[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:
[email protected].
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:
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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.
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\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 (SO2),
and nitrogen oxide (NOX) from boilers constructed after June
19, 1984. Sources subject to the NSPS will also be subject to the final
CAA section 112(d) standards for boilers and process heaters because
the section 112(d) standards regulate HAP emissions while the NSPS do
not. However, in developing this final rule, we considered the
monitoring requirements, testing requirements, and recordkeeping
requirements of the NSPS to avoid duplicating requirements.
[[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$]
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3% Discount rate 7% Discount rate
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Selected
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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.
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2,700 tons of other metals, 23
grams of dioxins/furans (TEQ),
Health effects from SO2
exposure, Ecosystem effects,
Visibility impairment.
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Alternative
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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.
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\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.
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\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 (H2S) in this final
rule. Finally, EPA has changed the dioxin/furan testing requirement to
a one-time compliance demonstration due to the low dioxin/furan
emissions demonstrated by the vast majority of sources that have tested
for dioxin/furan.
H. Continuous Compliance
The only significant change to the continuous compliance
requirements is for monitoring of CO. Rather than using CO CEMS, as
proposed, units will be required to continuously monitor and record the
oxygen level in their flue gas during the initial compliance test and
establish an operating limit that requires that the unit operate at an
oxygen percentage of at least 90 percent of the operating limit on a
12-hour block average basis. Units will be required to continuously
monitor oxygen to ensure continuous compliance.
[[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.
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\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.''
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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\
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\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\
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\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 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., 2.0
percent of the calibration span value). For instrument calibration span
values of 25 ppmv and less, the allowable calibration error, bias, or
drift values are each 0.5 ppmv.
We can estimate the equivalent of the method detection level for a
measurement with an instrumental test method (e.g., EPA Methods 3A, 6C,
7E, and 10) using a square root formula and these allowable data
quality criteria. For example, in the case of a calibration span value
of 25 ppmv, the square root formula (i.e., square root of the sum of
the squares) would indicate a value of 0.9 ppmv. Consistent with the
methodology we applied for 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 NOX in most
boiler burners.
Response: As mentioned elsewhere in this preamble, EPA is required
to establish MACT floor levels based on emissions limits achieved by
sources for which emissions information is available to the
Administrator. EPA has revised the proposed MACT floors as well as the
proposed subcategories, as explained above. EPA also examined several
ways in which it might be able to use other types of emissions
information in addition to actual emissions measurements. However, EPA
concluded that there was no appropriate method of using different types
of information in a manner that could be incorporated into the
variability analyses. EPA first assessed the potential for estimating
emissions for sources that lacked actual emissions data through the use
of emission factors. However, the emission factors lack any degree of
variability. Therefore, the use of such data in this rulemaking would
have distorted the data variability in many cases, leading to standards
that were more stringent than those developed using emissions data only
and that likely underestimated actual variability. EPA also considered
whether it could otherwise estimate emissions of sources that did not
provide emissions data. However, EPA concluded that such estimations
were not possible without the development of a technically appropriate
approach to evaluate relevant information, and commenters did not
provide any such approaches. EPA's approach provides MACT floors that
are consistent with the requirements of section 112, because the floors
are based on the average emissions performance of the best performers
for which the Administrator has emissions information that is
appropriate to use in setting the floors.
EPA agrees with commenters who note that many of the data sets are
small. However, stakeholders were encouraged to provide additional
data, and EPA significantly revised some of the proposed emission
limits based on new test data. We received little or no additional data
for some subcategories for which data sets were small at proposal. For
all data sets, the final emission limits are based on the available
data and reflect EPA's assessment of variability. Moreover, after
consideration of the comments on the achievability of the emission
limits, EPA performed additional analyses and detailed examinations of
the data and developed revised limits that are based on what has been
demonstrated to be achieved in practice. As described in more detail in
the docket memorandum entitled ``Revised MACT Floor Analysis (2011) for
the Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--Major
Source,'' EPA has made adjustments to treatment of non-detect values,
the statistical methodology, and monitoring requirements, and also
incorporated new data and data corrections into our analyses.
Accordingly, the final emission limits better reflect the performance
of the MACT floor units than the proposed limits. EPA notes that for
each subcategory, there are existing units that are meeting the MACT
floor limits or are expected to meet the limits through application of
available control technology.
Finally, in response to comments about low CO limits conflicting
with a unit's ability to meet NOX requirements, EPA does not
have specific information on the NOX limits and
NOX emissions for most of the units that will be subject to
the standard. However, the CO limits have been revised as discussed
elsewhere in this preamble, and compliance is based on a full load
test, while periods of startup and shutdown are subject to a work
practice standard. To the extent that units cannot meet the CO floor
and maintain NOX at the required level, oxidation catalysts
can be used to reduce CO without an increase in NOX. EPA has
included costs for these controls for many units in the cost analysis,
although data on NOX requirements were not sufficient to
allow NOX to be part of the analyses. Commenters did not
provide any data supporting claims that any of the other emission
limits or projected control devices would interfere with a source's
ability to meet any of the other emission limits.
6. Comments on Technical Approaches
Comment: Several commenters offered suggestions for adjusting the
treatment of data from common stacks. Commenters suggested that it is
improper to count the data twice if two boilers, in the same
subcategory, exhaust through a common stack. A test conducted on the
common stack does not represent the actual emissions from a single
boiler, but rather reflects emissions from the combined simultaneous
operation of the two boilers and their associated control device(s).
The commenters contended that it is impossible to claim the test result
would be exactly the same for each boiler and they added that if a
common stack test turns out to be in the lowest 12 percent in a
subcategory, counting it twice distorts the average of the best
performers and skews the variability calculations. Commenters also
noted that it is also not appropriate to divide emissions evenly
between each boiler. Instead these commenters suggested that EPA use
the data from common stacks only a single time in the MACT floor
ranking and UPL calculations.
Response: EPA's current approach is a reasonable approach for
comingled emissions, particularly in light of the limited dataset
available for some subcategories, because EPA can not accurately
separate the fraction of the emissions that came from the combustion
units and process emission points that are comingled in the same stack.
Applying the emissions equally to multiple units exhausting through a
common stack accurately represents the emissions of those units on
average. Further, although the use of a data point twice may dampen
variability, the inclusion of an extra unit in the floor has the
opposite effect on the overall emission limit by increasing the
denominator of the floor calculation. Either method could be used, but
the results would not differ significantly. Furthermore, for existing
sources, MACT cannot be less stringent than the average emission
limitation achieved by
[[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, SO2, and NOX) as well as the
New Source Performance Standard for Industrial Commercial Institutional
Boilers (40 CFR part 60 subpart Db) which includes an output-based
emissions standard for NOX. This commenter also provided
examples of output-based emissions regulations in 12 states, including
4 that regulate 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 NOX standard under the New
Source Performance Standards (subpart Da) for electric utility boilers.
The criteria used for selecting a specific output-based format were
based on the following: (1) Provide flexibility in promotion of plant
efficiency; (2) permit measurement of parameters related to stack
emissions and plant efficiency, on a continuous basis; and (3) be
suitable for equitable application on a variety of facility
configurations. The output-based option of mass of pollutant emitted
per boiler energy output (lb/MMBtu energy output) meets all three
criteria. The majority of ICI boilers produce steam only for process
operation or heating and, in this case, the energy output of the boiler
is the energy content of the boiler steam output. For those ICI boilers
that supply steam to generate, or cogenerate, electricity, the boiler's
energy output can include both electrical and thermal (process steam)
outputs. There are also some industrial boilers that only generate
electricity. Technologies are readily available to measure these energy
outputs, and they currently are measured routinely in many industrial
plants. Therefore, emission limits based on this format can be applied
equitably on a variety of facility configurations. Based on this
analysis, an emission limit format based on mass of pollutant emissions
per energy output was selected for the alternate output-based
standards.
In the case of a boiler that produces steam for process or heating
only (no power generation), the lb/MMBtu output-based emission limit is
based on the mass rate of emissions from the boiler and the energy
content in terms of MMBtu of the boiler steam output. At cogeneration
facilities (also known as combined heat and power (CHP)), energy output
includes both electricity and process steam. The steam from the boiler
is first used to generate electricity. The thermal energy (steam)
exiting the electricity generating equipment is then used for a variety
of useful purposes, such as manufacturing processes, space heating and
cooling, water heating, and drying. The electricity output and the
useful energy present in the steam exiting the turbine must both be
accounted for in determining the overall energy output from the boiler
and converted to a common basis of lb/MMBtu consistent with the output-
based standard for steam-only units.
The efficiency and associated environmental benefits of CHP result
from avoiding emissions from the generation of electricity at a central
station power plant. The avoided emissions at most times are from a
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
NOX emissions. Commenters also noted that these units were
not considered in development of the MACT standards, and claimed that
they are well known in the burner industry and referenced in standard
literature.
The third type of combination unit, one commenter mentioned, was a
subcategory for units co-firing biomass with any solid fuel. Commenters
claimed that by failing to recognize the wide verity of fuel inputs and
thus the variation in fuel quality (i.e., BTU and
[[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 SO2 limits that
considers the mix of fuel fired rather than assuming one fuel dictates
the emission limitations.
Some commenters were concerned that determination of MACT floor
limits should be based only on data obtained while firing 100 percent
of the affected fuel category and recommended that EPA either exclude
all test runs where a unit was co-firing or adjust the data accordingly
to remove the co-firing bias.
Response: In response to the variety of comments regarding
combination fuel boilers, EPA has revised the subcategories in order to
simplify implementation, improve the flexibility of units in
establishing and changing fuel mixtures, promote combustion of cleaner
fuels, and provide MACT standards that are enforceable and consistent
with the requirements of section 112. For the combination liquid and
gas-fired units, while the commenters provided some insights on these
units, the data available to EPA regarding any distinctions between
these units and units designed to burn liquid only were insufficient to
provide a justification for changing the approach for these units. For
combined fuel units that combust solid fuels, due to the many potential
combinations and percentages of solid fuels that are or can be
combusted, for the fuel-based pollutants, EPA selected the option of
combining the subcategories for solid fuels into a single solid fuel
subcategory. For the fuel-based pollutants, this alleviates the
concerns regarding changes in fuel mixtures, promotion of combustion of
dirtier fuels, and the implementation and compliance concerns. For
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 H2S and Hg that are no higher than those found in
Gas 1 units. Natural gas purity is commonly defined considering the
sulfur content of the gas, in the form of H2S. Sweet natural
gas, which is considered pipeline quality gas, contains no more than 4
ppmv H2S. Information on Hg levels typical of natural gas
was available through literature, and domestic natural gas Hg
concentrations range up to about 40 micrograms per cubic meter. Using
H2S and Hg concentration as parameters for establishing
equivalent contamination levels to natural gas, EPA is providing a fuel
specification that can be used by facilities to qualify Gas 2 units for
the Gas 1 standards. The fuel specification would also allow facilities
to perform pre-combustion gas cleanup in order to qualify Gas 2 units
for the Gas 1 standards. Boilers using process gases that do not meet
the fuel specification and are not processed to meet the contaminant
levels must meet the emissions limits for Gas 2 units.
3. Dioxin/Furan Emission Limits or Work Practices
Comment: Many commenters disagreed with the proposed dioxin/furan
emission limits. Some commenters noted that a large majority of the
dioxin/furan test data are 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 SO2 emissions from biomass units would
be limited due to the low inlet sulfur levels of this fuel.
Several other commenters suggested it is impossible to assess an
established health threshold for HCl such that a 112(d)(4) standard
could be set without evaluating the collateral benefits of a MACT
standard. And, as described in the recently finalized cement kiln MACT
rule, setting technology-based standards for HCl will result in
significant reductions in the emissions of other pollutants, including
SO2, Hg, and PM. The commenter added that these reductions
will provide enormous health and environmental benefits, which would
not be experienced if section 112(d)(4) standards had been finalized.
These commenters contended that HCl and other dangerous acid gases
produced by commercial and industrial boilers pose substantial risks to
industrial workers, as well as surrounding communities, and must be
limited by the strict conventional MACT standards.
Cost Impacts of HBCA
Several commenters indicated that the current economic climate
requires EPA to balance economic and environmental interests and they
indicated that HBCA would help target investments into solving true
health threats where limits are no more stringent or less stringent
than needed to protect public health. Many commenters provided
compliance cost savings if an HBCA is included in this final rule. For
example, representatives of one industry estimated aggregated capital
savings in excess of $100 million just for the small facilities in the
pulp & paper sector. Some commenters stressed the importance of an HBCA
options for small entities affected by the regulations. Several other
commenters suggested that EPA should estimate the costs and
environmental effects of the HBCA option compared to a conventional
MACT standard in order to make an informed decision on the adoption of
an HBCA.
Response: After considering the comments received, some of which
supported adoption of an emissions standard under section 112(d)(4) and
some of which opposed such a standard, EPA has decided not to adopt an
emissions standard based on its authority under section 112(d)(4) in
the final rule. EPA first notes that the Agency's authority under
section 112(d)(4) is discretionary. That provision states that EPA
``may'' consider established health thresholds when setting emissions
standards under section 112(d). By the use of the term ``may,''
Congress clearly intended to allow EPA to decide not to consider a
health threshold even for pollutants which have an established
threshold. As explained in the preamble to the proposed rule, it is
appropriate for EPA to consider relevant factors when deciding whether
to exercise its discretion under section 112(d)4). EPA has considered
the public comments received and is not adopting an emissions standard
under section 112(d)(4) for the reasons explained below.
First, as explained in the preamble to the proposed rule, EPA
continues to believe that the potential cumulative public health and
environmental effects of acid gas emissions from boilers and other acid
gas sources located near boilers supports the Agency's decision not to
exercise its discretion under section 112(d)(4). EPA requested in the
preamble to the proposed rule information regarding facility-specific
emissions of acid gases from boilers as well as sources which may be
co-located with boilers. In particular, information concerning the
variation of acid gas emission rates that can be expected from the
various subcategories of units was identified as a significant data
gap. Additional data were not provided during the comment period, and
the data already in hand regarding these emissions are not sufficient
to support the development of emissions standards for any of the
boilers subcategories under section 112(d) that take into account the
health threshold for acid gases, particularly given that the Act
requires EPA's consideration of health thresholds under section
112(d)(4) to protect public health with an ample margin of safety. In
addition, the concerns expressed by EPA in the proposal regarding the
potential environmental impacts and the cumulative impacts of acid
gases on public health were not assuaged by the comments received.
EPA also received comments recommending not only that EPA establish
emissions standards for acid gases pursuant to section 112(d)(4), but
that it do so by excluding specific facilities from complying with
emissions limits if the facility demonstrates that its emissions do not
pose a health risk. EPA does not believe that a plain reading of the
statute supports the establishment of such an approach. While section
112(d)(4) authorizes EPA to consider the level of
[[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.
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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
NOX limits. These commenters presented graphs and data to
demonstrate the inverse relationship between CO and NOX
emissions and noted that changing the boiler operation to reduce CO to
such low levels would result in an increase in NOX
emissions. Commenters added that this result would be particularly
challenging, and perhaps unproductive for boilers located in ozone non-
attainment areas. In addition to increasing NOX emissions,
commenters noted that driving emission levels down to extremely low CO
levels would also require boiler operators to increase excess air,
thereby reducing the efficiency of the boiler. This operational change
would require additional fuel to be combusted, thus increasing
emissions of other HAP. These commenters requested that CO limits be
[[Page 15646]]
balanced with NOX limits such that boiler efficiency is
optimized and State efforts to comply with NAAQS are not hindered. In
addition to concerns surrounding competing air quality standards, a few
commenters stated that National Fire Protection Act (NFPA) requirements
also affect CO emissions at low loads. The NFPA specifies a minimum
airflow at which a boiler can operate regardless of load, in order to
avoid boiler explosions. At low loads, this NFPA requirement can result
in excess air which leads to increased CO emissions. Commenters added
that in order to meet the limits as proposed, boilers may have to idle
at a higher load, increasing fuel costs and other emissions
(NOX, carbon dioxide (CO2), and HAP).
Response: In response to the many comments regarding the proposed
CO emission limits, EPA performed a 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 NOX limits, unless controls are added. Several
pointed out that tune-ups and combustion modifications such as a
linkageless boiler management system (LBMS) and replacement burners
would offer inadequate control in most cases.
Response: EPA incorporated additional CO data variability data
received during the comment period, adjusted subcategories, and revised
compliance mechanisms to address the issues discussed in these
comments.
Comment: One commenter pointed out that no documentation was found
of a successful LBMS retrofit to existing biomass-to-energy facilities
using stoker or fuel cell oven combustion. This commenter cited
conversations with several stoker burner manufacturers, and the
commenter could find no stoker units that have been retrofitted with an
LBMS. They added that manufacturers stated that a successful retrofit
to meet the proposed standards was doubtful based on the inherent
leakage of air in these types of facilities.
Response: EPA adjusted subcategories and compliance mechanisms and
analyzed new CO test data in order to make the CO limits more
reasonable. EPA estimates the cost of an LBMS as a placeholder for
other combustion
[[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
(SO3) are generated as part of the combustion process for
sulfur-containing fuels. The commenter noted that a CO oxidation
catalyst or Selective Catalytic Reduction NOX reduction
catalyst, will convert an additional percentage of the SO2to
SO3, which will inhibit Hg removal efficiency of activated
carbon injection. SO3 occupies the active sites on the
carbon, taking away those sites from the Hg. Additionally, some of
these commenters also pointed out that some of the suggested control
combinations have not been used with the affected boilers, so their use
is unproven and the retrofit costs unknown.
Response: EPA recognizes the potential interaction of different
control devices and has adjusted the subcategories and incorporated
additional emission data into the emission limit calculations. The
revised limits and subcategories incorporated in this final rule
mitigate these concerns. However, specifically addressing the
commenters concerns would require an extensive study of emissions and
controls, and the time or resources to conduct such a study are not
available. EPA used the available data to set standards as required
under section 112.
Comment: Some commenters questioned the assumption that facilities
will not incur costs to comply with the dioxin/furan standards because
they will test for dioxin/furan and be below detection levels. They
said this logic does not make sense because EPA has not outlined in the
proposed rule any procedures for handling non-detects when performing
compliance testing and there are boilers in the EPA emissions database
with dioxin/furan emissions that are non-detect but actually measured
emissions higher than the proposed limit.
Response: EPA adjusted the dioxin/furan emission limits based on
data corrections and corrected procedures for handling non-detect and
detection level limited values, making the need for 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 PM2.5 and
ozone concentrations. This results in an underestimate of the total
monetized benefits. We estimated the total monetized benefits of this
final regulatory action to be $22 billion to $54 billion (2008$, 3
percent discount rate) in the implementation year (2014). The monetized
benefits at a 7 percent discount rate are $20 billion to $49 billion
(2008$). Using alternate relationships between fine particulate matter
(PM2.5) and premature mortality supplied by experts, higher
and lower benefits estimates are plausible, but most of the expert-
based estimates fall between these two estimates.\8\ A summary of the
monetized benefits estimates at discount rates of 3 percent and 7
percent is provided in Table 4 of this preamble. A summary of the
avoided health incidences is provided in Table 5 of this preamble.
---------------------------------------------------------------------------
\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 PM2.5 and
ozone. The PM and ozone reductions are the result of emission limits on
PM as well as emission limits on other pollutants, including HAP. To
estimate the human health benefits, we used the environmental Benefits
Mapping and Analysis Program (BenMAP) model to quantify the changes in
PM2.5- and ozone-related health impacts and monetized
benefits based on changes in air quality. This approach is consistent
with the recently proposed Transport Rule RIA.\9\
---------------------------------------------------------------------------
\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 PM2.5 and
PM2.5 precursors into changes in ambient PM2.5
levels and BenMAP to estimate the changes in human health associated
with that change in air quality. Finally, the monetized
PM2.5 health benefits were divided by the emission
reductions to create the boiler sector-specific benefit-per-ton
estimates. These models assume that all fine particles, regardless of
their chemical composition, are equally potent in causing premature
mortality because there is no clear scientific evidence that would
support the development of differential effects estimates by particle
type. Directly emitted PM2.5 and SO2 are the
dominant PM2.5 precursors affected by this final rule. Even
though we assume that all fine particles have equivalent health
effects, the benefit-per-ton estimates vary between precursors because
each ton of precursor reduced has a different propensity to form
PM2.5. For example, SO2 has a lower benefit-per-
ton estimate than direct PM2.5 because it does not directly
transform into PM2.5, and because sulfate particles formed
from SO2 emissions can transport many miles, including over
areas with low populations. Direct PM2.5 emissions convert
directly into ambient PM2.5, thus, to the extent that
emissions occur in population areas, exposures to direct
PM2.5 will tend to be higher, and monetized health benefits
will be higher than for SO2 emissions.
In addition, we estimated the ozone benefits for this final rule.
Volatile organic compounds (VOC) are the primary ozone precursor
affected by this final rule. We used CAMx to convert emissions of VOC
into changes in ambient ozone levels and BenMAP to estimate the changes
in human health associated with that change in air quality.
Furthermore, CAMx modeling allows us to model the reduced Hg
deposition that would occur as a result of the estimated reductions of
Hg emissions. Although we are unable to model Hg methylation and human
consumption of Hg-contaminated fish, the Hg deposition maps provide an
improved qualitative characterization of the Hg benefits associated
with this final rulemaking.
For context, it is important to note that the magnitude of the PM
benefits is largely driven by the concentration response function for
premature mortality. Experts have advised EPA to consider a variety of
assumptions, including estimates based on both empirical
(epidemiological) studies and
[[Page 15653]]
judgments elicited from scientific experts, to characterize the
uncertainty in the relationship between PM2.5 concentrations
and premature mortality. For this final rule, we cite two key empirical
studies, one based on the American Cancer Society cohort study \10\ and
the extended Six Cities cohort study.\11\ In the RIA for this final
rule, which is available in the docket, we also include benefits
estimates derived from expert judgments and other assumptions.
---------------------------------------------------------------------------
\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
PM2.5 exposure. Consistent with this recent advice, we are
replacing the previous threshold sensitivity analysis with a new
``lowest measured level (LML)'' assessment. While an LML assessment
provides some insight into the level of uncertainty in the estimated PM
mortality benefits, EPA does not view the LML as a threshold and
continues to quantify PM-related mortality impacts using a full range
of modeled air quality concentrations.
Most of the estimated PM-related benefits in this final rule would
accrue to populations exposed to higher levels of PM2.5.
Using the Pope, et al., (2002) study, 79 percent of the population is
exposed at or above the LML of 7.5 microgram per cubic meter ([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 PM2.5-related
effects down to the lowest LML of the major cohort studies. This fact
is important, because as we estimate PM-related mortality among
populations exposed to levels of PM2.5 that are successively
lower, our confidence in the results diminishes. However, our analysis
shows that the great majority of the impacts occur at higher exposures.
It should be emphasized that the monetized benefits estimates
provided above do not include benefits from several important benefit
categories, including reducing other air pollutants, ecosystem effects,
and visibility impairment. The benefits from reducing other pollutants
have not been monetized in this analysis, including reducing 167,000
tons of CO, 30,000 tons of hydrochloric acid, 820 tons of HF, 23 grams
of dioxins/furans, 2,900 pounds of Hg, and 22,700 tons of other metals
each year. Specifically, we were unable to estimate the benefits
associated with HAPs that would be reduced as a result of this rule due
to data, resource, and methodology limitations. Challenges in
quantifying the HAP benefits include a lack of exposure-response
functions, uncertainties in emissions inventories and background
levels, the difficulty of extrapolating risk estimates to low doses,
and the challenges of tracking health progress for diseases with long
latency periods. Although we do not have sufficient information or
modeling available to provide monetized estimates for this rulemaking,
we include a qualitative assessment of the health effects of these air
pollutants in the RIA for this final rule, which is available in the
docket. In addition, we provide maps of reduced mercury deposition
anticipated from these rules in the RIA for this final rule.
In addition, the monetized benefits estimates provided in Table 4
do not reflect the disbenefits associated with increased electricity
usage from operation of the control devices. We estimate that the
increases in emissions of CO2 would have disbenefits valued
at $22 million at a 3 percent discount rate (average). CO2-
related disbenefits were calculated using the social cost of carbon,
which is discussed further in the RIA. However, these disbenefits do
not change the rounded total monetized benefits. In the RIA, we also
provide the monetized CO2 disbenefits using discount rates
of 5 percent (average), 2.5 percent (average), and 3 percent (95th
percentile).
This analysis does not include the type of detailed uncertainty
assessment found in the 2006 PM2.5 NAAQS RIA or 2008 Ozone
NAAQS RIA. However, the benefits analyses in these RIA provide an
indication of the sensitivity of our results to various assumptions,
including the use of alternative concentration-response functions and
the fraction of the population exposed to low PM2.5 levels.
For more information on the benefits analysis, please refer to the
RIA for this final rule that is available in the docket.
G. What are the secondary air impacts?
For units adding controls to meet the proposed emission limits, we
anticipate very minor secondary air impacts. The combustion of fuel
needed to generate additional electricity would yield slight increases
in emissions, including NOX, CO, PM and SO2 and
an increase in CO2 emissions. Since NOX and
SO2 are covered by capped emissions trading programs, and
methodological limitations prevent us from quantifying the change in CO
and PM, we do not estimate an increase in secondary air impacts for
this final rule from additional electricity demand. We do estimate
greenhouse gas impacts, which result from increased electricity
consumption, to be 954,000 tons per year from existing units and 4,100
tons per year from new units.
VII. Relationship of This Final Action to Section 112(c)(6) of the CAA
Section 112(c)(6) of the CAA requires EPA to identify categories of
sources of seven specified pollutants to assure that sources accounting
for not less than 90 percent of the aggregate emissions of each such
pollutant are subject to standards under CAA Section 112(d)(2) or
112(d)(4). EPA has identified ``Industrial Coal Combustion,''
``Industrial Oil Combustion,'' ``Industrial Wood/Wood Residue
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source
categories that emit two of the seven CAA Section 112(c)(6) pollutants:
POM and Hg. (The POM emitted is composed of 16 polyaromatic
hydrocarbons and extractable organic matter.) In the Federal Register
notice Source Category Listing for Section 112(d)(2) Rulemaking
Pursuant to Section 112(c)(6) Requirements, 63 FR 17838, 17849, Table 2
(1998), EPA identified ``Industrial Coal Combustion,'' ``Industrial Oil
Combustion,'' ``Industrial Wood/Wood Residue Combustion,'' ``Commercial
Coal Combustion,'' ``Commercial Oil Combustion,'' and ``Commercial
Wood/Wood Residue Combustion'' as source categories ``subject to
regulation'' for purposes of CAA Section 112(c)(6) with respect to the
CAA Section 112(c)(6) pollutants that these units emit.
Specifically, as byproducts of combustion, the formation of POM is
effectively reduced by the combustion and post-combustion practices
required to comply with the CAA Section 112 standards. Any POM that do
form during combustion are further controlled by the various 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-NOX burners), and hours of
use (limited use); EPA should have minimized facility monitoring and
reporting requirements; EPA should not have proposed the energy audit
requirement; EPA's proposed emissions standards are too stringent; and,
EPA should provide more flexibility for emissions averaging.
In response to the comments on the IRFA and other public comments,
EPA made the following changes to the final rule. EPA adopted
additional subcategories, including a limited-use subcategory for units
that operate less than 10 percent of the operating hours in a year, a
non-continental liquid unit subcategory for units with the unique
challenges faced by remote island locations, and a combination
suspension/grate boiler subcategory. EPA also consolidated the
subcategories for units combusting various types of solid fuels, which
will simplify compliance and will allow units to combust varying
percentages of different solid fuels without triggering subcategory
changes. EPA also decreased monitoring and testing costs by eliminating
the CO CEMS requirement for units greater than 100 mmBtu/hr and
changing the dioxin testing requirement to a one-time test. The final
rule also includes work practice standards for additional
subcategories, including limited-use units, new small units, and units
combusting gaseous fuels that are demonstrated to have similar
contaminant levels to natural gas. Finally, EPA is finalizing emission
limits that are less stringent than the proposed limits for most of the
subcategory/pollutant combinations. The emission limit changes are
largely due to the changes in subcategories, data corrections, and
incorporation of new data into the floor calculations. Additional
details on the changes discussed in this paragraph are included in
sections IV and V of this preamble.
While EPA did make significant changes based on public comment, EPA
did not finalize a HBCA or HBELs and is maintaining, but clarifying,
the energy assessment requirement. The discussion of the HBCA decision
is included in section V of this preamble. Some changes to the energy
assessment requirement that will reduce costs for small entities
include a the following provisions: The energy assessment for
facilities with affected boilers and process heaters using less than
0.3 trillion Btu per year heat input will be one day in length maximum.
The boiler system and energy use system accounting for at least 50
percent of the energy output will be evaluated to identify energy
savings opportunities, within the limit of performing a one-day energy
assessment; and the energy assessment for facilities with affected
boilers and process heaters using 0.3 to 1.0 trillion Btu per year will
be 3 days in length maximum. The boiler system and any energy use
system accounting for at least 33 percent of the energy output will be
evaluated to identify energy savings opportunities, within the limit of
performing a 3-day energy assessment. In addition, energy assessments
that have been conducted after January 1, 2008 are considered adequate
as long as they meet or are amended to meet the requirements of the
energy assessment.
While EPA did not make major adjustments to the emissions averaging
provisions, the change to a solid fuel subcategory will enable all
solid 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 PM2.5 and in SO2 that
would occur, including 28 thousand tons of PM2.5 and 443
thousand tons of SO2. These reductions occur within 3 years
after the implementation of the proposed regulation and are expected to
continue throughout the life of the affected sources. The major health
effect associated with reducing PM2.5 and PM2.5
precursors (such as SO2) is a reduction in premature
mortality. Other health effects associated with PM2.5
emission reductions include avoiding cases of chronic bronchitis, heart
attacks, asthma attacks, and work-lost days (i.e., days when employees
are unable to work). While we are unable to monetize the benefits
associated with the HAP emissions reductions, we are able to monetize
the benefits associated with the PM2.5 and SO2
emissions reductions. For SO2 and PM2.5, we
estimated the benefits associated with health effects of PM but were
unable to quantify all categories of benefits (particularly those
associated with ecosystem and visibility effects). Our estimates of the
monetized benefits in 2014 associated with the implementation of the
proposed alternative is range from $22 billion (2008 dollars) to $54
billion (2008 dollars) when using a 3 percent discount rate (or from
$20 billion (2008 dollars) to $49 billion (2008 dollars) when using a 7
percent discount rate). This estimate, at a 3 percent discount rate, is
about $20.5 billion (2008 dollars) to $52.5 billion (2008 dollars)
higher than the estimated social costs shown earlier in this section.
The general approach used to value benefits is discussed in more detail
earlier in this preamble. For more detailed information on the benefits
estimated for the rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
The UMRA requires that we estimate, where accurate estimation is
reasonably feasible, future compliance costs imposed by this final rule
and any disproportionate budgetary effects. Our estimates of the future
compliance costs of the rule are discussed previously in this preamble.
We do not believe that there will be any disproportionate budgetary
effects of this final rule on any particular areas of the country,
State or local governments, types of communities (e.g., urban, rural),
or particular industry
[[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, CO2, and CO content of exhaust gas.
This part of ASME PTC 19-10-1981-Part 10 is an acceptable alternative
to Method 3B.
The voluntary consensus standard ASTM D6522-00, ``Standard Test
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers and Process Heaters Using
Portable Analyzers'' is an acceptable alternative to EPA Method 3A for
identifying CO and oxygen concentrations for this final rule when the
fuel is natural gas.
The voluntary consensus standard ASTM Z65907, ``Standard Method for
Both Speciated and Elemental Mercury Determination,'' is an acceptable
alternative to EPA Method 29 (portion for Hg only) for the purpose of
this final rule. This standard can be used in the final rule to
determine the Hg concentration in stack gases for boilers with rated
heat input capacities of greater than 250 MMBtu/hr.
In addition to the voluntary consensus standards EPA used in the
proposed rule, the search for emissions measurement procedures
identified 15 other voluntary consensus standards. EPA determined that
13 of these 15 standards identified for measuring emissions of the HAP
or surrogates subject to emission standards in the proposed rule were
impractical alternatives to EPA test methods for the purposes of this
final rule. Therefore, EPA does not intend to adopt these standards for
this purpose. The reasons for this determination for the 13 methods are
discussed below.
The voluntary consensus standard ASTM D3154-00, ``Standard Method
for Average Velocity in a Duct (Pitot Tube Method),'' is impractical as
an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the
proposed rulemaking since the standard appears to lack in quality
control and quality assurance requirements. Specifically, ASTM D3154-00
does not include the following: (1) Proof that openings of standard
pitot tube have not plugged during the test; (2) if differential
pressure gauges other than inclined manometers (e.g., magnehelic
gauges) are used, their calibration must be checked after each test
series; and (3) the frequency and validity range for calibration of the
temperature sensors.
The voluntary consensus standard ASTM D3464-96 (2001), ``Standard
Test Method Average Velocity in a Duct Using a Thermal Anemometer,'' is
impractical as an alternative to EPA Method 2 for the purposes of the
proposed rule primarily because applicability specifications are not
clearly defined, e.g., range of gas composition, temperature limits.
Also, the lack of supporting quality assurance data for the calibration
procedures and specifications, and certain variability issues that are
not adequately addressed by the standard limit EPA's ability to make a
definitive comparison of the method in these areas.
The voluntary consensus standard ISO 10780:1994, ``Stationary
Source Emissions--Measurement of Velocity and Volume Flowrate of Gas
Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in
the proposed rule. The standard recommends the use of an L-shaped
pitot, which historically has not been recommended by EPA. EPA
specifies the S-type design which has large openings that are less
likely to plug up with dust.
The voluntary consensus standard, CAN/CSA Z223.2-M86 (1999),
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide,
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed
Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA
Method 3A since it does not include quantitative specifications for
measurement system performance, most notably the calibration procedures
and instrument performance characteristics. The instrument performance
characteristics that are provided are nonmandatory and also do not
provide the same level of quality assurance as the EPA methods. For
example, the zero and span/calibration drift is only checked weekly,
whereas the EPA methods require drift checks after each run.
Two very similar voluntary consensus standards, ASTM D5835-95
(2001), ``Standard Practice for Sampling Stationary Source Emissions
for Automated Determination of Gas Concentration,'' and ISO 10396:1993,
``Stationary Source Emissions: Sampling for the Automated Determination
of Gas Concentrations,'' are impractical alternatives to EPA Method 3A
for the purposes of this final rule because they lack in detail and
quality assurance/quality control requirements. Specifically, these two
standards do not include the following: (1) Sensitivity of the method;
(2) acceptable levels of analyzer calibration error; (3) acceptable
levels of sampling system bias; (4) zero drift and calibration drift
limits, time span, and required testing frequency; (5) a method to test
the interference response of the analyzer; (6) procedures
[[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,
NOX, PM, and SO2. SO2 and nitrogen
dioxide are precursors for the formation of PM2.5 and ozone.
Reducing these emissions will reduce ozone and PM2.5
formation and associated health effects, such as adult premature
mortality, chronic and acute bronchitis, asthma, and other respiratory
and cardiovascular diseases. (Please refer to the RIA contained in the
docket for this rulemaking.)
Based on the fact that this final rule does not allow emission
increases, EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority, low-income, or Tribal populations. To address
Executive Order 12898, EPA has conducted analyses to determine the
aggregate demographic makeup of the communities near affected sources.
EPA's demographic analysis of populations within the three-mile radius
showed that major source boilers are located in areas where minorities
are overrepresented when compared to the national average. For these
same areas, there is also an overrepresentation of population below the
poverty line as compared to the national average. The results of the
demographic analysis are presented in ``Review of Environmental Justice
Impacts'', April 2010, a copy of which is available in the docket.
However, to the extent that any minority, low income, or Tribal
subpopulation is disproportionately impacted by the current emissions
as a result of the proximity of their homes to these sources, that
subpopulation also stands to see increased environmental and health
benefit from the emissions reductions called for by this rule.
EPA defines ``Environmental Justice'' to include meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and polices. To promote
meaningful involvement, EPA has developed a communication and outreach
strategy to ensure that interested communities have access to this
final rule and are aware of its content. EPA also ensured that
interested communities had an opportunity to comment during the comment
period. During the comment period that followed the June 2010 proposal,
EPA publicized the rulemaking via EJ newsletters, Tribal newsletters,
EJ listservs, and the internet, including the Office of Policy's (OP)
Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/RuleGate.nsf/
). EPA will also provide general rulemaking fact sheets (e.g., why is
this important for my community) for EJ community groups and conduct
conference calls with interested communities. In addition, State and
federal permitting requirements will provide State and local
governments and members of affected communities the opportunity to
provide comments on the permit conditions associated with permitting
the sources affected by this rulemaking.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this final rule and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective May 20, 2011.
List of Subjects in 40 CFR part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.
Dated: February 21, 2011.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, part
63 of the Code of the Federal Regulations is amended as follows:
PART 63--[AMENDED]
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 (O2 CEMS) must be installed,
operated, and maintained according to the applicable procedures under
Performance Specification 3 at 40 CFR part 60, appendix B, and
according to the site-specific monitoring plan developed according to
Sec. 63.7505(d).
(2) You must conduct a performance evaluation of each O2
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 O2 CEMS must complete a minimum of one cycle of
operation (sampling, analyzing, and data recording) for each successive
15-minute period.
(4) The O2 CEMS data must be reduced as specified in
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.
EISiactual = Energy Input Savings for each energy
conservation measure implemented for an affected boiler, million Btu
per year.
EIbaseline = Energy Input for the affected boiler,
million Btu.
n = Number of energy conservation measures included in the emissions
credit for the affected boiler.
(d) The owner or operator shall develop and submit for approval an
Implementation Plan containing all of the information required in this
paragraph for all boilers to be included in an emissions credit
approach. The Implementation Plan shall identify all existing affected
boilers to be included in applying the emissions credits. The
Implementation Plan shall include a description of the energy
conservation measures implemented and the energy savings generated from
each measure and an explanation of the criteria used for determining
that savings. You must submit the implementation plan for emission
credits to the applicable delegated authority for review and approval
no later than 180 days before the date on which the facility intends to
demonstrate compliance using the emission credit approach.
(e) The emissions rate from each existing boiler participating in
the emissions credit option must be in compliance with the limits in
Table 2 to this subpart at all times following the compliance date
specified in 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:
Eadj = Emission level adjusted applying the emission
credits earned, lb per million Btu steam output for the affected
boiler.
Em = Emissions measured during the performance test, lb
per million Btu steam output for the affected boiler.
EC = Emission credits from equation 12 for the affected boiler.
Continuous Compliance Requirements
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 C3H8.
Opacity means the degree to which emissions reduce the transmission
of light and obscure the view of an object in the background.
Operating day means a 24-hour period between 12 midnight and the
following midnight during which any fuel is combusted at any time in
the boiler or process heater unit. It is not necessary for fuel to be
combusted for the entire 24-hour period.
Other gas 1 fuel means a gaseous fuel that is not natural gas or
refinery gas and does not exceed the maximum concentration of 40
micrograms/cubic meters of mercury and 4 parts per million, by volume,
of hydrogen sulfide.
Particulate matter (PM) means any finely divided solid or liquid
material, other than uncombined water, as measured by the test methods
specified under this subpart, or an approved alternative method.
Period of natural gas curtailment or supply interruption means a
period of time during which the supply of natural gas to an affected
facility is halted for reasons beyond the control of the facility. The
act of entering into a contractual agreement with a supplier of natural
gas established for curtailment purposes does not constitute a reason
that is under the control of a facility for the purposes of this
definition. An increase in the cost or unit price of natural gas does
not constitute a period of natural gas curtailment or supply
interruption.
Process heater means an enclosed device using controlled flame, and
the unit's primary purpose is to transfer heat indirectly to a process
material (liquid, gas, or solid) or to a heat transfer material for use
in a process unit, instead of generating steam. Process heaters are
devices in which the combustion gases do not come into direct contact
with process materials. A device combusting solid waste, as defined in
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