[Federal Register Volume 76, Number 54 (Monday, March 21, 2011)]
[Rules and Regulations]
[Pages 15608-15702]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-4494]



[[Page 15607]]

Vol. 76

Monday,

No. 54

March 21, 2011

Part V





 Environmental Protection Agency





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40 CFR Part 63



National Emission Standards for Hazardous Air Pollutants for Major 
Sources: Industrial, Commercial, and Institutional Boilers and Process 
Heaters; Final Rule

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

[[Page 15608]]


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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.

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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; E-mail address: 
<a href="/cdn-cgi/l/email-protection#1d6e756f7c7a786f337f6f747c735d786d7c337a726b"><span class="__cf_email__" data-cfemail="0c7f647e6d6b697e226e7e656d624c697c6d226b637a">[email protected]</span></a>.

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:

------------------------------------------------------------------------
                                                         Examples of
          Category               NAICS code \1\          potentially
                                                     regulated entities
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Any industry using a boiler   211.................  Extractors of crude
 or process heater as                                petroleum and
 defined in the final rule.                          natural gas.

[[Page 15609]]

 
                              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-the-floor'' 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.''

[[Page 15610]]

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 non-hazardous 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 (SO<INF>2</INF>), 
and nitrogen oxide (NO<INF>X</INF>) 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.

[[Page 15611]]

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.
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    \1\ See 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.
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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.
----------------------------------------------------------------------------------------------------------------
\1\ All 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.
\2\ The 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.
\3\ The 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.

[[Page 15612]]

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 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 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.
---------------------------------------------------------------------------

    \2\ Heat 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).

                            Table 1--Emission Limits for Boilers and Process Heaters
                                   [Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
                                                                                       Carbon
                                     Particulate      Hydrogen                     monoxide (CO)   Dioxin/furan
           Subcategory              matter  (PM)      chloride      Mercury (Hg)      (ppm @3%      (TEQ) (ng/
                                                        (HCl)                         oxygen)          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/              0.039          0.035        0.0000046           470             0.2
 Suspension Burner...............
Existing--Biomass Fuel Cells.....          0.039          0.035        0.0000046           690             4
Existing--Biomass Suspension/              0.039          0.035        0.0000046         3,500             0.2
 Grate...........................
Existing--Liquid.................          0.0075         0.00033      0.0000035            10             4
Existing--Gas 2 (Other Process             0.043          0.0017       0.000013              9.0           0.08
 Gases)..........................
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/                   0.0011         0.0022       0.0000035           470             0.2
 Suspension Burner...............
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
----------------------------------------------------------------------------------------------------------------


[[Page 15613]]

    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-the-floor 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-by-case 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,

[[Page 15614]]

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 site-
specific 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 tune-
up procedure must include the following:

[[Page 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 cost-effective 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 Sec.  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 Sec.  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

[[Page 15616]]

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

[[Page 15617]]

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 Sec.  
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, solvent-refined coal, coal-oil mixtures, and coal-water 
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 fuel-dependent 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 fuel-dependent 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

[[Page 15618]]

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 (H<INF>2</INF>S) 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.

[[Page 15619]]

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 Sec.  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 Sec.  
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 
Sec.  63.7525(d)(2) to Sec.  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

[[Page 15620]]

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 Sec.  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 ``Sec.  63.11202 and Sec.  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 air-pollution 
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 cross-references 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,

[[Page 15621]]

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-by-pollutant 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-by-pollutant 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 multi-pollutant 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-by-pollutant 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-by-HAP 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 sub-silentio mandating a different result

[[Page 15622]]

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.
---------------------------------------------------------------------------

    \3\ See 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.''
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \4\ Since 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.
---------------------------------------------------------------------------

    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 cost-justified; 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

[[Page 15623]]

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 technology-based 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 non-detects. 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

[[Page 15624]]

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\
---------------------------------------------------------------------------

    \5\ American Society of Mechanical Engineers, Reference Method 
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack 
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------

    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

[[Page 15625]]

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.
---------------------------------------------------------------------------

    \6\ Ibid.
---------------------------------------------------------------------------

    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 laboratory-specific 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 <plus-minus>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 site-specific 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., <plus-minus> 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 <plus-minus> 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 non-instrumental 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

[[Page 15626]]

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 NO<INF>X</INF> 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 NO<INF>X</INF> requirements, EPA does not 
have specific information on the NO<INF>X</INF> limits and 
NO<INF>X</INF> 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 NO<INF>X</INF> at the required level, oxidation catalysts 
can be used to reduce CO without an increase in NO<INF>X</INF>. EPA has 
included costs for these controls for many units in the cost analysis, 
although data on NO<INF>X</INF> requirements were not sufficient to 
allow NO<INF>X</INF> 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

[[Page 15627]]

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 best-controlled 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

[[Page 15628]]

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 fuel-based 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 fuel-based HAP, but recognizing the emission limits 
must be met at all times yet are based on short term stack test data, 
EPA selected the 99 percent confidence level. 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 
non-normal 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

[[Page 15629]]

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-size-fits-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

[[Page 15630]]

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 (intra-unit variability) as well as different tests at 
different units (inter-unit variability) in the floor. Since the floor 
calculations represent the average of the best-performing 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 output-based 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 output-based emissions 
standard for Hg, PM, SO<INF>2</INF>, and NO<INF>X</INF>) 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 NO<INF>X</INF>. This commenter also provided 
examples of output-based emissions regulations in 12 states, including 
4 that regulate non-electricity 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 
steam-generating 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

[[Page 15631]]

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 NO<INF>X</INF> 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 
less-efficient 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 output-based 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 
cost-effective 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

[[Page 15632]]

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 Sec.  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 non-emitting energy using systems at a facility; (2) 
EPA has not quantified the reductions associated with the energy 
assessment requirement, therefore it cannot be ``beyond the floor;'' 
and (3) the bare requirement to perform an audit without being required 
to implement its findings is not a standard under CAA section 112(d).
    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

[[Page 15633]]

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 non-continental 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 load-following (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

[[Page 15634]]

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 tune-up, 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/grate-floor 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

[[Page 15635]]

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 non-continental 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 non-continental 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 non-
continental units: A striking example of fuel system differences for 
non-continental 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 non-continental 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 biomass-fired 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 co-firing 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 
NO<INF>X</INF> 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

[[Page 15636]]

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 
multi-fuel 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 SO<INF>2</INF> 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 
combustion-based 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 combustion-based 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

[[Page 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 tune-ups 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 gas-fired 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 beyond-the-floor option and the complex controls needed to achieve 
such low emission levels would fail the cost-benefit 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.

[[Page 15638]]

    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 gas-fired 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 off-gases 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

[[Page 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 non-
assisted 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 gas-fired 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 H<INF>2</INF>S 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 H<INF>2</INF>S. Sweet natural 
gas, which is considered pipeline quality gas, contains no more than 4 
ppmv H<INF>2</INF>S. 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 
H<INF>2</INF>S 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 non-detect 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-to-energy 
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,

[[Page 15640]]

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 boiler-specific 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 risk-related 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.

[[Page 15641]]

    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 site-specific, 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

[[Page 15642]]

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

[[Page 15643]]

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 ``health-based'' 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 co-benefits of 
non-HAP were considered relevant to the analysis, the nominal co-
benefits of reducing SO<INF>2</INF> 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 
SO<INF>2</INF>, 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

[[Page 15644]]

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.
---------------------------------------------------------------------------

    \7\ EPA notes the support of commenter 2898 in this regard.
---------------------------------------------------------------------------

    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

[[Page 15645]]

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 low-fire 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, steady-state 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 
NO<INF>X</INF> limits. These commenters presented graphs and data to 
demonstrate the inverse relationship between CO and NO<INF>X</INF> 
emissions and noted that changing the boiler operation to reduce CO to 
such low levels would result in an increase in NO<INF>X</INF> 
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 NO<INF>X</INF> 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

[[Page 15646]]

balanced with NO<INF>X</INF> 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 
(NO<INF>X</INF>, carbon dioxide (CO<INF>2</INF>), and HAP).
    Response: In response to the many comments regarding the proposed 
CO emission limits, EPA performed a re-assessment 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 record-keeping, 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

[[Page 15647]]

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 NO<INF>X</INF> 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

[[Page 15648]]

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 
add-on controls conflicting with current controls and each other. For 
instance, one commenter explained small amounts of sulfur trioxide 
(SO<INF>3</INF>) are generated as part of the combustion process for 
sulfur-containing fuels. The commenter noted that a CO oxidation 
catalyst or Selective Catalytic Reduction NO<INF>X</INF> reduction 
catalyst, will convert an additional percentage of the SO<INF>2</INF>to 
SO<INF>3</INF>, which will inhibit Hg removal efficiency of activated 
carbon injection. SO<INF>3</INF> 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 add-on 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 
tune-ups. 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 `worst-case' 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

[[Page 15649]]

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 Sec.  
129 because EPA will have labeled the secondary materials burned as a 
non-waste. Further, they suggested that these non-waste secondary 
materials are not covered under the boiler rules under Sec.  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.

[[Page 15650]]



                                          Table 2--Summary of Emissions Reductions for Existing and New Sources
                                                                        (Tons/Yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                            Non mercury
                  Source                            Subcategory                HCl              PM          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 non-detect 
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.

[[Page 15651]]



                                        Table 3--Summary of Capital and Annual Costs for New and Existing Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Estimated/                        Testing and    Annualized cost
                                                                                         projected     Capital costs      monitoring      (10 \6\ $/yr)
                     Source                                   Subcategory                number of       (10 \6\ $)    annualized costs    (considering
                                                                                      affected units                     (10 \6\ $/yr)    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 PM<INF>2.5</INF> 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 
(PM<INF>2.5</INF>) 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.
---------------------------------------------------------------------------

    \8\ Roman 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 4--Summary of the Monetized Benefits Estimates for the Final Boiler MACT
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                        Emissions       Total monetized
             Pollutant                 reductions       benefits (at 3%        Total monetized benefits (at 7%
                                         (tons)          discount rate)                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.
                                    ----------------------------------------------------------------------------

[[Page 15652]]

 
    Total..........................  ..............  $22,000 to $54,000...  $20,000 to $49,000.
----------------------------------------------------------------------------------------------------------------
\1\ All 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.
------------------------------------------------------------------------
\1\ All 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 PM<INF>2.5</INF> 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 
PM<INF>2.5-</INF> 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\
---------------------------------------------------------------------------

    \9\ U.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.
---------------------------------------------------------------------------

    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 sector-specific 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 benefit-per-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 PM<INF>2.5</INF> and 
PM<INF>2.5</INF> precursors into changes in ambient PM<INF>2.5</INF> 
levels and BenMAP to estimate the changes in human health associated 
with that change in air quality. Finally, the monetized 
PM<INF>2.5</INF> 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 PM<INF>2.5</INF> and SO<INF>2</INF> are the 
dominant PM<INF>2.5</INF> precursors affected by this final rule. Even 
though we assume that all fine particles have equivalent health 
effects, the benefit-per-ton estimates vary between precursors because 
each ton of precursor reduced has a different propensity to form 
PM<INF>2.5</INF>. For example, SO<INF>2</INF> has a lower benefit-per-
ton estimate than direct PM<INF>2.5</INF> because it does not directly 
transform into PM<INF>2.5</INF>, and because sulfate particles formed 
from SO<INF>2</INF> emissions can transport many miles, including over 
areas with low populations. Direct PM<INF>2.5</INF> emissions convert 
directly into ambient PM<INF>2.5</INF>, thus, to the extent that 
emissions occur in population areas, exposures to direct 
PM<INF>2.5</INF> will tend to be higher, and monetized health benefits 
will be higher than for SO<INF>2</INF> 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

[[Page 15653]]

judgments elicited from scientific experts, to characterize the 
uncertainty in the relationship between PM<INF>2.5</INF> 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.
---------------------------------------------------------------------------

    \10\ Pope 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.
    \11\ Laden et al, 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173: 667-672.
---------------------------------------------------------------------------

    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 
PM<INF>2.5</INF> 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 PM<INF>2.5</INF>. 
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 ([mu]g/
m\3\). Using the Laden, et al., (2006) study, 34 percent of the 
population is exposed above the LML of 10 [mu]g/m\3\. It is important 
to emphasize that we have high confidence in PM<INF>2.5</INF>-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 PM<INF>2.5</INF> 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 CO<INF>2</INF> would have disbenefits valued 
at $22 million at a 3 percent discount rate (average). CO<INF>2</INF>-
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 CO<INF>2</INF> 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 PM<INF>2.5</INF> 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 PM<INF>2.5</INF> 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 NO<INF>X</INF>, CO, PM and SO<INF>2</INF> and 
an increase in CO<INF>2</INF> emissions. Since NO<INF>X</INF> and 
SO<INF>2</INF> 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 post-

[[Page 15654]]

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.
----------------------------------------------------------------------------------------------------------------
\1\ All 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.
\2\ The 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.
\3\ The 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.


[[Page 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-for-profit 
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

[[Page 15656]]

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-NO<INF>X</INF> 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 fuel-fired 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
----------------------------------------------------------------------------------------------------------------
                                                                               Total number of   Total number of
                NAICS                            NAICS description               facilities      small entities
----------------------------------------------------------------------------------------------------------------
111.................................  Crop Production.......................                 1                 0
113.................................  Forestry and Logging..................                 1                 0
115.................................  Support Activities for Agriculture and                 1                 0
                                       Forestry.
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                           5                 0
                                       Manufacturing.
313.................................  Textile Mills.........................                14                 1
314.................................  Textile Product Mills.................                 1                 0
316.................................  Leather and Allied Product                             3                 1
                                       Manufacturing.
321.................................  Wood Product Manufacturing............               183                18
322.................................  Paper Manufacturing...................               186                14

[[Page 15657]]

 
323.................................  Printing and Related Support                          33                 5
                                       Activities.
324.................................  Petroleum and Coal Products                           84                 8
                                       Manufacturing.
325.................................  Chemical Manufacturing................               220                17
326.................................  Plastics and Rubber Products                          89                11
                                       Manufacturing.
327.................................  Nonmetallic Mineral Product                           41                 2
                                       Manufacturing.
331.................................  Primary Metal Manufacturing...........                57                 6
332.................................  Fabricated Metal Product Manufacturing                46                 8
333.................................  Machinery Manufacturing...............                13                 0
334.................................  Computer and Electronic Product                        2                 0
                                       Manufacturing.
335.................................  Electrical Equipment, Appliance, and                  12                 0
                                       Component Manufacturing.
336.................................  Transportation Equipment Manufacturing               100                 7
337.................................  Furniture and Related Product                         45                 8
                                       Manufacturing.
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                          8                 0
                                       Technical Services.
561.................................  Administrative and Support Services...                 1                 0
562.................................  Waste Management and Remediation                       7                 2
                                       Services.
611.................................  Educational Services..................                29                 2
622.................................  Hospitals.............................                 4                 0
623.................................  Nursing and Residential Care                           1                 0
                                       Facilities.
811.................................  Repair and Maintenance................                 1                 0
921.................................  Executive, Legislative, and Other                      2                 0
                                       General Government Support.
928.................................  National Security and International                   23                 0
                                       Affairs.
----------------------------------------------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                                     Selected       Alternative
                        Sample statistic                             Proposal         option          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 site-specific 
monitoring plan and a site-specific 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

[[Page 15658]]

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 PM<INF>2.5</INF> and in SO<INF>2</INF> that 
would occur, including 28 thousand tons of PM<INF>2.5</INF> and 443 
thousand tons of SO<INF>2</INF>. 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 PM<INF>2.5</INF> and PM<INF>2.5</INF> 
precursors (such as SO<INF>2</INF>) is a reduction in premature 
mortality. Other health effects associated with PM<INF>2.5</INF> 
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 PM<INF>2.5</INF> and SO<INF>2</INF> 
emissions reductions. For SO<INF>2</INF> and PM<INF>2.5</INF>, 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

[[Page 15659]]

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

[[Page 15660]]

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, CO<INF>2</INF>, 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

[[Page 15661]]

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-of-stack 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[deg] C and 134[deg] 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

[[Page 15662]]

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 Sec.  63.7(f) and Sec.  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, 
NO<INF>X</INF>, PM, and SO<INF>2</INF>. SO<INF>2</INF> and nitrogen 
dioxide are precursors for the formation of PM<INF>2.5</INF> and ozone. 
Reducing these emissions will reduce ozone and PM<INF>2.5</INF> 
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]

0
1. The authority citation for part 63 continues to read as follows:

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


0
2. Section 63.14 is amended by:
0
a. Revising paragraphs (b)(27), (b)(35), (b)(39) through (44), (b)(47) 
through (52), (b)(57), (b)(61), (b)(64), and (i)(1).
0
b. Removing and reserving paragraphs (b)(45), (b)(46), (b)(55), 
(b)(56), (b)(58) through (60), and (b)(62).
0
c. Adding paragraphs (b)(66) through (68).
0
d. Adding paragraphs (p) and (q).


Sec.  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

[[Page 15663]]

Natural Gas Fired Reciprocating Engines, Combustion Turbines, Boilers, 
and Process Heaters Using Portable Analyzers, IBR approved for Sec.  
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 Sec.  63.7575 and Sec.  
63.11237.
    (40) ASTM D396-10 Standard Specification for Fuel Oils, approved 
October 1, 2010, IBR approved for Sec.  63.7575.
    (41) ASTM D1835-05 Standard Specification for Liquefied Petroleum 
(LP) Gases, approved April 1, 2005, IBR approved for Sec.  63.7575 and 
Sec.  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 Sec. Sec.  
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 Sec.  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 Sec.  63.7525(j)(2) and Sec.  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,

[[Page 15664]]

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 Cold-
Vapor 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.

0
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 tune-ups?
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


Sec.  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.


Sec.  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 Sec.  63.7575 that is located at, or is part of, a major 
source of HAP, except as specified in Sec.  63.7491. For purposes of 
this subpart, a major source of HAP is as defined in Sec.  63.2, except 
that for oil and natural gas production facilities, a major source of 
HAP is as defined in Sec.  63.761 (subpart HH of this part, National 
Emission Standards for Hazardous Air Pollutants from Oil and Natural 
Gas Production Facilities).


Sec.  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 Sec.  
63.7575.
    (2) The affected source of this subpart is each new or 
reconstructed industrial, commercial, or institutional boiler or

[[Page 15665]]

process heater, as defined in Sec.  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 Sec.  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.


Sec.  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 Sec.  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).


Sec.  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 Sec.  63.7545 
according to the schedule in Sec.  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 Sec.  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


Sec.  63.7499  What are the subcategories of boilers and process 
heaters?

    The subcategories of boilers and process heaters, as defined in 
Sec.  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.


Sec.  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 Sec.  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 Sec.  
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.

[[Page 15666]]

    (b) As provided in Sec.  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 tune-up as specified in Sec.  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.


Sec.  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 Sec.  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 Sec.  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 
Sec.  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


Sec.  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 Sec.  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 Sec.  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 Sec.  
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

[[Page 15667]]

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 Sec.  63.8(c)(1)(ii), (c)(3), and 
(c)(4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  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


Sec.  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 Sec.  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 Sec.  63.7521 
and Table 6 to this subpart, establishing operating limits according to 
Sec.  63.7530 and Table 7 to this subpart, and conducting CMS 
performance evaluations according to Sec.  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 Sec.  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 Sec.  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 Sec.  63.7521 
and Table 6 to this subpart and establish operating limits according to 
Sec.  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 Sec.  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 Sec.  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 Sec.  63.7495 and according to the applicable provisions 
in Sec.  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 Sec.  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.


Sec.  63.7515  When must I conduct subsequent performance tests, fuel 
analyses, or tune-ups?

    (a) You must conduct all applicable performance tests according to 
Sec.  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 Sec.  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 
Sec.  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

[[Page 15668]]

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 Sec.  63.7540(a)(10) and (a)(11), respectively. Each 
annual tune-up specified in Sec.  63.7540(a)(10) must be no more than 
13 months after the previous tune-up. Each biennial tune-up specified 
in Sec.  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 Sec.  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 Sec.  
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 Sec.  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 
Sec.  63.7530 and Table 7 to this subpart, as applicable. The reports 
for all subsequent performance tests must include all applicable 
information required in Sec.  63.7550.


Sec.  63.7520  What stack tests and procedures must I use?

    (a) You must conduct all performance tests according to Sec.  
63.7(c), (d), (f), and (h). You must also develop a site-specific stack 
test plan according to the requirements in Sec.  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 Sec.  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 F-Factor 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.


Sec.  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 site-specific 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 
cross-section 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.

[[Page 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 one-quarter 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 Sec.  
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 site-specific 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.


Sec.  63.7522  Can I use emissions averaging to comply with this 
subpart?

    (a) As an alternative to meeting the requirements of Sec.  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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.000


[[Page 15670]]


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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.001

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 Sec.  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 Sec.  
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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.002

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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.003

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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.004

Where:


[[Page 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 Sec.  63.7520;
    (v) The operating parameters to be monitored for each control 
system or device consistent with Sec.  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 Sec.  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 
Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.005

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 
Sec.  63.7520 in the common stack. If affected units and non-affected 
units vent to the common stack, the non-affected 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 Sec.  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.


Sec.  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 Sec.  63.7495. The oxygen level shall be 
monitored at the outlet of the boiler or process heater.
    (1) Each CEMS for oxygen (O<INF>2</INF> 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 site-specific monitoring plan developed according to 
Sec.  63.7505(d).
    (2) You must conduct a performance evaluation of each O<INF>2</INF> 
CEMS according

[[Page 15672]]

to the requirements in Sec.  63.8(e) and according to Performance 
Specification 3 at 40 CFR part 60, appendix B.
    (3) Each O<INF>2</INF> CEMS must complete a minimum of one cycle of 
operation (sampling, analyzing, and data recording) for each successive 
15-minute period.
    (4) The O<INF>2</INF> CEMS data must be reduced as specified in 
Sec.  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 Sec.  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 Sec.  
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 Sec.  63.8(e) and according to 
Performance Specification 1 at appendix B to part 60 of this chapter.
    (3) As specified in Sec.  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 Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
COMS according to the requirements in Sec.  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 Sec.  
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 Sec.  
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-of-control 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.

[[Page 15673]]

    (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 
Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  
63.7520, Table 7 to this subpart, and paragraph (b)(3) of this section, 
as applicable. You must also conduct fuel analyses according to Sec.  
63.7521 and establish maximum fuel pollutant input levels according to 
paragraphs (b)(1) and (2) of this section, as applicable. As specified 
in Sec.  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.

[[Page 15674]]

    (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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.006


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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.007


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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.008


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 Sec.  63.7521, in units of pounds 
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel 
samples analyzed according to Sec.  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.

[[Page 15675]]

[GRAPHIC] [TIFF OMITTED] TR21MR11.009


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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.010


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 Sec.  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 Sec.  63.7575, you 
must conduct an initial fuel specification analyses according to Sec.  
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 Sec.  63.7521(f) through (i) and Sec.  63.7540(c) and 
maintain records of the results of the testing as outlined in Sec.  
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.


Sec.  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 
output-based 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

[[Page 15676]]

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:
    [GRAPHIC] [TIFF OMITTED] TR21MR11.011
    

Where:

Credits = Energy Input Savings for all energy conservation measures 
implemented for an affected boiler, million Btu per year.
EIS<INF>iactual</INF> = Energy Input Savings for each energy 
conservation measure implemented for an affected boiler, million Btu 
per year.
EI<INF>baseline</INF> = 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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TR21MR11.012


Where:

E<INF>adj</INF> = Emission level adjusted applying the emission 
credits earned, lb per million Btu steam output for the affected 
boiler.
E<INF>m</INF> = 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


Sec.  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 site-specific monitoring plan required by Sec.  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 Sec.  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 out-of-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.


Sec.  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 
Sec. Sec.  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

[[Page 15677]]

be confirmed or reestablished during performance tests.
    (2) As specified in Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  63.7530. If the 
results of recalculating the maximum chlorine input using Equation 7 of 
Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  63.7530. If the results 
of recalculating the maximum mercury input using Equation 8 of Sec.  
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 Sec.  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 Sec.  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 Sec.  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 
limited-use boilers and process heaters, as defined in Sec.  63.7575.

[[Page 15678]]

    (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 Sec.  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 Sec.  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 Sec.  
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 Sec.  63.7521(f) through (i).


Sec.  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 Sec.  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


Sec.  63.7545  What notifications must I submit and when?

    (a) You must submit to the delegated authority all of the 
notifications in Sec.  63.7(b) and (c), Sec.  63.8(e), (f)(4) and (6), 
and Sec.  63.9(b) through (h) that apply to you by the dates specified.
    (b) As specified in Sec.  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 Sec.  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 Sec.  63.7530(a), you must submit a 
Notification of Compliance Status according to Sec.  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 Sec.  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 Sec.  241.3, whether the fuel(s) were processed from discarded 
non-hazardous secondary materials within the meaning of Sec.  241.3, 
and justification for the selection of fuel(s) burned during the 
compliance demonstration.

[[Page 15679]]

    (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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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 Sec.  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 Sec.  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 semi-annual compliance report.
    (1) The first compliance report must cover the period beginning on 
the compliance date that is specified for your affected source in Sec.  
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 Sec.  
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 Sec.  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 Sec.  70.6(a)(3)(iii)(A) or Sec.  
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

[[Page 15680]]

semiannual (or annual or biennial) reporting period, including, but not 
limited to, a description of the fuel, whether the fuel has received a 
non-waste 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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
63.7530 or the maximum mercury input operating limit using Equation 8 
of Sec.  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 Sec. Sec.  63.7521 and 63.7530 for affected 
sources subject to emission limits, and any fuel specification analyses 
conducted according to Sec.  63.7521(f) and Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 (low-level) and high-level checks.
    (3) The date, time, and duration that each CMS was out of control, 
including the information in Sec.  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.

[[Page 15681]]

    (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 Sec.  70.6(a)(3)(iii)(A) or Sec.  
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 Sec.  70.6(a)(3)(iii)(A) or 
Sec.  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 Sec.  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.


Sec.  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 
Sec.  63.10(b)(2)(xiv).
    (2) Records of performance tests, fuel analyses, or other 
compliance demonstrations and performance evaluations as required in 
Sec.  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 Sec.  63.10(b)(2)(vii) through (xi).
    (2) Monitoring data for continuous opacity monitoring system during 
a performance evaluation as required in Sec.  63.6(h)(7)(i) and (ii).
    (3) Previous (i.e., superseded) versions of the performance 
evaluation plan as required in Sec.  63.8(d)(3).
    (4) Request for alternatives to relative accuracy test for CEMS as 
required in Sec.  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 Sec.  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 Sec.  
241.3(b)(4), you must keep records as to how the operations that 
produced the fuel satisfies the definition of processing in Sec.  
241.2. If the fuel received a non-waste determination pursuant to the 
petition process submitted under Sec.  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 Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  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

[[Page 15682]]

general duty to minimize emissions in Sec.  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 Sec.  
63.7522, you must additionally keep a copy of the emission averaging 
implementation plan required in Sec.  63.7522(g), all calculations 
required under Sec.  63.7522, including monthly records of heat input 
or steam generation, as applicable, and monitoring records consistent 
with Sec.  63.7541.
    (f) If you elect to use emission credits from energy conservation 
measures to demonstrate compliance according to Sec.  63.7533, you must 
keep a copy of the Implementation Plan required in Sec.  63.7533(d) and 
copies of all data and calculations used to establish credits according 
to Sec.  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 Sec.  
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.


Sec.  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 Sec.  63.10(b)(1).
    (b) As specified in Sec.  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 Sec.  63.10(b)(1). 
You can keep the records off site for the remaining 3 years.

Other Requirements and Information


Sec.  63.7565  What parts of the General Provisions apply to me?

    Table 10 to this subpart shows which parts of the General 
Provisions in Sec. Sec.  63.1 through 63.15 apply to you.


Sec.  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 Sec.  63.7500(a) and (b) under Sec.  
63.6(g).
    (2) Approval of alternative opacity emission limits in Sec.  
63.7500(a) under Sec.  63.6(h)(9).
    (3) Approval of major change to test methods in Table 5 to this 
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.  
63.90, and alternative analytical methods requested under Sec.  
63.7521(b)(2).
    (4) Approval of major change to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90, and approval of alternative operating 
parameters under Sec.  63.7500(a)(2) and Sec.  63.7522(g)(2).
    (5) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(e) and as defined in Sec.  63.90.


Sec.  63.7575  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act, in 
Sec.  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 
Sec.  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, 
sub-

[[Page 15683]]

bituminous, or lignite by ASTM D388 (incorporated by reference, see 
Sec.  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 Sec.  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 one-third of 
its potential electric output capacity and more than 25 megawatts 
electrical output to any utility power distribution system for sale is 
considered an electric utility steam generating unit.
    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 air-conditioning 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

[[Page 15684]]

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, sub-bituminous 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, on-spec 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 Sec.  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

[[Page 15685]]

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 C<INF>3</INF>H<INF>8</INF>.
    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 
Sec.  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 Sec.  
63.14(b)).
    Responsible official means responsible official as defined in Sec.  
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

[[Page 15686]]

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/bio-based 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 Voie-Creuse, Case postale 56, CH-1211 
Geneva 20, Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm), Standards Australia (AS Level 10, The Exchange Centre, 20 
Bridge Street, Sydney, GPO Box 476, Sydney NSW 2001, + 61 2 9237 6171 
http://www.stadards.org.au), British Standards Institution (BSI, 389 
Chiswick High Road, London, W4 4AL, United Kingdom, +44 (0)20 8996 
9001, http://www.bsigroup.com), Canadian Standards Association (CSA 
5060 Spectrum Way, Suite 100, Mississauga, Ontario L4W 5N6, Canada, 
800-463-6727, http://www.csa.ca), European Committee for 
Standardization (CEN CENELEC Management Centre Avenue Marnix 17 B-1000 
Brussels, Belgium +32 2 550 08 11, http://www.cen.eu/cen), and German 
Engineering Standards (VDI 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 Sec.  63.7500, you must comply with the following 
applicable emission limits:

[[Page 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]
----------------------------------------------------------------------------------------------------------------
                                                      The emissions must   Or the emissions
                                                        not exceed the      must not exceed
If your boiler or process heater                      following emission     the following        Using this
  is in this subcategory . . .     For the following    limits, except       output-based     specified sampling
                                   pollutants . . .    during periods of    limits  (lb per   volume or test run
                                                          startup and       MMBtu of steam      duration . . .
                                                        shutdown . . .       output) . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. Particulate      0.0011 lb per       0.0011; (30-day     Collect a minimum
 designed to burn solid fuel.      Matter.             MMBtu of heat       rolling average     of 3 dscm per
                                                       input (30-day       for units 250       run.
                                                       rolling average     MMBtu/hr or
                                                       for units 250       greater, 3-run
                                                       MMBtu/hr or         average for units
                                                       greater, 3-run      less than 250
                                                       average for units   MMBtu/hr).
                                                       less than 250
                                                       MMBtu/hr).
                                  b. Hydrogen         0.0022 lb per       0.0021............  For M26A, collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26 collect a
                                                                                               minimum of 60
                                                                                               liters per run.
                                  c. Mercury........  3.5E-06 lb per      3.4E-06...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 1 dscm
                                                       input.                                  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         a. Carbon monoxide  12 ppm by volume    0.01..............  1 hr minimum
 pulverized coal/solid fossil      (CO).               on a dry basis                          sampling time,
 fuel.                                                 corrected to 3                          use a span value
                                                       percent oxygen.                         of 30 ppmv.
                                  b. Dioxins/Furans.  0.003 ng/dscm       2.8E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
3. Stokers designed to burn coal/ a. CO.............  6 ppm by volume on  0.005.............  1 hr minimum
 solid fossil fuel.                                    a dry basis                             sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 20 ppmv.
                                  b. Dioxins/Furans.  0.003 ng/dscm       2.8E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
4. Fluidized bed units designed   a. CO.............  18 ppm by volume    0.02..............  1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 40 ppmv.
                                  b. Dioxins/Furans.  0.002 ng/dscm       1.8E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
5. Stokers designed to burn       a. CO.............  160 ppm by volume   0.13..............  1 hr minimum
 biomass/bio-based solids.                             on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 400 ppmv.
                                  b. Dioxins/Furans.  0.005 ng/dscm       4.4E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
6. Fluidized bed units designed   a. CO.............  260 ppm by volume   0.18..............  1 hr minimum
 to burn biomass/bio-based                             on a dry basis                          sampling time,
 solids.                                               corrected to 3                          use a span value
                                                       percent oxygen.                         of 500 ppmv.
                                  b. Dioxins/Furans.  0.02 ng/dscm (TEQ)  1.8E-11 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
7. Suspension burners/Dutch       a. CO.............  470 ppm by volume   0.45..............  1 hr minimum
 Ovens designed to burn biomass/                       on a dry basis                          sampling time,
 bio-based solids.                                     corrected to 3                          use a span value
                                                       percent oxygen.                         of 1000 ppmv.
                                  b. Dioxins/Furans.  0.2 ng/dscm (TEQ)   1.8E-10 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
8. Fuel cells designed to burn    a. CO.............  470 ppm by volume   0.23..............  1 hr minimum
 biomass/bio-based solids.                             on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 1000 ppmv.
                                  b. Dioxins/Furans.  0.003 ng/dscm       2.86E-12 (TEQ)....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
9. Hybrid suspension/grate units  a. CO.............  1,500 ppm by        0.84..............  1 hr minimum
 designed to burn biomass/bio-                         volume on a dry                         sampling time,
 based solids.                                         basis corrected                         use a span value
                                                       to 3 percent                            of 3000 ppmv.
                                                       oxygen.

[[Page 15688]]

 
                                  b. Dioxins/Furans.  0.2 ng/dscm (TEQ)   1.8E-10 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
10. Units designed to burn        a. Particulate      0.0013 lb per       0.001; (30-day      Collect a minimum
 liquid fuel.                      Matter.             MMBtu of heat       rolling average     of 3 dscm per
                                                       input (30-day       for residual oil-   run.
                                                       rolling average     fired units 250
                                                       for residual oil-   MMBtu/hr or
                                                       fired units 250     greater, 3-run
                                                       MMBtu/hr or         average for other
                                                       greater, 3-run      units).
                                                       average for other
                                                       units).
                                  b. Hydrogen         0.00033 lb per      0.0003............  For M26A: Collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 60
                                                                                               liters per run.
                                  c. Mercury........  2.1E-07 lb per      0.2E-06...........  Collect enough
                                                       MMBtu of heat                           volume to meet an
                                                       input.                                  in-stack
                                                                                               detection limit
                                                                                               data quality
                                                                                               objective of 0.10
                                                                                               ug/dscm.
                                  d. CO.............  3 ppm by volume on  0.0026............  1 hr minimum
                                                       a dry basis                             sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 3 ppmv.
                                  e. Dioxins/Furans.  0.002 ng/dscm       4.6E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
11. Units designed to burn        a. Particulate      0.0013 lb per       0.001; (30-day      Collect a minimum
 liquid fuel located in non-       Matter.             MMBtu of heat       rolling average     of 3 dscm per
 continental States and                                input (30-day       for residual oil-   run.
 territories.                                          rolling average     fired units 250
                                                       for residual oil-   MMBtu/hr or
                                                       fired units 250     greater, 3-run
                                                       MMBtu/hr or         average for other
                                                       greater, 3-run      units).
                                                       average for other
                                                       units).
                                  b. Hydrogen         0.00033 lb per      0.0003............  For M26A: Collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 60
                                                                                               liters per run.
                                  c. Mercury........  7.8E-07 lb per      8.0E-07...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 3 dscm
                                                       input.                                  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    0.043.............  1 hr minimum
                                                       on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 100 ppmv.
                                  e. Dioxins/Furans.  0.002 ng/dscm       4.6E-12(TEQ)......  Collect a minimum
                                                       (TEQ) corrected                         of 3 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
12. Units designed to burn gas 2  a. Particulate      0.0067 lb per       .004; (30-day       Collect a minimum
 (other) gases.                    Matter.             MMBtu of heat       rolling average     of 1 dscm per
                                                       input (30-day       for units 250       run.
                                                       rolling average     MMBtu/hr or
                                                       for units 250       greater, 3-run
                                                       MMBtu/hr or         average for units
                                                       greater, 3-run      less than 250
                                                       average for units   MMBtu/hr).
                                                       less than 250
                                                       MMBtu/hr).
                                  b. Hydrogen         0.0017 lb per       .003..............  For M26A, Collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 60
                                                                                               liters per run.

[[Page 15689]]

 
                                  c. Mercury........  7.9E-06 lb per      2.0E-07...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 1 dscm
                                                       input.                                  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  0.002.............  1 hr minimum
                                                       a dry basis                             sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 10 ppmv.
                                  e. Dioxins/Furans.  0.08 ng/dscm (TEQ)  4.1E-12 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per run
                                                       percent oxygen.
----------------------------------------------------------------------------------------------------------------
\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 Sec.   63.14.

    As stated in Sec.  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]
----------------------------------------------------------------------------------------------------------------
                                                      The emissions must  The emissions must
                                                        not exceed the      not exceed the
If your boiler or process heater                      following emission   following output-      Using this
  is in this subcategory . . .     For the following    limits, except     based limits (lb   specified sampling
                                   pollutants . . .    during periods of  per MMBtu of steam  volume or test run
                                                          startup and        output) . . .      duration . . .
                                                        shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. Particulate      0.039 lb per MMBtu  0.038; (30-day      Collect a minimum
 designed to burn solid fuel.      Matter.             of heat input (30-  rolling average     of 1 dscm per
                                                       day rolling         for units 250       run.
                                                       average for units   MMBtu/hr or
                                                       250 MMBtu/hr or     greater, 3-run
                                                       greater, 3-run      average for units
                                                       average for units   less than 250
                                                       less than 250       MMBtu/hr).
                                                       MMBtu/hr).
                                  b. Hydrogen         0.035 lb per MMBtu  0.04..............  For M26A, collect
                                   Chloride.           of heat input.                          a minimum of 1
                                                                                               dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 60
                                                                                               liters per run.
                                  c. Mercury........  4.6E-06 lb per      4.5E-06...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 1 dscm
                                                       input.                                  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          a. CO.............  160 ppm by volume   0.14..............  1 hr minimum
 designed to burn pulverized                           on a dry basis                          sampling time,
 coal/solid fossil fuel.                               corrected to 3                          use a span value
                                                       percent oxygen.                         of 300 ppmv.
                                  b. Dioxins/Furans.  0.004 ng/dscm       3.7E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
3. Stokers designed to burn coal/ a. CO.............  270 ppm by volume   0.25..............  1 hr minimum
 solid fossil fuel.                                    on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 500 ppmv.
                                  b. Dioxins/Furans.  0.003 ng/dscm       2.8E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.

[[Page 15690]]

 
4. Fluidized bed units designed   a. CO.............  82 ppm by volume    0.08..............  1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 200 ppmv
                                  b. Dioxins/Furans.  0.002 ng/dscm       1.8E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
5. Stokers designed to burn       a. CO.............  490 ppm by volume   0.35..............  1 hr minimum
 biomass/bio-based solid.                              on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 1000 ppmv.
                                  b. Dioxins/Furans.  0.005 ng/dscm       4.4E-12 (TEQ).....  Collect a minimum
                                                       (TEQ) corrected                         of 4 dscm per
                                                       to 7 percent                            run.
                                                       oxygen.
6. Fluidized bed units designed   a. CO.............  430 ppm by volume   0.28..............  1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 850 ppmv.
                                  b. Dioxins/Furans.  0.02 ng/dscm (TEQ)  1.8E-11(TEQ)......  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
7. Suspension burners/Dutch       a. CO.............  470 ppm by volume   0.45..............  1 hr minimum
 Ovens designed to burn biomass/                       on a dry basis                          sampling time,
 bio-based solid.                                      corrected to 3                          use a span value
                                                       percent oxygen.                         of 1000 ppmv.
                                  b. Dioxins/Furans.  0.2 ng/dscm (TEQ)   1.8E-10 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
8. Fuel cells designed to burn    a. CO.............  690 ppm by volume   0.34..............  1 hr minimum
 biomass/bio-based solid.                              on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 1300 ppmv.
                                  b. Dioxins/Furans.  4 ng/dscm (TEQ)     3.5E-09 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
9. Hybrid suspension/grate units  a. CO.............  3,500 ppm by        2.0...............  1 hr minimum
 designed to burn biomass/bio-                         volume on a dry                         sampling time,
 based solid.                                          basis corrected                         use a span value
                                                       to 3 percent                            of 7000 ppmv.
                                                       oxygen.
                                  b. Dioxins/Furans.  0.2 ng/dscm (TEQ)   1.8E-10 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
10. Units designed to burn        a. Particulate      0.0075 lb per       0.0073; (30-day     Collect a minimum
 liquid fuel.                      Matter.             MMBtu of heat       rolling average     of 1 dscm per
                                                       input (30-day       for residual oil-   run.
                                                       rolling average     fired units 250
                                                       for residual oil-   MMBtu/hr or
                                                       fired units 250     greater, 3-run
                                                       MMBtu/hr or         average for other
                                                       greater, 3-run      units).
                                                       average for other
                                                       units).
                                  b. Hydrogen         0.00033 lb per      0.0003............  For M26A, collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 200
                                                                                               liters per run.
                                  c. Mercury........  3.5E-06 lb per      3.3E-06...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 1 dscm
                                                       input.                                  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    0.0083............  1 hr minimum
                                                       on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 20 ppmv.
                                  e. Dioxins/Furans.  4 ng/dscm (TEQ)     9.2E-09 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 1 dscm per
                                                       percent oxygen.                         run.

[[Page 15691]]

 
11. Units designed to burn        a. Particulate      0.0075 lb per       0.0073; (30-day     Collect a minimum
 liquid fuel located in non-       Matter.             MMBtu of heat       rolling average     of 1 dscm per
 continental States and                                input (30-day       for residual oil-   run.
 territories.                                          rolling average     fired units 250
                                                       for residual oil-   MMBtu/hr or
                                                       fired units 250     greater, 3-run
                                                       MMBtu/hr or         average for other
                                                       greater, 3-run      units).
                                                       average for other
                                                       units).
                                  b. Hydrogen         0.00033 lb per      0.0003............  For M26A, collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 200
                                                                                               liters per run.
                                  c. Mercury........  7.8E-07 lb per      8.0E-07...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 1 dscm
                                                       input.                                  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   0.13..............  1 hr minimum
                                                       on a dry basis                          sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 300 ppmv.
                                  e. Dioxins/Furans.  4 ng/dscm (TEQ)     9.2E-09 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 1 dscm per
                                                       percent oxygen.                         run.
12. Units designed to burn gas 2  a. Particulate      0.043 lb per MMBtu  0.026; (30-day      Collect a minimum
 (other) gases.                    Matter.             of heat input (30-  rolling average     of 1 dscm per
                                                       day rolling         for units 250       run.
                                                       average for units   MMBtu/hr or
                                                       250 MMBtu/hr or     greater, 3-run
                                                       greater, 3-run      average for units
                                                       average for units   less than 250
                                                       less than 250       MMBtu/hr).
                                                       MMBtu/hr).
                                  b. Hydrogen         0.0017 lb per       0.001.............  For M26A, collect
                                   Chloride.           MMBtu of heat                           a minimum of 1
                                                       input.                                  dscm per run; for
                                                                                               M26, collect a
                                                                                               minimum of 60
                                                                                               liters per run.
                                  c. Mercury........  1.3E-05 lb per      7.8E-06...........  For M29, collect a
                                                       MMBtu of heat                           minimum of 1 dscm
                                                       input.                                  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  0.005.............  1 hr minimum
                                                       a dry basis                             sampling time,
                                                       corrected to 3                          use a span value
                                                       percent oxygen.                         of 20 ppmv.
                                  e. Dioxins/Furans.  0.08 ng/dscm (TEQ)  3.9E-11 (TEQ).....  Collect a minimum
                                                       corrected to 7                          of 4 dscm per
                                                       percent oxygen.                         run.
----------------------------------------------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.

    As stated in Sec.  63.7500, you must comply with the following 
applicable work practice standards:

      Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
                                         You must meet the following . .
         If your unit is . . .                          .
------------------------------------------------------------------------
1. A new or existing boiler or process   Conduct a tune-up of the boiler
 heater with heat input capacity of       or process heater biennially
 less than 10 million Btu per hour or a   as specified in Sec.
 limited use boiler or process heater.    63.7540.

[[Page 15692]]

 
2. A new or existing boiler or process   Conduct a tune-up of the boiler
 heater in either the Gas 1 or Metal      or process heater annually as
 Process Furnace subcategory with heat    specified in Sec.   63.7540.
 input capacity of 10 million Btu per
 hour or greater.
3. An existing boiler or process heater  Must have a one-time energy
 located at a major source facility.      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    Minimize the unit's startup and
 emission limits in Tables 1, 2, or 12    shutdown periods following the
 of this subpart..                        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 Sec.  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 Sec.
                                          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 Sec.   63.7530(b)
                                          and Table 7 to this subpart.
3. Fabric filter control on units not    a. Maintain opacity to less
 required to install and operate a PM     than or equal to 10 percent
 CEMS.                                    opacity (daily block average);
                                          or
                                         b. Install and operate a bag
                                          leak detection system
                                          according to Sec.   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    a. This option is for boilers
 on units not required to install and     and process heaters that
 operate a PM CEMS.                       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 Sec.   63.7530(b)
                                          and Table 7 to this subpart.
5. Dry scrubber or carbon injection      Maintain the minimum sorbent or
 control.                                 carbon injection rate as
                                          defined in Sec.   63.7575 of
                                          this subpart.

[[Page 15693]]

 
6. Any other add-on air pollution        This option is for boilers and
 control type on units not required to    process heaters that operate
 install and operate a PM CEMS.           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 Sec.
                                          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 Sec.
                                          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 Sec.  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          Method 1 at 40
                                      sampling ports     CFR part 60,
                                      location and the   appendix A-1 of
                                      number of          this chapter.
                                      traverse points.  Method 2, 2F, or
                                     b. Determine        2G at 40 CFR
                                      velocity and       part 60,
                                      volumetric flow-   appendix A-1 or
                                      rate of the        A-2 to part 60
                                      stack gas..        of this
                                                         chapter.
                                     c. Determine       Method 3A or 3B
                                      oxygen or carbon   at 40 CFR part
                                      dioxide            60, appendix A-
                                      concentration of   2 to part 60 of
                                      the stack gas.     this chapter,
                                                         or ANSI/ASME
                                                         PTC 19.10-
                                                         1981.\a\
                                     d. Measure the     Method 4 at 40
                                      moisture content   CFR part 60,
                                      of the stack gas.  appendix A-3 of
                                                         this chapter.
                                     e. Measure the     Method 5 or 17
                                      particulate        (positive
                                      matter emission    pressure fabric
                                      concentration.     filters must
                                                         use Method 5D)
                                                         at 40 CFR part
                                                         60, appendix A-
                                                         3 or A-6 of
                                                         this chapter.
                                     f. Convert         Method 19 F-
                                      emissions          factor
                                      concentration to   methodology at
                                      lb per MMBtu       40 CFR part 60,
                                      emission rates.    appendix A-7 of
                                                         this chapter.
2. Hydrogen chloride...............  a. Select          Method 1 at 40
                                      sampling ports     CFR part 60,
                                      location and the   appendix A-1 of
                                      number of          this chapter.
                                      traverse points.
                                     b. Determine       Method 2, 2F, or
                                      velocity and       2G at 40 CFR
                                      volumetric flow-   part 60,
                                      rate of the        appendix A-2 of
                                      stack gas.         this chapter.
                                     c. Determine       Method 3A or 3B
                                      oxygen or carbon   at 40 CFR part
                                      dioxide            60, appendix A-
                                      concentration of   2 of this
                                      the stack gas.     chapter, or
                                                         ANSI/ASME PTC
                                                         19.10-1981.\a\
                                     d. Measure the     Method 4 at 40
                                      moisture content   CFR part 60,
                                      of the stack gas.  appendix A-3 of
                                                         this chapter.
                                     e. Measure the     Method 26 or 26A
                                      hydrogen           (M26 or M26A)
                                      chloride           at 40 CFR part
                                      emission           60, appendix A-
                                      concentration.     8 of this
                                                         chapter.
                                     f. Convert         Method 19 F-
                                      emissions          factor
                                      concentration to   methodology at
                                      lb per MMBtu       40 CFR part 60,
                                      emission rates.    appendix A-7 of
                                                         this chapter.
3. Mercury.........................  a. Select          Method 1 at 40
                                      sampling ports     CFR part 60,
                                      location and the   appendix A-1 of
                                      number of          this chapter.
                                      traverse points.
                                     b. Determine       Method 2, 2F, or
                                      velocity and       2G at 40 CFR
                                      volumetric flow-   part 60,
                                      rate of the        appendix A-1 or
                                      stack gas.         A-2 of this
                                                         chapter.
                                     c. Determine       Method 3A or 3B
                                      oxygen or carbon   at 40 CFR part
                                      dioxide            60, appendix A-
                                      concentration of   1 of this
                                      the stack gas.     chapter, or
                                                         ANSI/ASME PTC
                                                         19.10-1981.\a\
                                     d. Measure the     Method 4 at 40
                                      moisture content   CFR part 60,
                                      of the stack gas.  appendix A-3 of
                                                         this chapter.
                                     e. Measure the     Method 29, 30A,
                                      mercury emission   or 30B (M29,
                                      concentration.     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         Method 19 F-
                                      emissions          factor
                                      concentration to   methodology at
                                      lb per MMBtu       40 CFR part 60,
                                      emission rates.    appendix A-7 of
                                                         this chapter.
4. CO..............................  a. Select the      Method 1 at 40
                                      sampling ports     CFR part 60,
                                      location and the   appendix A-1 of
                                      number of          this chapter.
                                      traverse points.

[[Page 15694]]

 
                                     b. Determine       Method 3A or 3B
                                      oxygen             at 40 CFR part
                                      concentration of   60, appendix A-
                                      the stack gas.     3 of this
                                                         chapter, or
                                                         ASTM D6522-00
                                                         (Reapproved
                                                         2005), or ANSI/
                                                         ASME PTC 19.10-
                                                         1981.\a\
                                     c. Measure the     Method 4 at 40
                                      moisture content   CFR part 60,
                                      of the stack gas.  appendix A-3 of
                                                         this chapter.
                                     d. Measure the CO  Method 10 at 40
                                      emission           CFR part 60,
                                      concentration.     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      Method 1 at 40
                                      sampling ports     CFR part 60,
                                      location and the   appendix A-1 of
                                      number of          this chapter.
                                      traverse points.
                                     b. Determine       Method 3A or 3B
                                      oxygen             at 40 CFR part
                                      concentration of   60, appendix A-
                                      the stack gas.     3 of this
                                                         chapter, or
                                                         ASTM D6522-00
                                                         (Reapproved
                                                         2005),\a\ or
                                                         ANSI/ASME PTC
                                                         19.10-1981.\a\
                                     c. Measure the     Method 4 at 40
                                      moisture content   CFR part 60,
                                      of the stack gas.  appendix A-3 of
                                                         this chapter.
                                     d. Measure the     Method 23 at 40
                                      dioxins/furans     CFR part 60,
                                      emission           appendix A-7 of
                                      concentration.     this chapter.
                                     e. Multiply the    Table 11 of this
                                      measured dioxins/  subpart.
                                      furans emission
                                      concentration by
                                      the appropriate
                                      toxic
                                      equivalency
                                      factor.
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.

    As stated in Sec.  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 Sec.  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       Procedure in Sec.
                               samples.              63.7521(c) or ASTM
                                                     D2234/D2234M \a\
                                                     (for coal) or ASTM
                                                     D6323 \a\ (for
                                                     biomass), or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            EPA SW-846-3050B \a\
                               composited fuel       (for solid
                               samples.              samples), EPA SW-
                                                     846-3020A \a\ (for
                                                     liquid samples),
                                                     ASTM D2013/D2013M
                                                     \a\ (for coal),
                                                     ASTM D5198 \a\ (for
                                                     biomass), or
                                                     equivalent.
                              d. Determine heat     ASTM D5865 \a\ (for
                               content of the fuel   coal) or ASTM E711
                               type.                 \a\ (for biomass),
                                                     or equivalent.
                              e. Determine          ASTM D3173 \a\ or
                               moisture content of   ASTM E871,\a\ or
                               the fuel type.        equivalent.
                              f. Measure mercury    ASTM D6722 \a\ (for
                               concentration in      coal), EPA SW-846-
                               fuel sample.          7471B \a\ (for
                                                     solid samples), or
                                                     EPA SW-846-7470A
                                                     \a\ (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       Procedure in Sec.
                               samples.              63.7521(c) or ASTM
                                                     D2234/D2234M \a\
                                                     (for coal) or ASTM
                                                     D6323 \a\ (for
                                                     biomass), or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            EPA SW-846-3050B \a\
                               composited fuel       (for solid
                               samples.              samples), EPA SW-
                                                     846-3020A \a\ (for
                                                     liquid samples),
                                                     ASTM D2013/D2013M
                                                     \a\ (for coal), or
                                                     ASTM D5198 \a\ (for
                                                     biomass), or
                                                     equivalent.
                              d. Determine heat     ASTM D5865 \a\ (for
                               content of the fuel   coal) or ASTM E711
                               type.                 \a\ (for biomass),
                                                     or equivalent.
                              e. Determine          ASTM D3173 \a\ or
                               moisture content of   ASTM E871,\a\ or
                               the fuel type.        equivalent.
                              f. Measure chlorine   EPA SW-846-9250,\a\
                               concentration in      ASTM D6721 \a\ (for
                               fuel sample.          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               a. Measure mercury    ASTM D5954,\a\
 Specification for other gas   concentration in     ASTM D6350,\a\ ISO
 1 fuels.                      the fuel sample.      6978-1:2003(E),\a\
                              b. Convert             or ISO 6978-
                               concentration to      2:2003(E) \a\, or
                               unit of micrograms/   equivalent.
                               cubic meter.

[[Page 15695]]

 
4. Hydrogen Sulfide Fuel      a. Measure total      ASTM D4084a or
 Specification for other gas   hydrogen sulfide.     equivalent.
 1 fuels.                     b. Convert to ppm...
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.

    As stated in Sec.  63.7520, you must comply with the following 
requirements for establishing operating limits:

                       Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
                                  And your operating                                           According to the
    If you have an applicable      limits are based     You must . . .        Using . . .          following
    emission limit for . . .           on . . .                                                  requirements
----------------------------------------------------------------------------------------------------------------
1. Particulate matter or mercury  a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       pressure drop and   collect pressure
                                   parameters.         minimum pressure    liquid flow rate    drop and liquid
                                                       drop and minimum    monitors and the    flow rate data
                                                       flow rate           particulate         every 15 minutes
                                                       operating limit     matter or mercury   during the entire
                                                       according to Sec.   performance test.   period of the
                                                         63.7530(b).                           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    i. Establish a      (1) Data from the   (a) You must
                                   precipitator        site-specific       voltage and         collect secondary
                                   operating           minimum total       secondary           voltage and
                                   parameters          secondary           amperage monitors   secondary
                                   (option only for    electric power      during the          amperage for each
                                   units that          input according     particulate         ESP cell and
                                   operate wet         to Sec.             matter or mercury   calculate total
                                   scrubbers).         63.7530(b).         performance test.   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     i. Establish site-  (1) Data from the   (a) You must
                                   operating           specific minimum    pressure drop,      collect pH and
                                   parameters.         pressure drop,      pH, and liquid      liquid flow-rate
                                                       effluent pH, and    flow-rate           data every 15
                                                       flow rate           monitors and the    minutes during
                                                       operating limits    hydrogen chloride   the entire period
                                                       according to Sec.   performance test.   of the
                                                         63.7530(b).                           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.

[[Page 15696]]

 
                                  b. Dry scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       sorbent injection   collect sorbent
                                   parameters.         minimum sorbent     rate monitors and   injection rate
                                                       injection rate      hydrogen chloride   data every 15
                                                       operating limit     or mercury          minutes during
                                                       according to Sec.   performance test.   the entire period
                                                         63.7530(b). If                        of the
                                                       different acid                          performance
                                                       gas sorbents are                        tests;
                                                       used during the                        (b) Determine the
                                                       hydrogen chloride                       hourly average
                                                       performance test,                       sorbent injection
                                                       the average value                       rate by computing
                                                       for each sorbent                        the hourly
                                                       becomes the site-                       averages using
                                                       specific                                all of the 15-
                                                       operating limit                         minute readings
                                                       for that sorbent.                       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        i. Establish a      (1) Data from the   (a) You must
                                   carbon injection.   site-specific       activated carbon    collect activated
                                                       minimum activated   rate monitors and   carbon injection
                                                       carbon injection    mercury and         rate data every
                                                       rate operating      dioxins/furans      15 minutes during
                                                       limit according     performance tests.  the entire period
                                                       to Sec.                                 of the
                                                       63.7530(b).                             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      (1) Data from the   (a) You must
                                                       unit-specific       oxygen monitor      collect oxygen
                                                       limit for minimum   specified in Sec.   data every 15
                                                       oxygen level          63.7525(a).       minutes during
                                                       according to Sec.                       the entire period
                                                         63.7520.                              of the
                                                                                               performance
                                                                                               tests;

[[Page 15697]]

 
                                                                                              (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        a. Boiler or        i. Establish a      (1) Data from the   (a) You must
 compliance is demonstrated by a   process heater      unit specific       operating load      collect operating
 performance test.                 operating load.     limit for maximum   monitors or from    load or steam
                                                       operating load      steam generation    generation data
                                                       according to Sec.   monitors.           every 15 minutes
                                                         63.7520(c).                           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 Sec.  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       You must demonstrate continuous
work practice standards . . .             compliance by . . .
------------------------------------------------------------------------
1. Opacity...................  a. Collecting the opacity monitoring
                                system data according to Sec.
                                63.7525(c) and Sec.   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      Installing and operating a bag leak
 Detection Operation.           detection system according to Sec.
                                63.7525 and operating the fabric filter
                                such that the requirements in Sec.
                                63.7540(a)(9) are met.
3. Wet Scrubber Pressure Drop  a. Collecting the pressure drop and
 and Liquid Flow-rate.          liquid flow rate monitoring system data
                                according to Sec.  Sec.   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
                                Sec.   63.7530(b).
4. Wet Scrubber pH...........  a. Collecting the pH monitoring system
                                data according to Sec.  Sec.   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
                                Sec.   63.7530(b).
5. Dry Scrubber Sorbent or     a. Collecting the sorbent or carbon
 Carbon Injection Rate.         injection rate monitoring system data
                                for the dry scrubber according to Sec.
                                Sec.   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 Sec.
                                63.7575.
6. Electrostatic Precipitator  a. Collecting the total secondary
 Total Secondary Electric       electric power input monitoring system
 Power Input.                   data for the electrostatic precipitator
                                according to Sec.  Sec.   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
                                Sec.   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 Sec.   63.7530(b) or (c) as
                                applicable; and
                               b. Keeping monthly records of fuel use
                                according to Sec.   63.7540(a).

[[Page 15698]]

 
8. Oxygen content............  a. Continuously monitor the oxygen
                                content in the combustion exhaust
                                according to Sec.   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    a. Collecting operating load data or
 operating load.                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 Sec.   63.7520(c).
------------------------------------------------------------------------

    As stated in Sec.  63.7550, you must comply with the following 
requirements for reports:

                           Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
----------------------------------------------------------------------------------------------------------------
                                                                                      You must submit the report
          You must submit a(n)                   The report must contain . . .                   . . .
----------------------------------------------------------------------------------------------------------------
1. Compliance report....................  a. Information required in Sec.             Semiannually, annually, or
                                           63.7550(c)(1) through (12); and.            biennially according to
                                                                                       the requirements in Sec.
                                                                                        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-of-control as specified in Sec.
                                            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 Sec.   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 Sec.
                                           63.8(c)(7), or otherwise not operating,
                                           the report must contain the information
                                           in Sec.   63.7550(e).
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  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
------------------------------------------------------------------------
                                                           Applies to
           Citation                     Subject           subpart DDDDD
------------------------------------------------------------------------
Sec.   63.1...................  Applicability.........  Yes.
Sec.   63.2...................  Definitions...........  Yes. Additional
                                                         terms defined
                                                         in Sec.
                                                         63.7575
Sec.   63.3...................  Units and               Yes.
                                 Abbreviations.
Sec.   63.4...................  Prohibited Activities   Yes.
                                 and Circumvention.
Sec.   63.5...................  Preconstruction Review  Yes.
                                 and Notification
                                 Requirements.
Sec.   63.6(a), (b)(1)-(b)(5),  Compliance with         Yes.
 (b)(7), (c).                    Standards and
                                 Maintenance
                                 Requirements.
Sec.   63.6(e)(1)(i)..........  General duty to         No. See Sec.
                                 minimize emissions..    63.7500(a)(3)
                                                         for the general
                                                         duty
                                                         requirement.
Sec.   63.6(e)(1)(ii).........  Requirement to correct  No.
                                 malfunctions as soon
                                 as practicable..
Sec.   63.6(e)(3).............  Startup, shutdown, and  No.
                                 malfunction plan
                                 requirements..
Sec.   63.6(f)(1).............  Startup, shutdown, and  No.
                                 malfunction
                                 exemptions for
                                 compliance with non-
                                 opacity emission
                                 standards..
Sec.   63.6(f)(2) and (3).....  Compliance with non-    Yes.
                                 opacity emission
                                 standards..
Sec.   63.6(g)................  Use of alternative      Yes.
                                 standards.
Sec.   63.6(h)(1).............  Startup, shutdown, and  No. See Sec.
                                 malfunction             63.7500(a).
                                 exemptions to opacity
                                 standards..
Sec.   63.6(h)(2) to (h)(9)...  Determining compliance  Yes.
                                 with opacity emission
                                 standards.

[[Page 15699]]

 
Sec.   63.6(i)................  Extension of            Yes.
                                 compliance..
Sec.   63.6(j)................  Presidential            Yes.
                                 exemption..
Sec.   63.7(a), (b), (c), and   Performance Testing     Yes.
 (d).                            Requirements.
Sec.   63.7(e)(1).............  Conditions for          No. Subpart
                                 conducting              DDDDD specifies
                                 performance tests..     conditions for
                                                         conducting
                                                         performance
                                                         tests at Sec.
                                                         63.7520(a).
Sec.   63.7(e)(2)-(e)(9), (f),  Performance Testing     Yes.
 (g), and (h).                   Requirements.
Sec.   63.8(a) and (b)........  Applicability and       Yes.
                                 Conduct of Monitoring.
Sec.   63.8(c)(1).............  Operation and           Yes.
                                 maintenance of CMS.
Sec.   63.8(c)(1)(i)..........  General duty to         No. See Sec.
                                 minimize emissions      63.7500(a)(3).
                                 and CMS operation.
Sec.   63.8(c)(1)(ii).........  Operation and           Yes.
                                 maintenance of CMS.
Sec.   63.8(c)(1)(iii)........  Startup, shutdown, and  No.
                                 malfunction plans for
                                 CMS.
Sec.   63.8(c)(2) to (c)(9)...  Operation and           Yes.
                                 maintenance of CMS.
Sec.   63.8(d)(1) and (2).....  Monitoring              Yes.
                                 Requirements, Quality
                                 Control Program.
Sec.   63.8(d)(3).............  Written procedures for  Yes, except for
                                 CMS.                    the last
                                                         sentence, which
                                                         refers to a
                                                         startup,
                                                         shutdown, and
                                                         malfunction
                                                         plan. Startup,
                                                         shutdown, and
                                                         malfunction
                                                         plans are not
                                                         required.
Sec.   63.8(e)................  Performance evaluation  Yes.
                                 of a CMS.
Sec.   63.8(f)................  Use of an alternative   Yes.
                                 monitoring method..
63.8(g).......................  Reduction of            Yes.
                                 monitoring data..
Sec.   63.9...................  Notification            Yes.
                                 Requirements.
Sec.   63.10(a), (b)(1).......  Recordkeeping and       Yes.
                                 Reporting
                                 Requirements.
Sec.   63.10(b)(2)(i).........  Recordkeeping of        Yes.
                                 occurrence and
                                 duration of startups
                                 or shutdowns.
Sec.   63.10(b)(2)(ii)........  Recordkeeping of        No. See Sec.
                                 malfunctions.           63.7555(d)(7)
                                                         for
                                                         recordkeeping
                                                         of occurrence
                                                         and duration
                                                         and Sec.
                                                         63.7555(d)(8)
                                                         for actions
                                                         taken during
                                                         malfunctions.
Sec.   63.10(b)(2)(iii).......  Maintenance records...  Yes.
Sec.   63.10(b)(2)(iv) and (v)  Actions taken to        No.
                                 minimize emissions
                                 during startup,
                                 shutdown, or
                                 malfunction.
Sec.   63.10(b)(2)(vi)........  Recordkeeping for CMS   Yes.
                                 malfunctions.
Sec.   63.10(b)(2)(vii) to      Other CMS requirements  Yes.
 (xiv).
Sec.   63.10(b)(3)............  Recordkeeping           No.
                                 requirements for
                                 applicability
                                 determinations.
Sec.   63.10(c)(1) to (9).....  Recordkeeping for       Yes.
                                 sources with CMS.
Sec.   63.10(c)(10) and (11)..  Recording nature and    No. See Sec.
                                 cause of                63.7555(d)(7)
                                 malfunctions, and       for
                                 corrective actions.     recordkeeping
                                                         of occurrence
                                                         and duration
                                                         and Sec.
                                                         63.7555(d)(8)
                                                         for actions
                                                         taken during
                                                         malfunctions.
Sec.   63.10(c)(12) and (13)..  Recordkeeping for       Yes.
                                 sources with CMS.
Sec.   63.10(c)(15)...........  Use of startup,         No.
                                 shutdown, and
                                 malfunction plan.
Sec.   63.10(d)(1) and (2)....  General reporting       Yes.
                                 requirements.
Sec.   63.10(d)(3)............  Reporting opacity or    No.
                                 visible emission
                                 observation results.
Sec.   63.10(d)(4)............  Progress reports under  Yes.
                                 an extension of
                                 compliance.
Sec.   63.10(d)(5)............  Startup, shutdown, and  No. See Sec.
                                 malfunction reports.    63.7550(c)(11)
                                                         for malfunction
                                                         reporting
                                                         requirements.
Sec.   63.10(e) and (f).......  ......................  Yes.
Sec.   63.11..................  Control Device          No.
                                 Requirements.
Sec.   63.12..................  State Authority and     Yes.
                                 Delegation.
Sec.   63.13-63.16............  Addresses,              Yes.
                                 Incorporation by
                                 Reference,
                                 Availability of
                                 Information,
                                 Performance Track
                                 Provisions.
Sec.   63.1(a)(5),(a)(7)-       Reserved..............  No.
 (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)..
------------------------------------------------------------------------


   Table 11 to Subpart DDDDD of Part 63--Toxic Equivalency Factors for
                             Dioxins/Furans
------------------------------------------------------------------------
                                                     Toxic equivalency
              Dioxin/furan congener                        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

[[Page 15700]]

 
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
----------------------------------------------------------------------------------------------------------------
                                                                 The emissions must not
                                                                  exceed the following     Using this specified
 If your boiler or process heater is      For the following     emission limits, except  sampling volume or test
         in this subcategory                  pollutants           during periods of           run duration
                                                                  startup and shutdown
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories          a. Mercury.............  3.5E-06 lb per MMBtu of  For M29, collect a
 designed to burn solid fuel.                                    heat input.              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          a. Particulate Matter..  0.008 lb per MMBtu of    Collect a minimum of 1
 designed to burn solid fuel that                                heat input (30-day       dscm per run.
 combust at least 10 percent biomass/                            rolling average for
 bio-based solids on an annual heat                              units 250 MMBtu/hr or
 input basis and less than 10 percent                            greater, 3-run average
 coal/solid fossil fuels on an annual                            for units less than
 heat input basis.                                               250 MMBtu/hr).
                                       b. Hydrogen Chloride...  0.004 lb per MMBtu of    For M26A, collect a
                                                                 heat input.              minimum of 1 dscm per
                                                                                          run; for M26, collect
                                                                                          a minimum of 60 liters
                                                                                          per run.
3. Units in all subcategories          a. Particulate Matter..  0.0011 lb per MMBtu of   Collect a minimum of 3
 designed to burn solid fuel that                                heat input (30-day       dscm per run.
 combust at least 10 percent coal/                               rolling average for
 solid fossil fuels on an annual heat                            units 250 MMBtu/hr or
 input basis and less than 10 percent                            greater, 3-run average
 biomass/bio-based solids on an                                  for units less than
 annual heat input basis.                                        250 MMBtu/hr).
                                       b. Hydrogen Chloride...  0.0022 lb per MMBtu of   For M26A, collect a
                                                                 heat input.              minimum of 1 dscm per
                                                                                          run; for M26, collect
                                                                                          a minimum of 60 liters
                                                                                          per run.
4. Units designed to burn pulverized   a. CO..................  90 ppm by volume on a    1 hr minimum sampling
 coal/solid fossil fuel.                                         dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       b. Dioxins/Furans......  0.003 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
5. Stokers designed to burn coal/      a. CO..................  7 ppm by volume on a     1 hr minimum sampling
 solid fossil fuel.                                              dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       b. Dioxins/Furans......  0.003 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
6. Fluidized bed units designed to     a. CO..................  30 ppm by volume on a    1 hr minimum sampling
 burn coal/solid fossil fuel.                                    dry basis corrected to   time.
                                                                 3 percent oxygen.

[[Page 15701]]

 
                                       b. Dioxins/Furans......  0.002 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
7. Stokers designed to burn biomass/   a. CO..................  560 ppm by volume on a   1 hr minimum sampling
 bio-based solids.                                               dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       b. Dioxins/Furans......  0.005 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
8. Fluidized bed units designed to     a. CO..................  260 ppm by volume on a   1 hr minimum sampling
 burn biomass/bio-based solids.                                  dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       b. Dioxins/Furans......  0.02 ng/dscm (TEQ)       Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
9. Suspension burners/Dutch Ovens      a. CO..................  1,010 ppm by volume on   1 hr minimum sampling
 designed to burn biomass/bio-based                              a dry basis corrected    time.
 solids.                                                         to 3 percent oxygen.
                                       b. Dioxins/Furans......  0.2 ng/dscm (TEQ)        Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
10. Fuel cells designed to burn        a. CO..................  470 ppm by volume on a   1 hr minimum sampling
 biomass/bio-based solids.                                       dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       b. Dioxins/Furans......  0.003 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
11. Hybrid suspension/grate units      a. CO..................  1,500 ppm by volume on   1 hr minimum sampling
 designed to burn biomass/bio-based                              a dry basis corrected    time.
 solids.                                                         to 3 percent oxygen.
                                       b. Dioxins/Furans......  0.2 ng/dscm (TEQ)        Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
12. Units designed to burn liquid      a. Particulate Matter..  0.002 lb per MMBtu of    Collect a minimum of 2
 fuel.                                                           heat input (30-day       dscm per run.
                                                                 rolling average for
                                                                 units 250 MMBtu/hr or
                                                                 greater, 3-run average
                                                                 for units less than
                                                                 250 MMBtu/hr).
                                       b. Hydrogen Chloride...  0.0032 lb per MMBtu of   For M26A, collect a
                                                                 heat input.              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  For M29, collect a
                                                                 heat input.              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     1 hr minimum sampling
                                                                 dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       e. Dioxins/Furans......  0.002 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
13. Units designed to burn liquid      a. Particulate Matter..  0.002 lb per MMBtu of    Collect a minimum of 2
 fuel located in non-continental                                 heat input (30-day       dscm per run.
 States and territories.                                         rolling average for
                                                                 units 250 MMBtu/hr or
                                                                 greater, 3-run average
                                                                 for units less than
                                                                 250 MMBtu/hr).

[[Page 15702]]

 
                                       b. Hydrogen Chloride...  0.0032 lb per MMBtu of   For M26A, collect a
                                                                 heat input.              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  For M29, collect a
                                                                 heat input.              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    1 hr minimum sampling
                                                                 dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       e. Dioxins/Furans......  0.002 ng/dscm (TEQ)      Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
14. Units designed to burn gas 2       a. Particulate Matter..  0.0067 lb per MMBtu of   Collect a minimum of 1
 (other) gases.                                                  heat input (30-day       dscm per run.
                                                                 rolling average for
                                                                 units 250 MMBtu/hr or
                                                                 greater, 3-run average
                                                                 for units less than
                                                                 250 MMBtu/hr).
                                       b. Hydrogen Chloride...  0.0017 lb per MMBtu of   For M26A, collect a
                                                                 heat input.              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  For M29, collect a
                                                                 heat input.              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     1 hr minimum sampling
                                                                 dry basis corrected to   time.
                                                                 3 percent oxygen.
                                       e. Dioxins/Furans......  0.08 ng/dscm (TEQ)       Collect a minimum of 4
                                                                 corrected to 7 percent   dscm per run.
                                                                 oxygen.
----------------------------------------------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.

[FR Doc. 2011-4494 Filed 3-18-11; 8:45 am]
BILLING CODE 6560-50-P


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