[Federal Register Volume 76, Number 247 (Friday, December 23, 2011)]
[Proposed Rules]
[Pages 80597-80672]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-31667]
[[Page 80597]]
Vol. 76
Friday,
No. 247
December 23, 2011
Part V
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Proposed Rule
Federal Register / Vol. 76 , No. 247 / Friday, December 23, 2011 /
Proposed Rules
[[Page 80598]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-9503-6]
RIN 2060-AR13
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule; Reconsideration of final rule.
-----------------------------------------------------------------------
SUMMARY: On March 21, 2011, the EPA promulgated national emission
standards for the control of hazardous air pollutants from new and
existing industrial, commercial, and institutional boilers and process
heaters at major sources of hazardous air pollutants. On that same day,
the EPA also published a notice announcing its intent to reconsider
certain provisions of the final rule. The EPA subsequently issued a
notice on May 18, 2011, to postpone the effective dates of the final
rule until judicial review has been completed, or the agency finalizes
its reconsideration of the standard, whichever is earlier. In the
action to postpone the effective dates of the rule, the EPA also
requested the public to submit data and information to assist the EPA
in its reconsideration. Following these actions, the Administrator
received several petitions for reconsideration. In response to the
March 21, 2011, notice announcing its intent to initiate
reconsideration and the petitions submitted, the EPA is reconsidering
and requesting comment on several provisions of the final rule.
Additionally, the EPA is proposing amendments and technical corrections
to the final rule to clarify definitions, references, applicability,
and compliance issues raised by stakeholders subject to the final rule.
DATES: Comments. Comments must be received on or before February 21,
2012.
Public Hearing. We will hold a public hearing concerning the
proposed items for reconsideration. Persons interested in presenting
oral testimony at the hearing should contact Ms. Teresa Clemons at
(919) 541-7689 or at clemons.teresa@epa.gov by January 3, 2012. If no
one requests to speak at the public hearing by January 3, 2012, then
the public hearing will be cancelled. We will specify the date and time
of the public hearings on http://www.epa.gov/ttn/atw/boiler/boilerpg.html.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by one of the following methods:
http://www.regulations.gov: Follow the instructions for
submitting comments.
Email: Comments may be sent by email to a-and-r-Docket@epa.gov, Attention Docket ID No. EPA-HQ-OAR-2002-0058.
Fax: Fax your comments to: (202) 566-9744, Attention
Docket ID No. EPA-HQ-OAR-2002-0058.
Mail: Send your comments to: EPA Docket Center (EPA/DC),
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania
Ave. NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2002-0058.
Please include a total of two copies. In addition, please mail a copy
of your comments on the information collection provisions to the Office
of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA,
725 17th St. NW., Washington, DC 20503.
Hand Delivery: In person or by courier, deliver comments
to: EPA Docket Center (2822T), EPA West, Room 3334, 1301 Constitution
Ave. NW., Washington, DC 20460. Such deliveries are only accepted
during the Docket's normal hours of operation (8:30 a.m. to 4:30 p.m.,
Monday through Friday, excluding legal holidays), and special
arrangements should be made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2002-0058. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at http://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be confidential business information (CBI) or other information
whose disclosure is restricted by statute. Do not submit information
that you consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site
is an ``anonymous access'' system, which means the EPA will not know
your identity or contact information unless you provide it in the body
of your comment. If you send an email comment directly to the EPA
without going through http://www.regulations.gov, your email address
will be automatically captured and included as part of the comment that
is placed in the public docket and made available on the Internet. If
you submit an electronic comment, EPA recommends that you include your
name and other contact information in the body of your comment and with
any disk or CD-ROM you submit. If the EPA cannot read your comment due
to technical difficulties and cannot contact you for clarification, the
EPA may not be able to consider your comment. Electronic files should
avoid the use of special characters, any form of encryption, and be
free of any defects or viruses. For additional information about EPA's
public docket, visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the EPA Docket Center,
EPA West Building, Room 3334, 1301 Constitution Ave. NW., Washington,
DC. The Public Reading Room 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
Docket Center is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Mr. Brian Shrager, Energy Strategies
Group, Sector Policies and Programs Division, (D243-01), Office of Air
Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; Telephone number: (919)
541-7689; Fax number: (919) 541-5450; Email address:
shrager.brian@epa.gov.
SUPPLEMENTARY INFORMATION:
Organization of this Document. The following outline is provided to
aid in locating information in this preamble.
I. General Information
A. Does this notice of reconsideration apply to me?
B. What should I consider as I prepare my comments to the EPA?
C. How do I obtain a copy of this document and other related
information?
II. Background Information
III. Summary of This Proposed Rule
A. What is the source category regulated by this proposed rule?
B. What is the affected source?
C. What are the pollutants regulated by this proposed rule?
D. What emission limits and work practice standards must I meet?
E. What are the requirements during periods of startup, shutdown
and malfunction?
[[Page 80599]]
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. How should emissions test results be submitted to EPA?
J. What are the proposed compliance dates?
IV. Actions We Are Taking
V. Discussion of Issues for Reconsideration
A. Surrogates and Selected Regulated Pollutants
B. Output-Based Standards
C. Subcategories
D. Monitoring
E. Emission Limits
F. MACT Floor Methodology
G. Tune-up Work Practices
H. Energy Assessment
I. Affirmative Defense Provisions During Malfunctions
J. Work Practices During Startup and Shutdown
K. Applicability
L. Compliance
M. Other Issues Open for Comment
VI. Technical Corrections and Clarifications
VII. Impacts of This Proposed 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 proposed rule?
G. What are the secondary air impacts?
VIII. Relationship of this Proposed Action to Section 112(c)(6) of
the Clean Air Act
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
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
I. General Information
A. Does this notice of reconsideration apply to me?
The regulated categories and entities potentially affected by this
action include:
------------------------------------------------------------------------
Examples of
Category NAICS code \1\ potentially regulated
entities
------------------------------------------------------------------------
Any industry using a boiler or 211 Extractors of crude
process heater as defined in petroleum and
the proposed rule. natural gas.
321 Manufacturers of
lumber and wood
products.
322 Pulp and paper mills.
325 Chemical
manufacturers.
324 Petroleum refineries,
and manufacturers of
coal products.
316, 326, 339 Manufacturers of
rubber and
miscellaneous
plastic products.
331 Steel works, blast
furnaces.
332 Electroplating,
plating, polishing,
anodizing, and
coloring.
336 Manufacturers of
motor vehicle parts
and accessories.
221 Electric, gas, and
sanitary services.
622 Health services.
611 Educational services.
------------------------------------------------------------------------
\1\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
reconsideration action. To determine whether your facility may be
affected by this reconsideration 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 Institutional Boilers and Process Heaters).
If you have any questions regarding the applicability of the proposed
rule 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. What should I consider as I prepare my comments to the EPA?
Submitting CBI. Do not submit information that you consider to be
CBI electronically through http://www.regulations.gov or email. Send or
deliver information identified as CBI to only the following address:
Mr. Robert Morales, c/o OAQPS Document Control Officer (Room C404-02),
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, Attn: Docket ID No. EPA-HQ-OAR-2002-0058.
Clearly mark the part or all of the information that you claim to
be CBI. For CBI information in a disk or CD-ROM that you mail to the
EPA, mark the outside of the disk or CD-ROM as CBI and then identify
electronically within the disk or CD-ROM the specific information that
is claimed as CBI. In addition to one complete version of the comment
that includes information claimed as CBI, a copy of the comment that
does not contain the information claimed as CBI must be submitted for
inclusion in the public docket. If you submit a disk or CD-ROM that
does not contain CBI, mark the outside of the disk or CD-ROM clearly
that it does not contain CBI. Information marked as CBI will not be
disclosed except in accordance with procedures set forth in 40 CFR part
2.
If you have any questions about CBI or the procedures for claiming
CBI, please consult the person identified in the FOR FURTHER
INFORMATION CONTACT section.
C. How do I obtain a copy of this document and other related
information?
Docket. The docket number for this action and the proposed rule (40
CFR part 63, subpart DDDDD) is Docket ID No. EPA-HQ-OAR-2002-0058.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of this action is available on the WWW through the
Technology Transfer Network (TTN) Web site. Following signature, a copy
of this notice will be posted on the TTN's policy and guidance page for
newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg.
The TTN provides information and technology exchange in various areas
of air pollution control.
[[Page 80600]]
II. Background Information
On March 21, 2011, the EPA issued final standards for new and
existing industrial, commercial, and institutional boilers and process
heaters, pursuant to its authority under section 112 of the Clean Air
Act (CAA). On the same day as this final rule was issued, EPA also
stated in a separate notice that it planned to initiate a
reconsideration of several provisions of the final rule. This
reconsideration notice identified several provisions of the final rule
where additional public comment was appropriate, including:
Revisions to the proposed subcategories.
Establishing a fuel specification through which gas-fired
boilers that use a fuel other than natural gas or refinery gas may be
considered Gas 1 units.
Establishing a work practice standard for limited use
units.
Providing an affirmative defense for malfunction events.
This notice also identified several issues of central relevance to
the rulemaking where reconsideration was appropriate under CAA section
307(d), including:
Revisions to the proposed monitoring requirements for
carbon monoxide for major source boilers.
Revisions to the proposed dioxin emission limit and
testing requirement for major source boilers.
Establishing a full-load stack test requirement for carbon
monoxide coupled with continuous oxygen (oxygen trim) monitoring.
On May 18, 2011, the EPA issued a notice to postpone the effective
dates of the March 21, 2011, final rule. This notice also requested
that the public submit additional data and information to the EPA by
July 15, 2011, for review and consideration in the reconsideration
proceedings. Following promulgation of the final rule, the EPA received
petitions for reconsideration from the following organizations
(``Petitioners''): Alliance for Industrial Efficiency (AIE), U.S. Clean
Heat Power Association (USCHPA), Alyeska Pipeline, American Chemistry
Council (ACC), American Home Furnishings Alliance (AHFA), American Iron
and Steel Institute (AISI), American Coke and Coal Chemicals Institute
(ACCCI), American Municipal Power Inc. (AMP), American Petroleum
Institute (API), National Petrochemical and Refiners Association
(NPRA), Auto Industry Forum (AIF), Citizens Energy Group (CEG), Council
of Industrial Boiler Owners (CIBO), CraftMaster Manufacturing Inc.
(CMI), District Energy St. Paul, Florida Sugar Industry (FSI), Great
Plains Synfuels (GPSP), Hovensa L.L.C., Tesoro Hawaii Corp., Industry
Coalition (AF&PA et. al.), JELD-WEN Inc., Michigan State University
(MSU), Penn State University (PSU), Purdue University, Renovar Energy
Corp., Rochester Public Utilities (RPU), Sierra Club, Southeastern
Lumber Manufacturers Association, State of Washington Department of
Ecology, The Business Council for Sustainable Energy (BCSE), Utility
Air Regulatory Group (UARG), United States Sugar Corporation (U.S.
Sugar), Waste Management Inc. (WM), and Wisconsin Electric Power
Company. Copies of these petitions are provided in the docket (see
Docket ID No. EPA-HQ-OAR-2002-0058). Petitioners, pursuant to CAA
section 307(d)(7)(B), requested that the EPA reconsider numerous
provisions in the rules. In this action, the EPA is proposing multiple
changes to the final rule in response to the reconsideration requests
and the issues that the EPA previously identified as reconsideration
issues. The EPA also is soliciting comment on several provisions of the
final rule for which we are not proposing changes, because the public
did not previously have an opportunity to comment on those provisions.
The issues upon which the EPA is soliciting comment are discussed in
section V of this preamble.
III. Summary of This Proposed Rule
This section summarizes the requirements of this action. Some of
the requirements are currently found in the final boilers rule and are
not being proposed to be revised. Section IV below provides a summary
of the significant changes the EPA is proposing to make in its
reconsideration of the final rule, and on which EPA is soliciting
public comment.
A. What is the source category regulated by this proposed rule?
This proposed rule regulates industrial, commercial, and
institutional boilers and process heaters located at major sources of
hazardous air pollutants (HAP). Waste heat boilers and process heaters
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 proposed
rule.
B. What is the affected source?
This proposed rule affects industrial, commercial, and
institutional 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.
C. What are the pollutants regulated by this proposed rule?
This proposed rule regulates hydrogen chloride (HCl) (as a
surrogate for acid gas HAP), total selected metals (TSM) or particulate
matter (PM) (as a surrogate for non-mercury HAP metals), carbon
monoxide (CO) (as a surrogate for non-dioxin/furan organic HAP),
mercury (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 for each subcategory of units listed in the table. This
proposed rule includes 17 subcategories, which are based on unit
design. New and existing units in 3 of the subcategories would be
subject to work practices standards in lieu of emission limits for all
pollutants. Numeric emission limits are being proposed for new and
existing sources in each of 14 subcategories, which are shown in Table
1 of this preamble.
HCl and Hg are ``fuel-based pollutants'' that directly result from
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 liquid fuel (except as noted in this proposed
rule) 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 the lower contiguous 48 states and Alaska (referred to
as a non-continental unit for the remainder of this preamble and in
this proposed rule), and your new or existing unit combusts liquid fuel
(except as noted in this rule) 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 metal process furnace, limited-use
unit, or Gas 1 unit (that is, it combusts only natural gas,
[[Page 80601]]
refinery gas, or other clean gas that meets the fuel specification,
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, PM (a surrogate for metallic
HAP) and CO (a surrogate for non-dioxin organic HAP), your unit is
subject to the emission limits for the design-based subcategories shown
in Table 1 of this preamble. We also are proposing, as alternatives to
the PM limits, total selected metals emission limits for subcategories
of units that combust solid fuels or Gas 2 fuels. If your new or
existing boiler or process heater burns at least 10 percent biomass on
an annual average heat input \1\ 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 lower contiguous 48 states or Alaska and your new or
existing boiler or process heater burns light liquid fuel (i.e.,
distillate oil, biodiesel, or vegetable 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 light liquid subcategory. If your facility
is located in the lower contiguous 48 states or Alaska and your new or
existing boiler or process heater burns heavy liquid fuel (other
liquids that are not defined as light liquids) and less than 10 percent
coal and less than 10 percent biomass, on an annual average heat input
basis, your unit is in the heavy liquid subcategory. If your non-
continental new or existing boiler or process heater burns liquid fuel
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 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.
---------------------------------------------------------------------------
\1\ 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 gases
from other sources (such as stationary gas turbines, internal
combustion engines, and kilns).
Table 1--Emission Limits for Boilers and Process Heaters
[lb/MMBtu heat input basis unless noted; alternative output based limits are not shown in the summary table
below]
----------------------------------------------------------------------------------------------------------------
Filterable
Particulate Matter Hydrogen
(Filterable PM) chloride (HCl) Mercury (Hg) Carbon Alternate CO
Subcategory (or total selected (lb per MMBtu (lb per MMBtu monoxide(CO) CEMS limit,
metals) (lb per of heat input) of heat input) (ppm @3% (ppm @3%
MMBtu of heat \a\ \a\ oxygen) \a\ oxygen) \b\
input) \a\
----------------------------------------------------------------------------------------------------------------
Existing--Solid fuel........ NA 0.022 3.1E-06 NA NA
Existing--Coal Stoker....... 0.028 (8.3E-05) NA NA 220 34
Existing--Coal Fluidized Bed 0.088 (1.7E-05) NA NA 56 59
Existing--Coal-Burning 0.044 (5.9E-05) NA NA 41 28
Pulverized Coal............
Existing--Biomass Wet Stoker/ 0.029 (5.7E-05) NA NA 790 410
Sloped Grate/Other.........
Existing--Biomass Kiln-Dried 0.32 (0.004) NA NA 250 ND
Stoker/Sloped Grate/Other..
Existing--Biomass Fluidized 0.11 (0.0012) NA NA 370 180
Bed........................
Existing--Biomass Suspension 0.051 (0.0011) NA NA 58 1,400
Burner.....................
Existing--Biomass Dutch 0.036 (2.4E-04) NA NA 810 440
Ovens/Pile Burners.........
Existing--Biomass Fuel Cells 0.033 (4.9E-05) NA NA 1,500 ND
Existing--Biomass Hybrid 0.44 (4.9E-04) NA NA 3,900 730
Suspension Grate...........
Existing--Liquid............ NA 0.0012 2.6E-05 NA NA
Existing--Heavy Liquid...... \c\ 0.062 NA NA 10 18
Existing--Light Liquid...... \c\ 0.0034 NA NA 7 \d\ 60
Existing--non-Continental \c\ 0.0080 NA NA 18 \e\ 91
Liquid.....................
Existing--Gas 2 (Other 0.0067 (2.4E-04) 0.0017 7.9E-06 4 ND
Process Gases).............
New--Solid Fuel............. NA 0.022 8.6E-07 NA NA
New--Coal Stoker............ 0.028 (2.2E-05) NA NA 19 34
New--Coal Fluidized Bed..... 0.0011 (1.7E-05) NA NA 17 59
New--Coal-Burning Pulverized 0.0013 (2.8E-05) NA NA 9 28
Coal.......................
New--Biomass Wet Stoker/ 0.029 (2.6E-05) NA NA 590 410
Sloped Grate/Other.........
New--Biomass Kiln-Dried 0.32 (0.0040) NA NA 250 ND
Stoker/Sloped Grate/Other..
New--Biomass Fluidized Bed.. 0.0098 (4.2E-05) NA NA 230 180
New--Biomass Suspension 0.051 (0.0011) NA NA 58 1,400
Burner.....................
New--Biomass Dutch Ovens/ 0.036 (4.1E-05) NA NA 810 440
Pile Burners...............
New--Biomass Fuel Cells..... 0.011 (4.9E-05) NA NA 210 ND
New--Biomass Hybrid 0.026 (4.9E-04) NA NA 1,500 730
Suspension Grate...........
New--Liquid................. NA 0.0012 4.9E-07 NA NA
New--Heavy Liquid........... \c\ 0.013 NA NA 10 18
New--Light Liquid........... \c\ 0.0011 NA NA 3 \d\ 60
New--Non-Continental Liquid. \c\ 0.0080 NA NA 18 \e\ 91
New--Gas 2 (Other Process 0.0067 (2.4E-04) 0.0017 7.9E-06 4 ND
Gases).....................
----------------------------------------------------------------------------------------------------------------
NA--Not applicable; ND--No data available.
\a\ 3-run average, unless otherwise noted.
\b\ 10-day rolling average, unless otherwise noted.
\c\ Total selected metals alternative limits are not available to units in any of the liquid subcategories.
\d\ 1-day block average.
[[Page 80602]]
\e\ 3-hour rolling average.
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 proposed
rule. Pursuant to CAA section 112(h), the final rule requires a work
practice standard for the following particular classes of boilers and
process heaters: new and existing units that have a designed heat input
capacity of less than 10 MMBtu/hr, new and existing units in the Gas 1
(natural gas/refinery gas) subcategory and in the metal process
furnaces subcategory, and new and existing limited-use units. The work
practice standard for these boilers and process heaters requires the
implementation of a tune-up program. We also are proposing a work
practice standard for dioxin/furan emissions from all subcategories.
Finally, the final rule includes 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 IV of this preamble, of 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?
We are not proposing to change the malfunction provisions in this
rule. See 76 FR 15613. We are proposing revised work practice standards
for periods of startup and shutdown. The final rule required that an
owner/operator must ``Minimize the unit's startup and shutdown periods
following the manufacturer's recommended procedures. If manufacturer's
recommended procedures are not available, you must follow recommended
procedures for a unit of similar design for which manufacturer's
recommended procedures are available.''
While we are maintaining a work practice approach for startup and
shutdown, we are proposing to change the work practice standards to
better reflect the maximum achievable control technology. First, we are
proposing definitions of startup and shutdown. We are proposing to
define startup as the period between the state of no combustion in the
unit to the period where the unit first achieves 25 percent load (i.e.,
a cold start). We are proposing to define shutdown as the period that
begins when a unit last operates at 25 percent load and ending with a
state of no fuel combustion in the unit. For periods of startup and
shutdown, we are proposing the following work practice standard: you
must employ good combustion practices and demonstrate that good
combustion practices are maintained by monitoring O2
concentrations and optimizing those concentrations as specified by the
boiler manufacturer; you must ensure that boiler operators are trained
in startup and shutdown procedures, including maintenance and cleaning,
safety, control device startup, and procedures to minimize emissions;
and you must maintain records during periods of startup and shutdown
and include in your compliance reports the O2 conditions/
data for each startup event, length of startup/shutdown and reason for
the startup/shutdown (i.e., normal/routine, problem/malfunction,
outage). You must comply with all applicable emissions limits at all
times except for startup and shutdown periods, during which times you
must comply with these work practices.
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 conduct performance tests to demonstrate
compliance with all applicable emission limits. An owner or operator of
any affected unit would be required to conduct the following compliance
tests as applicable:
(1) Conduct initial and annual stack tests to determine compliance
with the PM emission limits using EPA Method 5 or 17 or conduct initial
and annual stack tests to determine compliance with the TSM emission
limits using EPA Method 29 for those subcategories with alternate TSM
limits.
(2) Conduct initial and annual stack tests to determine compliance
with the Hg emission limits using EPA Method 29, 30B, 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 are in the sample).
(4) Use EPA Method 19 to convert measured concentration values to
pound per million Btu values.
(5) Conduct initial and annual tests to determine compliance with
the CO emission limits using EPA Method 10 or install, operate, and
maintain CO continuous emission monitoring systems (CEMS) to determine
compliance with the alternate CO CEMS-based emission limits.
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 or TSM (as appropriate), Hg, HCl, and CO 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 parameter average measured during the three test runs (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 across the scrubber 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, 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 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
[[Page 80603]]
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 injection rate
operating limit value.
(4) For boilers and process heaters with fabric filters not subject
to PM Continuous Parametric Monitoring System (PM CPMS) or continuous
compliance with an opacity limit (i.e., continuous opacity monitoring
systems (COMS)), you must operate the fabric filter 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 CPMS is installed
to monitor PM control. For the purposes of the rule, we define a PM
CPMS as a continuous parametric monitoring device based on a detection
principle of light scatter, light scintillation, beta attenuation, or
mass accumulation detection of PM in the exhaust gas or representative
exhaust gas sample, installed and operated on the effluent stack or
duct downstream of any particulate control device(s), and programmed to
provide a continuous electronic signal representative of ongoing
particulate matter control device performance.
(5) For boilers and process heaters with electrostatic
precipitators (ESP) not subject to PM CPMS or continuous compliance
with an opacity limit (i.e., COMS), 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 hourly average total secondary electric power measured
during the three test runs establishes your site-specific minimum
operating limit for the ESP on a 12-hour block average basis.
(6) For boilers and process heaters that choose to demonstrate
compliance with the Hg emission limit by fuel analysis, you must
measure the Hg content of the inlet fuel that was burned during the Hg
performance test. This value is your maximum fuel Hg content operating
limit.
(7) For boilers and process heaters that choose to demonstrate
compliance with the HCl emission limit by fuel analysis, you must
measure the chlorine content of the inlet fuel that was burned during
the HCl performance test. This value is your maximum fuel chlorine
content operating limit.
(8) For boilers and process heaters that choose to demonstrate
compliance with the total selected metals emission limit on the basis
of fuel analysis, you are required to measure the total selected metals
content of the inlet fuel that was burned during the total selected
metals performance test. This value is your maximum fuel total selected
metals content operating limit.
(9) For boilers and process heaters that are subject to a CO
emission limit, you must record the oxygen concentration representative
of your boiler operation (e.g., oxygen trim) during the initial
performance test.
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. Instead, if requested, owners or operators of such boilers and
process heaters shall submit to the delegated authority or the EPA, as
appropriate, 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
actions:
(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 the system 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 any adjustments
related to the tune-up are made,
(6) Submit to the delegated authority or the EPA an annual report
containing the concentrations of CO in the effluent stream in ppmvd and
oxygen in percent dry basis, both measured before and after the
adjustments of the unit; 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 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 the EPA, as appropriate,
documentation that an energy assessment was performed by a qualified
energy assessor and documentation of the cost-effective energy
conservation measures indentified by the energy assessment.
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 or residual fuel oil (i.e., No. 4, 5
or 6 fuel oil) with average annual heat input rate of less than 250
MMBtu/hr (from the combustion of those fuels) or any units in the
biomass subcategories and all biomass units that do not use a wet
scrubber, opacity levels must be maintained to less than 10 percent
(daily average) for existing and new units with applicable emission
limits. If the unit is controlled with a fabric filter, instead of
being subject to continuous opacity monitoring, 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 CPMS is used).
(2) For units combusting coal or residual oil with heat input
capacities of 250 MMBtu/hr or greater from the combustion of those
fuels, the EPA is proposing the collection of data using a PM CPMS at
all times that the unit is subject to numeric emission limits, with the
exception of periods of PM CPMS repair, malfunction, scheduled
maintenance, or QA/QC related activities. The operating unit will
prepare, and submit for approval, a site-specific monitoring plan that
addresses the PM CPMS design, data collection, and the QA/QC elements
outlined in 63.8(d), including the performance criteria and design
specifications for the monitoring system equipment, the sample
interface location, frequency of quality control checks, frequency of
system performance evaluations, ongoing operation and maintenance
procedures as well as ongoing reporting and recordkeeping procedures.
An annual deviation report must be submitted detailing data collected
during periods of boiler startup, shutdown or malfunction and PM CPMS
malfunction, repair, or other QA/QC related activity. Records of these
data must be available on site for inspection, including corrective
actions necessary to return the PM CPMS to operation consistent with
the site specific monitoring plan. The operating unit will use output
data collected from the CPMS (milliamps, milligrams per actual cubic
meter, or other instrument output)
[[Page 80604]]
during all other operating hours where numeric emission limits apply to
assess compliance with the operating limit. An arithmetic average of
the measurement output values collected during each hour will be
calculated, and for each operating day the arithmetic average of all
hourly measurement output values will be calculated for the previous 30
operating days. You must transmit four reports per year for each PM
CPMS to the EPA's WebFIRE database by using the Compliance and
Emissions Data Reporting Interface, or CEDRI, that is accessed through
the EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Complete
reports must be submitted within 60 days after March 31st, June 30th,
September 30th, and December 31st. Complete reports contain daily PM
CPMS rolling 30-day average values for the periods that end with each
of the 4 previously mentioned dates.
(3) For boilers and process heaters with wet PM scrubbers, you must
monitor pressure drop and liquid flow rate of the scrubber and maintain
the 30-day rolling 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 30-day rolling 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, you must
continuously monitor the sorbent injection rate and maintain the hourly
average 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 not required to install a CPMS
and having an ESP installed, you must monitor the voltage and current
of the ESP collection plates and maintain the 30-day rolling average
total secondary electric power at or above the operating limits
established during the Hg, PM, or TSM performance test.
(7) For units that choose to comply with either the Hg emission
limit, the HCl emission limit, or TSM emission limit (solid fuel units
only) 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,
chlorine content, or TSM content of the inlet fuel was maintained at or
below your maximum fuel Hg content operating limit, your chlorine
content operating limit, or your TSM 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, maximum chlorine input, and/or maximum TSM 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, you must install, calibrate
and operate an oxygen trim system in order to ensure efficient
combustion and compliance with the CO standards.
(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 or 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
certifications of compliance with rule requirements in the notification
of compliance status report.
This proposed rule would require records to demonstrate compliance
with each emission limit, operating limit and work practice standard,
as specified in the General Provisions. 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 and
limited 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
continuous monitoring systems (CMS) data are required.
You are required to keep the following records:
(1) All reports and notifications submitted to comply with the
rule.
(2) Continuous monitoring data as required in the rule.
(3) Each instance in which you did not meet each emission limit and
each operating limit (i.e., deviations from the 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 the rule, for each affected source with an applicable
HCl emission limit.
(7) Calculations and supporting information of Hg fuel input, as
required in the rule, for each affected source with an applicable Hg
emission limit.
(8) A paragraph that discusses calculations and supporting
information of TSM fuel input, as required in the rule, for each
affected source with an applicable total selected metals emission
limit.
(9) A signed statement, as required in the 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.
[[Page 80605]]
(10) A signed statement, as required in the 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.
(11) A signed statement, as required in the rule, indicating that
you burned no new fuels and no new fuel mixture or that the
recalculation of total selected metals fuel input demonstrated that the
new fuel or new fuel mixture still meets the total selected metals fuel
input levels, for each affected source with an applicable total
selected metals emission limit.
(12) A copy of the results of all performance tests, fuel analyses,
opacity observations, performance evaluations, or other compliance
demonstrations conducted to demonstrate initial or continuous
compliance with the rule.
(13) A copy of your site-specific monitoring plan developed for the
rule as specified in 63 CFR 63.8(e), if applicable.
(14) A copy of your fuel analysis plan at least 60 days prior to
demonstrating initial compliance.
You also are required to 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 to occur.
(4) Notification of Compliance Status 60 calendar days following
completion of the performance test and/or compliance demonstration.
(5) Compliance reports semi-annually.
I. How should emissions test results be submitted to the EPA?
The EPA must have performance test data to conduct effective
reviews of CAA sections 112 standards, as well as for many other
purposes including compliance determinations, emission factor
development, and annual emission rate determinations. In conducting
these required reviews, the EPA has found it ineffective and time
consuming, for us, for regulatory agencies and for source owners and
operators, to locate, collect, and submit performance test data because
of varied locations for data storage and varied data storage methods.
In recent years, however, stack testing firms have typically collected
performance test data in electronic format, making it possible to move
to an electronic data submittal system that would increase the ease and
efficiency of data submittal and improve data accessibility.
In this proposal, the EPA is presenting a step to improve the ease
and efficiency of data submittal and increase data accessibility.
Specifically, the EPA is proposing that owners and operators of
industrial, commercial, and institutional boilers and process heaters
submit electronic copies of required performance test reports to EPA's
WebFIRE database. The WebFIRE database was constructed to store
performance test data for use in developing emission factors. A
description of the WebFIRE database is available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
Data entry would be through an electronic emissions test report
structure called the Electronic Reporting Tool (ERT). The ERT would be
able to transmit the electronic report through the EPA's CDX network
for storage in the WebFIRE database making submittal of data very
straightforward and easy. A description of the ERT can be found at
http://www.epa.gov/ttn/chief/ert/index.html.
The proposal to submit performance test data electronically to the
EPA would apply only to those performance tests conducted using test
methods that will be supported by the ERT. The ERT contains a specific
electronic data entry form for most of the commonly used EPA reference
methods. A listing of the pollutants and test methods supported by the
ERT is available at http://www.epa.gov/ttn/chief/ert/index.html. We
believe that industry would benefit from this proposed approach to
electronic data submittal. With these data, the EPA would be able to
develop improved emission factors, make fewer information requests, and
promulgate better regulations.
One major advantage of the proposed submittal of performance 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 rule. Another advantage is that the ERT clearly states what
testing information would be required. Another important proposed
benefit of submitting these data to the EPA at the time the source test
is conducted is that it should substantially reduce the effort involved
in data collection activities in the future. If the EPA has performance
test data from these submittals, the EPA will likely need fewer or less
substantial data collection requests in conjunction with prospective
required residual risk assessments or technology reviews. This would
reduce the burden on both affected facilities (in terms of reduced
manpower to respond to data collection requests) and the EPA (in terms
of preparing and distributing data collection requests and assessing
the results).
State, local, and tribal agencies could also benefit from more
streamlined and accurate review of electronic data submitted to them.
The ERT would allow for an electronic review process rather than a
manual data assessment, making review and evaluation of the source
provided data and calculations easier and more efficient. Finally,
another benefit of the proposed data submittal to WebFIRE
electronically is that these data would greatly improve the overall
quality of existing and new emissions factors, by supplementing the
pool of emissions test data for establishing emissions factors and by
ensuring that the factors are more representative of current industry
operational procedures. A common complaint from industry and regulators
is that emission factors are outdated or do not represent a particular
source category. With timely receipt and incorporation of data from
most performance tests, the EPA would be able to ensure that emission
factors, when updated, represent the most current range of operational
practices. In summary, in addition to supporting regulation
development, control strategy development and other air pollution
control activities, having an electronic database populated with
performance test data would save industry, state, local, tribal
agencies and the EPA significant time, money, and effort while also
improving the quality of emission inventories and, as a result, air
quality regulations.
J. What are the proposed compliance dates?
The EPA is proposing to reset the compliance date for existing
sources to the date 3 years after the date of publication of the final
reconsideration rule. For new sources, the EPA is proposing to change
the compliance date to 60 days after the date of publication of the
final reconsideration rule or upon startup, whichever is later. We are
not proposing to change the date that identifies whether a source is
new or existing. This date, June 4, 2010, is the publication date of
the original proposed rule.
[[Page 80606]]
IV. Actions We Are Taking
In this notice, we are granting reconsideration of, and requesting
comment on, issues presented in the March 21, 2011, reconsideration
notice as well as a subset of other issues raised by petitioners in
their petitions for reconsideration. Section V of this preamble
summarizes these issues and discusses our proposed responses to each
issue.
We have revised the rule language to address provisions related to
the reconsideration and are requesting comment on the revised rule text
to clarify definitions, applicability, compliance and references to
various sections of the rule. Finally, we are proposing technical
corrections to certain applicability and compliance provisions in the
final rule.
We are seeking public comment only on the issues specifically
identified in Section V of this action. We will not respond to any
comments addressing other aspects of the final rule or any other
related rulemakings.
V. Discussion of Issues for Reconsideration
This section of the preamble contains EPA's basis for our responses
to certain issues identified in the petitions for reconsideration and
the changes to the rule that we are proposing. We solicit comment on
all responses and revisions discussed in the following sections:
A. Surrogates and Selected Regulated Pollutants
1. Alternative Total Selected Metals Limit. Multiple petitioners
requested that EPA include an emission limit for TSM as an alternative
to the PM limits in the final rule, particularly for biomass units, as
part of the reconsideration. After assessing the available data, the
EPA determined that inclusion of these limits is appropriate for some
subcategories, and the EPA is proposing TSM limits for each subcategory
of units that combust solid fuels or Gas 2 fuels. Sources will have the
option of meeting either the TSM limit or the alternative PM limit. The
TSM measurement, which directly quantifies the HAP metals rather than
relying on a surrogate, is a more direct measurement of HAP than PM and
is, therefore, appropriate as a pollutant group for regulation with
numeric emission limits. For this rule, TSM includes the following
eight metals: Arsenic, beryllium, cadmium, chromium, lead, manganese,
nickel, and selenium. The EPA selected these eight metals, rather than
all of the HAP metals other than Hg, because more test data are
available for these metals than for the other two HAP metals, cobalt
and antimony. The use of 8 of 10 metals should have little or no impact
on a facility's selection of controls to meet the standards, and the
controls that would be used to reduce emissions of the eight metals
would be equally effective in reducing emissions of the other two
metals. Therefore, TSM can serve as a surrogate for all metallic HAP
except for Hg, which the final rule regulates separately.
For the light liquid, heavy liquid and non-continental liquid units
subcategories, we are not proposing alternative TSM emission limits.
Instead, we are proposing that these units meet the filterable PM
emission limits in all instances. We are not proposing the TSM
alternative because of the limited emission test data for TSM and the
large variability in the TSM data for these subcategories. Using the
EPA's maximum achievable control technology (MACT) floor methodology,
the alternative TSM limits resulted in MACT floor values which do not
appear to represent the actual performance of the best performing
units. The EPA has sent follow-up inquiries to facilities to confirm
these data, and is soliciting comment on whether alternative TSM limits
are appropriate for the subcategories of units designed to combust
liquid fuels. The EPA also is soliciting comment on whether an
alternative approach to calculating the TSM MACT floors for these units
is appropriate. If the EPA receives sufficient information that
supports the alternative TSM standards for units designed to combust
liquid fuels, we will consider adopting these limits in the final rule.
2. Work Practice for Dioxin/Furan Emissions. Multiple petitioners
requested that EPA reassess the potential for applying work practice
standards for dioxins/furans in lieu of numeric emission limits. The
EPA has re-assessed the dioxin/furan data sets and has determined that,
similar to data for electric utilities for which work practice
standards were proposed for dioxins/furans, the large majority of the
emission measurements for all of the subcategories are below the level
that can be accurately measured using EPA Method 23. While the EPA
recognized this as an issue prior to issuing the final rule, sufficient
time was not available to fully analyze the issue. For this proposal,
the EPA conducted extensive analyses to determine the lowest level of
emissions that can be accurately measured using EPA Method 23. The
percentages of measurements (test runs) below the method detection
level (a level at which the pollutant is known to be present but is not
accurately quantified) is about 55 percent, which is 10 percent lower
than the percentage for electric utilities. However, in addition to the
high percentage of measurements below the method detection level, a
very high percentage of measurements are below the level that can be
accurately measured (see section V.E.3 of this preamble) for each
subcategory. Those percentage are as follows: Coal stoker--100 percent;
coal fluidized bed--89 percent; pulverized coal--85 percent; biomass
stoker/other--100 percent; biomass fluidized bed--100 percent; biomass
dutch oven/pile burner--80 percent; biomass fuel cell--100 percent;
heavy liquid--96 percent; light liquid--100 percent; gas 2 (other
process gases)--100 percent; non-continental liquid--100 percent (based
on No. 6 oil data). While data are not available for two of the biomass
subcategories, there is no reason to believe that dioxin emissions for
those subcategories would be different than for the other biomass-based
subcategories. Based on the percentages of data below the method
detection limit coupled with the percentage of data below the level
that can be accurately quantified, the EPA concludes that emissions
from industrial boilers and process heaters cannot practicably be
measured, and the EPA is now proposing work practice standards in place
of numeric emission limits for dioxin/furan. The work practice
standards require an annual tune-up to ensure good combustion. Details
on the assessment of the minimum level that can be accurately measured
can be found in the docket memorandum entitled ``Updated data and
procedure for handling below detection level data in analyzing various
pollutant emissions databases for MACT and RTR emissions limits.'' We
do not expect that the change from numeric emission limits to work
practice standards will result in less public health protection because
the levels of dioxin emitted from units in the source category are at
or near current detection level capabilities, and we are not aware of
any emissions controls that are demonstrated to reduce dioxin emissions
from the low levels indicated by the available data for boilers and
process heaters.
B. Output-Based Standards
1. Revisions to Boiler Efficiency Analysis
Petitioners requested that the EPA reassess the calculation of
boiler efficiency, which is the key calculation in the development of
output-based standards, because the EPA's
[[Page 80607]]
calculations often resulted in efficiencies that were unrealistically
high, often above 100 percent, which is a physical impossibility. The
petitioners attributed this to the fact that the EPA had disregarded
feedwater temperature (industry average being 280 degrees F). The
inclusion of feedwater temperature provides the correct assessment of
boiler efficiency because it accounts for the heat energy that is
supplied by steam from the boiler to heat the feedwater. The steam used
to heat the feedwater is supplied by the boiler and was reported by
facilities as part of the boiler ``steam output,'' but was not
accounted for in the final rule efficiency calculations. Thus, the EPA
has modified the development of the revised output-based emission
limits to include the heat (energy) associated with the feedwater. The
revised boiler efficiencies of the best performing units for each
subcategory were determined by the equation:
Boiler Efficiency = (Steam output (Btu) - Feedwater Input (Btu))/(Fuel
Input (Btu))
To calculate ``feedwater input (Btu)'', we used the industry
average temperature of 280 degrees F and determined a heat content
value of 249.3 Btu/lb. Unit operators provided the ``steam output
(Btu)'' for each best performing unit in response to the EPA's
information gathering efforts. For all best performing units reporting
this steam energy output data, we calculated boiler efficiencies, as
well as corresponding input-to-output conversion factors (CF). We
averaged CF from the best performing units that have realistic boiler
efficiencies averaged and assigned a subcategory-specific conversion
factor. Finally, we applied the revised average CF to the proposed
input-based emission limits to develop the revised alternate output-
based limits. The resultant proposed output-based limits provide a
compliance option that achieves emission reductions equivalent to those
achieved by the input-based limits and encourage energy efficiency.
2. Other Changes to Output-Based Provisions
a. Accommodating Emissions Averaging Provisions. In order to allow
for emissions averaging for units that elect to comply with the output-
based emission limits, the EPA is proposing to add additional equations
to the rule to allow for emissions averaging as requested by
petitioners. Averaging of output based limits was not included in the
final rule due to time constraints, but there is no technical reason
why averaging of output-based limits is inappropriate. The output-based
limits are equivalent to the input-based limits and promote energy
efficiency, and, therefore, EPA is proposing to allow averaging for
units that elect to comply with the output-based standards.
b. Output-Based Standards for Units that Generate Electricity.
Petitioners pointed out that the final output-based standards were not
designed to consider efficiency improvements from units that generate
electricity only. In response to this concern, the EPA is proposing to
add language to the definition of ``Steam output'' that addresses
boilers that only produce electricity. The language provides fuel-
specific conversion factors for electricity generating units that
result in output-based standards in units of pounds per megawatt-hour.
c. Clarification that output-based standards are alternative
standards. Petitioners requested that the EPA clarify in the tables
that the output-based standards are alternative standards to the input-
based standards. The EPA is proposing regulatory text to make this
clarification.
d. Legal Authority for Emission Credits. One petitioner questioned
the legal authority of the emission credit system and stated that it
should be removed from the final rule. However, the petitioner provided
no support for its position, and the EPA continues to believe that the
emission credit system is consistent with the CAA as promulgated.
Therefore, no changes are being proposed. However, we are specifically
requesting comment on: (1) The overall concept of the emission credit
provision, (2) how to administer it consistently across the country,
and (3) available guidelines to inform the delegated authority's
decision to approve the implementation plan.
C. Subcategories
In the final rule, the EPA added subcategories for hybrid
suspension/grate biomass units, limited-use units, solid fuel units,
and non-continental liquid units. The EPA also added a fuel
specification to the final rule that would allow units combusting gases
not defined as ``Gas 1'' gases to qualify as Gas 1 units by
demonstrating that the fuels combusted meet a fuel specification.
Petitioners requested that EPA allow comment on these subcategory
changes and the fuel specification, and EPA is now soliciting comments
on these portions of the final rule, including the changes and
particular issues described in sections [1 through 7] below.
Petitioners also requested additional subcategories, clarification of
several subcategory definitions, and changes to some of the subcategory
definitions.
1. Solid Fuel. The EPA added a solid fuel subcategory to the final
rule that replaced previously proposed separate subcategories for units
designed to burn solid fossil-based fuels and units designed to burn
solid bio-based fuels. The solid fuel subcategory applied to pollutants
identified in the final rule as fuel-based pollutants (PM, HCl, and
Hg). Standards for combustion-based pollutants (CO and dioxin/furan),
however, were based on specific subcategories for the various types of
combustion units, including the specific fuel types the units were
designed to combust. The rationale for the change is presented in the
preamble to the final rule and the EPA is, in this action, soliciting
comments on the solid fuel subcategory.
One significant change is also being proposed related to the solid
fuel subcategory. Several petitioners provided information to support
the position that PM should be considered a combustion-based pollutant
rather than a fuel-based pollutant. After assessing the points raised
by the petitioners, the EPA determined that PM emissions are influenced
both by fuel type and unit design. Therefore, it is appropriate to
treat PM as a combustion-based pollutant. Differences in PM particle
size, applicability of air-pollution controls to units combusting
various fuels, and the lack of demonstration of certain control
technologies on certain designs of boilers (e.g., fabric filters are
not used on any hybrid suspension grate boilers) suggest that PM is
more appropriately classified as a combustion-based pollutant.
Therefore, the EPA is now proposing separate PM limits for each
``combustion-based'' subcategory.
Emission limits for HCl and Hg were developed for the same
subcategories as presented in the March 21, 2011, final rule; the only
changes associated with the HCl and Hg emission limits are due to new
data, corrections to old data, and inventory changes.
2. Units Designed to Combust Liquid Fuels. The EPA finalized a
single subcategory covering liquid fuel-fired units (with limited
exceptions such as non-continental liquid units and limited-used
units). Petitioners requested that the EPA reconsider the liquid unit
subcategories and include separate subcategories for units designed to
combust light liquids and units designed to combust heavy liquids.
Petitioners cited issues related to achievability of standards and the
types of controls that are used on liquid units but did not cite design
differences
[[Page 80608]]
that could be used to justify a subcategory. However, we identified
several design differences, including the need for steam atomization or
high-pressure atomization of heavy liquids, the need for heated storage
vessels for heavy liquids in some climates, and the lack of a
demonstration that the new source PM limit based on combustion of light
liquid fuels had been achieved by any unit combusting heavy liquid
fuels. Therefore, the EPA is proposing separate subcategories for heavy
liquid-fired and light liquid-fired units for PM and CO, pollutants
that are dependent on combustor design. Units designed to combust light
and heavy liquids will continue to be grouped together in a liquid fuel
subcategory for Hg and HCl, which are the fuel-based pollutants. Light
liquids include distillate oil, biodiesel and vegetable oil. Heavy
liquids include all other liquid fuels that are combusted in boilers,
including byproduct liquid fuels generated at industrial facilities and
residual oil. Units that combust any liquid fuels (and less than 10
percent coal/solid fossil fuel and less than 10 percent biomass/bio-
based solid fuel) where at least 10 percent of the heat input from
liquid fuels on an annual heat input basis comes from heavy liquids
would be considered heavy liquid units. Units that combust any liquid
fuels (and less than 10 percent coal/solid fossil fuel and less than 10
percent biomass/bio-based solid fuel) that are not part of the unit
designed to burn heavy liquid subcategory would be considered light
liquid units.
3. Non-Continental Liquid Units. The EPA finalized a subcategory
for non-continental liquid units. Stakeholders did not have the
opportunity to comment on this subcategory. Therefore, the EPA is now
soliciting comments on the non-continental liquid unit subcategory. The
preamble to the final rule presents the rationale for the establishment
of the subcategory. See 76 FR 15635. The EPA also is proposing to
revise several of the emission limits for non-continental liquid units
due to the receipt of new emissions data for PM and CO from these units
and the development of performance estimates based on the combustion of
No. 6 fuel oil (rather than all types of liquid fuels). The rationale
for estimating the performance of these units based on data from No. 6
oil units is presented below. Petitioners pointed out that non-
continental units do not combust distillate oil because of availability
issues. While non-continental liquid units typically combust refinery
gas, they combust residual oil when process requirements necessitate
supplementing the available refinery gas. The petitioners requested
that, in the absence of data from non-continental units, emission
limits for non-continental units be based on data from liquid units
that combust residual oil. The EPA agrees that it would be appropriate
to make this change for the combustion-based pollutants due to the
design of these units and the unique constraints faced by these units.
We now have data for both CO and PM from non-continental units, and
there are no longer data gaps for these pollutants. We are thus able to
establish numeric emission limits using data from within the
subcategory. For fuel-based pollutants, Hg and HCl, the EPA determined
that, based on the very limited data sets and the overlap of data for
units designed to combust various liquid fuels, it is more appropriate
to consider all liquid fuel-fired units together for the development of
MACT emission limits. This is consistent with the treatment of Hg and
HCl for solid fuel units.
4. Liquid Units in Alaska. A petitioner requested that liquid units
in Alaska be included in the non-continental liquid unit subcategory or
in a separate, newly created subcategory for units in Alaska. The
petitioner stated that units in Alaska face the same difficulties with
respect to the available supply of natural gas or refinery gas as the
non-continental units. The commenter did not provide specific design
differences from other types of liquid units. In addition, no test data
are available for liquid-fired units in Alaska. Finally, while units in
Alaska may face some unique constraints, the design of such units is
different from the non-continental units because the units are designed
to combust different fuels (i.e. non-continental units combust No. 6
fuel oil, which was not reported as a fuel for any unit in Alaska in
the responses to the EPA's information collection request). For these
reasons, the EPA is not proposing a subcategory for liquid units in
Alaska and is not including these units in the non-continental
subcategory. The EPA is, however, soliciting comment and supporting
rationale on whether a subcategory for liquid units in Alaska is
appropriate, and is requesting stack test data that could be used to
establish MACT floors if such a subcategory is justified.
5. Biomass. Petitioners requested additional biomass subcategories
and clarifications to the final subcategories. Suggestions included
separate subcategories (for all pollutants) for boilers that are
designed to combust kiln-dried wood and for hybrid suspension grate
boilers designed to combust bagasse, clarification of which subcategory
covers pile burners, and separation of the dutch oven and suspension
burner subcategories. In addition to soliciting comment on the proposed
changes described below, the EPA is requesting comment on whether
additional subcategories are appropriate, as well as data and rationale
in support of any additional subcategories.
a. Boilers Designed to Combust Kiln-Dried Wood. With respect to a
separate subcategory for boilers designed to combust kiln-dried wood,
the EPA is proposing a separate subcategory for these units based on
the design of the boilers and the unique nature of the facilities that
combust this material. These facilities are carefully integrated to
utilize their available resources on-site, and the boilers are designed
and sized to efficiently combust biomass that has already undergone a
drying process that enhances the fuel quality. Care is taken within the
facility to maintain the fuel moisture content at levels far lower than
virgin biomass materials, typically less than 2 percent moisture. The
EPA is proposing emission limits for PM and CO for this subcategory of
units that we are calling biomass dry stokers. For HCl and Hg, the
final rule's approach of regulating these pollutants under the ``solid
fuel subcategory'' for all solid fuel units has not changed.
b. Hybrid Suspension Grate Boilers Designed to Combust Bagasse. In
the final rule, the EPA added a subcategory for hybrid suspension/grate
boilers, which included boilers that are designed to combust very wet
biomass fuels such as bagasse. The rationale for the establishment of
the subcategory is presented in the preamble to the final rule. See 76
FR 15634-15635. Petitioners pointed out that in addition to their
unique designs that provide fuel drying within the combustor, these
units are highly integrated into the sugar production process and
primarily combust specific materials that are generated on-site.
Petitioners emphasized that the particle size profile from these units
differs significantly from units designed to combust other types of
fuels. As discussed in section V.C.1 of this preamble, the EPA is now
considering PM to be a ``combustion based'' pollutant. Accordingly, the
EPA is proposing emission limits for PM (along with an alternate TSM
standard) and CO for these types of units. For HCl and Hg, the final
rule's approach of regulating these pollutants under the
[[Page 80609]]
``solid fuel subcategory'' for all solid fuel units has not changed.
c. Clarification of Subcategories for Pile Burners, Dutch Ovens,
and Suspension Boilers. The final rule did not address pile burners,
and it established a single subcategory that covered dutch ovens and
suspension boilers. Petitioners pointed out that dutch ovens and
suspension boilers are inherently different types of boilers and
requested EPA to create separate subcategories for those types of
units. Petitioners also pointed out that pile burners are very similar
to dutch ovens, and, as such, should be included in the dutch oven
subcategory. The EPA evaluated these clarification requests and
determined that the petitioners' points regarding the design and other
differences between dutch ovens and suspension boilers are valid. The
EPA agrees that dutch ovens and pile burners should be included in the
same subcategory and suspension burners should be a separate
subcategory. Therefore, the EPA is proposing separate emission limits
for the combustion-based pollutants for these subcategories. All of
these types of units will remain in the solid fuel subcategory for the
fuel-based pollutants.
6. Gaseous Fuel Specification. Multiple petitioners requested
reconsideration of the fuel specification that the EPA finalized but
did not propose. Petitioners correctly pointed out that the levels of
the fuel specification were based only on natural gas and suggested
that it would be appropriate to base the fuel specification on levels
of contaminants in either natural gas or refinery gas. Petitioners
further pointed out that a fuel specification for hydrogen sulfide
(H2S) is not directly related to potential HAP emissions
from boilers and process heaters and the H2S fuel
specification should be eliminated from the rule. The EPA has
reexamined the fuel specification and agrees that the key contaminant
for demonstration of comparability from a HAP perspective is Hg and
that the H2S fuel specification that was finalized does not
provide a direct indication of potential HAP from combustion of gaseous
fuel. Accordingly, the EPA is proposing a fuel specification based only
on the Hg level in the gaseous fuel, and that level is the same level
that the EPA included in the March 2011 final rule. The rationale for
the Hg fuel specification is included in the preamble to the final
rule. See 76 FR 15639.
One petitioner stated that the inclusion of a fuel specification
demonstrates that emissions can be measured from the units that combust
the gaseous fuels, and therefore, the units cannot be regulated by a
work practice standard. Regarding this point, the EPA recognizes that
the contaminants in the fuel may be able to be measured, but the
resulting emissions from combustion of the fuel are another matter
entirely. For instance, a unit that combusts a fuel that meets the fuel
specification for Hg will have demonstrated that its fuel contains an
amount of Hg that is comparable to that found in natural gas. The
emissions data for natural gas-fired units show the overwhelming
majority of emissions to be below the level that can be accurately
quantified by the available test methods. Therefore, the same is
expected of units combusting gases with similar contaminant levels to
natural gas. Thus, a work practice standard is the appropriate standard
for these units. The EPA also is requesting comment on whether
additional parameters should be included in the fuel specification.
7. Work Practices for Limited-Use Units. The EPA added a
subcategory for limited-use units in the final rule, and petitioners
requested an opportunity to comment on the creation of the subcategory
and the definition of the subcategory. Specifically, multiple
petitioners requested that rather than defining the subcategory to
include units that operate less than 10 percent of the hours in a year,
the EPA define the subcategory to include units that operate with a
capacity factor of 10 percent or less. The petitioners believe that
such a change would provide more flexibility, but petitioners did not
provide support that such a subcategory would qualify for work practice
standards under section 112 the CAA. Therefore, the EPA is not
proposing a change to the final approach but is requesting comment on
how a subcategory defined with a 10 percent capacity factor would
qualify for work practice standards in lieu of emission limits. The EPA
also is requesting comment on the limited-use subcategory as finalized,
and the rationale for the creation of that subcategory can be found in
the preamble to the final rule. See 76 FR 15634.
D. Monitoring
1. Oxygen monitoring. Petitioners requested reconsideration of the
requirement for installation of oxygen monitoring systems on the outlet
of the boiler combustion chamber for numerous technical reasons.
Several parties expressed concern regarding this location as it is
known to be highly stratified, making it very difficult to find a
representative location and certify the instrumentation. In reviewing
alternatives to this requirement we find that rather than requiring
monitoring of oxygen levels in the stack that follows a combustion
unit, a better way to ensure good combustion is by requiring the
installation, calibration, monitoring and use of oxygen trim systems to
optimize air to fuel ratio and combustion efficiency. We agree with
petitioners that use of the data from such devices is not only an
appropriate control for efficient combustion and a less burdensome
alternative to monitoring stack oxygen concentration but also is a
better system for many types of units that experience significant load
swings and operate with high levels of excess air. Many units are
already fitted with these controls, and this proposed change will
reduce the monitoring burden for affected units. These systems will
provide adequate combustion control to maintain compliance with the CO
emission levels demonstrated during the performance test. We seek
comment on the appropriateness of using these controls operated as, and
for the purposes, described.
2. PM CEMS. Petitioners requested reconsideration of the use of PM
CEMS as compliance monitors for coal, biomass and residual oil units
with heat input capacity greater than 250 MMBtu/hr. Petitioners
emphasized that PM CEMS are not demonstrated for biomass units and
requested EPA to remove the requirement because of technical issues
related to PM particle size and the inability of PM CEMS effectively
measure PM from biomass units. Petitioners also stated that PM CEMS are
not demonstrated at the low levels that are required by the rule. The
EPA agrees that PM CEMS are not demonstrated for biomass units and that
significant technical concerns exist regarding the technology's ability
to monitor emissions from biomass units. The technical concerns include
the fact that PM CEMS are calibrated and certified to measure emissions
from a single fuel type. A change in fuel would require a change in the
calibration curve of the PM CEMS instrument. The unpredictable variety
of biomass fuel constituents as well as biomass fuel moisture content
make relying on a single calibration point problematic in terms of
compliance assessment when these fuel components change. Furthermore,
it is impracticable to replicate, during performance testing, all of
the varying fuel conditions necessary for calibrating the monitor. For
all of these reasons, it is impractical to appropriately apply PM CEMS
to provide the accuracy necessary for
[[Page 80610]]
compliance assessment. Accordingly, we are proposing to remove the PM
CEMS requirement for biomass units.
Relative to application for other boiler units, several parties
expressed concern over the state of readiness of current PM CEMS
technology, certification methodology and the technical effort and cost
required for the recertification necessary to handle changing fuel and
control operating conditions. In our reevaluation of this technology we
find that PM monitoring technology would best be employed as parametric
monitors (PM CPMS) and used to determine compliance with operating
limits rather than emissions limits. This approach reduces the burden
of certification of the monitor, which can be a substantial annual
cost, and maintains our goals of seeking continuous data monitoring of
the source particulate mass emission rate as a 30-day rolling average.
We seek comment on the use of these monitors as described in the rule.
3. CEMS Alternative for Hg. Petitioners requested reconsideration
of the absence of an option to use Hg CEMS for compliance demonstration
and monitoring for units subject to Hg limits whose operators do not
want to rely on periodic testing, fuel sampling analysis, and parameter
monitoring. We have included options in the proposed rule for the use
of Hg CEMS. We seek comment on the use of these monitors as described
in the rule.
4. Use of sulfur dioxide (SO2) CEMS for demonstrating continuous
compliance with HCl emission limits. A petitioner requested that the
EPA consider adding a provision to the rule to allow for the use of
SO2 CEMS for demonstration of continuous compliance with the
HCl emission limits for sources that are equipped with acid gas
controls. While the EPA does not have enough information to propose
specific requirements, we believe that a reasonable approach would be
to allow for the use of SO2 CEMS provided that the source
demonstrates a correlation between SO2 control and control
of other acid gases emitted from each specific unit that chooses to use
SO2 CEMS. Such a relationship is expected because the
available add-on controls for acid gases would provide better control
efficiencies for the acid gas HAP than for SO2, and,
therefore, demonstration of SO2 control using CEMS would
provide assurance that the acid gas HAP are being controlled.
Therefore, the EPA is soliciting comment on the use of SO2
CEMS for demonstrating continuous compliance with the HCl emission
limits with the condition noted above.
5. Minimum Data Availability Provisions. Petitioners noted that the
requirement to operate any CMS and collect data at all times is
unrealistic and that the agency should include a reasonable minimum
data availability limitation allowing for CMS downtime. We have not
included any specific minimum data availability requirement for CEMS or
other monitoring in the final rule. We disagree with petitioners that
we are establishing unreasonable monitoring operating requirements with
this rule. Instead, we believe that we are reiterating the source
owner's responsibility to operate and maintain the CMS in accordance
with existing rules. For example, section 63.8(c) already requires that
the source operate the CMS consistent with good air pollution control
practices and that the CMS be in continuous operation in accordance
with a written quality control program. The final rule clarified that
continuous operation does not include periods when the process is not
operating and the requirements delineated in the rule otherwise mirror
other existing requirements in the MACT general provisions. We do agree
with petitioners that a CMS must undergo periodic system inspections,
preventive maintenance, and parts replacements in order to continue
good operation. It is clear that these events are among normal
scheduled quality control events that would be included in the site-
specific quality control program that is required under section
63.8(d)(2)(iii) to which the source owner is subject. We also agree
that such periods are to be categorized as exceptions to CMS data
collection that are already allowed in the rule. Given the existing
regulatory requirements and the clarifications in this rule about how
to apply those requirements, we believe the rule provides allowances
sufficient for CMS operational flexibility and are therefore not
proposing any revisions on this issue.
6. Averaging Times. The EPA has determined that a 30-day rolling
average for parameter monitoring and demonstration of continuous
compliance with operating limits is appropriate for this rule. This
would be a change from the final rule, which generally included 12-hour
block averages that corresponded to the expected length of the longest
duration 3-run emission test that was required to demonstrate initial
compliance with the emission limits. The operating limits established
through performance testing in this rule represent short term process
and control operating conditions representative of compliance. Concerns
of variability outside the operators control such as fuel content,
seasonal factors, load cycling, and infrequent hours of needed
operation prompted us to look at longer averaging periods on which to
base operating compliance determination. We are aware from studies of
emissions over long averaging periods that long term (e.g., 30-day)
average emissions for a operating in compliance will have a variability
of about half of that represented by the results of short term testing.
Given that short term tests are representative of distinct points along
a continuum of that inherent operational variability, we believe it
appropriate to propose 30-day averages in order to provide a means for
the source operator to account for that variability by applying a long
term average for establishing compliance. We expect more problematic
control system variability (e.g., ESP transformer failure or scrubber
venturi fan failure) to result in deviations from a 30-day average
relative to compliance almost as much as for a shorter term average.
E. Emission Limits
1. Additional Data Received. The EPA received additional data from
stakeholders and incorporated all of the data into the MACT database.
The new data include 36 Hg test runs, 168 p.m. test runs, 24 dioxin/
furan test runs, 133 CO test runs, 63 HCl test runs, and 22 TSM test
runs. In addition to the stack test data, the EPA received fuel
analyses for 3 facilities and over 51,000 hours of CO CEMS data from 3
facilities. Finally, stakeholders submitted corrections to data and to
descriptions of combustion units. We have incorporated these
corrections into the project database. For details on the new data and
data corrections, see the memorandum in the docket entitled ``Revised
Handling and Processing of Corrections and New Data in the EPA ICR
Databases (October 2011).''
2. Quality Assurance Activities on Best Performers. The EPA
requested copies of all of the emission test reports for the best
performing units in each subcategory in order to perform additional
quality assurance. These test reports document the test results for the
summary test data that were submitted to the EPA as part of the EPA's
Phase 1 information collection request. This review resulted in
multiple changes to data and invalidation of some emission tests.
Overall, this effort improved the quality of the data provided by
industry. For details on the quality assurance effort, see the
memorandum in the docket entitled ``Data Quality Review of Best
Performers for PM, Hg, HCl, CO, and Dioxin/Furan Emissions from ICI
[[Page 80611]]
Boilers and Process Heaters at Major Sources of HAP (October 2011).''
3. Incorporation of Minimum Detection Levels and Measurement
Imprecision. In developing the final rule, the EPA incorporated
procedures to ensure that the available measurement methods would
provide accurate emissions measurements at the levels set for the
various standards. The preamble to the final rule described these
procedures, but stakeholders did not have an opportunity to comment on
them. The EPA has made minor adjustments to the methods used to account
for measurement imprecision and presents the rationale in the following
paragraphs. We are soliciting comment on the procedures described
below.
Test method measurement imprecision is a contributor to the
variability of a set of emissions data. One element 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;
measurement imprecision proportionally decreases for values measured
above the method detection level. The probability procedures applied in
calculating the floor or an emission limit inherently and reasonably
account for emissions data variability, including measurement
imprecision, when the database includes multiple tests from multiple
emissions units for which all data are measured significantly above the
method detection level. This is less true when the database includes
emissions occurring below method detection capabilities that are
reported as the method detection level values.
The EPA's guidance to data collection respondents for reporting
pollutant emissions specified the criteria for determining test-
specific method detection levels. Under those criteria, about a 1
percent probability of an error exists that a pollutant measured at the
method detection level is present when in fact it is 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 is 50
percent or greater. 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.\2\ 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. One
effect of reporting data in this manner is that the resulting database
is somewhat 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 that is based on a truncated database or
otherwise includes values measured near the method detection level may
not adequately account for the effects of measurement imprecision on
the data variability.
---------------------------------------------------------------------------
\2\ American Society of Mechanical Engineers, Reference Method
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------
We applied the following procedures to account for the effect of
measurement imprecision associated with a database that includes method
detection level data. In response to the comments and internal concerns
about the quality of measurements at very low emissions limits
especially for new sources, we revised the procedure for identifying a
representative detection level (RDL). The procedure for determining an
RDL starts with identifying all of the available reported pollutant
specific method detection levels for the best performing units
regardless of any subcategory (e.g., existing or new, fuel type, etc.).
From that combined pool of data, we calculate the arithmetic mean
value. By limiting the data set to those tests used to establish the
floor or emissions limit (i.e., from the best performers), the result
also represents the best performing testing companies and laboratories,
and data from underperforming laboratories are effectively removed from
the floor analysis. The outcome should minimize the effect of a test(s)
with an inordinately high method detection level (because, for example,
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). We then call the
resulting mean of the method detection levels as the RDL as
characteristic of accepted source emissions measurement performance.
The second step in the process is to calculate three times the RDL
to compare with the calculated floor or emissions limit. This step is
similar to what have used before including for the Portland cement MACT
determination. We use the multiplication factor of three to approximate
a 99 percent upper confidence interval for a data set of seven or more
values. For comparing to the floor, if three times the RDL were less
than the calculated floor or emissions limit (e.g., calculated from the
upper prediction limit (UPL)), we would conclude that measurement
variability was adequately addressed. The calculated floor or emissions
limit would need no adjustment. If, on the other hand, the value equal
to three times the RDL is greater than the UPL, we would conclude that
the calculated floor or emissions limit does not account entirely for
measurement variability. In this situation, we substituted the value
equal to three times the RDL for the calculated floor or emissions
limit.
We determined the RDL for each pollutant using data from tests of
all the best performers for all of the final regulatory subcategories
(i.e., pooled test data). We applied the same pollutant-specific RDL
and emissions limit adjustment procedure to all subcategories for which
we established emissions limits. We believe that emissions limits
adjusted in this manner better ensure that measurement variability is
adequately addressed relative to compliance determinations than did the
procedure applied for calculations in the June 4, 2010, proposed rule
that may have been based on data sets smaller than seven tests and as
few as one test. We also believe that the emissions testing procedures
and technologies available now and in the future will be adequate to
provide the measurement certainty sufficient for sources to demonstrate
compliance at the levels of the adjusted emissions limits.
4. CO CEMS-Based Alternative Emission Limits and Monitoring. As an
alternative to CO stack testing and oxygen monitoring, we are proposing
a compliance option that allows the use of CO CEMS. Some petitioners
noted that some affected sources currently use CO CEMS and that
installing additional monitoring equipment should not be required if a
unit elects to comply using existing CO CEMS equipment. In addition,
petitioners stated that due to the highly variable nature of CO
emissions, an emission limit based on CO CEMS data from boilers over
time would more adequately capture the true variability in CO emissions
over various operating conditions. In response to these requests, the
EPA has calculated a CO CEMS-based MACT floor for each subcategory for
which data were available. Facilities would have the option to comply
with the alternative
[[Page 80612]]
CO CEMS-based limits through monitoring with CO CEMS. Through the
Section 114 Information Collection Requests and additional voluntary
data submittals, a limited amount of CEMS data was available to compute
CO CEMS limits. Most sources that reported CEMS data had 30 days of
data either reported as hourly or daily averages. Given this limited
length of time, we selected a 10-day rolling averaging period in order
to allow us to compute multiple data points from each source's dataset.
If sources reported CEMS data on both an hourly and daily average
basis, we first computed daily averages from the hourly data. Next, we
combined the two datasets, sorted the data in sequential calendar data
order and computed a series of 10-day rolling averages from each unit.
CEMS data on a 10-day rolling average basis could be calculated for the
following subcategories: fluidized bed units designed to burn coal/
solid fossil fuel, pulverized coal boilers designed to burn coal/solid
fossil fuel, stokers designed to burn coal/solid fossil fuel, dutch
ovens/pile burners designed to burn biomass/bio-based solids, fluidized
bed units designed to burn biomass/bio-based solids, hybrid suspension
grate boiler designed to burn biomass/bio-based solids, stokers/sloped
grate/others designed to burn wet biomass fuel, suspension burners
designed to burn biomass/bio-based solids and units design to burn
heavy liquids. CO CEMS data on a 10-day rolling average basis data were
not available for the fuel cell units designed to burn biomass/bio-
based solids, biomass dry stoker units, and units designed to burn gas
2 (other) gases. Alternate CO CEMS-based limits are not being proposed
for these units, but if data are provided for those subcategories prior
to March 1, 2012, those data will be considered for use in the final
rule. A very limited amount of CEMS data were available from units
designed to burn light liquid fuel and units designed to burn liquid
fuel located in non-continental States and territories, but not enough
data points were available to compute a 10-day rolling average. We do
have data sufficient to develop CO CEMS-based limits on a 1-day block
average basis for light liquid units and a 3-hour rolling average basis
for non-continental liquid units, as discussed below. If sufficient
additional data are provided by March 1, 2012, the EPA will consider
adjusting the averaging times similar to the other emission limits.
In most cases, only one or two units in each subcategory have CO
CEMS data available. The memorandum ``CO CEMS MACT Floor Analysis
(October 2011) for the Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for Hazardous
Air Pollutants--Major Source'' provides a complete breakdown of the CO
CEMS data that were available. The EPA is requesting the submittal of
additional CO CEMS data to achieve a more robust dataset for the
purposes of revising the CO CEMS MACT floor calculations. Please
provide your dataset in an electronic spreadsheet or database format
with the data reduced to hourly CO averages reported as ppmvd. You
should include the oxygen associated with each measurement or report
the data at a standardized oxygen concentration, preferably adjusted to
3 percent oxygen. The EPA is expecting to receive additional CEMS data
before the final rule and to incorporate those data if received in
time. The data will likely change the CO CEMS floors, and may also
result in different averaging times, depending on the extent of the
data.
In order to identify the dataset that would be used to compute a CO
CEMS MACT floor emission limit, the EPA first identified all of the
units identified as best performers based on their reported stack test
results that had 10-day rolling average CO CEMS data available. Refer
to the memo ``Revised MACT Floor Analysis (October 2011) for the
Industrial, Commercial, and Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants--Major
Source,'' for more information on how the best performing CO stack
tests were identified for each subcategory. However, there was very
little overlap in the number of best performing units that had both
stack test and CO CEMS data available. After comparing the data, only
three subcategories would have best performing units with both stack
test and applicable CEMS data. Given these data gaps, we opted to rank
CO CEMS data based on each units minimum 10-day rolling average CO CEMS
value and then determining the best performers for each subcategory.
For the three subcategories where we have CEMS data for units that are
part of the stack test-based MACT floors, we included the CEMS data
from those units in the CEMS-based floors because those units are
demonstrated best performers for CO. We discuss two exceptions below,
where the data did not allow the use of a 10-day averaging period.
Within each subcategory, we ranked the minimum 10-day rolling averages
from lowest to highest to determine the best performing 12 percent.
Then, we identified any best performers based on the CO stack test data
that provided CO CEMS data, and we included those data in the MACT
floor pool. Next, we used all of the daily averages from the best
performing units to compute a MACT floor based on a 99 percent UPL.
For the units designed to burn light liquid fuels, the data were
insufficient to calculate 10-day rolling averages. Based on the
available data, the averaging basis selected was 1 day. For the units
designed to burn liquid fuel in the non-continental liquid units
subcategory, the data were insufficient to calculate 10-day rolling
averages. Based on the available data, the averaging basis selected was
3 hours for non-continental liquid units. Only one of the non-
continental boilers submitted CO CEMS data, with a total of 24 hourly
averages. In this case, we used each of the hourly averages from this
unit to compute a MACT floor based on a 99 percent UPL. The EPA is
aware that the averaging time selection and whether rolling or block
averaging is selected impacts the UPL calculation and ability to
demonstrate compliance. We believe that the averaging times selected
for this proposal are reasonable and note that, to some extent, they
are dictated by the limited datasets. The EPA is requesting comment on
the most appropriate averaging time (e.g., hourly, daily) and length of
rolling period (e.g., 10-day, 30-day) to use when calculating the CO
CEMS MACT floors and requests specific discussion and new data to
support your comments. The length of the averaging time will be
affected by the available data in each subcategory. The EPA also is
requesting comment on the approach used to calculate the UPL-based MACT
floors.
Ranking the dataset according to the minimum 10-day rolling average
does not necessarily correlate with the ranking used to identify the
best performing 12 percent of units with CO stack test data used to
calculate the stack test-based floors for CO. Separate sets of units in
the stack test and CEMS data sets create the possibility of incongruent
results between the two compliance options. To evaluate whether our
selection of the units identified as best performers for CO CEMS data
correlates to the units identified as best performers for stack test
data, we compared the CEMS data and the computed stack test CO MACT
floor for each subcategory. Each unit identified as a best performing
unit in the CO CEMS analysis had at least one 3-hour CEMS average at or
below the corresponding stack test CO MACT floor for the subcategory,
which suggests that
[[Page 80613]]
the units identified as best performers based on the CEMS data are
comparable to the units identified as best performers based on the
stack test data. The EPA specifically requests comment on the ranking
methodology which should be used, with discussion on whether CO CEMS
best performers should be selected from units also identified as best
performers from their stack test data, or if a value other than the
minimum 10-day rolling average should be used as the basis for ranking
the data.
Given the limited data available, the proposed new source CO CEMS
floors are similar to existing source floors since the existing source
CO CEMS UPL for each subcategory was determined using data from a
single unit, with two exceptions. The fluidized bed units designed to
burn biomass/bio-based solids and stokers/sloped grate/others designed
to burn wet biomass fuel each have two units in the existing source
floor calculations, whereas the new source floor would be based on the
single best performer. In the case of wet biomass stoker/sloped grate/
other, the computed new source floor would be higher than the existing
source, so the value reverts to the existing source value.
The 99 percent UPL calculations for CO CEMS used the following
statistical formula:
[GRAPHIC] [TIFF OMITTED] TP23DE11.028
Where:
n = the number of daily averages (or hourly averages for non-
continental units)
m = the number of test runs in the compliance average
In this case, m equals 10 given the 10-day rolling average compliance
period for all subcategories except for non-continental liquid, where m
equals 3 for the 3-hour averaging period. Similar to previous analysis
of the distribution of the dataset for stack test data MACT floor
calculations, the distribution of each CEMS dataset was classified as
either a normal distribution or log-normal distribution. In the case of
the CEMS datasets from each of the best performers, the datasets were
each log-normally distributed. See the ``CO CEMS MACT Floor Analysis
(November 2011) for the Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for Hazardous
Air Pollutants--Major Source'' for further details about the
calculations.
For each subcategory the analysis showed that the datasets were
lognormally distributed. Given the rolling-average compliance metric,
many of the datasets also exhibit varying degrees of autocorrelation.
Autocorrelation describes the correlation between values of the process
at different points in time. Although the UPL calculation is affected
by autocorrelation, no adjustments were made to incorporate
autocorrelation in this dataset. Depending on the final compliance
metric selected, EPA may adjust the dataset for the promulgated rule to
better address autocorrelation. The EPA is requesting comment on
incorporating autocorrelation into the analysis.
The EPA considered, but is not proposing, an additional final step
for establishing the CO CEMS-based floors. When we compared the
performance of the units in the top half of the MACT floor pool
(usually a single unit) to the UPL-based floor level, it was revealed
that the calculated UPL-based floor level resulted in the best
performing units in some subcategories not meeting the limit up to
about 25 percent of the time. The following final step in the floor
setting process for CEMS-based limits could be used to adjust the CO
CEMS-based limits to reflect the level achieved at all times by the
best performing sources (i.e., the top half of the MACT floor units).
In those instances where the best 6 percent of units did not meet the
calculated limit at all times, the limit was adjusted to reflect the
actual level that was demonstrated to be achieved at all times by those
units (the highest 10-day, 1-day, or 3-hour average, as applicable,
from the best 6 percent of units). The CO CEMS-based emission limits
based on this approach are shown in Table 2 of this preamble. The EPA
is requesting comment on whether this final step is appropriate for
developing CO CEMS-based MACT floors for boilers and process heaters.
Table 2--Alternative Approach CO CEMS-Based Emission Limits for Boilers
and Process Heaters
------------------------------------------------------------------------
Alternate CO CEMS
Subcategory limit, (ppm @3%
oxygen)
------------------------------------------------------------------------
New and Existing--Coal Stoker....................... 34
New and Existing--Coal Fluidized Bed................ 78
New and Existing--Coal-Burning Pulverized Coal...... 35
New and Existing--Biomass Wet Stoker/Sloped Grate/ 920
Other..............................................
New and Existing--Biomass Kiln-Dried Stoker/Sloped (1)
Grate/Other........................................
New and Existing--Biomass Fluidized Bed............. 480
New and Existing--Biomass Suspension Burner......... 2,300
New and Existing--Biomass Dutch Ovens/Pile Burners.. 440
New and Existing--Biomass Fuel Cells................ (1)
New and Existing--Biomass Hybrid Suspension Grate... 1,400
New and Existing--Heavy Liquid...................... 18
New and Existing--Light Liquid...................... 60
New and Existing--non-Continental Liquid............ 120
New and Existing--Gas 2 (Other Process Gases)....... (1)
------------------------------------------------------------------------
\1\ No data.
[[Page 80614]]
F. MACT Floor Methodology
1. Standards for Dioxin/Furans. Petitioners requested that EPA
revise the procedure used to calculate the final emission limits for
dioxin/furans, with the primary issue being the low levels and how
detection limits should be considered. The EPA re-assessed the lowest
level that can be accurately measured for dioxin/furan emissions from
boilers and process heaters. When we compared those levels to the
levels of emissions from all of the units that had test data available,
we found that for all subcategories of units, emissions were below the
value that can be accurately measured. Details on the establishment of
the level that can be accurately measured are provided in the docket
memorandum entitled: Updated data and procedure for handling below
detection level data in analyzing various pollutant emissions databases
for MACT and RTR emissions limits. As discussed in section V.A.2 of
this preamble, the EPA is now proposing to regulate dioxin/furan
emissions with a work practice standard in lieu of numeric emission
limits.
2. Filling Data Gaps for Non-Continental Liquid Units. The EPA
included numeric emission limits for non-continental liquid units in
the final rule. However, data were not available for all of the
regulated pollutants, and EPA relied on the MACT floors for liquid
units to establish some of the emission limits. Petitioners requested
that in cases where data gaps exist, a more appropriate substitution
would be to establish floors based on units that combust No. 6 fuel
oil, which is the fuel that the non-continental units are designed to
combust. While the EPA agrees that for estimating emission from these
units, use of data from No. 6 oil-fired units may be appropriate even
though some design differences have been identified (see FR 76 15635,
March 21, 2011), we are proposing a different approach for setting
emission limits for non-continental liquid units. Additional data were
submitted to EPA for PM and CO from non-continental units, and the
proposed PM and CO limits are based on these data from within the
subcategory. For HCl and Hg, which are considered fuel-based pollutants
that are not dependent on combustor design, the EPA is proposing to
base limits for all liquid units on the entire data set from liquid-
fired units. The currently available data and information do not
indicate that Hg and HCl should be considered separately for liquid
units designed to combust various types of liquids, and we therefore
are proposing Hg and HCl emission limits that are based on the
available data for all liquid units. The EPA requests comment on this
approach, and to the extent that other approaches are suggested, the
EPA requests data and rationale to support any suggested alternative
approaches.
3. Selection of Confidence Level for CO. In the final rule, the EPA
selected the use of a 99.9 percent confidence interval for calculating
the MACT floor for CO emissions. A petitioner requested reconsideration
of this selection given the fact that the EPA used a 99 percent
confidence interval for all of the other emission limits in the final
rule. The petitioner pointed out that if the data are highly variable,
the 99 percent confidence interval should adequately reflect the
variability of emissions as well as for the data sets for other
pollutants. In the development of the final rule, the 99.9 percent
confidence interval was selected in part because the standards covered
periods of startup and shutdown, while the data did not reflect CO
emissions during those periods. While the EPA finalized work practice
standards for startup and shutdown periods, the selection of the
confidence interval was not revisited due to time constraints. The EPA
is now proposing to use a 99 percent confidence interval in order to
maintain a consistent methodology with the development of the MACT
floors for other pollutants, and because optional CO CEMS-based limits
are being proposed that would allow sources additional flexibility in
meeting the requirements of the rule.
G. Tune-Up Work Practices
1. Requirements for Small and Limited-Use Units. Petitioners
requested that the EPA reconsider the tune-up work practices for a
subset of very small units. Specifically, petitioners requested that
small natural gas- and light oil-fired units (petitioners defined
``small'' at various levels between 2 MMBtu/hr and 10 MMBtu/hr) be
exempted from the rule. While the EPA disagrees that small units should
be exempt from the rule, the EPA agrees that for the smallest natural
gas-, refinery gas, other clean gas (that meets the fuel specification)
and light liquid-fired units, decreased tune-up frequency is
appropriate. The large number of small units that can be located at an
individual facility, particularly an institution, provides logistical
issues with completion of tune-ups on an annual basis. For instance,
one institution has over 700 identical small natural gas-fired units
that would, under the final rule, each be subject to a biennial tune-up
requirement. We are proposing to change that requirement for natural
gas-, refinery gas, other clean gas (that meets the fuel specification)
and light liquid-fired units equal to or less than 5 MMBtu/hr to a
tune-up once every 5 years, with the initial tune-up required by the
compliance date and subsequent tune-ups being required at intervals no
greater than 5 years from the previous tune-up.
2. Clarifications of Certain Tune-up Provisions. Petitioners
requested several changes to the tune-up requirements and timing of
completing the various aspects of tune-ups. The issues and the EPA's
proposed responses, are presented in the following paragraphs.
First, petitioners questioned the requirement that burner
inspections (part of the tune-up) must be completed at least once every
36 months, even if this requirement causes a unit to be shut down that
otherwise would not have been. The EPA agrees that the burner
inspection should not cause units to shut down and is proposing to
remove the ``every 36 months'' requirement. Instead, we are proposing
that burner inspections that cannot be completed during a tune-up can
be delayed until the next scheduled shutdown.
Second, petitioners requested that CO adjustments that are required
as part of a tune-up be allowed to be completed within 30 days of the
tune-up in order to allow for multiple adjustments and optimization of
CO emissions. The EPA agrees that this is a reasonable change and is
proposing to allow 30 days from the date the tune-up is completed.
Third, the EPA included a burner inspection requirement that is
difficult or impossible for certain units to meet. The EPA is proposing
to clarify this provision so as not to require a physical inspection
that cannot reasonably be completed.
3. Conducting Initial Tune-ups at New Sources. Petitioners
requested that the EPA clarify the timing of tune-ups with respect to
the compliance dates for existing and new sources. For new units, the
EPA recognizes that, as petitioners pointed out, units are generally
tuned as part of installation, but a learning curve exists for how to
most efficiently operate new units. Accordingly, the EPA is proposing
that the initial tune-up after startup must be completed within one
year of startup.
H. Energy Assessment
1. Scope. Petitioners requested that the EPA clarify the scope of
the energy assessment. Specifically, petitioners requested that the
scope be clearly limited to only those energy use systems that are
located on-site and associated with the affected boilers and process
heaters. The final definition for ``Energy
[[Page 80615]]
use system'' was intended only to list examples of potential systems
that may use the energy generated by affected boilers and process
heaters. We did not intend that the energy assessment would include
energy use systems using electricity purchased from an off-site source.
We also did not intend that the energy assessment include energy use
systems located off-site. We are proposing to revise the definition of
``Energy assessment'' to clarify our intent.
2. Compliance Date. Petitioners requested that the EPA clarify the
due date of the energy assessment. All emission standards must be met
by the compliance date, even if compliance demonstrations are sometimes
allowed after the compliance date. In order to meet the requirements of
the rule, energy assessments must, therefore, be completed by the
compliance date for existing sources.
3. Maximum Duration Requirements. Petitioners requested that the
EPA reconsider the stated ``maximum time'' to conduct the energy
assessment because the maximum times were not included in the proposal,
and stakeholders had no opportunity to comment. The concern raised by
petitioners is that, as the final definition of ``Energy assessment''
is worded, a deviation and a potential violation could occur if the
energy assessment effort exceeds these time limits. Our intent for
including the ``maximum time'' in the final rule definition was to
minimize the burden on the smaller fuel use facilities, many of which
are likely small entities, by limiting the extent of the energy
assessment. Our concern was that if there was no time limit, these
small facilities would have no means to limit the time/effort of an
outside energy assessor that is contracted to perform the energy
assessment. We have revised the definition of ``Energy assessment'' to
change the maximum time from 1 day to 8 technical hours and from three
days to 24 technical hours. This would allow sources to perform longer
assessments at their discretion.
I. Affirmative Defense Provisions During Malfunctions
The EPA finalized affirmative defense provisions for malfunctions.
As part of this reconsideration proposal, we are soliciting comments on
the affirmative defense provisions that were included in the final
rule. The rationale for the affirmative defense provisions is provided
in the preamble to the final rule. See 76 FR 15642.
J. Work Practices During Startup and Shutdown
1. Work Practices. The EPA finalized a work practice standard for
periods of startup and shutdown that requires facilities to minimize
emissions consistent with manufacturers' recommended procedures.
Petitioners requested that the EPA clarify whether the requirement
applies to the boiler or the control device manufacturer. The EPA is
proposing to amend the work practice standard so that manufacturers'
recommended procedures are no longer referenced, although the EPA
expects that facilities will follow such procedures for both the boiler
system and any air pollution control devices. The EPA is proposing to
amend the work practice standard as described in section III.E of this
preamble. The rationale for justifying work practice standards for
periods of startup and shutdown is described in the preamble to the
final rule. See 76 FR 15642. Additionally, we do not have emissions
data for startup and shutdown periods sufficient to establish numeric
emissions standards for these periods. The only available data is
limited CO emissions data, which is unlikely to reflect actual
emissions of the best performing units during startup and shutdown. The
rationale for the proposed changes to the work practice standard is
discussed below. The EPA is now proposing to define startup and
shutdown periods and is proposing more specific requirements than those
in the final rule. The definitions of startup and shutdown would
provide clarity regarding which periods of operation are subject to the
work practice standards rather than numeric emission limits and the
associated requirements. The proposed definitions specify that only the
periods of time between a complete shutdown of a unit (no fuel being
combusted) and the time that a unit first reaches 25 percent load
qualify as startup, and only the periods of time between the time that
a unit last reaches 25 percent load and the time when a unit is
completely shut down (no fuel being combusted) qualify as shutdown.
These definitions are intended to ensure that units cannot cycle in and
out of startup or shutdown. The EPA recognizes that it may be necessary
to establish a maximum time period to ensure that units cannot operate
in startup or shutdown mode for extended periods of time, and is
soliciting comment on the appropriate time period or time periods for
the various unit designs. The EPA believes that a work practice
standard that applies during such periods should require more than a
general duty to reduce emissions, which is essentially what was
required in the final rule. General duty requirements do not constitute
appropriate work practice standards under section 112(h). We are
soliciting comment on the rationale for work practice standards during
periods of startup and shutdown as well as the proposed work practice
standard and the rationale for proposing changes to the standard. We
also are soliciting comment on whether other work practices should be
required during startup and shutdown, including requirements to operate
using specific fuels to reduce emissions during such periods. Because
the EPA did not propose work practice standards for startup and
shutdown periods in the June 4, 2010, proposed rule, members of the
public did not have the opportunity to comment on those standards or
the rationale for the standards prior to issuance of the final rule.
2. Operating Parameters and Opacity Limits. Petitioners requested
that EPA clarify that the operating limits and opacity limits do not
apply during periods of startup and shutdown. Having finalized work
practice standards for these periods of time, EPA agrees that the
requested clarification is what was intended in the final rule.
K. Applicability
1. Exemption for Units Serving as Control Devices. In the final
rule, the EPA exempted any boiler or process heater that is used as a
control device to comply with another subpart of part 63, 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. Petitioners
requested that EPA extend the exemption to units that serve as control
devices for EPA standards issued under parts 60 or 61 of the CAA. We
recognize that part 61 is another part relevant to the NESHAP program
and should be treated the same as the exemption provided for part 63.
Although part 60 does not regulate HAP, the EPA does want to continue
to use combustion controls for organic pollutants that part 60
addresses, as it provides a pollution prevention strategy and reduces
the need for facilities to install other combustion equipment to serve
as dedicated control devices for NSPS and NESHAP regulated gas streams
(e.g., thermal oxidizers and flares). In addition, many of the
potential add-on combustion technologies do not recover energy, and the
resulting combustion using these technologies would emit approximately
the same level of contaminants as a boiler without the added benefit of
[[Page 80616]]
energy recovery. Therefore, the EPA is now proposing to exempt any
boiler or process heater that is used as a control device to comply
with standards issued under part 60, part 61, or part 63 of the CAA,
provided that at least 50 percent of the heat input to the boiler is
provided by a gas stream that is subject to standards under those
parts.
2. Waste Heat Boilers and Process Heaters. Petitioners requested
that the EPA clarify that waste heat process heaters, like waste heat
boilers, are not subject to the standards. Petitioners are correct that
the EPA intended to exempt waste heat process heaters from the rule,
and the EPA is amending the definition of process heater to exclude
waste heat process heaters. We also are clarifying that waste heat
boilers and process heaters can include supplemental burners as long as
those burners combust only Gas 1 fuels, up to 50 percent of their heat
input.
3. Units Firing Comparable Fuels. Petitioners requested that the
EPA clarify whether boilers and process heaters burning comparable
fuels, as defined under the Resource Conservation and Recovery Act
(RCRA), are subject to the NESHAP for industrial, commercial, and
institutional boilers and process heaters. Section 261.38 states that
hazardous secondary materials (i.e., spent materials, sludges and
byproducts) that have fuel value and whose hazardous constituent levels
are comparable to those found in fuel oil that could be burned in their
place are not solid wastes and hence not hazardous wastes under
Subtitle C of RCRA. These materials are called comparable fuels. Since
comparable fuels are not hazardous waste, boilers and process heaters
burning comparable fuels are not subject to the NESHAP for hazardous
waste combustors (part 63, Subpart EEE), which includes boilers and
process heaters that burn RCRA hazardous waste. Therefore, boilers and
process heaters burning comparable fuels are covered by the NESHAP for
industrial, commercial, and institutional boilers and process heaters.
4. Residential Unit Exemption. During the initial phases of
implementation of the area source boiler rule, stakeholders requested
clarification from the EPA on the applicability of the area source rule
to residential boilers, particularly those units at individual
residences located at institutional facilities. The EPA's intent was
not to cover such units, and during reconsideration, the EPA is
amending the area source rule accordingly. Similarly, the final major
source rule could be interpreted to cover residential boilers at large
institutions, which was not the intent of the rule. Accordingly, the
EPA is proposing to exempt residential boilers from the rule and is
proposing the following definition of residential boiler to the major
source rule: Residential boiler means a boiler, used in a dwelling
containing four or fewer family units, to provide heat and/or hot
water. This definition includes boilers used primarily to provide heat
and/or hot water for a dwelling containing four or fewer families
located at an institutional facility (e.g., university campus, military
base, church grounds) or commercial/industrial facility (e.g., farm).
L. Compliance
1. Extending Compliance Dates. On May 18, 2011, the EPA issued a
stay of the effective date of the final rule. The EPA is proposing
several revisions to the standards in this rule. As such, we are
proposing to revise the compliance date for existing sources to three
years after the date of publication of the final reconsideration rule.
This date is being proposed in order to enable facilities sufficient
time to install controls and make compliance-related decisions. For new
sources, the EPA is proposing that the compliance date is 60 days after
the date of publication of the final reconsideration rule, or upon
startup, whichever is later. This date assumes that the final
reconsideration rule will be subject to the Congressional Review Act,
which will delay the effective date of the rule by 60 days. We are
proposing to extend the compliance dates for all standards for several
reasons. First, the proposed changes to the emission limits for units
in every subcategory and the proposed use of work practice standards
for dioxin/furan emissions for all subcategories will have a
significant impact on the compliance strategies that are selected by
the affected sources. For instance, the proposed changes in PM emission
limits for existing biomass fluidized bed, hybrid suspension grate, and
the newly proposed dry stoker subcategories would require different PM
control selections than the emission limits finalized in March 2011.
The proposed changes in Hg, HCl and PM emission limits for units
designed to burn liquid fuels are likely to result in different
compliance responses and control selections for all of these
pollutants. For coal stoker units, the increased stringency of the
proposed PM and HCl emission limits would require increased control
efficiencies that, while not necessarily changing the types of controls
needed, may impact the design of those controls. Second, when the EPA
announced the reconsideration and postponed the effective date, it
indicated to industry that requirements could change significantly. The
resulting uncertainty has limited the ability of affected sources to
begin making appropriate selections of control technologies and other
compliance decisions. Even if significant changes were not being
proposed, an extended compliance date would likely be necessary to
provide enough time for facilities to achieve compliance. Third, most
of the dioxin emission limits that were finalized in March 2011 were
below the level that the EPA has now determined can be accurately
measured using the required test method. This was pointed out by
stakeholders who petitioned the EPA to move to a work practice approach
because the levels of dioxin/furan were too low to accurately measure
and resulted in a high degree of uncertainty regarding how to meet the
limits. The uncertainty resulted in the inability of sources to select
dioxin/furan control technology, and also prevented sources from
selecting controls for other pollutants because the emission controls
must be designed to work properly when operated together. For instance,
if a source required an ESP for PM control but needed carbon injection
to potentially meet a very low dioxin/furan emission limit, the source
may choose a fabric filter for PM control instead of an ESP.
Alternatively, if a source no longer needed carbon injection, the
particulate loading to the PM control device would be decreased, which
may result in a different design or possibly a selection of a different
control technology. Finally, the EPA has received comments that the
availability of control equipment and vendors to install control
equipment for boilers is in question due to the large number of units
requiring controls in conjunction with the parallel rulemaking for
electric generating units that will require controls from many of the
same vendors. While the EPA believes that the maximum time allotted
under section 112, 3 years after promulgation along with an additional
year for installation of controls that must be approved on a case-by-
case basis by the permitting authority, provides enough time for
boilers to achieve compliance, the EPA recognizes that maintaining the
compliance dates from the March 2011 final rule would essentially
provide less than 2 years for sources to meet the final standards,
whose stringency will not be determined until the reconsideration is
final. For all of the reasons discussed above, the EPA is proposing
that the compliance date for existing sources is three years after the
date of publication of the final reconsideration rule. The
[[Page 80617]]
EPA is requesting comment on the proposed changes to the compliance
dates.
2. Reduced Testing Frequency and Detection Levels. In the final
rule, the EPA changed the stack testing requirements to allow units
that demonstrate compliance for a particular pollutant at a level at or
below 75 percent of the emission limit for 2 consecutive years to
forego stack testing for up to 37 months. The EPA is maintaining this
provision for most of the emission limits and is soliciting comment on
this provision. The EPA also included, in the final rule analyses, a
method to ensure that emission limits are set at levels that can be
measured by the available test methods. During the development of the
rule, the EPA carefully considered comments regarding the very low
levels of some of the finalized emission limits that were based on a
level no less than 3 times the ``representative detection limit'' or
RDL. In cases where the calculated MACT floors were lower than the 3
times the RDL value, the calculated floor value was replaced by the 3
times the RDL value. For these values, which again represent the lowest
level that can be measured, units can qualify for skip testing by
meeting the limit rather than a level that cannot be accurately
measured.
3. Fuel Analysis of Gaseous Fuels at Co-Fired Units. Petitioners
requested that the EPA clarify the fuel analysis requirements for co-
fired units that combust Gas 1 fuels along with either solid or liquid
fuels. The EPA is clarifying that Gas 1 fuels are not included in the
fuel analysis requirement.
4. Coal Sampling Techniques. Petitioners requested that the EPA
allow for automated coal sampling systems. The EPA did not intend to
exclude these techniques in the final rule and is adding clarifying
language to allow for automated coal sampling techniques.
M. Other Issues Open for Comment
1. Stakeholders asked the EPA to consider, for units that are
retrofitted to switch to natural gas as a compliance option, allowing
those units to average emissions with units of the original unit
design. These parties suggested that continuing to allow such averaging
would be consistent with EPA's general approach of specifying emission
standards for affected facilities, but otherwise allowing the
facilities to comply however they see fit. They also pointed out that
this may allow for more effective controls overall. For example, they
suggested that without allowing for averaging of units that switch to
cleaner fuels as a compliance option, natural gas conversion is a less
attractive option than if such averaging was allowed, because a
facility would not have the ability to offset emissions using that
unit. In this case, these stakeholders believe that installing controls
that result in fewer emissions reductions than switching to natural gas
may be a perverse outcome. They suggested that continuing to allow
averaging across subcategories in cases where fuel switching has been
used to achieve compliance would instead encourage fuel switching to
cleaner fuels, which is environmentally beneficial. The EPA is
requesting comment on the potential benefit of this suggested approach,
and how such an approach could be justified and incorporated into the
rule.
2. Stakeholders requested that EPA consider creating a subcategory
for units that are installed and used in place of flares that are
currently used to combust process gases. The EPA is requesting comment
on how such a subcategory could be justified and incorporated into the
rule. The stakeholders also suggested that it would be appropriate to
assume that the emissions from process gases diverted from flares to
boilers have ``zero emissions'' for the purposes of classifying the
boiler they are combusted in. Since the process gases must be combusted
in either event, they requested that the EPA develop an approach where
we use a concept similar to the emissions averaging provisions, for
example, to simply assume that combustion of such process gases in a
boiler rather than a flare should not be counted as emissions from the
boiler because there is no net increase in emissions. The EPA requests
comment on how such an approach could be justified and incorporated
into the rule.
VI. Technical Corrections and Clarifications
We are proposing several technical corrections. These amendments
are being proposed to correct inaccuracies and oversights that were
promulgated in the final rule and to make the rule language consistent
with provisions addressed through this reconsideration. These proposed
changes are described in Table 3 of this preamble. We request comment
on all of these proposed changes.
Table 3--Miscellaneous Proposed Technical Corrections to 40 CFR Part 63,
Subpart DDDDD
------------------------------------------------------------------------
Section of subpart DDDDD Description of proposed correction
------------------------------------------------------------------------
40 CFR 63.7491(m)............ Clarify the language in this paragraph to
use the word ``unit'' instead of
``boiler.''
40 CFR 63.7495(b)............ Revise this paragraph to include a
provision in Sec. 63.6(i)
40 CFR 63.7499(f)-(s)........ Revise and add new paragraphs to
accommodate the addition of new
subcategories of boilers and process
heaters.
40 CFR 63.7499(d)............ Revise the term ``stokers'' to ``stokers/
sloped grate/other units'' consistent
with how the data for this rule was
analyzed.
40 CFR 63.7500(d)............ Revise this paragraph by adding a new
paragraph (d) to clarify that the
emission standards apply at all times,
except during startup and shutdown,
during which time you must comply only
with Table 3.
40 CFR 63.7501(b)............ Revise terms in this paragraph to correct
spelling errors.
40 CFR 63.7505(c)............ Revise this paragraph by removing the
reference to Table 12; this table is not
included because this is a proposed
rule.
40 CFR 63.7510(a)............ Revise this paragraph to create four
subparagraphs (1)-(4) to clarify our
intent on fuel analysis requirements for
gaseous fuels.
40 CFR 63.7510(b)............ Revise this paragraph to clarify that
certain fuels are not subject to the
fuel analysis requirements and that
units using a continuous emission
monitoring system for mercury or
hydrogen chloride are exempt from the
performance testing and operating limit
requirements.
40 CFR 63.7510(c)............ Revise this paragraph to clarify that
units using a continuous emission
monitoring system for carbon monoxide
are exempt from the performance testing
and operating limit requirements.
40 CFR 63.7510(d)............ Revise this paragraph to clarify that
owners and operators electing to comply
with the alternative total selected
metals limit are not required to install
a PM CPMS.
[[Page 80618]]
40 CFR 63.7510(g) and (h).... Insert a new paragraph (g) and renumber
(g) to (h). Paragraph (g) will clarify
the compliance provisions for new
sources with respect to the work
practice and tune-up provisions.
40 CFR 63.7510(f), Revise these paragraphs by removing the
63.7515(f), and 63.7520(d). references to Table 12; this table is
not included because this is a proposed
rule.
40 CFR 63.7521(a)............ Revise this paragraph to clarify that
fuel analysis cannot be used with
gaseous fuels to demonstrate compliance
with the limits for total selected
metals or hydrogen chloride given method
limitations. We are also proposing to
revise this paragraph to clarify that a
fuel gas system consisting of multiple
gaseous fuels collected and mixed with
each other is considered a single fuel
type and sampling and analysis is only
required of the combined fuel gas
system.
40 CFR 63.7521(b)............ Revise this paragraph to clarify that the
fuel monitoring plan is needed only if
you are required to conduct fuel
analyses.
40 CFR 63.7521(b)(1)......... Revise this paragraph to add a cross
reference to the section describing the
initial compliance demonstration.
40 CFR 63.7521(b)(2)(ii) Revise the subparagraphs to clarify that
through (iv). the requirements apply to each
anticipated fuel type.
40 CFR 63.7521(c)(1)(ii)..... Revise this paragraph by changing wording
from ``1-hour'' to ``one-hour''.
Clarify the different sampling
circumstances for performance stack
testing and monthly sampling.
40 CFR 63.7521(c)(2)(ii) and Revise this paragraph by clarifying
63.7521(d)(2). wording describing sampling requirements
to provide more flexibility for
automated sampling and reduce overly
prescriptive language.
40 CFR 63.7521(e)............ Reference equations 7, 8, and 9 within
this paragraph to add clarity.
40 CFR 63.7521(f)............ Add three sub-paragraphs to this
paragraph to organize exemptions from
fuel specification analyses.
40 CFR 63.7521(g)(1)......... Revise this paragraph to add a cross
reference to the section describing the
initial compliance demonstration.
40 CFR 63.7521(g)(2)(ii) Revise the subparagraphs to clarify that
through (iv). the requirements apply to each
anticipated fuel type.
40 CFR 63.7522(b)............ Revise this paragraph to add several
subparagraphs to clarify that emissions
averaging may not include units using
CEMS or PM CPMS; that averaging may only
be within units in a subcategory subject
to the same numerical emission limit;
and that emissions averaging is not
allowed for certain subcategories of
units for certain emission limits.
40 CFR 63.7522(e)(2)......... Add the units for emission limits to add
clarity (pounds per million Btu).
Revise the definition of the term ``Sm''
in Equation 2 to clarify that maximum
steam generation is in units of pounds
per hour.
40 CFR 63.7525(a)............ Remove a reference to Table 12; this
table is not included because this is a
proposed rule.
40 CFR 63.7525(b)(3)......... Change language from ``concentrations''
to ``rates'' to provide clarity.
40 CFR 63.7525(b)(5)......... Revise this paragraph by changing wording
from ``1-hour'' to ``one-hour''.
40 CFR 63.7525(d)(3)......... Revise the paragraph to add a reference
to 65.7535(d) to replace a description
of other situations that constitute a
monitoring deviation.
40 CFR 63.7525(d)(4)......... Change from the 12-hour block average to
30-day rolling average as specified in
the revised Table 8 to subpart DDDDD.
40 CFR 63.7530(b)............ Revise this paragraph to clarify which
fuels are exempt from analysis by cross-
referencing 40 CFR 63.7510(a)(2),
instead of repeating the information in
that paragraph.
40 CFR 63.7530(b)(4) Revise this paragraph to: 1. Clarify that
[formerly (b)(3)]. you are not required to establish and
comply with the operating parameter
limits when you are using a CEMS to
monitor and demonstrate compliance with
the applicable emission limit.
2. Clarify in the subparagraphs which
parameters are applicable to specific
types of control devices.
3. Add a new subparagraph to address PM
controls used in conjunction with a PM
CPMS.
4. Add a new paragraph to address
particulate wet scrubbers as distinct
from acid-gas wet scrubbers.
40 CFR 63.7530(c)(2)......... Revise the references to Equation 9 to be
Equation 10, to accommodate the change
in numbering of equations.
40 CFR 63.7530(c)(3)......... Revise the references to Equation 9 to be
Equation 10, to accommodate the change
in numbering of equations.
40 CFR 63.7530(c)(4)......... Revise the references to Equation 9 to be
Equation 10, to accommodate the change
in numbering of equations.
40 CFR 63.7530(h)............ Remove a reference to Table 12; this
table is not included because this is a
proposed rule.
40 CFR 63.7533(b)(2)......... Amend this paragraph to clarify that the
use of emission credits from
implementation of energy conservation
measures can only be used by existing
units, and that these credits can be
used to demonstrate initial and on-going
compliance.
40 CFR 63.7533(c), (c)(1)(i), Amend these paragraphs to change the date
and (c)(3). after which energy conservation measures
can be used to generate credits from
January 14, 2011, to January 1, 2008.
January 1, 2008 is the same cut-off date
for using a pre-existing energy
assessment to satisfy the energy
assessment requirement in Table 3 to
subpart DDDDD.
40 CFR 63.7533(c)(2)(i) and Revise the reference to Equation 12 to
(c)(3). Equation 14, to accommodate the change
in numbering of equations.
40 CFR 63.7533(c)(3)(i)...... Revise Equation 12 in this section to
clarify the summation to be performed in
that equation, and to clarify that the
energy credits are expressed as a
decimal fraction of the baseline energy
input.
40 CFR 63.7533(c)(3)(i) and Revise the names and definitions of the
(f). terms in Equations 12 and 13 to be
consistent.
40 CFR 63.7533(c)(f)......... Revise the paragraph to remove the
reference to (f)(1) and (2) because
there is no paragraph (2) and only a
single paragraph is needed.
[[Page 80619]]
Change the reference to Equation 13 to
Equation 15, to accommodate the change
in numbering of equations.
40 CFR 63.7535............... Revise the title of this section to add
clarity.
40 CFR 63.7535(b)............ Add language to the paragraph to clarify
that you must operate monitoring systems
while the unit is operating and
compliance is required. Add ``scheduled
CMS maintenance'' to the list of periods
during which you are not required to
collect data from a monitoring system.
40 CFR 63.7535(c)............ Amend this paragraph to clarify that
operators must record results of CMS
performance audits, dates and duration
of periods when the CMS is out of
control to completion of the corrective
actions necessary to return the CMS to
normal operation. Also adding language
to clarify that all collected data must
be used to assess compliance.
40 CFR 63.7535(d)............ Revise the paragraph to remove references
to ``out-of-control periods'' and to add
``system accuracy audits'' to the list
of periods during which data do not need
to be collected.
40 CFR 63.7540(a)............ Add references to Tables 1, 2, 3, and 4
to add clarity.
40 CFR 63.7540(a)(2)......... Split this paragraph into two
subparagraphs for clarity.
40 CFR 63.7540(a)(3)......... Revise the paragraph to clarify that fuel
analysis for hydrogen chloride is
applicable for only solid and liquid
fuels, and to clarify that certain fuels
are not subject to the fuel analysis
requirements.
40 CFR 63.7540(a)(3) and Change the references to Equation 9 to
(a)(3)(iii). Equation 11 to accommodate the change in
numbering of equations.
40 CFR 63.7540(a)(4), (a)(5), Revise these paragraphs to clarify that
and (a)(6). certain fuels are not subject to the
fuel analysis requirements.
40 CFR 63.7540(a)(5) and Change the reference to Equation 11 to
(a)(5)(iii). Equation 12 to accommodate the change in
numbering of equations.
40 CFR 63.7540(a)(9)......... Revise this paragraph and the
subparagraphs to remove the references
to the EPA performance specifications
for a PM CEMS, and replace them with a
reference to the PM CPMS provisions in
the facility's site-specific monitoring
plan required by 40 CFR 63.7505.
40 CFR 63.7540(a)(10)(i) and Revise this paragraph to specify that
(a)(12). required burner inspections be done at
the next burner shutdown, whether it is
scheduled or unscheduled.
40 CFR 63.7541 (a)(3) and (4) Change the 3-hour parameter averages to
30-day rolling parameter averages to
match Table 8 to subpart DDDDD.
40 CFR 63.7545(e)(3)......... Remove a reference to Table 12 (this
table is not included because this is a
proposed rule), and adding language to
clarify that this applies to facilities
``not using a CO CEMS to demonstrate
compliance.''
40 CFR 63.7545(f)............ Revise the paragraph to include units
that burn ``gaseous fuel subject to
another subpart of this part'' to add
clarity.
40 CFR 63.7550(c)(6)......... Change the reference to Equation 10 to
Equation 11, to accommodate the change
in numbering of equations.
40 CFR 63.7550(h), (i), and Revise paragraph (h) and adding
(j). paragraphs (i) and (j) to provide
additional instruction on submitting
data to EPA from performance emission
tests, CEMS performance evaluations, and
quarterly data from CEMS and CPMS
consistent with the proposed monitoring
requirements.
40 CFR 63.7555(d)............ Remove a reference to Table 12; this
table is not included because this is a
proposed rule.
40 CFR 63.7555(d)(2)......... Correct an inaccurate reference to 40 CFR
241.3(b)(1)and (2), and to add a
sentence to clarify that certain units
exempt from the incinerator standards
under section 129(g)(1) of the Clean Air
Act do not need to maintain the records
described in this paragraph.
40 CFR 63.7555(d)(4)......... Change the reference to Equation 10 to
Equation 11, to accommodate the change
in numbering of equations.
40 CFR 63.7555(d)(5)......... Change the reference to Equation 11 to
Equation 12, to accommodate the change
in numbering of equations.
40 CFR 63.7555(h)............ Revise the paragraph to include units
that burn ``gaseous fuel subject to
another subpart of this part'' to add
clarity.
40 CFR 63.7575............... Revise the definition of process heater
to include units heating hot water as a
process heat transfer medium.
Edit the definition of each solid fuel
combustor design-based subcategory to
establish a hierarchy and assisted
affected sources by clarifying
applicability for units with multiple
combustor types.
Revise the definition of ``dutch oven''
to clarify that fluidized bed boilers
are not part of the dutch oven design
category.
Revise the definition of ``energy
assessment'' to clarify the length of
days for each category of facilities.
Revise the definition of ``equivalent''
to remove references to hydrogen
sulfide.
Revise the definition of ``fluidized bed
boiler'' to clarify that pulverized coal
boilers are not included.
Revise the definition of ``hybrid
suspension grate boiler'' to clarify
that ``the fuel combusted in these units
exceed a moisture content of 40 percent
on an as-fired basis'' and ``Fluidized
bed, dutch oven, and pile burner designs
are not part of the hybrid suspension
grate boiler design category.''
Revise the definition of ``fuel cell'' to
clarify that ``fluidized bed, dutch
oven, pile burner, hybrid suspension
grate, and suspension burners are not
part of the fuel cell subcategory.''
Revise the definition of ``liquid fuel''
to include vegetable oil.
[[Page 80620]]
Revise the definition of ``process
heater'' to include ``units heating hot
water as a process heat transfer
medium'' and to clarify that ``waste
heat process heaters are excluded from
this definition'' similar to the
exemption allowed for waste heat
boilers.
Revise the definition of ``steam output''
to include a description of the total
energy output for a boiler that
generates only electricity.
Revise the definition of ``stoker'' to
clarify that ``fluidized bed, dutch
oven, pile burner, hybrid suspension
grate, suspension burners, and fuel
cells are not considered to be a stoker
design.''
Revise the term ``suspension boiler'' to
instead be ``suspension burner'', to
provide consistent terminology
throughout the rule and to clarify that
``fluidized bed, dutch oven, pile
burner, and hybrid suspension grate
units are not part of the suspension
burner subcategory.''
Revise the definition of ``waste heat
boiler'' to clarify that the definition
includes fired and unfired waste heat
boilers.
Revise the definition of ``waste heat
process heater to clarify that the
definition includes fired and unfired
waste heat process heaters.
Add new definitions of ``30-day rolling
average'', ``average annual heat input
rate'', ``biodiesel'', ``daily block
average'', ``heavy liquid'', ``light
liquid'', ``other combustor'', ``oxygen
analyzer'', ``oxygen trim system'',
``pile burner'', ``residential boiler'',
``sloped grate'', ``stoker/sloped grate/
other unit designed to burn kiln dried
biomass'', ``stoker/sloped grate/other
unit designed to burn wet biomass'',
``total selected metals'', ``unit
designed to burn heavy liquid
subcategory'', ``unit designed to burn
light liquid subcategory'', and
``vegetable oil''.
Remove the definition of ``liquid fuel
subcategory.''
Tables 1 and 2 to subpart Revise the sampling volumes collected and
DDDDD. also the prescribed span values
associated with the emission measurement
methods to account for changes in the
numerical emission limits and to be
consistent with the proposed emission
limits.
Table 3 to subpart DDDDD..... Revise items 1, 2, and 3 to account for
the proposed changes in the tune-up
requirements.
Revise item 4c to clarify the major
systems ``consuming energy from affected
boilers and process heaters and which
are under the control of the boiler/
process heater owner/operator.''
Revise item 5 to remove the reference to
Table 12; this table is not included
because this is a proposed rule.
Table 4 to subpart DDDDD..... Revise the operating limits for items 1
and 2 to read ``one-hour'' instead of
``1-hour''.
Revise certain items in the table to
clarify the applicability of the
parameter operating limits, and to
reflect that replace PM CEMS with PM
CPMS requirements.
Revise items 1, 2, and 4 in the table to
reflect the fact that we are proposing
that compliance with the operating
limits is based on a 30-day rolling
average.
Table 6 to subpart DDDDD..... Revise items 1, 2, and 3 to provide
additional instruction on demonstrating
compliance.
Revise item 4 to replace the requirements
for hydrogen sulfide in other gas 1
fuels with requirements for total
selected metals in solid fuels.
Table 7 to subpart DDDDD..... Revise item 1 to include total selected
metals with PM and mercury, and to
clarify the applicability of the
operating limits described in that item.
Table 8 to subpart DDDDD..... Include provisions for demonstrating
continuous compliance with a PM CPMS, to
reflect proposed changes elsewhere in
the rule.
Revise various items to reflect the
proposed change from 12-hour block
averages to 30-day rolling averages for
demonstrating compliance.
Revise the operating load compliance
provisions to be consistent with the
operating limit in Table 4 to subpart
DDDDD.
Table 11 to subpart DDDDD.... Delete Table 11 to subpart DDDDD to be
consistent with the proposal to remove
the numerical emission limits for dioxin/
furan emissions.
Table 12 to subpart DDDDD.... Remove Table 12 to subpart DDDDD because
this is a proposed rule and Table 12 was
needed only because the rule published
on March 21, 2011 (76 FR 15608) was a
final rule.
------------------------------------------------------------------------
VII. Impacts of This Proposed Rule
A. What are the air impacts?
Table 4 of this preamble illustrates, for each basic fuel
subcategory, the emissions reductions achieved by the proposed 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 volatile
organic compound (VOC)) will be reduced by 45,000 tons per year for
existing units and 19 tons per year for new units. Emissions of HCl
will be reduced by 37,000 tons per year for existing units and 0 tons
per year for new units. Emissions of Hg will be reduced between 0.5 to
1.8 tons per year for existing units and 20.2 pounds per year for new
units. Emissions of filterable PM will be reduced by 41,200 tons per
year for existing units and 1,500 tons per year for new units.
Emissions of non-mercury metals (i.e., antimony, arsenic, beryllium,
cadmium, chromium, cobalt, lead, manganese, nickel, and selenium) will
be reduced by 2,200 tons per year for existing units and 19 tons per
year for new units. In addition, emissions of SO2 are
estimated to be reduced by 558,400 tons per year for existing sources
and 0 tons per year for new sources. A discussion of the methodology
used to estimate emissions and emissions reductions is presented in
``Revised (November 2011) Methodology for Estimating Cost and Emission
Impacts for Industrial, Commercial, and Institutional Boilers and
Process Heaters NESHAP--Major Source'' in the docket.
[[Page 80621]]
Table 4--Summary of Emissions Reductions for Existing and New Sources
[Tons/yr]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non
Source Subcategory HCl PM mercury Mercury \b\ VOC
metals \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing Units............................. Limited Use............. 1 2 0.45 2.2E-04...................... 1
Solid units............. 34,815 34,830 271 0.4 to 1.4................... 2,487
Liquid units............ 2,039 6,240 1,905 0.04 to 0.3.................. 1,815
Non-Continental Liquid 158 29 4 0.001 to 0.01................ 169
units.
Gas 1 (NG/RG) units.... 21 118 0.9 0.01......................... 85
Gas 1 Metallurgical 0.4 3 0.02 0.001........................ 23
Furnaces.
Gas 2 (other) units..... 4 11 0.07 0.004 to 0.005............... 138
--------------------------------------------------------------------------------------------------------------------------------------------------------
New Units.................................. Solid units............. 0 1,462 19 0.01......................... 0
Liquid units............ 0 0 0 0............................ 0
Gas 1 units............. 0 0 0 0............................ 0
Gas 1 Metallurgical 0 0 0 0............................ 0
Furnaces.
Gas 2 (other) units..... 0 0 0 0............................ 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\Hg reductions are presented as a range due to adjustments on reported fractions and limits of detection. See memorandum entitled ``Revised (November
2011) Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission
Standards for Hazardous Air Pollutants--Major Source'' for a description of the two methods for estimating Hg reductions.
B. What are the water and solid waste impacts?
The EPA estimated the additional water usage that would result from
installing wet scrubbers to meet the emission limits for HCl would be
1.2 billion gallons per year for existing sources and 0 gallons per
year for new sources. In addition to the increased water usage, an
additional 416 million gallons per year of wastewater would be produced
for existing sources and 0 gallons per year for new sources. The annual
costs of treating the additional wastewater are $2.3 million for
existing sources and $0 for new sources. These costs are accounted for
in the control costs estimates.
The EPA estimated the additional solid waste that would result from
the MACT floor level of control to be 286,000 tons per year for
existing sources and 1,700 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 that is injected into exhaust streams or used
to filter gas streams. The costs of handling the additional solid waste
generated are $12.0 million for existing sources and $70,600 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 (November 2011) Methodology for Estimating Cost
and Emission Impacts for Industrial, Commercial, and Institutional
Boilers and Process Heaters NESHAP--Major Source'' in the Docket.
C. What are the energy impacts?
The EPA expects an increase of approximately 1.5 billion kilowatt
hours (kWh) in national annual energy usage as a result of the proposed
rule. Of this amount, 1.4 billion kWh would be from existing sources
and 120 million kWh 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 the proposed rule. Additionally, the 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 47.3 trillion BTU each year from existing
sources. The EPA did not estimate fuel savings and efficiency
improvements on new boilers since new boilers are expected to be tuned-
up up upon installation and will not achieve additional fuel savings in
the first year. This fuel savings estimate includes only those fuel
savings resulting from Gas 1, 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 the proposed 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. For 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 proposed 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;
electrostatic precipitators for units meeting Hg limits but requiring
additional control to meet the PM or total selected metals limits; wet
scrubbers or fabric filters with dry injection to meet the HCl limits;
tune-ups, replacement burners, combustion controls, and oxidation
catalysts for CO and organic HAP control; and tune-ups 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 the proposed rule. The resulting
total national cost impact of the proposed rule is 5.4 billion dollars
in capital expenditures and 1.9 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 1.5 billion dollars. The total capital and annual costs
include costs for control devices, work practices, testing and
monitoring. While these
[[Page 80622]]
costs are higher than the costs estimated for the final rule, these
estimates are based on an inventory that includes 300 additional units
that were identified after the final rule was completed. The costs
associated with the final rule inventory are just under $5.0 billion in
capital expenditures and $1.75 billion in total annual costs ($1.35
billion considering fuel savings). Table 5 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.
Table 5--Summary of Capital and Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
Testing and Annualized
Estimated/ monitoring cost(10 \6\ $/
Source Subcategory Projected Capital costs annualized yr)
number of (10 \6\ $) costs (10 \6\ (considering
affected units $/yr) fuel savings)
----------------------------------------------------------------------------------------------------------------
Existing Units................ Coal units...... 616 2,713 46 953
Biomass units... 508 639 33 169
Heavy Liquid 322 769 8.4 264
units.
Light Liquid 581 930 5.1 277
units.
Non-Continental 44 181 1.5 42
Liquid units.
Gas 1 (NG/RG) 11,911 77 0.9 (295)
units.
Gas 2 (other) 129 132 2.3 55
units.
Energy Assessment............. ALL............. 1,704 N/A N/A 28
(Facilities)
New Units..................... Coal units...... 0 0 0 0
Biomass units... 82 381 5.6 \a\ 99
Liquid units.... 0 0 0 0
Gas 1 (NG/RG) 1,762 11 0 \a\ 5.1
units.
Gas 2 (other) 0 0 0 0
units.
----------------------------------------------------------------------------------------------------------------
\a\ Total annualized costs for new units do not account for fuel savings since no fuel savings are estimated in
the first year for new units.
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 the proposed
rule for new boilers in the 3rd year is 393 million dollars in capital
expenditures and 104 million dollars per year in total annual costs.
Potential control device cost savings and increased recordkeeping
and reporting costs associated with the emissions averaging provisions
in the proposed 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 (November 2011) Methodology for Estimating Cost
and Emission Impacts for Industrial, Commercial, and Institutional
Boilers and Process Heaters NESHAP--Major Source'' in the Docket.
E. What are the economic impacts?
The EPA analyzed the economic impacts of this proposed rule using
the methodology that was discussed in the final rule RIA and in the
preamble to the final rule. See FR 76 15651. The market impact results
are very similar to the results presented in the final rule and the
RIA. The agency's economic model suggests the average national price
increases for industrial sectors are less than 0.01 percent, while
average annual domestic production may fall by less than 0.01 percent.
Because of higher domestic prices, imports slightly rise. The increase
in US trade deficit is now 1.93 billion dollars (2006$). For the RIA,
it was 1.86 billion dollars (2006$). The results for sales tests for
small businesses were somewhat reduced. For the sales tests using small
companies identified in the Combustion Survey, the mean cost to
receipts dropped from 4 percent in the RIA to 2 percent for this
proposed rule and the median was 0.2 percent for both. The number of
parent companies with sales tests exceeding 3 percent dropped from 8 in
the RIA to 6 for this proposed rule. There was no change in the results
for small public entities. Median cost is still about $1.1 million and
representative small major public entities would have cost-to-revenue
ratios above 10 percent. The change in employment estimates between the
RIA and the proposal is minimal. In the RIA for the final rule, we
estimated employment changes ranging between -3100 to +6,500 employees,
with a central estimate of +1,700. For this proposal, we estimate
employment changes ranging between -3000 to +6,300 employees, with a
central estimate of +1,600. These estimated annual employment changes
compared to the baseline employment, and are for the time period for
which the annualized cost applies (2015 to 2029).
The benefits estimates increased for this proposal. In the RIA for
the final rule, we estimated benefits ranging from $22 billion (2008$)
to 54 billion (2008$) at a 3 percent discount rate. For this proposal,
we estimate benefits ranging from $27 billion (2008$) to 67 billion
(2008$) at a 3 percent discount rate. The range for the RIA was $20
billion (2008$) to 49 billion (2008$) at a 7 percent discount rate. The
range for this proposal is $25 billion (2008$) to 61 billion (2008$) at
a 7 percent discount rate.
F. What are the benefits of this proposed rule?
We calculated health benefits using the methodology described in
the RIA prepared for the March 21, 2011, final rule. We incorporated
the revised emission reductions estimated for this reconsideration
proposal into the analysis. We were unable to estimate the benefits
from reducing exposure to HAP and ozone, ecosystem impairment, and
visibility impairment, including reducing 187,000 tons of carbon
monoxide, 37,000 tons of HCl, 1,000 tons of HF, 1,000 to 3,600 pounds
of Hg, and 2,200 tons of other metals. Please refer to the full
description in the final Boiler RIA of the unquantified benefits as
well as technical details of the analysis and its limitations and
uncertainties. These monetized benefits are approximately 23 percent
higher than the final rule benefits due to the increase in
SO2 emission reductions associated with the additional units
affected by the rule and the revised HCl limit. We estimate the total
monetized benefits of this proposed regulatory action to be $27 billion
to $67 billion (2008$, 3 percent discount rate) in the implementation
year (2015). A summary
[[Page 80623]]
of the monetized benefits estimates at discount rates of 3 percent and
7 percent is provided in Table 6 of this preamble. A summary of the
avoided health incidences is provided in Table 7 of this preamble.
Table 6--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% discount
(tons) discount rate) rate)
----------------------------------------------------------------------------------------------------------------
PM2.5-related benefits:
Direct PM2.5................... 25,601 $1,800 to $4,500.. $1,700 to $4,100.
SO2............................ 558,430 $25,000 to $63,000 $23,000 to $57,000.
=================
Total...................... $27,000 to $25,000 to
$67,000 $61,000..
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), 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 $5.8 to $75 million depending on the discount rate. These benefits reflect existing boilers and new
boilers anticipated to come online by 2015.
Table 7--Summary of the Avoided Health Incidences for the Final Boiler
MACT \1\
------------------------------------------------------------------------
Avoided health
incidences
------------------------------------------------------------------------
Avoided Premature Mortality............................. 3,100-8,000
Avoided Morbidity....................................... ..............
Chronic Bronchitis...................................... 2,000
Acute Myocardial Infarction............................. 4,900
Hospital Admissions, Respiratory........................ 750
Hospital Admissions, Cardiovascular..................... 1,600
Emergency Room Visits, Respiratory...................... 3,000
Acute Bronchitis........................................ 4,600
Work Loss Days.......................................... 390,000
Asthma Exacerbation..................................... 51,000
Minor Restricted Activity Days.......................... 2,300,000
Lower Respiratory Symptoms.............................. 55,000
Upper Respiratory Symptoms.............................. 41,000
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), 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 new boilers
anticipated to come online by 2015.
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 nitrogen oxide (NOX), CO and
SO2 and an increase in carbon dioxide (CO2)
emissions. Since NOX and SO2 are covered by
capped emissions trading programs, these pollutants do not contribute
disbenefits from additional electricity demand. Additional
CO2 emissions from increased electricity consumption are
estimated to be 931,000 tons per year from existing units and 79,700
tons per year from new units. Energy disbenefits due to increased
CO2 emissions range from $5.8 million to $75 million
depending on the discount rate, and thus do not affect the rounded
monetized benefits.
VIII. Relationship of This Proposed Action to Section 112(c)(6) of the
Clean Air Act
Section 112(c)(6) of the CAA requires the 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). The 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:
polycyclic organic matter (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), the 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.
For Hg, the 112(c)(6) requirement is directly met through the
proposed emission limits for Hg. Through these emission limits, the
types of boilers and process heaters listed in section 112(c)(6) are
subject to regulation.
For POM, which are 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. The tune-up
requirement for all major source units and the CO emission limits will
ensure that good combustion practices are followed, thus minimizing
emissions of organic HAP, including POM. Any POM that do form
[[Page 80624]]
during combustion would be reduced by the various post-combustion
controls. The add-on PM control systems (either fabric filter or wet
scrubber) and activated carbon injection in the fabric filter-based
systems would reduce emissions of these organic pollutants. 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.
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), 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, the EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
Because this action is proposing changes to a final rule and does
not increase costs by an amount that would qualify the proposed rule,
by itself, as a major rule, the EPA did not prepare a new RIA for this
action. Instead, the EPA prepared an assessment of the changes in the
costs and benefits of this proposed rule compared to the costs and
benefits associated with the March 21, 2011, final rule. Overall, the
costs and impacts are estimated to be similar to the costs and impacts
associated with the final rule, although the distribution is somewhat
different and the number of affected units in the inventory has
increased by about 300 units. When comparing the costs using only those
sources that were part of the final rule inventory, the costs have
decreased. The EPA re-ran the multimarket model to assess changes in
economic impacts, and this analysis confirmed that the overall economic
impacts are similar to the final rule. The benefits are projected to
increase by about 23 percent because of the increase in the estimated
SO2 reductions. A summary of the costs and benefits of the
final rule is provided in the preamble to the final rule (see 76 FR
15658) and the detailed analysis for the final rule is provided in the
RIA for the final rule. In addition, memoranda are provided in the
docket to document the changes in costs, economic impacts, and benefits
associated with this proposed rule.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule will
be submitted for approval to the OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by the EPA has been assigned EPA ICR number 2028.07.
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 the 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 proposed 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 a
notification of intent to commence burning solid waste materials and
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. 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 $96.2 million. This
includes 324,954 labor hours per year at a total labor cost of $30.7
million per year, and total non-labor capital costs of $65.5 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 VII.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 97,613 hours per year at a
total labor cost of $5.1 million per year. Burden is defined at 5 CFR
1320.3(b).
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2002-0058. Submit any comments related to the ICR to the EPA and
OMB. See ADDRESSES section at the beginning of this notice for where to
submit comments to the EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after December 23, 2011, a comment to OMB
[[Page 80625]]
is best assured of having its full effect if OMB receives it by January
23, 2012. The final rule will respond to any OMB or public comments on
the information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (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.\3\ The RFA also allows an agency to
``consider a series of closely related rules as one rule for the
purposes of sections'' 603 (initial regulatory flexibility analysis)
and 604 (final regulatory flexibility analysis) in order to avoid
``duplicative action.'' 5 U.S.C. 605(c). This proposed rule is closely
related to the final major source rule, which the EPA signed on
February 21, 2011. The EPA prepared initial regulatory flexibility
analyses in connection with the major source rule. Therefore, pursuant
to Sec. 605(c), the EPA is not required to complete an initial
regulatory flexibility analysis for this rule.
---------------------------------------------------------------------------
\3\ 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.
---------------------------------------------------------------------------
The EPA has been concerned with potential small entity impacts
since it began developing the major source rule. The EPA conducted
outreach to small entities and, pursuant to Sec. 609 of RFA, convened
a Small Business Advocacy Review Panel to obtain advice and
recommendations from small entity representatives.
Pursuant to the RFA, the EPA used the Panel's report and prepared
both an initial regulatory flexibility analysis and a final regulatory
flexibility analysis in connection with the closely related major
source rule. Convening an additional Panel and preparing an additional
initial regulatory flexibility analysis would be procedurally
duplicative and is unnecessary given that the issues here are within
the scope of those considered by the Panel. In addition, this
reconsideration proposal would decrease capital and annualized costs on
small entities by about 3 percent and 10 percent, respectively,
relative to the closely related final rule. We invite comments on the
aspects of the proposal outlined in section V of this preamble and
their impacts on small entities.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
state, local, and tribal governments and the private sector. This March
21, 2011, final rule contained 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 one year.
Accordingly, the EPA prepared under section 202 of the UMRA a written
statement for the final rule. The discussion below has been updated to
reflect the proposed changes.
1. Statutory Authority
As discussed in section I of this preamble, the statutory authority
for this proposed 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.
2. Social Costs and Benefits
The regulatory impact analysis prepared for the final rule, which
we have not revised for this proposed rule, including the agency's
assessment of costs and benefits, is detailed in the ``Regulatory
Impact Analysis for the Final Industrial Boilers and Process Heaters
MACT (2011)'' in the docket. Based on estimated compliance costs
associated with this proposed rule and the predicted change in prices
and production in the affected industries, the estimated social costs
of this proposed rule are $1.49 billion (2008 dollars).
It is estimated that 3 years after implementation of this proposed
rule, HAP would be reduced by 45,000 tons per year, including
reductions in HCl, 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 annual reductions in fine particulate matter
(PM2.5) and in SO2 that would occur, including
25,000 thousand tons of PM2.5 and 558 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 2015 associated with the implementation of the
proposed alternative range from $27 billion (2008 dollars) to $67
billion (2008 dollars) when using a 3 percent discount rate (or from
$25 billion (2008 dollars) to $61 billion (2008 dollars) when using a 7
percent discount rate). This estimate, at a 3 percent discount rate, is
about $25 billion (2008 dollars) to $65 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 and the memos updating
the impacts and benefits 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 proposed
rule and any
[[Page 80626]]
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 proposed rule on any particular areas of the country,
state or local governments, types of communities (e.g., urban, rural),
or particular industry segments. See the results of the ``Regulatory
Impact Analysis for the Final Industrial Boilers and Process Heaters
MACT (2011).''
4. Effects on the National Economy
The UMRA requires that we estimate the effect of this proposed rule
on the national economy. To the extent feasible, we must estimate the
effect on productivity, economic growth, full employment, creation of
productive jobs, and international competitiveness of the U.S. goods
and services, if we determine that accurate estimates are reasonably
feasible and that such effect is relevant and material.
The nationwide economic impact of this proposed rule is presented
in the ``Regulatory Impact Analysis for the Final Industrial Boilers
and Process Heaters MACT (2011)'' and two memoranda that are included
in the docket, entitled ``Health Benefits for Boiler MACT
Reconsideration Proposal'' and ``Regulatory Impact Results for the
Reconsideration Proposal for National Emission Standards for Hazardous
Air Pollutants for Industrial, Commercial, and Institutional Boilers
and Process Heaters at Major Sources,'' which update the RIA analyses.
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 proposed 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 UMRA 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 consulted with State and local air pollution control
officials during the development of the final rule. We have also held
meetings on this proposed 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 docket to document these meetings.
Consistent with section 205, the EPA has 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 the
emission limits in this proposed rule are based represents the MACT
floors for all subcategories and, as a result, it is the least costly
and least burdensome alternative.
This rule is not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments. While some small governments may
have some sources affected by this proposed rule, the impacts are not
expected to be significant. Therefore, this proposed rule is not
subject to the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
This action 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. This proposed rule will not impose
direct compliance costs on state or local governments, and will not
preempt state law. Thus, Executive Order 13132 does not apply to this
action.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between the EPA and state and local
governments, the EPA specifically solicits comment on this proposed
action from state and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial direct effects on tribal governments, on the relationship
between the federal government and Indian tribes, or on the
distribution of power and responsibilities between the federal
government and Indian tribes, as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
The EPA specifically solicits additional comment on this proposed
action from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying only to those regulatory actions that concern health
or safety risks, such that the analysis required under section 5-501 of
the Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it is based
solely on technology performance.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. For the March 21, 2011, final rule, we
estimated a 0.05 percent price increase for the energy sector and a -
0.02 percent percentage change in production. We estimated a 0.09
percent increase in energy imports. For more information on the
estimated energy effects, please refer to the ``Regulatory Impact
Analysis for the Final Industrial Boilers and Process Heaters MACT
(2011).'' The analysis is available in the public docket. While we did
not redo the RIA for this proposed action, the energy impacts for
existing sources decreased slightly, and the energy impacts for new
source increased due to the increased number of new sources that is now
projected. Overall, the projected energy use increased slightly but
would not change the analysis that was conducted for the final rule.
Therefore, we conclude that the proposed 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
[[Page 80627]]
Act of 1995 (NTTAA), Public Law 104-113,(15 U.S.C. 272 note) directs
the 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, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs the EPA to provide
Congress, through OMB, explanations when the agency decides not use
available and applicable voluntary consensus standards. The EPA is not
proposing the use of any additional EPA test methods, and, therefore,
the NTTAA discussion in the March 21, 2011, final rule is still valid.
See 76 FR 15660-15662.
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. 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 and low-income
populations in the United States.
For the March 2011 final rule, the EPA determined that rule would
not have disproportionately high and adverse human health or
environmental effects on minority or low-income populations because it
increases the level of environmental protection for all affected
populations without having any disproportionately high and adverse
human health or environmental effects on any population, including any
minority or low-income population. Compared to the final rule, while
the proposed amendments are somewhat less stringent for some
subcategories of units and more stringent for some others, the overall
increased health benefits demonstrate that the conclusions from the
environmental justice analysis conducted for the final rule are still
valid.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.
Dated: December 2, 2011.
Lisa P. Jackson,
Administrator.
For the reasons cited in the preamble, and under the authority of
42 U.S.C. 7401 et seq., Subpart DDDDD of 40 CFR part 63 is proposed to
be revised to read as follows:
PART 63--[AMENDED]
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 Is there a minimum amount of monitoring data I must obtain?
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
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
[[Page 80628]]
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
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 (n) 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, or part 60 or part 61 of
this chapter provided that at least 50 percent of the heat input to the
boiler or process heater 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 unit that burns hazardous waste covered by Subpart EEE of
this part. A unit that is exempt from Subpart EEE as specified in Sec.
63.1200(b) is not covered by Subpart EEE.
(n) Residential boilers as defined in this subpart.
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 [DATE 60 DAYS AFTER THE FINAL RULE
IS PUBLISHED IN THE Federal Register] 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 [DATE 3 YEARS AFTER PUBLICATION
OF THE FINAL RULE IN THE Federal Register], except as provided in Sec.
63.6(i).
(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/sloped grate/other units designed to burn kiln dried
biomass/bio-based solids.
(e) Stokers/sloped grate/other units designed to burn wet biomass/
bio-based solids.
(f) Fluidized bed units designed to burn biomass/bio-based solid.
(g) Suspension burners designed to burn biomass/bio-based solid.
(h) Dutch ovens/pile burners designed to burn biomass/bio-based
solid.
(i) Fuel cells designed to burn biomass/bio-based solid.
(j) Hybrid suspension/grate burners designed to burn wet biomass/
bio-based solid.
(k) Units designed to burn solid fuel.
(l) Units designed to burn liquid fuel.
(m) Units designed to burn heavy liquid fuel.
(n) Units designed to burn light liquid fuel.
(o) Units designed to burn liquid fuel in non-continental states or
territories.
(p) Units designed to burn natural gas, refinery gas or other gas 1
fuels.
(q) Units designed to burn gas 2 (other) gases.
(r) Metal process furnaces.
(s) 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), (c), and (d) of
this section. You must meet these requirements at all times, except as
provided in paragraph (e) of this section.
(1) You must meet each emission limit and work practice standard in
[[Page 80629]]
Tables 1 through 3 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. The output-based emission
limits (i.e., in units of pounds per million Btu of steam output) in
Tables 1 or 2 to this subpart are an alternative applicable only to
boilers that generate steam. The output-based emission limits are not
applicable to process heaters that do not generate steam.
(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.
(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.
(d) Boilers and process heaters with a heat input capacity of less
than 5 million Btu per hour in the units designed to burn natural gas,
refinery gas or other gas 1 fuels subcategory; units designed to burn
gas 2 (other) fuels subcategory, or units designed to burn light liquid
fuels subcategory must complete a tune-up every 5 years as specified in
Sec. 63.7540.
(e) These standards apply at all times, except during periods of
startup and shutdown, during which time you must comply only with Table
3 to this subpart.
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 limitation(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 occurrence 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, work
practice standards, and operating limits in this subpart. These limits
apply to you at all times except for the periods noted in Sec.
63.7500(e).
(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 emissions monitoring
system (CEMS), continuous opacity monitoring system (COMS), continuous
parameter
[[Page 80630]]
monitoring system (CPMS), or particulate matter continuous parameter
monitoring system (PM CPMS), where applicable. You may demonstrate
compliance with the applicable emission limit for hydrogen chloride,
mercury, or total selected metals using fuel analysis if the emission
rate calculated according to Sec. 63.7530(c) is less than the
applicable emission limit. (For gaseous fuels, you may not use fuel
analyses to comply with the total selected metals alternative standard
or the hydrogen chloride standard.) Otherwise, you must demonstrate
compliance for hydrogen chloride, mercury, or total selected metals
using performance testing, if subject to an applicable emission limit
listed in Table 1 or 2 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 CPMS), 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 CPMS. 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
CPMS), you must develop, and submit to the delegated authority for
approval upon request, a site-specific monitoring plan that addresses
design, data collection, and the quality assurance and quality control
elements outlined in Sec. 63.8(d) and the elements described in
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. Using the process
described in Sec. 63.8(f)(4), you may request approval of alternative
monitoring system quality assurance and quality control procedures in
place of those specified in this paragraph and, if approved, include
the alternatives in your site-specific monitoring plan.
(i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
(ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
(iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations, accuracy audits, analytical drift).
(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 are required to or 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 all the following:
(1) Conduct performance tests according to Sec. 63.7520 and Table
5 to this subpart.
(2) 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, except as specified in paragraphs (a)(2)(i) through (iii) of
this section.
(i) For affected sources that burn a single type of fuel, you are
not required 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. 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.
(ii) When natural gas, refinery gas, other gas 1 fuels are co-fired
with other fuels, you are not required to conduct a fuel analysis of
those fuels according to Sec. 63.7521 and Table 6 to this subpart. If
gaseous fuels other than natural gas, refinery gas, or other gas 1
fuels are co-fired with other fuels and those gaseous fuels are subject
to another subpart of this part, you are not required to conduct a fuel
analysis of those fuels according to Sec. 63.7521 and Table 6 to this
subpart.
(iii) You are not required to conduct a chlorine fuel analysis for
any gaseous fuels. You must still conduct a fuel analysis for mercury
on gaseous fuels unless the fuel is exempted in paragraphs (a)(2)(i)
through (iii) of this section.
(3) Establish operating limits according to Sec. 63.7530 and Table
7 to this subpart.
(4) Conduct CMS performance evaluations according to Sec. 63.7525.
(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, mercury or total selected metals 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. The fuels described in paragraph (a)(2)(i) through (iii) of
this section are exempt from these fuel analysis and operating limit
requirements. Boilers and process heaters that use a CEMS for mercury
or hydrogen chloride are exempt from the performance testing and
operating limit requirements specified in paragraph (a) of this
section.
(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, or conduct a performance evaluation of your
continuous carbon monoxide monitor, if applicable, according to Sec.
63.7525(a). Boilers and process heaters that use a continuous emission
monitoring system for carbon monoxide are exempt from the initial
carbon monoxide performance testing and oxygen concentration operating
limit requirements specified in paragraph (a) of this section.
(d) If your boiler or process heater subject to a PM limit has an
average annual heat input rate greater than 250 MMBtu per hour from
solid fossil fuel and/or residual oil, your initial
[[Page 80631]]
compliance demonstration for PM is to conduct a performance test in
accordance with Sec. 63.7520 and Table 5 to this subpart. Owners of
boilers and process heaters who elect to comply with the alternative
total selected metals limit are not required to install a CPMS.
(e) For existing affected sources, you must complete the initial
compliance demonstration, 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. You must complete an initial tune-up by following the
procedures described in Sec. 63.7540(a)(10)(i) through (vi) and
complete the one-time energy assessment specified in Table 3 to this
subpart, both no later than the compliance date specified in Sec.
63.7495.
(f) For new or reconstructed affected sources, you must complete
the initial compliance demonstration with the emission limits no later
than [DATE 240 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE Federal
Register] or within 180 days after startup of the source, whichever is
later.
(g) For new or reconstructed affected sources, you must demonstrate
initial compliance with the applicable work practice standards in Table
3 to this subpart no later than the compliance date that is specified
in Sec. 63.7595 and according to the applicable provisions in Sec.
63.7(a)(2). You must conduct the initial tune-up within 365 days after
startup of the source. Thereafter, you are required to complete the
applicable annual, biennial, or 5-year tune-up as specified in Sec.
63.7540(a).
(h) 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 as specified in paragraphs (b)
through (e) of this section. Annual performance tests must be completed
no more than 13 months after the previous performance test, except as
specified in paragraphs (b) through (e) of this section.
(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 (or, in limited instances as specified in Tables
1 and 2 to this subpart, at or below 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 (or, in limited instances as specified in
Tables 1 and 2 to this subpart, at or below 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
hydrogen chloride. The requirement to test at maximum mercury input
level is waived unless the stack test is conducted for mercury. The
requirement to test at maximum total selected metals input level is
waived unless the stack test is conducted for total selected metals.
(d) If a performance test shows emissions exceeded the emission
limit or 75 percent of the emission limit (as specified in Tables 1 and
2) for a pollutant, you must conduct annual performance tests for that
pollutant until all performance tests over a consecutive 2-year period
meet the required level (either 75 percent of the emission or the
emission limit, as specified in Tables 1 and 2).
(e) If you are required to meet an applicable tune-up work practice
standard, you must conduct an annual, biennial, or 5-year performance
tune-up according to Sec. 63.7540(a)(10), (11), or (12), 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. Each 5-year tune-up specified in
Sec. 63.7540(a)(12) must be conducted no more than 61 months after the
previous tune-up. For a new or reconstructed affected source, the first
annual, biennial, or 5-year tune-up must be no later than 13 months, 25
months, or 61 months, respectively, after the initial startup of the
new or reconstructed affected source.
(f) If you demonstrate compliance with the mercury, hydrogen
chloride, or total selected metals 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 or
2 to 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 limits 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.
[[Page 80632]]
(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 total selected metals if you are
opting to comply with the total selected metals alternative standard,
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 and 2 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, the measured mercury concentrations, and the
measured total selected metals 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 and liquid 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.
For solid fuels, you must also conduct fuel analyses for total selected
metals if you are opting to comply with the total selected metals
alternative standard. For gas 2 (other) fuels, you must conduct fuel
analysis for mercury according to the procedures in paragraphs (b)
through (e) of this section and Table 6 to this subpart, as applicable.
(For gaseous fuels, you may not use fuel analyses to comply with the
total selected metals alternative standard or the hydrogen chloride
standard.) For purposes of complying with this section, a fuel gas
system that consists of multiple gaseous fuels collected and mixed with
each other is considered a single fuel type and sampling and analysis
is only required on the combined fuel gas system that will feed the
boiler or process heater. Sampling and analysis of the individual
gaseous streams prior to combining is not required. 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, hydrogen chloride, or total selected
metals in Tables 1 and 2 to this subpart. Gaseous and liquid fuels are
exempt from the sampling 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, if you are required to conduct fuel analyses as specified
in Sec. 63.7510.
(1) You must submit the fuel analysis plan no later than 60 days
before the date that you intend to conduct the initial compliance
demonstration described in Sec. 63.7510.
(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 anticipated fuel type, the notification of whether
you or a fuel supplier will be conducting the fuel analysis.
(iii) For each anticipated 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 anticipated 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, or use an automated sampling mechanism that provides
representative composite fuel samples for each fuel type that includes
both coarse and fine material.
(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 one-hour intervals during the
testing period for sampling during performance stack testing. For
monthly sampling, each composite sample shall be collected at
approximately equal 10-day intervals during the month.
(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.
(ii) At each sampling site, you must dig into the pile to a uniform
depth of approximately 18 inches. You must insert a clean shovel into
the hole and withdraw a sample, making sure that large pieces do not
fall off during sampling; use the same shovel to collect all samples.
(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 large sample pieces (e.g., 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.
[[Page 80633]]
(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 and/or total selected metals) 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, for use in
Equations 7, 8, and 9 of 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 mercury
according to the procedures in paragraphs (g) through (i) of this
section and Table 6 to this subpart, as applicable, except as specified
in paragraph (f)(1) through (3) of this section.
(1) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section for natural gas or
refinery gas.
(2) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section for gaseous fuels that
are subject to another subpart of this part.
(3) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section on gaseous fuels for
units 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 the initial compliance
demonstration described in Sec. 63.7510.
(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 those
exempted from fuel specification analysis under (f)(1) through (3) of
this section anticipated to be burned in each boiler or process heater.
(ii) For each anticipated fuel type, the notification of whether
you or a fuel supplier will be conducting the fuel specification
analysis.
(iii) For each anticipated 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 to this subpart. 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 anticipated fuel type, the analytical methods from
Table 6 to this subpart, with the expected minimum detection levels, to
be used for the measurement of 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 to this subpart 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 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, 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 as specified in paragraph (b)(1) through (3) of this
section, if you satisfy the requirements in paragraphs (c) through (g)
of this section.
(1) You may not include in an average units using a CEMS or PM CPMS
for demonstrating compliance, even if the use of a CEMS or PM CPMS is
optional.
(2) For Hg and HCl, averaging is allowed as follows:
(i) You may average among units in any of the solid fuel
subcategories.
(ii) You may average among units in any of the liquid fuel
subcategories.
(iii) You may average among units in a subcategory of units
designed to burn gas 2 (other) fuels.
(iv) You may not average across the liquid, solid fuel, and gas 2
(other) subcategories.
(3) For particulate matter, averaging is only allowed between units
within each of the following combustor level subcategories and you may
not average across subcategories:
(i) Pulverized coal/solid fossil fuel units.
(ii) Stokers designed to burn coal/solid fossil fuel.
(iii) Fluidized bed units designed to burn coal/solid fossil fuel.
(iv) Stokers/sloped grate/other units designed to burn kiln dried
biomass/bio-based solids.
(v) Stokers/sloped grate/other units designed to burn wet biomass/
bio-based solids.
(vi) Fluidized bed units designed to burn biomass/bio-based solid.
(vii) Suspension burners designed to burn biomass/bio-based solid.
(viii) Dutch ovens/pile burners designed to burn biomass/bio-based
solid.
(ix) Fuel Cells designed to burn biomass/bio-based solid.
(x) Hybrid suspension/grate burners designed to burn wet biomass/
bio-based solid.
(xi) Units designed to burn heavy liquid fuel.
(xii) Units designed to burn light liquid fuel.
(xiii) Units designed to burn liquid fuel in non-continental states
or territories.
(xiv) Units designed to burn gas 2 (other) gases.
(c) For each existing boiler or process heater in the averaging
group, the emission rate achieved during the initial
[[Page 80634]]
compliance test for the HAP being averaged must not exceed the emission
level that was being achieved on [DATE 60 DAYS AFTER PUBLICATION OF THE
FINAL RULE IN THE Federal Register] 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 [DATE 60
DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE Federal Register].
(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 1a or 1b 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. Use Equation 1a if you are complying with the emission limits
on a heat input basis and use Equation 1b if you are complying with the
emission limits on a steam generation (output) basis.
[GRAPHIC] [TIFF OMITTED] TP23DE11.029
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.
[GRAPHIC] [TIFF OMITTED] TP23DE11.030
Where:
AveWeightedEmissions = Average weighted emissions for particulate
matter, hydrogen chloride, or mercury, in units of pounds per
million Btu of steam output.
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 steam output.
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). If you are taking
credit for energy conservation measures from a unit according to
Sec. 63.7533, use the adjusted emission level for that unit,
Eadj, determined according to Sec. 63.7533 for that
unit.
So = Maximum steam output capacity of unit, i, in units of million
Btu per hour, as defined in Sec. 63.7575.
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 1a 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 that are in pounds per
million Btu of heat input.
[GRAPHIC] [TIFF OMITTED] TP23DE11.031
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 per hour.
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 3a or 3b of this
section to calculate the average weighted emission rate for that month.
Use Equation 3a and the actual heat input for the month for each
existing unit participating in the emissions averaging option if you
are complying with emission limits on a heat input basis. Use Equation
3b and the actual steam generation for the month if you
[[Page 80635]]
are complying with the emission limits on a steam generation (output)
basis.
[GRAPHIC] [TIFF OMITTED] TP23DE11.032
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.
[GRAPHIC] [TIFF OMITTED] TP23DE11.033
Where:
AveWeightedEmissions = Average weighted emission level for
particulate matter, hydrogen chloride, or mercury, in units of
pounds per million Btu of steam output, 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 steam output.
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). If you are taking
credit for energy conservation measures from a unit according to
Sec. 63.7533, use the adjusted emission level for that unit,
Eadj, determined according to Sec. 63.7533 for that
unit.
So = The steam output for that calendar month from unit, i, in units
of million Btu, as defined in Sec. 63.7575.
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 3a 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] TP23DE11.034
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] TP23DE11.035
Where:
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 [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE Federal Register] 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;
[[Page 80636]]
(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] TP23DE11.036
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 or 2 to this subpart, you must
install, operate, and maintain an oxygen analyzer system as defined in
Sec. 63.7575, or a carbon monoxide continuous emission monitoring
system (CO CEMS) according to the procedures in paragraphs (a)(1)
through (10) of this section.
(1) The oxygen analyzer system or the CO CEMS must be installed by
the compliance date specified in Sec. 63.7495. If a CO CEMS is used,
the carbon monoxide level shall be monitored at the outlet of the
boiler or process heater.
(2) You must operate the oxygen trim system with the oxygen level
set at the minimum percent oxygen by volume that is established as the
operating limit for oxygen according to Table 4 to this subpart.
(3) Each CO CEMS must be installed, operated, and maintained
according to the applicable procedures under Performance Specification
4, 4A, or 4B at 40 CFR part 60, appendix B, and according to the site-
specific monitoring plan developed according to Sec. 63.7505(d).
(4) For a new unit, the initial performance evaluation shall be
completed no later than [DATE 240 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE Federal Register] or 180 days after the date of initial
startup, whichever is later. For an
[[Page 80637]]
existing unit, the initial performance evaluation shall be completed no
later than [DATE 3 YEARS AND 180 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE Federal Register].
(5) You must conduct a performance evaluation of each CO CEMS
according to the requirements in Sec. 63.8(e) and according to
Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B.
During each relative accuracy test run of the CO CEMS, emission data
for carbon monoxide must be collected concurrently (or within a 30- to
60-minute period) by both the CO CEMS and by Method 10, 10A, or 10B at
40 CFR part 60, appendix A-4. The relative accuracy testing must be at
representative operating conditions.
(6) For each CO CEMS, you must follow the quality assurance
procedures (e.g., quarterly accuracy determinations and daily
calibration drift tests) of Procedure 1 of appendix F to part 60. The
span value of the CO CEMS must be two times the applicable CO emission
limit, expressed as a concentration.
(7) Each CO CEMS must complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period. Collect at least four CO CEMS data values representing the four
15-minute periods in an hour, or at least two 15-minute data values
during an hour when CEMS calibration, quality assurance, or maintenance
activities are being performed.
(8) The CO CEMS data must be reduced as specified in Sec.
63.8(g)(2).
(9) You must calculate one-hour arithmetic averages, corrected to 3
percent oxygen from each hour of CO CEMS data in parts per million
carbon monoxide concentration. For all subcategories except for units
designed to burn liquid fuels in non-continental states and
territories, the one-hour arithmetic averages required shall be used to
calculate the boiler operating day daily arithmetic average emissions.
Calculate a 10-day rolling average from the daily averages. For units
designed to burn liquid fuels in non-continental states and
territories, the one-hour arithmetic averages required shall be used to
calculate the 3-hour arithmetic average emissions. Use Equation 19-19
in section 12.4.1 of Method 19 of 40 CFR part 60, appendix A-7 for
calculating the average carbon monoxide concentration from the hourly
values.
(10) For purposes of collecting CO data, you must operate the CO
CEMS as specified in Sec. 63.7535(b). You must use all the data
collected during all periods in calculating data averages and assessing
compliance, except that you must exclude certain data as specified in
Sec. 63.7535(c). Periods when CO data are unavailable may constitute
monitoring deviations as specified in Sec. 63.7535(d).
(b) If your boiler or process heater has an average annual heat
input rate greater than 250 MMBtu per hour from solid fossil fuel and/
or residual oil, and you demonstrate compliance with the PM limit
instead of the alternative total selected metals limit, you must
install, certify, maintain, and operate a PM CPMS monitoring emissions
discharged to the atmosphere and record the output of the system as
specified in paragraphs (b)(1) through (4) of this section. For other
boilers or process heaters, you may elect to use a PM CPMS operated in
accordance with this section in lieu of using other CMS for monitoring
PM compliance (e.g., bag leak detectors, ESP secondary power, PM
scrubber pressure).
(1) Install, certify, operate, and maintain your PM CPMS according
to the procedures in your approved site-specific monitoring plan
developed in accordance with Sec. 63.7505(d), the requirements in
Sec. 63.7540(a)(9), and (b)(1)(i) through (iii) of this section.
(i) The operating principle of the PM CPMS must be based on in-
stack or extractive light scatter, light scintillation, beta
attenuation, or mass accumulation detection of PM in the exhaust gas or
representative exhaust gas sample. The reportable measurement output
from the PM CPMS may be expressed as milliamps, stack concentration, or
other raw data signal.
(ii) The PM CPMS must have a cycle time (i.e., period required to
complete sampling, measurement, and reporting for each measurement) no
longer than 60 minutes.
(iii) The PM CPMS must be capable of detecting and responding to
particulate matter concentrations of no greater than 0.5 milligram per
actual cubic meter.
(2) For a new unit, complete the initial performance evaluation no
later than [DATE 240 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
Federal Register] or 180 days after the date of initial startup,
whichever is later. For an existing unit, complete the initial
performance evaluation no later than [DATE 3 YEARS AND 180 DAYS AFTER
PUBLICATION OF THE FINAL RULE IN THE Federal Register].
(3) Collect PM CPMS hourly average output data for all boiler
operating hours except as indicated in Sec. 63.7535(a) through (d).
Express the PM CPMS output as millamps, PM concentration, or other raw
data signal value.
(4) Calculate the arithmetic 30-day rolling average of all of the
hourly average PM CPMS output data collected during all boiler
operating hours (e.g., milliamps, PM concentration, raw data signal).
(c) If you have an applicable opacity operating limit in this rule,
and are not otherwise required or elect to install and operate a PM
CPMS 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
other than a PM CPMS or COMS, you must install, operate, and maintain
each CMS according to the procedures in
[[Page 80638]]
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) You must operate the monitoring system as specified in Sec.
63.7535(b), and comply with the data calculation requirements specified
in Sec. 63.7535(c).
(3) 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. Other
situations that constitute a monitoring deviation are specified in
Sec. 63.7535(d).
(4) You must determine the 30-day rolling 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.
(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) and (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 CPMS 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 (6) 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.
(6) 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.
(l) For each unit for which you decide to demonstrate compliance
with the mercury or hydrogen chloride emissions limits in Tables 1 or 2
of this subpart by use of a CEMS for mercury or hydrogen chloride, you
must install, certify, maintain, and operate a CEMS measuring emissions
discharged to the atmosphere and record the output of the system as
specified in paragraphs (l)(1) through (8) of this section. For
hydrogen chloride, this option for an affected unit takes effect on the
date a final
[[Page 80639]]
performance specification for a hydrogen chloride CEMS is published in
the Federal Register or the date of approval of a site-specific
monitoring plan.
(1) Notify the Administrator one month before starting use of the
CEMS, and notify the Administrator one month before stopping use of the
CEMS.
(2) Each CEMS shall be installed, certified, operated, and
maintained according to the requirements in Sec. 63.7540(a)(14) for a
mercury CEMS and Sec. 63.7540(a)(15) for a hydrogen chloride CEMS.
(3) For a new unit, you must complete the initial performance
evaluation of the CEMS by the latest of the dates specified in
paragraph (l)(3)(i) through (iii) of this section.
(i) No later than [DATE 240 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE Federal Register].
(ii) No later 180 days after the date of initial startup.
(iii) No later 180 days after notifying the Administrator before
starting to use the CEMS in place of performance testing or fuel
analysis to demonstrate compliance.
(4) For an existing unit, you must complete the initial performance
evaluation by the latter of the two dates specified in paragraph
(l)(4)(i) and (ii) of this section.
(i) No later than [DATE 3 YEARS AND 180 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE Federal Register].
(ii) No later 180 days after notifying the Administrator before
starting to use the CEMS in place of performance testing or fuel
analysis to demonstrate compliance.
(5) Compliance with the applicable emissions limit shall be
determined based on the 30-day rolling average of the hourly arithmetic
average emissions rates using the continuous monitoring system outlet
data. The 30-day rolling arithmetic average emission rate (lb/MMBtu)
shall be calculated using the equations in EPA Reference Method 19 at
40 CFR part 60, appendix A-7, but substituting the mercury or hydrogen
chloride concentration for the pollutant concentrations normally used
in Method 19.
(6) 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.
(7) The one-hour arithmetic averages required shall be expressed in
lb/MMBtu and shall be used to calculate the boiler operating day daily
arithmetic average emissions.
(8) If you are using an add-on control to comply with the mercury
or hydrogen chloride emission limit, you are allowed to substitute the
use of the mercury or hydrogen chloride CEMS for the applicable fuel
analysis, annual performance test, and operating limits specified in
Table 4 to this subpart to demonstrate compliance with the mercury or
hydrogen chloride emissions limit.
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,
operate, and 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)(4) 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) through (3) of this section, as applicable, and as
specified in Sec. 63.7510(a)(2). (Note that Sec. 63.7510(a)(2)
exempts certain fuels from the fuel analysis requirements.) However, if
you switch fuel(s) and cannot show that the new fuel(s) does (do) not
increase the chlorine, mercury, or total selected metals 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.
(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] TP23DE11.037
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] TP23DE11.038
[[Page 80640]]
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) If you opt to comply with the alternative total selected metals
limit, you must establish the maximum total selected metals fuel input
(TSMinput) for solid fuels during the initial fuel analysis according
to the procedures in paragraphs (b)(3)(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
total selected metals.
(ii) During the fuel analysis for total selected metals, 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
total selected metals, and the average total selected metals
concentration of each fuel type burned (TSMi).
(iii) You must establish a maximum total selected metals input
level using Equation 9 of this section.
[GRAPHIC] [TIFF OMITTED] TP23DE11.039
Where:
TSMinput = Maximum amount of total selected metals entering the
boiler or process heater through fuels burned in units of pounds per
million Btu.
TSMi = Arithmetic average concentration of total selected metals 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 total selected metals.
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 total
selected metals.
(4) You must establish parameter operating limits according to
paragraphs (b)(4)(i) through (vii) of this section. As indicated in
Table 4 to this subpart, you are not required to establish and comply
with the operating parameter limits when you are using a CEMS to
monitor and demonstrate compliance with the applicable emission limit
for that control device parameter.
(i) For a wet acid gas scrubber, you must establish the minimum
scrubber effluent pH and liquid flow rate as defined in Sec. 63.7575,
as your operating limits during the three-run performance test during
which you demonstrate compliance with your applicable limit. If you use
a wet scrubber and you conduct separate performance tests for hydrogen
chloride and mercury emissions, you must establish one set of minimum
scrubber effluent pH, liquid flow rate, 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
flow rate operating limit at the higher of the minimum values
established during the performance tests.
(ii) For any particulate control device (e.g., ESP, particulate wet
scrubber, fabric filter) for which you use a PM CPMS, you must
establish your operating limit during the three-run performance during
which you demonstrate compliance with your applicable limit. The PM
CPMS operating limit is the 1-hour average PM CPMS output value
recorded during the performance test. If you conduct separate
performance tests for PM and total selected metals, you must set the
maximum PM CPMS operating limits at the lower of maximum PM CPMS values
established during the performance tests.
(iii) For a particulate wet scrubber, you must establish the
minimum pressure drop and liquid flow rate as defined in Sec. 63.7575,
as your operating limits during the three-run performance test during
which you demonstrate compliance with your applicable limit. If you use
a wet scrubber and you conduct separate performance tests for
particulate matter and total selected metals emissions, you must
establish one set of minimum scrubber liquid flow rate 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
flow rate and pressure drop operating limits at the higher of the
minimum values established during the performance tests.
(iv) 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 during which you
demonstrate compliance with your applicable limit. (These operating
limits do not apply to electrostatic precipitators that are operated as
dry controls without a wet scrubber.)
(v) 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 during which you
demonstrate compliance with your applicable limit.
(vi) 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 during which you
demonstrate compliance with your applicable limit.
(vii) 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 (5) 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
[[Page 80641]]
pollutant concentration of the composite samples analyzed for each fuel
type using the one-sided z-statistic test described in Equation 10 of
this section.
[GRAPHIC] [TIFF OMITTED] TP23DE11.040
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 11 of this
section must not exceed the applicable emission limit for hydrogen
chloride.
[GRAPHIC] [TIFF OMITTED] TP23DE11.041
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 10 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 12 of this section must not
exceed the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TP23DE11.042
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 10 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.
(5) To demonstrate compliance with the applicable emission limit
for total selected metals for solid fuels, the total selected metals
emission rate that you calculate for your boiler or process heater from
solid fuels using Equation 13 of this section must not exceed the
applicable emission limit for total selected metals.
[GRAPHIC] [TIFF OMITTED] TP23DE11.043
Where:
Metals = Total selected metals emission rate from the boiler or
process heater in units of pounds per million Btu.
TSMi90 = 90th percentile confidence level concentration of total
selected metals in fuel, i, in units of pounds per million Btu as
calculated according to Equation 10 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest total selected metals 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 total selected metals
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 constituents in the gaseous
fuels will never exceed the specification 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 specification outlined in the definition of other gas 1 fuels. If
your gas constituents could vary above the specification, you will
conduct monthly testing according to the procedures in Sec. 63.7521(f)
through (i) and Sec. 63.7540(c)
[[Page 80642]]
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 to emission limits in
Tables 1 or 2 to this subpart, you must meet the work practice standard
according to Table 3 of this subpart. You must submit a signed
statement in the Notification of Compliance Status report that
indicates that you employed good combustion practices and you
maintained oxygen concentrations as specified by the boiler
manufacturer for each startup and shutdown event.
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 Table 2 to 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. You may use this
compliance approach for an existing affected boiler for demonstrating
initial compliance according to Sec. 63.7522(e) and for demonstrating
monthly compliance according to Sec. 63.7522(f). 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. You cannot use this compliance approach for a new
or reconstructed affected boiler.
(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. If possible, use actual data that
are current and timely rather than estimated data.
(c) Emissions credits can be generated if the energy conservation
measures were implemented after January 1, 2008 and if sufficient
information is 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
1, 2008, unless the level of energy demand reduction is increased after
January 1, 2008, in which case credit will be allowed only for change
in demand reduction achieved after January 1, 2008.
(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 14 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 1, 2008. Credits shall be calculated using Equation 14 of this
section as follows:
(i) The overall equation for calculating credits is:
[GRAPHIC] [TIFF OMITTED] TP23DE11.044
Where:
ECredits = Energy Input Savings for all energy conservation measures
implemented for an affected boiler, expressed as a decimal fraction
of the baseline energy input.
EISiactual = Energy Input Savings for each energy
conservation measure, i, implemented for an affected boiler, million
Btu per year.
EIbaseline = Energy Input baseline for the affected
boiler, million Btu per year.
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 as calculated using Equation 15 of this
section 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 use Equation 15 of this section to demonstrate initial
compliance by demonstrating 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.
[[Page 80643]]
[GRAPHIC] [TIFF OMITTED] TP23DE11.045
Where:
Eadj = Emission level adjusted by 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.
ECredits = Emission credits from Equation 14 for the affected
boiler.
Continuous Compliance Requirements
Sec. 63.7535 Is there a minimum amount of monitoring data I must
obtain?
(a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by 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
and compliance is required, 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, required zero
and span adjustments, and scheduled CMS maintenance as defined in your
site-specific monitoring plan. A monitoring system malfunction is any
sudden, infrequent, not reasonably preventable failure of the
monitoring system to provide valid data. Monitoring system failures
that are caused in part by poor maintenance or careless operation are
not malfunctions. You are required to complete monitoring system
repairs in response to monitoring system malfunctions or out-of-control
periods and to return the monitoring system to operation as
expeditiously as practicable.
(c) You may not use data 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 record and make available upon request results of CMS
performance audits and dates and duration of periods when the CMS is
out of control to completion of the corrective actions necessary to
return the CMS to operation consistent with your site-specific
monitoring plan. You must use all the data collected during all other
periods in assessing compliance and the operation of the control device
and associated control system.
(d) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, system accuracy audits, 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 in Tables 1 and 2 to this subpart, the work practice standards in
Table 3 to this subpart, and the operating limits in Table 4 to this
subpart that applies to you according to the methods specified in Table
8 to this subpart and paragraphs (a)(1) through (17) 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 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 result in either of the following:
(i) Lower emissions of hydrogen chloride, mercury, and total
selected metals than the applicable emission limit for each pollutant,
if you demonstrate compliance through fuel analysis.
(ii) Lower fuel input of chlorine, mercury, and total selected
metals 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 for a solid or liquid
fuel and you plan to burn a new type of solid or liquid fuel, you must
recalculate the hydrogen chloride emission rate using Equation 11 of
Sec. 63.7530 according to paragraphs (a)(3)(i) through (iii) of this
section. You are not required to complete fuel analyses for the fuels
described in Sec. 63.7510(a)(2)(i) through (iii). You may exclude the
fuels described in Sec. 63.7510(a)(2)(i) through (iii) when
recalculating the hydrogen chloride emission rate.
(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 11
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).
In recalculating the maximum chlorine input and establishing the new
operating limits, you are not required to complete fuel analyses for
and include the fuels described in Sec. 63.7510(a)(2)(i) through
(iii).
(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
12 of Sec. 63.7530 according to the procedures specified in paragraphs
(a)(5)(i) through (iii) of this
[[Page 80644]]
section. You are not required to complete fuel analyses for the fuels
described in Sec. 63.7510(a)(2)(i) through (iii). You may exclude the
fuels described in Sec. 63.7510(a)(2)(i) through (iii) when
recalculating the mercury emission rate.
(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 12 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). You are not required
to complete fuel analyses for the fuels described in Sec.
63.7510(a)(2)(i) through (iii). You may exclude the fuels described in
Sec. 63.7510(a)(2)(i) through (iii) when recalculating the mercury
emission rate.
(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) If you install a CO CEMS according to Sec. 63.7525(a), then
you must meet the requirements in paragraphs (a)(8)(i) through (iii) of
this section.
(i) Continuously monitor CO according to Sec. Sec. 63.7525(a) and
63.7535.
(ii) Maintain a CO emission level below or at your applicable
alternative CO CEMS-based standard in Tables 1 or 2 to this subpart at
all times.
(iii) Keep records of CO levels according to Sec. 63.7555(b).
(9) The owner or operator of an affected source using a PM CPMS to
meet requirements of this subpart shall install, certify, operate, and
maintain the PM CPMS in accordance with your site-specific monitoring
plan as required in Sec. 63.7505(d).
(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 (vi) of this section. This requirement does not apply to
limited-use boilers and process heaters, as defined in Sec. 63.7575.
(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 or unscheduled unit shutdown);
(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 used by each unit.
(11) If your boiler or process heater has a heat input capacity of
less than 10 million Btu per hour (except as specified in paragraph
(a)(12) of this section), 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 your boiler or process heater has a heat input capacity of
less than 5 million Btu per hour, and the unit is in the units designed
to burn natural gas, refinery gas or other gas 1 fuels, units designed
to burn gas 2 (other), or units designed to burn light liquid
subcategories, you must conduct a tune-up of the boiler or process
heater every 5 years as specified in paragraphs (a)(10)(i) through (vi)
of this section to demonstrate continuous compliance. You may delay the
burner inspection specified in paragraph (a)(10)(i) of this section
until the next scheduled or unscheduled unit shutdown, but you must
inspect each burner at least once every 72 months.
(13) 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.
(14) If you are using a CEMS measuring mercury emissions to meet
requirements of this subpart you must install, certify, operate, and
maintain the mercury CEMS as specified in paragraphs (a)(14)(i) and
(ii) of this section.
(i) Operate the mercury CEMS in accordance with performance
[[Page 80645]]
specification 12A of 40 CFR part 60, appendix B or operate a sorbent
trap based integrated monitor in accordance with performance
specification 12B of 40 CFR part 60, appendix B. The duration of the
performance test must be a calendar month. For each calendar month in
which the unit operates, you must obtain hourly mercury concentration
data, and stack gas volumetric flow rate data.
(ii) If you are using a mercury CEMS, you must install, operate,
calibrate, and maintain an instrument for continuously measuring and
recording the mercury mass emissions rate to the atmosphere according
to the requirements of performance specifications 6 and 12A of 40 CFR
part 60, appendix B, and quality assurance procedure 6 of 40 CFR part
60, appendix F.
(15) If you are using a CEMS to measure hydrogen chloride emissions
to meet requirements of this subpart, you must install, certify,
operate, and maintain the hydrogen chloride CEMS as specified in
paragraphs (a)(15)(i) and (ii) of this section. This option for an
affected unit takes effect on the date a final performance
specification for a hydrogen chloride CEMS is published in the Federal
Register or the date of approval of a site-specific monitoring plan.
(i) Operate the continuous emissions monitoring system in
accordance with the applicable performance specification in 40 CFR part
60, appendix B. The duration of the performance test must be a calendar
month. For each calendar month in which the unit operates, you must
obtain hourly hydrogen chloride concentration data, and stack gas
volumetric flow rate data.
(ii) If you are using a hydrogen chloride continuous emissions
monitoring system, you must install, operate, calibrate, and maintain
an instrument for continuously measuring and recording the hydrogen
chloride mass emissions rate to the atmosphere according to the
requirements of the applicable performance specification of 40 CFR part
60, appendix B, and the quality assurance procedures of 40 CFR part 60,
appendix F.
(16) If you demonstrate compliance with an applicable total
selected metals 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 total selected metals input using Equation 9 of
Sec. 63.7530. If the results of recalculating the maximum total
selected metals input using Equation 9 of Sec. 63.7530 are higher than
the maximum total selected 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 total selected
metals 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). You are not required to complete
fuel analyses for the fuels described in Sec. 63.7510(a)(2)(i) through
(iii). You may exclude the fuels described in Sec. 63.7510(a)(2)(i)
through (iii) when recalculating the total selected metals emission
rate.
(17) If you demonstrate compliance with an applicable total
selected metals emission limit through fuel analysis for solid fuels,
and you plan to burn a new type of fuel, you must recalculate the total
selected metals emission rate using Equation 13 of Sec. 63.7530
according to the procedures specified in paragraphs (a)(5)(i) through
(iii) of this section. You are not required to complete fuel analyses
for the fuels described in Sec. 63.7510(a)(2)(i) through (iii). You
may exclude the fuels described in Sec. 63.7510(a)(2)(i) through (iii)
when recalculating the total selected metals emission rate.
(i) You must determine the total selected metals 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 total selected metals.
(iii) Recalculate the total selected metals emission rate from your
boiler or process heater under these new conditions using Equation 13
of Sec. 63.7530. The recalculated total selected metals emission rate
must be less than the applicable emission limit.
(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 or operating limits, respectively, 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
specification for 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 specification, you must conduct monthly
fuel specification testing of the gaseous fuels, according to the
procedures in Sec. 63.7521(f) through (i).
(d) For periods of startup and shutdown, you must meet the work
practice standards according to Table 3 of this subpart.
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 30-day
rolling 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
30-day rolling 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.
[[Page 80646]]
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 [DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL
RULE IN THE Federal Register], you must submit an Initial Notification
not later than 120 days after [DATE 60 DAYS AFTER THE DATE OF
PUBLICATION OF THE FINAL RULE IN THE Federal Register].
(c) As specified in Sec. 63.9(b)(4) and (b)(5), if you startup
your new or reconstructed affected source on or after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], 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.
(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 or 2 to this subpart, if you
are not using a CO CEMS to demonstrate compliance.
(4) Identification of whether you plan to demonstrate compliance
with each applicable emission limit through performance testing, a
CEMS, 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 [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE Federal Register].
(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), (11), or (12) to conduct an annual, biennial, or 5-year
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, gaseous fuel
subject to another subpart of this part, 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,
biennial, or 5-year
[[Page 80647]]
tune-up according to Sec. 63.7540(a)(10), (11), or (12), respectively,
and not subject to emission limits or operating limits, you may submit
only an annual, biennial, or 5-year 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, 2, or 5 years, as
applicable, if submitting an annual, biennial, or 5-year 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,
biennial, or 5-year 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, biennial, and
5-year compliance reports must cover the applicable 1-, 2-, or 5-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, biennial, and 5-year 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 semiannual (or
annual, biennial, or 5-year) 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 11 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
12 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). If you
burned a new type of fuel and are subject to a total selected metals
emission limit, you must submit the calculation of total selected
metals input, using Equation 9 of Sec. 63.7530, that demonstrates that
your source is still within its maximum total selected metals input
level established during the previous performance testing (for sources
that demonstrate compliance through performance testing), or you must
submit the calculation of total selected metals emission rate, using
Equation 13 of Sec. 63.7530, that demonstrates that your source is
still meeting the emission limit for total selected metals 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, or the maximum total selected metals input operating
limit using Equation 9 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
[[Page 80648]]
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, biennial, or 5-
year tune-up according to Sec. 63.7540(a)(10), (11), or (12)
respectively. Include the date of the most recent burner inspection if
it was not done annually, biennially, or on a 5-year period and was
delayed until the next scheduled or unscheduled 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 than the level or control technology contained in
the notification of compliance status in Sec. 63.7545(e)(5)(i).
(14) For units subject to emission limits in Tables 1 or 2 of this
subpart, for each startup or shutdown event during the reporting
period, report the percentage concentration of oxygen in the firebox on
an hourly basis throughout the event, the calendar date and length of
each event, and the reason for each event.
(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.
(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) Within 60 days after the date of completing each performance
test, you must transmit the results of the performance tests required
by this subpart to EPA's WebFIRE database by using the Compliance and
Emissions Data Reporting Interface (CEDRI) that is accessed through
EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx). Performance
test data must be submitted in the file format generated through use of
EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test methods on the
ERT Web site are subject to this requirement for submitting reports
electronically to WebFIRE. Owners or operators who claim that some of
the information being submitted for performance tests is confidential
business information (CBI) must submit a complete ERT file including
information claimed to be CBI on a compact disk or other commonly used
electronic storage media (including, but not limited to, flash drives)
to the EPA. The electronic media must be clearly marked as CBI and
mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE
Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The
same ERT file with the CBI omitted must be submitted to EPA via CDX as
described earlier in this paragraph. At the discretion of the delegated
authority, you must also submit these reports, including the
confidential business information, to the delegated authority in the
format specified by the delegated authority.
(i) Within 60 days after the date of completing each CEMS (CO and
Hg) performance evaluation test, as defined in Sec. 63.2 and required
by this subpart, you must submit the relative accuracy test audit data
electronically into EPA's Central Data Exchange by using the Electronic
Reporting Tool as described in paragraph (h) of this section. Only data
collected using test methods compatible with ERT are subject to this
requirement to be submitted electronically to EPA's CDX.
(j) Within 60 days after the reporting periods ending on March 31,
June 30, September 30, and December 31, you must transmit quarterly
reports to EPA's WebFIRE database by using the Compliance and Emissions
Data Reporting Interface (CEDRI) that is accessed through EPA's Central
Data Exchange (CDX) (www.epa.gov/cdx). For each reporting period, the
quarterly reports must include all of the
[[Page 80649]]
calculated 30 day rolling average values based on the daily CEMS (CO
and Hg) and CPMS (PM CPMS output, scrubber pH, scrubber liquid flow
rate, scrubber pressure drop) data.
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 or 2 to this subpart, you must also keep the applicable
records in paragraphs (d)(1) through (9) 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. 241.3(b)(1) and (2),
you must keep a record that 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 satisfy 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. Units exempt from the incinerator standards under section
129(g)(1) of the Clean Air Act because they are qualifying facilities
burning a homogeneous waste stream do not need to maintain the records
described in this paragraph (d)(2).
(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 11 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 12 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 (or, in specific
instances noted in Tables 1 and 2 to this subpart, less than 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 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.
(9) A copy of all calculations and supporting documentation of
maximum total selected metals fuel input, using Equation 9 of Sec.
63.7530, that were done to demonstrate continuous compliance with the
total selected metals 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 total selected metals emission rates, using
Equation 13 of Sec. 63.7530, that were done to demonstrate compliance
with the total selected metals emission limit. Supporting documentation
should include results of any fuel analyses and basis for the estimates
of maximum total selected metals fuel input or total selected metals
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 total selected metals fuel
input, or total selected metals emission rates, for each boiler and
process heater.
(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
[[Page 80650]]
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
specification for 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 specification, you must maintain monthly
records of the calculations and results of the fuel specification for
mercury 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, gaseous fuel
subject to another subpart under this part, or other gas 1 fuel, you
must keep records of the total hours per calendar year that alternative
fuel is burned.
(i) For each startup or shutdown event, you must maintain records
that boiler operators have completed training for startup and shutdown
procedures.
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:
30-day rolling average means the arithmetic mean of all valid data
from 30 successive operating days that is calculated for each operating
day using the data from that operating day and the previous 29
operating days.
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.
Average annual heat input rate means annual heat input divided by
the hours of operation 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.
Biodiesel means a mono-akyl ester derived from biomass and
conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels (incorporated by
reference, see Sec. 63.14).
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 that use only
natural gas, refinery gas, or other gas 1 fuels for supplemental fuel
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
[[Page 80651]]
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-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.
Daily block average means the arithmetic mean of all valid emission
concentrations or parameter levels recorded when a unit is operating
measured over the 24-hour period from 12 a.m. (midnight) to 12 a.m.
(midnight).
Deviation. (1) Means any instance in which an affected source
subject to this subpart, or an owner or operator of such a source:
(i) Fails to meet any 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. Fluidized bed boilers are not part of the dutch oven design
category.
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. To be ``capable
of combusting'' fossil fuels, an EGU would need to have these fuels
allowed in their operating permits and have the appropriate fuel
handling facilities on-site or otherwise available (e.g., coal handling
equipment, including coal storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired EGU means any EGU that fired fossil fuel for more than 10.0
percent of the average annual heat input in any 3 consecutive calendar
years or for more than 15.0 percent of the annual heat input during any
one calendar year after [COMPLIANCE DATE OF THE FINAL EGU RULE].
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 8 technical labor hours in length maximum, but may be longer at
the discretion of the owner or operator of the affected source. The
boiler system 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 an 8-hour 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 24
technical labor hours in length maximum, but may be longer at the
discretion of the owner or operator. 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 24-hour 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 water systems; building envelop; and lighting.
Equivalent means the following only as this term is used in Table 6
to this subpart:
[[Page 80652]]
(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 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)
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 that is not a pulverized coal boiler.
Fluidized bed combustion means a process where a fuel is burned in
a bed of granulated particles, which are maintained in a mobile
suspension by the forward flow of air and combustion products.
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.
Fluidized bed, dutch oven, pile burner, hybrid suspension grate, and
suspension burners are not part of the fuel cell subcategory.
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.
Heavy Liquid includes residual oil and any other liquid fuel not
classified as a light liquid.
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 boilers (i.e., not generating steam) combusting
gaseous or liquid fuel with a heat input capacity of less than 1.6
million Btu per hour are included in this definition. 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 fuel combusted in these units
exceed a moisture content of 40 percent on an as-fired basis. 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. Fluidized bed, dutch oven, and pile burner designs are not
part of the hybrid suspension grate boiler design category.
Industrial boiler means a boiler used in manufacturing, processing,
mining, and refining or any other industry to provide steam and/or hot
water.
Light liquid includes distillate oil, biodiesel or vegetable oil.
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 includes, but is not limited to, distillate oil,
residual oil, on-spec used oil, biodiesel and vegetable oil.
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.
[[Page 80653]]
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 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 combustor means a unit designed to burn solid fuel that is
not classified as a dutch oven, fluidized bed, fuel cell, hybrid
suspension grate boiler, pulverized coal boiler, stoker, sloped grate,
or suspension boiler as defined in this subpart.
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.
Oxygen analyzer system means all equipment required to determine
the oxygen content of a gas stream and used to monitor oxygen in the
boiler flue gas or firebox. This definition includes oxygen trim
systems. The source owner or operator must install, calibrate,
maintain, and operate the oxygen analyzer system in accordance with the
manufacturer's recommendations.
Oxygen trim system means a system of monitors that is used to
maintain excess air at the desired level in a combustion device. A
typical system consists of a flue gas oxygen and/or carbon monoxide
monitor that automatically provides a feedback signal to the combustion
air controller.
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 gas curtailment or supply interruption means a period of
time during which the supply of gaseous fuel 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 due to normal
market fluctuations not during periods of supplier delivery restriction
does not constitute a period of natural gas curtailment or supply
interruption. On-site gaseous fuel system emergencies or equipment
failures qualify as periods of supply interruption when the emergency
or failure is beyond the control of the facility.
Pile burner means a boiler design incorporating a design where the
anticipated biomass fuel has a high relative moisture content. Grates
serve to support the fuel, and underfire air flowing up through the
grates provides oxygen for combustion, cools the grates, promotes
turbulence in the fuel bed, and fires the fuel. The most common form of
pile burning is the dutch oven.
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 include
units heating hot water as a process heat transfer medium. 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. Waste heat process heaters that
use only natural gas, refinery gas, or other gas 1 fuels for
supplemental fuel are excluded from this definition.
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 energy
savings opportunities for steam generation and major energy using
systems, including, but not limited to:
(i) Boiler combustion management.
(ii) Boiler thermal energy recovery, including
(A) Conventional 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
[[Page 80654]]
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.
Residential boiler means a boiler used in a dwelling containing
four or fewer family units to provide heat and/or hot water. This
definition includes boilers used primarily to provide heat and/or hot
water for a dwelling containing four or fewer families located at an
institutional facility (e.g., university campus, military base, church
grounds) or commercial/industrial facility (e.g., farm).
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.
Shutdown means the period that begins when a unit last operates at
25 percent load and ending with a state of no fuel combustion in the
unit.
Sloped grate means a unit where the solid fuel is fed to the top of
the grate from where it slides downwards; while sliding the fuel first
dries and then ignites and burns. The ash is deposited at the bottom of
the grate. Fluidized bed, dutch oven, pile burner, hybrid suspension
grate, suspension burners, and fuel cells are not considered to be a
sloped grate design.
Solid fossil fuel includes, but is not limited to, coal, coke,
petroleum coke, and tire derived fuel.
Solid fuel means any solid fossil fuel or biomass or bio-based
solid fuel.
Startup means the period between the state of no combustion in the
unit to the period where the unit first achieves 25 percent load (i.e.,
a cold start).
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;
(2) For a boiler that cogenerates process steam and electricity
(also known as combined heat and power), 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) and
(3) For a boiler that generates only electricity, the alternate
output-based emission limits would be calculated using Equations 16
through 20 of this section, as appropriate:
(i) For emission limits for boilers in the solid fuel subcategory
use Equation 16 of this section:
[GRAPHIC] [TIFF OMITTED] TP23DE11.046
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(ii) For PM and CO emission limits for boilers in one of the
subcategories of units designed to burn coal use Equation 17 of this
section:
[GRAPHIC] [TIFF OMITTED] TP23DE11.047
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(iii) For PM and CO emission limits for boilers in one of the
subcategories of units designed to burn biomass use Equation 18 of this
section:
[GRAPHIC] [TIFF OMITTED] TP23DE11.048
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(iv) For emission limits for boilers in the one of the
subcategories of units designed to burn liquid fuels use Equation 19 of
this section:
[GRAPHIC] [TIFF OMITTED] TP23DE11.049
Where:
ELOBE = Emission limit in units of pounds per megawatt-hour.
ELT = Appropriate emission limit from Table 1 or 2 of this subpart
in units of pounds per million Btu heat input.
(v) For emission limits for boilers in the Gas 2 subcategory use
Equation 20 of this section:
[GRAPHIC] [TIFF OMITTED] TP23DE11.050
[[Page 80655]]
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
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. Fluidized bed, dutch oven, pile burner, hybrid
suspension grate, suspension burners, and fuel cells are not considered
to be a stoker design.
Stoker/sloped grate/other unit designed to burn kiln dried biomass
means the unit is in the units designed to burn biomass/bio-based solid
subcategory that is either a stoker, sloped grate, or other combustor
design and is not in the stoker/sloped grate/other units designed to
burn wet biomass subcategory.
Stoker/sloped grate/other unit designed to burn wet biomass means
the unit is in the units designed to burn biomass/bio-based solid
subcategory that is either a stoker, sloped grate, or other combustor
design and any of the biomass/bio-based solid fuel combusted in the
unit exceeds 20 percent moisture.
Suspension burner 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. Fluidized
bed, dutch oven, pile burner, and hybrid suspension grate units are not
part of the suspension burner subcategory.
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 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.
Total selected metals means the combination of the following
metallic hazardous air pollutants: arsenic, beryllium, cadmium,
chromium, lead, manganese, nickel and selenium.
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 heavy liquid subcategory means a unit in the
unit designed to burn liquid subcategory where at least 10 percent of
the heat input from liquid fuels on an annual heat input basis comes
from heavy liquids.
Unit designed to burn light liquid subcategory means a unit in the
unit designed to burn liquid subcategory that is not part of the unit
designed to burn heavy liquid subcategory.
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 only solid fuels or at least 10 percent solid
fuel on an annual heat input basis in combination with liquid fuels or
gaseous fuels.
Vegetable oil means oils extracted from vegetation.
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
[[Page 80656]]
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. This definition includes
both fired and unfired waste heat boilers.
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.
This definition includes both fired and unfired waste heat 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:
Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters
[Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
The emissions must
not exceed the Or the emissions
If your boiler or process heater following emission must not exceed Using this
is in this subcategory . . . For the following limits, except the following specified sampling
pollutants . . . during periods of alternative output- volume or test run
startup and based limits . . . duration . . .
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. Hydrogen 0.022 lb per MMBtu 0.025 lb per MMBtu For M26A, collect
designed to burn solid fuel. Chloride. of heat input. of steam output a minimum of 1
or 0.28 lb per dscm per run; for
MWh. M26 collect a
minimum of 120
liters per run
b. Mercury........ 8.60E-07 lb per 9.4E-07 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 1.1 E- per run; for M30A
05 lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 4 dscm.
2. Pulverized coal boilers a. Carbon monoxide 9 ppm by volume on 0.0074 lb per 1 hr minimum
designed to burn coal/solid (CO) (or CEMS). a dry basis MMBtu of steam sampling time,
fossil fuel. corrected to 3 output or 0.092 use a span value
percent oxygen, 3- lb per MWh; 3-run of 20 ppmv for
run average; or average. Method 10.
(28 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.0013 lb per 0.0013 lb per Collect a minimum
Particulate MMBtu of heat MMBtu of steam of 3 dscm per
Matter (or Total input; or (2.8E- output or 0.016 run.
Selected Metals). 05 \a\ lb per lb per MWh; or
MMBtu of heat (2.8E-05 \a\ lb
input). per MMBtu of
steam output or
3.5E-04 \a\ lb
per MWh).
3. Stokers designed to burn coal/ a. CO (or CEMS)... 19 ppm by volume 0.017 lb per MMBtu 1 hr minimum
solid fossil fuel. on a dry basis of steam output sampling time,
corrected to 3 or 0.20 lb per use a span value
percent oxygen, 3- MWh; 3-run of 30 ppmv for
run average; or average. Method 10.
(34 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
[[Page 80657]]
b. Filterable 0.028 lb per MMBtu 0.028 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 2 dscm per
Matter (or Total (2.2E-05 \a\ lb or 0.35 lb per run.
Selected Metals). per MMBtu of heat MWh; or (3.0E-05
input). \a\ lb per MMBtu
of steam output
or 2.7E-04 \a\ lb
per MWh).
4. Fluidized bed units designed a. CO (or CEMS)... 17 ppm by volume 0.015 lb per MMBtu 1 hr minimum
to burn coal/solid fossil fuel. on a dry basis of steam output sampling time,
corrected to 3 or 0.18 lb per use a span value
percent oxygen, 3- MWh; 3-run of 40 ppmv for
run average; or average. Method 10.
(59 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.0011 lb per 0.0012 lb per Collect a minimum
Particulate MMBtu of heat MMBtu of steam of 4 dscm per
Matter (or Total input; or (1.7E- output or 0.014 run.
Selected Metals). 05 \a\ lb per lb per MWh; or
MMBtu of heat (1.8E-05 \a\ lb
input). per MMBtu of
steam output or
2.1E-04 \a\ lb
per MWh).
5. Stokers/sloped grate/others a. CO (or CEMS)... 590 ppm by volume 0.56 lb per MMBtu 1 hr minimum
designed to burn wet biomass on a dry basis of steam output sampling time,
fuel. corrected to 3 or 6.5 lb per use a span value
percent oxygen, 3- MWh; 3-run of 600 ppmv for
run average; or average. Method 10.
(410 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.029 lb per MMBtu 0.034 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 2 dscm per
Matter (or Total (2.6E-05 lb per or 0.41 lb per run.
Selected Metals). MMBtu of heat MWh; or (2.7E-05
input). lb per MMBtu of
steam output or
3.7E-04 lb per
MWh).
6. Stokers/sloped grate/others a. CO............. 250 ppm by volume 0.23 lb per MMBtu 1 hr minimum
designed to burn kiln-dried on a dry basis of steam output sampling time,
biomass fuel. corrected to 3 or 2.8 lb per MWh. use a span value
percent oxygen. of 400 ppmv for
Method 10.
b. Filterable 0.32 lb per MMBtu 0.37 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 2 dscm per
Matter (or Total (4.0E-03 lb per or 4.5 lb per run.
Selected Metals). MMBtu of heat MWh; or (4.2E-03
input). lb per MMBtu of
steam output or
0.056 lb per MWh).
7. Fluidized bed units designed a. CO (or CEMS)... 230 ppm by volume 0.22 lb per MMBtu 1 hr minimum
to burn biomass/bio-based on a dry basis of steam output sampling time,
solids. corrected to 3 or 2.6 lb per use a span value
percent oxygen, 3- MWh; 3-run of 400 ppmv for
run average; or average. Method 10.
(180 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.0098 lb per 0.012 lb per MMBtu Collect a minimum
Particulate MMBtu of heat of steam output of 3 dscm per
Matter (or Total input; or (4.2E- or 0.14 lb per run.
Selected Metals). 05 \a\ lb per MWh; or (5.4E-05
MMBtu of heat \a\ lb per MMBtu
input). of steam output
or 5.9E-04 \a\ lb
per MWh).
[[Page 80658]]
8. Suspension burners designed a. CO (or CEMS)... 58 ppm by volume 0.046 lb per MMBtu 1 hr minimum
to burn biomass/bio-based on a dry basis of steam output sampling time,
solids. corrected to 3 or 0.64 lb per use a span value
percent oxygen, 3- MWh; 3-run of 100 ppmv for
run average; or average. Method 10.
(1,400 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.051 lb per MMBtu 0.052 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (1.1E-03 lb per or 0.71 lb per run.
Selected Metals). MMBtu of heat MWh; or (0.0012
input). lb per MMBtu of
steam output or
0.016 lb per MWh).
9. Dutch Ovens/Pile burners a. CO (or CEMS)... 810 ppm by volume 0.89 lb per MMBtu 1 hr minimum
designed to burn biomass/bio- on a dry basis of steam output sampling time,
based solids. corrected to 3 or 8.9 lb per use a span value
percent oxygen, 3- MWh; 3-run of 1000 ppmv for
run average; or average. Method 10.
(440 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.036 lb per MMBtu 0.050 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (4.1E-05 lb per or 0.51 lb per run.
Selected Metals). MMBtu of heat MWh; or (5.5E-05
input). lb per MMBtu of
steam output or
5.8E-04 lb per
MWh).
10. Fuel cell units designed to a. CO............. 210 ppm by volume 0.29 lb per MMBtu 1 hr minimum
burn biomass/bio-based solids. on a dry basis of steam output sampling time,
corrected to 3 or 2.3 lb per MWh. use a span value
percent oxygen. of 500 ppmv for
Method 10.
b. Filterable 0.011 lb per MMBtu 0.030 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (4.9E-05 \a\ lb or 0.16 lb per run.
Selected Metals). per MMBtu of heat MWh; or (8.6E-05
input). \a\ lb per MMBtu
of steam output
or 6.9E-04 \a\ lb
per MWh).
11. Hybrid suspension grate a. CO (or CEMS)... 1,500 ppm by 1.80 lb per MMBtu 1 hr minimum
boiler designed to burn biomass/ volume on a dry of steam output sampling time,
bio-based solids. basis corrected or 17 lb per MWh; use a span value
to 3 percent 3-run average. of 3000 ppmv for
oxygen, 3-run Method 10.
average; or (730
ppm by volume on
a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.026 lb per MMBtu 0.033 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 3 dscm per
Matter (or Total (4.9E-04 \a\ lb or 0.37 lb per run.
Selected Metals). per MMBtu of heat MWh; or (6.2E-04
input). \a\ lb per MMBtu
of steam output
or 6.9E-03 \a\ lb
per MWh).
12. Units designed to burn a. Hydrogen 0.0012 lb per 0.0013 lb per For M26A: Collect
liquid fuel. Chloride. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.017 dscm per run; for
lb per MWh. M26, collect a
minimum of 120
liters per run.
b. Mercury........ 4.9E-07 \a\ lb per 5.4E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 6.8E-06 per run; for M30A
\a\ lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 4 dscm.
[[Page 80659]]
13. Units designed to burn heavy a. CO (or CEMS)... 10 ppm by volume 0.0091 lb per 1 hr minimum
liquid fuel. on a dry basis MMBtu of steam sampling time,
corrected to 3 output or 0.11 lb use a span value
percent oxygen, 3- per MWh; 3-run of 30 ppmv for
run average; or average. Method 10.
(18 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.013 lb per MMBtu 0.015 lb per MMBtu Collect a minimum
Particulate of heat input. of steam output of 2 dscm per
Matter. or 0.18 lb per run.
MWh.
14. Units designed to burn light a. CO (or CEMS)... 3 ppm by volume on 0.0031 lb per 1 hr minimum
liquid fuel. a dry basis MMBtu of steam sampling time,
corrected to 3 output or 0.033 use a span value
percent oxygen; lb per MWh. of 10 ppmv for
or (60 ppm by Method 10.
volume on a dry
basis corrected
to 3 percent
oxygen, 1-day
block average).
b. Filterable 0.0011 \a\ lb per 0.0015 \a\ lb per Collect a minimum
Particulate MMBtu of heat MMBtu of steam of 3 dscm per
Matter. input for light output or 0.016 run.
liquid. lb per MWh.
15. Units designed to burn a. CO............. 18 ppm by volume 0.017 lb per MMBtu 1 hr minimum
liquid fuel located in non- on a dry basis of steam output sampling time,
continental states and corrected to 3 or 0.20 lb per use a span value
territories. percent oxygen, 3- MWh; 3-run of 40 ppmv for
run average based average. Method 10.
on stack test (91
ppm by volume on
a dry basis
corrected to 3
percent oxygen, 3-
hour rolling
average based on
CEM).
b. Filterable 0.0080 lb per 0.0087 lb per Collect a minimum
Particulate MMBtu of heat MMBtu of steam of 4 dscm per
Matter. input. output or 0.11 lb run.
per MWh.
16. Units designed to burn gas 2 a. CO............. 4 ppm by volume on 0.005 lb per MMBtu 1 hr minimum
(other) gases. a dry basis of steam output sampling time,
corrected to 3 or 0.031 lb per use a span value
percent oxygen. MWh. of 10 ppmv for
Method 10.
b. Hydrogen 0.0017 lb per 0.0029 lb per For M26A, Collect
Chloride. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.018 dscm per run; for
lb per MWh. M26, collect a
minimum of 120
liters per run.
c. Mercury........ 7.9E-06 lb per 1.4E-05 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 8.3E-05 per run; for M30A
lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 3 dscm.
d. Filterable 0.0067 lb per 0.012 lb per MMBtu Collect a minimum
Particulate MMBtu of heat of steam output of 1 dscm per
Matter (or Total input; or (2.4E- or 0.070 lb per run.
Selected Metals). 04 lb per MMBtu MWh; or (4.0E-04
of heat input). lb per MMBtu of
steam output or
0.0025 lb per
MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provision of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec. 63.14.
[[Page 80660]]
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
not exceed the The emissions must
If your boiler or process heater following emission not exceed the Using this
is in this subcategory . . . For the following limits, except following specified sampling
pollutants . . . during periods of alternative output- volume or test run
startup and based limits . . . duration . . .
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. Hydrogen 0.022 lb per MMBtu 0.025 lb per MMBtu For M26A, Collect
designed to burn solid fuel. Chloride. of heat input. of steam output a minimum of 1
or 0.28 lb per dscm per run; for
MWh. M26, collect a
minimum of 120
liters per run.
b. Mercury........ 3.1E-06 lb per 3.5E-06 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 4.0E-05 per run; for M30A
lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 3 dscm.
2. Pulverized coal boilers a. CO (or CEMS)... 41 ppm by volume 0.035 lb per MMBtu 1 hr minimum
designed to burn coal/solid on a dry basis of steam output sampling time,
fossil fuel. corrected to 3 or 0.42 lb per use a span value
percent oxygen, 3- MWh; 3-run of 100 ppmv for
run average; or average. Method 10.
(28 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.044 lb per MMBtu 0.045 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (5.9E-05 lb per or 0.54 lb per run.
Selected Metals). MMBtu of heat MWh; or (6.0E-05
input). lb per MMBtu of
steam output or
7.3E-04 lb per
MWh).
3. Stokers designed to burn coal/ a. CO (or CEMS)... 220 ppm by volume 0.20 lb per MMBtu 1 hr minimum
solid fossil fuel. on a dry basis of steam output sampling time,
corrected to 3 or 2.3 lb per use a span value
percent oxygen, 3- MWh; 3-run of 400 ppmv for
run average; or average. Method 10.
(34 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.028 lb per MMBtu 0.030 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 2 dscm per
Matter (or Total (8.3E-05 lb per or 0.35 lb per run.
Selected Metals). MMBtu of heat MWh; or (8.8E-05
input). lb per MMBtu of
steam output or
0.0011 lb per
MWh).
4. Fluidized bed units designed a. CO (or CEMS)... 56 ppm by volume 0.049 lb per MMBtu 1 hr minimum
to burn coal/solid fossil fuel. on a dry basis of steam output sampling time,
corrected to 3 or 0.57 lb per use a span value
percent oxygen, 3- MWh; 3-run of 100 ppmv for
run average; or average. Method 10.
(59 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.088 lb per MMBtu 0.092 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (1.7E-05 lb per or 1.1 lb per run.
Selected Metals). MMBtu of heat MWh; or (1.8E-05
input). lb per MMBtu of
steam output or
2.1E-04 lb per
MWh).
[[Page 80661]]
5. Stokers/sloped grate/others a. CO (or CEMS)... 790 ppm by volume 0.72 lb per MMBtu 1 hr minimum
designed to burn wet biomass on a dry basis of steam output sampling time,
fuel. corrected to 3 or 8.7 lb per use a span value
percent oxygen, 3- MWh; 3-run of 1000 ppmv for
run average; or average. Method 10.
(410 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.029 lb per MMBtu 0.034 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 2 dscm per
Matter (or Total (5.7E-05 lb per or 0.41 lb per run.
Selected Metals). MMBtu of heat MWh; or (6.6E-05
input). lb per MMBtu of
steam output or
8.0E-04 lb per
MWh).
6. Stokers/sloped grate/others a. CO............. 250 ppm by volume 0.23 lb per MMBtu 1 hr minimum
designed to burn kiln-dried on a dry basis of steam output sampling time,
biomass fuel. corrected to 3 or 2.8 lb per MWh. use a span value
percent oxygen. of 500 ppmv for
Method 10.
b. Filterable 0.32 lb per MMBtu 0.37 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (4.0E-03 lb per or 4.5 lb per run.
Selected Metals). MMBtu of heat MWh; or (0.0046
input). lb per MMBtu of
steam output or
0.056 lb per MWh).
7. Fluidized bed units designed a. CO (or CEMS)... 370 ppm by volume 0.36 lb per MMBtu 1 hr minimum
to burn biomass/bio-based solid. on a dry basis of steam output sampling time,
corrected to 3 or 4.1 lb per use a span value
percent oxygen, 3- MWh; 3-run of 500 ppmv for
run average; or average. Method 10.
(180 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.11 lb per MMBtu 0.14 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (0.0012 lb per or 1.6 lb per run.
Selected Metals). MMBtu of heat MWh; or (0.0015
input). lb per MMBtu of
steam output or
0.017 lb per MWh).
8. Suspension burners designed a. CO (or CEMS)... 58 ppm by volume 0.046 lb per MMBtu 1 hr minimum
to burn biomass/bio-based solid. on a dry basis of steam output sampling time,
corrected to 3 or 0.64 lb per use a span value
percent oxygen, 3- MWh; 3-run of 100ppmv for
run average; or average. Method 10.
(1,400 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable 0.051 lb per MMBtu 0.052 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (0.0011 lb per or 0.71 lb per run.
Selected Metals). MMBtu of heat MWh; or (0.0012
input). lb per MMBtu of
steam output or
0.016 lb per MWh).
9. Dutch Ovens/Pile burners a. CO (or CEMS)... 810 ppm by volume 0.89 lb per MMBtu 1 hr minimum
designed to burn biomass/bio- on a dry basis of steam output sampling time,
based solid. corrected to 3 or 8.9 lb per use a span value
percent oxygen, 3- MWh; 3-run of 1000 ppmv for
run average; or average. Method 10.
(440 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
[[Page 80662]]
b. Filterable 0.036 lb per MMBtu 0.050 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (2.4E-04 lb per or 0.51 lb per run.
Selected Metals). MMBtu of heat MWh; or (3.4E-04
input). lb per MMBtu of
steam output or
0.0034 lb per
MWh).
10. Fuel cell units designed to a. CO............. 1,500 ppm by 3.2 lb per MMBtu 1 hr minimum
burn biomass/bio-based solid. volume on a dry of steam output sampling time,
basis corrected or 17 lb per MWh. use a span value
to 3 percent of 2000 ppmv for
oxygen. Method 10.
b. Filterable 0.033 lb per MMBtu 0.090 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (4.9E-05 lb per or 0.46 lb per run.
Selected Metals). MMBtu of heat MWh; or (1.4E-04
input). lb per MMBtu of
steam output or
6.9E-04 lb per
MWh).
11. Hybrid suspension grate a. CO (or CEMS)... 3,900 ppm by 3.9 lb per MMBtu 1 hr minimum
units designed to burn biomass/ volume on a dry of steam output sampling time,
bio-based solid. basis corrected or 43 lb per MWh; use a span value
to 3 percent 3-run average. of 5000 ppmv for
oxygen, 3-run Method 10.
average; or (730
ppm by volume on
a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.44 lb per MMBtu 0.55 lb per MMBtu Collect a minimum
Particulate of heat input; or of steam output of 1 dscm per
Matter (or Total (4.9E-04\a\ lb or 6.2 lb per run.
Selected Metals). per MMBtu of heat MWh; or (6.2E-
input). 04\a\ lb per
MMBtu of steam
output or 6.9E-
03\a\ lb per MWh).
12. Units designed to burn a. Hydrogen 0.0012 lb per 0.0015 lb per For M26A, collect
liquid fuel. Chloride. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.017 dscm per run; for
lb per MWh. M26, collect a
minimum of 120
liters per run.
b. Mercury........ 2.6E-05 lb per 3.3E-05 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 2 dscm
input. output or 3.6E-04 per run; for M30A
lb per MWh. or M30B collect a
minimum sample as
specified in the
method, for ASTM
D6784\b\ collect
a minimum of 2
dscm.
13. Units designed to burn heavy a. CO (or CEMS)... 10 ppm by volume 0.0091 lb per 1 hr minimum
liquid fuel. on a dry basis MMBtu of steam sampling time,
corrected to 3 output or 0.11 lb use a span value
percent oxygen, 3- per MWh; 3-run of 20 ppmv for
run average; or average. Method 10.
(18 ppm by volume
on a dry basis
corrected to 3
percent oxygen,
10-day rolling
average).
b. Filterable 0.062 lb per MMBtu 0.075 lb per MMBtu Collect a minimum
Particulate of heat input. of steam output of 1 dscm per
Matter. or 0.86 lb per run.
MWh.
14. Units designed to burn light a. CO (or CEMS)... 7 ppm by volume on 0.0071 lb per 1 hr minimum
liquid fuel. a dry basis MMBtu of steam sampling time,
corrected to 3 output or 0.076 use a span value
percent oxygen; lb per MWh. of 10 ppmv for
or (60 ppm by Method 10.
volume on a dry
basis corrected
to 3 percent
oxygen, 1-day
block average).
b. Filterable 0.0034 lb per 0.0045 lb per Collect a minimum
Particulate MMBtu of heat MMBtu of steam of 3 dscm per
Matter. input. output or 0.047 run.
lb per MWh.
[[Page 80663]]
15. Units designed to burn a. CO (or CEMS)... 18 ppm by volume 0.017 lb per MMBtu 1 hr minimum
liquid fuel located in non- on a dry basis of steam output sampling time,
continental states and corrected to 3 or 0.20 lb per use a span value
territories. percent oxygen, 3- MWh; 3-run of 40 ppmv for
run average based average. Method 10.
on stack test (91
ppm by volume on
a dry basis
corrected to 3
percent oxygen, 3-
hour rolling
average based on
CEM).
b. Filterable 0.0080 lb per 0.0097 lb per Collect a minimum
Particulate MMBtu of heat MMBtu of steam of 2 dscm per
Matter. input. output or 0.11 lb run.
per MWh.
16. Units designed to burn gas 2 a. CO............. 4 ppm by volume on 0.0050 lb per 1 hr minimum
(other) gases. a dry basis MMBtu of steam sampling time,
corrected to 3 output or 0.031 use a span value
percent oxygen. lb per MWh. of 10 ppmv for
Method 10.
b. Hydrogen 0.0017 lb per 0.0029 lb per For M26A, collect
Chloride. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.018 dscm per run; for
lb per MWh. M26, collect a
minimum of 120
liters per run.
c. Mercury........ 7.9E-06 lb per 1.4E-05 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 2 dscm
input. output or 8.3E-05 per run; for M30A
lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 2 dscm.
d. Filterable 0.0067 lb per 0.012 lb per MMBtu Collect a minimum
Particulate MMBtu of heat of steam output of 1 dscm per
Matter (or Total input or (2.4E-04 or 0.070 lb per run.
Selected Metals). lb per MMBtu of MWh; or (4.0E-04
heat input). lb per MMBtu of
steam output or
0.0025 lb per
MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provisions of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years
must show that your emissions are at or 75 percent of this limit in order to qualify for skip testing.
\b\ 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 every 5
less than 5 million Btu per hour in years as specified in Sec.
any of the following subcategories: 63.7540.
unit designed to burn natural gas,
refinery gas or other gas 1 fuels;
unit designed to burn gas 2 (other);
or unit designed to burn light liquid.
2. A limited use boiler or process Conduct a tune-up of the boiler
heater; or a new or existing boiler or or process heater biennially
process heater with heat input as specified in Sec.
capacity of less than 10 million Btu 63.7540.
per hour in the unit designed to burn
heavy liquid or unit designed to burn
solid fuel subcategories; or a new or
existing boiler or process heater with
heat input capacity of less than 10
million Btu per hour, but equal to or
greater than 5 million Btu per hour,
in any of the following subcategories:
unit designed to burn natural gas,
refinery gas or other gas 1 fuels;
unit designed to burn gas 2 (other);
or unit designed to burn light liquid.
[[Page 80664]]
3. A new or existing boiler or process Conduct a tune-up of the boiler
heater with heat input capacity of 10 or process heater annually as
million Btu per hour or greater. specified in Sec. 63.7540.
Units in either the Gas 1 or
Metal Process Furnace
subcategories will conduct
this tune-up as a work
practice for all regulated
emissions under this subpart.
Units in all other
subcategories will conduct
this tune-up as a work
practice for dioxins/furans.
4. 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
systems consuming energy from
affected boilers and process
heaters and which are under
the control of the boiler/
process heater owner/operator.
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.
h. A comprehensive report
detailing the ways to improve
efficiency, the cost of
specific improvements,
benefits, and the time frame
for recouping those
investments.
5. An existing or new unit subject to You must employ good combustion
emission limits in Tables 1 or 2 to practices and demonstrate that
this subpart. good combustion practices are
maintained by monitoring O2
concentrations and optimizing
those concentrations as
specified by the boiler
manufacturer; you must ensure
that boiler operators are
trained in startup and
shutdown procedures, including
maintenance and cleaning,
safety, control device
startup, and procedures to
minimize emissions; and you
must maintain records during
periods of startup and
shutdown and include in your
compliance reports the O2
conditions/data for each
event, length of startup/
shutdown and reason for the
startup/shutdown (i.e., normal/
routine, problem/malfunction,
outage).
------------------------------------------------------------------------
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 You must meet these operating limits . .
using . . . .
------------------------------------------------------------------------
1. Wet PM scrubber control on Maintain the 30-day rolling average
a boiler not using a PM CPMS. pressure drop and the 30-day rolling
average liquid flow rate at or above the
lowest one-hour average pressure drop
and the lowest one-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) Maintain the 30-day rolling average
scrubber control on a boiler effluent pH at or above the lowest one-
not using a hydrogen hour average pH and the 30-day rolling
chloride CEMS. average liquid flow rate at or above the
lowest one-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 a. Maintain opacity to less than or equal
units not using a PM CPMS. to 10 percent 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 a. This option is for boilers and process
control on units not using a heaters that operate dry control systems
PM CPMS. (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 CPMS
or continuous compliance with an opacity
limit (i.e., COMS). Maintain the 30-day
rolling average 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.
[[Page 80665]]
5. Dry scrubber or carbon Maintain the minimum sorbent or carbon
injection control on a injection rate as defined in Sec.
boiler not using a mercury 63.7575 of this subpart.
CEMS.
6. Any other add-on air This option is for boilers and process
pollution control type on heaters that operate dry control
units not using a PM CPMS. 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 it does not
exceed 110 percent of the average
operating load recorded during the most
recent performance test.
9. Oxygen Analyzer System.... For boilers and process heaters subject
to a carbon monoxide emission limit that
demonstrate compliance with an O2
analyzer system as specified in Sec.
63.7525(a), maintain the oxygen level
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 CFR
sampling ports part 60, appendix A-
location and the 1 of this chapter.
number of
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-1 or A-2
rate of the to part 60 of this
stack gas. chapter.
c. Determine Method 3A or 3B at 40
oxygen or carbon CFR part 60,
dioxide appendix A-2 to part
concentration of 60 of this chapter,
the stack gas. or ANSI/ASME PTC
19.10-1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix A-
of the stack gas. 3 of this chapter.
e. Measure the Method 5 or 17
particulate (positive pressure
matter emission fabric filters must
concentration. use Method 5D) at 40
CFR part 60,
appendix A-3 or A-6
of this chapter.
f. Convert Method 19 F-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of this
emission rates. chapter.
2. Hydrogen chloride.......... a. Select Method 1 at 40 CFR
sampling ports part 60, appendix A-
location and the 1 of this chapter.
number of
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-2 of this
rate of the chapter.
stack gas.
c. Determine Method 3A or 3B at 40
oxygen or carbon CFR part 60,
dioxide appendix A-2 of this
concentration of chapter, or ANSI/
the stack gas. ASME PTC 19.10-
1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix A-
of the stack gas. 3 of this chapter.
e. Measure the Method 26 or 26A (M26
hydrogen or M26A) at 40 CFR
chloride part 60, appendix A-
emission 8 of this chapter.
concentration.
f. Convert Method 19 F-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of this
emission rates. chapter.
3. Mercury.................... a. Select Method 1 at 40 CFR
sampling ports part 60, appendix A-
location and the 1 of this chapter.
number of
traverse points.
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-1 or A-2
rate of the of this chapter.
stack gas.
c. Determine Method 3A or 3B at 40
oxygen or carbon CFR part 60,
dioxide appendix A-1 of this
concentration of chapter, or ANSI/
the stack gas. ASME PTC 19.10-
1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix A-
of the stack gas. 3 of this chapter.
e. Measure the Method 29, 30A, or
mercury emission 30B (M29, M30A, or
concentration. 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-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of this
emission rates. chapter.
4. CO......................... a. Select the Method 1 at 40 CFR
sampling ports part 60, appendix A-
location and the 1 of this chapter.
number of
traverse points.
b. Determine Method 3A or 3B at 40
oxygen CFR part 60,
concentration of appendix A-3 of this
the stack gas. chapter, or ASTM
D6522-00 (Reapproved
2005), or ANSI/ASME
PTC 19.10-1981.\a\
c. Measure the Method 4 at 40 CFR
moisture content part 60, appendix A-
of the stack gas. 3 of this chapter.
[[Page 80666]]
d. Measure the CO Method 10 at 40 CFR
emission part 60, appendix A-
concentration. 4 of this chapter.
Use a span value of
2 times the
concentration of the
applicable emission
limit.
------------------------------------------------------------------------
\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 EPA
1631 or EPA 1631E
or ASTM D6323 \a\
(for solid), or EPA
821-R-01-013 (for
liquid or solid),
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
ASTME829 or EPA
3050 (for solid
fuel), or EPA 821-R-
01-013 (for liquid
or solid), or
equivalent.
d. Determine heat ASTM D5865 \a\ (for
content of the fuel coal) or ASTM E711
type. \a\ (for biomass),
or ASTM D5864 for
liquids and other
solids, or ASTM
D240 or equivalent.
e. Determine ASTM D3173 \a\, ASTM
moisture content of E871 \a\, or ASTM
the fuel type. D5864, or ASTM D240
or 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 Equation 8 in Sec.
concentration into 63.7530.
units of pounds of
mercury per MMBtu
of heat content.
h. Calculate the Equations 10 and 12
mercury emission in Sec. 63.7530.
rate from the
boiler or process
heater in units of
pounds per million
Btu.
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 coal
or 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 ASTM
E829 (for solid
fuel), or EPA 3050
or equivalent.
d. Determine heat ASTM D5865 \a\ (for
content of the fuel coal) or ASTM E711
type. \a\ (for biomass),
ASTM D5864, ASTM
D240 or equivalent.
e. Determine ASTM D3173 \a\ or
moisture content of ASTM E871 \a\, or
the fuel type. D5864, or ASTM D240
or equivalent.
f. Measure chlorine EPA SW-846-9250 \a\,
concentration in ASTM D6721 \a\,
fuel sample. ASTM D4208 (for
coal), or EPA SW-
846-5050 \a\ or
ASTM E776 \a\ (for
solid fuel), or EPA
SW-846-9056 or SW-
846-9076 (for
solids or liquids)
or equivalent.
g. Convert Equation 7 in Sec.
concentrations into 63.7530.
units of pounds of
hydrogen chloride
per MMBtu of heat
content.
h. Calculate the Equations 10 and 11
hydrogen chloride in Sec. 63.7530.
emission rate from
the boiler or
process heater in
units of pounds per
million Btu.
3. Mercury Fuel a. Measure mercury ASTM D5954 \a\, ASTM
Specification for other gas concentration in D6350 \a\, ISO 6978-
1 fuels. the fuel sample and 1:2003(E) \a\, or
convert to units of ISO 6978-2:2003(E)
micrograms per \a\, or equivalent.
cubic meter.
4. Total Selected Metals for a. Collect fuel Procedure in Sec.
solid fuels. samples. 63.7521(c) or ASTM
D2234/D2234M \a\
(for coal) or ASTM
D6323 \a\ (for coal
or biomass), or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
[[Page 80667]]
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\ or
TAPPI T266 (for
biomass), or ASTM
E829 (for solid
fuel), or EPA 3050
or equivalent.
d. Determine heat ASTM D5865 \a\ (for
content of the fuel coal) or ASTM E711
type. \a\ (for biomass),
or ASTM D5864 for
liquids and other
solids, or ASTM
D240 or equivalent.
e. Determine ASTM D3173 \a\ or
moisture content of ASTM E871 \a\, or
the fuel type. D5864, or ASTM D240
or equivalent.
f. Measure total ASTM D3683, or ASTM
selected metals D4606, or ASTM
concentration in D6357 or EPA 200.8
fuel sample. or or EPA SW-846-
6020, or EPA SW-846-
6020A, or ASTM
E885, or EPA SW-846-
6010B, EPA 7060 or
EPA 7060A (for
arsenic only), or
EPA SW-846-7740
(for selenium
only),
g. Convert Equations 9 in Sec.
concentrations into 63.7530.
units of pounds of
total selected
metals per MMBtu of
heat content.
h. Calculate the Equations 10 and 13
total selected in Sec. 63.7530.
metals emission
rate from the
boiler or process
heater in units of
pounds per million
Btu.
------------------------------------------------------------------------
\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, total a. Wet scrubber i. Establish a (1) Data from the (a) You must
selected metals, or mercury. operating site-specific scrubber pressure collect scrubber
parameters. minimum scrubber drop and liquid pressure drop and
pressure drop and flow rate liquid flow rate
minimum flow rate monitors and the data every 15
operating limit particulate minutes during
according to Sec. matter or mercury the entire period
63.7530(b). performance test. of the
performance
tests.
(b) Determine the
lowest hourly
average scrubber
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.
[[Page 80668]]
(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.
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
hydrogen chloride
performance test,
the average value
for each sorbent
becomes the site-
specific
operating limit
for that sorbent.
(b) Determine the
hourly average
sorbent injection
rate by computing
the hourly
averages using
all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
lowest hourly
average of the
three test run
averages
established
during the
performance test
as your operating
limit. When your
unit operates at
lower loads,
multiply your
sorbent injection
rate by the load
fraction (e.g.,
for 50 percent
load, multiply
the injection
rate operating
limit by 0.5) to
determine the
required
injection rate.
3. Mercury...................... 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 rate data every
rate operating performance test. 15 minutes during
limit according 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.
[[Page 80669]]
(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 analyzer collect oxygen
limit for minimum system specified data every 15
oxygen level in Sec. minutes during
according to Sec. 63.7525(a). the entire period
63.7520. of the
performance
tests.
(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. PM CPMS................... a. Collecting the PM CPMS output data
according to Sec. 63.7525;
[[Page 80670]]
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
PM CPMS output data to less than the
operating limit established during the
performance test according to Sec.
63.7530.
3. 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.
4. 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 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
pressure drop and liquid flow-rate at or
above the operating limits established
during the performance test according to
Sec. 63.7530(b).
5. 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 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
pH at or above the operating limit
established during the performance test
according to Sec. 63.7530(b).
6. 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 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
sorbent or carbon injection rate at or
above the minimum sorbent or carbon
injection rate as defined in Sec.
63.7575.
7. 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 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
total secondary electric power input at
or above the operating limits
established during the performance test
according to Sec. 63.7530(b).
8. 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).
9. Oxygen content............ a. Continuously monitor the oxygen
content using an oxygen trim system
according to Sec. 63.7525(a).
b. Reducing the data to 30-day rolling
averages; and
c. Maintain the 30-day rolling average
oxygen content at or above the lowest
hourly average oxygen level measured
during the most recent carbon monoxide
performance test.
10. Carbon monoxide emissions a. Continuously monitor the carbon
monoxide concentration in the combustion
exhaust according to Sec. 63.7525(a).
b. Correcting the data to 3 percent
oxygen, and reducing the data to one-
hour and daily block averages for all
subcategories except units designed to
burn liquid fuels located in non-
continental states and territories;
c. Reducing the data from the daily
averages to 10-day rolling averages for
all subcategories except units designed
to burn liquid fuels located in non-
continental states and territories;
d. Reducing the data from the one-hour
averages to three-hour averages for
units designed to burn liquid fuels
located in non-continental states and
territories;
e. Maintaining the 10-day rolling average
carbon monoxide concentration at or
below the applicable emission limit in
Tables 1 or 2 of this subpart for all
subcategories except units designed to
burn liquid fuels located in non-
continental states and territories; and
f. Maintaining the 3-hour rolling average
carbon monoxide concentration at or
below the applicable emission limit in
Tables 1 or 2 of this subpart for units
designed to burn liquid fuels located in
non-continental states and territories.
11. Boiler or process heater a. Collecting operating load data or
operating load. steam generation data every 15 minutes.
b. Maintaining the operating load such
that it does not exceed 110 percent of
the average operating load recorded
during the most recent 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
------------------------------------------------------------------------
The report must You must submit
You must submit a(n) contain . . . the report . . .
------------------------------------------------------------------------
1. Compliance report.......... a. Information Semiannually,
required in Sec. annually,
63.7550(c)(1) through biennially, or
(12); and. every 5 years
according to
the
requirements in
Sec.
63.7550(b).
[[Page 80671]]
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 subpart
Citation Subject 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 Yes.
Activities and
Circumvention.
Sec. 63.5..................... Preconstruction Yes.
Review 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 63.7500(a)(3) for
emissions.. the general duty
requirement.
Sec. 63.6(e)(1)(ii)........... Requirement to No.
correct
malfunctions as
soon as
practicable.
Sec. 63.6(e)(3)............... Startup, shutdown, No.
and malfunction
plan requirements.
Sec. 63.6(f)(1)............... Startup, shutdown, No.
and malfunction
exemptions for
compliance with
non-opacity
emission
standards.
Sec. 63.6(f)(2) and (3)....... Compliance with Yes.
non-opacity
emission
standards.
Sec. 63.6(g).................. Use of alternative Yes.
standards.
Sec. 63.6(h)(1)............... Startup, shutdown, No. See Sec.
and malfunction 63.7500(a).
exemptions to
opacity standards.
Sec. 63.6(h)(2) to (h)(9)..... Determining Yes.
compliance with
opacity emission
standards.
Sec. 63.6(i).................. Extension of Yes. Facilities
compliance. may request
extensions of
compliance for
the installation
of combined heat
and power or
waste heat
recovery as a
means of
complying with
this subpart.
Sec. 63.6(j).................. Presidential Yes.
exemption.
Sec. 63.7(a), (b), (c), and Performance Yes.
(d). Testing
Requirements.
Sec. 63.7(e)(1)............... Conditions for No. Subpart DDDDD
conducting specifies
performance conditions for
tests.. conducting
performance tests
at Sec.
63.7520(a) to
(c).
Sec. 63.7(e)(2)-(e)(9), (f), Performance Yes.
(g), and (h). Testing
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 63.7500(a)(3).
emissions and CMS
operation.
Sec. 63.8(c)(1)(ii)........... Operation and Yes.
maintenance of
CMS.
Sec. 63.8(c)(1)(iii).......... Startup, shutdown, No.
and malfunction
plans for CMS.
Sec. 63.8(c)(2) to (c)(9)..... Operation and Yes.
maintenance of
CMS.
[[Page 80672]]
Sec. 63.8(d)(1) and (2)....... Monitoring Yes.
Requirements,
Quality Control
Program.
Sec. 63.8(d)(3)............... Written procedures Yes, except for
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 Yes.
evaluation of a
CMS.
Sec. 63.8(f).................. Use of an Yes.
alternative
monitoring method.
Sec. 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 Yes.
records.
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 Yes.
CMS malfunctions.
Sec. 63.10(b)(2)(vii) to (xiv) Other CMS Yes.
requirements.
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 No. See Sec.
and cause of 63.7555(d)(7) for
malfunctions, and recordkeeping of
corrective occurrence and
actions. 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 No.
or visible
emission
observation
results.
Sec. 63.10(d)(4).............. Progress reports Yes.
under an
extension of
compliance.
Sec. 63.10(d)(5).............. Startup, shutdown, No. See Sec.
and malfunction 63.7550(c)(11)
reports. for malfunction
reporting
requirements.
Sec. 63.10(e)................. Additional Yes.
reporting
requirements for
sources with CMS.
Sec. 63.10(f)................. Waiver of Yes.
recordkeeping or
reporting
requirements.
Sec. 63.11.................... Control Device No.
Requirements.
Sec. 63.12.................... State Authority Yes.
and Delegation.
Sec. 63.13-63.16.............. Addresses, Yes.
Incorporation by
Reference,
Availability of
Information,
Performance Track
Provisions.
Sec. 63.1(a)(5),(a)(7)-(a)(9), Reserved.......... No.
(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).
------------------------------------------------------------------------
[FR Doc. 2011-31667 Filed 12-22-11; 8:45 am]
BILLING CODE 6560-50-P