[Federal Register Volume 85, Number 164 (Monday, August 24, 2020)]
[Proposed Rules]
[Pages 52198-52236]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-15121]
[[Page 52197]]
Vol. 85
Monday,
No. 164
August 24, 2020
Part II
Environmental Protection Agency
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40 CFR Part 63
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National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Amendments; Proposed Rule
Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 /
Proposed Rules
[[Page 52198]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-10010-81-OAR]
RIN 2060-AU20
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters; Amendments
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: On January 31, 2013, the U.S. Environmental Protection Agency
(EPA) finalized amendments to the national emission standards (NESHAP)
for the control of hazardous air pollutants (HAP) at major sources from
new and existing industrial, commercial, and institutional (ICI)
boilers and process heaters. Subsequently, the United States Court of
Appeals for the District of Columbia Circuit (D.C. Circuit), in a
decision issued in July 2016, remanded several of the emission
standards to the EPA based on the court's review of the EPA's approach
to setting those standards. In response to these remands, this action
proposes to amend several numeric emission limits for new and existing
boilers and process heaters consistent with the court's opinion and set
compliance dates for these new emission limits. The court also remanded
for further explanation the Agency's use of carbon monoxide (CO) as a
surrogate for organic HAP and, in a subsequent decision in March 2018,
remanded for further explanation the Agency's use of a CO threshold to
represent the application of the maximum achievable control technology
(MACT) for organic HAP. The proposed changes to the emissions limits
will protect air quality and promote public health by reducing
emissions of the HAP listed in the Clean Air Act (CAA). This action
also addresses the two issues remanded to the EPA for further
explanation. We are also proposing several technical clarifications and
corrections.
DATES:
Comments. Comments must be received on or before October 23, 2020.
Under the Paperwork Reduction Act (PRA), comments on the information
collection provisions are best assured of consideration if the Office
of Management and Budget (OMB) receives a copy of your comments on or
before September 23, 2020.
Public hearing. If anyone contacts us requesting a public hearing
on or before August 31, 2020, we will hold a virtual public hearing.
See SUPPLEMENTARY INFORMATION for information on requesting and
registering for a public hearing.
ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by any of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov/
(our preferred method). Follow the online instructions for submitting
comments.
Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2002-0058 in the subject line of the message.
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to https://www.regulations.gov/, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the SUPPLEMENTARY
INFORMATION section of this document. Out of an abundance of caution
for members of the public and our staff, the EPA Docket Center and
Reading Room was closed to public visitors on March 31, 2020, to reduce
the risk of transmitting COVID-19. Our Docket Center staff will
continue to provide remote customer service via email, phone, and
webform. We encourage the public to submit comments via https://www.regulations.gov/ or email, as there is a temporary suspension of
mail delivery to the EPA, and no hand deliveries are currently
accepted. For further information on EPA Docket Center services and the
current status, please visit us online at https://www.epa.gov/dockets.
If requested, the virtual hearing will be held on September 8,
2020. The hearing will convene at 9:00 a.m. Eastern Standard Time (EST)
and will conclude at 3:00 p.m. EST. The EPA will announce further
details on the virtual public hearing website at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters. Refer to the SUPPLEMENTARY
INFORMATION section below for additional information.
FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Mr. Jim Eddinger, 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) 541-5426; and email address:
[email protected].
SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. Please note that the EPA
is deviating from its typical approach because the President has
declared a national emergency. Due to the current Centers for Disease
Control and Prevention (CDC) recommendations, as well as state and
local orders for social distancing to limit the spread of COVID-19, the
EPA cannot hold in-person public meetings at this time.
If a public hearing is requested, the EPA will begin pre-
registering speakers for the hearing upon publication of this document
in the Federal Register. To register to speak at the virtual hearing,
please use the online registration form available at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters or contact Ms. Adrian Gates
at (919) 541-4860 or by email at [email protected] to register to
speak at the virtual public hearing. The last day to pre-register to
speak at the hearing will be September 8, 2020. On September 8, 2020,
the EPA will post a general agenda for the hearing that will list pre-
registered speakers in approximate order at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearing to run either ahead of schedule or behind schedule.
Each commenter will have 5 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony electronically (via email) by emailing it to Jim Eddinger and
Adrian Gates. The EPA also recommends submitting the text of your oral
testimony as written comments to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will
be posted online at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters. While the
[[Page 52199]]
EPA expects the hearing to go forward as set forth above, if requested,
please monitor our website or contact Adrian Gates at 919-541-4862 or
[email protected] to determine if there are any updates. The EPA
does not intend to publish a document in the Federal Register
announcing updates.
If you require the services of a translator or a special
accommodation such as audio description, please pre-register for the
hearing with Adrian Gates and describe your needs by August 31, 2020.
The EPA may not be able to arrange accommodations without advance
notice.
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2002-0058. All documents in the docket are
listed in Regulations.gov. Although listed, some information is not
publicly available, e.g., Confidential Business Information (CBI) or
other information whose disclosure is restricted by statute. Certain
other material, such as copyrighted material, is not placed on the
internet and will be publicly available only in hard copy. Publicly
available docket materials are available electronically in
Regulations.gov.
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 https://www.regulations.gov/, including any personal
information provided, unless the comment includes information claimed
to be CBI or other information whose disclosure is restricted by
statute. Do not submit electronically any information that you consider
to be CBI or other information whose disclosure is restricted by
statue. This type of information should be submitted by mail as
discussed below.
The EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). For additional submission methods, the full EPA
public comment policy, information about CBI or multimedia submissions,
and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
The https://www.regulations.gov/ website allows you to submit your
comment anonymously, 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
https://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, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media 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 not include special characters or any form of encryption and be
free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
The EPA is temporarily suspending its Docket Center and Reading
Room for public visitors to reduce the risk of transmitting COVID-19.
Written comments submitted by mail are temporarily suspended and no
hand deliveries will be accepted. Our Docket Center staff will continue
to provide remote customer service via email, phone, and webform. We
encourage the public to submit comments via https://www.regulations.gov/. For further information and updates on EPA Docket
Center services, please visit us online at https://www.epa.gov/dockets.
The EPA continues to carefully and continuously monitor information
from the CDC, local area health departments, and our Federal partners
so that we can respond rapidly as conditions change regarding COVID-19.
Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov/ or email. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
any digital storage media that you mail to the EPA, mark the outside of
the digital storage media as CBI and then identify electronically
within the digital storage media the specific information that is
claimed as CBI. In addition to one complete version of the comments
that includes information claimed as CBI, you must submit a copy of the
comments that does not contain the information claimed as CBI directly
to the public docket through the procedures outlined in Instructions
above. If you submit any digital storage media that does not contain
CBI, mark the outside of the digital storage media clearly that it does
not contain CBI. Information not marked as CBI will be included in the
public docket and the EPA's electronic public docket without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 Code of Federal Regulations
(CFR) part 2. Send or deliver information identified as CBI only to the
following address: OAQPS Document Control Officer (C404-02), OAQPS,
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, Attention: Docket ID No. EPA-HQ-OAR-2002-0058. Note
that written comments containing CBI and submitted by mail may be
delayed and no hand deliveries will be accepted.
Preamble acronyms and abbreviations. We use multiple acronyms and
terms in this preamble. While this list may not be exhaustive, to ease
the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms here:
CAA Clean Air Act
CEDRI Compliance and Emissions Data Reporting Interface
CBI Confidential Business Information
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CO Carbon Monoxide
EPA Environmental Protection Agency
HAP hazardous air pollutant(s)
HCl hydrogen chloride
Hg mercury
ICI industrial, commercial, and institutional
lb/MMBtu pounds per million British thermal units
MACT maximum achievable control technology
MPCRF Multipollutant Control Research Facility
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PAH polycyclic aromatic hydrocarbons
PM particulate matter
ppb parts per billion
ppm parts per million
RDL representative detection level
tpy tons per year
TSM total selected metals
UPL upper prediction limit
VOC volatile organic compounds
Organization of this document. The information in this preamble is
organized as follows:
I. General Information
A. Executive Summary
B. Does this action apply to me?
C. Where can I get a copy of this document and other related
information?
II. Background
[[Page 52200]]
A. What is the statutory authority for this action?
III. Discussion of the Proposed Amendments
A. Revisions to MACT Floor Emission Limits
B. Beyond-the-Floor Emission Limits
C. Revisions to Output-Based Emission Limits
D. Proposed Response to the Amended Issue: CO as a Surrogate for
Organic HAP
E. Proposed Response to the Amended Issue: CO 130 ppm Threshold
Emission Limits
IV. Results and Proposed Decisions
A. What are the resulting changes to emission limits?
B. What compliance dates are we proposing?
C. What other actions are we proposing?
V. Summary of Cost, Environmental, and Economic Impacts
A. What are the affected sources?
B. What are the air quality impacts?
C. What are the cost impacts?
D. What are the secondary impacts?
E. What are the economic impacts?
F. What are the benefits?
VI. Request for Comments
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA)
K. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action
a. Need for Regulatory Action
The NESHAP for Industrial, Commercial, and Institutional Boilers
and Process Heaters was promulgated on March 21, 2011, and amended on
January 31, 2013, and November 20, 2015. Environmental groups and
industry submitted petitions seeking judicial review of the NESHAP. On
December 23, 2016, the D.C. Circuit amended its July 29, 2016 decision
to remand instead of vacate certain emission standards where it held
that the EPA had improperly excluded certain units in establishing the
emission standards and remanded the use of CO as a surrogate for
organic HAP for further explanation. In March 2018, the court in a
separate case remanded the EPA's decision to set a limit of 130 parts
per million (ppm) CO as a minimum standard for certain subcategories
for further explanation. The courts did not set specific deadlines for
the EPA to issue revised regulations as part of either remand.
In response to these remands, the EPA is proposing to amend several
emission standards consistent with the court's opinion and proposing
responses to the two issues remanded for further explanation.
b. Legal Authority
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(d)(2) of the CAA directs
the EPA 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.\1\
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\1\ See 75 FR 32016 and section 63.7575 ``What definitions apply
to this subpart'' of 40 CFR part 63, subpart DDDDD for definitions
of ICI boilers and process heaters.
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2. Summary of the Major Provisions of the Regulatory Action in Question
The EPA is proposing to revise 34 different emission limits which
it had previously promulgated in 2011 and amended in, 2013. Of these 34
emission limits, 28 of the limits would become more stringent and six
of the limits would become less stringent. EPA is also proposing that
facilities would have up to 3 years after the effective date of the
final rule to demonstrate compliance with these revised emission
limits. A list of each combination of subcategory and pollutant where
the limits have proposed revisions is shown in Table 1.
Table 1--Summary of Subcategories With Proposed Revisions to Emission
Limits
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Pollutant where a limit is
Subcategory proposed to change
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New-Solid................................. HCl.
New-Dry Biomass Stoker.................... TSM.
New-Biomass Fluidized Bed................. CO, PM, TSM.
New-Biomass Suspension Burner............. CO, TSM.
New-Biomass Hybrid Suspension Grate....... CO.
New-Biomass Dutch Oven/Pile Burner........ PM.
New-Biomass Dutch Oven/Pile Burner........ PM.
New-Biomass Dutch Oven/Pile Burner........ CO, PM.
New-Liquid................................ HCl.
New-Heavy Liquid.......................... PM, TSM.
New-Process Gas........................... PM.
Existing-Solid............................ HCl, Hg.
Existing-Coal............................. PM.
Existing-Coal Stoker...................... CO.
Existing-Dry Biomass Stoker............... TSM.
Existing-Wet Biomass Stoker............... CO, PM, TSM.
Existing-Biomass Fluidized Bed............ CO, PM, TSM.
Existing-Biomass Suspension Burners....... PM, TSM.
Existing-Biomass Dutch Oven/Pile Burner... PM.
Existing-Liquid........................... Hg.
Existing-Heavy Liquid..................... PM.
Existing-Non-continental Liquid........... PM.
Existing-Process Gas...................... PM.
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3. Costs and Benefits
We have estimated certain cost and benefits of the proposed rule,
and these are found in Table 2. Present values (PV) of the net co-
benefits, in 2016 dollars and discounted to 2020, are from $655 million
to $1,575 million when using a 7-percent discount rate and from $751
million to $1,871 million when using a 3-percent discount rate. The
equivalent annualized values (EAV) of the net co-benefits are from $78
million to $194 million per year when using a 7-percent discount rate
and from $92 million to $232 million per year when using a 3-percent
discount rate. All of these estimates are in 2016 dollars. The
monetized benefits estimate reflects an annual average of 251 tons of
fine particulate matter (PM2.5) emission reductions per year
and 393 tons of sulfur dioxide (SO2) emission reductions per
year. These benefits are referred to as ancillary co-benefits since
these pollutants are not targeted for control in the proposal. The
unmonetized benefits include: Reduced exposure to HAP, including
mercury (Hg), hydrochloric acid (HCl), non-Hg metals (e.g., antimony,
cadmium), formaldehyde, benzene, and polycyclic
[[Page 52201]]
organic matter; reduced climate effects due to reduced black carbon
emissions; reduced ecosystem effects; and reduced visibility
impairments. We represent the present value of unmonetized benefits
from affected HAP emission reductions as a C, and this is part of the
net benefits estimate. We represent the equivalent annualized value of
unmonetized benefits from affected HAP emission reductions as a D, and
this is part of the net benefits estimate. These estimates also include
climate co-disbenefits resulting from an increase in carbon dioxide
(CO2) emissions, a secondary impact from electricity use by
additional control devices in response to the proposal. This disbenefit
is $0.09 million at a 3-percent discount rate and $0.01 million at a 7-
percent discount rate.
More information on these impacts can be found in section V of this
preamble and in the Regulatory Impact Analysis (RIA) for this proposal.
Table 2--Summary of Present Values and Equivalent Annualized Values for Annual Costs, Monetized Ancillary Co-
Benefits, and Monetized Net Benefits (Including Ancillary Co-Disbenefits) for the Proposed Rule
[Millions of 2016 dollars] 1 2
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3% Discount rate 7% Discount rate
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Present Value....................... Targeted Benefits \3\. C C
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Ancillary Co-Benefits. $730 to $1,650 $630 to $1,100
Cost \4\.............. $130 $100
Net Benefits \5\...... $600 to $1,520 + C $530 to $1,000 + C
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Equivalent Annualized Value......... Targeted Benefits \6\. D D
Ancillary Co-Benefits. $100 to 240 $90 to 180
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Costs................. 18 17
Net Benefits.......... $80 to 220 + D $70 to 160 + D
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\1\ All estimates in this table are rounded to one decimal point, so numbers may not sum due to independent
rounding.
\2\ All estimates reflect the amendments to the ICI Boilers MACT standard included in this proposal from a
baseline that includes the control technologies applied to meet the MACT standard.
\3\ C represents the present value of unquantified benefits from reductions in targeted HAP emissions.
\4\ The annualized present value of costs and benefits are calculated over an 8-year period from 2021 to 2028.
\5\ The total monetized ancillary co-benefits reflect the human health benefits associated with reducing
exposure to PM2.5 through reductions of directly emitted PM2.5 and SO2. Monetized ancillary co-benefits
include many, but not all, health effects associated with PM2.5 exposure. Co-benefits are shown as a range
from Krewski et al. (2009) to Lepeule et al. (2012). We do not report the total monetized ancillary co-
benefits by PM2.5 species. The ancillary climate co-disbenefits from additional CO2 emissions resulting from
control device operations are included in the results given the rounding convention employed in this table as
stated in footnote a. The net benefits calculation consists of the targeted benefits and ancillary co-benefits
minus the social costs.
\6\ D represents the equivalent annualized value of unquantified benefits from reductions in targeted HAP
emissions.
B. Does this action apply to me?
Table 3 of this preamble lists the NESHAP and associated regulated
industrial source categories that are the subject of this proposal.
Table 3 is not intended to be exhaustive, but rather provides a guide
for readers regarding the entities that this proposed action is likely
to affect. The proposed standards, once promulgated, will be directly
applicable to the affected sources. As defined in the Initial List of
Categories of Sources Under Section 112(c)(1) of the Clean Air Act
Amendments of 1990 (see 57 FR 31576, July 16, 1992) and Documentation
for Developing the Initial Source Category List, Final Report (see EPA-
450/3-91-030, July 1992), the Industrial Boiler source category
includes boilers used in manufacturing, processing, mining, and
refining or any other industry to provide steam, hot water, and/or
electricity. The Institutional/Commercial Boilers source category
includes, but is not limited to, boilers used in commercial
establishments, medical centers, research centers, institutions of
higher education, hotels, and laundries to provide electricity, steam,
and/or hot water. Waste heat boilers are excluded from this definition.
The Process Heaters source category includes, but is not limited to,
secondary metals process heaters, petroleum and chemical industry
process heaters, and other process heaters. A process heater is defined
as an enclosed device using controlled flame, and the unit's primary
purpose is to transfer heat indirectly to a process material (liquid,
gas, or solid) or to a heat transfer material (e.g., glycol or a
mixture of glycol and water) for use in a process unit, instead of
generating steam. Process heaters do not include units used for comfort
heat or space heat, food preparation for on-site consumption, or
autoclaves. Waste heat process heaters are excluded from this
definition. A boiler or process heater combusting solid waste 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 CAA.
[[Page 52202]]
Table 3--Source Categories Affected by This Proposed Action
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NAICS code 1 Examples of potentially
Source category NESHAP regulated entities
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Any industry using a boiler or process Industrial, Commercial, 211 Extractors of crude petroleum
heater as defined in the final rule. and Institutional and natural gas.
Boilers and Process
Heaters..
......................... 321 Manufacturers of lumber and
wood products.
......................... 322 Pulp and paper mills.
......................... 325 Chemical manufacturers.
......................... 324 Petroleum refineries, and
manufacturers of coal
products.
......................... 316, 326, 339 Manufacturers of rubber and
miscellaneous plastic
products.
......................... 331 Steel works, blast furnaces.
......................... 332 Electroplating, plating,
polishing, anodizing, and
coloring.
......................... 336 Manufacturers of motor
vehicle parts and
accessories.
......................... 221 Electric, gas, and sanitary
services.
......................... 622 Health services.
......................... 611 Educational services.
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\1\ North American Industry Classification System.
C. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this action is available on the internet. Following signature by the
EPA Administrator, the EPA will post a copy of this proposed action at
https://www.epa.gov/industrial-commercial-and-institutional-boilers-and-process-heaters. Following publication in the Federal Register, the
EPA will post the Federal Register version of the proposal and key
technical documents at this same website.
A redline version of the regulatory language that incorporates the
proposed changes in this action is available in the docket for this
action (Docket ID No. EPA-HQ-OAR-2002-0058).
II. Background
On March 21, 2011, the EPA established final emission standards for
ICI boilers and process heaters at major sources, reflecting the
application of MACT--the Boiler MACT (76 FR 15608). On January 31,
2013, the EPA promulgated final amendments to the Boiler MACT (78 FR
7138). On November 20, 2015, the EPA promulgated additional amendments
to the Boiler MACT (80 FR 72789) in response to certain reconsideration
issues, but other issues remained unresolved due to pending litigation
at the time these final amendments were published.
On July 29, 2016, the D.C. Circuit issued its decision in U.S.
Sugar Corp v. EPA, 830 F.3d 579. In that decision, the court upheld the
EPA's 2013 Boiler MACT against all challenges brought by industry
petitioners, and virtually all challenges brought by environmental
petitioners. However, the court vacated the MACT floor emission limits
for those subcategories where the EPA had excluded certain units from
its MACT-floor calculation because those units burned less than 90
percent of the subcategory defining fuel. U. S. Sugar Corp. v. EPA, 830
F.3d at 631. On December 23, 2016, the D.C. Circuit granted EPA's
motion for rehearing on remedy and remanded without vacatur these
affected MACT standards. 844 F.3d 268. Therefore, these MACT standards
have remained in effect since the court's decision.
Additionally, the court in U.S. Sugar remanded the use of CO as a
surrogate for non-dioxin organic HAP to the EPA for the limited purpose
of addressing the potential availability of post-combustion control
technologies that could control CO. In a subsequent decision on March
16, 2018, the D.C. Circuit remanded the EPA's decision to set a limit
of 130 ppm CO as a surrogate for non-dioxin organic HAP for certain
subcategories, again asking the Agency to better explain its analysis
supporting its decision. Sierra Club v. EPA, 884 F.3d 1185.
In this action, the EPA is proposing changes to certain emissions
limits in the final rule and is providing additional explanation of
certain issues relating to the CO standards in response to these
remands. The EPA is also proposing several technical corrections.
A. What is the statutory authority for this action?
Section 112 of the CAA establishes a regulatory process to address
emissions of HAP from stationary sources. CAA section 112(d) requires
the Agency to promulgate technology-based NESHAP for major sources.
``Major sources'' are defined in CAA Section 112(a) as sources that
emit or have the potential to emit 10 tons or more per year (tpy) of a
single HAP or 25 tpy or more of any combination of HAP. For major
sources, the technology-based NESHAP must require the maximum degree of
reduction in emissions of HAP achievable (after considering cost,
energy requirements, and non-air quality health and environmental
impacts). These standards are commonly referred to as MACT standards.
The MACT ``floor'' is the minimum control level allowed for MACT
standards promulgated under CAA section 112(d)(3) and may not be based
on cost considerations. For new sources, the MACT floor cannot be less
stringent than the emissions control that is achieved in practice by
the best controlled similar source. The MACT floor for existing sources
may be less stringent than floors for new sources but may not be less
stringent than the average emissions limitation achieved by the best-
performing 12 percent of existing sources in the category or
subcategory (or the best-performing five sources for categories or
subcategories with fewer than 30 sources). In developing MACT
standards, the EPA must also consider control options that are more
stringent than the floor (i.e., ``beyond-the-floor'' options) under CAA
section 112(d)(2). We may establish beyond-the-floor standards more
stringent than the floor based on considerations of the cost of
achieving the emission reductions, any non-air quality health and
environmental impacts, and energy requirements.
[[Page 52203]]
III. Discussion of the Proposed Amendments
A. Revisions to MACT Floor Emission Limits
1. Revisions to MACT Floor Ranking Methodology for Co-Fired Units
Many of the affected sources subject to numerical limits under the
NESHAP involve boilers and process heaters that co-fire multiple fuel
types. In the January 2013 final rule amendments, the EPA defined each
subcategory using a threshold of at least 10 percent of a subcategory-
defining fuel, on an annual heat input basis. These definitions were
set up in a hierarchical manner. Solid fuel units must burn at least
10-percent solid fuel. Coal and solid fossil fuel units must burn at
least 10-percent coal or another solid fossil fuel. Biomass units must
burn at least 10-percent biomass, but less than 10-percent coal. Liquid
fuel units may burn any liquid fuel but less than 10-percent coal or
fossil solid, and less than 10-percent biomass. The MACT floor analysis
conducted in the 2013 rulemaking used a 90-percent fuel threshold,
instead of the regulatory definition of 10 percent, to group test data
into subcategories for ranking the best performers and calculating the
MACT floors. This approach excluded several units that were in the
subcategory from the ranking analysis, which in turn excluded these
boilers from consideration in upper prediction limit (UPL) calculations
to establish the MACT floor.
The D.C. Circuit in U.S. Sugar stated that, if EPA includes a
source in a subcategory, it must consider whether any source in that
subcategory is a best-performing source which would then need to be
accounted for in setting the MACT floor. U.S. Sugar v. EPA, 830 F.3d at
631. Following the EPA's request for rehearing, the court remanded
standards affected by its decision to the EPA for further
consideration, and the EPA is now proposing to revise the affected
standards consistent with the court's opinion.
For this proposal, the same dataset used as the basis for the 2013
final rule was used as the basis of the calculations for the proposed
revised standards.\2\ The EPA performed a more detailed review of the
units in the dataset that had previously been excluded from the
rankings, with emphasis on the newly identified best performers. While
checking background test reports, the EPA corrected some database
errors, filled information gaps for certain co-fired fuel blends, and
adjusted CO instrument span measurements. However, since the proposed
revisions are solely to address the remand in U.S. Sugar, we re-ran the
MACT floor analysis to incorporate data that had been previously
excluded. The rankings of each subcategory were revised to incorporate
data from tests that fired at least 10 percent of a subcategory-
defining fuel. This change in criteria impacted the number of units
with emission test data for certain subcategories. In many cases test
data for co-fired units in the 2013 Emissions Database did not quantify
the exact fuel input breakdown.\3\ The EPA reviewed test reports that
were included as background data materials for the 2013 Emissions
Database and conducted outreach with selected facilities in order to
verify to which subcategory the various test data belonged. Appendix B
of the docketed memorandum, Revised MACT Floor Analysis (2019) for the
Industrial, Commercial, and Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants--Major Source
(2019 MACT Floor Memo), details the revised ranking of each subcategory
and compares the ranking to the previous ranking assignment from the
January 2013 final rule. As was done in the January 2013 final rule,
devices that were co-firing solid waste materials were excluded from
the ranking unless the device was exempted from the definition of a
solid waste incineration unit as provided in section 129(g)(1) of the
CAA.
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\2\ Emissions Database for Boilers and Process Heaters
Containing Stack Test, CEM, and Fuel Analysis Data Reporting under
ICR No. 2286.01 and ICR No.2286.03 (OMB Control Number 2060-0616)
(version 8). Docket ID No. EPA-HQ-OAR-2002-0058-3830.
\3\ Ibid.
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As part of the revisions to the ranking analysis, the EPA also made
corrections to some of the emissions data, as part of its data quality
review of the revised set of best performing units in each subcategory.
The EPA investigated historical notes in the 2013 Emissions Database
about whether certain test results were valid or were previously
excluded due to data quality concerns. When historical notes had
excluded data, those exclusions were carried forward into the revised
analysis supporting the proposal. Because some new best performing
units were identified in the ranking analysis, the EPA also reviewed
test reports that were available in the rulemaking docket to verify
reported emission results in the database as well as oxygen adjustment
factors, and CO instrument span and CO calibration data. EPA made
corrections to the values used in the MACT floor analysis when these
back-up documents suggested a correction was needed. In addition to
data available from the docketed data resources, the EPA also received
data correction files and a small number of additional tests from
members of the American Forest and Paper Association. The EPA reviewed
the additional data provided, including any supporting emission test
reports to evaluate if the data were accurate and complete and
representative prior to including the data in the revised ranking
analysis. A summary of data changes made since version 8 of the
database is available in the docketed memorandum, Summary of 2019
Emission Database Changes for Major Source Boilers and Process Heaters.
In addition, a summary of the expected impacts of these data changes is
available in the Regulatory Impact Analysis for the Proposed ICI
Boilers NESHAP Reconsideration, which is available in the docket for
this action. The changes include an increase in compliance costs as
well as an increase in emission reductions as a result of the more
stringent emission limits.
a. Existing Sources
Because the rankings shifted dramatically, the number of units in
each of the subcategories changed, as well as the specific units that
comprised the top 12 percent within the subcategory. Appendix B-1 of
the 2019 MACT Floor Memo summarizes the revised number of units in the
top 12 percent for each combination of subcategory and pollutant. The
remainder of the worksheets in Appendix B indicate which units are
identified to be among the top 12 percent.
Once the top 12 percent of units were identified, each unique
combination of pollutant and subcategory data was reviewed to determine
the distribution of the dataset and then calculate the UPL. The
procedures for determining the data distribution and calculating the
UPL remain the same as they did for the January 2013 final rule, with
the exception of ``limited datasets'' which are those that consisted of
less than seven test runs. The procedures for determining the
distribution and calculating the UPL are detailed in EPA's Response to
Remand of the Record for Major Source Boilers, July 14, 2014 available
in the docket for this action. Additional considerations for limited
datasets are discussed in section III.A.2 of this preamble. The actual
calculations and distribution assignments for each pollutant and
subcategory combination are shown in
[[Page 52204]]
Appendix C of the 2019 MACT Floor Memo. The EPA is not soliciting
comment on its use of the same methodology that it used to set the
January 2013 standards, but is soliciting comment on the proposed
revisions to the standards the Agency is proposing to address
concerning the court's remand in U.S. Sugar.
Once the UPL values were calculated, the EPA reviewed whether any
additional fuel variability factors were available to multiply by the
calculated UPL for Hg, HCl, and total selected metals \4\ (TSM). The
methodology for computing the fuel variability factor did not change
since the January 2013 final rule. Instead, any changes in the fuel
variability factors occurred because of changes to the units that
constituted the top 12 percent for each subcategory and were,
therefore, eligible for consideration in the fuel variability factor
analysis. The fuel variability factor calculations are shown in
Appendix A of the 2019 MACT Floor Memo. Fuel variability factors were
available for solid and liquid fuel subcategories for Hg and HCl and
for biomass fluidized bed, coal, and heavy liquid subcategories for
TSM.
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\4\ Total selected metals is the sum of the non-Hg HAP metals--
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and
selenium.
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b. New Sources
Similar to existing sources, the re-ranking of the data for each
new source subcategory impacted the specific units that were identified
as the lowest emitting for each combination of pollutant and
subcategory.
Additionally, as in the January 2013 final rule, the EPA did not
allow units with a nitrogen oxides-to-CO ratio above 50 to represent a
best performing boiler for CO. Instead, the EPA picked the next lowest
ranked unit for the Coal Stokers. Additionally, as in the January 2013
final rule, the EPA only considered units with at least three test runs
to serve as the basis of the new source floor except for cases where no
other data were available. This occurred only for the TSM UPL
calculations for new Biomass Suspension Burner. In that case, the
second ranked unit was selected. The revisions to the emissions
standards proposed here are for the limited purpose of addressing the
court's remand in U.S. Sugar, and the EPA is not proposing or
soliciting comment on other aspects of the standards or methodology
used to calculate the standards.
Once the best controlled similar source for each subcategory was
identified, each unique combination of pollutant and subcategory data
was reviewed to determine the distribution of the dataset and then
calculate the UPL. The procedures for determining the data distribution
and calculating the UPL remain the same as for the January 2013 final
rule, with the exception of limited datasets that consisted of less
than seven test runs or in cases where the calculated new source UPL
exceeded the existing source UPL for the same subcategory. The
procedures for determining the distribution and calculating the UPL are
detailed in the docketed memorandum, Revised MACT Floor Analysis (2019)
for the Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--Major
Source. Many of the new source UPL calculations involved limited
datasets and additional considerations for limited datasets are
discussed in section III.A.2 of this preamble. The actual calculations
and distribution assignments for each pollutant and subcategory
combination are shown in Appendix E of the 2019 MACT Floor Memo. This
appendix worksheet for each UPL calculation also shows the ranking of
each unit.
Once the UPL values were calculated, the EPA reviewed whether any
additional fuel variability factors were available to multiply by the
calculated UPL for Hg, HCl, and TSM. The methodology for computing the
fuel variability factor did not change since the January 2013 final
rule. Instead, any changes in the fuel variability factors occurred
because of changes to the unit selected to represent the best
controlled similar source and were, therefore, eligible for
consideration in the fuel variability factor analysis for new sources.
The fuel variability factor calculations are shown in Appendix A of the
2019 MACT Floor Memo. Fuel variability factors were available for
liquid fuel and coal subcategories for Hg and HCl, and the heavy liquid
subcategory for TSM.
The EPA also incorporated the same procedures as the January 2013
final rule to ensure that the available measurement methods would
provide accurate emissions measurements at the levels set for the
various standards. The procedures are discussed in detail at 76 FR
80611 and the calculated values are presented in technical memoranda in
the docket.\5\ The procedures remained the same, but which unit
represents the new source floor did change since January 2013; so, the
actual representative detection level (RDL) calculation accordingly
changed as well. The revised calculations for 3 times the RDL are
presented in the documented memorandum. After computing the RDL, the
UPL calculations were compared to a value equal to 3 times the RDL. In
the case of new sources, if the UPL was below the 3 times RDL value
then the MACT floor was set equal to 3 times the RDL.
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\5\ See Docket ID Item Nos.: EPA-HQ-OAR-2002-0058-3837 and EPA-
HQ-OAR-2002-0058-3839.
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Lastly, the EPA compared the calculated UPL, or 3 times RDL values
where appropriate, to the existing source emission limits for the same
pollutant and subcategory. If the new source floor was larger than the
existing source floor, the EPA reviewed the data further as discussed
in the UPL methodology for limited datasets in section III.A.2 of this
preamble to evaluate if the unit truly reflected the best controlled
similar source as determined by the Administrator and to evaluate if
the UPL calculations required any adjustments to ensure that the UPL
did not result in a less stringent standard for new sources. In
addition to the tests conducted on limited datasets, two subcategories
for new source limits required additional evaluation, as discussed
below. Specific names of the facility and boiler names refer to how the
boilers are identified in the MACT floor analysis to allow the reader
to find these units in the related technical support memoranda.
The MACT floor dataset for particulate matter (PM) from new
fluidized bed boilers designed to burn biomass includes 18 test runs
from a single boiler ``ORGeorgiaPacificWaunaMill, EU35--Fluidized Bed
Boiler'' (EU35) that we identified as the best performing unit based on
average emissions. The calculated UPL for new sources exceeded the UPL
calculated for existing units in the same subcategory. After
determining the correct distribution and ensuring that we used the
correct equation for the distribution, we evaluated the variance of
this unit. Our analysis showed that this unit, identified as the best
performing unit based on average emissions, has a variance that is 3
orders of magnitude higher than the second ranked unit
``WIGPGreenBay2818, B10--Wastepaper Sludge-Fired Boiler 10'' (B10) and
an overall average (considering all stack tests, not just the minimum
stack test average) that is approximately 4 times higher than the
second ranked unit. This information indicates that the second ranked
unit, B10, has a more consistent level of performance than the top
ranked unit, EU35, and the resulting UPL calculations support this. The
calculated UPL is lower for the second ranked unit, B10, than for the
top
[[Page 52205]]
ranked unit, EU35. For these reasons, we determined that the unit with
the lowest average, EU35, is not the best performing source for this
subcategory and pollutant and we are instead identifying B10 as the
best performing source.
The MACT floor dataset for PM from new stoker boilers designed to
burn wet biomass includes nine test runs from a single boiler
``IAMonsantoMuscatine, Boiler #8 EP-195'' that we identified as the
best performing unit based on average emissions. The calculated UPL for
new sources exceeded the UPL calculated for existing units in the same
subcategory. The UPL based on a lognormal equation was 10.2 times
higher than the mean. After reviewing the distribution of the dataset,
we found that the distribution was incorrectly flagged as lognormally
distributed instead of normally distributed. The UPL based on the
normal distribution no longer exceeds the UPL calculation for existing
sources. The UPL based on a normal equation was 2.36 times higher than
the mean. After correcting the distribution, we also evaluated the
variance of this unit, which was 4 times lower than the variance of the
next lowest ranked unit. For these reasons, we determined that the UPL
based on the normal distribution was the appropriate basis for the new
source floor for this subcategory.
2. UPL Methodology for Limited Datasets
In August 2013, the D.C. Circuit issued its decision in National
Ass'n. of Clean Water Agencies (NACWA) v. EPA, which addressed
challenges to the EPA's 2011 Sewage Sludge Incinerator (SSI) rule,
issued under section 129 of the CAA. In NACWA v. EPA, the court
remanded the EPA's use of the UPL methodology to the Agency for further
explanation of how the methodology reflected the average emissions
limitation achieved by the best-performing 12 percent of sources (for
existing sources) and the average emissions limitation achieved by the
best-performing similar source (for new sources). NACWA v. EPA, 734
F.3d 1115, 1151. Because the UPL methodology used in the SSI rule was
the same as that used in the major source Boiler MACT, the EPA
requested a remand of the record in U.S. Sugar v. EPA in order to
address the court's decision in NACWA v. EPA. The EPA prepared a
memorandum explaining the methodology for the UPL. This memorandum,
EPA's Response to Remand of the Record for Major Source Boilers,
provides a detailed rationale to use the UPL as the basis of setting a
MACT floor for new and existing sources, and the methodology and the
explanation in the memorandum were upheld by the D.C. Circuit in U.S.
Sugar v. EPA. 830 F.3d at 639. Following the UPL memorandum, the EPA
issued a subsequent memorandum specifically addressing the application
of the UPL methodology when setting MACT emission limits with limited
datasets, Approach for Applying the Upper Prediction Limit to Limited
Datasets. In that memorandum, the EPA concluded that there are
additional considerations when setting MACT floors for limited
datasets. The EPA is not, in this action, proposing any revisions to or
soliciting comment on either the EPA's Response to Remand of the Record
for Major Source Boilers memorandum or the limited datasets memorandum.
Rather, the EPA is proposing limited revisions to certain Boiler MACT
standards to address the specific issue remanded to the Agency by the
court in U.S. Sugar v. EPA. The docketed memorandum, Approach for
Applying the Upper Prediction Limit to Limited Datasets for Boilers and
Process Heaters at Major Sources, discusses the generic methods in the
previously issued limited dataset memorandum, as well as a summary of
the findings for certain boiler and process heater subcategories. A
summary of those findings is also discussed here.
For the ICI Boilers and Process Heaters source categories, we have
limited datasets for the following subcategories and pollutants for
both existing and new sources: process gas (Hg, HCl, TSM, and PM),
biomass suspension burner (TSM), dry biomass stoker (TSM, PM, and CO),
and coal fluidized bed coal refuse (CO). For the ICI Boilers and
Process Heaters source categories, we have limited datasets for the
following subcategories and pollutants for new sources: Solid (Hg and
HCl), liquid (Hg and HCl), heavy liquid (TSM and PM), light liquid (TSM
and PM), biomass dutch oven/pile burner (TSM), biomass fuel cell (TSM),
biomass fluidized bed (TSM), biomass suspension burner (TSM), biomass
suspension grate (CO), wet biomass stoker (TSM), and coal (TSM and PM).
Therefore, we evaluated these specific datasets to determine whether it
is appropriate to make any modifications to the UPL approach used to
calculate the MACT floors. For each dataset, we performed the following
steps: Selected the data distribution that best represents the dataset;
ensured that the correct equation for the distribution was then applied
to the data; and compared individual components of the limited dataset
to determine if the standards based on the limited dataset reasonably
represent the performance of the units included in the dataset. The
results of the limited dataset analyses are presented below for each
subcategory and pollutant.
The MACT floor datasets for Hg, HCl, and PM from existing and new
boilers designed to burn process gas include three test runs from a
single boiler. In addition, there are no other process gas units in the
rankings to select from for these pollutants. Using the available data,
we first determined the correct distribution and ensured that we used
the correct equation for each distribution. The MACT floor dataset for
TSM from existing and new boilers designed to burn process gas only
includes two test runs. We assumed a distribution of lognormal for this
dataset. We then calculated the UPL-based limits which range from 1.2
to 3 times the average (mean) of all test runs from the best performing
source. This result indicates that the emission limits are not
unreasonable compared to the actual performance of the unit upon which
the limits are based and are within the ranges that we see when we
evaluate larger datasets using our MACT floor calculation procedures.
Therefore, we determined that the emission limit reasonably accounts
for variability and that no changes to the standard floor calculation
procedure were warranted for this pollutant and subcategory.
The MACT floor dataset for TSM from existing and new suspension
burner boilers designed to burn biomass includes three test runs from a
single boiler that we identified as the best performing unit based on
average emissions. In addition, there are no other biomass suspension
burner units in the rankings to select from for this pollutant because
the other unit with test data only has two test runs, and units with
less than three test runs were not considered for UPL calculations if
other data are available (see discussion in section III.A.1 of this
preamble). Using the available data, we first determined the correct
distribution and ensured that we used the correct equation for each
distribution. We then calculated the UPL-based limit which is 1.7 times
the short-term average emissions from the best performing source. This
result indicates that the emission limit is not unreasonable compared
to the actual performance of the unit upon which the limit is based and
is within the range that we see when we evaluate larger datasets using
our MACT floor calculation procedures. Therefore, we determined that
the emission limit reasonably accounts for
[[Page 52206]]
variability and that no changes to the standard floor calculation
procedure were warranted for this pollutant and subcategory.
The MACT floor dataset for TSM from existing and new stoker boilers
designed to burn dry biomass includes three test runs from a single
boiler. In addition, there are no other dry biomass stoker units in the
rankings to select from for this pollutant. Using the available data,
we first determined the correct distribution and ensured that we used
the correct equation for each distribution. We then calculated the UPL-
based-limit, which is approximately 2 times the short-term average
emissions from the best performing source, indicating that the emission
limit is not unreasonable compared to the actual performance of the
unit upon which the limit is based and is within the range that we see
when we evaluate larger datasets using our MACT floor calculation
procedures. Therefore, we determined that the emission limit reasonably
accounts for variability and that no changes to the standard floor
calculation procedure were warranted for this pollutant and
subcategory.
The MACT floor datasets for PM and CO from existing and new stoker
boilers designed to burn dry biomass include three test runs from a
single boiler that we identified as the best performing unit based on
average emissions. After determining the correct distribution and
ensuring that we used the correct equation for each distribution, we
evaluated the variance of this unit for each pollutant, comparing it to
other boilers in the same subcategory. Our analysis showed that this
unit, identified as the best performing unit based on average
emissions, also had the lowest variance for each pollutant, indicating
that not only did it have the lowest average emissions but also the
most consistent performance. Therefore, we determined that the emission
limits reasonably account for variability and that no changes to our
standard floor calculation procedure were warranted for this
subcategory and pollutants.
The MACT floor dataset for CO from existing and new fluidized bed
boilers designed to burn coal refuse includes three test runs from a
single boiler. In addition, there are no other units in the rankings to
select from for this pollutant. Using the available data, we first
determined the correct distribution and ensured that we used the
correct equation for the distribution. We then calculated the UPL-based
limit which is approximately 1.5 times the short-term average emissions
from the best performing source, indicating that the emission limit is
not unreasonable compared to the actual performance of the unit upon
which the limit is based and is within the range that we see when we
evaluate larger datasets using our MACT floor calculation procedures.
Therefore, we determined that the emission limit reasonably accounts
for variability and that no changes to the standard floor calculation
procedure were warranted for this pollutant and subcategory.
The MACT floor dataset for Hg from new boilers designed to burn
solid fuel includes six test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for each distribution, we evaluated the variance
of this unit, comparing it to other boilers in the same subcategory.
Our analysis showed that this unit, identified as the best performing
unit based on average emissions, also had the lowest variance,
indicating that not only did it have the lowest average emissions but
also the most consistent performance. Therefore, we determined that the
emission limit reasonably accounts for variability and that no changes
to our standard floor calculation procedure were warranted for this
subcategory and pollutant.
The MACT floor dataset for HCl from new boilers designed to burn
solid fuel includes six test runs from a single boiler
``ARPotlatchForestWarren, Wellons Boiler'' (Wellons Boiler) that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for each distribution, we compared the calculated
UPL to the short-term average emissions and found that the unit had a
UPL that was 81 times higher than the lowest short-term average
emission test and that this ratio is not within the range that we see
when we evaluate larger datasets using our MACT floor calculation
procedures. Based on this, we evaluated the variance of this unit and
concluded that further consideration of the best performer selection
was warranted. The variance of the top ranked unit was 6 orders of
magnitude higher than the variance of the next ranked unit
``TXDibollTemple-Inland, PB-44'' (PB-44). In addition, the Wellons
Boiler six test runs were from two separate stack tests, and while the
unit was the top ranked unit due to one of the stack test averages
being very low, the other stack test average was 6.2 times higher. The
high degree of variance in the dataset for the unit with the lowest
average, Wellons Boiler, prompted us to question whether this unit was,
in fact, the best performing unit and to evaluate the dataset for PB-
44. The dataset for PB-44 includes three test runs and the average
emissions are only about 7 percent higher than the Wellons Boiler
lowest stack test average. However, the PB-44 average emissions are
actually 97 percent lower when comparing to the Wellons Boiler average
for both stack tests. This information indicates that the second ranked
unit, PB-44, has a more consistent level of performance than the top
ranked unit, Wellons Boiler, and the resulting UPL calculations support
this. The HCl UPL value is lower for PB-44 than for Wellons Boiler and
the Wellons Boiler UPL exceeded the UPL for existing solid fuel
boilers. For these reasons, we determined that the unit with the lowest
average, Wellons Boiler, is not the best performing source for this
pollutant and we are instead determining PB-44 to be the best
performing source.
The MACT floor dataset for Hg from new boilers designed to burn
liquid fuel includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for each distribution, we evaluated the variance
of this unit. Our analysis showed that this unit, identified as the
best performing unit based on average emissions, and the second ranked
unit both have similar and extremely low variance, indicating
consistent performance. Therefore, we determined that the emission
limit reasonably accounts for variability and that no changes to the
standard floor calculation procedure were warranted for this
subcategory and pollutant.
The MACT floor dataset for HCl from new boilers designed to burn
liquid fuel includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for each distribution, we evaluated the variance
of this unit, comparing it to other boilers in the same subcategory.
Our analysis showed that this unit, identified as the best performing
unit based on average emissions, also had the lowest variance,
indicating that not only did it have the lowest average emissions but
also the most consistent performance. Therefore, we determined that the
emission limit reasonably accounts for variability and that no changes
to the standard floor calculation procedure were warranted for this
subcategory and pollutant.
The MACT floor dataset for TSM from new boilers designed to burn
heavy
[[Page 52207]]
liquid fuel includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for the distribution, we evaluated the variance of
this unit, comparing it to other boilers in the same subcategory. Our
analysis showed that this unit, identified as the best unit based on
average emissions, had a slightly higher variance than the next ranked
unit. Therefore, we also evaluated the second ranked unit and
determined its distribution and applied the equation for its
distribution. Comparing the calculated UPL values for the top two
units, the best performing unit resulted in the lower UPL. While its
variance was slightly higher, the top ranked unit's lower overall
emissions and resulting UPL calculations indicate it is the best
performer. Therefore, we determined that the emission limit reasonably
accounts for variability and that no changes to the standard floor
calculation procedure were warranted for this pollutant and
subcategory.
The MACT floor dataset for PM from new boilers designed to burn
heavy liquid fuel includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for the distribution, we evaluated the variance of
this unit, comparing it to other boilers in the same subcategory. Our
analysis showed that this unit, identified as the best performing unit
based on average emissions, also had the lowest variance, indicating
that not only did it have the lowest average emissions but also the
most consistent performance. Therefore, we determined that the emission
limit reasonably accounts for variability and that no changes to the
standard floor calculation procedure were warranted for this pollutant
and subcategory.
The MACT floor dataset for TSM from new boilers designed to burn
light liquid fuel includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for the distribution, we evaluated the variance of
this unit, comparing it to other boilers in the same subcategory. Our
analysis showed that this unit, identified as the best performing unit
based on average emissions, and the second ranked unit have nearly
equivalent variance, indicating consistent performance. Therefore, we
determined that the emission limit reasonably accounts for variability
and that no changes to the standard floor calculation procedure were
warranted for this pollutant and subcategory.
The MACT floor dataset for PM from new boilers designed to burn
light liquid fuel includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for the distribution, we evaluated the variance of
this unit, comparing it to other boilers in the same subcategory. Our
analysis showed that this unit, identified as the best performing unit
based on average emissions, also had the lowest variance, indicating
that not only did it have the lowest average emissions but also the
most consistent performance. Therefore, we determined that the emission
limit reasonably accounts for variability and that no changes to the
standard floor calculation procedure were warranted for this pollutant
and subcategory.
The MACT floor dataset for TSM from new dutch oven boilers designed
to burn biomass includes three test runs from a single boiler that we
identified as the best performing unit based on average emissions.
After determining the correct distribution and ensuring that we used
the correct equation for the distribution, we evaluated the variance of
this unit, comparing it to other boilers in the same subcategory. Our
analysis showed that this unit, identified as the best performing unit
based on average emissions, also had the lowest variance, indicating
that not only did it have the lowest average emissions but also the
most consistent performance. Therefore, we determined that the emission
limit reasonably accounts for variability and that no changes to the
standard floor calculation procedure were warranted for this pollutant
and subcategory.
The MACT floor dataset for TSM from new biomass fuel cell boilers
includes six test runs from a single boiler that we identified as the
best performing unit based on average emissions. After determining the
correct distribution and ensuring that we used the correct equation for
the distribution, we evaluated the variance of this unit, comparing it
to other boilers in the same subcategory. Our analysis showed that this
unit, identified as the best performing unit based on average
emissions, also had the lowest variance, indicating that not only did
it have the lowest average emissions but also the most consistent
performance. Therefore, we determined that the emission limit
reasonably accounts for variability and that no changes to the standard
floor calculation procedure were warranted for this pollutant and
subcategory.
The MACT floor dataset for TSM from new fluidized bed boilers
designed to burn biomass includes three test runs from a single boiler
that we identified as the best performing unit based on average
emissions. After determining the correct distribution and ensuring that
we used the correct equation for the distribution, we evaluated the
variance of this unit, comparing it to other boilers in the same
subcategory. Our analysis showed that this unit, identified as the best
performing unit based on average emissions, also had the lowest
variance, indicating that not only did it have the lowest average
emissions but also the most consistent performance. Therefore, we
determined that the emission limit reasonably accounts for variability
and that no changes to the standard floor calculation procedure were
warranted for this pollutant and subcategory.
The MACT floor dataset for TSM from new suspension burners designed
to burn biomass includes three test runs from a single boiler. In
addition, there are no other biomass suspension burner units in the
rankings to select from for this pollutant. Using the available data,
we first determined the correct distribution and ensured that we used
the correct equation for each distribution. We then calculated the UPL-
based limit which is 1.7 times the short-term average emissions from
the best performing source, indicating that the emission limit is not
unreasonable compared to the actual performance of the unit upon which
the limit is based and is within the range that we see when we evaluate
larger datasets using our MACT floor calculation procedures. Therefore,
we determined that the emission limit reasonably accounts for
variability and that no changes to our standard floor calculation
procedure were warranted for this subcategory and pollutant.
The MACT floor dataset for TSM from new stoker boilers designed to
burn wet biomass includes six test runs from a single boiler
``GAGPCelluloseBrunswick, U700--No. 4 Power Boiler'' (U700--No. 4 Power
Boiler) that we identified as the best performing unit based on average
emissions. After determining the correct distribution and ensuring that
we used the correct equation for the distribution, we evaluated the
variance of this unit, comparing it to other boilers in the same
subcategory. We note that the second and third ranked units each have
less than three test runs, and units with less than three test runs
were not considered for UPL calculations if other data are available
(see discussion in section
[[Page 52208]]
III.A.1 of this preamble). Our analysis showed that this unit,
identified as the best performing unit based only on average emissions,
has a higher variance than the fourth ranked unit ``MESDWarrenSomerset,
No. 2 Power Boiler'' (No. 2 Power Boiler) and an overall average
(considering all stack tests, not just the minimum stack test average)
that is approximately 18 percent higher than the fourth ranked unit.
This information indicates that the fourth ranked unit, No. 2 Power
Boiler, has a more consistent level of performance than the top ranked
unit, U700--No. 4 Power Boiler, and the resulting UPL calculations
support this. The calculated UPL is lower for the fourth ranked unit,
No. 2 Power Boiler, than for the top ranked unit, U700--No. 4 Power
Boiler. For these reasons, we determined that the unit with the lowest
average, U700--No. 4 Power Boiler, is not the best performing source
for this subcategory and pollutant and we are instead determining that
No. 2 Power Boiler is the best performing source.
The MACT floor dataset for CO from new suspension grate boilers
designed to burn biomass includes three test runs from a single boiler
that we identified as the best performing unit based on average
emissions. After determining the correct distribution and ensuring that
we used the correct equation for each distribution, we evaluated the
variance of this unit, comparing it to other boilers in the same
subcategory. Our analysis showed that this unit, identified as the best
unit based on average emissions, also had the lowest variance,
indicating that not only did it have the lowest average emissions but
also the most consistent performance. Therefore, we determined that the
emission limit reasonably accounts for variability and that no changes
to the standard floor calculation procedure were warranted for this
subcategory and pollutant.
The MACT floor dataset for TSM from new coal boilers includes six
test runs from a single boiler that we identified as the best
performing unit based on average emissions. After determining the
correct distribution and ensuring that we used the correct equation for
each distribution, we evaluated the variance of this unit and concluded
that further consideration of the best performer selection was
warranted. The variance of the top ranked unit was approximately 3
times higher than the variance of the next ranked unit. The degree of
variance in the dataset for the unit with the lowest average prompted
us to question whether this unit was, in fact, the best performing unit
and to evaluate the second ranked unit. The second ranked unit includes
3 test runs. We calculated the UPL using data for the second ranked
unit, however, and the resulting UPL was higher than when using data
from the top ranked unit. While its variance was higher, the top ranked
unit's lower overall emissions and resulting UPL calculations indicate
it is the best performer. Therefore, we determined that the emission
limit reasonably accounts for variability and that no changes to the
standard floor calculation procedure were warranted for this
subcategory and pollutant.
The MACT floor dataset for PM from new coal boilers includes six
test runs from a single boiler that we identified as the best
performing unit based on average emissions. After determining the
correct distribution and ensuring that we used the correct equation for
each distribution, we evaluated the variance of this unit and concluded
that further consideration of the best performer selection was
warranted. The variance of the top ranked unit was approximately 2.5
times higher than the variance of the next ranked unit. The degree of
variance in the dataset for the unit with the lowest average prompted
us to question whether this unit was, in fact, the best performing unit
and to evaluate the second ranked unit. The second ranked unit includes
three test runs. We calculated the UPL using data for the second ranked
unit, however, and the resulting UPL was higher than when using data
from the top ranked unit. Therefore, while its variance was higher, the
top ranked unit's lower overall emissions and resulting UPL
calculations indicate it is the best performer. Therefore, we
determined that the emission limit reasonably accounts for variability
and that no changes to the standard floor calculation procedure were
warranted for this subcategory and pollutant.
The Process Gas and Coal Fluidized Bed subcategories for existing
and new sources and the Heavy Liquid Fuel, Light Liquid Fuel,
Pulverized Coal Boilers, and Coal Stoker subcategories for new sources
have limited datasets for CO. However, the best performers have very
low CO emissions and the emission limits were set equal to a minimum CO
level; the applicable methodology is discussed in section III.E of this
preamble.
B. Beyond-the-Floor Emission Limits
We reviewed the recalculated MACT floor emission limits that are
less stringent than those in the January 2013 final rule in order to
assess whether a beyond-the-floor option was technically achievable and
cost-effective. To assess whether the January 2013 limits were
technically achievable we reviewed the compliance data available to the
EPA through the Compliance and Emissions Data Reporting Interface
(CEDRI) and WebFIRE \6\ and compared these data to the emission limits
in the January 2013 final rule to assess whether those more stringent
limits were being achieved in practice. Data is submitted to CEDRI by
regulated entities to EPA in order to meet electronic reporting
requirements of 40 CFR part 60 subpart DDDDD. These reports include
performance tests, CEMS relative accuracy test audits, notifications of
compliance status reports, among other items. WebFIRE displays these
reports to the public and can be searched by regulatory subpart or
boiler process type (e.g., fuel type, boiler size). For existing
sources, with the exception of TSM at coal units, all of the compliance
data available for the subcategory showed that the units were complying
with the more stringent 2013 emission limit. For TSM at coal-fired
units, 83 percent of the units (10 of 12) with data were below the more
stringent 2013 emission limit. The two units that were not were 12
percent above the 2013 emission limit, but these units were using the
emission averaging provision to comply at a common stack. To assess
whether the limits were cost-effective, the EPA reviewed the control
devices currently installed to determine if any cost savings would
occur should the less stringent limit be selected. In all of these
cases, the controls that were already installed were the same types of
controls that would be required to meet either the January 2013 limits
or the less stringent recalculated limits and, therefore, no additional
costs would be incurred to meet the more stringent limits. There were
three additional cases where the January 2013 remanded emission limit
was more stringent than the recalculated emission limit, but no recent
compliance data were available in these three cases. Since no data were
available for PM at Gas 2 units, and TSM at biomass suspension burners
or dry biomass stokers, the EPA did not select a beyond-the-floor limit
for these three emission limits. In all three of these cases, where we
did not have data, the changes are resulting from the revised
methodology for limited datasets. The process gas unit is uncontrolled,
and the dry biomass stoker and biomass suspension burner both had a
multiclone installed.
---------------------------------------------------------------------------
\6\ U.S. Environmental Protection Agency. Compliance and
Emissions Data Reporting Interface (CEDRI) https://www.epa.gov/electronic-reporting-air-emissions/cedri and WebFIRE database
https://www.epa.gov/electronic-reporting-air-emissions/webfire.
---------------------------------------------------------------------------
[[Page 52209]]
Based on the review of compliance data, the EPA selected a beyond-
the-floor level for 10 of the existing source emission limits, as
listed in Table 4.
Table 4--Existing Source Emission Limits Based on Beyond-the-Floor
------------------------------------------------------------------------
Existing source subcategory
limit Discussion
------------------------------------------------------------------------
HCl-Liquid................... All of the existing units with data
available are below the 2013 emission
limit.
TSM-Coal..................... All 10 of the existing units complying
with the TSM limit were below the 2013
emission limit.
TSM-Heavy Liquid............. The two existing units with data were
both below the 2013 emission limit.
TSM-Light Liquid............. The two existing units with data were
both below the 2013 emission limit.
PM-Dry Biomass Stoker........ All six of the existing units with data
were below the 2013 limit.
CO-Biomass Suspension Burner. All 12 of the existing units with data
were below the 2013 limit.
CO-Biomass Suspension Grate.. All 99 of the existing units with data
were below the 2013 limit.
CO-Dry Biomass Stoker........ All six of the existing units with data
were below the 2013 limit.
CO-Coal Fluidized Bed with The one existing unit with data was below
Heat Exchanger. the 2013 limit.
------------------------------------------------------------------------
For new sources, the EPA made a similar comparison to compliance
data from new and existing boilers in order to assess whether the
limits were achievable. In addition, for PM emission limits at new
sources, consistent with the analysis taken during the January 2013
final rule, PM emission limits were compared to the PM limit of 0.03
pound per million British thermal units (lb/MMBtu) for new biomass
boilers in 40 CFR part 60, subparts Db and Dc. Only biomass compliance
data were available for new sources, and so the EPA compared both
existing and new source compliance data, when available, to the
emission limits in the January 2013 final rule. For three of the
limits, all of the units with available compliance data were below the
more stringent January 2013 emission limit. For the PM limit at dry
biomass stokers, and the TSM limit at wet biomass stokers, all of the
available new source compliance data were meeting the more stringent
January 2013 emission limit. Two of the limits had no new source data
available for comparison, but the TSM at coal units had 50 percent of
the existing units with data below the January 2013 new source limit,
and 9 percent of the coal units were below the new source limit for PM.
Both of these cases demonstrate that the limits are technically
achievable. There were three cases where the January 2013 remanded new
source emission limit was more stringent than the emission limit
calculated based on the revised MACT floor calculation methodology, but
no recent compliance data were available in these four cases. These
were the same three groups mentioned for existing sources, PM at Gas 2
units, and TSM at biomass suspension burners or dry biomass stokers.
Due to lack of data, the EPA did not select a beyond-the-floor limit
for these three emission limits. For new sources, there were seven
emission limits where a beyond-the-floor level was selected, as listed
in Table 5.
Table 5--New Source Emission Limits Based On Beyond-the-Floor
------------------------------------------------------------------------
New source subcategory limit Discussion
------------------------------------------------------------------------
TSM-Wet Biomass Stoker....... Only one existing and one new wet stoker
boiler has TSM compliance data. The new
source data is below the 2013 new source
limit.
TSM-Coal..................... Six of the 12 existing units with
compliance data are below the 2013 limit
for new sources. Of the ones that were
above the limit, all of them were above
both the 2013 limit and the remanded
MACT floor emission limit. No new coal
units were identified in recent
compliance data.
PM-Suspension Burner......... The calculated UPL is identical to the
value calculated in the 2013 final rule
for existing sources. However, the UPL
calculation was less stringent than the
new source performance standards (NSPS)
limit for new boilers. Additionally, all
of the 13 units with PM test data are
below the 2013 limit for new sources.
PM-Dry Biomass Stoker........ Of the seven units with PM test data,
three units were below the 2013 emission
limits for new sources, including one
new dry biomass stoker boiler.
Additionally, the UPL calculation was
less stringent than the NSPS limit for
new boilers.
PM-Coal...................... Of the 101 existing units with PM test
data, nine units were below the 2013
emission limit for new sources. No new
coal units were identified in recent
compliance data.
CO-Dry Biomass Stoker........ All seven of the existing units with
data, including one new dry biomass
stoker were below the 2013 limit.
CO-Coal Fluidized Bed with The one existing unit with data was below
Heat Exchanger. the 2013 limit.
------------------------------------------------------------------------
C. Revisions to Output-Based Emission Limits
The EPA reviewed the output-based emission limits, and revised as
necessary, for subcategories and pollutants where the input-based
emission limits were revised. There was not a corresponding revision in
the output-based emission limit for certain subcategories and
pollutants where the input-based emission limit was revised, due to
rounding (i.e., the input-based emission limit revision was small
enough that performing the output-based calculations did not result in
a different emission limit after rounding to two significant figures).
We also updated the output-based emission limit calculations to use
data from the current population of best performers, considering the
changes to the rankings made in response to the court remands.
Specifically, we revised the steam conversion factor (steam Btu out/
fuel Btu in) used to calculate the output-based limits in the units of
lb/MMBtu steam output for three subcategories for existing sources:
Biomass dutch oven, wet biomass, and coal stoker. We reviewed the
corresponding steam conversion factors for new sources, but revisions
were not necessary as a result of the new analyses. The memorandum,
[[Page 52210]]
Alternate Equivalent Output-Based Emission Limits for Boilers and
Process Heaters Located at Major Source Facilities--2019 Revision,
which is available in the docket for this action, provides details of
the output-based emission limit revisions and methodology.
D. Proposed Response to the Amended Issue: CO as a Surrogate for
Organic HAP
On July 29, 2016, the D.C. Circuit remanded to the EPA to address a
public comment relating to the potential availability of alternative
control technologies which reduce organic HAP without impacting CO
emissions. In doing so, the court rejected challengers' argument that
the EPA could not use CO as a surrogate for non-dioxin/furan (D/F)
organic HAP and limited its remand to the Agency's failure to address
evidence in the record on the potential availability of alternative
control technologies. The court further noted that ``it is likely''
that the EPA would be able to adequately explain its use of CO on
remand. U.S. Sugar v. EPA, 830 F.3d at 630.
It is helpful to provide some background on the EPA's decision to
use CO as a surrogate in the Boiler MACT rule in order to provide the
context for the EPA's action to address the U.S. Sugar court's remand
for explanation. In the preamble to the June 2010 proposal, we
presented the rationale for using CO as a surrogate for non-D/F organic
HAP emitted from boilers and process heaters. We stated that CO has
generally been used as a surrogate for organic HAP because CO is a good
indicator of incomplete combustion and organic HAP are products of
incomplete combustion. However, based on concerns that CO may not be an
appropriate surrogate for D/F because, unlike other organic HAP, D/F
can be formed outside the combustion unit, we proposed using CO as a
surrogate only for non-D/F organic HAP. For non-D/F organic HAP, we
concluded that using CO as a surrogate was a reasonable approach
because minimizing CO emissions will result in minimizing non-D/F
organic HAP. We stated that, for boilers and process heaters, methods
used for the control of CO emissions would be the same methods used to
control non-D/F organic HAP emissions. These emission control methods
include achieving good combustion or using an oxidation catalyst.
Standards limiting emissions of CO will also result in decreases in
non-D/F organic HAP emissions (with the additional benefit of
decreasing volatile organic compounds (VOC) emissions). Establishing
emission limits for specific organic HAP would be impractical and
costly. Thus, we concluded that CO, which is less expensive to test for
and monitor, is appropriate for use as a surrogate for non-dioxin
organic HAP.
We stated in the 2010 proposal that we recognized that the level
and distribution of organic HAP will vary from unit to unit. For
example, the principal organic HAP emitted from coal-fired units is
benzene, which accounts for about 20 percent of the organic HAP with
formaldehyde accounting for about 4 percent of the organic HAP.
Whereas, the principal organic HAP emitted from biomass-fired units is
formaldehyde, which accounts for 34 percent of the organic HAP with
benzene accounting for about 25 percent of the organic HAP.\7\ For oil-
fired units, formaldehyde is the principal organic HAP, accounting for
about 80 percent of the organic HAP. Limiting CO as a surrogate for
only non-dioxin organic HAP would eliminate costs associated with
speciating numerous compounds. We also stated that CO was preferable
because many sources currently have CO continuous emission monitoring
systems (CEMS).
---------------------------------------------------------------------------
\7\ Based on emission factors reported on the EPA web page, AP
42, Fifth Edition, Volume 1--Chapter 1: External Combustion Sources,
located at https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf.
---------------------------------------------------------------------------
In the 2013 final rule preamble, as part of the rationale for the
130 ppm CO minimum MACT floor level, we again explained the basis for
concluding that CO is an appropriate surrogate. That is, CO is a
conservative surrogate for organic HAP because organic HAP emissions
are extremely low when sources operate under the good combustion
conditions required to achieve low CO levels. There are myriad factors
that affect combustion efficiency (CE) and, as a function of CE, CO
emissions. As combustion conditions improve and hydrocarbon levels
decrease, the larger and easier to combust compounds are oxidized to
form smaller compounds that are, in turn, oxidized to form CO and
water. As combustion continues, CO is then oxidized to form
CO2 and water. Because CO is a difficult to destroy
refractory compound (i.e., oxidation of CO to CO2 is the
slowest and last step in the oxidation of hydrocarbons), it is a
conservative surrogate for destruction of hydrocarbons, including
organic HAP.
Available control technologies for organic HAP emissions are of two
types: Combustion and recovery. The combustion devices include thermal
incinerators, catalytic incinerators, flares, and boilers/process
heaters. Applicable recovery devices include condensers, adsorbers, and
absorbers. The combustion devices are the more commonly applied control
devices, since they are capable of high removal (i.e., destruction)
efficiencies for almost any type of organic vapor HAP.\8\ As discussed
below, the removal efficiencies of the recovery techniques generally
depend on the physical and chemical characteristics of the organic HAP
under consideration as well as the emission stream characteristics.
Applicability of the control techniques depends on the individual
emission stream under consideration. In this case, it would be emission
streams from boilers and process heaters. The key emission stream
characteristics and HAP characteristics that affect the applicability
of each control technique are discussed below.
---------------------------------------------------------------------------
\8\ Handbook Control Technologies for Hazardous Air Pollutants,
EPA/625/6-91/014, June 1991, Center for Environmental Research
Information, Office of Research and Development, U.S. EPA.
---------------------------------------------------------------------------
Thermal incinerators use combustion to control a wide variety of
continuous organic HAP emission streams. Compared to the other
techniques, thermal incineration is broadly applicable; that is, it is
much less dependent on HAP characteristics and emission stream
characteristics. Destruction efficiencies up to 99 percent or higher
are achievable with thermal incineration. Thermal incineration
typically is applied to emission streams that are dilute mixtures of
organic HAP and air.
Catalytic incinerators are similar to thermal incinerators in
design and operation except that they employ a catalyst to enhance the
reaction rate. Since the catalyst allows the reaction to take place at
lower temperatures, significant fuel savings may be possible with
catalytic incineration. Catalytic incineration is not as broadly
applicable as thermal incineration since performance of catalytic
incinerators is more sensitive to pollutant characteristics and process
conditions than is thermal incinerator performance. Materials in the
emission stream can poison the catalyst and severely affect its
performance. Destruction efficiencies of 95 percent of HAP can
typically be achieved with catalytic incineration.
Flares are commonly used for disposal of waste gases during process
upsets and emergencies. They are basically safety devices that are also
used to destroy waste emission streams. Flares can be used for
controlling almost any organic HAP emission stream.
[[Page 52211]]
Boilers or process heaters are used to control emission streams
containing organic compounds. These are currently used as control
devices for emission streams from several industries (e.g., refinery
operations, polymers and resins operations, chemical reactor processes,
and distillation operations, etc.). See 40 CFR part 63, subparts JJJ,
OOO, and PPP. Typically, off-gases containing organic HAP emissions are
controlled in boilers or process heaters and used as supplemental fuel
if they have sufficient heating value. When used as emission control
devices, boilers or process heaters can provide destruction
efficiencies of greater than 98 percent.
Carbon adsorption is a recovery (non-combustion) technique commonly
employed as a pollution control and/or a solvent recovery technique. It
is applied to dilute mixtures of HAP and air. Removal efficiencies of
95 to 99 percent can be achieved using carbon adsorption. Outlet
concentrations around 50 parts per million by volume (ppmv) can be
routinely achieved with state-of-the-art systems; concentrations as low
as 10 to 20 ppmv can be achieved with some compounds. Highly volatile
materials (i.e., molecular weight less than about 45) do not adsorb
readily on carbon; therefore, adsorption is not typically used for
controlling emission streams containing such compounds. Carbon
adsorption is also relatively sensitive to emission stream conditions,
such as high humidity and temperatures.
Absorption is widely used as a raw material and/or a product
recovery technique in separation and purification of gaseous streams
containing high concentrations of VOC. As an emission control
technique, it is much more commonly employed for inorganic vapors than
for organic vapors. Using absorption as the primary control technique
for organic vapor HAP is subject to several limitations and problems.
The suitability of absorption for controlling organic vapor emissions
is determined by several factors; most of these factors will depend on
the specific HAP in question. For example, the most important factor is
the availability of a suitable solvent. The pollutant in question
should be readily soluble in the solvent for effective absorption
rates.
Condensers are widely used as raw material and/or product recovery
devices. They are frequently applied as preliminary air pollution
control devices for removing VOC contaminants from emission streams
prior to other control devices such as incinerators, adsorbers, or
absorbers. Condensers are also used by themselves for controlling
emission streams containing high VOC concentrations (usually >5,000
ppmv). In these cases, removal efficiencies obtained by condensers can
range from 50 to 90 percent although removal efficiencies at the higher
end of the scale usually require HAP concentrations of around 10,000
ppmv or greater. Therefore, it is not possible for condensation with
water as the coolant to achieve the low outlet concentrations that
would be required in HAP control applications.
In summary, combustion is the more commonly applied technology for
controlling organic HAP since it is capable of high removal
efficiencies for organic HAP and its effectiveness does not depend on
the makeup of the organic HAP stream or the organic HAP concentration.
In fact, the devices regulated by the rule (boilers and process
heaters) not only combust fuel for producing steam and/or process heat
but serve a dual function in that they also effectively control organic
HAP when good combustion conditions are present. Recovery (non-
combustion) devices are not applicable on all organic HAP and are not
effective on low organic HAP concentration streams. Also, recovery
devices' effectiveness is dependent on an emission stream with a high
organic HAP content (>250 ppmv), compared to the organic HAP content of
the emission streams from boilers which are around 1 ppmv for fossil
fuels (coal and oil) and around 10 ppmv for biomass.\9\ Therefore, at
the organic HAP levels generated and emitted from a boiler, the
recovery (non-combustion) technologies would be ineffective.
Furthermore, none of the best performing units employ any add-on
alternative control device for controlling organic HAP. Many industrial
boilers and process heaters employ post combustion controls for PM,
acid gases, and/or Hg but these add-on controls do not affect emissions
of CO or non-dioxin organic HAP.
---------------------------------------------------------------------------
\9\ Based on emission factors reported on the EPA web page, AP
42, Fifth Edition, Volume 1--Chapter 1: External Combustion Sources,
located at https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf.
---------------------------------------------------------------------------
For these reasons, we continue to conclude that the level of CO
emissions, which indicates organic HAP reductions achieved through the
use of combustion controls, is an appropriate surrogate for controlling
organic HAP emissions from boilers and process heaters.
E. Proposed Response to the Amended Issue: CO 130 PPM Threshold
Emission Limits
The D.C. Circuit, on March 16, 2018, issued an opinion in the
Boiler MACT reconsideration case, Sierra Club v. EPA, 884 F.3d 1185,
which was a petition for review by environmental groups of the 2015
reconsideration of the Boiler MACT rule. The case addressed two issues
that were severed from the litigation challenging the 2013 Boiler MACT
rule (U.S. Sugar v. EPA): (1) The 130-ppm threshold for CO standards,
which, as described above, were established as a surrogate for non-
dioxin organic HAP and (2) the definitions of periods of startup and
shutdown and the applicable work practices to be used during those
periods. The court granted the petition as to the CO issue, finding
that the EPA had not provided sufficient record support for the CO
concentration threshold and remanded for further explanation, but
denied the petition on the startup/shutdown issue and upheld the EPA's
approach as consistent with the CAA.
The court declined to revisit its opinion in U.S. Sugar, in which
the court upheld the use of CO as a surrogate for organic HAP but
remanded to the EPA to address whether there are means to reduce
organic HAP other than by combustion. Against that backdrop, the court,
in its decision in Sierra Club said the question before it was whether,
assuming CO is an appropriate surrogate, the EPA's decision to
establish a 130-ppm threshold as the lowest (i.e., most stringent)
numeric CO limit was consistent with the requirements of the CAA. Based
on a close examination of the record, the court held that the EPA had
not sufficiently explained its rationale and questioned EPA's reliance
on data regarding the relationship between formaldehyde and organic HAP
that the EPA had previously characterized as unreliable.
The court did note that if the EPA made and adequately supported a
determination that no further reduction of HAP would occur once CO
levels had been reduced to 130 ppm, the threshold would be appropriate
and consistent with the CAA. The court noted three specific issues it
believed the Agency did not adequately address: (1) The EPA gave no
reason why organic HAP emissions could not be further reduced, once CO
emissions reach 130 ppm, (2) the EPA relied on formaldehyde data to
support its conclusion but elsewhere stated that the same data were not
a reliable indicator of organic HAP emissions at very low levels, and
(3) the EPA did not adequately explain if there is a non-zero CO level
below which organic HAP levels cannot be further reduced, why 130 ppm
is the appropriate level. Responses to these three issues are addressed
below.
[[Page 52212]]
In the January 31, 2013, final rule, we revised the CO emission
limit for several subcategories, both new and existing, to reflect a CO
level that, we stated, is consistent with MACT for organic HAP
reduction. The revision was brought about by several commenters who
recommended that the EPA evaluate a minimum CO standard (i.e., 100 ppm
corrected to 7-percent oxygen \10\) to serve as a lower bound surrogate
for organic HAP. The commenters also provided data and information to
support such a standard and noted that the EPA has taken a similar
approach in other emission standards under CAA section 112. See 40 CFR
part 63, subpart EEE (NESHAP for Hazardous Waste Combustors).
---------------------------------------------------------------------------
\10\ The CO emission standards in the 2013 final rule are
corrected to 3-percent oxygen. The 130 ppm CO standards in the 2013
final rule is equivalent to 100 ppm corrected to 7-percent oxygen.
---------------------------------------------------------------------------
In the preamble to the 2013 final rule, we stated that we evaluated
whether there is a minimum CO level for boilers and process heaters
below which there is no further benefit in organic HAP reduction/
destruction. Specifically, we evaluated the relationship between CO and
formaldehyde using the available data obtained during the rulemaking.
Formaldehyde was selected as the basis of the organic HAP comparison
because it is the most prevalent organic HAP in the emission database
and many paired tests existed for boilers and process heaters for CO
and formaldehyde and because formaldehyde was the only organic HAP for
which we had such data. The paired data show decreasing formaldehyde
emissions with decreasing CO emissions down to CO levels around 300 ppm
(with formaldehyde emissions down to less than 1 ppm), supporting the
selection of CO as a surrogate for organic HAP emissions. A slight
increase in formaldehyde emissions, to between 1 and 2 ppm, was
observed at CO levels below around 200 ppm, suggesting a breakdown in
the CO-formaldehyde relationship at low CO concentrations. At levels
lower than 150 ppm, the mean levels of formaldehyde appeared to
increase, as does the overall maximum value of and variability in
formaldehyde emissions. However, at that time, we were not aware of any
reason why formaldehyde concentrations would increase as CO
concentrations continue to decrease, indicating improved combustion
conditions. Our thinking at the time was that imprecise formaldehyde
measurements at low concentrations (i.e., 1-2 ppm) may have accounted
for this slight increase in formaldehyde emissions observed at CO
levels below 130 ppm.
In the preamble of the 2013 final rule, we stated, ``Based on this,
we do not believe that such measurements are sufficiently reliable to
use as a basis for establishing an emissions limit.'' See 78 FR 7145.
In that statement, we were referring to the formaldehyde measurements
and, thus, to the decision to set a CO standard instead of a
formaldehyde standard. Based on that analysis, we promulgated a minimum
MACT floor level for CO of 130 ppm corrected to 3-percent oxygen (which
is equivalent to 100 ppm corrected to 7-percent oxygen). We noted this
was the same approach used to establish the CO emission limit of 100
ppm corrected to 7-percent oxygen for the Burning of Hazardous Waste in
Boilers and Industrial Furnaces final rule (56 FR 7134, February 21,
1991). In that rulemaking, the EPA chose the 100-ppm (corrected to 7-
percent oxygen) limit because the research indicated that while CO was
a good surrogate for the destruction of organic HAP, the validity of
that surrogacy was questionable at CO levels of approximately 400 ppm
and below. Based on the EPA's authority under the Resource Conservation
and Recovery Act to establish standards that are protective of human
health and the environment, the Agency established the 100-ppm
standard. The EPA later established the 100-ppm corrected to 7-percent
oxygen standard as the MACT standard for hazardous waste combustors
(see 70 FR 59462) and explained why that standard was an appropriate
floor (see 69 FR at 21282).
The trend that our CO--formaldehyde data present has also been
observed in a study \11\ done on polycyclic aromatic hydrocarbons (PAH)
emissions from coal combustion. PAH constitute a group of organic HAP.
The study presents a graph of PAH vs. excess oxygen \12\ which shows
that at the lowest percentage of excess oxygen (5 percent), the highest
PAH amount (0.25 ppm) is measured and shows minimum PAH emissions (0.02
ppm) at 20-percent excess oxygen. The graph further shows that as the
excess oxygen level increases above 20 percent, higher PAH emissions
(about 0.06 ppm at 40 percent excess air) are observed. The study does
not present corresponding CO values. However, the study does provide
information showing that CO emissions continue to decrease with
increasing excess oxygen levels above 20 percent, as indicated by the
increased combustion efficiencies reported in the study for excess
oxygen over the range of 5 to 40 percent. Combustion efficiency (CE) is
a measure of the completeness of oxidation of all fuel (organic)
compounds and is determine by the CE Formula: CE = [CO2/
(CO2 + CO)] x 100.\13\ Thus, CE increases with decreasing CO
levels.
---------------------------------------------------------------------------
\11\ Organic Atmospheric Pollutants: Polycyclic Hydrocarbons
from Coal Atmospheric Fluidised Bed Combustion (AFBC), A.M Mastral,
M.S. Callen, R. Murillo, and T. Garcia, Instituto de Carboquimica,
1999.
\12\ Excess oxygen, or excess air, is commonly used to define
combustion. The excess oxygen is the amount of oxygen in the
incoming air not used during combustion. Inadequate excess oxygen
results in unburned combustibles (fuel and CO), while too much
excess oxygen results in increased flue gas flow and decreased
temperature and residence time for combustion.
\13\ CE formula and calculator, https://ncalculators.com/environmental/combustion-efficiency-calculator.htm.
---------------------------------------------------------------------------
The PAH study does provide a possible explanation for this
phenomenon. In order to assess the PAH emissions as a function of
combustion variables, the first aim of the study was to reach maximum
CE. The study stated that ``it can be assumed that the emissions due to
bad combustion have practically been eliminated, and so the data
obtained will be due to the combustion process.'' The study states that
at the lowest percentages of excess oxygen, the interaction between
oxygen and radicals should be less favored and, as a result, the PAH
amount would be higher. At the highest percentages of excess oxygen
possible, interaction with PAH seemed to be minimized due to the higher
gas velocities shortening the contact resulting in increasing PAH
emissions.
Furthermore, the EPA's Office of Research and Development (ORD), in
support of the NESHAP from Coal- and Oil-Fired Electric Utility Steam
Generating Units (also known as the Mercury and Air Toxics Standards or
MATS), conducted a series of tests in the Agency's Multipollutant
Control Research Facility (MPCRF). As part of these tests, potential
surrogate relationships were examined for various non-D/F organic HAP.
The objective of the testing program was to collect selected HAP
emission data while firing coals under varied test conditions and
evaluate relationships between those concentrations and other process
concentrations and/or conditions. One of the principal objectives was
to measure concentrations of non-D/F organic HAP and compare to the
emission of candidate surrogates (e.g., CO, total hydrocarbons, etc.)
\14\ Several organic HAP, discussed below and
[[Page 52213]]
presented as figures in the study's final report, were quantified from
multiple tests with CO concentrations and show a similar trend.
---------------------------------------------------------------------------
\14\ Surrogacy Testing in the MPCRF, Prepared for U.S. EPA,
Prepared by ARCADIS, March 30, 2011. See Docket ID Item No. EPA-HQ-
OAR-2002-0058-3942.
---------------------------------------------------------------------------
Figure 4-16 of the MPCRF study shows the concentration of phenol,
an organic HAP, plotted against concentration of CO. CO concentrations
ranged from 40 to 140 ppm, at 7-percent oxygen, with phenol
concentrations ranging from 0.6 parts per billion (ppb) at 40 ppm CO to
1 ppb at 140-ppm CO with the lowest phenol concentration (0.5 ppb)
measured at 95-ppm CO (120-ppm CO at 3-percent oxygen).
The MPCRF study also examined formaldehyde emissions against CO
concentrations. The five data points (Figure 4-17 of the study) are all
for CO concentrations below 70 ppm with the lowest formaldehyde
emissions (10 ppb) measured at 70-ppm CO and with higher formaldehyde
emissions (57 ppb) measured at a lower CO level of 40-ppm CO.
In addition, the MPCRF study shows similar results for chloroform
(another organic HAP). The five data points (Figure 4-24 of the study)
show chloroform emissions of 0.038 ppb at 170-ppm CO at 3-percent
oxygen, 0.025 ppb chloroform at 130-ppm CO at 3-percent oxygen, and
0.054 ppb chloroform at 40-ppm CO at 3-percent oxygen.
The MPCRF does not present any explanation on why these trends were
observed. One of the goals of the MPCRF testing was to determine or
demonstrate a relationship between concentrations of organic compounds
and combustion conditions. However, due to low emission levels, non-
detects, and other complexities, the key conclusion drawn was that the
testing did not disprove an expected relationship between organic
concentrations and combustion conditions.
There are myriad factors that affect CE and, as a function of CE,
CO emissions. As combustion conditions improve and hydrocarbon levels
decrease, the larger and easier to combust compounds are oxidized to
form smaller compounds that are, in turn, oxidized to form CO and
water. As combustion continues, CO is then oxidized to form
CO2 and water. Because CO is a difficult to destroy
refractory compound (i.e., oxidation of CO to CO2 is the
slowest and last step in the oxidation of hydrocarbons), it has been
considered a conservative surrogate for destruction of hydrocarbons,
including organic HAP.
Neither the PAH study nor the MPCRF study provide an explanation
for the phenomenon observed in these studies. In trying to explain why
this phenomenon occurs, we know that combustion is the chemical
reaction of oxygen with combustible compounds (e.g., organics) and that
time, temperature, and turbulence impact the speed and completeness of
the combustion reaction. For complete combustion, the oxygen must come
into intimate contact with the combustible molecule at sufficient
temperature, and for a sufficient length of time, in order to complete
the reaction. Two factors that affect reaction rates are the
concentration of the reactants (oxygen and organic HAP) and the
temperature of the reactants. Every combustible substance has a minimum
ignition temperature, which must be attained or exceeded, in the
presence of oxygen, if combustion is to ensue under the given
conditions. Lower concentrations will produce a decrease in the rate of
reaction and a decrease in the temperature will decrease rate of
reaction. As more ambient temperature combustion air (oxygen) is added,
the concentration and temperature of the reactant (organic HAP) is
reduced. Thus, a potential explanation is that with the increased
combustion air (oxygen), the resulting increased turbulence, while
providing increased mixing, can result in more organic molecules being
forced near the furnace walls, which are cold compared to the
combustion zone. This can essentially slow down or quench the
combustion reactions by cooling the molecules of the organic compounds
to below their minimum ignition temperature. Thus, those organic HAP
molecules would not be combusted and would be emitted unchanged. Any
action having the effect of decreasing the reaction rate of the organic
HAP will consequently result in less organic HAP being combusted and,
thus, higher organic HAP emissions being observed and appear to be an
increase, at higher excess oxygen (and lower CO emissions) levels.
The range of the formaldehyde measurements for the reported paired
formaldehyde-CO emissions data for the 97 emission units is 0.00009 ppm
(0.09 ppb) to 2.0 ppm. The mathematical average of the corresponding CO
emissions from the best performing 12 percent of units, identified as
those units with the lowest formaldehyde emissions, is 137 ppm.
At the time of the 2013 rulemaking, we observed that reducing CO
emissions also resulted in a reduction of organic HAP emissions until a
leveling off in organic HAP reduction is reached after which further
reduction of CO levels appeared to result in higher levels of organic
HAP emitted. Our determination that setting a CO standard below a CO
level of 130 ppm would result in no additional organic HAP reduction is
supported by both the independent PAH emission study and the MPCRF
study which both show similar trends. That is, organic HAP levels
decreased with decreasing CO levels until a leveling off and trending
upward with further decreasing CO levels. Also, based on the level of
the organic HAP emissions measured in the two studies, we do not
consider the formaldehyde data used in our establishment of the 130 ppm
CO standard to have been imprecise and, thus, unreliable. The
formaldehyde data measured at CO levels below 130 ppm reflect the
variability (scatter) of organic HAP emissions when each data point is
from a different unit. Whereas, the organic HAP emission results
presented in the two studies, which were measured at similar low
concentrations, are from tests conducted on a single unit at varying CO
levels.
The seven subcategories with the 130 ppm CO level in the 2013 final
rule are: (1) Pulverized Coal Boilers; (2) Coal Stokers; (3) Coal
Fluidized Bed; (4) Heavy Liquid Fuel; (5) Light Liquid Fuel; (6) Non-
Continental Liquid; and (7) Process Gas. Based on our review of the
data in 2013, we established that a CO emission level of 130 ppm
represented MACT for controlling organic HAP emissions for units in the
six subcategories. Based on additional information obtained during and
after the rulemaking, as discussed above, we reaffirm our conclusion
that a 130-ppm CO concentration threshold represents MACT for organic
HAP for the six subcategories.
IV. Results and Proposed Decisions
A. What are the resulting changes to emission limits?
Based on all of the revisions made to address the remand related to
ranking and assessing co-fired units in the MACT floor calculations,
the changes made for UPL calculations for small datasets, and the
decisions to propose certain limits as beyond-the-floor limits, there
are 34 different emission limits that we are proposing to change. The
detailed list of revisions to unit rankings and revised MACT floor
calculations are presented in the docketed memorandum, Revised MACT
Floor Analysis (2019) for the Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for Hazardous
Air Pollutants--Major Source. Of these 34 emission limits, 28 of the
limits are more stringent than the corresponding limits in the 2013
final rule. Six of the
[[Page 52214]]
limits are modestly less stringent, with no more than a 25-percent
increase. The proposed and corresponding current limits are shown in
Table 6.
Table 6--Summary of Changes to Emission Limits in the Proposed Action
----------------------------------------------------------------------------------------------------------------
Current emission Proposed emission
limit (lb/MMBtu of limit (lb/MMBtu of
Subcategory Pollutant heat input or ppm at heat input or ppm at
3-percent oxygen for 3-percent oxygen for
CO) CO)
----------------------------------------------------------------------------------------------------------------
New-Solid............................. HCl......................... 2.2E-02 3.0E-04
New-Dry Biomass Stoker................ TSM8........................ 4.0E-03 5.0E-03
New-Biomass Fluidized Bed............. CO.......................... 230 130
New-Biomass Fluidized Bed............. PM (TSM).................... 9.8E-03 (8.3E-05) 4.1E-03 (8.4E-06)
New-Biomass Suspension Burner......... CO.......................... 2,400 220
New-Biomass Suspension Burner......... TSM......................... 6.5E-03 8.0E-03
New-Biomass Hybrid Suspension Grate... CO.......................... 1,100 180
New-Biomass Dutch Oven/Pile Burner.... PM.......................... 3.2E-03 2.5E-03
New-Biomass Fuel Cell................. PM.......................... 2.0E-02 1.1E-02
New-Wet Biomass Stoker................ CO.......................... 620 590
New-Wet Biomass Stoker................ PM.......................... 0.03 0.013
New-Liquid............................ HCl......................... 4.4E-04 7.0E-05
New-Heavy Liquid...................... PM (TSM).................... 1.3E-02 (7.5E-05) 1.9E-03 (6.4E-06)
New-Process Gas....................... PM.......................... 6.7E-03 7.3E-03
Existing-Solid........................ HCl......................... 2.2E-02 2.0E-02
Existing-Solid........................ Hg.......................... 5.7E-06 5.4E-06
Existing-Coal......................... PM.......................... 4.0E-02 3.9E-02
Existing-Coal Stoker.................. CO.......................... 160 150
Existing-Dry Biomass Stoker........... TSM......................... 4.0E-03 5.0E-03
Existing-Wet Biomass Stoker........... CO.......................... 1,500 1,100
Existing-Wet Biomass Stoker........... PM (TSM).................... 3.7E-02 (2.4E-04) 3.4E-02 (2.0E-04)
Existing-Biomass Fluidized Bed........ CO.......................... 470 210
Existing-Biomass Fluidized Bed........ PM (TSM).................... 1.1E-01 (1.2E-03) 2.1E-02 (6.4E-05)
Existing-Biomass Suspension Burners... PM (TSM).................... 5.1E-02 (6.5E-03) 4.1E-02 (8.0E-03)
Existing-Biomass Dutch Oven/Pile PM.......................... 2.8E-01 1.8E-01
Burner.
Existing-Liquid....................... Hg.......................... 2.0E-06 7.3E-07
Existing-Heavy Liquid................. PM.......................... 6.2E-02 5.9E-02
Existing-Non-Continental Liquid....... PM.......................... 2.7E-01 2.2E-01
Existing-Process Gas.................. PM.......................... 6.7E-03 7.3E-03
----------------------------------------------------------------------------------------------------------------
The EPA requests comment on the revisions to the emission limits in
light of the changes the EPA has proposed in response to the remand.
Broader comments with respect to the UPL calculation methodology will
not be considered within the scope of this rulemaking. The EPA will
only consider data that is already available in the rulemaking record.
The EPA also requests comments on its determination of beyond-the-floor
emission limits for certain subcategories. The emission reduction
impacts associated with these changes to the MACT floor emission limits
are discussed in the docketed memorandum Revised (2019) Methodology for
Estimating Impacts for Industrial, Commercial, Institutional Boilers
and Process Heaters National Emission Standards for Hazardous Air
Pollutants.
B. What compliance dates are we proposing?
The EPA is proposing that facilities have up to 3 years after the
effective date of the final rule to comply with the new emissions
limits in the final rule. Before this date, facilities must continue to
comply with the rule as it was finalized in 2015. This allowance is
being made considering that some facilities may require additional add-
on controls or monitoring equipment to be designed, purchased, and
installed in order to meet the more stringent emission limits, or to
modify the method of compliance based on the changes in emission
limits. In addition, units will require lead time to prepare and
execute their testing plans to demonstrate compliance with the updated
emission limits and to update reports to incorporate the revised
emission limits. The EPA requests comment on this time frame.
C. What other actions are we proposing?
We are proposing several technical corrections. These amendments
are being proposed to correct inadvertent errors that were promulgated
in the final rule. We are soliciting comment only on whether the
proposed changes provide the intended accuracy, clarity, and
consistency. These proposed changes are described in Table 7 of this
preamble. We request comment on all these proposed changes.
[[Page 52215]]
Table 7--Miscellaneous Proposed Technical Corrections to 40 CFR Part 63,
Subpart DDDDD
------------------------------------------------------------------------
Section of subpart DDDDD Description of proposed correction
------------------------------------------------------------------------
40 CFR 63.7500(a)............ Revise this paragraph to remove the comma
after ``paragraphs (b).''
40 CFR 63.7521(c)(1)(ii) Revise this paragraph to remove the
requirement to collect samples during
the test period at 1-hour intervals.
40 CFR 63.7530(b)(4)(iii) Revise this paragraph to remove the
sentence regarding establishing the pH
operating limit because establishing the
pH operating limit is not required for a
PM wet scrubber.
40 CFR 63.7540(a)(9) Revise this paragraph to clarify that
``certify'' is intended to apply only to
PM CEMS, not PM continuous parameter
monitoring systems (CPMS) because PM
CPMS do not have a performance
specification.
40 CFR 63.7575............... Revise the definition of ``Other gas 1
fuel'' to clarify that it is the maximum
Hg concentration of 40 micrograms/cubic
meter of gas.
Add definition of ``12-month rolling
average'' to clarify that the previous
12 months must be consecutive but not
necessarily continuous.
Revise paragraph (4) of definition
``Steam output'' to correct ``heaters''
to ``headers.''
Table 1 to subpart DDDDD Revise the output limit in item 8.a to
correct for a rounding error, the value
is now 4.3E-01 lb per MMBtu instead of
4.2E-01 lb per MMBtu.
Table 7 to subpart DDDDD Revise footnote ``b'' to clarify that
when multiple performance tests are
conducted, the maximum operating load is
the lower of the maximum values
established during the performance
tests.
Table 8 to subpart DDDDD Revise item 8.d to clarify that the
correct equations to use are Equations
7, 8, and/or 9 in 40 CFR 63.7530.
------------------------------------------------------------------------
V. Summary of Cost, Environmental, and Economic Impacts
A. What are the affected sources?
As mentioned previously, this rule affects a wide range of
facilities in the ICI sector that are located at major sources of HAP
and have a boiler or process heater as defined in the final rule. The
2013 Emission Database for Boilers and Process Heaters estimated there
were approximately 14,000 existing boilers and process heaters
currently operating at 1,702 different facilities that are major
sources of HAP and subject to the Boiler MACT. The vast majority of
these combustion units (nearly 12,000 units) were gas-fired and in the
Gas 1 subcategory, which are subject to the rule but are not subject to
numeric emission limits. Another 472 units were small or limited use
and were also not subject to numeric emission limits. By contrast, the
EPA has reviewed compliance data submitted to CEDRI and WebFIRE and the
trade association Council of Industrial Boilers, which had provided
input on units that had shutdown or switched to natural gas fuel as
part of its compliance strategy. The EPA then compiled an updated
estimate of units that are subject to emission limits. These data show
533 existing boilers and process heaters, of which 443 remain
operational and belong in one of the subcategories that are subject to
numeric emission limits. This count excludes any boilers that are no
longer operational, boilers that have refueled and switched to the
natural gas subcategory and are, therefore, no longer impacted by
changes to emission limits, or boilers that are classified as small or
limited use.
For new sources, the EPA had projected new sources anticipated to
be built by 2015 from a baseline year of 2008.\15\ While the
projections had anticipated correctly that the only new units subject
to emission limits would be new large biomass units, the actual number
of new units is significantly lower than projected in the January 2013
final rule. The CEDRI and WebFIRE compliance data provided updates on
eight new biomass units that are subject to emission limits and
reporting compliance data. Since new units have had to comply since
April 2013, these eight units reflect a new unit rate of 1.3 new units
per year during the 6-year period of April 2013 through April 2019.
Using these new source data, the EPA estimates that, four more biomass
boilers or process heaters are expected to be constructed over the next
3 years. As such, 12 new boilers and process heaters are estimated to
be affected by the proposed amendments.
---------------------------------------------------------------------------
\15\ See docketed memorandum: Revised New Unit Analysis
Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--
Major Source. November 2011. Docket ID Item No. EPA-HQ-OAR-2002-
0058-3388.
---------------------------------------------------------------------------
Table 8 presents a summary table comparing the number of existing
and new affected sources, by subcategory. The counts exclude small or
limited use units.
Table 8--Summary of Changes to Number of Affected Sources
------------------------------------------------------------------------
Estimate of Estimate of
Subcategory sources in 2013 sources in 2019
final rule proposal
------------------------------------------------------------------------
Existing-Biomass................ 481............... 285.
Existing-Coal................... 606............... 124.
Existing-Heavy Liquid........... 291............... 6.
Existing-Light Liquid........... 260............... 24.
Existing-Non-Continental Liquid. 19................ 5.
Existing-Process Gas............ 78................ 0.
New-Biomass..................... 78 (projected 8 (actual) + 4
online by 2015). (projected).
New-Coal........................ 0................. 0.
New-Heavy Liquid................ 0................. 0.
New-Light Liquid................ 0................. 0.
New-Non-Continental Liquid...... 0................. 0.
New-Process Gas................. 0................. 0.
------------------------------------------------------------------------
[[Page 52216]]
B. What are the air quality impacts?
Table 9 of this preamble illustrates, for each basic fuel
subcategory, the incremental emissions reductions that would be
achieved by the proposed amendments. The reductions are all additional
to the reductions accounted for in the January 2013 final rule for both
new and existing sources. Nationwide emissions of selected HAP (i.e.,
HCl, hydrogen fluoride, Hg, metals) would be reduced by an additional
37.35 tpy as compared to the estimates in the January 2013 final rule.
This additional decrease is due mainly to changes to certain emission
limits that are anticipated to achieve additional reductions. The
proposed amendments are expected to result in an additional 34 tpy of
reductions in HCl emissions. The proposed amendments are also expected
to have a modest effect on Hg, with an estimated additional reduction
of 3.96 lbs per year. Emissions of filterable PM would decrease by 333
tpy, of which 251 tpy is PM2.5, due to the proposed
amendments. Emissions of non-Hg metals (i.e., antimony, arsenic,
beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and
selenium) would decrease by 2.3 tpy. In addition, the proposed
amendments are estimated to result in an additional 393 tpy of
reductions in SO2 emissions. A discussion of the methodology
used to estimate emissions, emissions reductions, and incremental
emission reductions is presented in the memorandum, Revised (2019)
Methodology for Estimating Impacts for Industrial, Commercial,
Institutional Boilers and Process Heaters National Emission Standards
for Hazardous Air Pollutants, which is available in the docket for this
action.
Table 9--Summary of Total Emissions Reductions for the Proposed Rule
[Tons/Yr]
----------------------------------------------------------------------------------------------------------------
Non-Hg metals
Source Subcategory HCl PM \1\ Hg
----------------------------------------------------------------------------------------------------------------
Exiting Units................. Coal............ 9.8 0 0 1.88E-03
Biomass......... 14.5 333 2.3 1.79E-04
New Units..................... Biomass......... 9.8 0 0 0
----------------------------------------------------------------------------------------------------------------
\1\ Antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
C. What are the cost impacts?
We estimated the total capital costs of the proposed amendments to
be about $83 million and the total annualized costs to be about $22
million in 2016 dollars. The total capital and annual costs include
costs for control devices, testing, and monitoring associated with the
changes to the emission limits. These costs are incremental to the
costs presented in the January 2013 final rule in the sense that they
show where units with compliance data must install add-on controls or
modify compliance strategies in order to meet the more stringent limits
in this proposal. Table 10 of this preamble shows the total capital and
annual cost impacts of the proposed rule for each subcategory. The cost
methodology and results are documented in the memorandum, Revised
(2019) Methodology for Estimating Impacts for Industrial, Commercial,
Institutional Boilers and Process Heaters National Emission Standards
for Hazardous Air Pollutants, which is available in the docket for this
action.
Table 10--Summary of Total Capital and Annual Costs for New and Existing Sources for the Proposed Rule
[2016$]
----------------------------------------------------------------------------------------------------------------
Testing and
Estimated/ monitoring Annualized
Source Subcategory projected Capital costs annualized cost (10\6\ $/
number of (10\6\ $) costs (10\6\ $/ yr)
affected units yr)
----------------------------------------------------------------------------------------------------------------
Existing Units Coal............ 2 0.803 0.006 0.327
Biomass......... 26 81.1 0.267 20.5
New Units..................... Solid units (all 5 0.952 0.017 0.653
biomass)
----------------------------------------------------------------------------------------------------------------
In addition, another way to present compliance costs is the PV. A
PV is an estimate of costs that is a discounted stream of the
annualized costs for the proposal calculated for the present day. The
PV in 2016 of the costs is $103.7 million at a discount rate of 7
percent and $128.1 million at 3 percent. Calculated as an EAV, which is
consistent with the PV of costs in 2016, the costs are $17.4 million at
a discount rate of 7 percent and $18.3 million at a discount rate of 3
percent. These estimates are also in 2016 dollars. More information on
the PV and EAV estimates can be found in the RIA for this proposal that
is in the docket for this action.
D. What are the secondary impacts?
The EPA estimated the additional water usage that would result from
installing wet scrubbers to meet the proposed amended emission limits
for HCl would be 0.64 million gallons per year for new and existing
sources compared to the current baseline. In addition to the increased
water usage, an additional 0.27 million gallons per year of wastewater
would be produced for new and existing sources. The annual costs of
treating the additional wastewater are approximately $1,830. These
additional costs are accounted for in the control cost estimates.
[[Page 52217]]
The EPA estimated the additional solid waste that would result due
to the proposed amendments to be 1,550 tpy for new and existing
sources. Solid waste is generated from flyash and dust captured in
fabric filters and electrostatic precipitators (ESP) installed for PM
and Hg controls as well as from spent materials from wet scrubbers and
sorbent injection systems installed for additional HCl controls. The
costs of handling the additional solid waste generated are $74,100.
These costs are also accounted for in the control costs estimates.
The EPA estimated the proposed amendments would result in an
increase of about 29.5 million kilowatts per year in national energy
usage from the electricity required to operate control devices, such as
wet scrubbers, ESPs, and fabric filters which are expected to be
installed to meet the proposed rule. This energy requirement is
estimated to result in an increase of approximately 17,740 tpy
CO2 based on emissions related to additional energy
consumption.
A discussion of the methodology used to estimate impacts is
presented in the Revised (2019) Methodology for Estimating Impacts for
Industrial, Commercial, Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants, which is
available in the docket for this action.
E. What are the economic impacts?
The EPA conducted an economic impact analysis for this proposal, as
detailed in the Regulatory Impact Analysis for the Proposed ICI Boilers
NESHAP Reconsideration, which is available in the docket for this
action. The economic impacts of the proposal are calculated as the
percentage of total annualized costs incurred by affected parent owners
to their annual revenues. This ratio of total annualized costs to
annual revenues provides a measure of the direct economic impact to
parent owners of affected facilities while presuming no passthrough of
costs to consumers of output produced by these facilities. We estimate
that none of the 26 parent owners affected by this proposal will incur
total annualized costs of 0.70 percent or greater of their revenues.
Thus, these economic impacts are quite low for the affected companies
and the multiple affected industries, and consumers of affected output
should experience minimal price changes.
F. What are the benefits?
The EPA reports the estimated impact on health benefits from
changes in PM2.5 and SO2 emissions. The estimated
health co-benefits are the monetized value of the human health benefits
among populations exposed to changes in PM2.5. These
benefits are co-benefits in this analysis since these pollutants are
not targeted for control by this proposal. This rule is expected to
alter the emissions of PM2.5 (and SO2). Due to
the small change in emissions expected, we used the ``benefit per ton''
(BPT) approach to estimate the benefits of this rulemaking. The EPA has
applied this approach in several previous RIAs \16\ in which the
economic value of human health impacts are derived at the national
level based on previously established source-receptor relationships
from photochemical air quality modeling.\17\ These BPT estimates
provide the total monetized human health benefits (the sum of premature
mortality and premature morbidity) of reducing 1 ton of
PM2.5 (or PM2.5 precursor such as nitrogen oxide
or SO2) from a specified source. Specifically, in this
analysis, we multiplied the estimates from the ``Industrial Point
Sources'' sector by the corresponding emission reductions. This assumes
that the emissions reductions from this proposed rule for industrial
boilers scale linearly with the BPT Industrial Point Sources sector.
The method used to derive these estimates is described in the Technical
Support Document on estimating the BPT of reducing PM2.5 and
its precursors from 17 sectors.\18\ One limitation of using the BPT
approach is an inability to provide estimates of the health benefits
associated with exposure to HAP (HCl, for example), CO, nitrogen
dioxide, or ozone. The photochemical modeled emissions of the
industrial point source sector-attributable PM2.5
concentrations used to derive the BPT values may not match the change
in air quality resulting from the emissions controls. The
PM2.5 emission reductions resulting from this rule are
approximately 0.4 percent of the PM2.5 annual emissions and
0.04 percent of the SO2 emissions attributable to the BPT
Industrial Point Sources. For this reason, the health co-benefits
reported in Table 11 may be larger, or smaller, than those realized
through this rule. We are taking comment on the modeling assumptions
behind the benefits analysis results mentioned above as well as the
utility of performing full-form (i.e., full-scale) photochemical
modeling for the final rule.
---------------------------------------------------------------------------
\16\ U.S. EPA. Regulatory Impact Analysis for the Federal
Implementation Plans to Reduce Interstate Transport of Fine
Particulate Matter and Ozone in 27 States; Correction of SIP
Approvals for 22 States. June 2011; Regulatory Impact Analysis for
the Final Mercury and Air Toxics Standards, December 2011; and
Regulatory Impact Analysis for the Particulate Matter National
Ambient Air Quality Standards; December 2012.
\17\ Fann N, Fulcher CM, Hubbell BJ. The influence of location,
source, and emission type in estimates of the human health benefits
of reducing a ton of air pollution. Air Qual Atmos Health.
2009;2(3):169-176. doi:10.1007/s11869-009-0044-0.
\18\ U.S. EPA, Technical Support Document. Estimating the
Benefit per Ton of Reducing PM2.5 Precursors from 17
Sectors. February 2018.
---------------------------------------------------------------------------
Table 11 summarizes the monetized PM-related health benefits per
ton or reducing precursor pollutant emissions, using discount rates of
3 percent and 7 percent.
Table 11--Estimated PM2.5-Related Benefits per Ton of Proposed ICI Boilers and Process Heaters MACT
Reconsideration
----------------------------------------------------------------------------------------------------------------
Epidemiologic study used to quantify PM-related premature deaths
-----------------------------------------------------------------------------------------------------------------
Krewski et al. (2009) Lepeule et al. (2012)
---------------------------------------------------------------------------
Pollutant BPT (3-percent BPT (7-percent BPT (3-percent BPT (7-percent
discount rate) discount rate) discount rate) discount rate)
----------------------------------------------------------------------------------------------------------------
PM2.5............................... $330,000 $300,000 $790,000 $690,000
SO2................................. 52,000 47,000 120,000 100,000
----------------------------------------------------------------------------------------------------------------
[[Page 52218]]
Table 12 summarizes the range of estimated benefits by pollutant
for the two BPT estimates at discount rates of 3 percent and 7 percent.
Table 12--Estimated PM2.5-Related Health Benefits of Proposed ICI Boilers and Process Heaters MACT
Reconsideration
----------------------------------------------------------------------------------------------------------------
Epidemiologic study used to quantify PM and SO2-related premature deaths
-----------------------------------------------------------------------------------------------------------------
Krewski et al. (2009) Lepeule et al. (2012)
---------------------------------------------------------------------------
Benefits Benefits Benefits Benefits
Pollutant (millions of (millions of (millions of (millions of
2016$, 3-percent 2016$, 7-percent 2016$, 3-percent 2016$, 7-percent
discount rate) discount rate) discount rate) discount rate)
----------------------------------------------------------------------------------------------------------------
PM2.5............................... $84 $76 $200 $170
SO2................................. 21 19 49 40
---------------------------------------------------------------------------
Total........................... 110 95 250 210
----------------------------------------------------------------------------------------------------------------
All BPT estimates have inherent limitations. Specifically, all
national-average BPT estimates reflect the geographic distribution of
the modeled emissions, which may not exactly match the emission
reductions in this rulemaking, and they may not reflect local
variability in population density, meteorology, exposure, baseline
health incidence rates, or other local factors for any specific
location. The photochemical modeled emissions of the industrial point
source sector-attributable PM2.5 concentrations used to
derive the BPT values may not match well the change in air quality
resulting from the emissions controls. For this reason, the health
benefits reported here may be larger, or smaller, than those realized
by this rule.
There are also climate disbenefits from the increase in
CO2 emissions that result from the increase in national
energy use from control device operation. The disbenefits are $0.09
million at a 3-percent discount rate and $0.01 million at a 7-percent
discount rate. These calculations reflect the domestic social cost of
carbon for CO2 for 2025, the year for which benefits are
estimated that is an approximation for 2023, the year of full rule
compliance. These disbenefits are included in the estimates of benefits
and net benefits for this proposal.
The benefit analysis for this proposal is detailed in the
Regulatory Impact Analysis for the Proposed ICI Boilers and Process
Heaters NESHAP Reconsideration, which is available in the docket for
this action.
VI. Request for Comments
The EPA is seeking comments on the issues raised in this proposal.
It will not respond to comments addressing any other issues.
Specifically, the EPA is seeking comments on the revised MACT floor
emission limit calculations, including any comments or corrections to
the underlying data used to compute those emission limits, the
selection of beyond-the-floor limits for certain subcategories. The EPA
is also seeking input on the inventory of units used to quantify the
impacts of these proposed amendments, which relied on real compliance
data submitted to CEDRI and WebFIRE through April 2019, and the
methodology used to quantify the impacts analysis discussed in section
V of this preamble. The EPA is also seeking comments on the accuracy of
the control technology assessment and/or whether there are other
compliance options available to meet the proposed revised emissions
limits. Finally, we request comment on the Agency's approach for using
a Benefit per-Ton value to quantify benefits as well as the utility of
performing full-form modeling for the final rule.
The current version of this regulation contains language which
details how facilities that seek to monitor CO2 in lieu of
oxygen as part of their CEMS used to demonstrate compliance with the CO
emission limits in this subpart must have this approach approved as an
alternative method before doing so. The EPA is seeking comment on
replacing the requirement to have approval of an alternative test
method with a required methodology to be followed when monitoring
CO2 in lieu of oxygen as the diluent for CO which would
account for any changes in CO2 emission levels caused by a
control device, etc. Additionally, the EPA believes it is appropriate
to expand this language to the monitoring of all pollutants when
CO2 is used as the diluent and seeks comment on this as
well. Finally, in the course of reviewing the monitoring language under
40 CFR part 63, subpart DDDDD, the EPA is proposing to remove several
requirements for the continuous monitoring of moisture and flow which
were found to be unnecessary. We also seek comment on these revisions.
A draft of the language we would propose to accomplish these revisions
is included in the docket.
VII. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is an economically significant regulatory action that
was submitted to OMB for review. Any changes made in response to OMB
recommendations have been documented in the docket. The RIA for the ICI
Boilers NESHAP Reconsideration contains the estimated costs, benefits,
and other impacts associated with this action, and it is available in
the docket.
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
This action is expected to be an Executive Order 13771 regulatory
action. Details on the estimated costs of this proposed rule can be
found in the EPA's analysis of the potential costs and benefits
associated with this action, which is the RIA for this proposal.
C. Paperwork Reduction Act (PRA)
The new information collection activities imposed by this proposed
rule have been submitted for approval to OMB under the PRA. The
Information Collection Request (ICR) document that the EPA prepared has
been assigned EPA ICR number 2028.10. You can find a copy of the ICR in
the docket for this rule, and it is briefly summarized here.
[[Page 52219]]
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.
The proposed amendments change several emission limits as part of
the EPA's response to the remand granted on December 23, 2016, by the
D.C. Circuit. The changes result in more stringent emission limits in
some cases, which is expected to require additional recordkeeping and
reporting burden. This increase is a result of additional monitoring
and control devices anticipated to be installed to comply with the more
stringent emission limits in the proposed amendments. With additional
control devices, comes additional control device parametric monitoring,
or in the case of CO, continuous emissions monitoring, and the
associated records of that monitoring that must be maintained on-site
and reported. Over the next 3 years, approximately 25 respondents
operating existing large solid fuel-fired boilers and three respondents
operating new solid fuel-fired boilers will be impacted by the new
requirements under the standard as a result of these amendments. In
addition to the costs to install and maintain records of additional
monitoring equipment, the ICR details other additional record keeping
and reporting burden changing records associated with adjusting
operating parameter limit values, modifying monitoring plans, and
familiarizing themselves with the changes in the proposed amendments.
Respondents/affected entities: Owners or operators of ICI boilers
and process heaters.
Respondent's obligation to respond: Mandatory, 40 CFR part 63.
Estimated number of respondents: 28.
Frequency of response: Semi-annual, annual, periodic.
Total estimated burden: 1,080 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $307,000 (per year), includes $180,000
annualized capital or operation and maintenance costs.
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.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates, and any suggested methods
for minimizing respondent burden to the EPA using the docket identified
at the beginning of this rule. The EPA will respond to any ICR-related
comments in the final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. This
action will not impose any requirements on small entities. Of the 26
entities determined to be impacted by this action, only one is a small
entity. This small entity is expected to not incur any costs associated
with this action. More information on these small entity impacts is
available in the RIA for this proposal.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain any unfunded mandate as described in
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect
small governments. The action imposes no enforceable duty on any state,
local, or tribal governments or the private sector.
F. 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. The action
affects private industry and does not impose economic costs on State or
local governments.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. 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.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risk.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution or use of energy. The energy impacts estimated for this
proposed rule increased only slightly the energy impacts estimated for
the March 21, 2011, final rule which was concluded not to be a
significant regulatory action under Executive Order 13211. Therefore,
we conclude that this proposed rule, when implemented, is not likely to
have a significant adverse effect on the supply, distribution, or use
of energy.
J. National Technology Transfer and Advancement Act (NTTAA)
This rulemaking does not involve technical standards.
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specified in Executive Order 12898 (59 FR 7629, February 16, 1994).
The documentation for this decision is contained in the preamble to
the March 2011 final rule (see 76 FR 15662). For the March 2011 final
rule, the EPA determined that the 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
[[Page 52220]]
minority or low-income population. Compared to the final rule, the
proposed amendments are somewhat more stringent for some subcategories
and, thus, the overall increased health benefits demonstrate that the
conclusion from the environmental justice analysis conducted for the
final rule are still valid.
List of Subjects in 40 CFR Part 63
Environmental protection, Air pollution control, Hazardous
substances, Reporting and recordkeeping requirements.
Andrew Wheeler,
Administrator.
For the reasons stated in the preamble, 40 CFR part 63 is proposed
to be amended as follows:
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
1. The authority citation for part 63 continuous to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart DDDDD--National Emission Standards For Hazardous Air
Pollutants For Major Sources: Industrial, Commercial, And
Institutional Boilers And Process Heaters
0
2. Section 63.7500 is amended by revising paragraph (a) introductory
text and paragraphs (a)(1), (c), and (e) to read as follows:
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) through (e) of
this section. You must meet these requirements at all times the
affected unit is operating, except as provided in paragraph (f) of this
section.
(1) You must meet each emission limit and work practice standard in
Tables 1 through 3, and 11 through 15 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, 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 and process heaters that generate either steam, cogenerate
steam with electricity, or both. The output-based emission limits, in
units of pounds per megawatt-hour, in Tables 1 or 2 to this subpart are
an alternative applicable only to boilers that generate only
electricity. Boilers that perform multiple functions (cogeneration and
electricity generation) or supply steam to common headers would
calculate a total steam energy output using equation 21 of Sec.
63.7575 to demonstrate compliance with the output-based emission
limits, in units of pounds per million Btu of steam output, in Tables 1
or 2 to this subpart. If you operate a new boiler or process heater,
you can choose to comply with alternative limits as discussed in
paragraphs (a)(1)(i) through (a)(1)(iv) of this section, but on or
after [DATE 3 YEARS AFTER DATE OF PUBLICATION OF FINAL RULE IN THE
Federal Register], you must comply with the emission limits in Table 1
to this subpart. If you operate an existing boiler or process heater,
you can choose to comply with alternative limits as discussed in
paragraphs (a)(1)(v) of this section, but on or after [DATE 3 YEARS
AFTER DATE OF PUBLICATION OF FINAL RULE IN THE Federal Register] you
must comply with the emission limits in Table 2 to this subpart.
(i) If your boiler or process heater commenced construction or
reconstruction after June 4, 2010, and before May 20, 2011, you may
comply with the emission limits in Table 11 or 14 to this subpart until
January 31, 2016.
(ii) If your boiler or process heater commenced construction or
reconstruction on or after May 20, 2011, and before December 23, 2011,
you may comply with the emission limits in Table 12 or 14 to this
subpart until January 31, 2016.
(iii) If your boiler or process heater commenced construction or
reconstruction on or after December 23, 2011, and before April 1, 2013,
you may comply with the emission limits in Table 13 or 14 to this
subpart until January 31, 2016.
(iv) If you operate a new boiler or process heater, you may comply
with the emission limits in Table 1 or 14 until you must comply with
the emission limits in Table 1 to this subpart.
(v) If you operate an existing boiler or process heater, you may
comply with the emission limits in Table 2 or 15 until you must comply
with the emission limits in Table 2 to this subpart.
* * * * *
(c) Limited-use boilers and process heaters must complete a tune-up
every 5 years as specified in Sec. 63.7540. They are not subject to
the emission limits in Tables 1 and 2 or 11 through 15 to this subpart,
the annual tune-up, or the energy assessment requirements in Table 3 to
this subpart, or the operating limits in Table 4 to this subpart.
* * * * *
(e) Boilers and process heaters in the units designed to burn gas 1
fuels subcategory with a heat input capacity of less than or equal to 5
million Btu per hour must complete a tune-up every 5 years as specified
in Sec. 63.7540. Boilers and process heaters in the units designed to
burn gas 1 fuels subcategory with a heat input capacity greater than 5
million Btu per hour and less than 10 million Btu per hour must
complete a tune-up every 2 years as specified in Sec. 63.7540. Boilers
and process heaters in the units designed to burn gas 1 fuels
subcategory are not subject to the emission limits in Tables 1 and 2 or
11 through 15 to this subpart, or the operating limits in Table 4 to
this subpart.
* * * * *
0
3. Section 63.7505 is amended by revising paragraph (c) to read as
follows:
Sec. 63.7505 What are my general requirements for complying with this
subpart?
* * * * *
(c) You must demonstrate compliance with all applicable emission
limits using performance stack testing, fuel analysis, or continuous
monitoring systems (CMS), including a continuous emission monitoring
system (CEMS), continuous opacity monitoring system (COMS), continuous
parameter 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 (HCl), mercury, or total selected metals (TSM) 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 TSM alternative standard or
the HCl standard. Otherwise, you must demonstrate compliance for HCl,
mercury, or TSM using performance stack testing, if subject to an
applicable emission limit listed in Tables 1, 2, or 11 through 15 to
this subpart.
* * * * *
0
4. Section 63.7510 is amended by revising paragraph (a) introductory
text and paragraphs (b), (c), (f), and (j) to read as follows:
[[Page 52221]]
Sec. 63.7510 What are my initial compliance requirements and by what
date must I conduct them?
(a) For each boiler or process heater that is required or that you
elect to demonstrate compliance with any of the applicable emission
limits in Tables 1 or 2 or 11 through 15 of this subpart through
performance (stack) testing, your initial compliance requirements
include all the following:
* * * * *
(b) For each boiler or process heater that you elect to demonstrate
compliance with the applicable emission limits in Tables 1 or 2 or 11
through 15 to this subpart for HCl, mercury, or TSM 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) and (ii) of this
section are exempt from these fuel analysis and operating limit
requirements. The fuels described in paragraph (a)(2)(ii) of this
section are exempt from the chloride fuel analysis and operating limit
requirements. Boilers and process heaters that use a CEMS for mercury
or HCl are exempt from the performance testing and operating limit
requirements specified in paragraph (a) of this section for the HAP for
which CEMS are used.
(c) If your boiler or process heater is subject to a carbon
monoxide (CO) limit, your initial compliance demonstration for CO is to
conduct a performance test for CO according to Table 5 to this subpart
or conduct a performance evaluation of your continuous CO monitor, if
applicable, according to Sec. 63.7525(a). Boilers and process heaters
that use a CO CEMS to comply with the applicable alternative CO CEMS
emission standard listed in Tables 1, 2, or 11 through 15 to this
subpart, as specified in Sec. 63.7525(a), are exempt from the initial
CO performance testing and oxygen concentration operating limit
requirements specified in paragraph (a) of this section.
* * * * *
(f) For new or reconstructed affected sources (as defined in Sec.
63.7490), you must complete the initial compliance demonstration with
the emission limits no later than July 30, 2013, or within 180 days
after startup of the source, whichever is later.
(1) If you are demonstrating compliance with an emission limit in
Tables 11 through 13 to this subpart that is less stringent (that is,
higher) than the applicable emission limit in Table 14 to this subpart,
you must demonstrate compliance with the applicable emission limit in
Table 14 no later than July 29, 2016.
(2) If you are demonstrating compliance with an emission limit in
Table 14 to this subpart that is less stringent (that is, higher) than
the applicable emission limit in Table 1 to this subpart, you must
demonstrate compliance with the applicable emission limit in Table 1 to
this subpart no later than [date 3 years after date of publication of
final rule in the Federal Register].
* * * * *
(j) For existing affected sources (as defined in Sec. 63.7490)
that have not operated between the effective date of the rule and the
compliance date that is specified for your source in Sec. 63.7495, you
must complete the initial compliance demonstration, if subject to the
emission limits in Tables 2 or 14, to this subpart, as applicable, as
specified in paragraphs (a) through (d) of this section, no later than
180 days after the re-start of the affected source 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) no later
than 30 days after the re-start of the affected source and, if
applicable, complete the one-time energy assessment specified in Table
3 to this subpart, no later than the compliance date specified in Sec.
63.7495.
* * * * *
0
5. Section 63.7515 is amended by revising paragraphs (b), (c), (e),
(g), and (i) to read as follows:
Sec. 63.7515 When must I conduct subsequent performance tests, fuel
analyses, or tune-ups?
* * * * *
(b) If your performance tests for a given 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 or 11 through 15 to this subpart, at or below the emission
limit) for the pollutant, and if there are no changes in the operation
of the individual boiler or process heater or air pollution control
equipment that could increase emissions, you may choose to conduct
performance tests for the pollutant every third year. Each such
performance test must be conducted no more than 37 months after the
previous performance test. If you elect to demonstrate compliance using
emission averaging under Sec. 63.7522, you must continue to conduct
performance tests annually. The requirement to test at maximum chloride
input level is waived unless the stack test is conducted for HCl. The
requirement to test at maximum mercury input level is waived unless the
stack test is conducted for mercury. The requirement to test at maximum
TSM input level is waived unless the stack test is conducted for TSM.
(c) If a performance test shows emissions exceeded the emission
limit or 75 percent of the emission limit (as specified in Tables 1 and
2 or 11 through 15 to this subpart) 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 (at or below
75 percent of the emission limit, as specified in Tables 1 and 2 or 11
through 15 to this subpart).
* * * * *
(e) If you demonstrate compliance with the mercury, HCl, or TSM
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 Tables 1, 2, or 11 through 15 to this subpart.
You may comply with this monthly requirement by completing the fuel
analysis any time within the calendar month as long as the analysis is
separated from the previous analysis by at least 14 calendar days. 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 each of 12 consecutive monthly fuel analyses demonstrates
75 percent or less of the compliance level, you may decrease the fuel
analysis frequency to quarterly for that fuel. If any quarterly sample
exceeds 75 percent of the compliance level or you begin burning a new
type of fuel, you must return to monthly monitoring for that fuel,
until 12 months of fuel analyses are again less than 75 percent of the
compliance level. If sampling is conducted on 1 day per month, samples
should be no less than 14 days apart, but if multiple samples are taken
per month, the 14-day restriction does not apply.
* * * * *
(g) For affected sources (as defined in Sec. 63.7490) that have
not operated since the previous compliance demonstration and more than
1 year has passed since the previous compliance demonstration, you must
complete the subsequent compliance demonstration, if subject to the
emission limits in Tables 1, 2, or 11 through 15 to this subpart, no
later than
[[Page 52222]]
180 days after the re-start of the affected source and according to the
applicable provisions in Sec. 63.7(a)(2) as cited in Table 10 to this
subpart. You must complete a subsequent tune-up by following the
procedures described in Sec. 63.7540(a)(10)(i) through (vi) and the
schedule described in Sec. 63.7540(a)(13) for units that are not
operating at the time of their scheduled tune-up.
* * * * *
(i) If you operate a CO CEMS that meets the Performance
Specifications outlined in Sec. 63.7525(a)(3) of this subpart to
demonstrate compliance with the applicable alternative CO CEMS emission
standard listed in Tables 1, 2, or 11 through 15 to this subpart, you
are not required to conduct CO performance tests and are not subject to
the oxygen concentration operating limit requirement specified in Sec.
63.7510(a).
0
6. Section 63.7520 is amended by revising paragraph (d) to read as
follows:
Sec. 63.7520 What stack tests and procedures must I use?
* * * * *
(d) You must conduct a minimum of 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 or 11 through 15
to this subpart.
* * * * *
0
7. Section 63.7521 is amended by revising paragraphs (a) and (c)(1)(ii)
to read as follows:
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 and liquid fuels, you must also conduct fuel analyses
for TSM if you are opting to comply with the TSM alternative standard.
For gas 2 (other) fuels, you must conduct fuel analyses 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 TSM alternative
standard or the HCl 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, HCl, or TSM in
Tables 1 and 2 or 11 through 15 to this subpart. Gaseous and liquid
fuels are exempt from the sampling requirements in paragraphs (c) and
(d) of this section.
* * * * *
(c) * * *
(1) * * *
(ii) Each composite sample will consist of a minimum of three
samples collected at approximately equal intervals during the testing
period for sampling during performance stack testing.
* * * * *
0
8. Section 63.7522 is amended by revising paragraph (b) introductory
text and paragraphs (d), (e)(1), (2), (h), and (j)(1) to read as
follows:
Sec. 63.7522 Can I use emissions averaging to comply with this
subpart?
* * * * *
(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 PM (or TSM), HCl, or mercury emissions among existing units to
demonstrate compliance with the limits in Table 2 or 15 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.
* * * * *
(d) The averaged emissions rate from the existing boilers and
process heaters participating in the emissions averaging option must
not exceed 90 percent of the limits in Table 2 or 15 to this subpart at
all times the affected units are subject to numeric emission limits
following the compliance date specified in Sec. 63.7495.
(e) * * *
(1) You must use Equation 1a or 1b or 1c of this section to
demonstrate that the PM (or TSM), HCl, 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 or 15 to this
subpart. Use Equation 1a if you are complying with the emission limits
on a heat input basis, use Equation 1b if you are complying with the
emission limits on a steam generation (output) basis, and use Equation
1c if you are complying with the emission limits on a electric
generation (output) basis.
[GRAPHIC] [TIFF OMITTED] TP24AU20.000
Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM),
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as determined during the initial compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM 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] TP24AU20.001
Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM),
HCl, or mercury, in units of pounds per million Btu of steam output.
Er = Emission rate (as determined during the initial compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of steam output. Determine the
emission rate for PM (or TSM), HCl, or mercury by
[[Page 52223]]
performance testing according to Table 5 to this subpart, or by fuel
analysis for HCl or mercury or TSM 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.
[GRAPHIC] [TIFF OMITTED] TP24AU20.002
Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM),
HCl, or mercury, in units of pounds per megawatt hour.
Er = Emission rate (as determined during the initial compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per megawatt hour. Determine the emission rate for
PM (or TSM), HCl, or mercury by performance testing according to
Table 5 to this subpart, or by fuel analysis for HCl or mercury or
TSM 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.
Eo = Maximum electric generating output capacity of unit, i, in
units of megawatt 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 PM (or TSM), HCl, 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 or 15 to this subpart that are in pounds per million Btu of
heat input.
[GRAPHIC] [TIFF OMITTED] TP24AU20.003
Where:
AveWeightedEmissions = Average weighted emission level for PM (or
TSM), HCl, or mercury, in units of pounds per million Btu of heat
input.
Er = Emission rate (as determined during the most recent compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM 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.
* * * * *
(h) For a group of two or more existing affected units, each of
which vents through a single common stack, you may average PM (or TSM),
HCl, or mercury emissions to demonstrate compliance with the limits for
that pollutant in Table 2 or 15 to this subpart if you satisfy the
requirements in paragraph (i) or (j) of this section.
* * * * *
(j) * * *
(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] TP24AU20.004
Where:
En = HAP emission limit, pounds per million British thermal units
(lb/MMBtu) or parts per million (ppm).
ELi = Appropriate emission limit from Table 2 or 15 to this subpart
for unit i, in units of lb/MMBtu or ppm.
Hi = Heat input from unit i, MMBtu.
* * * * *
0
9. Section 63.7525 is amended by revising paragraphs (a), (2), (2)(iv),
(l), and (m) introductory text to read as follows:
Sec. 63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If your boiler or process heater is subject to a CO emission
limit in Tables 1, 2, or 11 through 15 to this subpart, you must
install, operate, and maintain an oxygen analyzer system, as defined in
Sec. 63.7575, or install, certify, operate and maintain continuous
emission monitoring systems for CO and oxygen (or carbon dioxide
(CO2)) according to the procedures in paragraphs (a)(1)
through (6) of this section.
* * * * *
(2) To demonstrate compliance with the applicable alternative CO
CEMS emission standard listed in Tables 1, 2, or 11 through 15 to this
subpart, you must install, certify, operate, and maintain a CO CEMS and
an oxygen analyzer according to the applicable procedures under
Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B;
part 75 of this chapter (if an CO2 analyzer is used); the
site-specific monitoring plan developed according to Sec. 63.7505(d);
and the requirements in Sec. 63.7540(a)(8) and paragraph (a) of this
section. Any boiler or process heater that has a CO CEMS that is
compliant with Performance Specification 4, 4A, or 4B at 40 CFR part
60, appendix B, a site-specific monitoring plan developed according to
Sec. 63.7505(d), and the requirements in Sec. 63.7540(a)(8) and
paragraph (a) of this section must use the CO CEMS to comply with the
applicable alternative CO CEMS emission standard listed in Tables 1, 2,
or 11 through 15 to this subpart.
* * * * *
(iv) Any CO CEMS that does not comply with Sec. 63.7525(a) cannot
be used to meet any requirement in this subpart to demonstrate
compliance with a CO emission limit listed in Tables 1, 2, or 11
through 15 to this subpart.
* * * * *
(l) For each unit for which you decide to demonstrate compliance
with the mercury or HCl emissions limits in Tables 1 or 2 or 11 through
15 of this subpart by use of a CEMS for mercury or HCl, you must
install, certify, maintain, and operate a CEMS measuring emissions
discharged to the
[[Page 52224]]
atmosphere and record the output of the system as specified in
paragraphs (l)(1) through (8) of this section. For HCl, this option for
an affected unit takes effect on the date a final performance
specification for a HCl CEMS is published in the Federal Register or
the date of approval of a site-specific monitoring plan.
(m) If your unit is subject to a HCl emission limit in Tables 1, 2,
or 11 through 15 of this subpart and you have an acid gas wet scrubber
or dry sorbent injection control technology and you elect to use an
SO2 CEMS to demonstrate continuous compliance with the HCl
emission limit, you must install the monitor at the outlet of the
boiler or process heater, downstream of all emission control devices,
and you must install, certify, operate, and maintain the CEMS according
to either part 60 or part 75 of this chapter.
* * * * *
0
10. Section 63.7530 is amended by revising paragraphs (b)(4)(ii)(E) and
(iii) and the introductory text of paragraph (h) to read as follows:
Sec. 63.7530 How do I demonstrate initial compliance with the
emission limitations, fuel specifications and work practice standards?
* * * * *
(b) * * *
(4) * * *
(ii) * * *
(E) Use EPA Method 5 of appendix A to part 60 of this chapter to
determine PM emissions. For each performance test, conduct three
separate runs under the conditions that exist when the affected source
is operating at the highest load or capacity level reasonably expected
to occur. Conduct each test run to collect a minimum sample volume
specified in Tables 1, 2, or 11 through 15 to this subpart, as
applicable, for determining compliance with a new source limit or an
existing source limit. Calculate the average of the results from three
runs to determine compliance. You need not determine the PM collected
in the impingers (``back half'') of the Method 5 particulate sampling
train to demonstrate compliance with the PM standards of this subpart.
This shall not preclude the permitting authority from requiring a
determination of the ``back half'' for other purposes.
* * * * *
(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 PM and
TSM emissions, you must establish one set of minimum scrubber liquid
flow rate and pressure drop operating limits. 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.
* * * * *
(h) If you own or operate a unit subject to emission limits in
Tables 1 or 2 or 11 through 15 to this subpart, you must meet the work
practice standard according to Table 3 of this subpart. During startup
and shutdown, you must only follow the work practice standards
according to items 5 and 6 of Table 3 of this subpart.
* * * * *
0
11. Section 63.7533 is amended by revising paragraphs (a), (e), and (f)
to read as follows:
Sec. 63.7533 Can I use efficiency credits earned from implementation
of energy conservation measures to comply with this subpart?
(a) If you elect to comply with the alternative equivalent output-
based emission limits, instead of the heat input-based limits listed in
Table 2 or 15 to this subpart, and you want to take credit for
implementing energy conservation measures identified in an energy
assessment, you may demonstrate compliance using efficiency 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 efficiency credits, develop an
Implementation Plan, comply with the general reporting requirements,
and apply the efficiency 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.
Additional guidance from the Department of Energy on efficiency credits
is available at: http://www.epa.gov/ttn/atw/boiler/boilerpg.html.
* * * * *
(e) The emissions rate as calculated using Equation 20 of this
section from each existing boiler participating in the efficiency
credit option must be in compliance with the limits in Table 2 or 15 to
this subpart at all times the affected unit is subject to numeric
emission limits, following the compliance date specified in Sec.
63.7495.
(f) You must use Equation 20 of this section to demonstrate initial
compliance by demonstrating that the emissions from the affected boiler
participating in the efficiency credit compliance approach do not
exceed the emission limits in Table 2 or 15 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP24AU20.005
Where:
Eadj = Emission level adjusted by applying the efficiency
credits earned, lb per million Btu steam output (or lb per MWh) for
the affected boiler.
Em = Emissions measured during the performance test, lb
per million Btu steam output (or lb per MWh) for the affected
boiler.
ECredits = Efficiency credits from Equation 19 for the affected
boiler.
* * * * *
0
12. Section 63.7540 is amended by:
0
a. Revising paragraphs (a), (8), and (19) introductory text; and
0
b. Revising paragraphs (a)(8)(ii), (9), and (b).
The revisions read as follows:
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 or 11 through 15 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 (19)
of this section.
* * * * *
(8) To demonstrate compliance with the applicable alternative CO
CEMS emission limit listed in Tables 1, 2, or 11 through 15 to this
subpart, you must meet the requirements in paragraphs (a)(8)(i) through
(iv) of this section.
* * * * *
(ii) Maintain a CO emission level below or at your applicable
alternative CO CEMS-based standard in Tables 1 or 2 or 11 through 15 to
this subpart at all times the affected unit is subject to numeric
emission limits.
* * * * *
(9) The owner or operator of a boiler or process heater using a PM
CPMS or a PM CEMS to meet requirements of this subpart shall install,
certify (PM CEMS only), operate, and maintain the PM CPMS or PM CEMS in
accordance with
[[Page 52225]]
your site-specific monitoring plan as required in Sec. 63.7505(d).
* * * * *
(19) If you choose to comply with the PM filterable emissions limit
by using PM CEMS you must install, certify, operate, and maintain a PM
CEMS and record the output of the PM CEMS as specified in paragraphs
(a)(19)(i) through (vii) of this section. The compliance limit will be
expressed as a 30-day rolling average of the numerical emissions limit
value applicable for your unit in Tables 1 or 2 or 11 through 15 of
this subpart.
* * * * *
(b) You must report each instance in which you did not meet each
emission limit and operating limit in Tables 1 through 4 or 11 through
15 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.
* * * * *
0
13. Section 63.7545 is amended by revising paragraph (e)(3) to read as
follows:
Sec. 63.7545 What notifications must I submit and when?
* * * * *
(e) * * *
(3) A summary of the maximum CO emission levels recorded during the
performance test to show that you have met any applicable emission
standard in Tables 1, 2, or 11 through 15 to this subpart, if you are
not using a CO CEMS to demonstrate compliance.
* * * * *
0
14. Section 63.7555 is amended by revising paragraph (d) introductory
text and paragraph (5) to read as follows:
Sec. 63.7555 What records must I keep?
* * * * *
(d) For each boiler or process heater subject to an emission limit
in Tables 1, 2, or 11 through 15 to this subpart, you must also keep
the applicable records in paragraphs (d)(1) through (11) of this
section.
* * * * *
(5) If, consistent with Sec. 63.7515(b), you choose to stack test
less frequently than annually, you must keep a record that documents
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 or 11 through 15 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.
* * * * *
0
15. Section 63.7575 is amended by:
0
a. Adding, in alphabetical order, a definition for ``12-month rolling
average'';
0
b. Revising the definition of ``Other gas 1 fuel''; and
0
c. Revising paragraphs (3) and (4) under the definition of ``Steam
output.''
The additions and revisions read as follows:
Sec. 63.7575 What definitions apply to this subpart?
* * * * *
12-month rolling average means the arithmetic mean of the previous
12 months of valid fuel analysis data. The 12 months should be
consecutive, but not necessarily continuous if operations were
intermittent.
* * * * *
Other gas 1 fuel means a gaseous fuel that is not natural gas or
refinery gas and does not exceed a maximum mercury concentration of 40
micrograms/cubic meters of gas.
* * * * *
Steam output * * *
* * * * *
(3) For a boiler that generates only electricity, the alternate
output-based emission limits would be the appropriate emission limit
from Table 1 or 2 or 14 or 15 of this subpart in units of pounds per
million Btu heat input (lb per MWh).
(4) For a boiler that performs multiple functions and produces
steam to be used for any combination of paragraphs (1), (2) and (3) of
this definition that includes electricity generation of paragraph (3)
of this definition, the total energy output, in terms of MMBtu of steam
output, is the sum of the energy content of steam sent directly to the
process and/or used for heating (S1), the energy content of
turbine steam sent to process plus energy in electricity according to
paragraph (2) of this definition (S2), and the energy
content of electricity generated by a electricity only turbine as
paragraph (3) of this definition (MW3) and would be
calculated using Equation 21 of this section. In the case of boilers
supplying steam to one or more common headers, S1,
S2, and MW(3) for each boiler would be calculated
based on the its (steam energy) contribution (fraction of total steam
energy) to the common header.
[GRAPHIC] [TIFF OMITTED] TP24AU20.006
Where:
SOM = Total steam output for multi-function boiler, MMBtu
S1 = Energy content of steam sent directly to the process
and/or used for heating, MMBtu
S2 = Energy content of turbine steam sent to the process
plus energy in electricity according to (2) above, MMBtu
MW(3) = Electricity generated according to paragraph (3)
of this definition, MWh
CFn = Conversion factor for the appropriate subcategory for
converting electricity generated according to paragraph (3) of this
definition to equivalent steam energy, MMBtu/MWh
CFn for emission limits for boilers in the unit designed to burn
solid fuel subcategory = 10.8
CFn PM and CO emission limits for boilers in one of the
subcategories of units designed to burn coal = 11.7
CFn PM and CO emission limits for boilers in one of the
subcategories of units designed to burn biomass = 12.1
CFn for emission limits for boilers in one of the subcategories of
units designed to burn liquid fuel = 11.2
CFn for emission limits for boilers in the unit designed to burn gas
2 (other) subcategory = 6.2
* * * * *
0
16. Table 1 to subpart DDDDD is amended to read as follows:
[[Page 52226]]
Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters
As stated in Sec. 63.7500, you must comply with the following applicable emission limits: [Units with heat
input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
Or the emissions
The emissions must must not exceed
not exceed the the following Using this
If your boiler or process heater For the following following emission alternative output- specified sampling
is in this subcategory . . . pollutants . . . limits, except based limits, volume or test run
during startup and except during duration . . .
shutdown . . . startup and
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............ 3.0E-04 lb per 4.1E-04 lb per For M26A, collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 3.9E-03 dscm per run; for
lb per MWh. M26 collect a
minimum of 120
liters per run.
b. Mercury........ 8.0E-07 \a\ lb per 8.7E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 1.1E-05 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.
2. Units designed to burn coal/ a. Filterable PM 1.1E-03 lb per 1.1E-03 lb per Collect a minimum
solid fossil fuel. (or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.3E- output or 1.4E-02 run.
05 lb per MMBtu lb per MWh; or
of heat input). (2.7E-05 lb per
MMBtu of steam
output or 2.9E-04
lb per MWh).
3. Pulverized coal boilers a. Carbon monoxide 130 ppm by volume 0.11 lb per MMBtu 1 hr minimum
designed to burn coal/solid (CO) (or CEMS). on a dry basis of steam output sampling time.
fossil fuel. corrected to 3- or 1.4 lb per
percent oxygen, 3- MWh; three-run
run average; or average.
(320 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
4. Stokers/others designed to a. CO (or CEMS)... 130 ppm by volume 0.12 lb per MMBtu 1 hr minimum
burn coal/solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per
percent oxygen, 3- MWh; three-run
run average; or average.
(340 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
5. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 0.11 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 1.4 lb per
percent oxygen, 3- MWh; three-run
run average; or average.
(230 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
6. Fluidized bed units with an a. CO (or CEMS)... 140 ppm by volume 1.2E-01 lb per 1 hr minimum
integrated heat exchanger on a dry basis MMBtu of steam sampling time.
designed to burn coal/solid corrected to 3- output or 1.5 lb
fossil fuel. percent oxygen, 3- per MWh; three-
run average; or run average.
(150 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
7. Stokers/sloped grate/others a. CO (or CEMS)... 590 ppm by volume 6.1E-01 lb per 1 hr minimum
designed to burn wet biomass on a dry basis MMBtu of steam sampling time.
fuel. corrected to 3- output or 6.5 lb
percent oxygen, 3- per MWh; three-
run average; or run average.
(390 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
b. Filterable PM 1.3E-02 lb per 1.4E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.6E- output or 1.9E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (2.7E-05 lb per
MMBtu of steam
output or 3.7E-04
lb per MWh).
8. Stokers/sloped grate/others a. CO............. 460 ppm by volume 4.3E-01 lb per 1 hr minimum
designed to burn kiln-dried on a dry basis MMBtu of steam sampling time.
biomass fuel. corrected to 3- output or 5.1 lb
percent oxygen. per MWh.
b. Filterable PM 3.0E-02 lb per 3.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.0E- output or 4.2E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (5.2E-03 lb per
MMBtu of steam
output or 7.0E-02
lb per MWh).
9. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 1.3E-01 lb per 1 hr minimum
to burn biomass/bio-based on a dry basis MMBtu of steam sampling time.
solids. corrected to 3- output or 1.5 lb
percent oxygen, 3- per MWh; three-
run average; or run average.
(310 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
b. Filterable PM 4.1E-03 lb per 5.0E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (8.4E- output or 5.8E-02 run.
06 \a\ lb per lb per MWh; or
MMBtu of heat (1.1E-05 \a\ lb
input). per MMBtu of
steam output or
1.2E-04 \a\ lb
per MWh).
10. Suspension burners designed a. CO (or CEMS)... 220 ppm by volume 0.18 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 2.5 lb per
percent oxygen, 3- MWh; three-run
run average; or average.
(2,000 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 10-day
rolling average).
[[Page 52227]]
b. Filterable PM 3.0E-02 lb per 3.1E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (8.0E- output or 4.2E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (8.1E-03 lb per
MMBtu of steam
output or 1.2E-01
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS)... 330 ppm by volume 3.5E-01 lb per 1 hr minimum
designed to burn biomass/bio- on a dry basis MMBtu of steam sampling time.
based solids. corrected to 3- output or 3.6 lb
percent oxygen, 3- per MWh; three-
run average; or run average.
(520 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 10-day
rolling average).
b. Filterable PM 2.5E-03 lb per 3.4E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (3.9E- output or 3.5E-02 run.
05 lb per MMBtu lb per MWh; or
of heat input). (5.2E-05 lb per
MMBtu of steam
output or 5.5E-04
lb per MWh).
12. Fuel cell units designed to a. CO............. 910 ppm by volume 1.1 lb per MMBtu 1 hr minimum
burn biomass/bio-based solids. on a dry basis of steam output sampling time.
corrected to 3- or 1.0E+01 lb per
percent oxygen. MWh.
b. Filterable PM 1.1E-02 lb per 2.0E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.9E- output or 1.6E-01 run.
05 \a\ lb per lb per MWh; or
MMBtu of heat (5.1E-05 lb per
input). MMBtu of steam
output or 4.1E-04
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS)... 180 ppm by volume 0.22 lb per MMBtu 1 hr minimum
boiler designed to burn biomass/ on a dry basis of steam output sampling time.
bio-based solids. corrected to 3- or 2.0 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (900
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
b. Filterable PM 2.6E-02 lb per 3.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (4.4E- output or 3.7E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (5.5E-04 lb per
MMBtu of steam
output or 6.2E-03
lb per MWh).
14. Units designed to burn a. HCl............ 7.0E-05 lb per 7.7E-05 lb per For M26A: Collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 9.7E-04 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
b. Mercury........ 4.8E-07 \a\ lb per 5.3E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 6.7E-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.
15. Units designed to burn heavy a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average. average.
b. Filterable PM 1.9E-03 lb per 2.1E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (6.1E- output or 2.7E-02 run.
06 lb per MMBtu lb per MWh; or
of heat input). (6.7E-6 lb per
MMBtu of steam
output or 8.5E-5
lb per MWh).
16. Units designed to burn light a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per MWh.
percent oxygen.
b. Filterable PM 1.1E-03 \a\ lb per 1.2E-03 \a\ lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.9E- output or 1.6E-02 run.
05 lb per MMBtu \a\ lb per MWh;
of heat input). or (3.2E-05 lb
per MMBtu of
steam output or
4.0E-04 lb per
MWh).
17. Units designed to burn a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel that are non- on a dry basis of steam output sampling time.
continental units. corrected to 3- or 1.4 lb per
percent oxygen, 3- MWh; three-run
run average based average.
on stack test.
b. Filterable PM 2.3E-02 lb per 2.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 4 dscm per
input; or (8.6E- output or 3.2E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (9.4E-04 lb per
MMBtu of steam
output or 1.2E-02
lb per MWh).
18. Units designed to burn gas 2 a. CO............. 130 ppm by volume 0.16 lb per MMBtu 1 hr minimum
(other) gases. on a dry basis of steam output sampling time.
corrected to 3- or 1.0 lb per MWh.
percent oxygen.
b. HCl............ 1.7E-03 lb per 2.9E-03 lb per For M26A, Collect
MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.8E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
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.
[[Page 52228]]
d. Filterable PM 7.3E-03 lb per 1.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.1E- output or 7.6E-02 run.
04 lb per MMBtu lb per MWh; or
of heat input). (3.5E-04 lb per
MMBtu of steam
output or 2.2E-03
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 below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ If your affected source is a new or reconstructed affected source that commenced construction or
reconstruction after June 4, 2010, and before April 1, 2013, you may comply with the emission limits in Tables
11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before [date 3 years
after date of publication of final rule in the Federal Register] you may comply with the emission limits in
Table 14 to this subpart. On and after [date 3 years after date of publication of final rule in the Federal
Register], you must comply with the emission limits in Table 1 to this subpart.
\d\ An owner or operator may request an alternative test method under Sec. 63.7 of this chapter, in order that
compliance with the carbon monoxide emissions limit be determined using CO2 as a diluent correction in place
of oxygen at 3 percent. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
appropriate CO2 correction percentage for the fuel type burned in the unit and must also take into account
that the 3-percent oxygen correction is to be done on a dry basis. The alternative test method request must
account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone
injection, scrubber media, etc.
0
17. Table 2 to subpart DDDDD is amended to read as follows:
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing Boilers and Process Heaters
As stated in Sec. 63.7500, you must comply with the following applicable emission limits: [Units with heat
input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
The emissions must
The emissions must not exceed the
not exceed the following Using this
If your boiler or process heater For the following following emission alternative output- specified sampling
is in this subcategory . . . pollutants . . . limits, except based limits, volume or test run
during startup and except during duration . . .
shutdown . . . startup and
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............ 2.0E-02 lb per 2.3E-02 lb per For M26A, Collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.26 lb dscm per run; for
per MWh. M26, collect a
minimum of 120
liters per run.
b. Mercury........ 5.4E-06 lb per 6.2E-06 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 6.9E-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. Units design to burn coal/ a. Filterable PM 3.9E-02 lb per 4.1E-02 lb per Collect a minimum
solid fossil fuel. (or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.3E- output or 4.8E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (5.6E-05 lb per
MMBtu of steam
output or 6.5E-04
lb per MWh).
3. Pulverized coal boilers a. CO (or CEMS)... 130 ppm by volume 0.11 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 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (320
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
4. Stokers/others designed to a. CO (or CEMS)... 150 ppm by volume 0.14 lb per MMBtu 1 hr minimum
burn coal/solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.6 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (340
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
5. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 0.12 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 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (230
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
6. Fluidized bed units with an a. CO (or CEMS)... 140 ppm by volume 1.3E-01 lb per 1 hr minimum
integrated heat exchanger on a dry basis MMBtu of steam sampling time.
designed to burn coal/solid corrected to 3- output or 1.5 lb
fossil fuel. percent oxygen, per MWh; three-
three-run run average.
average; or (150
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
7. Stokers/sloped grate/others a. CO (or CEMS)... 1,100 ppm by 1.1 lb per MMBtu 1 hr minimum
designed to burn wet biomass volume on a dry of steam output sampling time.
fuel. basis corrected or 13 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or (720
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
[[Page 52229]]
b. Filterable PM 3.4E-02 lb per 4.0E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.0E- output or 4.8E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (2.4E-04 lb per
MMBtu of steam
output or 2.8E-03
lb per MWh).
8. Stokers/sloped grate/others a. CO............. 460 ppm by volume 4.2E-01 lb per 1 hr minimum
designed to burn kiln-dried on a dry basis MMBtu of steam sampling time.
biomass fuel. corrected to 3- output or 5.1 lb
percent oxygen. per MWh.
b. Filterable PM 3.2E-01 lb per 3.7E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (5.0E- output or 4.5 lb run.
03 lb per MMBtu per MWh; or (5.9E-
of heat input). 03 lb per MMBtu
of steam output
or 7.0E-02 lb per
MWh).
9. Fluidized bed units designed a. CO (or CEMS)... 210 ppm by volume 2.1E-01 lb per 1 hr minimum
to burn biomass/bio-based solid. on a dry basis MMBtu of steam sampling time.
corrected to 3- output or 2.3 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (310
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
b. Filterable PM 2.1E-02 lb per 2.6E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (6.4E- output or 0.30 lb run.
05 lb per MMBtu per MWh; or (8.0E-
of heat input). 05 lb per MMBtu
of steam output
or 9.0E-04 lb per
MWh).
10. Suspension burners designed a. CO (or CEMS)... 2,400 ppm by 1.9 lb per MMBtu 1 hr minimum
to burn biomass/bio-based solid. volume on a dry of steam output sampling time.
basis corrected or 27 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or
(2,000 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\c\ 10-day
rolling average).
b. Filterable PM 4.1E-02 lb per 4.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (8.0E- output or 5.8E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (8.1E-03 lb per
MMBtu of steam
output or 0.12 lb
per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS)... 770 ppm by volume 8.4E-01 lb per 1 hr minimum
designed to burn biomass/bio- on a dry basis MMBtu of steam sampling time.
based solid. corrected to 3- output or 8.4 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (520
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 10-day
rolling average).
b. Filterable PM 1.8E-01 lb per 2.5E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (2.0E- output or 2.6 lb run.
03 lb per MMBtu per MWh; or (2.8E-
of heat input). 03 lb per MMBtu
of steam output
or 2.8E-02 lb per
MWh).
12. Fuel cell units designed to a. CO............. 1,100 ppm by 2.4 lb per MMBtu 1 hr minimum
burn biomass/bio-based solid. volume on a dry of steam output sampling time.
basis corrected or 12 lb per MWh.
to 3-percent
oxygen.
b. Filterable PM 2.0E-02 lb per 5.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.8E- output or 2.8E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (1.6E-02 lb per
MMBtu of steam
output or 8.1E-02
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS)... 3,500 ppm by 3.5 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 39 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or (900
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
b. Filterable PM 4.4E-01 lb per 5.5E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (4.5E- output or 6.2 lb run.
04 lb per MMBtu per MWh; or (5.7E-
of heat input). 04 lb per MMBtu
of steam output
or 6.3E-03 lb per
MWh).
14. Units designed to burn a. HCl............ 1.1E-03 lb per 1.4E-03 lb per For M26A, collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.6E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
b. Mercury........ 7.3E-07 \a\ lb per 8.8E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 1.1E-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.
15. Units designed to burn heavy a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average. average.
[[Page 52230]]
b. Filterable PM 5.9E-02 lb per 7.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (2.0E- output or 8.2E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (2.5E-04 lb per
MMBtu of steam
output or 2.8E-03
lb per MWh).
16. Units designed to burn light a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per MWh.
percent oxygen.
b. Filterable PM 7.9E-03 \a\ lb per 9.6E-03 \a\ lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (6.2E- output or 1.1E-01 run.
05 lb per MMBtu \a\ lb per MWh;
of heat input). or (7.5E-05 lb
per MMBtu of
steam output or
8.6E-04 lb per
MWh).
17. Units designed to burn a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel that are non- on a dry basis of steam output sampling time.
continental units. corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average average.
based on stack
test.
b. Filterable PM 2.2E-01 lb per 2.7E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (8.6E- output or 3.1 lb run.
04 lb per MMBtu per MWh; or (1.1E-
of heat input). 03 lb per MMBtu
of steam output
or 1.2E-02 lb per
MWh).
18. Units designed to burn gas 2 a. CO............. 130 ppm by volume 0.16 lb per MMBtu 1 hr minimum
(other) gases. on a dry basis of steam output sampling time.
corrected to 3- or 1.0 lb per MWh.
percent oxygen.
b. HCl............ 1.7E-03 lb per 2.9E-03 lb per For M26A, collect
MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.8E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
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 2 dscm.
d. Filterable PM 7.3E-03 lb per 1.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input or (2.1E-04 output or 7.6E-02 run.
lb per MMBtu of lb per MWh; or
heat input). (3.5E-04 lb per
MMBtu of steam
output or 2.2E-03
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 below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ An owner or operator may request an alternative test method under Sec. 63.7 of this chapter, in order that
compliance with the carbon monoxide emissions limit be determined using CO2 as a diluent correction in place
of oxygen at 3 percent. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
appropriate CO2 correction percentage for the fuel type burned in the unit and must also take into account
that the 3-percent oxygen correction is to be done on a dry basis. The alternative test method request must
account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone
injection, scrubber media, etc.
\d\ Before [date 3 years after date of publication of final rule in the Federal Register] you may comply with
the emission limits in Table 15 to this subpart. On and after [date 3 years after date of publication of final
rule in the Federal Register], you must comply with the emission limits in Table 2 to this subpart.
0
18. Table 3 of subpart DDDDD is amended by revising the entry for
``5.'' and ``6.'' to read as follows:
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
As stated in Sec. 63.7500, you must comply with the following
applicable work practice standards:
------------------------------------------------------------------------
If your unit is . . . You must meet the following . . .
------------------------------------------------------------------------
* * * * * * *
5. An existing or new boiler a. You must operate all CMS during
or process heater subject to startup.
emission limits in Table 1 b. For startup of a boiler or process
or 2 or 11 through 13 to heater, you must use one or a
this subpart during startup. combination of the following clean
fuels: Natural gas, synthetic natural
gas, propane, other Gas 1 fuels,
distillate oil, syngas, ultra-low sulfur
diesel, fuel oil-soaked rags, kerosene,
hydrogen, paper, cardboard, refinery
gas, liquefied petroleum gas, clean dry
biomass, and any fuels meeting the
appropriate HCl, mercury and TSM
emission standards by fuel analysis.
c. You have the option of complying using
either of the following work practice
standards.
[[Page 52231]]
(1) If you choose to comply using
definition (1) of ``startup'' in Sec.
63.7575, once you start firing fuels
that are not clean fuels you must vent
emissions to the main stack(s) and
engage all of the applicable control
devices except limestone injection in
fluidized bed combustion (FBC) boilers,
dry scrubber, fabric filter, and
selective catalytic reduction (SCR). You
must start your limestone injection in
FBC boilers, dry scrubber, fabric
filter, and SCR systems as expeditiously
as possible. Startup ends when steam or
heat is supplied for any purpose, OR
(2) If you choose to comply using
definition (2) of ``startup'' in Sec.
63.7575, once you start to feed fuels
that are not clean fuels, you must vent
emissions to the main stack(s) and
engage all of the applicable control
devices so as to comply with the
emission limits within 4 hours of start
of supplying useful thermal energy. You
must engage and operate PM control
within one hour of first feeding fuels
that are not clean fuels\a\. You must
start all applicable control devices as
expeditiously as possible, but, in any
case, when necessary to comply with
other standards applicable to the source
by a permit limit or a rule other than
this subpart that require operation of
the control devices. You must develop
and implement a written startup and
shutdown plan, as specified in Sec.
63.7505(e).
d. You must comply with all applicable
emission limits at all times except
during startup and shutdown periods at
which time you must meet this work
practice. You must collect monitoring
data during periods of startup, as
specified in Sec. 63.7535(b). You must
keep records during periods of startup.
You must provide reports concerning
activities and periods of startup, as
specified in Sec. 63.7555.
6. An existing or new boiler You must operate all CMS during shutdown.
or process heater subject to While firing fuels that are not clean
emission limits in Tables 1 fuels during shutdown, you must vent
or 2 or 11 through 15 to emissions to the main stack(s) and
this subpart during shutdown. operate all applicable control devices,
except limestone injection in FBC
boilers, dry scrubber, fabric filter,
and SCR but, in any case, when necessary
to comply with other standards
applicable to the source that require
operation of the control device.
If, in addition to the fuel used prior to
initiation of shutdown, another fuel
must be used to support the shutdown
process, that additional fuel must be
one or a combination of the following
clean fuels: Natural gas, synthetic
natural gas, propane, other Gas 1 fuels,
distillate oil, syngas, ultra-low sulfur
diesel, refinery gas, and liquefied
petroleum gas.
You must comply with all applicable
emissions limits at all times except for
startup or shutdown periods conforming
with this work practice. You must
collect monitoring data during periods
of shutdown, as specified in Sec.
63.7535(b). You must keep records during
periods of shutdown. You must provide
reports concerning activities and
periods of shutdown, as specified in
Sec. 63.7555.
------------------------------------------------------------------------
* * * * *
0
19. Table 4 to subpart DDDDD is amended by revising the column headings
to read as follows:
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
Process Heaters
As stated in Sec. 63.7500, you must comply with the applicable
operating limits:
------------------------------------------------------------------------
When complying with a Table 1, 2, 11, 12,
13, 14, or 15 numerical emission limit You must meet these
using . . . operating limits . . .
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
* * * * *
0
20. Table 7 to subpart DDDDD is amended by revising footnote ``b'' to
read as follows:
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits a b
As stated in Sec. 63.7520, you must comply with the following
requirements for establishing operating limits:
------------------------------------------------------------------------
--------------------------------------------
* * * * *
------------------------------------------------------------------------
\b\ 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. For a
minimum oxygen level, if you conduct multiple performance tests, you
must set the minimum oxygen level at the lower of the minimum values
established during the performance tests. For maximum operating load,
if you conduct multiple performance tests, you must set the maximum
operating load at the lower of the maximum values established during
the performance tests.
0
21. Table 8 to subpart DDDDD is amended by revising the entry for
``8.'' to read as follows:
[[Page 52232]]
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
As stated in Sec. 63.7540, you must show continuous compliance with
the emission limitations for each boiler or process heater according to
the following:
------------------------------------------------------------------------
If you must meet the
following operating limits or You must demonstrate continuous
work practice standards . . . compliance by . . .
------------------------------------------------------------------------
* * * * * * *
8. Emission limits using fuel a. Conduct monthly fuel analysis for HCl
analysis. or mercury or TSM according to Table 6
to this subpart; and
b. Reduce the data to 12-month rolling
averages; and
c. Maintain the 12-month rolling average
at or below the applicable emission
limit for HCl or mercury or TSM in
Tables 1 and 2 or 11 through 15 to this
subpart.
d. Calculate the HCI, mercury, and/or TSM
emission rate from the boiler or process
heater in units of lb/MMBtu using
Equations 7, 8, and/or 9 in Sec.
63.7530.
* * * * * * *
------------------------------------------------------------------------
* * * * *
0
22. Add Table 14 to subpart DDDDD of part 63 to read as follows:
Table 14 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters
As stated in Sec. 63.7500, you may continue to comply with the following applicable emission limits until
[date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity
of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
Or the emissions
The emissions must must not exceed
not exceed the the following Using this
If your boiler or process heater For the following following emission alternative output- specified sampling
is in this subcategory . . . pollutants . . . limits, except based limits, volume or test run
during startup and except during duration . . .
shutdown . . . startup and
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............ 2.2E-02 lb per 2.5E-02 lb per For M26A, collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.28 lb dscm per run; for
per MWh. M26 collect a
minimum of 120
liters per run.
b. Mercury........ 8.0E-07 \a\ lb per 8.7E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 1.1E-05 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.
2. Units designed to burn coal/ a. Filterable PM 1.1E-03 lb per 1.1E-03 lb per Collect a minimum
solid fossil fuel. (or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.3E- output or 1.4E-02 run.
05 lb per MMBtu lb per MWh; or
of heat input). (2.7E-05 lb per
MMBtu of steam
output or 2.9E-04
lb per MWh).
3. Pulverized coal boilers a. Carbon monoxide 130 ppm by volume 0.11 lb per MMBtu 1 hr minimum
designed to burn coal/solid (CO) (or CEMS). on a dry basis of steam output sampling time.
fossil fuel. corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (320
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
4. Stokers/others designed to a. CO (or CEMS)... 130 ppm by volume 0.12 lb per MMBtu 1 hr minimum
burn coal/solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (340
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
5. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 0.11 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 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (230
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
6. Fluidized bed units with an a. CO (or CEMS)... 140 ppm by volume 1.2E-01 lb per 1 hr minimum
integrated heat exchanger on a dry basis MMBtu of steam sampling time.
designed to burn coal/solid corrected to 3- output or 1.5 lb
fossil fuel. percent oxygen, per MWh; three-
three-run run average.
average; or (150
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
7. Stokers/sloped grate/others a. CO (or CEMS)... 620 ppm by volume 5.8E-01 lb per 1 hr minimum
designed to burn wet biomass on a dry basis MMBtu of steam sampling time.
fuel. corrected to 3- output or 6.8 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (390
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
b. Filterable PM 3.0E-02 lb per 3.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.6E- output or 4.2E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (2.7E-05 lb per
MMBtu of steam
output or 3.7E-04
lb per MWh).
[[Page 52233]]
8. Stokers/sloped grate/others a. CO............. 460 ppm by volume 4.2E-01 lb per 1 hr minimum
designed to burn kiln-dried on a dry basis MMBtu of steam sampling time.
biomass fuel. corrected to 3- output or 5.1 lb
percent oxygen. per MWh.
b. Filterable PM 3.0E-02 lb per 3.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (4.0E- output or 4.2E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (4.2E-03 lb per
MMBtu of steam
output or 5.6E-02
lb per MWh).
9. Fluidized bed units designed a. CO (or CEMS)... 230 ppm by volume 2.2E-01 lb per 1 hr minimum
to burn biomass/bio-based on a dry basis MMBtu of steam sampling time.
solids. corrected to 3- output or 2.6 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (310
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
b. Filterable PM 9.8E-03 lb per 1.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (8.3E- output or 0.14 lb run.
05 \a\ lb per per MWh; or (1.1E-
MMBtu of heat 04 \a\ lb per
input). MMBtu of steam
output or 1.2E-03
\a\ lb per MWh).
10. Suspension burners designed a. CO (or CEMS)... 2,400 ppm by 1.9 lb per MMBtu 1 hr minimum
to burn biomass/bio-based volume on a dry of steam output sampling time.
solids. basis corrected or 27 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or
(2,000 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 10-day
rolling average).
b. Filterable PM 3.0E-02 lb per 3.1E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (6.5E- output or 4.2E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (6.6E-03 lb per
MMBtu of steam
output or 9.1E-02
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS)... 330 ppm by volume 3.5E-01 lb per 1 hr minimum
designed to burn biomass/bio- on a dry basis MMBtu of steam sampling time.
based solids. corrected to 3- output or 3.6 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (520
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 10-day
rolling average).
b. Filterable PM 3.2E-03 lb per 4.3E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (3.9E- output or 4.5E-02 run.
05 lb per MMBtu lb per MWh; or
of heat input). (5.2E-05 lb per
MMBtu of steam
output or 5.5E-04
lb per MWh).
12. Fuel cell units designed to a. CO............. 910 ppm by volume 1.1 lb per MMBtu 1 hr minimum
burn biomass/bio-based solids. on a dry basis of steam output sampling time.
corrected to 3- or 1.0E+01 lb per
percent oxygen. MWh.
b. Filterable PM 2.0E-02 lb per 3.0E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.9E- output or 2.8E-01 run.
05 \a\ lb per lb per MWh; or
MMBtu of heat (5.1E-05 lb per
input). MMBtu of steam
output or 4.1E-04
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS)... 1,100 ppm by 1.4 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 12 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or (900
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\d\ 30-day
rolling average).
b. Filterable PM 2.6E-02 lb per 3.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (4.4E- output or 3.7E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (5.5E-04 lb per
MMBtu of steam
output or 6.2E-03
lb per MWh).
14. Units designed to burn a. HCl............ 4.4E-04 lb per 4.8E-04 lb per For M26A: Collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 6.1E-03 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
b. Mercury........ 4.8E-07 \a\ lb per 5.3E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 6.7E-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.
15. Units designed to burn heavy a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average. average.
b. Filterable PM 1.3E-02 lb per 1.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (7.5E- output or 1.8E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (8.2E-05 lb per
MMBtu of steam
output or 1.1E-03
lb per MWh).
16. Units designed to burn light a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per MWh.
percent oxygen.
[[Page 52234]]
b. Filterable PM 1.1E-03 \a\ lb per 1.2E-03 \a\ lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.9E- output or 1.6E-02 run.
05 lb per MMBtu \a\ lb per MWh;
of heat input). or (3.2E-05 lb
per MMBtu of
steam output or
4.0E-04 lb per
MWh).
17. Units designed to burn a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel that are non- on a dry basis of steam output sampling time.
continental units. corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average average.
based on stack
test.
b. Filterable PM 2.3E-02 lb per 2.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 4 dscm per
input; or (8.6E- output or 3.2E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (9.4E-04 lb per
MMBtu of steam
output or 1.2E-02
lb per MWh).
18. Units designed to burn gas 2 a. CO............. 130 ppm by volume 0.16 lb per MMBtu 1 hr minimum
(other) gases. on a dry basis of steam output sampling time.
corrected to 3- or 1.0 lb per MWh.
percent oxygen.
b. HCl............ 1.7E-03 lb per 2.9E-03 lb per For M26A, Collect
MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.8E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
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 PM 6.7E-03 lb per 1.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.1E- output or 7.0E-02 run.
04 lb per MMBtu lb per MWh; or
of heat input). (3.5E-04 lb per
MMBtu of steam
output or 2.2E-03
lb per MWh).
----------------------------------------------------------------------------------------------------------------
0
23. Add Table 15 to subpart DDDDD of part 63 to read as follows:
Table 15 to Subpart DDDDD of Part 63--Alternative Emission Limits for Existing Boilers and Process Heaters
As stated in Sec. 63.7500, you may continue to comply with following emission limits until [date 3 years after
date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu
per hour or greater]
----------------------------------------------------------------------------------------------------------------
The emissions must
The emissions must not exceed the
not exceed the following Using this
If your boiler or process heater For the following following emission alternative output- specified sampling
is in this subcategory . . . pollutants . . . limits, except based limits, volume or test
during startup and except during run duration . . .
shutdown . . . startup and
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............ 2.2E-02 lb per 2.5E-02 lb per For M26A, Collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.27 lb dscm per run; for
per MWh. M26, collect a
minimum of 120
liters per run.
b. Mercury........ 5.7E-06 lb per 6.4E-06 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 7.3E-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.
2. Units design to burn coal/ a. Filterable PM 4.0E-02 lb per 4.2E-02 lb per Collect a minimum
solid fossil fuel. (or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.3E- output or 4.9E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (5.6E-05 lb per
MMBtu of steam
output or 6.5E-04
lb per MWh).
3. Pulverized coal boilers a. CO (or CEMS)... 130 ppm by volume 0.11 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 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (320
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
4. Stokers/others designed to a. CO (or CEMS)... 160 ppm by volume 0.14 lb per MMBtu 1 hr minimum
burn coal/solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.7 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (340
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
[[Page 52235]]
5. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 0.12 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 1.4 lb per
percent oxygen, MWh; three-run
three-run average.
average; or (230
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
6. Fluidized bed units with an a. CO (or CEMS)... 140 ppm by volume 1.3E-01 lb per 1 hr minimum
integrated heat exchanger on a dry basis MMBtu of steam sampling time.
designed to burn coal/solid corrected to 3- output or 1.5 lb
fossil fuel. percent oxygen, per MWh; three-
three-run run average.
average; or (150
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
7. Stokers/sloped grate/others a. CO (or CEMS)... 1,500 ppm by 1.4 lb per MMBtu 1 hr minimum
designed to burn wet biomass volume on a dry of steam output sampling time.
fuel. basis corrected or 17 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or (720
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
b. Filterable PM 3.7E-02 lb per 4.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.4E- output or 5.2E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (2.8E-04 lb per
MMBtu of steam
output or 3.4E-04
lb per MWh).
8. Stokers/sloped grate/others a. CO............. 460 ppm by volume 4.2E-01 lb per 1 hr minimum
designed to burn kiln-dried on a dry basis MMBtu of steam sampling time.
biomass fuel. corrected to 3- output or 5.1 lb
percent oxygen. per MWh.
b. Filterable PM 3.2E-01 lb per 3.7E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (4.0E- output or 4.5 lb run.
03 lb per MMBtu per MWh; or (4.6E-
of heat input). 03 lb per MMBtu
of steam output
or 5.6E-02 lb per
MWh).
9. Fluidized bed units designed a. CO (or CEMS)... 470 ppm by volume 4.6E-01 lb per 1 hr minimum
to burn biomass/bio-based solid. on a dry basis MMBtu of steam sampling time.
corrected to 3- output or 5.2 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (310
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
b. Filterable PM 1.1E-01 lb per 1.4E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (1.2E- output or 1.6 lb run.
03 lb per MMBtu per MWh; or (1.5E-
of heat input). 03 lb per MMBtu
of steam output
or 1.7E-02 lb per
MWh).
10. Suspension burners designed a. CO (or CEMS)... 2,400 ppm by 1.9 lb per MMBtu 1 hr minimum
to burn biomass/bio-based solid. volume on a dry of steam output sampling time.
basis corrected or 27 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or
(2,000 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\c\ 10-day
rolling average).
b. Filterable PM 5.1E-02 lb per 5.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (6.5E- output or 7.1E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (6.6E-03 lb per
MMBtu of steam
output or 9.1E-02
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS)... 770 ppm by volume 8.4E-01 lb per 1 hr minimum
designed to burn biomass/bio- on a dry basis MMBtu of steam sampling time.
based solid. corrected to 3- output or 8.4 lb
percent oxygen, per MWh; three-
three-run run average.
average; or (520
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 10-day
rolling average).
b. Filterable PM 2.8E-01 lb per 3.9E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (2.0E- output or 3.9 lb run.
03 lb per MMBtu per MWh; or (2.8E-
of heat input). 03 lb per MMBtu
of steam output
or 2.8E-02 lb per
MWh).
12. Fuel cell units designed to a. CO............. 1,100 ppm by 2.4 lb per MMBtu 1 hr minimum
burn biomass/bio-based solid. volume on a dry of steam output sampling time.
basis corrected or 12 lb per MWh.
to 3-percent
oxygen.
b. Filterable PM 2.0E-02 lb per 5.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.8E- output or 2.8E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (1.6E-02 lb per
MMBtu of steam
output or 8.1E-02
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS)... 3,500 ppm by 3.5 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 39 lb per MWh;
to 3-percent three-run average.
oxygen, three-run
average; or (900
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
[[Page 52236]]
b. Filterable PM 4.4E-01 lb per 5.5E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (4.5E- output or 6.2 lb run.
04 lb per MMBtu per MWh; or (5.7E-
of heat input). 04 lb per MMBtu
of steam output
or 6.3E-03 lb per
MWh).
14. Units designed to burn a. HCl............ 1.1E-03 lb per 1.4E-03 lb per For M26A, collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.6E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
b. Mercury........ 2.0E-06 \a\ lb per 2.5E-06 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 2.8E-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.
15. Units designed to burn heavy a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three-run average. average.
b. Filterable PM 6.2E-02 lb per 7.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (2.0E- output or 8.6E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (2.5E-04 lb per
MMBtu of steam
output or 2.8E-03
lb per MWh).
16. Units designed to burn light a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3- or 1.4 lb per MWh.
percent oxygen.
b. Filterable PM 7.9E-03 \a\ lb per 9.6E-03 \a\ lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (6.2E- output or 1.1E-01 run.
05 lb per MMBtu \a\ lb per MWh;
of heat input). or (7.5E-05 lb
per MMBtu of
steam output or
8.6E-04 lb per
MWh).
17. Units designed to burn a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel that are non- on a dry basis of steam output sampling time.
continental units. corrected to 3- or 1.4 lb per
percent oxygen, MWh; three-run
three3-run average.
average based on
stack test.
b. Filterable PM 2.7E-01 lb per 3.3E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (8.6E- output or 3.8 lb run.
04 lb per MMBtu per MWh; or (1.1E-
of heat input). 03 lb per MMBtu
of steam output
or 1.2E-02 lb per
MWh).
18. Units designed to burn gas 2 a. CO............. 130 ppm by volume 0.16 lb per MMBtu 1 hr minimum
(other) gases. on a dry basis of steam output sampling time.
corrected to 3- or 1.0 lb per MWh.
percent oxygen.
b. HCl............ 1.7E-03 lb per 2.9E-03 lb per For M26A, collect
MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.8E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
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 2 dscm.
d. Filterable PM 6.7E-03 lb per 1.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of three dscm per
input or (2.1E-04 output or 7.0E-02 run.
lb per MMBtu of lb per MWh; or
heat input). (3.5E-04 lb per
MMBtu of steam
output or 2.2E-03
lb per MWh).
----------------------------------------------------------------------------------------------------------------
[FR Doc. 2020-15121 Filed 8-21-20; 8:45 am]
BILLING CODE 6560-50-P