to a 

set of proposed emission limits that are 

more stringent than would have resulted 

from a random sampling of all the 

regulated sources. Several commenters 

also provided input on how EPA should 

have designed its Phase II test plan in 

order to develop a representative 

dataset. They added that 

representativeness may be considered as 

the measure of the degree to which data 

accurately and precisely represent a 

characteristic of a population. The 

commenters identified EPA’s approach 

for selecting Phase II testing sites as a 

form of judgmental sampling, which 

EPA defines as the ‘‘selection of 

sampling units on the basis of expert 

knowledge or professional judgment.’’ 

These commenters then cited an EPA 

document (Data Quality Assessment: A 

Reviewer’s Guide, EPA QA/G–9R, p. 11, 

U.S. EPA 2006) which outlines 

preferred sampling procedures for 

emission data. According to this 

document, probabilistic sampling 

(random selection) is preferable where 

EPA wishes to draw quantitative 

conclusions about the sampled 

population through statistical 

inferences. When using judgmental 

sampling, however, this document 

stated that ‘‘statistical analysis cannot be 

used to draw conclusions about the 

target population,’’ and ‘‘quantitative 

statements about the level of confidence 

in an estimate (such as confidence 

intervals) cannot be made.’’ Yet the 

commenters point out that EPA did use 

the Phase II data to perform statistical 

analyses and establish a MACT floor 

emission limit for each subcategory. The 

commenters added that generally, 

conclusions drawn from judgmental 

samples apply only to those individual 

samples while aggregation of data 

collected from judgmental samples may 

result in severe bias due to lack of 

representativeness and lead to highly 

erroneous conclusions. Many 

commenters also suggested methods to 

mitigate the bias in the Phase II testing. 

Some commenters suggested that 

instead of taking the top 12 percent of 

units with stack test data available, EPA 

should determine how many units 

comprise the top 12 percent of a given 

subcategory and then use data from that 

many units to compute the floor. The 

commenters suggested that this 

approach is warranted because the 

Phase I ICR data allowed EPA to reliably 

select the top performers in each 

subcategory for purposes of collecting 

the Phase II information. Other 

commenters suggested that EPA 

supplement its ICR survey and testing 

data with other data sources such as fuel 

records, production records and 

associated emission factors from AP–42, 

commercial warranties and guarantees, 

or other EPA databases such as the 

National Emission Inventory or Toxics 

Release Inventory. Other commenters 

requested that EPA incorporate data 

from the ICR Phase II testing as long as 

these data are from a unit that has 

similar fuel and control device 

characteristics to the units identified in 

the top 12 percent. 

Response: Section 112 specifies that 

MACT floors must be based on sources 

for which emissions information is 

available to the Administrator. While 

EPA’s Phase II data collection did target 

units with particular control 

configurations, these units were 

identified to fill data gaps, including 

providing additional information on the 

effectiveness of the various control 

technologies that are used to control 

emissions from boilers and process 

heaters. EPA disagrees with commenters 

who recommended that EPA should use 

data from the number of units that 

comprise 12 percent of a subcategory to 

calculate the floor, even where the 

Agency lacks information for all sources 

in the subcategory. That approach 

would be inconsistent with the language 

of section 112(d)(3), which clearly states 

that, for existing sources, the MACT 

floor cannot be less stringent than ‘‘the 

average emission limitation achieved by 

the best performing 12 percent of the 

existing sources (for which the 

Administrator has emissions 

information)[.]’’ This is precisely what 

EPA has done in today’s final rule. The 

commenters’ recommended approach 

would instead base the floors on the 

average emission limitation achieved by 


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all the sources for which EPA has 

emissions information, rather than that 

achieved by the best-performing 12 

percent, if emissions information is only 

available for 12 percent of sources. This 

outcome would contradict the language 

of the statutory MACT floor provision. 

EPA also notes that sources had 

ample opportunity to perform testing on 

other units and submit the data to EPA 

for consideration. EPA informed various 

industry groups that additional test data 

would be welcomed, and to the extent 

that additional data were provided, such 

data were used in the floor-setting 

process. Furthermore, the large majority 

of the proposed emission limits were 

based on data from both phases of the 

ICR, with most of the data coming from 

the phase I ICR, in which EPA requested 

any existing emissions data, and 

commenters do not allege any bias 

associated with the phase I data. The 

only emission limits that were based 

primarily on phase II ICR data were the 

dioxin/furan limits, and for those 

pollutants, the units were not selected 

based on any assumptions about their 

dioxin/furan emissions or the 

effectiveness of add-on controls. 

Instead, the units were selected to 

ensure that data would be available to 

set floors for the subcategories that EPA 

was considering at the time of the Phase 

I ICR. 

I. Issues Related to Carbon Monoxide 

Emission Limits 

Comment: Numerous commenters 

disagreed with EPA’s statement that CO 

emissions do not vary significantly over 

the operating range of a unit, 75 FR 

32029. These commenters provided 

limited data across the operating range 

of boilers showing significant variation 

in CO emissions; the data also support 

the contention that CO emissions are 

higher at low load. In addition, 

commenters note that the degree of 

variability in emissions is dependent 

upon a specific unit and its design and 

operation characteristics, as well as 

other factors. With the premise that 

boilers do have variable CO emissions, 

in order to meet the applicable emission 

limit, commenters stated that stable 

boiler operation would be necessary, but 

that such boiler operation is not always 

possible. They contend that boiler loads 

vary constantly and rapidly and such 

load swings are a normal part of many 

processes and operations. Factors 

affecting the load include changes in 

fuel mix, fuel quantity, and fluctuations 

in load demand. Quick changes or large 

swings can also result in spikes which 

are substantially higher than average 

emissions. Commenters stated that in 

addition to daily fluctuations, CO 

emissions vary depending on broader 

issues such as business cycles or the 

time of year. Commenters claimed that 

even the top performers could not meet 

the limits due to load fluctuations. 

Some commenters provided input 

from boiler manufacturers and the 

guarantees that are currently available 

on the market for CO emissions. These 

guarantees include provisions that void 

the guarantee at loads below 25 percent 

load. Burner and boiler manufacturers 

state that CO emissions do fluctuate 

with load and suggest that limits should 

not be lower than manufacturer 

guarantees. 

Many commenters took issue with the 

use of stack test data to set the emission 

limit. Due to the highly variable nature 

of CO emissions, setting a standard that 

boilers must meet at all times based on 

stack test data does not properly 

characterize boiler emissions. Noting 

that stack tests are typically conducted 

at 90 percent of full load, commenters 

contended that this represents a small 

and unrepresentative snapshot in time 

captured during the best operating 

conditions. Some commenters 

compared stack test averages to CEMS 

values showing extreme differences 

(CEMS data could be >10 times higher), 

and stated that stack tests do not come 

close to capturing the long-term 

variability of CO emissions. 

Furthermore, commenters stated that 

some boilers frequently operate at lowfire conditions and that stack tests are 

not conducted at ‘‘representative 

operation conditions’’. A few 

commenters cited the DC Circuit [Sierra 

Club v. EPA, 167 F.3d 658, 665 (D.C. 

Cir. 1999)] and pointed out that stack 

tests do not capture the level of 

performance a unit will achieve ‘‘under 

the most adverse circumstances which 

can reasonably be expected to recur.’’ 

The commenters claimed that this 

condition must be considered in setting 

MACT floors. 

While EPA did present a comparison 

of data from units that had both stack 

test and hourly CO CEMS data available, 

commenters stated that the data are not 

representative. EPA presented only 

three units which have CEMS data and 

stack test data, and these units do not 

have data over a wide load range that 

could be considered to represent typical 

operating conditions. Commenters also 

noted that no CEMS data for liquid units 

were available. Many commenters 

suggested that EPA acquire and 

incorporate more CEMS data when 

setting the limits to show a more 

accurate picture of variability. A few 

commenters also pointed out that CEMS 

data is needed to characterize intra-unit 

operating variability due to load 

changes, because the 99 percent UPL 

only characterizes inter-unit, steadystate operation. Looking at the CEMS 

data provided, some commenters used 

the ‘‘start anew’’ method to calculate a 

30-day rolling average, and claimed that 

the unit would exceed the CO limit for 

several days, showing that the proposed 

limits are too low and the CEMS data 

are not appropriately considered. 

Some commenters noted the 

discrepancy between using stack test 

data to set the limits, and then having 

to comply by using CEMS. They 

suggested that whichever method is 

used to set the limits, the same method 

should be used for compliance. Several 

commenters pointed out that although 

the vacated Boiler MACT included a 

requirement for CO CEMS, it did not 

require CO CEMS data obtained at less 

than 50 percent of maximum load to be 

included in the 30-day CO average. 

Commenters recommended that these 

data exclusions be incorporated in the 

compliance provisions of this final rule. 

In addition, a few commenters cited a 

ruling by the U.S. Court of Appeals for 

the D.C. Circuit that ‘‘a significant 

difference between techniques used by 

the Agency in arriving at standards, and 

requirements presently prescribed for 

determining compliance with standards, 

raises serious questions about the 

validity of the standard.’’ (Portland 

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

375, 396 (DC Cir. 1973)). These 

commenters stated that the primary 

difference between these two methods is 

that the variability experienced during 

normal operations will not be captured 

during the stack test but will become 

apparent as the facility operates a CEMS 

over time. 

Finally, many commenters stated that 

the low proposed CO limits will cause 

additional challenges to boilers that are 

subject to NOX limits. These 

commenters presented graphs and data 

to demonstrate the inverse relationship 

between CO and NOX emissions and 

noted that changing the boiler operation 

to reduce CO to such low levels would 

result in an increase in NOX emissions. 

Commenters added that this result 

would be particularly challenging, and 

perhaps unproductive for boilers 

located in ozone non-attainment areas. 

In addition to increasing NOX

emissions, commenters noted that 

driving emission levels down to 

extremely low CO levels would also 

require boiler operators to increase 

excess air, thereby reducing the 

efficiency of the boiler. This operational 

change would require additional fuel to 

be combusted, thus increasing 

emissions of other HAP. These 

commenters requested that CO limits be 


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balanced with NOX limits such that 

boiler efficiency is optimized and State 

efforts to comply with NAAQS are not 

hindered. In addition to concerns 

surrounding competing air quality 

standards, a few commenters stated that 

National Fire Protection Act (NFPA) 

requirements also affect CO emissions at 

low loads. The NFPA specifies a 

minimum airflow at which a boiler can 

operate regardless of load, in order to 

avoid boiler explosions. At low loads, 

this NFPA requirement can result in 

excess air which leads to increased CO 

emissions. Commenters added that in 

order to meet the limits as proposed, 

boilers may have to idle at a higher load, 

increasing fuel costs and other 

emissions (NOX, carbon dioxide (CO2), 

and HAP). 

Response: In response to the many 

comments regarding the proposed CO 

emission limits, EPA performed a reassessment of the available data. In 

addition, EPA analyzed additional data 

that were not used to develop the 

proposed limits, including data 

submitted prior to proposal but too late 

for consideration for purposes of the 

proposed rule, data submitted during 

the public comment period, and data 

submitted after the comment period 

closed. While many comments were 

received opposing EPA’s proposal to set 

limits based on stack test data, EPA 

cannot set limits based on CEMs data 

because the available CEMS data are 

insufficient to set emission limits that 

are reflective of the best performing 12 

percent of sources in the various 

subcategories. First, CEMS data are not 

available for all of the subcategories. 

Second, most of the subcategories have 

only a single CEM data set from one 

facility. In contrast, a large amount of 

CO stack test data are available. For 

these reasons, EPA concluded that it 

was appropriate to use the stack test 

data rather than the CEMS data for 

setting the MACT floors for CO. 

Industry commenters who 

recommended that the emission limits 

be based on CEMS had ample 

opportunity to conduct CEMS testing 

(on the units identified as ‘‘best 

performers’’ based on the 3-run stack 

tests or on additional units to provide a 

broader base of data), but very little 

CEMS data were submitted to EPA after 

the proposal, and significant data gaps 

still exist. EPA does agree that, based on 

the high degree of variability shown by 

the available data for CO from boilers 

and process heaters, CEM-based limits 

could accurately reflect the actual 

emissions. However, EPA would need 

sufficient CEMS data to accurately 

calculate emissions limits, and, 

therefore, another approach must be 

used. In this instance, the alternative 

that EPA selected was to base the limits 

on 3-run stack test data. 

To develop emission limits based on 

3-run stack tests, EPA first reviewed the 

emission test reports for the best 

performing sources in order to ensure 

that that data reflected the actual 

performance of the units during the 

testing periods. EPA also incorporated 

data corrections from facilities that 

submitted test data, and between these 

two quality assurance measures, EPA 

has ensured that accurate data were 

used to establish the emission limits. 

Second, EPA examined the operating 

load at which the stack tests were 

conducted and found that, as pointed 

out by multiple commenters, the stack 

test data are representative of conditions 

at or near full load. Third, EPA 

determined that the calibration range of 

the CO analyzer must be considered in 

determining the minimum value that 

can be supported technically during a 

CO stack test. This assessment of 

calibration range resulted in some low 

CO levels being adjusted upward, as 

explained in more detail in the docket 

memo entitled ‘‘Assessment of 

Minimum Levels of CO that Can Be 

Established Under Various Analyzer 

Calibration Ranges.’’ EPA then ranked 

the data for each subcategory and 

developed stack test-based emission 

limits using the 99.9 percent UPL. The 

99.9 percent level was selected to 

provide an additional allowance for 

variability in the CO emission limits, 

since the CEM data show that CO levels 

have a higher degree of variability than 

other pollutants (for which EPA 

continues to use the 99 percent UPL). 

This change from the proposed 99 

percent UPL level resulted in about a 10 

percent increase in each of the CO 

emission limits (from the 99 percent 

UPL using the same data). The CO 

emission limits in today’s rule must be 

met through the use of a stack test 

during the initial and annual 

compliance tests, and parametric 

monitoring is required to demonstrate 

continuous compliance. As discussed 

elsewhere in the preamble, during 

periods of startup and shutdown, units 

that would otherwise be subject to a 

numeric emission limit are instead 

subject to a work practice standard. 

J. Cost Issues 

1. Inaccuracy of Basis of Costs 

Comment: Numerous commenters 

disagreed with EPA’s cost estimates. 

Many of them provided specific cost 

estimates for bringing their facilities 

into compliance with the proposed 

regulation to show that the costs were 

considerably higher than the EPA 

estimate. The estimations given 

included vendor data, real project costs, 

Best Achievable Control Technology 

and Best Available Retrofit Technology 

analyses and industrial control cost 

studies. 

Several commenters stated that the 

Office of Air Quality Planning and 

Standards (OAQPS) cost manual used to 

estimate costs was outdated and 

inaccurate. They noted costs that were 

missing from the estimates, such as 

additional man-hours for recordkeeping, compliance plan development 

and implementation, and operating and 

maintenance expenses. Some costs were 

said to be underestimated, such as the 

estimates for catalysts and carbon 

injection. 

Response: The OAQPS cost manual is 

the accepted basis of cost estimates for 

EPA regulations. EPA welcomed new 

information or methods for estimating 

costs and used the available data to 

adjust cost estimates where appropriate. 

EPA did not adjust catalyst costs since 

this information provided by 

commenters was based on proprietary 

cost estimates that could not be scaled 

to all boiler types. This catalyst also 

represented a regenerative oxidative 

catalyst which was a different 

technology than the CO oxidation 

catalyst used in initial estimates from 

EPA at proposal. The main concern 

about carbon injection costs was that the 

technology would be needed on far 

more units than estimated, because the 

assumption that fabric filters would be 

adequate to achieve the Hg emission 

limits was incorrect. EPA has adjusted 

the emission limits since proposal and 

notes that none of the units in the 

MACT floor calculations for solid fuels 

use activated carbon injection (ACI) 

control. Of the solid fuel units in the 

MACT floor calculations that are 

achieving the floor, only 2 units 

reported to have fabric filter and ACI 

installed and 132 units have only a 

fabric filter installed. The assumption 

that most units will meet the Hg floor 

using a fabric filter is reasonable and 

supported by the data on record. One 

commenter also questioned the 

inclusion of a factor for installing ACI 

equipment to an existing unit, saying 

that this important factor had been left 

out of the original calculation. A review 

of the ACI algorithm confirmed that the 

factor for installing the unit had been 

included originally, and no change was 

necessary. 

Comment: One of the most frequently 

mentioned concerns was the difficulty 

of retrofitting existing units with add-on 

control devices, which could lead to the 


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replacement of existing units, at a 

greater cost that what was estimated in 

the EPA background documents. Also 

mentioned were the increased costs 

associated with non-continental units, 

for which retrofits could be 1.3 to 2.3 

times higher than elsewhere. 

Response: EPA does not have enough 

information to assess the possibility of 

units being replaced due to difficulty 

retrofitting existing units. However, 

regardless of any information on that 

topic, the emission standards must 

reflect the floor level of control. Costs 

and emission impacts estimated for the 

boiler MACT standard are intended to 

represent national impacts. 

Consequently, costs for a specific 

facility may be lower or higher than 

what was estimated but on a national 

basis, we believe that our estimates are 

reasonable. We would also note that the 

cost algorithms include a cost factor for 

retrofitting existing boilers. 

Comment: One commenter also 

expressed concern that process heaters 

had costs estimated using algorithms 

based on boiler add-on control costs, 

giving grossly underestimated process 

heater control costs. 

Response: The algorithms estimate 

costs based on exhaust gas flow rate 

volumes and pollutant inlet 

concentrations and not specific to boiler 

costs. Some of the algorithms were 

based on costs from the 2009 HMIWI 

rulemaking. EPA considers these 

estimates to be reasonable estimates for 

both boilers and process heaters and the 

commenters did not provide an 

alternative cost estimate specific to 

process heaters. 

Comment: Several commenters stated 

that the number of affected sources was 

also underestimated, especially for gas 

or liquid-fired units, and one requested 

clarification with regards to the 

discrepancy between the number of 

units estimated in the vacated rule and 

the proposal. 

Response: The current inventory 

gathered for this rulemaking included 

unit data from industry sources. The 

public was encouraged to send any 

updates or changes necessary to correct 

the source inventory. The current 

inventory overrides the inventory 

created previously for the 2004 

rulemaking. 

2. Unproven Controls 

Comment: Many commenters stated 

that the suggested add-on controls have 

not been proven capable of 

simultaneously achieving the low 

emission limits proposed for the 

affected units. They expressed dismay at 

the high cost of adding numerous 

control devices without any reassurance 

that the emission limits could be 

achieved, or that human health would 

be better protected as a result. Some 

commenters included quotes from 

control device vendors stating that they 

were unable to guarantee the equipment 

could achieve the removal efficiency 

necessary to meet the proposed 

emission limits. 

Response: EPA has adjusted emission 

limits and compliance mechanisms to 

address these concerns. These 

adjustments include creation of a 

consolidated solid fuel subcategory for 

fuel-based HAP and CO monitoring 

provisions. 

3. Economic Hardship 

Comment: Numerous commenters 

worried that the proposed rule would 

lead to plant shut-downs, job loss, 

discouraged use of renewable energy 

and other negative economic impacts 

not considered in the rule. The 

commenters stated that the proposed 

regulation fails to find balance between 

job preservation, economic growth and 

environmental protection and suggested 

that EPA use their discretionary 

authority under the CAA to craft a more 

appropriate rule. A few industry 

representatives worried that the 

cumulative impact of multiple EPA 

regulations was putting U.S. industry at 

a cost disadvantage compared to 

international companies, and another 

asked if costs to comply with other 

MACT standards were also being taken 

into account in the RIA. Other 

commenters stated that the cost of 

controls necessary for their units to 

comply with the proposed rule 

exceeded the cost of the boiler itself, 

and in many cases exceeded the costs of 

plant profits in recent years. 

Response: EPA appreciates these 

concerns and, since proposal, has 

considered opportunities to reduce the 

costs of compliance with this final rule 

while continuing to achieve the public 

health objectives and meet the 

requirements of the CAA. In a number 

of cases in this final rule, EPA has 

adjusted emission limits, compliance 

mechanisms and subcategories that will 

make compliance less difficult and 

costly. In addition, EPA has added a 

discussion about the interaction of this 

rule with other rules to section 7.2 of 

the RIA. 

4. Technical Concerns 

Comment: In some cases, technical 

shortcomings of the cost estimates were 

addressed. For instance, one commenter 

pointed out that neither chlorine or Hg 

can be cost effectively removed from 

liquid fuels down to the proposed 

emission levels, so the cost of fuels will 

likely increase as suppliers blend 

different fuel sources to achieve fuel 

requirements. 

Response: EPA does not have the 

information necessary to estimate the 

potential costs that could result from 

new fuel blends. 

Comment: Several commenters had 

concerns about the use of packed bed 

scrubbers as a suggested control device. 

They pointed out that these scrubbers 

can only be used with relatively small 

units having an exhaust flow rate no 

greater than 75,000 standard cubic feet 

per minute (scfm). 

Response: EPA cost estimates took the 

flow rate capabilities of packed bed 

scrubbers into account by estimating 

additional scrubbers for units with flow 

rates beyond 75,000 scfm. 

Comment: Other commenters 

mentioned that some facilities, most 

often rural plants in the wood products 

sector, do not have and cannot obtain a 

wastewater discharge permit, so they 

cannot use wet scrubbers and would 

need to install more costly dry scrubbers 

to meet the HCl emission limits. 

Response: EPA added estimated costs 

for a Dry Injection/Fabric Filter control 

alternative for units unable to install 

wet scrubbers to meet HCl limits. 

Comment: Several commenters stated 

that the proposed CO emission limits 

would not be achievable at all operating 

conditions while also meeting NOX

limits, unless controls are added. 

Several pointed out that tune-ups and 

combustion modifications such as a 

linkageless boiler management system 

(LBMS) and replacement burners would 

offer inadequate control in most cases. 

Response: EPA incorporated 

additional CO data variability data 

received during the comment period, 

adjusted subcategories, and revised 

compliance mechanisms to address the 

issues discussed in these comments. 

Comment: One commenter pointed 

out that no documentation was found of 

a successful LBMS retrofit to existing 

biomass-to-energy facilities using stoker 

or fuel cell oven combustion. This 

commenter cited conversations with 

several stoker burner manufacturers, 

and the commenter could find no stoker 

units that have been retrofitted with an 

LBMS. They added that manufacturers 

stated that a successful retrofit to meet 

the proposed standards was doubtful 

based on the inherent leakage of air in 

these types of facilities. 

Response: EPA adjusted subcategories 

and compliance mechanisms and 

analyzed new CO test data in order to 

make the CO limits more reasonable. 

EPA estimates the cost of an LBMS as 

a placeholder for other combustion 


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improvements that are expected to 

achieve the CO limits. 

Comment: Some wrote to suggest that 

the number of units requiring activated 

carbon injection is grossly 

underestimated, because fabric filters 

alone would be frequently inadequate to 

meet the proposed Hg limits. Other 

commenters suggested that the use of 

activated carbon would lead to 

increased fabric filter use and additional 

costs for disposing of the resulting waste 

stream. 

Response: EPA adjusted Hg emission 

limits and incorporated a new solid fuel 

subcategory to address this concern. 

Further, many of the units in the MACT 

floor calculations demonstrate that they 

have achieved the Hg limit without 

installing activated carbon injection. 

Comment: The commenters suggested 

that far more facilities would need to 

add fabric filters, rather than the less 

expensive electrostatic precipitators that 

had been included in the cost estimates. 

Response: EPA is now basing the 

costs primarily on fabric filter 

installation, although owners/operators 

will choose a technology, that can meet 

the limits, that is best-suited to their 

process. 

Comment: Several times, commenters 

expressed concern about required addon controls conflicting with current 

controls and each other. For instance, 

one commenter explained small 

amounts of sulfur trioxide (SO3) are 

generated as part of the combustion 

process for sulfur-containing fuels. The 

commenter noted that a CO oxidation 

catalyst or Selective Catalytic Reduction 

NOX reduction catalyst, will convert an 

additional percentage of the SO2to SO3, 

which will inhibit Hg removal 

efficiency of activated carbon injection. 

SO3 occupies the active sites on the 

carbon, taking away those sites from the 

Hg. Additionally, some of these 

commenters also pointed out that some 

of the suggested control combinations 

have not been used with the affected 

boilers, so their use is unproven and the 

retrofit costs unknown. 

Response: EPA recognizes the 

potential interaction of different control 

devices and has adjusted the 

subcategories and incorporated 

additional emission data into the 

emission limit calculations. The revised 

limits and subcategories incorporated in 

this final rule mitigate these concerns. 

However, specifically addressing the 

commenters concerns would require an 

extensive study of emissions and 

controls, and the time or resources to 

conduct such a study are not available. 

EPA used the available data to set 

standards as required under section 112. 

Comment: Some commenters 

questioned the assumption that facilities 

will not incur costs to comply with the 

dioxin/furan standards because they 

will test for dioxin/furan and be below 

detection levels. They said this logic 

does not make sense because EPA has 

not outlined in the proposed rule any 

procedures for handling non-detects 

when performing compliance testing 

and there are boilers in the EPA 

emissions database with dioxin/furan 

emissions that are non-detect but 

actually measured emissions higher 

than the proposed limit. 

Response: EPA adjusted the dioxin/ 

furan emission limits based on data 

corrections and corrected procedures for 

handling non-detect and detection level 

limited values, making the need for addon controls to achieve compliance even 

less likely. For matters of compliance, it 

should be noted that EPA Method 23 

indicates that for compliance 

demonstrations, a value of zero should 

be used in place of a value below the 

detection limit for each non-detect 

isomer. Adherence to this procedure 

will ensure that non-detect values do 

not cause units to violate the emission 

limits. 

Comment: Other commenters 

disagreed with the EPA assumption that 

an ESP would be installed to meet the 

PM emissions limit unless a unit 

already had a fabric filter installed 

because sorbent injection will be 

required to control acid gas, Hg, and 

dioxin/furan. When sorbent injection is 

required, the commenters suggested that 

fabric filters will likely be chosen for 

units without existing ESPs in order to 

maximize the performance of the 

sorbents and minimize the amount of 

sorbent used. 

Response: EPA considers the original 

approach to be reasonable, and even 

more realistic, given the adjustments 

made to the emission limits. 

5. Tune-up Costs 

Comment: Some commenters 

questioned the inclusion of a tune-up in 

the proposed rule and suggested that 

many sites already perform regular tuneups. Some commenters also disagreed 

with annualizing the cost of the tune-up 

and energy audit over a five year period. 

The commenters contended that since a 

tune-up is a service, it must be paid in 

year 1 to the individual or company 

performing the work. 

Response: EPA agrees that some sites 

already perform regular tune-ups, which 

means the requirement will not increase 

costs for those facilities. EPA considers 

it appropriate to annualize the cost of a 

tune-up because the initial tune-up 

involves more costly steps that make 

subsequent tune-ups less costly. 

6. Testing and Monitoring Costs 

Comment: Numerous commenters 

stated that there will be a significant 

burden associated with performance 

testing and that EPA has underestimated 

these costs. EPA used an estimate of 

$55,000 plus $6,500 for labor per test, 

while the commenters provided both 

estimated and actual testing costs 

ranging from $60,000 to $90,000. A few 

commenters also noted when testing for 

HCl and Hg the testing costs should be 

doubled, because to meet the ‘worstcase’ condition stipulation the boilers 

will have to maximize emissions for two 

different operating parameters. 

Additionally, when testing HCl and Hg 

it is required that units also test for CO, 

PM, and dioxin/furan which increases 

costs and complexity of tests. As a result 

of this paired testing, the number of 

liquid units estimated to need controls 

for Hg and HCl and which, therefore, 

must conduct a performance test is also 

low. A few commenters contended that 

if a unit uses CO CEMS a reduction of 

$3,000 instead of $7,000 from the test 

estimate is more accurate. These 

commenters also noted that additional 

fuel sampling costs for sources firing gas 

or solids are necessary given the 

requirements for sources firing more 

than one type of fuel. Commenters 

suggested that additional costs for 

adding ports or scaffolding to stacks; 

additional space and runs to conduct 

the sophisticated tests; modifications to 

the permitting or compliance system; 

man-hours to enter data into the ERT; 

increased overtime; lost production, 

unit downtime, and additional 

engineering effort to adjust operations; 

and an increased cost to contract stack 

testers due to high demand should be 

factored into the estimated overall 

testing costs. 

Response: EPA’s revised cost 

estimates include two tests for Hg and 

HCl for each unit in the solid fuel 

subcategory, in order to account for 

potential worst case conditions that may 

be necessary to satisfy this final rule’s 

requirements. In addition, EPA is 

maintaining the reduced testing option 

for units that demonstrate emissions a 

specified percentage below the limits for 

three years. We have clarified and 

modified this option to state that 

performance testing for a given 

pollutant may be performed every 3 

years, instead of annually, if measured 

emissions during 2 consecutive annual 

performance tests are less than 75 

percent of the applicable emission limit. 

Comment: To reduce the testing 

burden commenters provided input to 


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modify the rule. The proposed rule 

requires annual stack testing with the 

opportunity to qualify for testing every 

3 years after 3 consecutive successful 

compliance demonstrations showing 

emissions, but many commenters 

suggested that a one-time test or one test 

every 5 years, coupled with parameter 

monitoring, is more appropriate 

Response: In order to reduce the cost 

of the testing requirements, EPA 

adjusted a couple of requirements based 

on the public comments. First, at 

proposal, EPA specified that to qualify 

for testing once every 3 years, sources 

must meet a level at or below 75 percent 

of the emission limit for each pollutant 

for 3 consecutive years. We have 

modified this option so that 

performance testing for a given 

pollutant may be performed every 3 

years, instead of annually, if measured 

emissions during 2 consecutive annual 

performance tests are less than 75 

percent of the applicable emission limit. 

In addition, for dioxin/furan, we are 

changing the testing requirement to an 

initial test demonstrating compliance 

with the limit and no additional testing, 

provided that the unit’s design is not 

modified in a manner inconsistent with 

good combustion practices. In addition, 

the oxygen level must be maintained at 

or above 90 percent of the level during 

the initial compliance test in order to 

provide an assurance of good 

combustion. The rationale behind the 

adjusted dioxin compliance 

demonstration is that the measured 

emissions from a limited number of 

tests indicate that dioxin emissions from 

boilers and process heaters are very low, 

and while it is required that sources 

meet the MACT floor levels, a one-time 

test and the required parameter 

monitoring are sufficient to ensure that 

combustion conditions are maintained 

and that the dioxin emissions remain 

low while also minimizing costs. 

Comment: Similarly, many 

commenters contended that costs 

associated with CO and PM CEMS are 

underestimated as well. For the 

installations of CEMS, one commenter 

provided a cost estimate which was 3 

times higher than the EPA estimate, 

while another said that costs for 

planning and engineering could be as 

much as 40 times higher with annual 

operating costs 3 times higher than EPA 

estimates. Also, in addition to the 

capital cost for the instrument itself, 

expensive certification costs are 

necessary; one commenter stated that 

this would be an additional $30,000 to 

$50,000 for each CEMS. Commenters 

noted that even for units where CEMS 

has already been installed, new 

equipment may be necessary in order to 

comply with proposed requirements for 

certifying and calibrating the CEMS. 

Commenters stated that a data 

acquisition system would be necessary 

to manage the data, which can cost more 

than $10,000. Many commenters also 

discussed the necessity of adding a 

stack platform, access, and additional 

utilities which can exceed $100,000 per 

stack. 

Response: EPA has removed CO 

CEMS requirements from this final rule. 

The costs detailed in Appendix J–2 of 

the memorandum ‘‘Methodology for 

Estimating Control Costs for Industrial, 

Commercial, Institutional Boilers and 

Process Heaters National Emission 

Standards for Hazardous Air 

Pollutants—Major Source (2010)’’ 

include planning, installations, RATA 

certifications, performance 

specifications and QA/QC checks. For 

PM CEMS, EPA’s estimates of installed 

capital costs include planning, selecting 

equipment, support facilities, 

installation, performance specifications 

tests and QA/QC and is consistent with 

estimates provided in the 2009 HMIWI 

rulemaking. EPA does not have 

information on which facilities would 

need to install a stack platform or 

utilities. Given that PM CEMS are 

required on only the largest units, EPA 

considers its assumption that most 

larger facilities have platform and utility 

access reasonable. 

K. Non-hazardous Secondary Materials 

Comment: Commenters from several 

environmental non-governmental 

organizations were concerned that if 

EPA moves forward with the proposal to 

define non-hazardous solid waste to 

exclude a majority of secondary 

materials burned for energy recovery, 

EPA will effectively exempt many 

boilers from any regulation. These 

commenters suggested that boilers 

burning secondary materials are not 

included in the regulatory definition of 

solid waste will not be regulated under 

§ 129 because EPA will have labeled the 

secondary materials burned as a nonwaste. Further, they suggested that these 

non-waste secondary materials are not 

covered under the boiler rules under 

§ 112. These commenters suggested that 

while some boilers burning secondary 

materials will be included in EPA’s 

categories for coal, oil, or biomass fired 

units, a large group of units will remain 

unregulated, including units burning 

only solid secondary materials or only 

secondary materials and gaseous fuels. 

One commenter stated that EPA must 

set section 112 standards for these units 

to meet its obligations under section 112 

and the order in Sierra Club v. EPA, No 

01—1537 (D.D.C.) requiring EPA to 

‘‘promulgate emission standards 

assuring that sources accounting for not 

less than 90 percent of the aggregate 

emissions of each of the hazardous air 

pollutants enumerated in Section 

112(c)(6) are subject to emission 

standards under section 112(d)(2) or 

(d)(4) no later than December 16, 2010.’’ 

These commenters were concerned that 

exempting units that burn secondary 

material from any emission standards 

will have adverse impacts on the 

communities that are exposed to the 

uncontrolled pollutants. 

Response: EPA has amended the 

definitions in this final rule to cover 

boilers burning non-hazardous 

secondary materials. 

VI. Impacts of This Final Rule 

A. What are the air impacts? 

Table 2 of this preamble illustrates, 

for each basic fuel subcategory, the 

emissions reductions achieved by this 

final rule (i.e., the difference in 

emissions between a boiler or process 

heater controlled to the floor level of 

control and boilers or process heaters at 

the current baseline) for new and 

existing sources. Nationwide emissions 

of selected HAP (i.e., HCl, HF, Hg, 

metals, and volative organic 

compounds) will be reduced by 40,000 

tons per year for existing units and 60 

tons per year for new units. Emissions 

of HCl will be reduced by 30,000 tons 

per year for existing units and 29 tons 

per year for new units. Emissions of Hg 

will be reduced by 1.4 tons per year for 

existing units and 10.8 pounds per year 

for new units. Emissions of filterable 

PM will be reduced by 47,400 tons per 

year for existing units and 85 tons per 

year for new units. Emissions of non-Hg 

metals (i.e., antimony, arsenic, 

beryllium, cadmium, chromium, cobalt, 

lead, Mn, nickel, and selenium) will be 

reduced by 2,700 tons per year for 

existing units and will be reduced by 

1.5 tons per year for new units. In 

addition, emissions of SO2 are 

estimated to be reduced by 442,000 tons 

per year for existing sources and 400 

tons per year for new sources. Emissions 

of dioxin/furan, will be reduced by 23 

grams of TCDD-equivalents per year for 

existing units and 0.01 gram per year of 

TCDD-equivalents for new units. A 

discussion of the methodology used to 

estimate emissions and emissions 

reductions is presented in ‘‘Revised 

Methodology for Estimating Cost and 

Emissions Impacts for Industrial, 

Commercial, Institutional Boilers and 

Process Heaters National Emission 

Standards for Hazardous Air 

Pollutants—Major Source (2011)’’ in the 

docket. 


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TABLE 2—SUMMARY OF EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES

(Tons/Yr) 

Source Subcategory HCl PM Non mercury 

metals a Mercury VOC 

Existing Units .................. Solid units ....................... 27,592 33,299 314 0.6 5,046 

Liquid units ..................... 1,936 13,269 2,229 0.7 1,881 

Non-Continental Liquid 

units.

89 726 115 0.06 0 .01 

Gas 1 (NG/RG) units ..... 23 139 0 .3 0.009 82 

Gas 1 Metallurgical Furnaces.0 .4 2 0 .02 0.001 30 

Gas 2 (other) units ......... 0 .4 0 .1 0 .0009 4.5E–05 111 

New Units ........................ Solid units ....................... 0 0 0 0 0 

Liquid units ..................... 29 85 1 .5 0.005 27 

Gas 1 units ..................... 0 .02 0 .1 0 .0003 7.9E–06 0 .03 

Gas 2 (other) units ......... 0 0 0 0 0 

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

B. What are the water and solid waste 

impacts? 

EPA estimated the additional water 

usage that would result from installing 

wet scrubbers to meet the emission 

limits for HCl would be 700 million 

gallons per year for existing sources and 

242,000 gallons per year for new 

sources. In addition to the increased 

water usage, an additional 266 million 

gallons per year of wastewater would be 

produced for existing sources and 

194,000 gallons per year for new 

sources. The annual costs of treating the 

additional wastewater are $1.4 million 

for existing sources and $1,055 for new 

sources. These costs are accounted for 

in the control costs estimates. 

EPA estimated the additional solid 

waste that would result from the MACT 

floor level of control to be 100,450 tons 

per year for existing sources and 580 

tons per year for new sources. Solid 

waste is generated from flyash and dust 

captured in PM and Hg controls as well 

as from spent carbon and spent sorbent 

that is injected into exhaust streams or 

used to filter gas streams. The costs of 

handling the additional solid waste 

generated are $4.2 million for existing 

sources and $25,000 for new sources. 

These costs are also accounted for in the 

control costs estimates. 

A discussion of the methodology used 

to estimate impacts is presented in 

‘‘Revised Methodology for Estimating 

Cost and Emissions Impacts for 

Industrial, Commercial, Institutional 

Boilers and Process Heaters National 

Emission Standards for Hazardous Air 

Pollutants—Major Source (2011)’’. 

C. What are the energy impacts? 

EPA expects an increase of 

approximately 1.442 billion kilowatt 

hours (kWh) in national annual energy 

usage as a result of this final rule. Of 

this amount, 1.436 billion kWh would 

be from existing sources and 6.2 million 

kWh are estimated from new sources. 

The increase results from the electricity 

required to operate control devices, 

such as wet scrubbers, electrostatic 

precipitators, and fabric filters which 

are expected to be installed to meet this 

final rule. Additionally, EPA expects 

work practice standards such as boilers 

tune-ups and combustion controls will 

improve the efficiency of boilers, 

resulting in an estimated fuel savings of 

53 TBtu each year from existing sources 

and an additional 11 billion BTU each 

year from new sources. This fuel savings 

estimate includes only those fuel 

savings resulting from gas, liquid, and 

coal fuels and it is based on the 

assumption that the work practice 

standards will achieve 1 percent 

improvement in efficiency. 

D. What are the cost impacts? 

To estimate the national cost impacts 

of this final rule for existing sources, we 

developed average baseline emission 

factors for each fuel type/control device 

combination based on the emission data 

obtained and contained in the Boiler 

MACT emission database. If a unit 

reported emission data, we assigned its 

unit-specific emission data as its 

baseline emissions. If a unit did not 

report emission data but similar units at 

the facility with the same fuel and 

combustor design reported data, the 

average of all similar units at a given 

facility was assigned as its baseline 

emissions. If no unit-specific or similar 

units from the same facility had data 

available, a baseline average emission 

factor was assigned to the unit. Units 

that reported non-detect emission data 

for a pollutant that did not have a 

standardized numeric detection limit 

were assigned to the average of all nondetect emission data for that pollutant. 

For the remaining units that did not 

report emission data, we assigned the 

appropriate emission factors to each 

existing unit in the inventory database, 

based on the average emission factors 

for boilers with similar fuel, design, and 

control devices. We then compared each 

unit’s baseline emission factors to the 

final MACT floor emission limit to 

determine if control devices were 

needed to meet the emission limits. The 

control analysis considered fabric filters 

and activated carbon injection to be the 

primary control devices for Hg control, 

ESP for units meeting Hg limits but 

requiring additional control to meet the 

PM limits, wet scrubbers, dry injection/ 

fabric filters, or increased caustic rates 

to meet the HCl limits, depending on 

whether or not the facility was assumed 

to have a wastewater discharge permit, 

tune-ups, replacement burners, and 

combustion controls for CO and organic 

HAP control, and carbon injection for 

dioxin/furan control. We identified 

where one control device could achieve 

reductions in multiple pollutants, for 

example a fabric filter was expected to 

achieve both PM and Hg control in 

order to avoid overestimating the costs. 

We also included costs for testing and 

monitoring requirements contained in 

this final rule. The resulting total 

national cost impact of this final rule is 

5.1 billion dollars in capital 

expenditures and 1.8 billion dollars per 

year in total annual costs. Considering 

estimated fuel savings resulting from 

work practice standards and combustion 

controls, the total annualized costs are 

reduced to 1.4 billion dollars. The total 

capital and annual costs include costs 

for control devices, work practices, 

testing and monitoring. Table 3 of this 

preamble shows the capital and annual 

cost impacts for each subcategory. Costs 

include testing and monitoring costs, 

but not recordkeeping and reporting 

costs. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15651 

8Roman et al, 2008. Expert Judgment Assessment 

of the Mortality Impact of Changes in Ambient Fine 

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

Technol., 42, 7, 2268–2274. 

TABLE 3—SUMMARY OF CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES

Source Subcategory 

Estimated/projected number 

of affected 

units 

Capital costs 

(10 6 $) 

Testing and 

monitoring 

annualized costs 

(10 6 $/yr) 

Annualized cost 

(10 6 $/yr) (considering fuel 

savings) 

Existing Units ................................ Solid units ..................................... 1,014 2,183 108 846 

Liquid units ................................... 713 2,656 19 .8 828 

Non-Continental Liquid units ........ 27 86 0 .7 21 

Gas 1 units ................................... 10,797 70 0 .3 (325 ) 

Gas 1 Metallurgical Furnaces ...... 694 4 .5 0 (6 ) 

Gas 2 (other) units ....................... 118 79 6 .3 37 

Limited Use .................................. 477 3 .1 0 (25 ) 

Energy Assessment ...................... ALL ............................................... ........................ .......................... ............................ 27 

New Units ...................................... Solid units ..................................... 0 0 0 0 

Liquid units ................................... 13 21 0 .3 6.1 

Gas (NG/RG) units ....................... 34 0 .2 0 (0.02 ) 

Gas (other) units .......................... 0 0 0 0 

Using Department of Energy 

projections on fuel expenditures, the 

number of additional boilers that could 

be potentially constructed was 

estimated. The resulting total national 

cost impact of this final rule in the 3rd 

year is 21 million dollars in capital 

expenditures and 6.1 million dollars per 

year in total annual costs, when 

considering a 1 percent fuel savings. 

Potential control device cost savings 

and increased recordkeeping and 

reporting costs associated with the 

emissions averaging provisions and 

reduced testing allowance in this final 

rule are not accounted for in either the 

capital or annualized cost estimates. 

A discussion of the methodology used 

to estimate cost impacts is presented in 

‘‘Revised Methodology for Estimating 

the Control Costs for Industrial, 

Commercial, and Institutional Boiler 

and Process Heater NESHAP (2011)’’ 

and ‘‘Revised Methodology for 

Estimating Cost and Emission Impacts 

for Industrial, Commercial, and 

Industrial Boilers and Process Heaters 

National Emission Standards for 

Hazardous Air Pollutants—Major 

Source (2011)’’ in the Docket. 

E. What are the economic impacts? 

Under this final rule, EPA’s economic 

model suggests the average national 

market-level variables (prices, 

production-levels, consumption, 

international trade) will not change 

significantly (e.g., are less than 0.01 

percent). EPA performed a screening 

analysis for impacts on small entities by 

comparing compliance costs to sales/ 

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

EPA’s analysis found the tests were 

above 3 percent for 8 of the 50 small 

entities included in the screening 

analysis. 

In addition to estimating this rule’s 

social costs and benefits, EPA has 

estimated the employment impacts of 

the final rule. We expect that the rule’s 

direct impact on employment will be 

small. We have not quantified the rule’s 

indirect or induced impacts. For further 

explanation and discussion of our 

analysis, see Chapter 4 of the RIA. 

F. What are the benefits of this final 

rule? 

The benefit categories associated with 

the emission reduction anticipated for 

this rule can be broadly categorized as 

those benefits attributable to reduced 

exposure to hazardous air pollutants 

(HAPs) and those attributable to 

exposure to other pollutants. Because 

we were unable to monetize the benefits 

associated with reducing HAPs, all 

monetized benefits reflect 

improvements in ambient PM2.5 and 

ozone concentrations. This results in an 

underestimate of the total monetized 

benefits. We estimated the total 

monetized benefits of this final 

regulatory action to be $22 billion to $54 

billion (2008$, 3 percent discount rate) 

in the implementation year (2014). The 

monetized benefits at a 7 percent 

discount rate are $20 billion to $49 

billion (2008$). Using alternate 

relationships between fine particulate 

matter (PM2.5) and premature mortality 

supplied by experts, higher and lower 

benefits estimates are plausible, but 

most of the expert-based estimates fall 

between these two estimates.8 A 

summary of the monetized benefits 

estimates at discount rates of 3 percent 

and 7 percent is provided in Table 4 of 

this preamble. A summary of the 

avoided health incidences is provided 

in Table 5 of this preamble. 

TABLE 4—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT 

[Millions of 2008$] 1

Pollutant Emissions reductions (tons) Total monetized benefits (at 3% discount rate) Total monetized benefits 

(at 7% discount rate) 

PM2.5-related benefits 

Direct PM2.5 .......................................................... 29,007 $2,100 to $5,100 .................................................. $1,900 to $4,600. 

SO2 ....................................................................... 439,901 $20,000 to $49,000 .............................................. $18,000 to $45,000. 

Ozone-related benefits 

VOCs .................................................................... 6,537 $3.6 to $15 ........................................................... $3.6 to $15. 


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15652 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

9U.S. Environmental Protection Agency, 2010. 

RIA for the Proposed Federal Transport Rule. 

Prepared by Office of Air and Radiation. June. 

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

ecas/regdata/RIAs/proposaltrria_final.pdf. 

TABLE 4—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT—Continued 

[Millions of 2008$] 1

Pollutant Emissions reductions (tons) Total monetized benefits (at 3% discount rate) Total monetized benefits 

(at 7% discount rate) 

Total ............................................................... ........................ $22,000 to $54,000 .............................................. $20,000 to $49,000. 

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

fine particles are assumed to have equivalent health effects. Benefits from reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy disbenefits valued at $22 million. These benefits reflect existing boilers and 47 new boilers anticipated to come online by 2014. 

TABLE 5—SUMMARY OF THE AVOIDED HEALTH INCIDENCES FOR THE FINAL BOILER MACT 1

Avoided health 

incidences 

Avoided Premature Mortality ............................................................................................................................................................ 2,500 to 6,500. 

Avoided Morbidity 

Chronic Bronchitis ............................................................................................................................................................................. 1,600. 

Acute Myocardial Infarction .............................................................................................................................................................. 4,000. 

Hospital Admissions, Respiratory ..................................................................................................................................................... 610. 

Hospital Admissions, Cardiovascular ............................................................................................................................................... 1,300. 

Emergency Room Visits, Respiratory ............................................................................................................................................... 2,400. 

Acute Bronchitis ................................................................................................................................................................................ 3,700. 

Work Loss Days ............................................................................................................................................................................... 310,000. 

Asthma Exacerbation ........................................................................................................................................................................ 41,000. 

Minor Restricted Activity Days .......................................................................................................................................................... 1,900,000. 

Lower Respiratory Symptoms .......................................................................................................................................................... 44,000. 

Upper Respiratory Symptoms .......................................................................................................................................................... 34,000. 

School Loss Days ............................................................................................................................................................................. 810. 

1All estimates are for the implementation year (2014), and are rounded to two significant figures. All fine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included. These benefits reflect existing boilers and 47 new boilers anticipated to come 

online by 2014. 

These quantified benefits estimates 

represent the human health benefits 

associated with reducing exposure to 

PM2.5 and ozone. The PM and ozone 

reductions are the result of emission 

limits on PM as well as emission limits 

on other pollutants, including HAP. To 

estimate the human health benefits, we 

used the environmental Benefits 

Mapping and Analysis Program 

(BenMAP) model to quantify the 

changes in PM2.5- and ozone-related 

health impacts and monetized benefits 

based on changes in air quality. This 

approach is consistent with the recently 

proposed Transport Rule RIA.9

For this final rule, we have expanded 

and updated the analysis since the 

proposal in several important ways. 

Using the Comprehensive Air Quality 

Model with extensions (CAMx) model, 

we are able to provide boiler sectorspecific air quality impacts attributable 

to the emission reductions anticipated 

from this final rule. We believe that this 

modeling provides estimates that are 

more appropriate for characterizing the 

health impacts and monetized benefits 

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

analysis. 

To generate the boiler sector-specific 

benefit-per-ton estimates, we used 

CAMx to convert emissions of direct 

PM2.5 and PM2.5 precursors into changes 

in ambient PM2.5 levels and BenMAP to 

estimate the changes in human health 

associated with that change in air 

quality. Finally, the monetized PM2.5

health benefits were divided by the 

emission reductions to create the boiler 

sector-specific benefit-per-ton estimates. 

These models assume that all fine 

particles, regardless of their chemical 

composition, are equally potent in 

causing premature mortality because 

there is no clear scientific evidence that 

would support the development of 

differential effects estimates by particle 

type. Directly emitted PM2.5 and SO2 are 

the dominant PM2.5 precursors affected 

by this final rule. Even though we 

assume that all fine particles have 

equivalent health effects, the benefitper-ton estimates vary between 

precursors because each ton of 

precursor reduced has a different 

propensity to form PM2.5. For example, 

SO2 has a lower benefit-per-ton estimate 

than direct PM2.5 because it does not 

directly transform into PM2.5, and 

because sulfate particles formed from 

SO2 emissions can transport many 

miles, including over areas with low 

populations. Direct PM2.5 emissions 

convert directly into ambient PM2.5, 

thus, to the extent that emissions occur 

in population areas, exposures to direct 

PM2.5 will tend to be higher, and 

monetized health benefits will be higher 

than for SO2 emissions. 

In addition, we estimated the ozone 

benefits for this final rule. Volatile 

organic compounds (VOC) are the 

primary ozone precursor affected by this 

final rule. We used CAMx to convert 

emissions of VOC into changes in 

ambient ozone levels and BenMAP to 

estimate the changes in human health 

associated with that change in air 

quality. 

Furthermore, CAMx modeling allows 

us to model the reduced Hg deposition 

that would occur as a result of the 

estimated reductions of Hg emissions. 

Although we are unable to model Hg 

methylation and human consumption of 

Hg-contaminated fish, the Hg deposition 

maps provide an improved qualitative 

characterization of the Hg benefits 

associated with this final rulemaking. 

For context, it is important to note 

that the magnitude of the PM benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised EPA to 

consider a variety of assumptions, 

including estimates based on both 

empirical (epidemiological) studies and 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15653 

10Pope et al, 2002.‘‘Lung Cancer, 

Cardiopulmonary Mortality, and Long-term 

Exposure to Fine Particulate Air Pollution.’’ Journal 

of the American Medical Association 287:1132– 

1141. 

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

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173: 667–672. 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

For this final rule, we cite two key 

empirical studies, one based on the 

American Cancer Society cohort 

study 10 and the extended Six Cities 

cohort study.11 In the RIA for this final 

rule, which is available in the docket, 

we also include benefits estimates 

derived from expert judgments and 

other assumptions. 

EPA strives to use the best available 

science to support our benefits analyses. 

We recognize that interpretation of the 

science regarding air pollution and 

health is dynamic and evolving. After 

reviewing the scientific literature and 

recent scientific advice, we have 

determined that the no-threshold model 

is the most appropriate model for 

assessing the mortality benefits 

associated with reducing PM2.5

exposure. Consistent with this recent 

advice, we are replacing the previous 

threshold sensitivity analysis with a 

new ‘‘lowest measured level (LML)’’ 

assessment. While an LML assessment 

provides some insight into the level of 

uncertainty in the estimated PM 

mortality benefits, EPA does not view 

the LML as a threshold and continues to 

quantify PM-related mortality impacts 

using a full range of modeled air quality 

concentrations. 

Most of the estimated PM-related 

benefits in this final rule would accrue 

to populations exposed to higher levels 

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

study, 79 percent of the population is 

exposed at or above the LML of 7.5 

microgram per cubic meter (μg/m3). 

Using the Laden, et al., (2006) study, 34 

percent of the population is exposed 

above the LML of 10 μg/m3. It is 

important to emphasize that we have 

high confidence in PM2.5-related effects 

down to the lowest LML of the major 

cohort studies. This fact is important, 

because as we estimate PM-related 

mortality among populations exposed to 

levels of PM2.5 that are successively 

lower, our confidence in the results 

diminishes. However, our analysis 

shows that the great majority of the 

impacts occur at higher exposures. 

It should be emphasized that the 

monetized benefits estimates provided 

above do not include benefits from 

several important benefit categories, 

including reducing other air pollutants, 

ecosystem effects, and visibility 

impairment. The benefits from reducing 

other pollutants have not been 

monetized in this analysis, including 

reducing 167,000 tons of CO, 30,000 

tons of hydrochloric acid, 820 tons of 

HF, 23 grams of dioxins/furans, 2,900 

pounds of Hg, and 22,700 tons of other 

metals each year. Specifically, we were 

unable to estimate the benefits 

associated with HAPs that would be 

reduced as a result of this rule due to 

data, resource, and methodology 

limitations. Challenges in quantifying 

the HAP benefits include a lack of 

exposure-response functions, 

uncertainties in emissions inventories 

and background levels, the difficulty of 

extrapolating risk estimates to low 

doses, and the challenges of tracking 

health progress for diseases with long 

latency periods. Although we do not 

have sufficient information or modeling 

available to provide monetized 

estimates for this rulemaking, we 

include a qualitative assessment of the 

health effects of these air pollutants in 

the RIA for this final rule, which is 

available in the docket. In addition, we 

provide maps of reduced mercury 

deposition anticipated from these rules 

in the RIA for this final rule. 

In addition, the monetized benefits 

estimates provided in Table 4 do not 

reflect the disbenefits associated with 

increased electricity usage from 

operation of the control devices. We 

estimate that the increases in emissions 

of CO2 would have disbenefits valued at 

$22 million at a 3 percent discount rate 

(average). CO2-related disbenefits were 

calculated using the social cost of 

carbon, which is discussed further in 

the RIA. However, these disbenefits do 

not change the rounded total monetized 

benefits. In the RIA, we also provide the 

monetized CO2 disbenefits using 

discount rates of 5 percent (average), 2.5 

percent (average), and 3 percent (95th 

percentile). 

This analysis does not include the 

type of detailed uncertainty assessment 

found in the 2006 PM2.5 NAAQS RIA or 

2008 Ozone NAAQS RIA. However, the 

benefits analyses in these RIA provide 

an indication of the sensitivity of our 

results to various assumptions, 

including the use of alternative 

concentration-response functions and 

the fraction of the population exposed 

to low PM2.5 levels. 

For more information on the benefits 

analysis, please refer to the RIA for this 

final rule that is available in the docket. 

G. What are the secondary air impacts? 

For units adding controls to meet the 

proposed emission limits, we anticipate 

very minor secondary air impacts. The 

combustion of fuel needed to generate 

additional electricity would yield slight 

increases in emissions, including NOX, 

CO, PM and SO2 and an increase in CO2

emissions. Since NOX and SO2 are 

covered by capped emissions trading 

programs, and methodological 

limitations prevent us from quantifying 

the change in CO and PM, we do not 

estimate an increase in secondary air 

impacts for this final rule from 

additional electricity demand. We do 

estimate greenhouse gas impacts, which 

result from increased electricity 

consumption, to be 954,000 tons per 

year from existing units and 4,100 tons 

per year from new units. 

VII. Relationship of This Final Action 

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

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

EPA to identify categories of sources of 

seven specified pollutants to assure that 

sources accounting for not less than 90 

percent of the aggregate emissions of 

each such pollutant are subject to 

standards under CAA Section 112(d)(2) 

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

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ ‘‘Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion,’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ as source categories that 

emit two of the seven CAA Section 

112(c)(6) pollutants: POM and Hg. (The 

POM emitted is composed of 16 

polyaromatic hydrocarbons and 

extractable organic matter.) In the 

Federal Register notice Source Category 

Listing for Section 112(d)(2) Rulemaking 

Pursuant to Section 112(c)(6) 

Requirements, 63 FR 17838, 17849, 

Table 2 (1998), EPA identified 

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ ‘‘Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion,’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ as source categories 

‘‘subject to regulation’’ for purposes of 

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

the CAA Section 112(c)(6) pollutants 

that these units emit. 

Specifically, as byproducts of 

combustion, the formation of POM is 

effectively reduced by the combustion 

and post-combustion practices required 

to comply with the CAA Section 112 

standards. Any POM that do form 

during combustion are further 

controlled by the various postVerDate Mar<15>2010 19:21 Mar 18, 2011 Jkt 223001 PO 00000 Frm 00047 Fmt 4701 Sfmt 4700 E:\FR\FM\21MRR5.SGM 21MRR5

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15654 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

combustion controls. The add-on PM 

control systems (either fabric filter or 

wet scrubber) and activated carbon 

injection in the fabric filter-based 

systems further reduce emissions of 

these organic pollutants, and also 

reduce Hg emissions, as is evidenced by 

performance data. Specifically, the 

emission tests obtained at currently 

operating units show that the proposed 

MACT regulations will reduce Hg 

emissions by about 77 percent. It is, 

therefore, reasonable to conclude that 

POM emissions will be substantially 

controlled. Thus, while this final rule 

does not identify specific numerical 

emission limits for POM, emissions of 

POM are, for the reasons noted below, 

nonetheless ‘‘subject to regulation’’ for 

purposes of Section 112(c)(6) of the 

CAA. 

In lieu of establishing numerical 

emissions limits for pollutants such as 

POM, we regulate surrogate substances. 

While we have not identified specific 

numerical limits for POM, CO serves as 

an effective surrogate for this HAP, 

because CO, like POM, is formed as a 

byproduct of combustion, and both 

would increase with an increase in the 

level of incomplete combustion. 

Consequently, we have concluded 

that the emissions limits for CO 

function as a surrogate for control of 

POM, such that it is not necessary to 

require numerical emissions limits for 

POM with respect to boilers and process 

heaters to satisfy CAA Section 112(c)(6). 

To further address POM and Hg 

emissions, this final rule also includes 

an energy assessment provision that 

encourage modifications to the facility 

to reduce energy demand that lead to 

these emissions. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Orders 12866 and 13563: 

Regulatory Planning and Review 

Under Executive Orders 12866 (58 FR 

51735, October 4, 1993) and 13563 (76 

FR 3821, January 21, 2011), this action 

is an ‘‘economically significant 

regulatory action’’ because it is likely to 

have an annual effect on the economy 

of $100 million or more or adversely 

affect in a material way the economy, a 

sector of the economy, productivity, 

competition, jobs, the environment, 

public health or safety, or State, local, 

or tribal governments or communities. 

Accordingly, EPA submitted this 

action to the Office of Management and 

Budget (OMB) for review under 

Executive Orders 12866 and 13563 and 

any changes in response to OMB 

recommendations have been 

documented in the docket for this 

action. For more information on the 

costs and benefits for this rule see the 

following table. 

SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER MACT IN 2014 

[Millions of 2008$] 

3% Discount rate 7% Discount rate 

Selected 

Total Monetized Benefits 2 .................................................... $22,000 to $54,000 .............................................................. $20,000 to $49,000 

Total Social Costs 3 ............................................................... $1,500 .................................................................................. $1,500 

Net Benefits ........................................................................... $20,500 to $52,500 .............................................................. $18,500 to $47,500 

Non-Monetized Benefits ........................................................ 112,000 tons of CO. 

30,000 tons of HCl. 

820 tons of HF. 

2,800 pounds of Hg. 

2,700 tons of other metals. 

23 grams of dioxins/furans (TEQ). 

Health effects from SO2 exposure. 

Ecosystem effects. 

Visibility impairment. 

Alternative 

Total Monetized Benefits 2 .................................................... $18,000 to $43,000 .............................................................. $16,000 to $39,000 

Total Social Costs 3 ............................................................... $1,900 .................................................................................. $1,900 

Net Benefits ........................................................................... $16,100 to $41,100 .............................................................. $14,100 to $37,100 

Non-Monetized Benefits ........................................................ 112,000 tons of CO. 

22,000 tons of HCl. 

620 tons of HF. 

2,400 pounds of Hg. 

2,600 tons of other metals. 

23 grams of dioxins/furans (TEQ). 

Health effects from SO2 exposure. 

Ecosystem effects. 

Visibility impairment. 

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

come online and the lowest cost disposal assumption. 2The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of directly emitted PM2.5 and PM2.5 precursors such as SO2, as well as reducing exposure to ozone through reductions of VOCs. It is important to note that the 

monetized benefits include many but not all health effects associated with PM2.5 exposure. Benefits are shown as a range from Pope et al. 

(2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type. These estimates include energy disbenefits valued at $23 million for the selected option and $35 million for the alternative option. 

Ozone benefits are valued at $3.6 to $15 million for both options. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15655 

B. Paperwork Reduction Act 

The information collection 

requirements in this final rule will be 

submitted for approval to the OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. An ICR document 

has been prepared by EPA (ICR No. 

2028.06). The information collection 

requirements are not enforceable until 

OMB approves them. 

The information requirements are 

based on notification, recordkeeping, 

and reporting requirements in the 

NESHAP General Provisions (40 CFR 

part 63, subpart A), which are 

mandatory for all operators subject to 

national emission standards. These 

recordkeeping and reporting 

requirements are specifically authorized 

by section 114 of the CAA (42 U.S.C. 

7414). All information submitted to EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to Agency 

policies set forth in 40 CFR part 2, 

subpart B. 

This final rule would require 

maintenance inspections of the control 

devices but would not require any 

notifications or reports beyond those 

required by the General Provisions aside 

from the notification of alternative fuel 

use for those units that are in the Gas 

1 subcategory but burn liquid fuels for 

periodic testing, or during periods of gas 

curtailment or gas supply emergencies. 

The recordkeeping requirements require 

only the specific information needed to 

determine compliance. 

When a malfunction occurs, sources 

must report them according to the 

applicable reporting requirements of 

this Subpart DDDDD. An affirmative 

defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions is available to a 

source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 

(sudden, infrequent, not reasonable 

preventable and not caused by poor 

maintenance and or careless operation) 

and where the source took necessary 

actions to minimize emissions. In 

addition, the source must meet certain 

notification and reporting requirements. 

For example, the source must prepare a 

written root cause analysis and submit 

a written report to the Administrator 

documenting that it has met the 

conditions and requirements for 

assertion of the affirmative defense. 

To provide the public with an 

estimate of the relative magnitude of the 

burden associated with an assertion of 

the affirmative defense position adopted 

by a source, EPA provides an 

administrative adjustment to this ICR 

that shows what the notification, 

recordkeeping and reporting 

requirements associated with the 

assertion of the affirmative defense 

might entail. EPA’s estimate for the 

required notification, reports and 

records, including the root cause 

analysis, totals $3,141 and is based on 

the time and effort required of a source 

to review relevant data, interview plant 

employees, and document the events 

surrounding a malfunction that has 

caused an exceedance of an emission 

limit. The estimate also includes time to 

produce and retain the record and 

reports for submission to EPA. EPA 

provides this illustrative estimate of this 

burden because these costs are only 

incurred if there has been a violation 

and a source chooses to take advantage 

of the affirmative defense. 

The annual monitoring, reporting, and 

recordkeeping burden for this collection 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $95.9 million. This 

includes 280,459 labor hours per year at 

a total labor cost of $26.5 million per 

year, and total non-labor capital costs of 

$69.3 million per year. This estimate 

includes initial and annual performance 

test, conducting an documenting an 

energy assessment, conducting fuel 

specifications for Gas 1 units, repeat 

testing under worst-case conditions for 

solid fuel units, conducting and 

documenting a tune-up, semiannual 

excess emission reports, maintenance 

inspections, developing a monitoring 

plan, notifications, and recordkeeping. 

Monitoring, testing, tune-up and energy 

assessment costs and cost were also 

included in the cost estimates presented 

in the control costs impacts estimates in 

section IV.D of this preamble. The total 

burden for the Federal government 

(averaged over the first 3 years after the 

effective date of the standard) is 

estimated to be 97,563 hours per year at 

a total labor cost of $5.2 million per 

year. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and use technology and 

systems for the purposes of collecting, 

validating, and verifying information, 

processing and maintaining 

information, and disclosing and 

providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. An agency 

may not conduct or sponsor, and a 

person is not required to respond to, a 

collection of information unless it 

displays a currently valid OMB control 

number. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. When this ICR is 

approved by OMB, the Agency will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 

C. Regulatory Flexibility Act, as 

Amended by the Small Business 

Regulatory Enforcement Fairness Act of 

1996, 5 U.S.C. 601 et seq. 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

according to Small Business 

Administration (SBA) size standards by 

the North American Industry 

Classification System category of the 

owning entity. The range of small 

business size standards for the affected 

industries ranges from 500 to 1,000 

employees, except for petroleum 

refining and electric utilities. In these 

latter two industries, the size standard 

is 1,500 employees and a mass 

throughput of 75,000 barrels/day or less, 

and 4 million kilowatt-hours of 

production or less, respectively; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

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

owned and operated and is not 

dominant in its field. 

Pursuant to section 603 of the RFA, 

EPA prepared an initial regulatory 

flexibility analysis (IRFA) for the 

proposed rule and convened a Small 

Business Advocacy Review Panel to 


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obtain advice and recommendations of 

representatives of the regulated small 

entities. A detailed discussion of the 

Panel’s advice and recommendations is 

found in the final Panel Report (Docket 

ID No. EPA–HQ–OAR–2002–0058– 

0797). A summary of the Panel’s 

recommendations is also presented in 

the preamble to the proposed rule at 75 

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

proposed rule, EPA included provisions 

consistent with four of the Panel’s 

recommendations. 

As required by section 604 of the 

RFA, we also prepared a final regulatory 

flexibility analysis (FRFA) for today’s 

final rule. The FRFA addresses the 

issues raised by public comments on the 

IRFA, which was part of the proposal of 

this rule. The FRFA, which is included 

as a section in the RIA, is available for 

review in the docket and is summarized 

below. 

Section II.A of this preamble 

describes the reasons that EPA is 

finalizing this action. The rule is 

intended to reduce emissions of HAP as 

required under section 112 of the CAA. 

Many significant issues were raised 

during the public comment period, and 

EPA’s responses to those comments are 

presented in section V of this preamble 

or in the response to comments 

document contained in the docket. 

Significant changes to the rule that 

resulted from the public comments are 

described in section IV of this preamble. 

The primary comments on the IRFA 

were provided by SBA, with the 

remainder of the comments generally 

supporting SBA’s comments. Those 

comments included the following: EPA 

should have adopted a health-based 

compliance alternative (HBCA) which 

provides alternative emission limits for 

threshold chemicals; EPA should have 

adopted additional subcategories, 

including the following: Subcategories 

based on fuel type (including coal rank, 

bagasse, biomass by type, and oil by 

type), unit design type (e.g., process 

heater, fluidized bed, stoker, fuel cell, 

suspension burner), duty cycle, 

geographic location, boiler size, burner 

type (with and without low-NOX

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

EPA should have minimized facility 

monitoring and reporting requirements; 

EPA should not have proposed the 

energy audit requirement; EPA’s 

proposed emissions standards are too 

stringent; and, EPA should provide 

more flexibility for emissions averaging. 

In response to the comments on the 

IRFA and other public comments, EPA 

made the following changes to the final 

rule. EPA adopted additional 

subcategories, including a limited-use 

subcategory for units that operate less 

than 10 percent of the operating hours 

in a year, a non-continental liquid unit 

subcategory for units with the unique 

challenges faced by remote island 

locations, and a combination 

suspension/grate boiler subcategory. 

EPA also consolidated the subcategories 

for units combusting various types of 

solid fuels, which will simplify 

compliance and will allow units to 

combust varying percentages of different 

solid fuels without triggering 

subcategory changes. EPA also 

decreased monitoring and testing costs 

by eliminating the CO CEMS 

requirement for units greater than 100 

mmBtu/hr and changing the dioxin 

testing requirement to a one-time test. 

The final rule also includes work 

practice standards for additional 

subcategories, including limited-use 

units, new small units, and units 

combusting gaseous fuels that are 

demonstrated to have similar 

contaminant levels to natural gas. 

Finally, EPA is finalizing emission 

limits that are less stringent than the 

proposed limits for most of the 

subcategory/pollutant combinations. 

The emission limit changes are largely 

due to the changes in subcategories, 

data corrections, and incorporation of 

new data into the floor calculations. 

Additional details on the changes 

discussed in this paragraph are included 

in sections IV and V of this preamble. 

While EPA did make significant 

changes based on public comment, EPA 

did not finalize a HBCA or HBELs and 

is maintaining, but clarifying, the energy 

assessment requirement. The discussion 

of the HBCA decision is included in 

section V of this preamble. Some 

changes to the energy assessment 

requirement that will reduce costs for 

small entities include a the following 

provisions: The energy assessment for 

facilities with affected boilers and 

process heaters using less than 0.3 

trillion Btu per year heat input will be 

one day in length maximum. The boiler 

system and energy use system 

accounting for at least 50 percent of the 

energy output will be evaluated to 

identify energy savings opportunities, 

within the limit of performing a one-day 

energy assessment; and the energy 

assessment for facilities with affected 

boilers and process heaters using 0.3 to 

1.0 trillion Btu per year will be 3 days 

in length maximum. The boiler system 

and any energy use system accounting 

for at least 33 percent of the energy 

output will be evaluated to identify 

energy savings opportunities, within the 

limit of performing a 3-day energy 

assessment. In addition, energy 

assessments that have been conducted 

after January 1, 2008 are considered 

adequate as long as they meet or are 

amended to meet the requirements of 

the energy assessment. 

While EPA did not make major 

adjustments to the emissions averaging 

provisions, the change to a solid fuel 

subcategory will enable all solid fuelfired units at a facility to use the 

emissions averaging provision for Hg, 

PM, and HCl. 

The rule applies to a many different 

types of small entities. The table below 

describes the small entities identified in 

the Combustion Facility Survey. 

CLASSES OF SMALL ENTITIES

NAICS NAICS description Total number of 

facilities 

Total number of 

small entities 

111 .................. Crop Production .................................................................................................................. 1 0 

113 .................. Forestry and Logging ......................................................................................................... 1 0 

115 .................. Support Activities for Agriculture and Forestry .................................................................. 1 0 

211 .................. Oil and Gas Extraction ....................................................................................................... 24 3 

212 .................. Mining (Except Oil and Gas) .............................................................................................. 14 1 

221 .................. Utilities ................................................................................................................................ 183 23 

311 .................. Food Manufacturing ............................................................................................................ 110 7 

312 .................. Beverage and Tobacco Product Manufacturing ................................................................. 5 0

313 .................. Textile Mills ......................................................................................................................... 14 1 

314 .................. Textile Product Mills ........................................................................................................... 1 0 

316 .................. Leather and Allied Product Manufacturing ......................................................................... 3 1 

321 .................. Wood Product Manufacturing ............................................................................................. 183 18 

322 .................. Paper Manufacturing .......................................................................................................... 186 14 


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CLASSES OF SMALL ENTITIES—Continued 

NAICS NAICS description Total number of 

facilities 

Total number of 

small entities 

323 .................. Printing and Related Support Activities .............................................................................. 33 5 

324 .................. Petroleum and Coal Products Manufacturing .................................................................... 84 8 

325 .................. Chemical Manufacturing ..................................................................................................... 220 17 

326 .................. Plastics and Rubber Products Manufacturing .................................................................... 89 11 

327 .................. Nonmetallic Mineral Product Manufacturing ...................................................................... 41 2 

331 .................. Primary Metal Manufacturing ............................................................................................. 57 6 

332 .................. Fabricated Metal Product Manufacturing ........................................................................... 46 8 

333 .................. Machinery Manufacturing ................................................................................................... 13 0 

334 .................. Computer and Electronic Product Manufacturing .............................................................. 2 0

335 .................. Electrical Equipment, Appliance, and Component Manufacturing ..................................... 12 0 

336 .................. Transportation Equipment Manufacturing .......................................................................... 100 7 

337 .................. Furniture and Related Product Manufacturing ................................................................... 45 8 

339 .................. Miscellaneous Manufacturing ............................................................................................. 15 1 

423 .................. Durable Goods Merchant Wholesalers .............................................................................. 1 1 

424 .................. Nondurable Goods Merchant Wholesalers ........................................................................ 1 0 

441 .................. Motor Vehicle and Parts Dealers ....................................................................................... 1 0 

481 .................. Air Transportation ............................................................................................................... 7 0 

482 .................. Rail Transportation ............................................................................................................. 1 0 

486 .................. Pipeline Transportation ....................................................................................................... 60 0 

488 .................. Support Activities for Transportation .................................................................................. 3 0 

493 .................. Warehousing and Storage .................................................................................................. 5 1 

531 .................. Real Estate ......................................................................................................................... 1 0 

541 .................. Professional, Scientific, and Technical Services ................................................................ 8 0 

561 .................. Administrative and Support Services ................................................................................. 1 0 

562 .................. Waste Management and Remediation Services ................................................................ 7 2 

611 .................. Educational Services .......................................................................................................... 29 2 

622 .................. Hospitals ............................................................................................................................. 4 0 

623 .................. Nursing and Residential Care Facilities ............................................................................. 1 0 

811 .................. Repair and Maintenance .................................................................................................... 1 0 

921 .................. Executive, Legislative, and Other General Government Support ...................................... 2 0 

928 .................. National Security and International Affairs ......................................................................... 23 0 

We compared the estimated costs to 

the sales for these entities. The results 

are found in the following table. 

SALES TESTS USING SMALL COMPANIES IDENTIFIED IN THE COMBUSTION SURVEY

Sample statistic Proposal Selected 

option 

Alternative 

option 

Mean ............................................................................................................................................ 4.9% 4.0% 3.8% 

Median ......................................................................................................................................... 0.4% 0.2% 0.4% 

Maximum ..................................................................................................................................... 72.9% 59.8% 31.4% 

Minimum ...................................................................................................................................... <0.01% <0.01% <0.01% 

Ultimate parent company observations ....................................................................................... 50 50 50 

Ultimate parent companies with sale tests exceeding 3% .......................................................... 14 8 13 

For more detail please see the RIA. 

The information collection activities 

in this ICR include initial and annual 

stack tests, fuel analyses, operating 

parameter monitoring, continuous O2 

monitoring for all units greater than 10 

mmBtu/hr, continuous emission 

monitoring for PM at units greater than 

250 mmBtu/hr, certified energy audits, 

annual or biennial tune-ups (depending 

on the size of the combustion 

equipment), preparation of a sitespecific monitoring plan and a sitespecific fuel monitoring plan, one-time 

and periodic reports, and the 

maintenance of records. Based on the 

distribution of major source facilities 

with affected boilers or process heaters 

reported in the 2008 survey entitled 

‘‘Information Collection Effort for 

Facilities with Combustion Units (ICR 

No. 2286.01),’’ there are 1,639 existing 

facilities with affected boilers or process 

heaters. Of these, 94 percent are located 

in the private sector and the remaining 

6 percent are located in the public 

sector. A table included in the FRFA 

summarizes the types and number of 

each type of small entities expected to 

be affected by the major source rule. 

The Agency expects that persons with 

knowledge of .pdf software, spreadsheet 

and relational database programs will be 

necessary in order to prepare the report 

or record. Based on experience with 

previous emission stack testing, we 

expect most facilities to contract out 

preparation of the reports associated 

with emission stack testing, including 

creation of the Electronic Reporting 

Tool submittal which will minimize the 

need for in depth knowledge of 

databases or spreadsheet software at the 

source. We also expect affected sources 

will need to work with web-based 

applicability tools and flowcharts to 

determine the requirements applicable 

to them, knowledge of the heat input 

capacity and fuel use of the combustion 


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units at each facility will be necessary 

in order to develop the reports and 

determine initial applicability to the 

rule. Affected facilities will also need 

skills associated with vendor selection 

in order to identify service providers 

that can help them complete their 

compliance requirements, as necessary. 

As required by section 212 of 

SBREFA, EPA also is preparing a Small 

Entity Compliance Guide to help small 

entities comply with this rule. Small 

entities will be able to obtain a copy of 

the Small Entity Compliance guide at 

the following Web site: http:// 

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

boilerpg.html. The guide should be 

available by May 20, 2011. 

D. Unfunded Mandates Reform Act of 

1995 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

we generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may result 

in expenditures to State, local, and 

tribal governments, in the aggregate, or 

to the private sector, of $100 million or 

more in any 1 year. Before promulgating 

a rule for which a written statement is 

needed, section 205 of the UMRA 

generally requires us to identify and 

consider a reasonable number of 

regulatory alternatives and adopt the 

least costly, most cost-effective or least 

burdensome alternative that achieves 

the objectives of the rule. The 

provisions of section 205 do not apply 

when they are inconsistent with 

applicable law. Moreover, section 205 

allows us to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before we establish 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, we must develop a small 

government agency plan under section 

203 of the UMRA. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of regulatory proposals 

with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this final 

rule contains a Federal mandate that 

may result in expenditures of $100 

million or more for State, local, and 

Tribal governments, in the aggregate, or 

the private sector in any 1 year. 

Accordingly, we have prepared a 

written statement entitled ‘‘Unfunded 

Mandates Reform Act Analysis for the 

Proposed Industrial Boilers and Process 

Heaters NESHAP’’ under section 202 of 

the UMRA which is summarized below. 

1. Statutory Authority 

As discussed in section I of this 

preamble, the statutory authority for this 

final rulemaking is section 112 of the 

CAA. Title III of the CAA Amendments 

was enacted to reduce nationwide air 

toxic emissions. Section 112(b) of the 

CAA lists the 188 chemicals, 

compounds, or groups of chemicals 

deemed by Congress to be HAP. These 

toxic air pollutants are to be regulated 

by NESHAP. 

Section 112(d) of the CAA directs us 

to develop NESHAP which require 

existing and new major sources to 

control emissions of HAP using MACT 

based standards. This NESHAP applies 

to all ICI boilers and process heaters 

located at major sources of HAP 

emissions. 

In compliance with section 205(a) of 

the UMRA, we identified and 

considered a reasonable number of 

regulatory alternatives. Additional 

information on the costs and 

environmental impacts of these 

regulatory alternatives is presented in 

the docket. 

The regulatory alternative upon 

which this final rule is based represents 

the MACT floor for industrial boilers 

and process heaters and, as a result, it 

is the least costly and least burdensome 

alternative. 

2. Social Costs and Benefits 

The regulatory impact analysis 

prepared for this final rule, including 

the Agency’s assessment of costs and 

benefits, is detailed in the ‘‘Regulatory 

Impact Analysis for the Proposed 

Industrial Boilers and Process Heaters 

MACT’’ in the docket. Based on 

estimated compliance costs associated 

with this final rule and the predicted 

change in prices and production in the 

affected industries, the estimated social 

costs of this final rule are $1.5 billion 

(2008 dollars). 

It is estimated that 3 years after 

implementation of this final rule, HAP 

would be reduced by thousands of tons, 

including reductions in hydrochloric 

acid, hydrogen fluoride, metallic HAP 

including Hg, and several other organic 

HAP from boilers and process heaters. 

Studies have determined a relationship 

between exposure to these HAP and the 

onset of cancer, however, the Agency is 

unable to provide a monetized estimate 

of the HAP benefits at this time. In 

addition, there are significant 

reductions in PM2.5 and in SO2 that 

would occur, including 28 thousand 

tons of PM2.5 and 443 thousand tons of 

SO2. These reductions occur within 3 

years after the implementation of the 

proposed regulation and are expected to 

continue throughout the life of the 

affected sources. The major health effect 

associated with reducing PM2.5 and 

PM2.5 precursors (such as SO2) is a 

reduction in premature mortality. Other 

health effects associated with PM2.5

emission reductions include avoiding 

cases of chronic bronchitis, heart 

attacks, asthma attacks, and work-lost 

days (i.e., days when employees are 

unable to work). While we are unable to 

monetize the benefits associated with 

the HAP emissions reductions, we are 

able to monetize the benefits associated 

with the PM2.5 and SO2 emissions 

reductions. For SO2 and PM2.5, we 

estimated the benefits associated with 

health effects of PM but were unable to 

quantify all categories of benefits 

(particularly those associated with 

ecosystem and visibility effects). Our 

estimates of the monetized benefits in 

2014 associated with the 

implementation of the proposed 

alternative is range from $22 billion 

(2008 dollars) to $54 billion (2008 

dollars) when using a 3 percent 

discount rate (or from $20 billion (2008 

dollars) to $49 billion (2008 dollars) 

when using a 7 percent discount rate). 

This estimate, at a 3 percent discount 

rate, is about $20.5 billion (2008 dollars) 

to $52.5 billion (2008 dollars) higher 

than the estimated social costs shown 

earlier in this section. The general 

approach used to value benefits is 

discussed in more detail earlier in this 

preamble. For more detailed 

information on the benefits estimated 

for the rulemaking, refer to the RIA in 

the docket. 

3. Future and Disproportionate Costs 

The UMRA requires that we estimate, 

where accurate estimation is reasonably 

feasible, future compliance costs 

imposed by this final rule and any 

disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of the rule are discussed previously in 

this preamble. 

We do not believe that there will be 

any disproportionate budgetary effects 

of this final rule on any particular areas 

of the country, State or local 

governments, types of communities 

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


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segments. See the results of the 

‘‘Economic Impact Analysis of the 

Proposed Industrial Boilers and Process 

Heaters NESHAP,’’ the results of which 

are discussed previously in this 

preamble. 

4. Effects on the National Economy 

The Unfunded Mandates Act requires 

that we estimate the effect of this final 

rule on the national economy. To the 

extent feasible, we must estimate the 

effect on productivity, economic 

growth, full employment, creation of 

productive jobs, and international 

competitiveness of the U.S. goods and 

services, if we determine that accurate 

estimates are reasonably feasible and 

that such effect is relevant and material. 

The nationwide economic impact of 

this final rule is presented in the 

‘‘Economic Impact Analysis for the 

Industrial Boilers and Process Heaters 

MACT’’ in the docket. This analysis 

provides estimates of the effect of this 

rule on some of the categories 

mentioned above. The results of the 

economic impact analysis are 

summarized previously in this 

preamble. The results show that there 

will be a small impact on prices and 

output, and little impact on 

communities that may be affected by 

this final rule. In addition, there should 

be little impact on energy markets (in 

this case, coal, natural gas, petroleum 

products, and electricity). Hence, the 

potential impacts on the categories 

mentioned above should be small. 

5. Consultation With Government 

Officials 

The Unfunded Mandates Act requires 

that we describe the extent of the 

Agency’s prior consultation with 

affected State, local, and tribal officials, 

summarize the officials’ comments or 

concerns, and summarize our response 

to those comments or concerns. In 

addition, section 203 of the UMRA 

requires that we develop a plan for 

informing and advising small 

governments that may be significantly 

or uniquely impacted by a proposal. We 

have consulted with State and local air 

pollution control officials. We have also 

held meetings on this final rule with 

many of the stakeholders from 

numerous individual companies, 

institutions, environmental groups, 

consultants and vendors, labor unions, 

and other interested parties. We have 

added materials to the Air Docket to 

document these meetings. 

In addition, we have determined that 

this final rule contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

While some small governments may 

have some sources affected by this final 

rule, the impacts are not expected to be 

significant. Therefore, this final rule is 

not subject to the requirements of 

section 203 of the UMRA. 

E. Executive Order 13132: Federalism 

Executive Order 13132 (64 FR 43255, 

August 10, 1999), requires EPA to 

develop an accountable process to 

ensure ‘‘meaningful and timely input by 

State and local officials in the 

development of regulatory policies that 

have federalism implications.’’ ‘‘Policies 

that have federalism implications’’ is 

defined in the Executive Order to 

include regulations that have 

‘‘substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

This final rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. Thus, Executive 

Order 13132 does not apply to this final 

rule. In the spirit of Executive Order 

13132, and consistent with EPA policy 

to promote communications between 

EPA and State and local governments, 

EPA specifically solicited comment on 

this proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to the Executive Order 13175 

(65 FR 67249, November 9, 2000) EPA 

may not issue a regulation that has tribal 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by tribal governments, or 

EPA consults with tribal officials early 

in the process of developing the 

proposed regulation and develops a 

tribal summary impact statement. 

Executive Order 13175 requires EPA to 

develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ 

EPA has concluded that this action 

may have tribal implications. However, 

it will neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt Tribal law. This rule would 

impose requirements on owners and 

operators of major industrial boilers. We 

are only aware of a few installations of 

industrial, commercial, or institutional 

boilers owned or operated by Indian 

tribal governments. We conducted 

outreach to tribal environmental staff on 

this rule through the Tribal Air 

Newsletter, discussions at the National 

Tribal Forum and the monthly 

conference call with the National Tribal 

Air Association, we also hosted a 

webinar on the proposed rule in which 

tribal environmental staff participated. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045 (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Orders 12866 and 13563, and (2) 

concerns an environmental health or 

safety risk that EPA has reason to 

believe may have a disproportionate 

effect on children. If the regulatory 

action meets both criteria, the Agency 

must evaluate the environmental health 

or safety effects of this planned rule on 

children, and explain why this planned 

regulation is preferable to other 

potentially effective and reasonably 

feasible alternatives considered by the 

Agency. 

This final rule is not subject to 

Executive Order 13045 because the 

Agency does not believe the 

environmental health risks or safety 

risks addressed by this action present a 

disproportionate risk to children. The 

reason for this determination is that this 

final rule is based solely on technology 

performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211, (66 FR 28355, 

May 22, 2001), provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, a 

Statement of Energy Effects for certain 

actions identified as significant energy 

actions. Section 4(b) of Executive Order 

13211 defines ‘‘significant energy 

actions’’ as ‘‘any action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation, including 

notices of inquiry, advance notices of 

proposed rulemaking, and notices of 

proposed rulemaking: (1)(i) that is a 

significant regulatory action under 

Executive Orders 12866, 13563, or any 

successor order, and (ii) is likely to have 


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a significant adverse effect on the 

supply, distribution, or use of energy; or 

(2) that is designated by the 

Administrator of the Office of 

Information and Regulatory Affairs as a 

significant energy action.’’ This final 

rule is not a ‘‘significant regulatory 

action’’ because it is not likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

The basis for the determination is as 

follows. 

We estimate a 0.05 percent price 

increase for the energy sector and a 

¥0.02 percent percentage change in 

production. We estimate a 0.09 percent 

increase in energy imports. For more 

information on the estimated energy 

effects, please refer to the economic 

impact analysis for this final rule. The 

analysis is available in the public 

docket. 

Therefore, we conclude that this final 

rule when implemented is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

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

15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This rulemaking involves technical 

standards. EPA cites the following 

standards in the final rule: EPA 

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

17, 19, 23, 26, 26A, 29 of 40 CFR part 

60. Consistent with the NTTAA, EPA 

conducted searches to identify 

voluntary consensus standards in 

addition to these EPA methods. No 

applicable voluntary consensus 

standards were identified for EPA 

Methods 2F, 2G, 5D, and 19. The search 

and review results have been 

documented and are placed in the 

docket for the proposed rule. 

The three voluntary consensus 

standards described below were 

identified as acceptable alternatives to 

EPA test methods for the purposes of 

the final rule. 

The voluntary consensus standard 

American Society of Mechanical 

Engineers (ASME) PTC 19–10–1981– 

Part 10, ‘‘Flue and Exhaust Gas 

Analyses,’’ is cited in the proposed rule 

for its manual method for measuring the 

oxygen, CO2, and CO content of exhaust 

gas. This part of ASME PTC 19–10– 

1981–Part 10 is an acceptable 

alternative to Method 3B. 

The voluntary consensus standard 

ASTM D6522–00, ‘‘Standard Test 

Method for the Determination of 

Nitrogen Oxides, Carbon Monoxide, and 

Oxygen Concentrations in Emissions 

from Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers 

and Process Heaters Using Portable 

Analyzers’’ is an acceptable alternative 

to EPA Method 3A for identifying CO 

and oxygen concentrations for this final 

rule when the fuel is natural gas. 

The voluntary consensus standard 

ASTM Z65907, ‘‘Standard Method for 

Both Speciated and Elemental Mercury 

Determination,’’ is an acceptable 

alternative to EPA Method 29 (portion 

for Hg only) for the purpose of this final 

rule. This standard can be used in the 

final rule to determine the Hg 

concentration in stack gases for boilers 

with rated heat input capacities of 

greater than 250 MMBtu/hr. 

In addition to the voluntary 

consensus standards EPA used in the 

proposed rule, the search for emissions 

measurement procedures identified 15 

other voluntary consensus standards. 

EPA determined that 13 of these 15 

standards identified for measuring 

emissions of the HAP or surrogates 

subject to emission standards in the 

proposed rule were impractical 

alternatives to EPA test methods for the 

purposes of this final rule. Therefore, 

EPA does not intend to adopt these 

standards for this purpose. The reasons 

for this determination for the 13 

methods are discussed below. 

The voluntary consensus standard 

ASTM D3154–00, ‘‘Standard Method for 

Average Velocity in a Duct (Pitot Tube 

Method),’’ is impractical as an 

alternative to EPA Methods 1, 2, 3B, and 

4 for the purposes of the proposed 

rulemaking since the standard appears 

to lack in quality control and quality 

assurance requirements. Specifically, 

ASTM D3154–00 does not include the 

following: (1) Proof that openings of 

standard pitot tube have not plugged 

during the test; (2) if differential 

pressure gauges other than inclined 

manometers (e.g., magnehelic gauges) 

are used, their calibration must be 

checked after each test series; and (3) 

the frequency and validity range for 

calibration of the temperature sensors. 

The voluntary consensus standard 

ASTM D3464–96 (2001), ‘‘Standard Test 

Method Average Velocity in a Duct 

Using a Thermal Anemometer,’’ is 

impractical as an alternative to EPA 

Method 2 for the purposes of the 

proposed rule primarily because 

applicability specifications are not 

clearly defined, e.g., range of gas 

composition, temperature limits. Also, 

the lack of supporting quality assurance 

data for the calibration procedures and 

specifications, and certain variability 

issues that are not adequately addressed 

by the standard limit EPA’s ability to 

make a definitive comparison of the 

method in these areas. 

The voluntary consensus standard 

ISO 10780:1994, ‘‘Stationary Source 

Emissions—Measurement of Velocity 

and Volume Flowrate of Gas Streams in 

Ducts,’’ is impractical as an alternative 

to EPA Method 2 in the proposed rule. 

The standard recommends the use of an 

L-shaped pitot, which historically has 

not been recommended by EPA. EPA 

specifies the S-type design which has 

large openings that are less likely to 

plug up with dust. 

The voluntary consensus standard, 

CAN/CSA Z223.2–M86 (1999), ‘‘Method 

for the Continuous Measurement of 

Oxygen, Carbon Dioxide, Carbon 

Monoxide, Sulphur Dioxide, and Oxides 

of Nitrogen in Enclosed Combustion 

Flue Gas Streams,’’ is unacceptable as a 

substitute for EPA Method 3A since it 

does not include quantitative 

specifications for measurement system 

performance, most notably the 

calibration procedures and instrument 

performance characteristics. The 

instrument performance characteristics 

that are provided are nonmandatory and 

also do not provide the same level of 

quality assurance as the EPA methods. 

For example, the zero and span/ 

calibration drift is only checked weekly, 

whereas the EPA methods require drift 

checks after each run. 

Two very similar voluntary consensus 

standards, ASTM D5835–95 (2001), 

‘‘Standard Practice for Sampling 

Stationary Source Emissions for 

Automated Determination of Gas 

Concentration,’’ and ISO 10396:1993, 

‘‘Stationary Source Emissions: Sampling 

for the Automated Determination of Gas 

Concentrations,’’ are impractical 

alternatives to EPA Method 3A for the 

purposes of this final rule because they 

lack in detail and quality assurance/ 

quality control requirements. 

Specifically, these two standards do not 

include the following: (1) Sensitivity of 

the method; (2) acceptable levels of 

analyzer calibration error; (3) acceptable 

levels of sampling system bias; (4) zero 

drift and calibration drift limits, time 

span, and required testing frequency; (5) 

a method to test the interference 

response of the analyzer; (6) procedures 


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to determine the minimum sampling 

time per run and minimum 

measurement time; and (7) 

specifications for data recorders, in 

terms of resolution (all types) and 

recording intervals (digital and analog 

recorders, only). 

The voluntary consensus standard 

ISO 12039:2001, ‘‘Stationary Source 

Emissions—Determination of Carbon 

Monoxide, Carbon Dioxide, and 

Oxygen—Automated Methods,’’ is not 

acceptable as an alternative to EPA 

Method 3A. This ISO standard is similar 

to EPA Method 3A, but is missing some 

key features. In terms of sampling, the 

hardware required by ISO 12039:2001 

does not include a 3-way calibration 

valve assembly or equivalent to block 

the sample gas flow while calibration 

gases are introduced. In its calibration 

procedures, ISO 12039:2001 only 

specifies a two-point calibration while 

EPA Method 3A specifies a three-point 

calibration. Also, ISO 12039:2001 does 

not specify performance criteria for 

calibration error, calibration drift, or 

sampling system bias tests as in the EPA 

method, although checks of these 

quality control features are required by 

the ISO standard. 

The voluntary consensus standard 

ASME PTC–38–80 R85 (1985), 

‘‘Determination of the Concentration of 

Particulate Matter in Gas Streams,’’ is 

not acceptable as an alternative for EPA 

Method 5 because ASTM PTC–38–80 is 

not specific about equipment 

requirements, and instead presents the 

options available and the pro’s and 

con’s of each option. The key specific 

differences between ASME PTC–38–80 

and the EPA methods are that the ASME 

standard: (1) Allows in-stack filter 

placement as compared to the out-ofstack filter placement in EPA Methods 

5 and 17; (2) allows many different 

types of nozzles, pitots, and filtering 

equipment; (3) does not specify a filter 

weighing protocol or a minimum 

allowable filter weight fluctuation as in 

the EPA methods; and (4) allows filter 

paper to be only 99 percent efficient, as 

compared to the 99.95 percent 

efficiency required by the EPA methods. 

The voluntary consensus standard 

ASTM D3685/D3685M–98, ‘‘Test 

Methods for Sampling and 

Determination of Particulate Matter in 

Stack Gases,’’ is similar to EPA Methods 

5 and 17, but is lacking in the following 

areas that are needed to produce quality, 

representative particulate data: (1) 

Requirement that the filter holder 

temperature should be between 120° C 

and 134° C, and not just ‘‘above the acid 

dew-point;’’ (2) detailed specifications 

for measuring and monitoring the filter 

holder temperature during sampling; (3) 

procedures similar to EPA Methods 1, 2, 

3, and 4, that are required by EPA 

Method 5; (4) technical guidance for 

performing the Method 5 sampling 

procedures, e.g., maintaining and 

monitoring sampling train operating 

temperatures, specific leak check 

guidelines and procedures, and use of 

reagent blanks for determining and 

subtracting background contamination; 

and (5) detailed equipment and/or 

operational requirements, e.g., 

component exchange leak checks, use of 

glass cyclones for heavy particulate 

loading and/or water droplets, operating 

under a negative stack pressure, 

exchanging particulate loaded filters, 

sampling preparation and 

implementation guidance, sample 

recovery guidance, data reduction 

guidance, and particulate sample 

calculations input. 

The voluntary consensus standard 

ISO 9096:1992, ‘‘Determination of 

Concentration and Mass Flow Rate of 

Particulate Matter in Gas Carrying 

Ducts—Manual Gravimetric Method,’’ is 

not acceptable as an alternative for EPA 

Method 5. Although sections of ISO 

9096 incorporate EPA Methods 1, 2, and 

5 to some degree, this ISO standard is 

not equivalent to EPA Method 5 for 

collection of particulate matter. The 

standard ISO 9096 does not provide 

applicable technical guidance for 

performing many of the integral 

procedures specified in Methods 1, 2, 

and 5. Major performance and 

operational details are lacking or 

nonexistent, and detailed quality 

assurance/quality control guidance for 

the sampling operations required to 

produce quality, representative 

particulate data (e.g., guidance for 

maintaining and monitoring train 

operating temperatures, specific leak 

check guidelines and procedures, and 

sample preparation and recovery 

procedures) are not provided by the 

standard, as in EPA Method 5. Also, 

details of equipment and/or operational 

requirements, such as those specified in 

EPA Method 5, are not included in the 

ISO standard, e.g., stack gas moisture 

measurements, data reduction guidance, 

and particulate sample calculations. 

The voluntary consensus standard 

CAN/CSA Z223.1–M1977, ‘‘Method for 

the Determination of Particulate Mass 

Flows in Enclosed Gas Streams,’’ is not 

acceptable as an alternative for EPA 

Method 5. Detailed technical procedures 

and quality control measures that are 

required in EPA Methods 1, 2, 3, and 4 

are not included in CAN/CSA Z223.1. 

Second, CAN/CSA Z223.1 does not 

include the EPA Method 5 filter 

weighing requirement to repeat 

weighing every 6 hours until a constant 

weight is achieved. Third, EPA Method 

5 requires the filter weight to be 

reported to the nearest 0.1 milligram 

(mg), while CAN/CSA Z223.1 requires 

only to the nearest 0.5 mg. Also, CAN/ 

CSA Z223.1 allows the use of a standard 

pitot for velocity measurement when 

plugging of the tube opening is not 

expected to be a problem. Whereas, EPA 

Method 5 requires an S-shaped pitot. 

The voluntary consensus standard EN 

1911–1,2,3 (1998), ‘‘Stationary Source 

Emissions-Manual Method of 

Determination of HCl-Part 1: Sampling 

of Gases Ratified European Text-Part 2: 

Gaseous Compounds Absorption 

Ratified European Text-Part 3: 

Adsorption Solutions Analysis and 

Calculation Ratified European Text,’’ is 

impractical as an alternative to EPA 

Methods 26 and 26A. Part 3 of this 

standard cannot be considered 

equivalent to EPA Method 26 or 26A 

because the sample absorbing solution 

(water) would be expected to capture 

both HCl and chlorine gas, if present, 

without the ability to distinguish 

between the two. The EPA Methods 26 

and 26A use an acidified absorbing 

solution to first separate HCl and 

chlorine gas so that they can be 

selectively absorbed, analyzed, and 

reported separately. In addition, in EN 

1911 the absorption efficiency for 

chlorine gas would be expected to vary 

as the pH of the water changed during 

sampling. 

The voluntary consensus standard EN 

13211 (1998), is not acceptable as an 

alternative to the Hg portion of EPA 

Method 29 primarily because it is not 

validated for use with impingers, as in 

the EPA method, although the method 

describes procedures for the use of 

impingers. This European standard is 

validated for the use of fritted bubblers 

only and requires the use of a side 

(split) stream arrangement for isokinetic 

sampling because of the low sampling 

rate of the bubblers (up to 3 liters per 

minute, maximum). Also, only two 

bubblers (or impingers) are required by 

EN 13211, whereas EPA Method 29 

require the use of six impingers. In 

addition, EN 13211 does not include 

many of the quality control procedures 

of EPA Method 29, especially for the use 

and calibration of temperature sensors 

and controllers, sampling train assembly 

and disassembly, and filter weighing. 

Two of the 15 voluntary consensus 

standards identified in this search were 

not available at the time the review was 

conducted for the purposes of the 

proposed rule because they are under 

development by a voluntary consensus 

body: ASME/BSR MFC 13M, ‘‘Flow 

Measurement by Velocity Traverse,’’ for 

EPA Method 2 (and possibly 1); and 


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ASME/BSR MFC 12M, ‘‘Flow in Closed 

Conduits Using Multiport Averaging 

Pitot Primary Flowmeters,’’ for EPA 

Method 2. 

Section 63.7520 and Tables 4A 

through 4D to subpart DDDDD, 40 CFR 

part 63, list the EPA testing methods 

included in the proposed rule. Under 

§ 63.7(f) and § 63.8(f) of subpart A of the 

General Provisions, a source may apply 

to EPA for permission to use alternative 

test methods or alternative monitoring 

requirements in place of any of the EPA 

testing methods, performance 

specifications, or procedures. 

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes Federal 

executive policy on environmental 

justice (EJ). Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations, low-income, and Tribal 

populations in the United States. 

This final action establishes national 

emission standards for new and existing 

industrial, commercial, institutional 

boilers and process heaters that combust 

non-waste materials (i.e. natural gas, 

process gas, fuel oil, biomass, and coal) 

and that are located at a major source. 

EPA estimates that there are 

approximately 13,840 units located at 

1,639 facilities covered by this final 

rule. 

This final rule will reduce emissions 

of all the listed HAP that come from 

boilers and process heaters. This 

includes metals (Hg, arsenic, beryllium, 

cadmium, chromium, lead, Mn, nickel, 

and selenium), organics (POM, 

acetaldehyde, acrolein, benzene, dioxin/ 

furan, ethylene dichloride, 

formaldehyde, and polychlorinated 

biphenyls), hydrochloric acid, and 

hydrofluoric acid. Adverse health 

effects from these pollutants include 

cancer, irritation of the lungs, skin, and 

mucus membranes; effects on the 

central nervous system, damage to the 

kidneys, and other acute health 

disorders. This final rule will also result 

in substantial reductions of criteria 

pollutants such as CO, NOX, PM, and 

SO2. SO2 and nitrogen dioxide are 

precursors for the formation of PM2.5

and ozone. Reducing these emissions 

will reduce ozone and PM2.5 formation 

and associated health effects, such as 

adult premature mortality, chronic and 

acute bronchitis, asthma, and other 

respiratory and cardiovascular diseases. 

(Please refer to the RIA contained in the 

docket for this rulemaking.) 

Based on the fact that this final rule 

does not allow emission increases, EPA 

has determined that this final rule will 

not have disproportionately high and 

adverse human health or environmental 

effects on minority, low-income, or 

Tribal populations. To address 

Executive Order 12898, EPA has 

conducted analyses to determine the 

aggregate demographic makeup of the 

communities near affected sources. 

EPA’s demographic analysis of 

populations within the three-mile 

radius showed that major source boilers 

are located in areas where minorities are 

overrepresented when compared to the 

national average. For these same areas, 

there is also an overrepresentation of 

population below the poverty line as 

compared to the national average. The 

results of the demographic analysis are 

presented in ‘‘Review of Environmental 

Justice Impacts’’, April 2010, a copy of 

which is available in the docket. 

However, to the extent that any 

minority, low income, or Tribal 

subpopulation is disproportionately 

impacted by the current emissions as a 

result of the proximity of their homes to 

these sources, that subpopulation also 

stands to see increased environmental 

and health benefit from the emissions 

reductions called for by this rule. 

EPA defines ‘‘Environmental Justice’’ 

to include meaningful involvement of 

all people regardless of race, color, 

national origin, or income with respect 

to the development, implementation, 

and enforcement of environmental laws, 

regulations, and polices. To promote 

meaningful involvement, EPA has 

developed a communication and 

outreach strategy to ensure that 

interested communities have access to 

this final rule and are aware of its 

content. EPA also ensured that 

interested communities had an 

opportunity to comment during the 

comment period. During the comment 

period that followed the June 2010 

proposal, EPA publicized the 

rulemaking via EJ newsletters, Tribal 

newsletters, EJ listservs, and the 

internet, including the Office of Policy’s 

(OP) Rulemaking Gateway Web site 

(http://yosemite.epa.gov/opei/ 

RuleGate.nsf/). EPA will also provide 

general rulemaking fact sheets (e.g., why 

is this important for my community) for 

EJ community groups and conduct 

conference calls with interested 

communities. In addition, State and 

federal permitting requirements will 

provide State and local governments 

and members of affected communities 

the opportunity to provide comments on 

the permit conditions associated with 

permitting the sources affected by this 

rulemaking. 

K. Congressional Review Act 

The Congressional Review Act, 5 

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

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this final rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). This 

rule will be effective May 20, 2011. 

List of Subjects in 40 CFR part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: February 21, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 63 of 

the Code of the Federal Regulations is 

amended as follows: 

PART 63—[AMENDED] 

■ 1. The authority citation for part 63 

continues to read as follows: 

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

■ 2. Section 63.14 is amended by: 

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

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

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

■ b. Removing and reserving paragraphs 

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

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

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

(68). 

■ d. Adding paragraphs (p) and (q). 

§ 63.14 Incorporations by reference. 

* * * * * 

(b) * * * 

* * * * * 

(27) ASTM D6522–00, Standard Test 

Method for Determination of Nitrogen 

Oxides, Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 


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Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, IBR approved for 

§ 63.9307(c)(2). 

* * * * * 

(35) ASTM D6784–02 (Reapproved 

2008) Standard Test Method for 

Elemental, Oxidized, Particle-Bound 

and Total Mercury in Flue Gas 

Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method), 

approved April 1, 2008, IBR approved 

for table 1 to subpart DDDDD of this 

part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD of this 

part, table 12 to subpart DDDDD of this 

part, and table 4 to subpart JJJJJJ of this 

part. 

* * * * * 

(39) ASTM D388–05 Standard 

Classification of Coals by Rank, 

approved September 15, 2005, IBR 

approved for § 63.7575 and § 63.11237. 

(40) ASTM D396–10 Standard 

Specification for Fuel Oils, approved 

October 1, 2010, IBR approved for 

§ 63.7575. 

(41) ASTM D1835–05 Standard 

Specification for Liquefied Petroleum 

(LP) Gases, approved April 1, 2005, IBR 

approved for § 63.7575 and § 63.11237. 

(42) ASTM D2013/D2013M–09 

Standard Practice for Preparing Coal 

Samples for Analysis, approved 

November 1, 2009, IBR approved for 

table 6 to subpart DDDDD of this part 

and table 5 to subpart JJJJJJ of this part. 

(43) ASTM D2234/D2234M–10 

Standard Practice for Collection of a 

Gross Sample of Coal, approved January 

1, 2010, IBR approved for table 6 to 

subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part. 

(44) ASTM D3173–03 (Reapproved 

2008) Standard Test Method for 

Moisture in the Analysis Sample of Coal 

and Coke, approved February 1, 2008, 

IBR approved for table 6 to subpart 

DDDDD of this part and table 5 to 

subpart JJJJJJ of this part. 

* * * * * 

(47) ASTM D5198–09 Standard 

Practice for Nitric Acid Digestion of 

Solid Waste, approved February 1, 2009, 

IBR approved for table 6 to subpart 

DDDDD of this part and table 5 to 

subpart JJJJJJ of this part. 

(48) ASTM D5865–10a Standard Test 

Method for Gross Calorific Value of Coal 

and Coke, approved May 1, 2010, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

(49) ASTM D6323–98 (Reapproved 

2003) Standard Guide for Laboratory 

Subsampling of Media Related to Waste 

Management Activities, approved 

August 10, 2003, IBR approved for table 

6 to subpart DDDDD of this part and 

table 5 to subpart JJJJJJ of this part. 

(50) ASTM E711–87 (Reapproved 

2004) Standard Test Method for Gross 

Calorific Value of Refuse-Derived Fuel 

by the Bomb Calorimeter, approved 

August 28, 1987, IBR approved for table 

6 to subpart DDDDD of this part and 

table 5 to subpart JJJJJJ of this part. 

(51) ASTM E776–87 (Reapproved 

2009) Standard Test Method for Forms 

of Chlorine in Refuse-Derived Fuel, 

approved July 1, 2009, IBR approved for 

table 6 to subpart DDDDD of this part. 

(52) ASTM E871–82 (Reapproved 

2006) Standard Test Method for 

Moisture Analysis of Particulate Wood 

Fuels, approved November 1, 2006, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

* * * * * 

(57) ASTM D6721–01 (Reapproved 

2006) Standard Test Method for 

Determination of Chlorine in Coal by 

Oxidative Hydrolysis Microcoulometry, 

approved April 1, 2006, IBR approved 

for table 6 to subpart DDDDD of this 

part. 

* * * * * 

(61) ASTM D6722–01 (Reapproved 

2006) Standard Test Method for Total 

Mercury in Coal and Coal Combustion 

Residues by the Direct Combustion 

Analysis, approved April 1, 2006, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

* * * * * 

(64) ASTM D6522–00 (Reapproved 

2005), Standard Test Method for 

Determination of Nitrogen Oxides, 

Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, approved October 1, 2005, 

IBR approved for table 4 to subpart 

ZZZZ of this part, table 5 to subpart 

DDDDD of this part, and table 4 to 

subpart JJJJJJ of this part. 

* * * * * 

(66) ASTM D4084–07 Standard Test 

Method for Analysis of Hydrogen 

Sulfide in Gaseous Fuels (Lead Acetate 

Reaction Rate Method), approved June 

1, 2007, IBR approved for table 6 to 

subpart DDDDD of this part. 

(67) ASTM D5954–98 (Reapproved 

2006), Standard Test Method for 

Mercury Sampling and Measurement in 

Natural Gas by Atomic Absorption 

Spectroscopy, approved December 1, 

2006, IBR approved for table 6 to 

subpart DDDDD of this part. 

(68) ASTM D6350–98 (Reapproved 

2003) Standard Test Method for 

Mercury Sampling and Analysis in 

Natural Gas by Atomic Fluorescence 

Spectroscopy, approved May 10, 2003, 

IBR approved for table 6 to subpart 

DDDDD of this part. 

* * * * * 

(i) * * * 

(1) ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses [Part 

10, Instruments and Apparatus],’’ IBR 

approved for §§ 63.309(k)(1)(iii), 

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

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

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

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

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

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

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

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

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

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

table 5 to subpart DDDDD of this part, 

table 1 to subpart ZZZZZ of this part, 

and table 4 to subpart JJJJJJ of this part. 

* * * * * 

(p) The following material is available 

from the U.S. Environmental Protection 

Agency, 1200 Pennsylvania Avenue, 

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

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

(1) National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for 

Integrated Iron and Steel Plants— 

Background Information for Proposed 

Standards, Final Report, EPA–453/R– 

01–005, January 2001, IBR approved for 

§ 63.7491(g). 

(2) Office Of Air Quality Planning 

And Standards (OAQPS), Fabric Filter 

Bag Leak Detection Guidance, EPA–454/ 

R–98–015, September 1997, IBR 

approved for § 63.7525(j)(2) and 

§ 63.11224(f)(2). 

(3) SW–846–3020A, Acid Digestion of 

Aqueous Samples And Extracts For 

Total Metals For Analysis By GFAA 

Spectroscopy, Revision 1, July 1992, in 

EPA Publication No. SW–846, Test 

Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third 

Edition, IBR approved for table 6 to 

subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part. 

(4) SW–846–3050B, Acid Digestion of 

Sediments, Sludges, And Soils, Revision 

2, December 1996, in EPA Publication 

No. SW–846, Test Methods for 

Evaluating Solid Waste, Physical/ 

Chemical Methods, Third Edition, IBR 

approved for table 6 to subpart DDDDD 

of this part and table 5 to subpart JJJJJJ 

of this part. 

(5) SW–846–7470A, Mercury In 

Liquid Waste (Manual Cold-Vapor 

Technique), Revision 1, September 

1994, in EPA Publication No. SW–846, 


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Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD of this part and table 

5 to subpart JJJJJJ of this part. 

(6) SW–846–7471B, Mercury In Solid 

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

2007, in EPA Publication No. SW–846, 

Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD of this part and table 

5 to subpart JJJJJJ of this part. 

(7) SW–846–9250, Chloride 

(Colorimetric, Automated Ferricyanide 

AAI), Revision 0, September 1986, in 

EPA Publication No. SW–846, Test 

Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third 

Edition, IBR approved for table 6 to 

subpart DDDDD of this part. 

(q) The following material is available 

for purchase from the International 

Standards Organization (ISO), 1, ch. de 

la Voie-Creuse, Case postale 56, CH– 

1211 Geneva 20, Switzerland, +41 22 

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

home.htm. 

(1) ISO 6978–1:2003(E), Natural Gas— 

Determination of Mercury—Part 1: 

Sampling of Mercury by Chemisorption 

on Iodine, First edition, October 15, 

2003, IBR approved for table 6 to 

subpart DDDDD of this part. 

(2) ISO 6978–2:2003(E), Natural gas— 

Determination of Mercury—Part 2: 

Sampling of Mercury by Amalgamation 

on Gold/Platinum Alloy, First edition, 

October 15, 2003, IBR approved for table 

6 to subpart DDDDD of this part. 

■ 3. Part 63 is amended by revising 

subpart DDDDD to read as follows: 

Subpart DDDDD—National Emission 

Standards for Hazardous Air Pollutants 

for Major Sources: Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters 

Sec. 

What This Subpart Covers 

63.7480 What is the purpose of this 

subpart? 

63.7485 Am I subject to this subpart? 

63.7490 What is the affected source of this 

subpart? 

63.7491 Are any boilers or process heaters 

not subject to this subpart? 

63.7495 When do I have to comply with 

this subpart? 

Emission Limitations and Work Practice 

Standards 

63.7499 What are the subcategories of 

boilers and process heaters? 

63.7500 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

63.7501 How can I assert an affirmative 

defense if I exceed an emission 

limitations during a malfunction? 

General Compliance Requirements 

63.7505 What are my general requirements 

for complying with this subpart? 

Testing, Fuel Analyses, and Initial 

Compliance Requirements 

63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

63.7515 When must I conduct subsequent 

performance tests, fuel analyses, or tuneups? 

63.7520 What stack tests and procedures 

must I use? 

63.7521 What fuel analyses, fuel 

specification, and procedures must I use? 

63.7522 Can I use emissions averaging to 

comply with this subpart? 

63.7525 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

63.7530 How do I demonstrate initial 

compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

63.7533 Can I use emission credits earned 

from implementation of energy 

conservation measures to comply with 

this subpart? 

Continuous Compliance Requirements 

63.7535 How do I monitor and collect data 

to demonstrate continuous compliance? 

63.7540 How do I demonstrate continuous 

compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

63.7541 How do I demonstrate continuous 

compliance under the emissions 

averaging provision? 

Notification, Reports, and Records 

63.7545 What notifications must I submit 

and when? 

63.7550 What reports must I submit and 

when? 

63.7555 What records must I keep? 

63.7560 In what form and how long must I 

keep my records? 

Other Requirements and Information 

63.7565 What parts of the General 

Provisions apply to me? 

63.7570 Who implements and enforces this 

subpart? 

63.7575 What definitions apply to this 

subpart? 

Tables to Subpart DDDDD of Part 63 

Table 1 to Subpart DDDDD of Part 63— 

Emission Limits for New or 

Reconstructed Boilers and Process 

Heaters 

Table 2 to Subpart DDDDD of Part 63— 

Emission Limits for Existing Boilers and 

Process Heaters (Units with heat input 

capacity of 10 million Btu per hour or 

greater) 

Table 3 to Subpart DDDDD of Part 63—Work 

Practice Standards 

Table 4 to Subpart DDDDD of Part 63— 

Operating Limits for Boilers and Process 

Heaters 

Table 5 to Subpart DDDDD of Part 63— 

Performance Testing Requirements 

Table 6 to Subpart DDDDD of Part 63—Fuel 

Analysis Requirements 

Table 7 to Subpart DDDDD of Part 63— 

Establishing Operating Limits 

Table 8 to Subpart DDDDD of Part 63— 

Demonstrating Continuous Compliance 

Table 9 to Subpart DDDDD of Part 63— 

Reporting Requirements 

Table 10 to Subpart DDDDD of Part 63— 

Applicability of General Provisions to 

Subpart DDDDD 

Table 11 to Subpart DDDDD of Part 63— 

Toxic Equivalency Factors for Dioxins/ 

Furans 

Table 12 to Subpart DDDDD of Part 63— 

Alternative Emission Limits for New or 

Reconstructed Boilers and Process 

Heaters That Commenced Construction 

or Reconstruction After June 4, 2010, and 

Before May 20, 2011 

What This Subpart Covers 

§ 63.7480 What is the purpose of this 

subpart? 

This subpart establishes national 

emission limitations and work practice 

standards for hazardous air pollutants 

(HAP) emitted from industrial, 

commercial, and institutional boilers 

and process heaters located at major 

sources of HAP. This subpart also 

establishes requirements to demonstrate 

initial and continuous compliance with 

the emission limitations and work 

practice standards. 

§ 63.7485 Am I subject to this subpart? 

You are subject to this subpart if you 

own or operate an industrial, 

commercial, or institutional boiler or 

process heater as defined in § 63.7575 

that is located at, or is part of, a major 

source of HAP, except as specified in 

§ 63.7491. For purposes of this subpart, 

a major source of HAP is as defined in 

§ 63.2, except that for oil and natural gas 

production facilities, a major source of 

HAP is as defined in § 63.761 (subpart 

HH of this part, National Emission 

Standards for Hazardous Air Pollutants 

from Oil and Natural Gas Production 

Facilities). 

§ 63.7490 What is the affected source of 

this subpart? 

(a) This subpart applies to new, 

reconstructed, and existing affected 

sources as described in paragraphs (a)(1) 

and (2) of this section. 

(1) The affected source of this subpart 

is the collection at a major source of all 

existing industrial, commercial, and 

institutional boilers and process heaters 

within a subcategory as defined in 

§ 63.7575. 

(2) The affected source of this subpart 

is each new or reconstructed industrial, 

commercial, or institutional boiler or 


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process heater, as defined in § 63.7575, 

located at a major source. 

(b) A boiler or process heater is new 

if you commence construction of the 

boiler or process heater after June 4, 

2010, and you meet the applicability 

criteria at the time you commence 

construction. 

(c) A boiler or process heater is 

reconstructed if you meet the 

reconstruction criteria as defined in 

§ 63.2, you commence reconstruction 

after June 4, 2010, and you meet the 

applicability criteria at the time you 

commence reconstruction. 

(d) A boiler or process heater is 

existing if it is not new or reconstructed. 

§ 63.7491 Are any boilers or process 

heaters not subject to this subpart? 

The types of boilers and process 

heaters listed in paragraphs (a) through 

(m) of this section are not subject to this 

subpart. 

(a) An electric utility steam generating 

unit. 

(b) A recovery boiler or furnace 

covered by subpart MM of this part. 

(c) A boiler or process heater that is 

used specifically for research and 

development. This does not include 

units that provide heat or steam to a 

process at a research and development 

facility. 

(d) A hot water heater as defined in 

this subpart. 

(e) A refining kettle covered by 

subpart X of this part. 

(f) An ethylene cracking furnace 

covered by subpart YY of this part. 

(g) Blast furnace stoves as described 

in EPA–453/R–01–005 (incorporated by 

reference, see § 63.14). 

(h) Any boiler or process heater that 

is part of the affected source subject to 

another subpart of this part (i.e., another 

National Emission Standards for 

Hazardous Air Pollutants in 40 CFR part 

63). 

(i) Any boiler or process heater that is 

used as a control device to comply with 

another subpart of this part, provided 

that at least 50 percent of the heat input 

to the boiler is provided by the gas 

stream that is regulated under another 

subpart. 

(j) Temporary boilers as defined in 

this subpart. 

(k) Blast furnace gas fuel-fired boilers 

and process heaters as defined in this 

subpart. 

(l) Any boiler specifically listed as an 

affected source in any standard(s) 

established under section 129 of the 

Clean Air Act. 

(m) A boiler required to have a permit 

under section 3005 of the Solid Waste 

Disposal Act or covered by subpart EEE 

of this part (e.g., hazardous waste 

boilers). 

§ 63.7495 When do I have to comply with 

this subpart? 

(a) If you have a new or reconstructed 

boiler or process heater, you must 

comply with this subpart by May 20, 

2011 or upon startup of your boiler or 

process heater, whichever is later. 

(b) If you have an existing boiler or 

process heater, you must comply with 

this subpart no later than March 21, 

2014. 

(c) If you have an area source that 

increases its emissions or its potential to 

emit such that it becomes a major source 

of HAP, paragraphs (c)(1) and (2) of this 

section apply to you. 

(1) Any new or reconstructed boiler or 

process heater at the existing source 

must be in compliance with this subpart 

upon startup. 

(2) Any existing boiler or process 

heater at the existing source must be in 

compliance with this subpart within 3 

years after the source becomes a major 

source. 

(d) You must meet the notification 

requirements in § 63.7545 according to 

the schedule in § 63.7545 and in subpart 

A of this part. Some of the notifications 

must be submitted before you are 

required to comply with the emission 

limits and work practice standards in 

this subpart. 

(e) If you own or operate an 

industrial, commercial, or institutional 

boiler or process heater and would be 

subject to this subpart except for the 

exemption in § 63.7491(l) for 

commercial and industrial solid waste 

incineration units covered by part 60, 

subpart CCCC or subpart DDDD, and 

you cease combusting solid waste, you 

must be in compliance with this subpart 

on the effective date of the switch from 

waste to fuel. 

Emission Limitations and Work 

Practice Standards 

§ 63.7499 What are the subcategories of 

boilers and process heaters? 

The subcategories of boilers and 

process heaters, as defined in § 63.7575 

are: 

(a) Pulverized coal/solid fossil fuel 

units. 

(b) Stokers designed to burn coal/ 

solid fossil fuel. 

(c) Fluidized bed units designed to 

burn coal/solid fossil fuel. 

(d) Stokers designed to burn biomass/ 

bio-based solid. 

(e) Fluidized bed units designed to 

burn biomass/bio-based solid. 

(f) Suspension burners/Dutch Ovens 

designed to burn biomass/bio-based 

solid. 

(g) Fuel Cells designed to burn 

biomass/bio-based solid. 

(h) Hybrid suspension/grate burners 

designed to burn biomass/bio-based 

solid. 

(i) Units designed to burn solid fuel. 

(j) Units designed to burn liquid fuel. 

(k) Units designed to burn liquid fuel 

in non-continental States or territories. 

(l) Units designed to burn natural gas, 

refinery gas or other gas 1 fuels. 

(m) Units designed to burn gas 2 

(other) gases. 

(n) Metal process furnaces. 

(o) Limited-use boilers and process 

heaters. 

§ 63.7500 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

(a) You must meet the requirements in 

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

section, except as provided in 

paragraphs (b) and (c) of this section. 

You must meet these requirements at all 

times. 

(1) You must meet each emission 

limit and work practice standard in 

Tables 1 through 3, and 12 to this 

subpart that applies to your boiler or 

process heater, for each boiler or process 

heater at your source, except as 

provided under § 63.7522. If your 

affected source is a new or 

reconstructed affected source that 

commenced construction or 

reconstruction after June 4, 2010, and 

before May 20, 2011, you may comply 

with the emission limits in Table 1 or 

12 to this subpart until March 21, 2014. 

On and after March 21, 2014, you must 

comply with the emission limits in 

Table 1 to this subpart. 

(2) You must meet each operating 

limit in Table 4 to this subpart that 

applies to your boiler or process heater. 

If you use a control device or 

combination of control devices not 

covered in Table 4 to this subpart, or 

you wish to establish and monitor an 

alternative operating limit and 

alternative monitoring parameters, you 

must apply to the EPA Administrator for 

approval of alternative monitoring 

under § 63.8(f). 

(3) 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. 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. 


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(b) As provided in § 63.6(g), EPA may 

approve use of an alternative to the 

work practice standards in this section. 

(c) Limited-use boilers and process 

heaters must complete a biennial tuneup as specified in § 63.7540. They are 

not subject to the emission limits in 

Tables 1 and 2 to this subpart, the 

annual tune-up requirement in Table 3 

to this subpart, or the operating limits 

in Table 4 to this subpart. Major sources 

that have limited-use boilers and 

process heaters must complete an 

energy assessment as specified in Table 

3 to this subpart if the source has other 

existing boilers subject to this subpart 

that are not limited-use boilers. 

§ 63.7501 How can I assert an affirmative 

defense if I exceed an emission limitations 

during a malfunction? 

In response to an action to enforce the 

emission limitations and operating 

limits set forth in § 63.7500 you may 

assert an affirmative defense to a claim 

for civil penalties for exceeding such 

standards that are caused by 

malfunction, as defined at § 63.2. 

Appropriate penalties may be assessed, 

however, if you fail to meet your burden 

of proving all of the requirements in the 

affirmative defense. The affirmative 

defense shall not be available for claims 

for injunctive relief. 

(a) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in paragraph 

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

preponderance of evidence that: 

(1) The excess emissions: 

(i) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner, and 

(ii) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(iv) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(2) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; and 

(3) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; and 

(4) If the excess emissions resulted 

from a bypass of control equipment or 

a process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(5) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health; and 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(7) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(8) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(b) Notification. The owner or 

operator of the facility experiencing an 

exceedance of its emission limitat(s) 

during a malfunction shall notify the 

Administrator by telephone or facsimile 

(fax) transmission as soon as possible, 

but no later than 2 business days after 

the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial ocurrence 

of the exceedance of the standard in 

§ 63.7500 to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedance. 

General Compliance Requirements 

§ 63.7505 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emission limits and operating limits 

in this subpart. These limits apply to 

you at all times. 

(b) [Reserved] 

(c) You must demonstrate compliance 

with all applicable emission limits 

using performance testing, fuel analysis, 

or continuous monitoring systems 

(CMS), including a continuous emission 

monitoring system (CEMS) or 

continuous opacity monitoring system 

(COMS), where applicable. You may 

demonstrate compliance with the 

applicable emission limit for hydrogen 

chloride or mercury using fuel analysis 

if the emission rate calculated according 

to § 63.7530(c) is less than the 

applicable emission limit. Otherwise, 

you must demonstrate compliance for 

hydrogen chloride or mercury using 

performance testing, if subject to an 

applicable emission limit listed in Table 

1, 2, or 12 to this subpart. 

(d) If you demonstrate compliance 

with any applicable emission limit 

through performance testing and 

subsequent compliance with operating 

limits (including the use of continuous 

parameter monitoring system), or with a 

CEMS, or COMS, you must develop a 

site-specific monitoring plan according 

to the requirements in paragraphs (d)(1) 

through (4) of this section for the use of 

any CEMS, COMS, or continuous 

parameter monitoring system. This 

requirement also applies to you if you 

petition the EPA Administrator for 

alternative monitoring parameters under 

§ 63.8(f). 

(1) For each CMS required in this 

section (including CEMS, COMS, or 

continuous parameter monitoring 

system), you must develop, and submit 

to the delegated authority for approval 

upon request, a site-specific monitoring 

plan that addresses paragraphs (d)(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. This requirement to develop 

and submit a site specific monitoring 

plan does not apply to affected sources 

with existing monitoring plans that 

apply to CEMS and COMS prepared 

under appendix B to part 60 of this 

chapter and that meet the requirements 

of § 63.7525. 

(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 


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parametric signal analyzer, and the data 

collection and reduction systems; and 

(iii) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations). 

(2) In your site-specific monitoring 

plan, you must also address paragraphs 

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

(i) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

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

(ii) Ongoing data quality assurance 

procedures in accordance with the 

general requirements of § 63.8(d); and 

(iii) Ongoing recordkeeping and 

reporting procedures in accordance with 

the general requirements of § 63.10(c) 

(as applicable in Table 10 to this 

subpart), (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. 

Testing, Fuel Analyses, and Initial 

Compliance Requirements 

§ 63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) For affected sources that elect to 

demonstrate compliance with any of the 

applicable emission limits in Tables 1 or 

2 of this subpart through performance 

testing, your initial compliance 

requirements include conducting 

performance tests according to § 63.7520 

and Table 5 to this subpart, conducting 

a fuel analysis for each type of fuel 

burned in your boiler or process heater 

according to § 63.7521 and Table 6 to 

this subpart, establishing operating 

limits according to § 63.7530 and Table 

7 to this subpart, and conducting CMS 

performance evaluations according to 

§ 63.7525. For affected sources 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 or process 

heater according to § 63.7521 and Table 

6 to this subpart. For purposes of this 

subpart, units that use a supplemental 

fuel only for startup, unit shutdown, 

and transient flame stability purposes 

still qualify as affected sources that burn 

a single type of fuel, and the 

supplemental fuel is not subject to the 

fuel analysis requirements under 

§ 63.7521 and Table 6 to this subpart. 

(b) For affected sources that elect to 

demonstrate compliance with the 

applicable emission limits in Tables 1 or 

2 of this subpart for hydrogen chloride 

or mercury through fuel analysis, your 

initial compliance requirement is to 

conduct a fuel analysis for each type of 

fuel burned in your boiler or process 

heater according to § 63.7521 and Table 

6 to this subpart and establish operating 

limits according to § 63.7530 and Table 

8 to this subpart. 

(c) If your boiler or process heater is 

subject to a carbon monoxide limit, your 

initial compliance demonstration for 

carbon monoxide is to conduct a 

performance test for carbon monoxide 

according to Table 5 to this subpart. 

Your initial compliance demonstration 

for carbon monoxide also includes 

conducting a performance evaluation of 

your continuous oxygen monitor 

according to § 63.7525(a). 

(d) If your boiler or process heater 

subject to a PM limit has a heat input 

capacity greater than 250 MMBtu per 

hour and combusts coal, biomass, or 

residual oil, your initial compliance 

demonstration for PM is to conduct a 

performance evaluation of your 

continuous emission monitoring system 

for PM according to § 63.7525(b). Boilers 

and process heaters that use a 

continuous emission monitoring system 

for PM are exempt from the performance 

testing and operating limit requirements 

specified in paragraph (a) of this 

section. 

(e) For existing affected sources, you 

must demonstrate initial compliance, as 

specified in paragraphs (a) through (d) 

of this section, no later than 180 days 

after the compliance date that is 

specified for your source in § 63.7495 

and according to the applicable 

provisions in § 63.7(a)(2) as cited in 

Table 10 to this subpart. 

(f) If your new or reconstructed 

affected source commenced 

construction or reconstruction after June 

4, 2010, you must demonstrate initial 

compliance with the emission limits no 

later than November 16, 2011 or within 

180 days after startup of the source, 

whichever is later. If you are 

demonstrating compliance with an 

emission limit in Table 12 to this 

subpart that is less stringent than (that 

is, higher than) the applicable emission 

limit in Table 1 to this subpart, you 

must demonstrate compliance with the 

applicable emission limit in Table 1 no 

later than September 17, 2014. 

(g) For affected sources that ceased 

burning solid waste consistent with 

§ 63.7495(e) 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. 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. 

§ 63.7515 When must I conduct 

subsequent performance tests, fuel 

analyses, or tune-ups? 

(a) You must conduct all applicable 

performance tests according to § 63.7520 

on an annual basis, except those for 

dioxin/furan emissions, unless you 

follow the requirements listed in 

paragraphs (b) through (e) of this 

section. Annual performance tests must 

be completed no more than 13 months 

after the previous performance test, 

unless you follow the requirements 

listed in paragraphs (b) through (e) of 

this section. Annual performance testing 

for dioxin/furan emissions is not 

required after the initial compliance 

demonstration. 

(b) You can conduct performance tests 

less often for a given pollutant if your 

performance tests for the pollutant for at 

least 2 consecutive years show that your 

emissions are at or below 75 percent of 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions. In this case, you do not have 

to conduct a performance test for that 

pollutant for the next 2 years. You must 

conduct a performance test during the 

third year and no more than 37 months 

after the previous performance test. If 

you elect to demonstrate compliance 

using emission averaging under 

§ 63.7522, you must continue to conduct 

performance tests annually. 

(c) If your boiler or process heater 

continues to meet the emission limit for 

the pollutant, you may choose to 

conduct performance tests for the 

pollutant every third year if your 

emissions are at or below 75 percent of 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions, but each such performance 

test must be conducted no more than 37 

months after the previous performance 

test. If you elect to demonstrate 

compliance using emission averaging 

under § 63.7522, you must continue to 

conduct performance tests annually. 

The requirement to test at maximum 

chloride input level is waived unless 

the stack test is conducted for HCl. The 

requirement to test at maximum Hg 

input level is waived unless the stack 

test is conducted for Hg. 

(d) If a performance test shows 

emissions exceeded 75 percent of the 

emission limit for a pollutant, you must 

conduct annual performance tests for 

that pollutant until all performance tests 


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15668 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

over a consecutive 2-year period show 

compliance. 

(e) If you are required to meet an 

applicable tune-up work practice 

standard, you must conduct an annual 

or biennial performance tune-up 

according to § 63.7540(a)(10) and 

(a)(11), respectively. Each annual tuneup specified in § 63.7540(a)(10) must be 

no more than 13 months after the 

previous tune-up. Each biennial tune-up 

specified in § 63.7540(a)(11) must be 

conducted no more than 25 months after 

the previous tune-up. 

(f) If you demonstrate compliance 

with the mercury or hydrogen chloride 

based on fuel analysis, you must 

conduct a monthly fuel analysis 

according to § 63.7521 for each type of 

fuel burned that is subject to an 

emission limit in Table 1, 2, or 12 of this 

subpart. If you burn a new type of fuel, 

you must conduct a fuel analysis before 

burning the new type of fuel in your 

boiler or process heater. You must still 

meet all applicable continuous 

compliance requirements in § 63.7540. 

If 12 consecutive monthly fuel analyses 

demonstrate compliance, you may 

request decreased fuel analysis 

frequency by applying to the EPA 

Administrator for approval of 

alternative monitoring under § 63.8(f). 

(g) You must report the results of 

performance tests and the associated 

initial fuel analyses within 90 days after 

the completion of the performance tests. 

This report must also verify that the 

operating limits for your affected source 

have not changed or provide 

documentation of revised operating 

parameters established according to 

§ 63.7530 and Table 7 to this subpart, as 

applicable. The reports for all 

subsequent performance tests must 

include all applicable information 

required in § 63.7550. 

§ 63.7520 What stack tests and procedures 

must I use? 

(a) You must conduct all performance 

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

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

requirements in § 63.7(c). You shall 

conduct all performance tests under 

such conditions as the Administrator 

specifies to you based on representative 

performance of the affected source for 

the period being tested. Upon request, 

you shall make available to the 

Administrator such records as may be 

necessary to determine the conditions of 

the performance tests. 

(b) You must conduct each 

performance test according to the 

requirements in Table 5 to this subpart. 

(c) You must conduct each 

performance test under the specific 

conditions listed in Tables 5 and 7 to 

this subpart. You must conduct 

performance tests at representative 

operating load conditions while burning 

the type of fuel or mixture of fuels that 

has the highest content of chlorine and 

mercury, and you must demonstrate 

initial compliance and establish your 

operating limits based on these 

performance tests. These requirements 

could result in the need to conduct 

more than one performance test. 

Following each performance test and 

until the next performance test, you 

must comply with the operating limit 

for operating load conditions specified 

in Table 4 to this subpart. 

(d) You must conduct three separate 

test runs for each performance test 

required in this section, as specified in 

§ 63.7(e)(3). Each test run must comply 

with the minimum applicable sampling 

times or volumes specified in Tables 1, 

2, and 12 to this subpart. 

(e) To determine compliance with the 

emission limits, you must use the FFactor methodology and equations in 

sections 12.2 and 12.3 of EPA Method 

19 at 40 CFR part 60, appendix A–7 of 

this chapter to convert the measured 

particulate matter concentrations, the 

measured hydrogen chloride 

concentrations, and the measured 

mercury concentrations that result from 

the initial performance test to pounds 

per million Btu heat input emission 

rates using F-factors. 

§ 63.7521 What fuel analyses, fuel 

specification, and procedures must I use? 

(a) For solid, liquid, and gas 2 (other) 

fuels, you must conduct fuel analyses 

for chloride and mercury according to 

the procedures in paragraphs (b) 

through (e) of this section and Table 6 

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 and hydrogen chloride in 

Tables 1, 2, or 12 to this subpart. 

Gaseous and liquid fuels are exempt 

from requirements in paragraphs (c) and 

(d) of this section and Table 6 of this 

subpart. 

(b) You must develop and submit a 

site-specific fuel monitoring plan to the 

EPA Administrator for review and 

approval according to the following 

procedures and requirements in 

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

(1) You must submit the fuel analysis 

plan no later than 60 days before the 

date that you intend to conduct an 

initial compliance demonstration. 

(2) You must include the information 

contained in paragraphs (b)(2)(i) 

through (vi) of this section in your fuel 

analysis plan. 

(i) The identification of all fuel types 

anticipated to be burned in each boiler 

or process heater. 

(ii) For each fuel type, the notification 

of whether you or a fuel supplier will 

be conducting the fuel analysis. 

(iii) For each fuel type, a detailed 

description of the sample location and 

specific procedures to be used for 

collecting and preparing the composite 

samples if your procedures are different 

from paragraph (c) or (d) of this section. 

Samples should be collected at a 

location that most accurately represents 

the fuel type, where possible, at a point 

prior to mixing with other dissimilar 

fuel types. 

(iv) For each fuel type, the analytical 

methods from Table 6, with the 

expected minimum detection levels, to 

be used for the measurement of chlorine 

or mercury. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 shall be used until the requested 

alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(c) At a minimum, you must obtain 

three composite fuel samples for each 

fuel type according to the procedures in 

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

(1) If sampling from a belt (or screw) 

feeder, collect fuel samples according to 

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

section. 

(i) Stop the belt and withdraw a 6- 

inch wide sample from the full crosssection of the stopped belt to obtain a 

minimum two pounds of sample. You 

must collect all the material (fines and 

coarse) in the full cross-section. You 

must transfer the sample to a clean 

plastic bag. 

(ii) Each composite sample will 

consist of a minimum of three samples 

collected at approximately equal 1-hour 

intervals during the testing period. 

(2) If sampling from a fuel pile or 

truck, you must collect fuel samples 

according to paragraphs (c)(2)(i) through 

(iii) of this section. 

(i) For each composite sample, you 

must select a minimum of five sampling 

locations uniformly spaced over the 

surface of the pile. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15669 

(ii) At each sampling site, you must 

dig into the pile to a depth of 18 inches. 

You must insert a clean flat square 

shovel into the hole and withdraw a 

sample, making sure that large pieces do 

not fall off during sampling. 

(iii) You must transfer all samples to 

a clean plastic bag for further 

processing. 

(d) You must prepare each composite 

sample according to the procedures in 

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

section. 

(1) You must thoroughly mix and 

pour the entire composite sample over 

a clean plastic sheet. 

(2) You must break sample pieces 

larger than 3 inches into smaller sizes. 

(3) You must make a pie shape with 

the entire composite sample and 

subdivide it into four equal parts. 

(4) You must separate one of the 

quarter samples as the first subset. 

(5) If this subset is too large for 

grinding, you must repeat the procedure 

in paragraph (d)(3) of this section with 

the quarter sample and obtain a onequarter subset from this sample. 

(6) You must grind the sample in a 

mill. 

(7) You must use the procedure in 

paragraph (d)(3) of this section to obtain 

a one-quarter subsample for analysis. If 

the quarter sample is too large, 

subdivide it further using the same 

procedure. 

(e) You must determine the 

concentration of pollutants in the fuel 

(mercury and/or chlorine) in units of 

pounds per million Btu of each 

composite sample for each fuel type 

according to the procedures in Table 6 

to this subpart. 

(f) To demonstrate that a gaseous fuel 

other than natural gas or refinery gas 

qualifies as an other gas 1 fuel, as 

defined in § 63.7575, you must conduct 

a fuel specification analyses for 

hydrogen sulfide and mercury according 

to the procedures in paragraphs (g) 

through (i) of this section and Table 6 

to this subpart, as applicable. You are 

not required to conduct the fuel 

specification analyses in paragraphs (g) 

through (i) of this section for gaseous 

fuels other than natural gas or refinery 

gas that are complying with the limits 

for units designed to burn gas 2 (other) 

fuels. 

(g) You must develop and submit a 

site-specific fuel analysis plan for other 

gas 1 fuels to the EPA Administrator for 

review and approval according to the 

following procedures and requirements 

in paragraphs (g)(1) and (2) of this 

section. 

(1) You must submit the fuel analysis 

plan no later than 60 days before the 

date that you intend to conduct an 

initial compliance demonstration. 

(2) You must include the information 

contained in paragraphs (g)(2)(i) through 

(vi) of this section in your fuel analysis 

plan. 

(i) The identification of all gaseous 

fuel types other than natural gas or 

refinery gas anticipated to be burned in 

each boiler or process heater. 

(ii) For each fuel type, the notification 

of whether you or a fuel supplier will 

be conducting the fuel specification 

analysis. 

(iii) For each fuel type, a detailed 

description of the sample location and 

specific procedures to be used for 

collecting and preparing the samples if 

your procedures are different from the 

sampling methods contained in Table 6. 

Samples should be collected at a 

location that most accurately represents 

the fuel type, where possible, at a point 

prior to mixing with other dissimilar 

fuel types. If multiple boilers or process 

heaters are fueled by a common fuel 

stream it is permissible to conduct a 

single gas specification at the common 

point of gas distribution. 

(iv) For each fuel type, the analytical 

methods from Table 6, with the 

expected minimum detection levels, to 

be used for the measurement of 

hydrogen sulfide and mercury. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 shall be used until the requested 

alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(h) You must obtain a single fuel 

sample for each other gas 1 fuel type 

according to the sampling procedures 

listed in Table 6 for fuel specification of 

gaseous fuels. 

(i) You must determine the 

concentration in the fuel of mercury, in 

units of microgram per cubic meter, and 

of hydrogen sulfide, in units of parts per 

million, by volume, dry basis, of each 

sample for each gas 1 fuel type 

according to the procedures in Table 6 

to this subpart. 

§ 63.7522 Can I use emissions averaging 

to comply with this subpart? 

(a) As an alternative to meeting the 

requirements of § 63.7500 for particulate 

matter, hydrogen chloride, or mercury 

on a boiler or process heater-specific 

basis, if you have more than one 

existing boiler or process heater in any 

subcategory located at your facility, you 

may demonstrate compliance by 

emissions averaging, if your averaged 

emissions are not more than 90 percent 

of the applicable emission limit, 

according to the procedures in this 

section. You may not include new 

boilers or process heaters in an 

emissions average. 

(b) For a group of two or more existing 

boilers or process heaters in the same 

subcategory that each vent to a separate 

stack, you may average particulate 

matter, hydrogen chloride, or mercury 

emissions among existing units to 

demonstrate compliance with the limits 

in Table 2 to this subpart if you satisfy 

the requirements in paragraphs (c), (d), 

(e), (f), and (g) of this section. 

(c) For each existing boiler or process 

heater in the averaging group, the 

emission rate achieved during the initial 

compliance test for the HAP being 

averaged must not exceed the emission 

level that was being achieved on May 

20, 2011 or the control technology 

employed during the initial compliance 

test must not be less effective for the 

HAP being averaged than the control 

technology employed on May 20, 2011. 

(d) The averaged emissions rate from 

the existing boilers and process heaters 

participating in the emissions averaging 

option must be in compliance with the 

limits in Table 2 to this subpart at all 

times following the compliance date 

specified in § 63.7495. 

(e) You must demonstrate initial 

compliance according to paragraph 

(e)(1) or (2) of this section using the 

maximum rated heat input capacity or 

maximum steam generation capacity of 

each unit and the results of the initial 

performance tests or fuel analysis. 

(1) You must use Equation 1 of this 

section to demonstrate that the 

particulate matter, hydrogen chloride, or 

mercury emissions from all existing 

units participating in the emissions 

averaging option for that pollutant do 

not exceed the emission limits in Table 

2 to this subpart. 


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15670 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

Where: 

AveWeightedEmissions = Average weighted 

emissions for particulate matter, 

hydrogen chloride, or mercury, in units 

of pounds per million Btu of heat input. 

Er = Emission rate (as determined during the 

initial compliance demonstration) of 

particulate matter, hydrogen chloride, or 

mercury from unit, i, in units of pounds 

per million Btu of heat input. Determine 

the emission rate for particulate matter, 

hydrogen chloride, or mercury by 

performance testing according to Table 5 

to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the 

applicable equation in § 63.7530(c). 

Hm = Maximum rated heat input capacity of 

unit, i, in units of million Btu per hour. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

(2) If you are not capable of 

determining the maximum rated heat 

input capacity of one or more boilers 

that generate steam, you may use 

Equation 2 of this section as an 

alternative to using Equation 1 of this 

section to demonstrate that the 

particulate matter, hydrogen chloride, or 

mercury emissions from all existing 

units participating in the emissions 

averaging option do not exceed the 

emission limits for that pollutant in 

Table 2 to this subpart. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for PM, hydrogen 

chloride, or mercury, in units of pounds 

per million Btu of heat input. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of heat input. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). 

Sm = Maximum steam generation capacity by 

unit, i, in units of pounds. 

Cfi = Conversion factor, calculated from the 

most recent compliance test, in units of 

million Btu of heat input per pounds of 

steam generated for unit, i. 

1.1 = Required discount factor. 

(f) After the initial compliance 

demonstration described in paragraph 

(e) of this section, you must demonstrate 

compliance on a monthly basis 

determined at the end of every month 

(12 times per year) according to 

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

section. The first monthly period begins 

on the compliance date specified in 

§ 63.7495. 

(1) For each calendar month, you 

must use Equation 3 of this section to 

calculate the average weighted emission 

rate for that month using the actual heat 

input for each existing unit participating 

in the emissions averaging option. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for particulate matter, 

hydrogen chloride, or mercury, in units 

of pounds per million Btu of heat input, 

for that calendar month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of heat input. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). 

Hb = The heat input for that calendar month 

to unit, i, in units of million Btu. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

(2) If you are not capable of 

monitoring heat input, you may use 

Equation 4 of this section as an 

alternative to using Equation 3 of this 

section to calculate the average 

weighted emission rate using the actual 

steam generation from the boilers 

participating in the emissions averaging 

option. 

Where: 

AveWeightedEmissions = average weighted 

emission level for PM, hydrogen 

chloride, or mercury, in units of pounds 

per million Btu of heat input for that 

calendar month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of heat input. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). 

Sa = Actual steam generation for that 

calendar month by boiler, i, in units of 

pounds. 

Cfi = Conversion factor, as calculated during 

the most recent compliance test, in units 

of million Btu of heat input per pounds 

of steam generated for boiler, i. 

1.1 = Required discount factor. 

(3) Until 12 monthly weighted average 

emission rates have been accumulated, 

calculate and report only the average 

weighted emission rate determined 

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

section for each calendar month. After 

12 monthly weighted average emission 

rates have been accumulated, for each 

subsequent calendar month, use 

Equation 5 of this section to calculate 

the 12-month rolling average of the 

monthly weighted average emission 

rates for the current calendar month and 

the previous 11 calendar months. 

Where: 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15671 

Eavg = 12-month rolling average emission 

rate, (pounds per million Btu heat input) 

ERi = Monthly weighted average, for calendar 

month ‘‘i’’ (pounds per million Btu heat 

input), as calculated by paragraph (f)(1) 

or (2) of this section. 

(g) You must develop, and submit to 

the applicable delegated authority for 

review and approval, an 

implementation plan for emission 

averaging according to the following 

procedures and requirements in 

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

section. 

(1) You must submit the 

implementation plan no later than 180 

days before the date that the facility 

intends to demonstrate compliance 

using the emission averaging option. 

(2) You must include the information 

contained in paragraphs (g)(2)(i) through 

(vii) of this section in your 

implementation plan for all emission 

sources included in an emissions 

average: 

(i) The identification of all existing 

boilers and process heaters in the 

averaging group, including for each 

either the applicable HAP emission 

level or the control technology installed 

as of May 20, 2011 and the date on 

which you are requesting emission 

averaging to commence; 

(ii) The process parameter (heat input 

or steam generated) that will be 

monitored for each averaging group; 

(iii) The specific control technology or 

pollution prevention measure to be used 

for each emission boiler or process 

heater in the averaging group and the 

date of its installation or application. If 

the pollution prevention measure 

reduces or eliminates emissions from 

multiple boilers or process heaters, the 

owner or operator must identify each 

boiler or process heater; 

(iv) The test plan for the measurement 

of particulate matter, hydrogen chloride, 

or mercury emissions in accordance 

with the requirements in § 63.7520; 

(v) The operating parameters to be 

monitored for each control system or 

device consistent with § 63.7500 and 

Table 4, and a description of how the 

operating limits will be determined; 

(vi) If you request to monitor an 

alternative operating parameter 

pursuant to § 63.7525, you must also 

include: 

(A) A description of the parameter(s) 

to be monitored and an explanation of 

the criteria used to select the 

parameter(s); and 

(B) A description of the methods and 

procedures that will be used to 

demonstrate that the parameter 

indicates proper operation of the control 

device; the frequency and content of 

monitoring, reporting, and 

recordkeeping requirements; and a 

demonstration, to the satisfaction of the 

applicable delegated authority, that the 

proposed monitoring frequency is 

sufficient to represent control device 

operating conditions; and 

(vii) A demonstration that compliance 

with each of the applicable emission 

limit(s) will be achieved under 

representative operating load 

conditions. Following each compliance 

demonstration and until the next 

compliance demonstration, you must 

comply with the operating limit for 

operating load conditions specified in 

Table 4 to this subpart. 

(3) The delegated authority shall 

review and approve or disapprove the 

plan according to the following criteria: 

(i) Whether the content of the plan 

includes all of the information specified 

in paragraph (g)(2) of this section; and 

(ii) Whether the plan presents 

sufficient information to determine that 

compliance will be achieved and 

maintained. 

(4) The applicable delegated authority 

shall not approve an emission averaging 

implementation plan containing any of 

the following provisions: 

(i) Any averaging between emissions 

of differing pollutants or between 

differing sources; or 

(ii) The inclusion of any emission 

source other than an existing unit in the 

same subcategory. 

(h) For a group of two or more 

existing affected units, each of which 

vents through a single common stack, 

you may average particulate matter, 

hydrogen chloride, or mercury 

emissions to demonstrate compliance 

with the limits for that pollutant in 

Table 2 to this subpart if you satisfy the 

requirements in paragraph (i) or (j) of 

this section. 

(i) For a group of two or more existing 

units in the same subcategory, each of 

which vents through a common 

emissions control system to a common 

stack, that does not receive emissions 

from units in other subcategories or 

categories, you may treat such averaging 

group as a single existing unit for 

purposes of this subpart and comply 

with the requirements of this subpart as 

if the group were a single unit. 

(j) For all other groups of units subject 

to the common stack requirements of 

paragraph (h) of this section, including 

situations where the exhaust of affected 

units are each individually controlled 

and then sent to a common stack, the 

owner or operator may elect to: 

(1) Conduct performance tests 

according to procedures specified in 

§ 63.7520 in the common stack if 

affected units from other subcategories 

vent to the common stack. The emission 

limits that the group must comply with 

are determined by the use of Equation 

6 of this section. 

Where: 

En = HAP emission limit, pounds per million 

British thermal units (lb/MMBtu), parts 

per million (ppm), or nanograms per dry 

standard cubic meter (ng/dscm). 

ELi = Appropriate emission limit from Table 

2 to this subpart for unit i, in units of lb/ 

MMBtu, ppm or ng/dscm. 

Hi = Heat input from unit i, MMBtu. 

(2) Conduct performance tests 

according to procedures specified in 

§ 63.7520 in the common stack. If 

affected units and non-affected units 

vent to the common stack, the nonaffected units must be shut down or 

vented to a different stack during the 

performance test unless the facility 

determines to demonstrate compliance 

with the non-affected units venting to 

the stack; and 

(3) Meet the applicable operating limit 

specified in § 63.7540 and Table 8 to 

this subpart for each emissions control 

system (except that, if each unit venting 

to the common stack has an applicable 

opacity operating limit, then a single 

continuous opacity monitoring system 

may be located in the common stack 

instead of in each duct to the common 

stack). 

(k) The common stack of a group of 

two or more existing boilers or process 

heaters in the same subcategory subject 

to paragraph (h) of this section may be 

treated as a separate stack for purposes 

of paragraph (b) of this section and 

included in an emissions averaging 

group subject to paragraph (b) of this 

section. 

§ 63.7525 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) If your boiler or process heater is 

subject to a carbon monoxide emission 

limit in Table 1, 2, or 12 to this subpart, 

you must install, operate, and maintain 

a continuous oxygen monitor according 

to the procedures in paragraphs (a)(1) 

through (6) of this section by the 

compliance date specified in § 63.7495. 

The oxygen level shall be monitored at 

the outlet of the boiler or process heater. 

(1) Each CEMS for oxygen (O2 CEMS) 

must be installed, operated, and 

maintained according to the applicable 

procedures under Performance 

Specification 3 at 40 CFR part 60, 

appendix B, and according to the sitespecific monitoring plan developed 

according to § 63.7505(d). 

(2) You must conduct a performance 

evaluation of each O2 CEMS according 


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15672 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

to the requirements in § 63.8(e) and 

according to Performance Specification 

3 at 40 CFR part 60, appendix B. 

(3) Each O2 CEMS must complete a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. 

(4) The O2 CEMS data must be 

reduced as specified in § 63.8(g)(2). 

(5) You must calculate and record 12- 

hour block average concentrations for 

each operating day. 

(6) For purposes of calculating data 

averages, you must use all the data 

collected during all periods in assessing 

compliance, excluding data collected 

during periods when the monitoring 

system malfunctions or is out of control, 

during associated repairs, and during 

required quality assurance or control 

activities (including, as applicable, 

calibration checks and required zero 

and span adjustments). Monitoring 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. Any period for which 

the monitoring system malfunctions or 

is out of control and data are not 

available for a required calculation 

constitutes a deviation from the 

monitoring requirements. Periods when 

data are unavailable because of required 

quality assurance or control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments) do not constitute 

monitoring deviations. 

(b) If your boiler or process heater has 

a heat input capacity of greater than 250 

MMBtu per hour and combusts coal, 

biomass, or residual oil, you must 

install, certify, maintain, and operate a 

CEMS measuring PM emissions 

discharged to the atmosphere and 

record the output of the system as 

specified in paragraphs (b)(1) through 

(5) of this section. 

(1) Each CEMS shall be installed, 

certified, operated, and maintained 

according to the requirements in 

§ 63.7540(a)(9). 

(2) For a new unit, the initial 

performance evaluation shall be 

completed no later than November 16, 

2011 or 180 days after the date of initial 

startup, whichever is later. For an 

existing unit, the initial performance 

evaluation shall be completed no later 

than September 17, 2014. 

(3) Compliance with the applicable 

emissions limit shall be determined 

based on the 30-day rolling average of 

the hourly arithmetic average emissions 

concentrations using the continuous 

monitoring system outlet data. The 30- 

day rolling arithmetic average emission 

concentration shall be calculated using 

EPA Reference Method 19 at 40 CFR 

part 60, appendixA–7. 

(4) Collect CEMS hourly averages for 

all operating hours on a 30-day rolling 

average basis. Collect 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. 

(5) The 1-hour arithmetic averages 

required shall be expressed in lb/ 

MMBtu and shall be used to calculate 

the boiler operating day daily arithmetic 

average emissions. 

(c) If you have an applicable opacity 

operating limit in this rule, and are not 

otherwise required to install and operate 

a PM CEMS or a bag leak detection 

system, you must install, operate, certify 

and maintain each COMS according to 

the procedures in paragraphs (c)(1) 

through (7) of this section by the 

compliance date specified in § 63.7495. 

(1) Each COMS must be installed, 

operated, and maintained according to 

Performance Specification 1 at appendix 

B to part 60 of this chapter. 

(2) You must conduct a performance 

evaluation of each COMS according to 

the requirements in § 63.8(e) and 

according to Performance Specification 

1 at appendix B to part 60 of this 

chapter. 

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

COMS must complete a minimum of 

one cycle of sampling and analyzing for 

each successive 10-second period and 

one cycle of data recording for each 

successive 6-minute period. 

(4) The COMS data must be reduced 

as specified in § 63.8(g)(2). 

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

acceptance criteria for operating and 

maintaining each COMS according to 

the requirements in § 63.8(d). At a 

minimum, the monitoring plan must 

include a daily calibration drift 

assessment, a quarterly performance 

audit, and an annual zero alignment 

audit of each COMS. 

(6) You must operate and maintain 

each COMS according to the 

requirements in the monitoring plan 

and the requirements of § 63.8(e). You 

must identify periods the COMS is out 

of control including any periods that the 

COMS fails to pass a daily calibration 

drift assessment, a quarterly 

performance audit, or an annual zero 

alignment audit. Any 6-minute period 

for which the monitoring system is out 

of control and data are not available for 

a required calculation constitutes a 

deviation from the monitoring 

requirements. 

(7) You must determine and record all 

the 6-minute averages (and daily block 

averages as applicable) collected for 

periods during which the COMS is not 

out of control. 

(d) If you have an operating limit that 

requires the use of a CMS, you must 

install, operate, and maintain each 

continuous parameter monitoring 

system according to the procedures in 

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

section by the compliance date specified 

in § 63.7495. 

(1) The continuous parameter 

monitoring system must complete a 

minimum of one cycle of operation for 

each successive 15-minute period. You 

must have a minimum of four 

successive cycles of operation to have a 

valid hour of data. 

(2) Except for monitoring 

malfunctions, associated repairs, and 

required quality assurance or control 

activities (including, as applicable, 

calibration checks and required zero 

and span adjustments), you must 

conduct all monitoring in continuous 

operation at all times that the unit is 

operating. A monitoring malfunction is 

any sudden, infrequent, not reasonably 

preventable failure of the monitoring to 

provide valid data. Monitoring failures 

that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. 

(3) For purposes of calculating data 

averages, you must not use data 

recorded during monitoring 

malfunctions, associated repairs, out of 

control periods, or required quality 

assurance or control activities. You 

must use all the data collected during 

all other periods in assessing 

compliance. Any 15-minute period for 

which the monitoring system is out-ofcontrol and data are not available for a 

required calculation constitutes a 

deviation from the monitoring 

requirements. 

(4) You must determine the 4-hour 

block average of all recorded readings, 

except as provided in paragraph (d)(3) 

of this section. 

(5) You must record the results of 

each inspection, calibration, and 

validation check. 

(e) If you have an operating limit that 

requires the use of a flow monitoring 

system, you must meet the requirements 

in paragraphs (d) and (e)(1) through (4) 

of this section. 

(1) You must install the flow sensor 

and other necessary equipment in a 

position that provides a representative 

flow. 

(2) You must use a flow sensor with 

a measurement sensitivity of no greater 

than 2 percent of the expected flow rate. 


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(3) You must minimize the effects of 

swirling flow or abnormal velocity 

distributions due to upstream and 

downstream disturbances. 

(4) You must conduct a flow 

monitoring system performance 

evaluation in accordance with your 

monitoring plan at the time of each 

performance test but no less frequently 

than annually. (f) If you have an 

operating limit that requires the use of 

a pressure monitoring system, you must 

meet the requirements in paragraphs (d) 

and (f)(1) through (6) of this section. 

(1) Install the pressure sensor(s) in a 

position that provides a representative 

measurement of the pressure (e.g., PM 

scrubber pressure drop). 

(2) Minimize or eliminate pulsating 

pressure, vibration, and internal and 

external corrosion. 

(3) Use a pressure sensor with a 

minimum tolerance of 1.27 centimeters 

of water or a minimum tolerance of 1 

percent of the pressure monitoring 

system operating range, whichever is 

less. 

(4) Perform checks at least once each 

process operating day to ensure pressure 

measurements are not obstructed (e.g., 

check for pressure tap pluggage daily). 

(5) Conduct a performance evaluation 

of the pressure monitoring system in 

accordance with your monitoring plan 

at the time of each performance test but 

no less frequently than annually. 

(6) If at any time the measured 

pressure exceeds the manufacturer’s 

specified maximum operating pressure 

range, conduct a performance 

evaluation of the pressure monitoring 

system in accordance with your 

monitoring plan and confirm that the 

pressure monitoring system continues to 

meet the performance requirements in 

you monitoring plan. Alternatively, 

install and verify the operation of a new 

pressure sensor. 

(g) If you have an operating limit that 

requires a pH monitoring system, you 

must meet the requirements in 

paragraphs (d) and (g)(1) through (4) of 

this section. 

(1) Install the pH sensor in a position 

that provides a representative 

measurement of scrubber effluent pH. 

(2) Ensure the sample is properly 

mixed and representative of the fluid to 

be measured. 

(3) Conduct a performance evaluation 

of the pH monitoring system in 

accordance with your monitoring plan 

at least once each process operating day. 

(4) Conduct a performance evaluation 

(including a two-point calibration with 

one of the two buffer solutions having 

a pH within 1 of the pH of the operating 

limit) of the pH monitoring system in 

accordance with your monitoring plan 

at the time of each performance test but 

no less frequently than quarterly. 

(h) If you have an operating limit that 

requires a secondary electric power 

monitoring system for an electrostatic 

precipitator (ESP) operated with a wet 

scrubber, you must meet the 

requirements in paragraphs (h)(1) and 

(2) of this section. 

(1) Install sensors to measure 

(secondary) voltage and current to the 

precipitator collection plates. 

(2) Conduct a performance evaluation 

of the electric power monitoring system 

in accordance with your monitoring 

plan at the time of each performance 

test but no less frequently than 

annually. 

(i) If you have an operating limit that 

requires the use of a monitoring system 

to measure sorbent injection rate (e.g., 

weigh belt, weigh hopper, or hopper 

flow measurement device), you must 

meet the requirements in paragraphs (d) 

and (i)(1) through (2) of this section. 

(1) Install the system in a position(s) 

that provides a representative 

measurement of the total sorbent 

injection rate. 

(2) Conduct a performance evaluation 

of the sorbent injection rate monitoring 

system in accordance with your 

monitoring plan at the time of each 

performance test but no less frequently 

than annually. 

(j) If you are not required to use a PM 

CEMS and elect to 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 (j)(1) through (7) of this 

section. 

(1) You must install a bag leak 

detection sensor(s) in a position(s) that 

will be representative of the relative or 

absolute particulate matter loadings for 

each exhaust stack, roof vent, or 

compartment (e.g., for a positive 

pressure fabric filter) of the fabric filter. 

(2) Conduct a performance evaluation 

of the bag leak detection system in 

accordance with your monitoring plan 

and consistent with the guidance 

provided in EPA–454/R–98–015 

(incorporated by reference, see § 63.14). 

(3) Use a bag leak detection system 

certified by the manufacturer to be 

capable of detecting particulate matter 

emissions at concentrations of 10 

milligrams per actual cubic meter or 

less. 

(4) Use a bag leak detection system 

equipped with a device to record 

continuously the output signal from the 

sensor. 

(5) Use a bag leak detection system 

equipped with a system that will alert 

when an increase in relative particulate 

matter emissions over a preset level is 

detected. The alarm must be located 

where it can be easily heard or seen by 

plant operating personnel. 

(7) Where multiple bag leak detectors 

are required, the system’s 

instrumentation and alarm may be 

shared among detectors. 

(k) For each unit that meets the 

definition of limited-use boiler or 

process heater, you must monitor and 

record the operating hours per year for 

that unit. 

§ 63.7530 How do I demonstrate initial 

compliance with the emission limitations, 

fuel specifications and work practice 

standards? 

(a) You must demonstrate initial 

compliance with each emission limit 

that applies to you by conducting initial 

performance tests and fuel analyses and 

establishing operating limits, as 

applicable, according to § 63.7520, 

paragraphs (b) and (c) of this section, 

and Tables 5 and 7 to this subpart. If 

applicable, you must also install, and 

operate, maintain all applicable CMS 

(including CEMS, COMS, and 

continuous parameter monitoring 

systems) according to § 63.7525. 

(b) If you demonstrate compliance 

through performance testing, you must 

establish each site-specific operating 

limit in Table 4 to this subpart that 

applies to you according to the 

requirements in § 63.7520, Table 7 to 

this subpart, and paragraph (b)(3) of this 

section, as applicable. You must also 

conduct fuel analyses according to 

§ 63.7521 and establish maximum fuel 

pollutant input levels according to 

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

as applicable. As specified in 

§ 63.7510(a), if your affected source 

burns a single type of fuel (excluding 

supplemental fuels used for unit 

startup, shutdown, or transient flame 

stabilization), you are not required to 

perform the initial fuel analysis for each 

type of fuel burned in your boiler or 

process heater. However, if you switch 

fuel(s) and cannot show that the new 

fuel(s) do (does) not increase the 

chlorine or mercury input into the unit 

through the results of fuel analysis, then 

you must repeat the performance test to 

demonstrate compliance while burning 

the new fuel(s). 

(1) You must establish the maximum 

chlorine fuel input (Clinput) during the 

initial fuel analysis according to the 

procedures in paragraphs (b)(1)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your boiler or process heater that has 

the highest content of chlorine. 


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15674 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

(ii) During the fuel analysis for 

hydrogen chloride, you must determine 

the fraction of the total heat input for 

each fuel type burned (Qi) based on the 

fuel mixture that has the highest content 

of chlorine, and the average chlorine 

concentration of each fuel type burned 

(Ci). 

(iii) You must establish a maximum 

chlorine input level using Equation 7 of 

this section. 

Where: 

Clinput = Maximum amount of chlorine 

entering the boiler or process heater 

through fuels burned in units of pounds 

per million Btu. 

Ci = Arithmetic average concentration of 

chlorine in fuel type, i, analyzed 

according to § 63.7521, in units of 

pounds per million Btu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types 

during the performance testing, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

chlorine. 

(2) You must establish the maximum 

mercury fuel input level (Mercuryinput) 

during the initial fuel analysis using the 

procedures in paragraphs (b)(2)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your boiler or process heater that has 

the highest content of mercury. 

(ii) During the compliance 

demonstration for mercury, you must 

determine the fraction of total heat 

input for each fuel burned (Qi) based on 

the fuel mixture that has the highest 

content of mercury, and the average 

mercury concentration of each fuel type 

burned (HGi). 

(iii) You must establish a maximum 

mercury input level using Equation 8 of 

this section. 

Where: 

Mercuryinput = Maximum amount of 

mercury entering the boiler or process 

heater through fuels burned in units of 

pounds per million Btu. 

HGi = Arithmetic average concentration of 

mercury in fuel type, i, analyzed 

according to § 63.7521, in units of 

pounds per million Btu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest mercury content. If you 

do not burn multiple fuel types during 

the performance test, it is not necessary 

to determine the value of this term. 

Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

mercury. 

(3) You must establish parameter 

operating limits according to paragraphs 

(b)(3)(i) through (iv) of this section. 

(i) For a wet scrubber, you must 

establish the minimum scrubber effluent 

pH, liquid flowrate, and pressure drop 

as defined in § 63.7575, as your 

operating limits during the three-run 

performance test. If you use a wet 

scrubber and you conduct separate 

performance tests for particulate matter, 

hydrogen chloride, and mercury 

emissions, you must establish one set of 

minimum scrubber effluent pH, liquid 

flowrate, and pressure drop operating 

limits. The minimum scrubber effluent 

pH operating limit must be established 

during the hydrogen chloride 

performance test. If you conduct 

multiple performance tests, you must 

set the minimum liquid flowrate and 

pressure drop operating limits at the 

highest minimum values established 

during the performance tests. 

(ii) For an electrostatic precipitator 

operated with a wet scrubber, you must 

establish the minimum voltage and 

secondary amperage (or total power 

input), as defined in § 63.7575, as your 

operating limits during the three-run 

performance test. (These operating 

limits do not apply to electrostatic 

precipitators that are operated as dry 

controls without a wet scrubber.) 

(iii) For a dry scrubber, you must 

establish the minimum sorbent injection 

rate for each sorbent, as defined in 

§ 63.7575, as your operating limit during 

the three-run performance test. 

(iv) For activated carbon injection, 

you must establish the minimum 

activated carbon injection rate, as 

defined in § 63.7575, as your operating 

limit during the three-run performance 

test. 

(v) The operating limit for boilers or 

process heaters 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 § 63.7525, 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 emission 

limit through fuel analysis, you must 

conduct fuel analyses according to 

§ 63.7521 and follow the procedures in 

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

section. 

(1) If you burn more than one fuel 

type, you must determine the fuel 

mixture you could burn in your boiler 

or process heater that would result in 

the maximum emission rates of the 

pollutants that you elect to demonstrate 

compliance through fuel analysis. 

(2) You must determine the 90th 

percentile confidence level fuel 

pollutant concentration of the 

composite samples analyzed for each 

fuel type using the one-sided z-statistic 

test described in Equation 9 of this 

section. 

Where: 

P90 = 90th percentile confidence level 

pollutant concentration, in pounds per 

million Btu. 

Mean = Arithmetic average of the fuel 

pollutant concentration in the fuel 

samples analyzed according to § 63.7521, 

in units of pounds per million Btu. 

SD = Standard deviation of the pollutant 

concentration in the fuel samples 

analyzed according to § 63.7521, 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 emission limit for 

hydrogen chloride, the hydrogen 

chloride emission rate that you calculate 

for your boiler or process heater using 

Equation 10 of this section must not 

exceed the applicable emission limit for 

hydrogen chloride. 


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Where: 

HCl = Hydrogen chloride emission rate from 

the boiler or process heater in units of 

pounds per million Btu. 

Ci90 = 90th percentile confidence level 

concentration of chlorine in fuel type, i, 

in units of pounds per million Btu as 

calculated according to Equation 9 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types, it 

is not necessary to determine the value 

of this term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

chlorine. 

1.028 = Molecular weight ratio of hydrogen 

chloride to chlorine. 

(4) To demonstrate compliance with 

the applicable emission limit for 

mercury, the mercury emission rate that 

you calculate for your boiler or process 

heater using Equation 11 of this section 

must not exceed the applicable emission 

limit for mercury. 

Where: 

Mercury = Mercury emission rate from the 

boiler or process heater in units of 

pounds per million Btu. 

Hgi90 = 90th percentile confidence level 

concentration of mercury in fuel, i, in 

units of pounds per million Btu as 

calculated according to Equation 9 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest mercury content. If you 

do not burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest mercury 

content. 

(d) If you own or operate an existing 

unit 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 a 

tune-up of the unit. 

(e) You must include with the 

Notification of Compliance Status a 

signed certification that the energy 

assessment was completed according to 

Table 3 to this subpart and is an 

accurate depiction of your facility. 

(f) You must submit the Notification 

of Compliance Status containing the 

results of the initial compliance 

demonstration according to the 

requirements in § 63.7545(e). 

(g) If you elect to demonstrate that a 

gaseous fuel meets the specifications of 

an other gas 1 fuel as defined in 

§ 63.7575, you must conduct an initial 

fuel specification analyses according to 

§ 63.7521(f) through (i). If the mercury 

and hydrogen sulfide constituents in the 

gaseous fuels will never exceed the 

specifications included in the 

definition, you will include a signed 

certification with the Notification of 

Compliance Status that the initial fuel 

specification test meets the gas 

specifications outlined in the definition 

of other gas 1 fuels. If your gas 

constituents could vary above the 

specifications, you will conduct 

monthly testing according to the 

procedures in § 63.7521(f) through (i) 

and § 63.7540(c) and maintain records 

of the results of the testing as outlined 

in § 63.7555(g). 

(h) If you own or operate a unit 

subject emission limits in Tables 1, 2, or 

12 of this subpart, you must minimize 

the unit’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 

unit of similar design if manufacturer’s 

recommended procedures are not 

available. 

§ 63.7533 Can I use emission credits 

earned from implementation of energy 

conservation measures to comply with this 

subpart? 

(a) If you elect to comply with the 

alternative equivalent steam outputbased emission limits, instead of the 

heat input-based limits, listed in Tables 

1 and 2 of this subpart and you want to 

take credit for implementing energy 

conservation measures identified in an 

energy assessment, you may 

demonstrate compliance using emission 

reduction credits according to the 

procedures in this section. Owners or 

operators using this compliance 

approach must establish an emissions 

benchmark, calculate and document the 

emission credits, develop an 

Implementation Plan, comply with the 

general reporting requirements, and 

apply the emission credit according to 

the procedures in paragraphs (b) 

through (f) of this section. 

(b) For each existing affected boiler 

for which you intend to apply emissions 

credits, establish a benchmark from 

which emission reduction credits may 

be generated by determining the actual 

annual fuel heat input to the affected 

boiler before initiation of an energy 

conservation activity to reduce energy 

demand (i.e., fuel usage) according to 

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

section. The benchmark shall be 

expressed in trillion Btu per year heat 

input. 

(1) The benchmark from which 

emission credits may be generated shall 

be determined by using the most 

representative, accurate, and reliable 

process available for the source. The 

benchmark shall be established for a 

one-year period before the date that an 

energy demand reduction occurs, unless 

it can be demonstrated that a different 

time period is more representative of 

historical operations. 

(2) Determine the starting point from 

which to measure progress. Inventory 

all fuel purchased and generated on-site 

(off-gases, residues) in physical units 

(MMBtu, million cubic feet, etc.). 

(3) Document all uses of energy from 

the affected boiler. Use the most recent 

data available. 

(4) Collect non-energy related facility 

and operational data to normalize, if 

necessary, the benchmark to current 

operations, such as building size, 

operating hours, etc. Use actual, not 

estimated, use data, if possible and data 

that are current and timely. 

(c) Emissions credits can be generated 

if the energy conservation measures 

were implemented after January 14, 

2011 and if sufficient information is 


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15676 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

available to determine the appropriate 

value of credits. 

(1) The following emission points 

cannot be used to generate emissions 

averaging credits: 

(i) Energy conservation measures 

implemented on or before January 14, 

2011, unless the level of energy demand 

reduction is increased after January 14, 

2011, in which case credit will be 

allowed only for change in demand 

reduction achieved after January 14, 

2011. 

(ii) Emission credits on shut-down 

boilers. Boilers that are shut down 

cannot be used to generate credits. 

(2) For all points included in 

calculating emissions credits, the owner 

or operator shall: 

(i) Calculate annual credits for all 

energy demand points. Use Equation 12 

to calculate credits. Energy conservation 

measures that meet the criteria of 

paragraph (c)(1) of this section shall not 

be included, except as specified in 

paragraph (c)(1)(i) of this section. 

(3) Credits are generated by the 

difference between the benchmark that 

is established for each affected boiler, 

and the actual energy demand 

reductions from energy conservation 

measures implemented after January 14, 

2011. Credits shall be calculated using 

Equation 12 of this section as follows: 

(i) The overall equation for calculating 

credits is: 

Where: 

Credits = Energy Input Savings for all energy 

conservation measures implemented for 

an affected boiler, million Btu per year. 

EISiactual = Energy Input Savings for each 

energy conservation measure 

implemented for an affected boiler, 

million Btu per year. 

EIbaseline = Energy Input for the affected boiler, 

million Btu. 

n = Number of energy conservation measures 

included in the emissions credit for the 

affected boiler. 

(d) The owner or operator shall 

develop and submit for approval an 

Implementation Plan containing all of 

the information required in this 

paragraph for all boilers to be included 

in an emissions credit approach. The 

Implementation Plan shall identify all 

existing affected boilers to be included 

in applying the emissions credits. The 

Implementation Plan shall include a 

description of the energy conservation 

measures implemented and the energy 

savings generated from each measure 

and an explanation of the criteria used 

for determining that savings. You must 

submit the implementation plan for 

emission credits to the applicable 

delegated authority for review and 

approval no later than 180 days before 

the date on which the facility intends to 

demonstrate compliance using the 

emission credit approach. 

(e) The emissions rate from each 

existing boiler participating in the 

emissions credit option must be in 

compliance with the limits in Table 2 to 

this subpart at all times following the 

compliance date specified in § 63.7495. 

(f) You must demonstrate initial 

compliance according to paragraph (f)(1) 

or (2) of this section. 

(1) You must use Equation 13 of this 

section to demonstrate that the 

emissions from the affected boiler 

participating in the emissions credit 

compliance approach do not exceed the 

emission limits in Table 2 to this 

subpart. 

Where: 

Eadj = Emission level adjusted applying the 

emission credits earned, lb per million 

Btu steam output for the affected boiler. 

Em = Emissions measured during the 

performance test, lb per million Btu 

steam output for the affected boiler. 

EC = Emission credits from equation 12 for 

the affected boiler. 

Continuous Compliance Requirements 

§ 63.7535 How do I monitor and collect 

data to demonstrate continuous 

compliance? 

(a) You must monitor and collect data 

according to this section and the sitespecific monitoring plan required by 

§ 63.7505(d). 

(b) You must operate the monitoring 

system and collect data at all required 

intervals at all times that the affected 

source is operating, except for periods of 

monitoring system malfunctions or out 

of control periods (see § 63.8(c)(7) of 

this part), and required monitoring 

system quality assurance or control 

activities, including, as applicable, 

calibration checks and required zero 

and span adjustments. A monitoring 

system malfunction is any sudden, 

infrequent, not reasonably preventable 

failure of the monitoring system to 

provide valid data. Monitoring system 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. You are required to 

effect monitoring system repairs in 

response to monitoring system 

malfunctions or out-of-control periods 

and to return the monitoring system to 

operation as expeditiously as 

practicable. 

(c) You may not use data recorded 

during monitoring system malfunctions 

or out-of-control periods, repairs 

associated with monitoring system 

malfunctions or out-of-control periods, 

or required monitoring system quality 

assurance or control activities in data 

averages and calculations used to report 

emissions or operating levels. You must 

use all the data collected during all 

other periods in assessing the operation 

of the control device and associated 

control system. 

(d) Except for periods of monitoring 

system malfunctions or out-of-control 

periods, repairs associated with 

monitoring system malfunctions or outof-control periods, and required 

monitoring system quality assurance or 

quality control activities including, as 

applicable, calibration checks and 

required zero and span adjustments, 

failure to collect required data is a 

deviation of the monitoring 

requirements. 

§ 63.7540 How do I demonstrate 

continuous compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

(a) You must demonstrate continuous 

compliance with each emission limit, 

operating limit, and work practice 

standard in Tables 1 through 3 to this 

subpart that applies to you according to 

the methods specified in Table 8 to this 

subpart and paragraphs (a)(1) through 

(11) 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 63.7510, 

whichever date comes first, operation 

above the established maximum or 

below the established minimum 

operating limits shall constitute a 

deviation of established operating limits 

listed in Table 4 of this subpart except 

during performance tests conducted to 

determine compliance with the 

emission limits or to establish new 

operating limits. Operating limits must 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15677 

be confirmed or reestablished during 

performance tests. 

(2) As specified in § 63.7550(c), you 

must keep records of the type and 

amount of all fuels burned in each 

boiler or process heater during the 

reporting period to demonstrate that all 

fuel types and mixtures of fuels burned 

would either result in lower emissions 

of hydrogen chloride and mercury than 

the applicable emission limit for each 

pollutant (if you demonstrate 

compliance through fuel analysis), or 

result in lower fuel input of chlorine 

and mercury than the maximum values 

calculated during the last performance 

test (if you demonstrate compliance 

through performance testing). 

(3) If you demonstrate compliance 

with an applicable hydrogen chloride 

emission limit through fuel analysis and 

you plan to burn a new type of fuel, you 

must recalculate the hydrogen chloride 

emission rate using Equation 9 of 

§ 63.7530 according to paragraphs 

(a)(3)(i) through (iii) of this section. 

(i) You must determine the chlorine 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of chlorine. 

(iii) Recalculate the hydrogen chloride 

emission rate from your boiler or 

process heater under these new 

conditions using Equation 10 of 

§ 63.7530. The recalculated hydrogen 

chloride emission rate must be less than 

the applicable emission limit. 

(4) If you demonstrate compliance 

with an applicable hydrogen chloride 

emission limit through performance 

testing and you plan to burn a new type 

of fuel or a new mixture of fuels, you 

must recalculate the maximum chlorine 

input using Equation 7 of § 63.7530. If 

the results of recalculating the 

maximum chlorine input using 

Equation 7 of § 63.7530 are greater than 

the maximum chlorine input level 

established during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the hydrogen chloride emissions do 

not exceed the emission limit. You must 

also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.7530(b). 

(5) If you demonstrate compliance 

with an applicable mercury emission 

limit through fuel analysis, and you 

plan to burn a new type of fuel, you 

must recalculate the mercury emission 

rate using Equation 11 of § 63.7530 

according to the procedures specified in 

paragraphs (a)(5)(i) through (iii) of this 

section. 

(i) You must determine the mercury 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of mercury. 

(iii) Recalculate the mercury emission 

rate from your boiler or process heater 

under these new conditions using 

Equation 11 of § 63.7530. The 

recalculated mercury emission rate must 

be less than the applicable emission 

limit. 

(6) If you demonstrate compliance 

with an applicable mercury emission 

limit through performance testing, and 

you plan to burn a new type of fuel or 

a new mixture of fuels, you must 

recalculate the maximum mercury input 

using Equation 8 of § 63.7530. If the 

results of recalculating the maximum 

mercury input using Equation 8 of 

§ 63.7530 are higher than the maximum 

mercury input level established during 

the previous performance test, then you 

must conduct a new performance test 

within 60 days of burning the new fuel 

type or fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the mercury emissions do not 

exceed the emission limit. You must 

also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.7530(b). 

(7) 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 

complete corrective actions as soon as 

practical, 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 shall be counted as a 

minimum of 1 hour. If you take longer 

than 1 hour to initiate corrective action, 

the alarm time shall be counted as the 

actual amount of time taken to initiate 

corrective action. 

(8) [Reserved]. 

(9) The owner or operator of an 

affected source using a CEMS measuring 

PM emissions to meet requirements of 

this subpart shall install, certify, 

operate, and maintain the PM CEMS as 

specified in paragraphs (a)(9)(i) through 

(a)(9)(iv) of this section. 

(i) The owner or operator shall 

conduct a performance evaluation of the 

PM CEMS according to the applicable 

requirements of § 60.13, and 

Performance Specification 11 at 40 CFR 

part 60, appendix B of this chapter. 

(ii) During each PM correlation testing 

run of the CEMS required by 

Performance Specification 11 at 40 CFR 

part 60, appendix B of this chapter, PM 

and oxygen (or carbon dioxide) data 

shall be collected concurrently (or 

within a 30-to 60-minute period) by 

both the CEMS and conducting 

performance tests using Method 5 or 5B 

at 40 CFR part 60, appendix A–3 or 

Method 17 at 40 CFR part 60, appendix 

A–6 of this chapter. 

(iii) Quarterly accuracy 

determinations and daily calibration 

drift tests shall be performed in 

accordance with Procedure 2 at 40 CFR 

part 60, appendix F of this chapter. 

Relative Response Audits must be 

performed annually and Response 

Correlation Audits must be performed 

every 3 years. 

(iv) After December 31, 2011, within 

60 days after the date of completing 

each CEMS relative accuracy test audit 

or performance test conducted to 

demonstrate compliance with this 

subpart, you must submit the relative 

accuracy test audit data and 

performance test data to EPA by 

successfully submitting the data 

electronically into EPA’s Central Data 

Exchange by using the Electronic 

Reporting Tool (see http://www.epa.gov/ 

ttn/chief/ert/ert tool.html/). 

(10) If your boiler or process heater is 

in either the natural gas, refinery gas, 

other gas 1, or Metal Process Furnace 

subcategories and has a heat input 

capacity of 10 million Btu per hour or 

greater, you must conduct a tune-up of 

the boiler or process heater annually to 

demonstrate continuous compliance as 

specified in paragraphs (a)(10)(i) 

through (a)(10)(vi) of this section. This 

requirement does not apply to limiteduse boilers and process heaters, as 

defined in § 63.7575. 


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(i) As applicable, inspect the burner, 

and clean or replace any components of 

the burner as necessary (you may delay 

the burner inspection until the next 

scheduled unit shutdown, but you must 

inspect each burner at least once every 

36 months); 

(ii) 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; 

(iii) Inspect the system controlling the 

air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and 

functioning properly; 

(iv) Optimize total emissions of 

carbon monoxide. This optimization 

should be consistent with the 

manufacturer’s specifications, if 

available; 

(v) Measure the concentrations in the 

effluent stream of carbon monoxide in 

parts per million, by volume, and 

oxygen in volume percent, before and 

after the adjustments are made 

(measurements may be either on a dry 

or wet basis, as long as it is the same 

basis before and after the adjustments 

are made); and 

(vi) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (a)(10)(vi)(A) 

through (C) of this section, 

(A) The concentrations of carbon 

monoxide in the effluent stream in parts 

per million by volume, and oxygen in 

volume percent, measured before and 

after the adjustments of the boiler; 

(B) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(C) The type and amount of fuel used 

over the 12 months prior to the annual 

adjustment, 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. 

(11) If your boiler or process heater 

has a heat input capacity of less than 10 

million Btu per hour, or meets the 

definition of limited-use boiler or 

process heater in § 63.7575, you must 

conduct a biennial tune-up of the boiler 

or process heater as specified in 

paragraphs (a)(10)(i) through (a)(10)(vi) 

of this section to demonstrate 

continuous compliance. 

(12) If the unit is not operating on the 

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

must be conducted within one week of 

startup. 

(b) You must report each instance in 

which you did not meet each emission 

limit and operating limit in Tables 1 

through 4 to this subpart that apply to 

you. These instances are deviations 

from the emission limits in this subpart. 

These deviations must be reported 

according to the requirements in 

§ 63.7550. 

(c) If you elected to demonstrate that 

the unit meets the specifications for 

hydrogen sulfide and mercury for the 

other gas 1 subcategory and you cannot 

submit a signed certification under 

§ 63.7545(g) because the constituents 

could exceed the specifications, you 

must conduct monthly fuel specification 

testing of the gaseous fuels, according to 

the procedures in § 63.7521(f) through 

(i). 

§ 63.7541 How do I demonstrate 

continuous compliance under the 

emissions averaging provision? 

(a) Following the compliance date, the 

owner or operator must demonstrate 

compliance with this subpart on a 

continuous basis by meeting the 

requirements of paragraphs (a)(1) 

through (5) of this section. 

(1) For each calendar month, 

demonstrate compliance with the 

average weighted emissions limit for the 

existing units participating in the 

emissions averaging option as 

determined in § 63.7522(f) and (g). 

(2) You must maintain the applicable 

opacity limit according to paragraphs 

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

(i) For each existing unit participating 

in the emissions averaging option that is 

equipped with a dry control system and 

not vented to a common stack, maintain 

opacity at or below the applicable limit. 

(ii) For each group of units 

participating in the emissions averaging 

option where each unit in the group is 

equipped with a dry control system and 

vented to a common stack that does not 

receive emissions from non-affected 

units, maintain opacity at or below the 

applicable limit at the common stack. 

(3) For each existing unit participating 

in the emissions averaging option that is 

equipped with a wet scrubber, maintain 

the 3-hour average parameter values at 

or below the operating limits 

established during the most recent 

performance test. 

(4) For each existing unit participating 

in the emissions averaging option that 

has an approved alternative operating 

plan, maintain the 3-hour average 

parameter values at or below the 

operating limits established in the most 

recent performance test. 

(5) For each existing unit participating 

in the emissions averaging option 

venting to a common stack 

configuration containing affected units 

from other subcategories, maintain the 

appropriate operating limit for each unit 

as specified in Table 4 to this subpart 

that applies. 

(b) Any instance where the owner or 

operator fails to comply with the 

continuous monitoring requirements in 

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

section is a deviation. 

Notification, Reports, and Records 

§ 63.7545 What notifications must I submit 

and when? 

(a) You must submit to the delegated 

authority all of the notifications in 

§ 63.7(b) and (c), § 63.8(e), (f)(4) and (6), 

and § 63.9(b) through (h) that apply to 

you by the dates specified. 

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

startup your affected source before May 

20, 2011, you must submit an Initial 

Notification not later than 120 days after 

May 20, 2011. 

(c) As specified in § 63.9(b)(4) and 

(b)(5), if you startup your new or 

reconstructed affected source on or after 

May 20, 2011, you must submit an 

Initial Notification not later than 15 

days after the actual date of startup of 

the affected source. 

(d) If you are required to conduct a 

performance test you must submit a 

Notification of Intent to conduct a 

performance test at least 60 days before 

the performance test is scheduled to 

begin. 

(e) If you are required to conduct an 

initial compliance demonstration as 

specified in § 63.7530(a), you must 

submit a Notification of Compliance 

Status according to § 63.9(h)(2)(ii). For 

the initial compliance demonstration for 

each affected source, you must submit 

the Notification of Compliance Status, 

including all performance test results 

and fuel analyses, before the close of 

business on the 60th day following the 

completion of all performance test and/ 

or other initial compliance 

demonstrations for the affected source 

according to § 63.10(d)(2). The 

Notification of Compliance Status report 

must contain all the information 

specified in paragraphs (e)(1) through 

(8), as applicable. 

(1) A description of the affected 

unit(s) including identification of which 

subcategory the unit is in, the design 

heat input capacity of the unit, a 

description of the add-on controls used 

on the unit, description of the fuel(s) 

burned, including whether the fuel(s) 

were determined by you or EPA through 

a petition process to be a non-waste 

under § 241.3, whether the fuel(s) were 

processed from discarded nonhazardous secondary materials within 

the meaning of § 241.3, and justification 

for the selection of fuel(s) burned during 

the compliance demonstration. 


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(2) Summary of the results of all 

performance tests and fuel analyses, and 

calculations conducted to demonstrate 

initial compliance including all 

established operating limits. 

(3) A summary of the maximum 

carbon monoxide emission levels 

recorded during the performance test to 

show that you have met any applicable 

emission standard in Table 1, 2, or 12 

to this subpart. 

(4) Identification of whether you plan 

to demonstrate compliance with each 

applicable emission limit through 

performance testing or fuel analysis. 

(5) Identification of whether you plan 

to demonstrate compliance by emissions 

averaging and identification of whether 

you plan to demonstrate compliance by 

using emission credits through energy 

conservation: 

(i) If you plan to demonstrate 

compliance by emission averaging, 

report the emission level that was being 

achieved or the control technology 

employed on May 20, 2011. 

(6) A signed certification that you 

have met all applicable emission limits 

and work practice standards. 

(7) If you had a deviation from any 

emission limit, work practice standard, 

or operating limit, you must also submit 

a description of the deviation, the 

duration of the deviation, and the 

corrective action taken in the 

Notification of Compliance Status 

report. 

(8) In addition to the information 

required in § 63.9(h)(2), your 

notification of compliance status must 

include the following certification(s) of 

compliance, as applicable, and signed 

by a responsible official: 

(i) ‘‘This facility complies with the 

requirements in § 63.7540(a)(10) to 

conduct an annual or biennial tune-up, 

as applicable, of each unit.’’ 

(ii) ‘‘This facility has had an energy 

assessment performed according to 

§ 63.7530(e).’’ 

(iii) Except for units that qualify for a 

statutory exemption as provided in 

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

include the following: ‘‘No secondary 

materials that are solid waste were 

combusted in any affected unit.’’ 

(f) If you operate a unit designed to 

burn natural gas, refinery gas, or other 

gas 1 fuels that is subject to this subpart, 

and you intend to use a fuel other than 

natural gas, refinery gas, or other gas 1 

fuel to fire the affected unit during a 

period of natural gas curtailment or 

supply interruption, as defined in 

§ 63.7575, you must submit a 

notification of alternative fuel use 

within 48 hours of the declaration of 

each period of natural gas curtailment or 

supply interruption, as defined in 

§ 63.7575. The notification must include 

the information specified in paragraphs 

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

(1) Company name and address. 

(2) Identification of the affected unit. 

(3) Reason you are unable to use 

natural gas or equivalent fuel, including 

the date when the natural gas 

curtailment was declared or the natural 

gas supply interruption began. 

(4) Type of alternative fuel that you 

intend to use. 

(5) Dates when the alternative fuel use 

is expected to begin and end. 

(g) 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) or process heater(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. 

(h) If you intend to switch fuels, and 

this fuel switch may result in the 

applicability of a different subcategory, 

you must provide 30 days prior notice 

of the date upon which you will switch 

fuels. The notification must identify: 

(1) The name of the owner or operator 

of the affected source, the location of the 

source, the boiler(s) that will switch 

fuels, and the date of the notice. 

(2) The currently applicable 

subcategory under this subpart. 

(3) The date on which you became 

subject to the currently applicable 

standards. 

(4) The date upon which you will 

commence the fuel switch. 

§ 63.7550 What reports must I submit and 

when? 

(a) You must submit each report in 

Table 9 to this subpart that applies to 

you. 

(b) Unless the EPA Administrator has 

approved a different schedule for 

submission of reports under § 63.10(a), 

you must submit each report by the date 

in Table 9 to this subpart and according 

to the requirements in paragraphs (b)(1) 

through (5) of this section. For units that 

are subject only to a requirement to 

conduct an annual or biennial tune-up 

according to § 63.7540(a)(10) or (a)(11), 

respectively, and not subject to emission 

limits or operating limits, you may 

submit only an annual or biennial 

compliance report, as applicable, as 

specified in paragraphs (b)(1) through 

(5) of this section, instead of a semiannual compliance report. 

(1) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for 

your affected source in § 63.7495 and 

ending on June 30 or December 31, 

whichever date is the first date that 

occurs at least 180 days (or 1 or 2 year, 

as applicable, if submitting an annual or 

biennial compliance report) after the 

compliance date that is specified for 

your source in § 63.7495. 

(2) The first compliance report must 

be postmarked or delivered no later than 

July 31 or January 31, whichever date is 

the first date following the end of the 

first calendar half after the compliance 

date that is specified for your source in 

§ 63.7495. The first annual or biennial 

compliance report must be postmarked 

no later than January 31. 

(3) Each subsequent compliance 

report must cover the semiannual 

reporting period from January 1 through 

June 30 or the semiannual reporting 

period from July 1 through December 

31. Annual and biennial compliance 

reports must cover the applicable one or 

two year periods from January 1 to 

December 31. 

(4) Each subsequent compliance 

report must be postmarked or delivered 

no later than July 31 or January 31, 

whichever date is the first date 

following the end of the semiannual 

reporting period. Annual and biennial 

compliance reports must be postmarked 

no later than January 31. 

(5) For each affected source that is 

subject to permitting regulations 

pursuant to part 70 or part 71 of this 

chapter, and if the delegated authority 

has established dates for submitting 

semiannual reports pursuant to 

§ 70.6(a)(3)(iii)(A) or § 71.6(a)(3)(iii)(A), 

you may submit the first and subsequent 

compliance reports according to the 

dates the delegated authority has 

established instead of according to the 

dates in paragraphs (b)(1) through (4) of 

this section. 

(c) The compliance report must 

contain the information required in 

paragraphs (c)(1) through (13) of this 

section. 

(1) Company name and address. 

(2) Statement by a responsible official 

with that official’s name, title, and 

signature, certifying the truth, accuracy, 

and completeness of the content of the 

report. 

(3) Date of report and beginning and 

ending dates of the reporting period. 

(4) The total fuel use by each affected 

source subject to an emission limit, for 

each calendar month within the 


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semiannual (or annual or biennial) 

reporting period, including, but not 

limited to, a description of the fuel, 

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

basis for concluding that the fuel is not 

a waste, and the total fuel usage amount 

with units of measure. 

(5) A summary of the results of the 

annual performance tests for affected 

sources subject to an emission limit, a 

summary of any fuel analyses associated 

with performance tests, and 

documentation of any operating limits 

that were reestablished during this test, 

if applicable. If you are conducting 

performance tests once every 3 years 

consistent with § 63.7515(b) or (c), the 

date of the last 2 performance tests, a 

comparison of the emission level you 

achieved in the last 2 performance tests 

to the 75 percent emission limit 

threshold required in § 63.7515(b) or (c), 

and a statement as to whether there 

have been any operational changes since 

the last performance test that could 

increase emissions. 

(6) A signed statement indicating that 

you burned no new types of fuel in an 

affected source subject to an emission 

limit. Or, if you did burn a new type of 

fuel and are subject to a hydrogen 

chloride emission limit, you must 

submit the calculation of chlorine input, 

using Equation 5 of § 63.7530, that 

demonstrates that your source is still 

within its maximum chlorine input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing) or you must submit 

the calculation of hydrogen chloride 

emission rate using Equation 10 of 

§ 63.7530 that demonstrates that your 

source is still meeting the emission limit 

for hydrogen chloride emissions (for 

boilers or process heaters that 

demonstrate compliance through fuel 

analysis). If you burned a new type of 

fuel and are subject to a mercury 

emission limit, you must submit the 

calculation of mercury input, using 

Equation 8 of § 63.7530, that 

demonstrates that your source is still 

within its maximum mercury input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing), or you must 

submit the calculation of mercury 

emission rate using Equation 11 of 

§ 63.7530 that demonstrates that your 

source is still meeting the emission limit 

for mercury emissions (for boilers or 

process heaters that demonstrate 

compliance through fuel analysis). 

(7) If you wish to burn a new type of 

fuel in an affected source subject to an 

emission limit and you cannot 

demonstrate compliance with the 

maximum chlorine input operating limit 

using Equation 7 of § 63.7530 or the 

maximum mercury input operating limit 

using Equation 8 of § 63.7530, you must 

include in the compliance report a 

statement indicating the intent to 

conduct a new performance test within 

60 days of starting to burn the new fuel. 

(8) A summary of any monthly fuel 

analyses conducted to demonstrate 

compliance according to §§ 63.7521 and 

63.7530 for affected sources subject to 

emission limits, and any fuel 

specification analyses conducted 

according to § 63.7521(f) and 

§ 63.7530(g). 

(9) If there are no deviations from any 

emission limits or operating limits in 

this subpart that apply to you, a 

statement that there were no deviations 

from the emission limits or operating 

limits during the reporting period. 

(10) If there were no deviations from 

the monitoring requirements including 

no periods during which the CMSs, 

including CEMS, COMS, and 

continuous parameter monitoring 

systems, were out of control as specified 

in § 63.8(c)(7), a statement that there 

were no deviations and no periods 

during which the CMS were out of 

control during the reporting period. 

(11) If a malfunction occurred during 

the reporting period, the report must 

include the number, duration, and a 

brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by you during a 

malfunction of a boiler, process heater, 

or associated air pollution control 

device or CMS to minimize emissions in 

accordance with § 63.7500(a)(3), 

including actions taken to correct the 

malfunction. 

(12) Include the date of the most 

recent tune-up for each unit subject to 

only the requirement to conduct an 

annual or biennial tune-up according to 

§ 63.7540(a)(10) or (a)(11), respectively. 

Include the date of the most recent 

burner inspection if it was not done 

annually or biennially and was delayed 

until the next scheduled unit shutdown. 

(13) If you plan to demonstrate 

compliance by emission averaging, 

certify the emission level achieved or 

the control technology employed is no 

less stringent that the level or control 

technology contained in the notification 

of compliance status in 

§ 63.7545(e)(5)(i). 

(d) For each deviation from an 

emission limit or operating limit in this 

subpart that occurs at an affected source 

where you are not using a CMS to 

comply with that emission limit or 

operating limit, the compliance report 

must additionally contain the 

information required in paragraphs 

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

(1) The total operating time of each 

affected source during the reporting 

period. 

(2) A description of the deviation and 

which emission limit or operating limit 

from which you deviated. 

(3) Information on the number, 

duration, and cause of deviations 

(including unknown cause), as 

applicable, and the corrective action 

taken. 

(4) A copy of the test report if the 

annual performance test showed a 

deviation from the emission limits. 

(e) For each deviation from an 

emission limit, operating limit, and 

monitoring requirement in this subpart 

occurring at an affected source where 

you are using a CMS to comply with 

that emission limit or operating limit, 

you must include the information 

required in paragraphs (e)(1) through 

(12) of this section. This includes any 

deviations from your site-specific 

monitoring plan as required in 

§ 63.7505(d). 

(1) The date and time that each 

deviation started and stopped and 

description of the nature of the 

deviation (i.e., what you deviated from). 

(2) The date and time that each CMS 

was inoperative, except for zero (lowlevel) and high-level checks. 

(3) The date, time, and duration that 

each CMS was out of control, including 

the information in § 63.8(c)(8). 

(4) The date and time that each 

deviation started and stopped. 

(5) A summary of the total duration of 

the deviation during the reporting 

period and the total duration as a 

percent of the total source operating 

time during that reporting period. 

(6) An analysis of the total duration of 

the deviations during the reporting 

period into those that are due to control 

equipment problems, process problems, 

other known causes, and other 

unknown causes. 

(7) A summary of the total duration of 

CMS’s downtime during the reporting 

period and the total duration of CMS 

downtime as a percent of the total 

source operating time during that 

reporting period. 

(8) An identification of each 

parameter that was monitored at the 

affected source for which there was a 

deviation. 

(9) A brief description of the source 

for which there was a deviation. 

(10) A brief description of each CMS 

for which there was a deviation. 


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(11) The date of the latest CMS 

certification or audit for the system for 

which there was a deviation. 

(12) A description of any changes in 

CMSs, processes, or controls since the 

last reporting period for the source for 

which there was a deviation. 

(f) Each affected source that has 

obtained a Title V operating permit 

pursuant to part 70 or part 71 of this 

chapter must report all deviations as 

defined in this subpart in the 

semiannual monitoring report required 

by § 70.6(a)(3)(iii)(A) or 

§ 71.6(a)(3)(iii)(A). If an affected source 

submits a compliance report pursuant to 

Table 9 to this subpart along with, or as 

part of, the semiannual monitoring 

report required by § 70.6(a)(3)(iii)(A) or 

§ 71.6(a)(3)(iii)(A), and the compliance 

report includes all required information 

concerning deviations from any 

emission limit, operating limit, or work 

practice requirement in this subpart, 

submission of the compliance report 

satisfies any obligation to report the 

same deviations in the semiannual 

monitoring report. However, submission 

of a compliance report does not 

otherwise affect any obligation the 

affected source may have to report 

deviations from permit requirements to 

the delegated authority. 

(g) [Reserved] 

(h) As of January 1, 2012 and within 

60 days after the date of completing 

each performance test, as defined in 

§ 63.2, conducted to demonstrate 

compliance with this subpart, you must 

submit relative accuracy test audit (i.e., 

reference method) data and performance 

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

opacity data, electronically to EPA’s 

Central Data Exchange (CDX) by using 

the Electronic Reporting Tool (ERT) (see 

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

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFIRE database. 

§ 63.7555 What records must I keep? 

(a) You must keep records according 

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

section. 

(1) A copy of each notification and 

report that you submitted to comply 

with this subpart, including all 

documentation supporting any Initial 

Notification or Notification of 

Compliance Status or semiannual 

compliance report that you submitted, 

according to the requirements in 

§ 63.10(b)(2)(xiv). 

(2) Records of performance tests, fuel 

analyses, or other compliance 

demonstrations and performance 

evaluations as required in 

§ 63.10(b)(2)(viii). 

(b) For each CEMS, COMS, and 

continuous monitoring system you must 

keep records according to paragraphs 

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

(1) Records described in 

§ 63.10(b)(2)(vii) through (xi). 

(2) Monitoring data for continuous 

opacity monitoring system during a 

performance evaluation as required in 

§ 63.6(h)(7)(i) and (ii). 

(3) Previous (i.e., superseded) 

versions of the performance evaluation 

plan as required in § 63.8(d)(3). 

(4) Request for alternatives to relative 

accuracy test for CEMS as required in 

§ 63.8(f)(6)(i). 

(5) Records of the date and time that 

each deviation started and stopped. 

(c) You must keep the records 

required in Table 8 to this subpart 

including records of all monitoring data 

and calculated averages for applicable 

operating limits, such as opacity, 

pressure drop, pH, and operating load, 

to show continuous compliance with 

each emission limit and operating limit 

that applies to you. 

(d) For each boiler or process heater 

subject to an emission limit in Table 1, 

2 or 12 to this subpart, you must also 

keep the applicable records in 

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

section. 

(1) You must keep records of monthly 

fuel use by each boiler or process heater, 

including the type(s) of fuel and 

amount(s) used. 

(2) If you combust non-hazardous 

secondary materials that have been 

determined not to be solid waste 

pursuant to § 41.3(b)(1), you must keep 

a record which documents how the 

secondary material meets each of the 

legitimacy criteria. If you combust a fuel 

that has been processed from a 

discarded non-hazardous secondary 

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

must keep records as to how the 

operations that produced the fuel 

satisfies the definition of processing in 

§ 241.2. If the fuel received a non-waste 

determination pursuant to the petition 

process submitted under § 241.3(c), you 

must keep a record that documents how 

the fuel satisfies the requirements of the 

petition process. 

(3) You must keep records of monthly 

hours of operation by each boiler or 

process heater that meets the definition 

of limited-use boiler or process heater. 

(4) A copy of all calculations and 

supporting documentation of maximum 

chlorine fuel input, using Equation 7 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the hydrogen chloride emission 

limit, for sources that demonstrate 

compliance through performance 

testing. For sources that demonstrate 

compliance through fuel analysis, a 

copy of all calculations and supporting 

documentation of hydrogen chloride 

emission rates, using Equation 10 of 

§ 63.7530, that were done to 

demonstrate compliance with the 

hydrogen chloride emission limit. 

Supporting documentation should 

include results of any fuel analyses and 

basis for the estimates of maximum 

chlorine fuel input or hydrogen chloride 

emission rates. You can use the results 

from one fuel analysis for multiple 

boilers and process heaters provided 

they are all burning the same fuel type. 

However, you must calculate chlorine 

fuel input, or hydrogen chloride 

emission rate, for each boiler and 

process heater. 

(5) A copy of all calculations and 

supporting documentation of maximum 

mercury fuel input, using Equation 8 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the mercury emission limit for 

sources that demonstrate compliance 

through performance testing. For 

sources that demonstrate compliance 

through fuel analysis, a copy of all 

calculations and supporting 

documentation of mercury emission 

rates, using Equation 11 of § 63.7530, 

that were done to demonstrate 

compliance with the mercury emission 

limit. Supporting documentation should 

include results of any fuel analyses and 

basis for the estimates of maximum 

mercury fuel input or mercury emission 

rates. You can use the results from one 

fuel analysis for multiple boilers and 

process heaters provided they are all 

burning the same fuel type. However, 

you must calculate mercury fuel input, 

or mercury emission rates, for each 

boiler and process heater. 

(6) If, consistent with § 63.7515(b) and 

(c), you choose to stack test less 

frequently than annually, you must keep 

annual records that document that your 

emissions in the previous stack test(s) 

were less than 75 percent of the 

applicable emission limit, and 

document that there was no change in 

source operations including fuel 

composition and operation of air 

pollution control equipment that would 

cause emissions of the relevant 

pollutant to increase within the past 

year. 

(7) Records of the occurrence and 

duration of each malfunction of the 

boiler or process heater, or of the 

associated air pollution control and 

monitoring equipment. 

(8) Records of actions taken during 

periods of malfunction to minimize 

emissions in accordance with the 


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general duty to minimize emissions in 

§ 63.7500(a)(3), including corrective 

actions to restore the malfunctioning 

boiler or process heater, air pollution 

control, or monitoring equipment to its 

normal or usual manner of operation. 

(e) If you elect to average emissions 

consistent with § 63.7522, you must 

additionally keep a copy of the emission 

averaging implementation plan required 

in § 63.7522(g), all calculations required 

under § 63.7522, including monthly 

records of heat input or steam 

generation, as applicable, and 

monitoring records consistent with 

§ 63.7541. 

(f) If you elect to use emission credits 

from energy conservation measures to 

demonstrate compliance according to 

§ 63.7533, you must keep a copy of the 

Implementation Plan required in 

§ 63.7533(d) and copies of all data and 

calculations used to establish credits 

according to § 63.7533(b), (c), and (f). 

(g) If you elected to demonstrate that 

the unit meets the specifications for 

hydrogen sulfide and mercury for the 

other gas 1 subcategory and you cannot 

submit a signed certification under 

§ 63.7545(g) because the constituents 

could exceed the specifications, you 

must maintain monthly records of the 

calculations and results of the fuel 

specifications for mercury and hydrogen 

sulfide in Table 6. 

(h) If you operate a unit designed to 

burn natural gas, refinery gas, or other 

gas 1 fuel that is subject to this subpart, 

and you use an alternative fuel other 

than natural gas, refinery gas, or other 

gas 1 fuel, you must keep records of the 

total hours per calendar year that 

alternative fuel is burned. 

§ 63.7560 In what form and how long must 

I keep my records? 

(a) Your records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). 

(b) As specified in § 63.10(b)(1), you 

must keep each record for 5 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(c) You must keep each record on site, 

or they must be accessible from on site 

(for example, through a computer 

network), for at least 2 years after the 

date of each occurrence, measurement, 

maintenance, corrective action, report, 

or record, according to § 63.10(b)(1). 

You can keep the records off site for the 

remaining 3 years. 

Other Requirements and Information 

§ 63.7565 What parts of the General 

Provisions apply to me? 

Table 10 to this subpart shows which 

parts of the General Provisions in 

§§ 63.1 through 63.15 apply to you. 

§ 63.7570 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by EPA, or a delegated 

authority such as your State, local, or 

tribal agency. If the EPA Administrator 

has delegated authority to your State, 

local, or tribal agency, then that agency 

(as well as EPA) has the authority to 

implement and enforce this subpart. 

You should contact your EPA Regional 

Office to find out if 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 

listed in paragraphs (b)(1) through (5) of 

this section are retained by the EPA 

Administrator and are not transferred to 

the State, local, or tribal agency, 

however, EPA retains oversight of this 

subpart and can take enforcement 

actions, as appropriate. 

(1) Approval of alternatives to the 

non-opacity emission limits and work 

practice standards in § 63.7500(a) and 

(b) under § 63.6(g). 

(2) Approval of alternative opacity 

emission limits in § 63.7500(a) under 

§ 63.6(h)(9). 

(3) Approval of major change to test 

methods in Table 5 to this subpart 

under § 63.7(e)(2)(ii) and (f) and as 

defined in § 63.90, and alternative 

analytical methods requested under 

§ 63.7521(b)(2). 

(4) Approval of major change to 

monitoring under § 63.8(f) and as 

defined in § 63.90, and approval of 

alternative operating parameters under 

§ 63.7500(a)(2) and § 63.7522(g)(2). 

(5) Approval of major change to 

recordkeeping and reporting under 

§ 63.10(e) and as defined in § 63.90. 

§ 63.7575 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act, in § 63.2 

(the General Provisions), and in this 

section as follows: 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Annual heat input 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 principle to 

monitor relative particulate matter 

loadings. 

Benchmarking means a process of 

comparison against standard or average. 

Biomass or bio-based solid fuel means 

any biomass-based solid fuel that is not 

a solid waste. This includes, but is not 

limited to, wood residue; 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. 

Blast furnace gas fuel-fired boiler or 

process heater means an industrial/ 

commercial/institutional boiler or 

process heater that receives 90 percent 

or more of its total annual gas volume 

from blast furnace gas. 

Boiler means an enclosed device 

using controlled flame combustion and 

having the primary purpose of 

recovering thermal energy in the form of 

steam or 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, 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 are excluded from this 

definition. 

Boiler system means the boiler and 

associated components, such as, the 

feed water system, the combustion air 

system, the fuel system (including 

burners), blowdown system, combustion 

control system, and energy consuming 

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, subVerDate Mar<15>2010 19:21 Mar 18, 2011 Jkt 223001 PO 00000 Frm 00076 Fmt 4701 Sfmt 4700 E:\FR\FM\21MRR5.SGM 21MRR5

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bituminous, or lignite by 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 for creating useful 

heat, including but not limited to, 

solvent-refined coal, coal-oil mixtures, 

and coal-water mixtures. Coal derived 

gases are excluded from this definition. 

Coal refuse means any by-product of 

coal mining or coal cleaning operations 

with an ash content greater than 50 

percent (by weight) and a heating value 

less than 13,900 kilojoules per kilogram 

(6,000 Btu per pound) on a dry basis. 

Commercial/institutional boiler 

means a boiler used in commercial 

establishments or institutional 

establishments such as medical centers, 

research centers, institutions of higher 

education, hotels, and laundries to 

provide 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. 

Cost-effective energy conservation 

measure means a measure that is 

implemented to improve the energy 

efficiency of the boiler or facility that 

has a payback (return of investment) 

period of 2 years or less. 

Deviation. 

(1) Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(i) Fails to meet any requirement or 

obligation established by this subpart 

including, but not limited to, any 

emission limit, operating limit, or work 

practice standard; 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. 

(2) A deviation is not always a 

violation. The determination of whether 

a deviation constitutes a violation of the 

standard is up to the discretion of the 

entity responsible for enforcement of the 

standards. 

Dioxins/furans means tetra- through 

octa-chlorinated dibenzo-p-dioxins and 

dibenzofurans. 

Distillate oil means fuel oils, 

including recycled oils, that comply 

with the specifications for fuel oil 

numbers 1 and 2, as defined by ASTM 

D396 (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 in 

fluidized bed boilers and process 

heaters are included in this definition. 

A dry scrubber is a dry control system. 

Dutch oven means a unit having a 

refractory-walled cell connected to a 

conventional boiler setting. Fuel 

materials are introduced through an 

opening in the roof of the Dutch oven 

and burn in a pile on its floor. 

Electric utility steam generating unit 

means a fossil fuel-fired combustion 

unit of more than 25 megawatts that 

serves a generator that produces 

electricity for sale. A fossil fuel-fired 

unit that cogenerates steam and 

electricity and supplies more than onethird 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. 

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. 

Emission credit means emission 

reductions above those required by this 

subpart. Emission credits generated may 

be used to comply with the emissions 

limits. Credits may come from pollution 

prevention projects that result in 

reduced fuel use by affected units. 

Shutdowns cannot be used to generate 

credits. 

Energy assessment means the 

following only as this term is used in 

Table 3 to this subpart. 

(1) Energy assessment for facilities 

with affected boilers and process heaters 

using less than 0.3 trillion Btu per year 

heat input will be one day in length 

maximum. The boiler system and 

energy use system accounting for at 

least 50 percent of the energy output 

will be evaluated to identify energy 

savings opportunities, within the limit 

of performing a one-day energy 

assessment. 

(2) The Energy assessment for 

facilities with affected boilers and 

process heaters using 0.3 to 1.0 trillion 

Btu per year will be 3 days in length 

maximum. The boiler system and any 

energy use system accounting for at 

least 33 percent of the energy output 

will be evaluated to identify energy 

savings opportunities, within the limit 

of performing a 3-day energy 

assessment. 

(3) In the Energy assessment for 

facilities with affected boilers and 

process heaters using greater than 1.0 

trillion Btu per year, the boiler system 

and any energy use system accounting 

for at least 20 percent of the energy 

output will be evaluated to identify 

energy savings opportunities. 

Energy management practices means 

the 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. 

Energy use system includes, but is not 

limited to, process heating; compressed 

air systems; machine drive (motors, 

pumps, fans); process cooling; facility 

heating, ventilation, and airconditioning systems; hot heater 

systems; building envelop; and lighting. 

Equivalent means the following only 

as this term is used in Table 6 to this 

subpart: 

(1) An equivalent sample collection 

procedure means a published voluntary 

consensus standard or practice (VCS) or 

EPA method that includes collection of 

a minimum of three composite fuel 

samples, with each composite 

consisting of a minimum of three 

increments collected at approximately 

equal intervals over the test period. 

(2) An equivalent sample compositing 

procedure means a published VCS or 

EPA method to systematically mix and 

obtain a representative subsample (part) 

of the composite sample. 

(3) An equivalent sample preparation 

procedure means a published VCS or 

EPA method that: Clearly states that the 

standard, practice or method is 

appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate 

sample preparation standard, practice or 

method for the pollutant in the chosen 

VCS or EPA determinative or analytical 

method. 

(4) An equivalent procedure for 

determining heat content means a 

published VCS or EPA method to obtain 

gross calorific (or higher heating) value. 

(5) An equivalent procedure for 

determining fuel moisture content 

means a published VCS or EPA method 

to obtain moisture content. If the sample 

analysis plan calls for determining 

metals (especially the mercury, 

selenium, or arsenic) using an aliquot of 

the dried sample, then the drying 


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temperature must be modified to 

prevent vaporizing these metals. 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 metals concentration 

mathematically adjusted to a dry basis. 

(6) An equivalent pollutant (mercury, 

hydrogen chloride, hydrogen sulfide) 

determinative or analytical procedure 

means a published VCS or EPA method 

that clearly states that the standard, 

practice, or method is appropriate for 

the pollutant and the fuel matrix and 

has a published detection limit equal or 

lower than the methods listed in Table 

6 to this subpart for the same purpose. 

Fabric filter means an add-on air 

pollution control device used to capture 

particulate matter by filtering gas 

streams through filter media, also 

known as a baghouse. A fabric filter is 

a dry control system. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the EPA Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, 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. 

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. 

Fuel cell means a boiler type in which 

the fuel is dropped onto suspended 

fixed grates and is fired in a pile. The 

refractory-lined fuel cell uses 

combustion air preheating and 

positioning of secondary and tertiary air 

injection ports to improve boiler 

efficiency. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

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

biomass, residual oil. Individual fuel 

types received from different suppliers 

are not considered new fuel types. 

Gaseous fuel includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, refinery 

gas, and biogas. Blast furnace gas is 

exempted from this definition. 

Heat input means heat derived from 

combustion of fuel in a boiler or process 

heater and does not include the heat 

input from preheated combustion air, 

recirculated flue gases, or exhaust gases 

from other sources such as gas turbines, 

internal combustion engines, kilns, etc. 

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. 

Hot water heater means a closed 

vessel with a capacity of no more than 

120 U.S. gallons in which water is 

heated by combustion of gaseous or 

liquid fuel and is withdrawn for use 

external to the vessel at pressures not 

exceeding 160 psig, including the 

apparatus by which the heat is 

generated and all controls and devices 

necessary to prevent water temperatures 

from exceeding 210 degrees Fahrenheit 

(99 degrees Celsius). Hot water heater 

also means a tankless unit that provides 

on demand hot water. 

Hybrid suspension grate boiler means 

a boiler designed with air distributors to 

spread the fuel material over the entire 

width and depth of the boiler 

combustion zone. The drying and much 

of the combustion of the fuel takes place 

in suspension, and the combustion is 

completed on the grate or floor of the 

boiler. 

Industrial boiler means a boiler used 

in manufacturing, processing, mining, 

and refining or any other industry to 

provide steam and/or hot water. 

Limited-use boiler or process heater 

means any boiler or process heater that 

burns any amount of solid, liquid, or 

gaseous fuels, has a rated capacity of 

greater than 10 MMBtu per hour heat 

input, and has a federally enforceable 

limit of no more than 876 hours per year 

of operation. 

Liquid fuel subcategory includes any 

boiler or process heater of any design 

that burns more than 10 percent liquid 

fuel and less than 10 percent solid fuel, 

based on the total annual heat input to 

the unit. 

Liquid fuel includes, but is not 

limited to, distillate oil, residual oil, onspec used oil, and biodiesel. 

Load fraction means the actual heat 

input of the boiler or process heater 

divided by the average operating load 

determined according to Table 7 to this 

subpart. 

Metal process furnaces include 

natural gas-fired annealing furnaces, 

preheat furnaces, reheat furnaces, aging 

furnaces, heat treat furnaces, and 

homogenizing furnaces. 

Million Btu (MMBtu) means one 

million British thermal units. 

Minimum activated carbon injection 

rate means load fraction (percent) 

multiplied by the lowest hourly average 

activated carbon injection rate measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limits. 

Minimum pressure drop means the 

lowest hourly average pressure drop 

measured according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

emission limit. 

Minimum scrubber effluent pH means 

the lowest hourly average sorbent liquid 

pH measured at the inlet to the wet 

scrubber according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

hydrogen chloride emission limit. 

Minimum scrubber liquid flow rate 

means the lowest hourly average liquid 

flow rate (e.g., to the PM scrubber or to 

the acid gas scrubber) measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limit. 

Minimum scrubber pressure drop 

means the lowest hourly average 

scrubber pressure drop measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limit. 

Minimum sorbent injection rate 

means load fraction (percent) multiplied 

by the lowest hourly average sorbent 

injection rate for each sorbent measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limits. 

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 7 to this 

subpart during the most recent 

performance 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 

(2) Liquid petroleum gas, as defined 

in ASTM D1835 (incorporated by 

reference, see § 63.14); or 

(3) A mixture of hydrocarbons that 

maintains a gaseous state at ISO 

conditions. Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 34 and 43 

mega joules (MJ) per dry standard cubic 


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meter (910 and 1,150 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. 

Opacity means the degree to which 

emissions reduce the transmission of 

light and obscure the view of an object 

in the background. 

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 or process heater unit. It is not 

necessary for fuel to be combusted for 

the entire 24-hour period. 

Other gas 1 fuel means a gaseous fuel 

that is not natural gas or refinery gas 

and does not exceed the maximum 

concentration of 40 micrograms/cubic 

meters of mercury and 4 parts per 

million, by volume, of hydrogen sulfide. 

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. 

Period of natural gas curtailment or 

supply interruption means a period of 

time during which the supply of natural 

gas to an affected facility is halted for 

reasons beyond the control of the 

facility. The act of entering into a 

contractual agreement with a supplier of 

natural gas established for curtailment 

purposes does not constitute a reason 

that is under the control of a facility for 

the purposes of this definition. An 

increase in the cost or unit price of 

natural gas does not constitute a period 

of natural gas curtailment or supply 

interruption. 

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 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. A 

device combusting solid waste, as 

defined in § 241.3, is not a process 

heater 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. Process 

heaters do not include units used for 

comfort heat or space heat, food 

preparation for on-site consumption, or 

autoclaves. 

Pulverized coal boiler means a boiler 

in which pulverized coal or other solid 

fossil fuel is introduced into an air 

stream that carries the coal to the 

combustion chamber of the boiler where 

it is fired in suspension. 

Qualified energy assessor means: 

(1) someone who has demonstrated 

capabilities to evaluate a set of the 

typical energy savings opportunities 

available in opportunity areas for steam 

generation and major energy using 

systems, including, but not limited to: 

(i) Boiler combustion management. 

(ii) Boiler thermal energy recovery, 

including 

(A) Conventional feed water 

economizer, 

(B) Conventional combustion air 

preheater, and 

(C) Condensing economizer. 

(iii) Boiler blowdown thermal energy 

recovery. 

(iv) Primary energy resource selection, 

including 

(A) Fuel (primary energy source) 

switching, and 

(B) Applied steam energy versus 

direct-fired energy versus electricity. 

(v) Insulation issues. 

(vi) Steam trap and steam leak 

management. 

(vi) Condensate recovery. 

(viii) Steam end-use management. 

(2) Capabilities and knowledge 

includes, but is not limited to: 

(i) Background, experience, and 

recognized abilities to perform the 

assessment activities, data analysis, and 

report preparation. 

(ii) Familiarity with operating and 

maintenance practices for steam or 

process heating systems. 

(iii) Additional potential steam 

system improvement opportunities 

including improving steam turbine 

operations and reducing steam demand. 

(iv) Additional process heating system 

opportunities including effective 

utilization of waste heat and use of 

proper process heating methods. 

(v) Boiler-steam turbine cogeneration 

systems. 

(vi) Industry specific steam end-use 

systems. 

Refinery gas means any gas that is 

generated at a petroleum refinery and is 

combusted. Refinery gas includes 

natural gas when the natural gas is 

combined and combusted in any 

proportion with a gas generated at a 

refinery. Refinery gas includes gases 

generated from other facilities when that 

gas is combined and combusted in any 

proportion with gas generated at a 

refinery. 

Residual oil means crude oil, and all 

fuel oil numbers 4, 5 and 6, as defined 

in ASTM D396–10 (incorporated by 

reference, see § 63.14(b)). 

Responsible official means 

responsible official as defined in § 70.2. 

Solid fossil fuel includes, and is not 

limited to, coal, coke, petroleum coke, 

and tire derived fuel. 

Solid fuel means any solid fossil fuel 

or biomass or bio-based solid fuel. 

Steam output means (1) for a boiler 

that produces steam for process or 

heating only (no power generation), the 

energy content in terms of MMBtu of the 

boiler steam output, and (2) for a boiler 

that cogenerates process steam and 

electricity (also known as combined 

heat and power (CHP)), the total energy 

output, which is the sum of the energy 

content of the steam exiting the turbine 

and sent to process in MMBtu and the 

energy of the electricity generated 

converted to MMBtu at a rate of 10,000 

Btu per kilowatt-hour generated (10 

MMBtu per megawatt-hour). 

Stoker means a unit consisting of a 

mechanically operated fuel feeding 

mechanism, a stationary or moving grate 

to support the burning of fuel and admit 

under-grate air to the fuel, an overfire 

air system to complete combustion, and 

an ash discharge system. This definition 

of stoker includes air swept stokers. 

There are two general types of stokers: 

Underfeed and overfeed. Overfeed 

stokers include mass feed and spreader 

stokers. 

Suspension boiler means a unit 

designed to feed the fuel by means of 

fuel distributors. The distributors inject 

air at the point where the fuel is 

introduced into the boiler in order to 

spread the fuel material over the boiler 

width. The drying (and much of the 

combustion) occurs while the material 

is suspended in air. The combustion of 

the fuel material is completed on a grate 

or floor below. Suspension boilers 

almost universally are designed to have 

high heat release rates to dry quickly the 

wet fuel as it is blown into the boilers. 

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 for more than 12 

consecutive months. Any temporary 

boiler that replaces a temporary boiler at 

a location and performs the same or 

similar function will be included in 

calculating the consecutive time period. 

(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 


srobinson on DSKHWCL6B1PROD with RULES5
15686 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

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 in an attempt to 

circumvent the residence time 

requirements of this definition. 

Tune-up means adjustments made to 

a boiler in accordance with procedures 

supplied by the manufacturer (or an 

approved specialist) to optimize the 

combustion efficiency. 

Unit designed to burn biomass/biobased solid subcategory includes any 

boiler or process heater that burns at 

least 10 percent biomass or bio-based 

solids on an annual heat input basis in 

combination with solid fossil fuels, 

liquid fuels, or gaseous fuels. 

Unit designed to burn coal/solid fossil 

fuel subcategory includes any boiler or 

process heater that burns any coal or 

other solid fossil fuel alone or at least 

10 percent coal or other solid fossil fuel 

on an annual heat input basis in 

combination with liquid fuels, gaseous 

fuels, or less than 10 percent biomass 

and bio-based solids on an annual heat 

input basis. 

Unit designed to burn gas 1 

subcategory includes any boiler or 

process heater that burns only natural 

gas, refinery gas, and/or other gas 1 

fuels; with the exception of liquid fuels 

burned for periodic testing not to exceed 

a combined total of 48 hours during any 

calendar year, or during periods of gas 

curtailment and gas supply 

emergencies. 

Unit designed to burn gas 2 (other) 

subcategory includes any boiler or 

process heater that is not in the unit 

designed to burn gas 1 subcategory and 

burns any gaseous fuels either alone or 

in combination with less than 10 

percent coal/solid fossil fuel, less than 

10 percent biomass/bio-based solid fuel, 

and less than 10 percent liquid fuels on 

an annual heat input basis. 

Unit designed to burn liquid 

subcategory includes any boiler or 

process heater that burns any liquid 

fuel, but less than 10 percent coal/solid 

fossil fuel and less than 10 percent 

biomass/bio-based solid fuel on an 

annual heat input basis, either alone or 

in combination with gaseous fuels. 

Gaseous fuel boilers and process heaters 

that burn liquid fuel for periodic testing 

of liquid fuel, maintenance, or operator 

training, not to exceed a combined total 

of 48 hours during any calendar year or 

during periods of maintenance, operator 

training, or testing of liquid fuel, not to 

exceed a combined total of 48 hours 

during any calendar year are not 

included in this definition. Gaseous fuel 

boilers and process heaters that burn 

liquid fuel during periods of gas 

curtailment or gas supply emergencies 

of any duration are also not included in 

this definition. 

Unit designed to burn liquid fuel that 

is a non-continental unit means an 

industrial, commercial, or institutional 

boiler or process heater designed to 

burn liquid fuel located in the State of 

Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Unit designed to burn solid fuel 

subcategory means any boiler or process 

heater that burns any solid fuel alone or 

at least 10 percent solid fuel on an 

annual heat input basis in combination 

with liquid fuels or gaseous fuels. 

Voluntary Consensus Standards or 

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 VoieCreuse, 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 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 and 

converts it to usable heat. Waste heat 

boilers are also referred to as heat 

recovery steam generators. 

Waste heat process heater means an 

enclosed device that recovers normally 

unused energy and converts it to usable 

heat. Waste heat process heaters are also 

referred to as recuperative process 

heaters. 

Wet scrubber means any add-on air 

pollution control device that mixes an 

aqueous stream or slurry with the 

exhaust gases from a boiler or process 

heater to control emissions of 

particulate matter or to 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, that is promulgated pursuant to 

section 112(h) of the Clean Air Act. 

Tables to Subpart DDDDD of Part 63 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 


srobinson on DSKHWCL6B1PROD with RULES5
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15687 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS a

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process 

heater is in this subcategory . . . 

For the following pollutants 

. . . 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following output-based limits 

(lb per MMBtu of steam 

output) . . . 

Using this specified sampling volume or test run 

duration . . . 

1. Units in all subcategories designed to burn 

solid fuel.

a. Particulate Matter .......... 0.0011 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

0.0011; (30-day rolling average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 3 

dscm per run. 

b. Hydrogen Chloride ........ 0.0022 lb per MMBtu of 

heat input.

0.0021 ............................... For M26A, collect a minimum of 1 dscm per run; 

for M26 collect a minimum of 60 liters per 

run. 

c. Mercury ......................... 3.5E–06 lb per MMBtu of 

heat input.

3.4E–06 ............................. For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 b

collect a minimum of 2 

dscm. 

2. Units designed to burn 

pulverized coal/solid fossil fuel.

a. Carbon monoxide (CO) 12 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.01 ................................... 1 hr minimum sampling 

time, use a span value 

of 30 ppmv. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.2.8E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

3. Stokers designed to 

burn coal/solid fossil fuel.

a. CO ................................. 6 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

0.005 ................................. 1 hr minimum sampling 

time, use a span value 

of 20 ppmv. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.2.8E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

4. Fluidized bed units designed to burn coal/solid 

fossil fuel.

a. CO ................................. 18 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.02 ................................... 1 hr minimum sampling 

time, use a span value 

of 40 ppmv. 

b. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

5. Stokers designed to 

burn biomass/bio-based 

solids.

a. CO ................................. 160 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.13 ................................... 1 hr minimum sampling 

time, use a span value 

of 400 ppmv. 

b. Dioxins/Furans .............. 0.005 ng/dscm (TEQ) corrected to 7 percent oxygen.4.4E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

6. Fluidized bed units designed to burn biomass/ 

bio-based solids.

a. CO ................................. 260 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.18 ................................... 1 hr minimum sampling 

time, use a span value 

of 500 ppmv. 

b. Dioxins/Furans .............. 0.02 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–11 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

7. Suspension burners/ 

Dutch Ovens designed 

to burn biomass/biobased solids.

a. CO ................................. 470 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.45 ................................... 1 hr minimum sampling 

time, use a span value 

of 1000 ppmv. 

b. Dioxins/Furans .............. 0.2 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–10 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

8. Fuel cells designed to 

burn biomass/bio-based 

solids.

a. CO ................................. 470 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.23 ................................... 1 hr minimum sampling 

time, use a span value 

of 1000 ppmv. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.2.86E–12 (TEQ) ................ Collect a minimum of 4 

dscm per run. 

9. Hybrid suspension/grate 

units designed to burn 

biomass/bio-based solids.

a. CO ................................. 1,500 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.84 ................................... 1 hr minimum sampling 

time, use a span value 

of 3000 ppmv. 


srobinson on DSKHWCL6B1PROD with RULES5
15688 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS a—Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process 

heater is in this subcategory . . . 

For the following pollutants 

. . . 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following output-based limits 

(lb per MMBtu of steam 

output) . . . 

Using this specified sampling volume or test run 

duration . . . 

b. Dioxins/Furans .............. 0.2 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–10 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

10. Units designed to burn 

liquid fuel.

a. Particulate Matter .......... 0.0013 lb per MMBtu of 

heat input (30-day rolling 

average for residual oilfired units 250 MMBtu/hr 

or greater, 3-run average for other units).

0.001; (30-day rolling average for residual oil-fired 

units 250 MMBtu/hr or 

greater, 3-run average 

for other units).

Collect a minimum of 3 

dscm per run. 

b. Hydrogen Chloride ........ 0.00033 lb per MMBtu of 

heat input.

0.0003 ............................... For M26A: Collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury ......................... 2.1E–07 lb per MMBtu of 

heat input.

0.2E–06 ............................. Collect enough volume to 

meet an in-stack detection limit data quality objective of 0.10 ug/dscm. 

d. CO ................................. 3 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

0.0026 ............................... 1 hr minimum sampling 

time, use a span value 

of 3 ppmv. 

e. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.4.6E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

11. Units designed to burn 

liquid fuel located in noncontinental States and 

territories.

a. Particulate Matter .......... 0.0013 lb per MMBtu of 

heat input (30-day rolling 

average for residual oilfired units 250 MMBtu/hr 

or greater, 3-run average for other units).

0.001; (30-day rolling average for residual oil-fired 

units 250 MMBtu/hr or 

greater, 3-run average 

for other units).

Collect a minimum of 3 

dscm per run. 

b. Hydrogen Chloride ........ 0.00033 lb per MMBtu of 

heat input.

0.0003 ............................... For M26A: Collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury ......................... 7.8E–07 lb per MMBtu of 

heat input.

8.0E–07 ............................. For M29, collect a minimum of 3 dscm per run; 

for M30B, collect a minimum sample as specified in the method; for 

ASTM D6784 b collect a 

minimum of 3 dscm. 

d. CO ................................. 51 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.043 ................................. 1 hr minimum sampling 

time, use a span value 

of 100 ppmv. 

e. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.4.6E–12(TEQ) ................... Collect a minimum of 3 

dscm per run. 

12. Units designed to burn 

gas 2 (other) gases.

a. Particulate Matter .......... 0.0067 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

.004; (30-day rolling average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.0017 lb per MMBtu of 

heat input.

.003 ................................... For M26A, Collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 


srobinson on DSKHWCL6B1PROD with RULES5
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15689 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS a—Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process 

heater is in this subcategory . . . 

For the following pollutants 

. . . 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following output-based limits 

(lb per MMBtu of steam 

output) . . . 

Using this specified sampling volume or test run 

duration . . . 

c. Mercury ......................... 7.9E–06 lb per MMBtu of 

heat input.

2.0E–07 ............................. For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 b

collect a minimum of 2 

dscm. 

d. CO ................................. 3 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

0.002 ................................. 1 hr minimum sampling 

time, use a span value 

of 10 ppmv. 

e. Dioxins/Furans .............. 0.08 ng/dscm (TEQ) corrected to 7 percent oxygen.4.1E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run 

a If your affected source is a new or reconstructed affected source that commenced construction or reconstruction after June 4, 2010, and before May 20, 2011, you may comply with the emission limits in Table 12 to this subpart until March 21, 2014. On and after March 21, 2014, you 

must comply with the emission limits in Table 1 to this subpart. b Incorporated by reference, see § 63.14. 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process 

heater is in this subcategory . . . 

For the following pollutants 

. . . 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following output-based limits (lb per 

MMBtu of steam output) 

. . . 

Using this specified sampling volume or test run 

duration . . . 

1. Units in all subcategories designed to burn 

solid fuel.

a. Particulate Matter .......... 0.039 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

0.038; (30-day rolling average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.035 lb per MMBtu of 

heat input.

0.04 ................................... For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury ......................... 4.6E–06 lb per MMBtu of 

heat input.

4.5E–06 ............................. For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

2. Pulverized coal units designed to burn pulverized coal/solid fossil fuel.a. CO ................................. 160 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.14 ................................... 1 hr minimum sampling 

time, use a span value 

of 300 ppmv. 

b. Dioxins/Furans .............. 0.004 ng/dscm (TEQ) corrected to 7 percent oxygen.3.7E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

3. Stokers designed to 

burn coal/solid fossil fuel.

a. CO ................................. 270 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.25 ................................... 1 hr minimum sampling 

time, use a span value 

of 500 ppmv. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.2.8E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 


srobinson on DSKHWCL6B1PROD with RULES5
15690 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process 

heater is in this subcategory . . . 

For the following pollutants 

. . . 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following output-based limits (lb per 

MMBtu of steam output) 

. . . 

Using this specified sampling volume or test run 

duration . . . 

4. Fluidized bed units designed to burn coal/solid 

fossil fuel.

a. CO ................................. 82 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.08 ................................... 1 hr minimum sampling 

time, use a span value 

of 200 ppmv 

b. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

5. Stokers designed to 

burn biomass/bio-based 

solid.

a. CO ................................. 490 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.35 ................................... 1 hr minimum sampling 

time, use a span value 

of 1000 ppmv. 

b. Dioxins/Furans .............. 0.005 ng/dscm (TEQ) corrected to 7 percent oxygen.4.4E–12 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

6. Fluidized bed units designed to burn biomass/ 

bio-based solid.

a. CO ................................. 430 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.28 ................................... 1 hr minimum sampling 

time, use a span value 

of 850 ppmv. 

b. Dioxins/Furans .............. 0.02 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–11(TEQ) ................... Collect a minimum of 4 

dscm per run. 

7. Suspension burners/ 

Dutch Ovens designed 

to burn biomass/biobased solid.

a. CO ................................. 470 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.45 ................................... 1 hr minimum sampling 

time, use a span value 

of 1000 ppmv. 

b. Dioxins/Furans .............. 0.2 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–10 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

8. Fuel cells designed to 

burn biomass/bio-based 

solid.

a. CO ................................. 690 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.34 ................................... 1 hr minimum sampling 

time, use a span value 

of 1300 ppmv. 

b. Dioxins/Furans .............. 4 ng/dscm (TEQ) corrected to 7 percent oxygen.3.5E–09 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

9. Hybrid suspension/grate 

units designed to burn 

biomass/bio-based solid.

a. CO ................................. 3,500 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

2.0 ..................................... 1 hr minimum sampling 

time, use a span value 

of 7000 ppmv. 

b. Dioxins/Furans .............. 0.2 ng/dscm (TEQ) corrected to 7 percent oxygen.1.8E–10 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

10. Units designed to burn 

liquid fuel.

a. Particulate Matter .......... 0.0075 lb per MMBtu of 

heat input (30-day rolling 

average for residual oilfired units 250 MMBtu/hr 

or greater, 3-run average for other units).

0.0073; (30-day rolling average for residual oilfired units 250 MMBtu/hr 

or greater, 3-run average for other units).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.00033 lb per MMBtu of 

heat input.

0.0003 ............................... For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 200 liters per 

run. 

c. Mercury ......................... 3.5E–06 lb per MMBtu of 

heat input.

3.3E–06 ............................. For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B collect a minimum sample 

as specified in the method, for ASTM D6784 a

collect a minimum of 2 

dscm. 

d. CO ................................. 10 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.0083 ............................... 1 hr minimum sampling 

time, use a span value 

of 20 ppmv. 

e. Dioxins/Furans .............. 4 ng/dscm (TEQ) corrected to 7 percent oxygen.9.2E–09 (TEQ) .................. Collect a minimum of 1 

dscm per run. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15691 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process 

heater is in this subcategory . . . 

For the following pollutants 

. . . 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following output-based limits (lb per 

MMBtu of steam output) 

. . . 

Using this specified sampling volume or test run 

duration . . . 

11. Units designed to burn 

liquid fuel located in noncontinental States and 

territories.

a. Particulate Matter .......... 0.0075 lb per MMBtu of 

heat input (30-day rolling 

average for residual oilfired units 250 MMBtu/hr 

or greater, 3-run average for other units).

0.0073; (30-day rolling average for residual oilfired units 250 MMBtu/hr 

or greater, 3-run average for other units).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.00033 lb per MMBtu of 

heat input.

0.0003 ............................... For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 200 liters per 

run. 

c. Mercury ......................... 7.8E–07 lb per MMBtu of 

heat input.

8.0E–07 ............................. For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

d. CO ................................. 160 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.13 ................................... 1 hr minimum sampling 

time, use a span value 

of 300 ppmv. 

e. Dioxins/Furans .............. 4 ng/dscm (TEQ) corrected to 7 percent oxygen.9.2E–09 (TEQ) .................. Collect a minimum of 1 

dscm per run. 

12. Units designed to burn 

gas 2 (other) gases.

a. Particulate Matter .......... 0.043 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

0.026; (30-day rolling average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.0017 lb per MMBtu of 

heat input.

0.001 ................................. For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury ......................... 1.3E–05 lb per MMBtu of 

heat input.

7.8E–06 ............................. For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

d. CO ................................. 9 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

0.005 ................................. 1 hr minimum sampling 

time, use a span value 

of 20 ppmv. 

e. Dioxins/Furans .............. 0.08 ng/dscm (TEQ) corrected to 7 percent oxygen.3.9E–11 (TEQ) .................. Collect a minimum of 4 

dscm per run. 

a Incorporated by reference, see § 63.14. 

As stated in § 63.7500, you must 

comply with the following applicable 

work practice standards: 

TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS

If your unit is . . . You must meet the following . . . 

1. A new or existing boiler or process heater with heat input capacity of 

less than 10 million Btu per hour or a limited use boiler or process 

heater.

Conduct a tune-up of the boiler or process heater biennially as specified in § 63.7540. 


srobinson on DSKHWCL6B1PROD with RULES5
15692 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS—Continued 

If your unit is . . . You must meet the following . . . 

2. A new or existing boiler or process heater in either the Gas 1 or 

Metal Process Furnace subcategory with heat input capacity of 10 

million Btu per hour or greater.

Conduct a tune-up of the boiler or process heater annually as specified 

in § 63.7540. 

3. An existing boiler or process heater located at a major source facility Must have a one-time energy assessment performed on the major 

source facility by qualified energy assessor. An energy assessment 

completed on or after January 1, 2008, that meets or is amended to 

meet the energy assessment requirements in this table, satisfies the 

energy assessment requirement. The energy assessment must include: 

a. A visual inspection of the boiler or process heater system. 

b. An evaluation of operating characteristics of the facility, specifications of energy using systems, operating and maintenance procedures, and unusual operating constraints, 

c. An inventory of major energy consuming systems, 

d. A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage, 

e. A review of the facility’s energy management practices and provide 

recommendations for improvements consistent with the definition of 

energy management practices, 

f. A list of major energy conservation measures, 

g. A list of the energy savings potential of the energy conservation 

measures identified, and 

h. A comprehensive report detailing the ways to improve efficiency, the 

cost of specific improvements, benefits, and the time frame for recouping those investments. 

4. An existing or new unit subject to emission limits in Tables 1, 2, or 

12 of this subpart..

Minimize the unit’s startup and shutdown periods following the manufacturer’s recommended procedures. If manufacturer’s recommended 

procedures are not available, you must follow recommended procedures for a unit of similar design for which manufacturer’s recommended procedures are available. 

As stated in § 63.7500, you must 

comply with the applicable operating 

limits: 

TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS

If you demonstrate compliance using . . . You must meet these operating limits . . . 

1. Wet PM scrubber control ..................................................................... Maintain the 12-hour block average pressure drop and the 12-hour 

block average liquid flow rate at or above the lowest 1-hour average 

pressure drop and the lowest 1-hour average liquid flow rate, respectively, measured during the most recent performance test demonstrating compliance with the PM emission limitation according to 

§ 63.7530(b) and Table 7 to this subpart. 

2. Wet acid gas (HCl) scrubber control .................................................... Maintain the 12-hour block average effluent pH at or above the lowest 

1-hour average pH and the 12-hour block average liquid flow rate at 

or above the lowest 1-hour average liquid flow rate measured during 

the most recent performance test demonstrating compliance with the 

HCl emission limitation according to § 63.7530(b) and Table 7 to this 

subpart. 

3. Fabric filter control on units not required to install and operate a PM 

CEMS.

a. Maintain opacity to less than or equal to 10 percent opacity (daily 

block average); or 

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

§ 63.7525 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. 

4. Electrostatic precipitator control on units not required to install and 

operate a PM CEMS.

a. This option is for boilers and process heaters that operate dry control systems (i.e., an ESP without a wet scrubber). Existing and new 

boilers and process heaters must maintain opacity to less than or 

equal to 10 percent opacity (daily block average); or 

b. This option is only for boilers and process heaters not subject to PM 

CEMS or continuous compliance with an opacity limit (i.e., COMS). 

Maintain the minimum total secondary electric power input of the 

electrostatic precipitator at or above the operating limits established 

during the performance test according to § 63.7530(b) and Table 7 to 

this subpart. 

5. Dry scrubber or carbon injection control .............................................. Maintain the minimum sorbent or carbon injection rate as defined in 

§ 63.7575 of this subpart. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15693 

TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS—Continued 

If you demonstrate compliance using . . . You must meet these operating limits . . . 

6. Any other add-on air pollution control type on units not required to 

install and operate a PM CEMS.

This option is for boilers and process heaters that operate dry control 

systems. Existing and new boilers and process heaters must maintain opacity to less than or equal to 10 percent opacity (daily block 

average). 

7. Fuel analysis ........................................................................................ Maintain the fuel type or fuel mixture such that the applicable emission 

rates calculated according to § 63.7530(c)(1), (2) and/or (3) is less 

than the applicable emission limits. 

8. Performance testing ............................................................................. For boilers and process heaters that demonstrate compliance with a 

performance test, maintain the operating load of each unit such that 

is does not exceed 110 percent of the average operating load recorded during the most recent performance test. 

9. Continuous Oxygen Monitoring System ............................................... For boilers and process heaters subject to a carbon monoxide emission limit that demonstrate compliance with an O2 CEMS as specified in § 63.7525(a), maintain the oxygen level of the stack gas such 

that it is not below the lowest hourly average oxygen concentration 

measured during the most recent CO performance test. 

As stated in § 63.7520, you must 

comply with the following requirements 

for performance testing for existing, new 

or reconstructed affected sources: 

TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS

To conduct a performance 

test for the following pollutant... You must... Using... 

1. Particulate Matter ............ a. Select sampling ports location and the number of traverse points.

b. Determine velocity and volumetric flow-rate of the 

stack gas..

Method 1 at 40 CFR part 60, appendix A–1 of this 

chapter. 

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 

or A–2 to part 60 of this chapter. 

c. Determine oxygen or carbon dioxide concentration of 

the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–2 to 

part 60 of this chapter, or ANSI/ASME PTC 19.10– 

1981.a

d. Measure the moisture content of the stack gas .......... Method 4 at 40 CFR part 60, appendix A–3 of this 

chapter. 

e. Measure the particulate matter emission concentration.Method 5 or 17 (positive pressure fabric filters must use 

Method 5D) at 40 CFR part 60, appendix A–3 or A–6 

of this chapter. 

f. Convert emissions concentration to lb per MMBtu 

emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of this chapter. 

2. Hydrogen chloride ........... a. Select sampling ports location and the number of traverse points.Method 1 at 40 CFR part 60, appendix A–1 of this 

chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–2 

of this chapter. 

c. Determine oxygen or carbon dioxide concentration of 

the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–2 of 

this chapter, or ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the stack gas .......... Method 4 at 40 CFR part 60, appendix A–3 of this 

chapter. 

e. Measure the hydrogen chloride emission concentration.Method 26 or 26A (M26 or M26A) at 40 CFR part 60, 

appendix A–8 of this chapter. 

f. Convert emissions concentration to lb per MMBtu 

emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of this chapter. 

3. Mercury ........................... a. Select sampling ports location and the number of traverse points.Method 1 at 40 CFR part 60, appendix A–1 of this 

chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 

or A–2 of this chapter. 

c. Determine oxygen or carbon dioxide concentration of 

the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–1 of 

this chapter, or ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the stack gas .......... Method 4 at 40 CFR part 60, appendix A–3 of this 

chapter. 

e. Measure the mercury emission concentration ............ Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 

CFR part 60, appendix A–8 of this chapter or Method 

101A at 40 CFR part 60, appendix B of this chapter, 

or ASTM Method D6784.a

f. Convert emissions concentration to lb per MMBtu 

emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of this chapter. 

4. CO ................................... a. Select the sampling ports location and the number of 

traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this 

chapter. 


srobinson on DSKHWCL6B1PROD with RULES5
15694 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

To conduct a performance 

test for the following pollutant... You must... Using... 

b. Determine oxygen concentration of the stack gas ...... Method 3A or 3B at 40 CFR part 60, appendix A–3 of 

this chapter, or ASTM D6522–00 (Reapproved 2005), 

or ANSI/ASME PTC 19.10–1981.a

c. Measure the moisture content of the stack gas .......... Method 4 at 40 CFR part 60, appendix A–3 of this 

chapter. 

d. Measure the CO emission concentration .................... Method 10 at 40 CFR part 60, appendix A–4 of this 

chapter. Use a span value of 2 times the concentration of the applicable emission limit. 

5. Dioxins/Furans ................ a. Select the sampling ports location and the number of 

traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this 

chapter. 

b. Determine oxygen concentration of the stack gas ...... Method 3A or 3B at 40 CFR part 60, appendix A–3 of 

this chapter, or ASTM D6522–00 (Reapproved 

2005),a or ANSI/ASME PTC 19.10–1981.a

c. Measure the moisture content of the stack gas .......... Method 4 at 40 CFR part 60, appendix A–3 of this 

chapter. 

d. Measure the dioxins/furans emission concentration ... Method 23 at 40 CFR part 60, appendix A–7 of this 

chapter. 

e. Multiply the measured dioxins/furans emission concentration by the appropriate toxic equivalency factor.Table 11 of this subpart. 

a Incorporated by reference, see § 63.14. 

As stated in § 63.7521, you must 

comply with the following requirements 

for fuel analysis testing for existing, new 

or reconstructed affected sources. 

However, equivalent methods (as 

defined in § 63.7575) may be used in 

lieu of the prescribed methods at the 

discretion of the source owner or 

operator: 

TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS

To conduct a fuel 

analysis for the following 

pollutant . . . 

You must . . . Using . . . 

1. Mercury .......................................................... a. Collect fuel samples .................................... Procedure in § 63.7521(c) or ASTM D2234/ 

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

biomass), or equivalent. 

b. Composite fuel samples .............................. Procedure in § 63.7521(d) or equivalent. 

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

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

ASTM D2013/D2013M a (for coal), ASTM 

D5198 a (for biomass), or equivalent. 

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

biomass), or equivalent. 

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

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

7471Ba (for solid samples), or EPA SW– 

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

g. Convert concentration into units of pounds 

of pollutant per MMBtu of heat content.

2. Hydrogen Chloride ......................................... a. Collect fuel samples .................................... Procedure in § 63.7521(c) or ASTM D2234/ 

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

biomass), or equivalent. 

b. Composite fuel samples .............................. Procedure in § 63.7521(d) or equivalent. 

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

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

ASTM D2013/D2013M a (for coal), or ASTM 

D5198 a (for biomass), or equivalent. 

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

biomass), or equivalent. 

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

f. Measure chlorine concentration in fuel sample.EPA SW–846–9250,a ASTM D6721 a (for 

coal), or ASTM E776 a (for biomass), or 

equivalent. 

g. Convert concentrations into units of pounds 

of pollutant per MMBtu of heat content.

3. Mercury Fuel Specification for other gas 1 

fuels.

a. Measure mercury concentration in the fuel 

sample.

b. Convert concentration to unit of 

micrograms/cubic meter.

ASTM D5954,a

ASTM D6350,a ISO 6978–1:2003(E),a or ISO 

6978–2:2003(E) a, or equivalent. 


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Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15695 

TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS—Continued 

To conduct a fuel 

analysis for the following 

pollutant . . . 

You must . . . Using . . . 

4. Hydrogen Sulfide Fuel Specification for other 

gas 1 fuels.

a. Measure total hydrogen sulfide ...................

b. Convert to ppm ............................................

ASTM D4084a or equivalent. 

a Incorporated by reference, see § 63.14. 

As stated in § 63.7520, you must 

comply with the following requirements 

for establishing operating limits: 

TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS

If you have an applicable 

emission limit for . . . 

And your operating limits 

are based on . . . You must . . . Using . . . According to the following requirements 

1. Particulate matter or 

mercury.

a. Wet scrubber operating 

parameters.

i. Establish a site-specific 

minimum pressure drop 

and minimum flow rate 

operating limit according 

to § 63.7530(b).

(1) Data from the pressure 

drop and liquid flow rate 

monitors and the particulate matter or mercury 

performance test.

(a) You must collect pressure drop and liquid flow 

rate data every 15 minutes during the entire 

period of the performance tests; 

(b) Determine the lowest 

hourly average pressure 

drop and liquid flow rate 

by computing the hourly 

averages using all of the 

15-minute readings 

taken during each performance test. 

b. Electrostatic precipitator 

operating parameters 

(option only for units that 

operate wet scrubbers).

i. Establish a site-specific 

minimum total secondary electric power 

input according to 

§ 63.7530(b).

(1) Data from the voltage 

and secondary amperage monitors during the 

particulate matter or 

mercury performance 

test.

(a) You must collect secondary voltage and secondary amperage for 

each ESP cell and calculate total secondary 

electric power input data 

every 15 minutes during 

the entire period of the 

performance tests; 

(b) Determine the average 

total secondary electric 

power input by computing the hourly averages using all of the 15- 

minute readings taken 

during each performance test. 

2. Hydrogen Chloride ........ a. Wet scrubber operating 

parameters.

i. Establish site-specific 

minimum pressure drop, 

effluent pH, and flow 

rate operating limits according to § 63.7530(b).

(1) Data from the pressure 

drop, pH, and liquid 

flow-rate monitors and 

the hydrogen chloride 

performance test.

(a) You must collect pH 

and liquid flow-rate data 

every 15 minutes during 

the entire period of the 

performance tests; 

(b) Determine the hourly 

average pH and liquid 

flow rate by computing 

the hourly averages 

using all of the 15- 

minute readings taken 

during each performance test. 


srobinson on DSKHWCL6B1PROD with RULES5
15696 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS—Continued 

If you have an applicable 

emission limit for . . . 

And your operating limits 

are based on . . . You must . . . Using . . . According to the following requirements 

b. Dry scrubber operating 

parameters.

i. Establish a site-specific 

minimum sorbent injection rate operating limit 

according to 

§ 63.7530(b). If different 

acid gas sorbents are 

used during the hydrogen chloride performance test, the average 

value for each sorbent 

becomes the site-specific operating limit for 

that sorbent.

(1) Data from the sorbent 

injection rate monitors 

and hydrogen chloride 

or mercury performance 

test.

(a) You must collect sorbent injection rate data 

every 15 minutes during 

the entire period of the 

performance tests; 

(b) Determine the hourly 

average sorbent injection rate by computing 

the hourly averages 

using all of the 15- 

minute readings taken 

during each performance test. 

(c) Determine the lowest 

hourly average of the 

three test run averages 

established during the 

performance test as 

your operating limit. 

When your unit operates 

at lower loads, multiply 

your sorbent injection 

rate by the load fraction 

(e.g., for 50 percent 

load, multiply the injection rate operating limit 

by 0.5) to determine the 

required injection rate. 

3. Mercury and dioxins/ 

furans.

a. Activated carbon injection.i. Establish a site-specific 

minimum activated carbon injection rate operating limit according to 

§ 63.7530(b).

(1) Data from the activated 

carbon rate monitors 

and mercury and 

dioxins/furans performance tests.

(a) You must collect activated carbon injection 

rate data every 15 minutes during the entire 

period of the performance tests; 

(b) Determine the hourly 

average activated carbon injection rate by 

computing the hourly 

averages using all of the 

15-minute readings 

taken during each performance test. 

(c) Determine the lowest 

hourly average established during the performance test as your 

operating limit. When 

your unit operates at 

lower loads, multiply 

your activated carbon injection rate by the load 

fraction (e.g., actual heat 

input divided by heat 

input during performance test, for 50 percent 

load, multiply the injection rate operating limit 

by 0.5) to determine the 

required injection rate. 

4. Carbon monoxide .......... a. Oxygen .......................... i. Establish a unit-specific 

limit for minimum oxygen level according to 

§ 63.7520.

(1) Data from the oxygen 

monitor specified in 

§ 63.7525(a).

(a) You must collect oxygen data every 15 minutes during the entire 

period of the performance tests; 


srobinson on DSKHWCL6B1PROD with RULES5
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15697 

TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS—Continued 

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 hourly 

average oxygen concentration by computing 

the hourly averages 

using all of the 15- 

minute readings taken 

during each performance test. 

(c) Determine the lowest 

hourly average established during the performance test as your 

minimum operating limit. 

5. Any pollutant for which 

compliance is demonstrated by a performance test.

a. Boiler or process heater 

operating load.

i. Establish a unit specific 

limit for maximum operating load according to 

§ 63.7520(c).

(1) Data from the operating load monitors or 

from steam generation 

monitors.

(a) You must collect operating load 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. 

(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. 

As stated in § 63.7540, you must show 

continuous compliance with the 

emission limitations for affected sources 

according to the following: 

TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

If you must meet the following operating limits 

or work practice standards . . . You must demonstrate continuous compliance by . . . 

1. Opacity ............................................................ a. Collecting the opacity monitoring system data according to § 63.7525(c) and § 63.7535; 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 § 63.7525 and operating the 

fabric filter such that the requirements in § 63.7540(a)(9) are met. 

3. Wet Scrubber Pressure Drop and Liquid 

Flow-rate.

a. Collecting the pressure drop and liquid flow rate monitoring system data according to 

§§ 63.7525 and 63.7535; and 

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

c. Maintaining the 12-hour average pressure drop and liquid flow-rate at or above the operating limits established during the performance test according to § 63.7530(b). 

4. Wet Scrubber pH ............................................ a. Collecting the pH monitoring system data according to §§ 63.7525 and 63.7535; and 

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

c. Maintaining the 12-hour average pH at or above the operating limit established during the 

performance test according to § 63.7530(b). 

5. Dry Scrubber Sorbent or Carbon Injection 

Rate.

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

according to §§ 63.7525 and 63.7535; and 

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

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

sorbent or carbon injection rate as defined in § 63.7575. 

6. Electrostatic Precipitator Total Secondary 

Electric Power Input.

a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§ 63.7525 and 63.7535; and 

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

c. Maintaining the 12-hour average total secondary electric power input at or above the operating limits established during the performance test according to § 63.7530(b). 

7. Fuel Pollutant Content .................................... a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to § 63.7530(b) or (c) as applicable; and 

b. Keeping monthly records of fuel use according to § 63.7540(a). 


srobinson on DSKHWCL6B1PROD with RULES5
15698 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE—Continued 

If you must meet the following operating limits 

or work practice standards . . . You must demonstrate continuous compliance by . . . 

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

§ 63.7525(a). 

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

c. Maintain the 12-hour block average oxygen content in the exhaust at or above the lowest 

hourly average oxygen level measured during the most recent carbon monoxide performance test. 

9. Boiler or process heater operating load ......... a. Collecting operating load data or steam generation data every 15 minutes.

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

c. Maintaining the 12-hour average operating load at or below the operating limit established 

during the performance test according to § 63.7520(c). 

As stated in § 63.7550, you must 

comply with the following requirements 

for reports: 

TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS

You must submit a(n) The report must contain . . . You must submit the report 

. . . 

1. Compliance report ........... a. Information required in § 63.7550(c)(1) through (12); and ...................................... Semiannually, annually, or 

biennially according to 

the requirements in 

§ 63.7550(b). 

b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the requirements 

for work practice standards in Table 3 to this subpart that apply to you, a statement that there were no deviations from the emission limitations and work practice standards during the reporting period. If there were no periods during which 

the CMSs, including continuous emissions monitoring system, continuous opacity 

monitoring system, and operating parameter monitoring systems, were out-ofcontrol as specified in § 63.8(c)(7), a statement that there were no periods during 

which the CMSs were out-of-control during the reporting period; and 

c. If you have a deviation from any emission limitation (emission limit and operating 

limit) where you are not using a CMS to comply with that emission limit or operating limit, or a deviation from a work practice standard during the reporting period, the report must contain the information in § 63.7550(d); and 

d. If there were periods during which the CMSs, including continuous emissions 

monitoring system, continuous opacity monitoring system, and operating parameter monitoring systems, were out-of-control as specified in § 63.8(c)(7), or otherwise not operating, the report must contain the information in § 63.7550(e).

As stated in § 63.7565, you must 

comply with the applicable General 

Provisions according to the following: 

TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD 

Citation Subject Applies to subpart DDDDD 

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

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

§ 63.7575 

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

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

§ 63.5 ............................................... Preconstruction Review and Notification Requirements ....................... Yes. 

§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c) ... Compliance with Standards and Maintenance Requirements .............. Yes. 

§ 63.6(e)(1)(i) ................................... General duty to minimize emissions. .................................................... No. See § 63.7500(a)(3) for the 

general duty requirement. 

§ 63.6(e)(1)(ii) .................................. Requirement to correct malfunctions as soon as practicable. .............. No. 

§ 63.6(e)(3) ...................................... Startup, shutdown, and malfunction plan requirements. ....................... No. 

§ 63.6(f)(1) ....................................... Startup, shutdown, and malfunction exemptions for compliance with 

non-opacity emission standards..

No. 

§ 63.6(f)(2) and (3) .......................... Compliance with non-opacity emission standards. ............................... Yes.

§ 63.6(g) .......................................... Use of alternative standards .................................................................. Yes. 

§ 63.6(h)(1) ...................................... Startup, shutdown, and malfunction exemptions to opacity standards. No. See § 63.7500(a). 

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


srobinson on DSKHWCL6B1PROD with RULES5
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15699 

TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD— 

Continued 

Citation Subject Applies to subpart DDDDD 

§ 63.6(i) ............................................ Extension of compliance. ....................................................................... Yes. 

§ 63.6(j) ............................................ Presidential exemption. ......................................................................... Yes. 

§ 63.7(a), (b), (c), and (d) ................ Performance Testing Requirements ...................................................... Yes. 

§ 63.7(e)(1) ...................................... Conditions for conducting performance tests. ....................................... No. Subpart DDDDD specifies 

conditions for conducting performance tests at § 63.7520(a). 

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

§ 63.8(a) and (b) .............................. Applicability and Conduct of Monitoring ................................................ Yes. 

§ 63.8(c)(1) ...................................... Operation and maintenance of CMS ..................................................... Yes. 

§ 63.8(c)(1)(i) ................................... General duty to minimize emissions and CMS operation ..................... No. See § 63.7500(a)(3). 

§ 63.8(c)(1)(ii) .................................. Operation and maintenance of CMS ..................................................... Yes. 

§ 63.8(c)(1)(iii) ................................. Startup, shutdown, and malfunction plans for CMS .............................. No. 

§ 63.8(c)(2) to (c)(9) ........................ Operation and maintenance of CMS ..................................................... Yes. 

§ 63.8(d)(1) and (2) ......................... Monitoring Requirements, Quality Control Program ............................. Yes. 

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

which refers to a startup, shutdown, and malfunction plan. 

Startup, shutdown, and malfunction plans are not required. 

§ 63.8(e) .......................................... Performance evaluation of a CMS ........................................................ Yes. 

§ 63.8(f) ........................................... Use of an alternative monitoring method. ............................................. Yes. 

63.8(g) ............................................. Reduction of monitoring data. ............................................................... Yes. 

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

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

§ 63.10(b)(2)(i) ................................. Recordkeeping of occurrence and duration of startups or shutdowns Yes. 

§ 63.10(b)(2)(ii) ................................ Recordkeeping of malfunctions ............................................................. No. See § 63.7555(d)(7) for recordkeeping of occurrence and 

duration and § 63.7555(d)(8) for 

actions taken during malfunctions. 

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

§ 63.10(b)(2)(iv) and (v) .................. Actions taken to minimize emissions during startup, shutdown, or 

malfunction.

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) and (11) ................... Recording nature and cause of malfunctions, and corrective actions .. No. See § 63.7555(d)(7) for recordkeeping of occurrence and 

duration and § 63.7555(d)(8) for 

actions taken during malfunctions. 

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

§ 63.10(c)(15) .................................. Use of startup, shutdown, and malfunction 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) .................................... Startup, shutdown, and malfunction reports .......................................... No. See § 63.7550(c)(11) for malfunction reporting requirements. 

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

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

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

§ 63.13–63.16 .................................. Addresses, Incorporation by Reference, Availability of Information, 

Performance Track Provisions.

Yes. 

§ 63.1(a)(5),(a)(7)–(a)(9), (b)(2), 

(c)(3)-(4), (d), 63.6(b)(6), (c)(3), 

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

(h)(5)(iv), 63.8(a)(3), 63.9(b)(3), 

(h)(4), 63.10(c)(2)–(4), (c)(9)..

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

TABLE 11 TO SUBPART DDDDD OF PART 63—TOXIC EQUIVALENCY FACTORS FOR DIOXINS/FURANS

Dioxin/furan congener Toxic equivalency 

factor 

2,3,7,8-tetrachlorinated dibenzo-p-dioxin .............................................................................................................................. 1 

1,2,3,7,8-pentachlorinated dibenzo-p-dioxin .......................................................................................................................... 1 

1,2,3,4,7,8-hexachlorinated dibenzo-p-dioxin ........................................................................................................................ 0 .1 

1,2,3,7,8,9-hexachlorinated dibenzo-p-dioxin ........................................................................................................................ 0 .1 

1,2,3,6,7,8-hexachlorinated dibenzo-p-dioxin ........................................................................................................................ 0 .1 


srobinson on DSKHWCL6B1PROD with RULES5
15700 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 11 TO SUBPART DDDDD OF PART 63—TOXIC EQUIVALENCY FACTORS FOR DIOXINS/FURANS—Continued 

Dioxin/furan congener Toxic equivalency 

factor 

1,2,3,4,6,7,8-heptachlorinated dibenzo-p-dioxin .................................................................................................................... 0 .01 

octachlorinated dibenzo-p-dioxin ........................................................................................................................................... 0 .0003 

2,3,7,8-tetrachlorinated dibenzofuran .................................................................................................................................... 0 .1 

2,3,4,7,8-pentachlorinated dibenzofuran ............................................................................................................................... 0 .3 

1,2,3,7,8-pentachlorinated dibenzofuran ............................................................................................................................... 0 .03 

1,2,3,4,7,8-hexachlorinated dibenzofuran ............................................................................................................................. 0 .1 

1,2,3,6,7,8-hexachlorinated dibenzofuran ............................................................................................................................. 0 .1 

1,2,3,7,8,9-hexachlorinated dibenzofuran ............................................................................................................................. 0 .1 

2,3,4,6,7,8-hexachlorinated dibenzofuran ............................................................................................................................. 0 .1 

1,2,3,4,6,7,8-heptachlorinated dibenzofuran ......................................................................................................................... 0 .01 

1,2,3,4,7,8,9-heptachlorinated dibenzofuran ......................................................................................................................... 0 .01 

octachlorinated dibenzofuran ................................................................................................................................................. 0 .0003 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011 

If your boiler or process heater is in this subcategory For the following pollutants 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown 

Using this specified sampling volume or test run 

duration 

1. Units in all subcategories designed to burn solid fuel a. Mercury ......................... 3.5E–06 lb per MMBtu of 

heat input.

For M29, collect a minimum of 2 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

2. Units in all subcategories designed to burn solid fuel 

that combust at least 10 percent biomass/bio-based 

solids on an annual heat input basis and less than 10 

percent coal/solid fossil fuels on an annual heat input 

basis.

a. Particulate Matter .......... 0.008 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.004 lb per MMBtu of 

heat input.

For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

3. Units in all subcategories designed to burn solid fuel 

that combust at least 10 percent coal/solid fossil fuels 

on an annual heat input basis and less than 10 percent biomass/bio-based solids on an annual heat 

input basis.

a. Particulate Matter .......... 0.0011 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 3 

dscm per run. 

b. Hydrogen Chloride ........ 0.0022 lb per MMBtu of 

heat input.

For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

4. Units designed to burn pulverized coal/solid fossil 

fuel.

a. CO ................................. 90 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

5. Stokers designed to burn coal/solid fossil fuel ........... a. CO ................................. 7 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

6. Fluidized bed units designed to burn coal/solid fossil 

fuel.

a. CO ................................. 30 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 


srobinson on DSKHWCL6B1PROD with RULES5
Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 15701 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued 

If your boiler or process heater is in this subcategory For the following pollutants 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown 

Using this specified sampling volume or test run 

duration 

b. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

7. Stokers designed to burn biomass/bio-based solids .. a. CO ................................. 560 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.005 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

8. Fluidized bed units designed to burn biomass/biobased solids.a. CO ................................. 260 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.02 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

9. Suspension burners/Dutch Ovens designed to burn 

biomass/bio-based solids.

a. CO ................................. 1,010 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.2 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

10. Fuel cells designed to burn biomass/bio-based solids.a. CO ................................. 470 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

11. Hybrid suspension/grate units designed to burn biomass/bio-based solids.a. CO ................................. 1,500 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

b. Dioxins/Furans .............. 0.2 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

12. Units designed to burn liquid fuel ............................. a. Particulate Matter .......... 0.002 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 2 

dscm per run. 

b. Hydrogen Chloride ........ 0.0032 lb per MMBtu of 

heat input.

For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury .......................... 3.0E–07 lb per MMBtu of 

heat input.

For M29, collect a minimum of 2 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

d. CO ................................. 3 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling 

time. 

e. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

13. Units designed to burn liquid fuel located in noncontinental States and territories.a. Particulate Matter .......... 0.002 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 2 

dscm per run. 


srobinson on DSKHWCL6B1PROD with RULES5
15702 Federal Register / Vol. 76, No. 54 / Monday, March 21, 2011 / Rules and Regulations 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued 

If your boiler or process heater is in this subcategory For the following pollutants 

The emissions must not 

exceed the following emission limits, except during 

periods of startup and 

shutdown 

Using this specified sampling volume or test run 

duration 

b. Hydrogen Chloride ........ 0.0032 lb per MMBtu of 

heat input.

For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury .......................... 7.8E–07 lb per MMBtu of 

heat input.

For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

d. CO ................................. 51 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

1 hr minimum sampling 

time. 

e. Dioxins/Furans .............. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

14. Units designed to burn gas 2 (other) gases ............. a. Particulate Matter .......... 0.0067 lb per MMBtu of 

heat input (30-day rolling 

average for units 250 

MMBtu/hr or greater, 3- 

run average for units 

less than 250 MMBtu/hr).

Collect a minimum of 1 

dscm per run. 

b. Hydrogen Chloride ........ 0.0017 lb per MMBtu of 

heat input.

For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 60 liters per 

run. 

c. Mercury .......................... 7.9E–06 lb per MMBtu of 

heat input.

For M29, collect a minimum of 1 dscm per run; 

for M30A or M30B, collect a minimum sample 

as specified in the method; for ASTM D6784 a

collect a minimum of 2 

dscm. 

d. CO ................................. 3 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling 

time. 

e. Dioxins/Furans .............. 0.08 ng/dscm (TEQ) corrected to 7 percent oxygen.Collect a minimum of 4 

dscm per run. 

a Incorporated by reference, see § 63.14. 

[FR Doc. 2011–4494 Filed 3–18–11; 8:45 am] 

BILLING CODE 6560–50–P 


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