National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, 60816-60865 [2022-19612]
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 63
[EPA–HQ–OAR–2002–0058; FRL–6312–02–
OAR]
RIN 2060–AU20
National Emission Standards for
Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and
Institutional Boilers and Process
Heaters
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
This action finalizes
amendments to the national emission
standards for hazardous air pollutants
(NESHAP) at major sources from new
and existing industrial, commercial, and
institutional (ICI) boilers and process
heaters. Certain aspects of these
standards were challenged and
subsequently remanded to the Agency
by the United States Court of Appeals
for the District of Columbia Circuit (D.C.
Circuit). This action finalizes
amendments to several numeric
emission limits for new and existing
boilers and process heaters consistent
with the court’s opinion and sets
compliance dates for these new
emission limits. This action also
provides further explanation of one
aspect of the Agency’s use of carbon
monoxide (CO) as a surrogate for
organic hazardous air pollutants (HAP)
and its use of a CO threshold to
represent the application of the
maximum achievable control
technology (MACT) for organic HAP.
We are also finalizing several technical
clarifications and corrections.
DATES: This final rule is effective on
December 5, 2022. The incorporation by
reference (IBR) of certain material listed
in the rule is approved by the Director
of the Federal Register as of October 6,
2022. The incorporation by reference of
this material was previously approved
by the Director of the Federal Register
as of May 20, 2011.
FOR FURTHER INFORMATION CONTACT: For
questions about this final action, contact
Lisa Thompson, 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–
9775; and email address:
thompson.lisa@epa.gov or Nick Hutson,
Sector Policies and Programs Division
(D243–01), Office of Air Quality
Planning and Standards, U.S.
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SUMMARY:
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Environmental Protection Agency,
Research Triangle Park, North Carolina
27711; telephone number: (919) 541–
2968; and email address: hutson.nick@
epa.gov.
SUPPLEMENTARY INFORMATION:
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 on
the https://www.regulations.gov/
website. Although listed, some
information is not publicly available,
e.g., Confidential Business Information
or other information whose disclosure is
restricted by statute. Certain other
material, such as copyrighted material,
is not placed on the internet and will be
publicly available only in hard copy
form. Publicly available docket
materials are available electronically
through https://www.regulations.gov/.
Out of an abundance of caution for
members of the public and our staff, the
EPA Docket Center and Reading Room
are closed to the public, with limited
exceptions, to reduce the risk of
transmitting COVID–19. Our Docket
Center staff will continue to provide
remote customer service via email,
phone, and webform.
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?
D. Judicial Review and Administrative
Reconsideration
II. Background
III. Summary of Final Action and Significant
Changes Since Proposal
A. Revisions to MACT Floor Emission
Limits
B. Beyond-the-Floor Emission Limits
C. Revisions to Output-Based Emission
Limits
D. CO as a Surrogate for Organic HAP
E. CO 130 PPM Threshold Emission Limits
F. New Source Definition
G. Approval for CO2 in Lieu of O2
Monitoring for CO CEMS Compliance
Calculations
IV. Results and Final Decisions
A. What are the resulting changes to
emission limits?
B. What compliance dates are we
finalizing?
C. What other actions are we finalizing?
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?
G. What analysis of environmental justice
did we conduct?
VI. Statutory and Executive Order Reviews
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A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act
(UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and
Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
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
(ICI) and Process Heaters was
promulgated on March 21, 2011 and
amended on January 31, 2013 and again
on November 20, 2015. Environmental
groups and industry submitted petitions
seeking judicial review of the 2013
NESHAP. On July 29, 2016, the D.C.
Circuit remanded for further
explanation the use of CO as a surrogate
for organic HAP due to the EPA’s failure
to address a public comment received
and vacated certain emission standards
where it held that the EPA had
improperly excluded certain units in
establishing the emission standards.
U.S. Sugar Corp. v. EPA, 830 F.3d 579,
631. On December 23, 2016, the D.C.
Circuit amended its July 29, 2016
decision to remand those emission
standards instead of vacating them. 844
F.3d 268. In March 2018, the court, in
a separate challenge to the 2015
amended NESHAP, remanded for
further explanation the EPA’s decision
to set a limit of 130 parts per million
(ppm) CO as a minimum standard for
certain subcategories of boilers and
process heaters. Sierra Club v. EPA, 884
F.3d 1185.
In response to these remands, the EPA
is finalizing revisions to several
emission standards consistent with the
court’s opinion and providing further
explanation of the two issues remanded
for that purpose.
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b. Legal Authority
The statutory authority for this final
action is section 112 of the Clean Air
Act (CAA). 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
2. Summary of the Major Provisions of
the Regulatory Action in Question
The EPA is finalizing revisions to 34
different emission limits which it had
previously promulgated in 2011 and
amended in 2013. Of these 34 emission
limits, 28 of the limits are more
stringent and six of the limits are less
stringent than the previously
promulgated emission limits. The EPA
is also finalizing a deadline of 3 years
after the effective date of the final rule
for sources to demonstrate compliance
with these revised emission limits. A
list of each combination of subcategory
and pollutant with revised limits is
shown in Table 1.
TABLE 1—SUMMARY OF SUBCATEGORIES WITH REVISED EMISSION
LIMITS
Subcategory
Pollutant
New-Solid .......................................
New-Dry Biomass Stoker ...............
New-Biomass Fluidized Bed ..........
New-Biomass Suspension Burner ..
New-Biomass Hybrid Suspension
Grate.
New-Biomass Dutch Oven/Pile
Burner.
New-Biomass Fuel Cell ..................
New-Wet Biomass Stoker ..............
New-Liquid ......................................
New-Heavy Liquid ..........................
New-Process Gas ...........................
Existing-Solid ..................................
Existing-Coal ...................................
Existing-Coal Stoker .......................
Existing-Dry Biomass Stoker ..........
Existing-Wet Biomass Stoker .........
Existing-Biomass Fluidized Bed .....
Existing-Biomass Suspension
Burners.
Existing-Biomass Dutch Oven/Pile
Burner.
Existing-Liquid ................................
Existing-Heavy Liquid .....................
Existing-Non-continental Liquid ......
Existing-Process Gas .....................
HCl.
TSM.*
CO, PM, TSM.
CO, TSM.*
CO.
PM.
PM.
CO, PM.
HCl.
PM, TSM.
PM.*
HCl, Hg.
PM.
CO.
TSM.*
CO, PM, TSM.
CO, PM, TSM.
PM, TSM.*
PM.
Hg.
PM.
PM.
PM.*
* Indicates a less stringent limit compared to the
previously promulgated emission limits.
3. Costs and Benefits
We have estimated certain costs and
benefits of the final rule, and these are
found in Table 2. All of these estimates
are in 2016 dollars (2016$). The
60817
monetized benefits estimate reflects an
annual average of 446 tons of fine
particulate matter (PM2.5) emission
reductions per year and 1,141 tons of
sulfur dioxide (SO2) emission
reductions per year, both pollutants not
directly regulated by this final rule. The
unmonetized benefits include reduced
exposure to directly regulated HAP,
including mercury (Hg), hydrochloric
acid (HCl), non-Hg metals (e.g.,
antimony, cadmium), formaldehyde,
benzene, and polycyclic organic matter;
reduced climate effects due to reduced
black carbon emissions; reduced
ecosystem effects; and reduced visibility
impairments. These estimates also
include climate disbenefits resulting
from an increase in carbon dioxide
(CO2) emissions, a secondary impact
from electricity use by additional
control devices in response to the final
amendments.
Table 2 presents estimates of the
present values (PV) and equivalent
annualized values (EAV), calculated
using discount rates of 3 and 7 percent
as directed by OMB’s Circular A–4, of
the health benefits, climate disbenefits,
compliance costs, and net benefits of the
final rule, in 2016 dollars, discounted to
2020. The estimated net benefits are the
estimated benefits minus the estimated
disbenefits and the estimated costs of
the final rule.
TABLE 2—ESTIMATED HEALTH BENEFITS, CLIMATE DISBENEFITS, COMPLIANCE COSTS, AND NET BENEFITS OF THE FINAL
RULE, 2022 THROUGH 2029
[Millions 2016$, discounted to 2020] a
3% Discount rate
Present Value:
Health Benefits b .......................................................................................................................
Climate Disbenefits b ................................................................................................................
Compliance Costs c ..................................................................................................................
Net Benefits d ............................................................................................................................
$500 and $505 ..........
$7 ..............................
$315 ..........................
$178 and $182 + B ...
$350 and $353.
$7.
$265.
$80 and $83 + B.
Equivalent Annualized Value:
Health Benefits .........................................................................................................................
Climate Disbenefits ...................................................................................................................
Compliance Costs ....................................................................................................................
Net Benefits ..............................................................................................................................
$71 and $72 ..............
$1 ..............................
$45 ............................
$25 and $26 + C .......
$58 and $59.
$1.
$44.
$13 and $14 + C.
a Numbers
may not sum due to independent rounding.
health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The health benefits are a result of the PM2.5 and SO2 emission reductions estimated for this final rule, and are associated with several point estimates and are
presented at real discount rates of 3 and 7 percent. The two benefits estimates are separated by the word ‘‘and’’ to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates and should not be summed. Data, resource, and methodological limitations prevented the EPA from monetizing the human health benefits from reduced exposure to mercury, HCl, and other HAP whose
emissions are directly regulated by this final rule. The EPA provides a qualitative discussion of mercury, HCl, and other HAP benefits in the RIA.
In addition, the potential benefits from reduced ecosystem effects and reduced visibility impairment from the reduction in emissions of non-HAP
pollutants such as PM2.5 and SO2 are also not monetized here. Climate disbenefits are based on changes (increases) in CO2 emissions and are
calculated using four different estimates of the social cost of carbon (SC–CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount
rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we show the climate disbenefits associated with
the average SC–CO2 at a 3 percent discount rate, but the Agency does not have a single central SC–CO2 point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC–CO2 estimates; the additional disbenefit estimates are presented
in section V of this preamble. As discussed in Chapter 4 of the Regulatory Impact Analysis (RIA) for this final rule, a consideration of climate
disbenefits calculated using discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting intergenerational
impacts.
b The
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7% Discount rate
1 See 75 FR 32016 and § 63.7575 ‘‘What
definitions apply to this subpart’’ of 40 CFR part 63,
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subpart DDDDD, for definitions of ICI boilers and
process heaters.
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c To estimate these annualized costs, the EPA uses a conventional and widely accepted approach, the equivalent uniform annual cost (EUAC)
approach, that applies a capital recovery factor (CRF) multiplier to capital investments and adds that to the annual incremental operating expenses. Annual costs were calculated using a 5.5% nominal interest rate consistent with the rate used for the cost analysis done for the proposed rule.
d The letter ‘‘B’’ captures the portion of the present value of net benefits due to the unmonetized benefits from the emission reductions of directly regulated HAP and all other emission changes resulting from this final rule. The letter ‘‘C’’ captures the portion of the equivalent annualized
value of net benefits due to the unmonetized benefits from the emission reductions of directly regulated HAP and all other emission changes resulting from this final rule. The benefits from emission reductions of directly regulated HAP under this final rule are not monetized due to lack of
appropriate valuation estimates. More information on the unmonetized benefits from HAP and non-HAP emission reductions can be found in
Chapter 4 of the RIA.
As shown in Table 2, the PV of the
health benefits of this final rule,
discounted at a 3-percent discount rate,
is estimated to be about $500 million
and $505 million, with an EAV of about
$71 million and $72 million. At a 7percent discount rate, the PV of the
health benefits is estimated to be $350
million and $353 million, with an EAV
of about $58 million and $59 million.
The two health benefits estimates for
each discount rate reflect alternative
PM2.5 mortality risk estimates. The PV of
the climate disbenefits of this final rule,
discounted at a 3-percent rate, is
estimated to be about $7 million, with
an EAV of about $1 million. The PV of
the compliance costs, discounted at a 3percent rate, is estimated to be about
$315 million, with an EAV of about $45
million. At a 7-percent discount rate,
the PV of the compliance costs is
estimated to be about $265 million, with
an EAV of about $44 million.
More information on these impacts
can be found in section V of this
preamble and in the Regulatory Impact
Analysis (RIA) for this final rule.
B. Does this action apply to me?
Table 3 lists the NESHAP and
associated regulated industrial source
categories that are the subject of this
action. Table 3 is not intended to be
exhaustive, but rather provides a guide
for readers regarding the entities that
this action affects. The final standards
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/Commercial 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, and petroleum and chemical
industry 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.
TABLE 3—SOURCE CATEGORIES AFFECTED BY THIS FINAL ACTION
Source category
NESHAP
NAICS code 1
Examples of regulated entities
Any industry using a boiler or
process heater as defined in
the final rule.
Industrial, Commercial, and Institutional Boilers and Process Heaters.
211
321
322
325
324
316, 326, 339
331
332
336
221
622
611
Extractors of crude petroleum and natural gas.
Manufacturers of lumber and wood products.
Pulp and paper mills.
Chemical manufacturers.
Petroleum refineries, and manufacturers of coal products.
Manufacturers of rubber and miscellaneous plastic products.
Steel works, blast furnaces.
Electroplating, plating, polishing, anodizing, and coloring.
Manufacturers of motor vehicle parts and accessories.
Electric, gas, and sanitary services.
Health services.
Educational services.
1 North
American Industry Classification System.
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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 final action
at https://www.epa.gov/stationarysources-air-pollution/industrialcommercial-and-institutional-boilers-
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and-process-heaters. Following
publication in the Federal Register, the
EPA will post the Federal Register
version of the action and key technical
documents at this same website.
A redline version of the regulatory
language that incorporates the finalized
changes in this action is available in the
docket for this action (Docket ID No.
EPA–HQ–OAR–2002–0058).
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D. Judicial Review and Administrative
Reconsideration
Under CAA section 307(b)(1), judicial
review of this final action is available
only by filing a petition for review in
the United States Court of Appeals for
the District of Columbia Circuit by
December 5, 2022. Under CAA section
307(b)(2), the requirements established
by this final rule may not be challenged
separately in any civil or criminal
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proceedings brought by the EPA to
enforce the requirements.
Section 307(d)(7)(B) of the CAA
further provides that only an objection
to a rule or procedure which was raised
with reasonable specificity during the
period for public comment (including
any public hearing) may be raised
during judicial review. This section also
provides a mechanism for the EPA to
reconsider the rule if the person raising
an objection can demonstrate to the
Administrator that it was impracticable
to raise such objection within the period
for public comment or if the grounds for
such objection arose after the period for
public comment (but within the time
specified for judicial review) and if such
objection is of central relevance to the
outcome of the rule. Any person seeking
to make such a demonstration should
submit a Petition for Reconsideration to
the Office of the Administrator, U.S.
EPA, Room 3000, WJC South Building,
1200 Pennsylvania Ave. NW,
Washington, DC 20460, with a copy to
both the person(s) listed in the
preceding FOR FURTHER INFORMATION
CONTACT section, and the Associate
General Counsel for the Air and
Radiation Law Office, Office of General
Counsel (Mail Code 2344A), U.S. EPA,
1200 Pennsylvania Ave. NW,
Washington, DC 20460.
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 the
maximum achievable control
technology (MACT) (76 FR 15608). On
January 31, 2013, the EPA promulgated
final amendments (78 FR 7138), which
were challenged by industry and
environmental petitioners. On
November 20, 2015, the EPA
promulgated additional amendments
(80 FR 72789) in response to certain
reconsideration issues.
On July 29, 2016, the D.C. Circuit
issued its decision in U.S. Sugar Corp
v. EPA. In that decision, the court
upheld the EPA’s 2013 final rule 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 MACTfloor 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. As the
court explained, ‘‘[a]lthough the EPA
allowed sources that combust only 10
per cent of a subcategory defining fuel
to join that subcategory, it declined to
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consider emissions from any source that
burned less than 90 per cent of the
subcategory-defining fuel when
determining the average emissions level
of the best performing sources in setting
MACT floors for existing sources. And
when it set a subcategory’s MACT floors
for new sources, the Agency declined to
consider the emissions levels from any
source that did not burn 100 per cent of
the fuel.’’ Id. Because of this, ‘‘several
sources excluded from the MACT floor
determination were among the best
performing sources (or, in some cases,
the single best performing source) in
that fuel-based subcategory.’’ Id. The
court concluded that because the Clean
Air Act requires the EPA to ‘‘set the
MACT floor at the level achieved by the
best performing source, or the average of
the best performing sources, in a
subcategory,’’ when ‘‘the EPA includes
a source in a subcategory, it must take
into account that source’s emissions
levels in setting the MACT floor,’’ no
matter what percentage of subcategorydefining fuel that source burns. The D.C.
Circuit therefore ‘‘vacate[d] the MACT
standards for all major boiler
subcategories that would have been
affected had the EPA considered all
sources included in the subcategories.’’
Id. at 632.
The D.C. Circuit subsequently granted
EPA’s motion for rehearing on remedy,
withdrew its vacatur, and instead
remanded for the EPA ‘‘to identify those
standards for which the MACT floor
would have differed if the EPA had
included all best-performing sources in
each subcategory in its MACT-floor
analysis’’ and to ‘‘revise those standards
consistent with our July 29, 2016
opinion in this case.’’ 844 F.3d at 270.
Therefore, these standards have
remained in effect since the court’s
decision.
The court in U.S. Sugar also
remanded the use of CO as a surrogate
for non-dioxin organic HAP to the EPA
for the limited purpose of addressing
public comments on the potential
availability of post-combustion control
technologies that could control CO. Id.
at 628–30. As the D.C. Circuit
explained, ‘‘the EPA used carbon
monoxide (CO) as a surrogate for several
non-dioxin/furan organic HAPs when
the Agency set the MACT floors for
major boilers. In support of this
approach, the EPA found that both CO
and these HAPs were the products of
‘incomplete combustion.’ The Agency
concluded as a result that CO was a
reasonable surrogate because: (1)
minimizing CO emissions would
minimize these HAPs; (2) methods used
for the control of these HAP emissions
would be the same methods used to
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control CO emissions (i.e., good
combustion or using an oxidation
catalyst); (3) standards limiting CO
emissions would result in decreases in
these HAP emissions; and (4)
establishing emission limits for
individual organic HAPs would be
impractical and costly.’’ Id. at 628
(citing 2010 Proposed Major Boilers
Rule, 75 FR 32018). The environmental
petitioners argued ‘‘that the EPA has not
adequately explained how setting
emission standards for CO will . . . set
emission standards for organic HAPs at
the average level achieved by the best
performers with regard to those HAPs.’’
Id. The D.C. Circuit agreed, concluding
that ‘‘during notice and comment, the
EPA failed to directly consider and
respond to several comments that
introduced evidence suggesting that
other control technologies and methods
could be effectively used to reduce HAP
emissions without also impacting CO
emissions, or vice versa.’’ Id. at 629.
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, asking
the Agency to better explain its analysis
supporting its decision. Sierra Club v.
EPA, 884 F.3d 1185. As the D.C. Circuit
explained, in promulgating ‘‘regulations
that indirectly control a group of organic
pollutants by limiting carbon monoxide
emissions as a proxy for the targeted
pollutants,’’ and ‘‘[a]fter calculating
emissions limits for the organic
pollutants by reference to the amount of
carbon monoxide emitted by the best
performing boilers in each subcategory,
EPA concluded that the lowest of the
carbon monoxide limits were too low,
so it substituted a single, higher limit
that it deemed sufficient to control the
pollutants.’’ Id. at 1189. The D.C. Circuit
concluded that the ‘‘EPA did not
adequately justify its change of direction
on the carbon monoxide limits because
it failed to explain how the revised
limits would minimize the targeted
pollutants to the extent the Clean Air
Act requires.’’ Id. On August 24, 2020,
the EPA published a notice of proposed
rulemaking (NPRM) to address these
issues remanded by the D.C. Circuit,
and to make several technical
clarifications and corrections (85 FR
52198). Section 112 of the CAA
establishes a regulatory process to
address emissions of hazardous air
pollutants (HAP) from stationary
sources. CAA section 112(d) requires
the Agency to promulgate technologybased national emission standards for
hazardous air pollutants (NESHAP) for
major sources. ‘‘Major sources’’ are
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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). The EPA 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.
III. Summary of Final Action and
Significant Changes Since Proposal
In this action, we are finalizing
amendments to certain emission limits
for new and existing boilers and process
heaters. Most of these changes are
identical to the emission limits that
were proposed. As discussed further
below at sections III.A.3 (HCl) and
III.A.4 (PM), three of the emission limits
have been revised since proposal
following consideration of public
comments received—New-Solid (HCl),
New-Liquid (HCl), and Existing-Biomass
Fluidized Bed (PM). We are also
providing additional explanation to
support the use of CO as a surrogate for
organic HAP and to set a minimum CO
emission limit of 130 ppm. In addition,
we are finalizing approval of an
alternative monitoring provision
allowing for use of CO2 as a diluent in
lieu of O2 when a continuous emission
monitoring system (CEMS) is used to
comply with an emission limit. We are
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also finalizing a small number of
technical corrections based on our
proposed action and our consideration
of public comments received.
A. Revisions to MACT Floor Emission
Limits
On July 29, 2016, the D.C. Circuit
issued its decision in U.S. Sugar Corp
v. EPA. In that decision, the court
vacated those MACT limits where it
held that the EPA had improperly
excluded certain units in establishing
the emission standards. Specifically, the
court vacated all MACT limits where
the EPA had included certain units in
a subcategory but excluded those same
units from its assessment of the
subcategory’s best performing sources.
On December 23, 2016, the D.C. Circuit
amended its July 29, 2016 decision,
remanding those limits instead of
vacating them, and ordering the Agency
‘‘to identify those standards for which
the MACT floor would have differed if
the EPA had included all bestperforming sources in each subcategory
in its MACT-floor analysis’’ and to
‘‘revise those standards consistent with
our July 29, 2016 opinion in this case.’’
844 F.3d at 270.
Prior to the U.S. Sugar decision, on
August 20, 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 upper
prediction limit (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 Boiler Rule,
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, EPA’s
Response to Remand of the Record for
Major Source Boilers,2 that provided a
detailed rationale to use the UPL as the
basis of setting a MACT floor for new
and existing sources. The methodology
and the explanation in the
memorandum were upheld by the D.C.
2 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3892.
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Circuit in U.S. Sugar v. EPA. 830 F.3d
at 639.
Accordingly, the EPA is finalizing
changes to emission limits for new and
existing boilers and process heaters.
These changes address the court’s
concern regarding co-firing units that
were included in a subcategory but
excluded from consideration of that
subcategory’s best-performing sources in
the 2013 analysis. In addition, these
changes apply the UPL to the MACT
floor analysis for limited datasets as
explained in EPA’s August 2019,
memorandum titled ‘‘Approach for
Applying the Upper Prediction Limit to
Limited Datasets for Boilers and Process
Heaters at Major Sources.’’
1. Overarching Methodology and
Dataset Basis
In the 2020 proposal, the EPA based
its revised analysis to address the
remand on the same dataset used as the
basis for the 2013 final rule.3 4 The 2013
final rule incorporated electronic
reporting requirements into the rule. As
a result, numerous emission test reports
and other compliance data are now
available through the Compliance and
Emissions Data Reporting Interface
(CEDRI) and WebFIRE.5 However, since
the revisions to the MACT floor analysis
were conducted solely to address the
remand in U.S. Sugar by correcting the
calculations the court found
impermissible, the EPA did not update
its dataset to incorporate CEDRI
compliance data into its revised MACT
floor analysis.
While the EPA proposed to maintain
the same dataset basis as the 2013 rule,
the revisions to the rankings of
emissions information to identify the
best-performing units to include in the
MACT floor calculation 6 required that
the EPA conduct a more detailed review
of the data available for the units in the
dataset that had previously been
excluded from the rankings, focusing on
the newly identified best performers in
3 See
85 FR 52203.
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). See Docket ID Item No. EPA–HQ–OAR–
2002–0058–3830.
5 U.S. Environmental Protection Agency.
Compliance and Emissions Data Reporting Interface
(CEDRI) https://www.epa.gov/electronic-reportingair-emissions/cedri and WebFIRE database https://
www.epa.gov/electronic-reporting-air-emissions/
webfire.
6 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–0815 for background on how the EPA
calculates MACT emission limits, along with the
docketed memorandum, Revised MACT Floor
Analysis (2021) for the Industrial, Commercial, and
Institutional Boilers and Process Heaters National
Emission Standards for Hazardous Air Pollutants—
Major Source.
4 Emissions
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the 2020 proposal. While reviewing the
underlying emissions test reports, the
EPA corrected some database errors,
filled information gaps on relative heat
inputs from individual fuel types for
certain co-fired fuel blends in order to
verify that units did indeed belong to a
specific fuel subcategory based on
background combustion process
information provided in the test reports
or database fuel heat input background
tables, and adjusted CO instrument span
measurements since some of the revised
rankings showed test run values that
were incorrectly reported as zero, nondetect, or negative in the database. The
CO instrument span establishes the
appropriate representative detection
level (RDL) to use in the MACT floor
calculations and the underlying
emissions test reports in the record
typically contained the span
information. In some cases, when the
span information was not available,
default span values were assigned as
discussed in the memorandum,
Incorporating Measurement Error in
Reported Carbon Monoxide (CO) and
Total Hydrocarbon (THC) Data (Revised
August 2012).7 These adjustments were
needed to ensure that we could use the
data from the newly identified best
performers. Had these units been
identified as best performers in the
original rulemaking, the EPA would
have conducted a similar review of the
test data and made the same corrections
and adjustments. These data had not
been previously scrutinized since they
were not used in the original UPL
calculations. While corrections were
made to the original dataset for the
purposes of revising UPL calculations
for this final rule, no recent compliance
data after January 31, 2013 (e.g.,
emission test reports and other
compliance data available through
CEDRI and WebFIRE) were incorporated
into the rankings or UPL calculations for
these final MACT floor emission
standards, for the reasons explained
later in this subsection.
Commenters both agreed and
disagreed with the EPA’s use of the
original 2013 dataset for this reanalysis
of the emission limits. Some
commenters provided limited, specific
examples of where they believed
additional data should be incorporated
to provide additional emission test run
variability in cases where there are
limited datasets. However, these same
commenters also agreed that EPA’s use
of the 2013 dataset is reasonable. These
commenters pointed out that the court’s
decision in U.S. Sugar directed the EPA
to correct its analysis of the 2013 dataset
that established the emissions
standards, not to collect new data.
Another commenter disagreed with
the proposed approach to base the
revisions to the MACT floor analysis on
data from the 2013 final rule. The
commenter claims the data is obsolete
and ignores several years of compliance
data available in CEDRI. This
commenter did not dispute the EPA’s
methodology in calculating revised
MACT standards consistent with the
D.C. Circuit’s opinion in U.S. Sugar v.
EPA. The commenter’s criticism was
that the EPA should have considered
additional data beyond those contained
in the 2013 database for the remanded
rule, and they claimed that, in fact,
section 112(d) of the CAA requires the
Agency to consider compliance data in
its action on remand.
Another commenter also requested
that the EPA consider certain additional
data. The commenter stated that, ‘‘it is
appropriate to include only information
that is relevant for setting the floor or
identifying appropriate variability and
exclude data that represents postpromulgation changes made to existing
sources,’’ 8 and that including the latter
data would inappropriately redefine a
standard based on actions taken to
comply with such standard. However,
the commenter believes that the EPA
should not ignore units for which it has
emissions information without
justifying why the result from more
limited data is sufficient. The
commenter cites section 112(d)(3)(A) of
the CAA, which requires that the MACT
floor be no less stringent than the
average emission limitation achieved by
the best performing 12 percent of the
existing sources for which the
Administrator has emissions
information.
The commenters claiming that the
EPA must consider on remand
additional data beyond the 2013 dataset
that was used to establish the 2013
standards which were before the court
misconstrue the D.C. Circuit’s
instructions in its decision remanding
those standards to the EPA. The court
stated that on remand, the EPA must
‘‘identify those standards for which the
MACT floor would have differed if the
EPA had included all best-performing
sources in each subcategory in its
MACT-floor analysis.’’ U.S. Sugar v.
EPA, 844 F.3d 268 (2016) (granting
EPA’s motion for rehearing). The court
further instructed the EPA to ‘‘revise
those standards consistent with’’ the
court’s opinion. Id. Nothing in the
7 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3833.
8 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3969.
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court’s opinion or in its grant of
rehearing instructs or requires the EPA
to initiate a new standard-setting
process or to assemble additional data.
Rather, the remand was targeted to only
those standards affected by the court’s
decision, and the court did not address
the question of whether the EPA
should—let alone must—consider data
that did not exist at the time the
challenged rule was issued. In contrast,
the D.C. Circuit vacated—rather than
remanded—the EPA’s 2004 emissions
standards for commercial and industrial
boilers because it anticipated a
‘‘wholesale revision’’ of the rule would
be required. NRDC v. EPA, 489 F.3d
1250, 1262 (2007). Here, the court
neither vacated the standards, nor
indicated that it anticipated
consideration of additional data.
The EPA further disagrees that section
112(d)(3)(A)’s reference to sources ‘‘for
which the Administrator has emissions
information’’ requires consideration of
additional data beyond the 2013 dataset,
such as compliance data. That
qualifying language is intended to
ensure that the EPA need not obtain
emissions data from 100 percent of the
source category or subcategory in order
to identify the best performing 12
percent of the source category,
consistent with the overall
Congressional intent in enacting the
1990 amendments to section 112 to
prevent delay in regulating emissions of
hazardous air pollutants. Rather, the
EPA could identify the best performing
12 percent of the sources for which it
had emissions data, even if the Agency
did not have emissions data for all the
sources in the source category or
subcategory and could set standards on
that basis without having to collect
information from all sources. In other
words, the language the commenter
refers to does not compel collection or
consideration of additional data,
particularly here, where the EPA is
revising standards solely in response to
a court remand on a very specific,
limited issue. The EPA further notes
that some commenters would have the
EPA selectively consider additional
data, such as data showing additional
variability. For example, one commenter
claims that the EPA must consider
compliance data only for the purpose of
accounting for variability, but not
otherwise. The EPA does not agree that
it would be reasonable or appropriate to
consider compliance data only to
account for additional variability.
Where the EPA uses data for the UPL
calculation, it uses that data for
purposes of calculating the floor as well
as for accounting for variability, and it
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would not be appropriate to take a
different approach here. As explained
above, in this action the EPA is only
correcting the flaw in its 2013 final rule
analysis identified by the U.S. Sugar
court in response to the court’s remand.
Further, while this action is limited to
the remand, the Agency disagrees that,
as a general matter, data representing
compliance actions taken by sources to
meet a previous standard are necessarily
inappropriate to consider when revising
a standard. However, that question is
not at issue here.
The EPA’s approach is reasonable
given the limited nature of the remand.
In addition, if the EPA were to revise
the affected standards using newer
emissions information, it could result in
the potentially inequitable outcome of
some units being subject to more
stringent standards solely because of the
EPA’s error in its initial MACT floor
calculations, while other units
unaffected by the court decision would
remain unchanged. Revising all of the
boiler MACT standards, including the
standards that have not been remanded,
would require EPA to incur a significant
resource burden and could result in
wholesale changes to standards that
were largely upheld by the D.C. Circuit.
Given its other obligations under the
statute and the EPA‘s determination that
using new data is unnecessary to
respond to the remand, the EPA has
chosen to maintain the original data set
for purposes of calculating standards.
The revisions incorporate the co-fired
boilers that met the subcategory
definition using a threshold of at least
10 percent of a subcategory-defining
fuel, on an annual heat input basis, but
were excluded from the ranking analysis
in the 2013 final emission standards.
The D.C. Circuit in U.S. Sugar stated
that, if the EPA includes a source in a
subcategory, it must consider whether
any source in that subcategory is a bestperforming source which would then
need to be accounted for in setting the
MACT floor. U.S. Sugar v. EPA, 830
F.3d at 631. The final standards fully
incorporate these sources in the
development of standards as required by
the remand.
2. UPL Methodology for Limited
Datasets
Some of the MACT floor emission
limits the EPA proposed were based on
datasets with less than 7 test runs
(‘‘limited datasets’’). There were limited
datasets for the following subcategories
and pollutants for both existing and new
sources: process gas (Hg, HCl, total
selected metals (TSM), and PM),
biomass suspension burner (TSM), dry
biomass stoker (TSM, PM, and CO), and
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coal fluidized bed coal refuse (CO).
Limited datasets also existed 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).
On remand, these limited datasets were
reviewed in additional detail to
determine whether it was appropriate to
make any modifications to the UPL
approach used to calculate the MACT
floors.
In addition to the proposed MACT
floors involving limited datasets, the
EPA also conducted a similar, more
detailed review of the new source
standards to evaluate if the UPL
calculations required any adjustments to
ensure that the resulting emission
standards for new sources were not less
stringent than for existing sources.
Based on this review, the EPA found
that the revised emission limits for three
new source subcategories and pollutants
did not reasonably account for
variability and some changes were made
to be consistent with EPA’s Approach
for Applying the Upper Prediction Limit
to Limited Dataset Boiler and Process
Heaters at Major Sources 9 to avoid the
anomalous result the Court identified in
NACWA v. EPA 10 where the calculated
new source floor was less stringent than
the existing source floor: These new
source subcategories and pollutants are
the following: solid (HCl), wet biomass
stokers (TSM, PM), and biomass
fluidized beds (PM).
The only comments received on the
proposed methodology for analyzing
limited datasets were made in the
context of the new source solid fuel HCl
emission limit. Those comments are
summarized in section III.A.3 of this
preamble.
The EPA is finalizing limited
revisions to certain standards to address
the specific issue identified by the court
in NACWA v. EPA. The EPA is
finalizing, as proposed, adjustments
needed to three new source standards—
Solid (HCl) and wet biomass stokers
(TSM, PM), and biomass fluidized beds
(PM)—to ensure that the new source
floor is no less stringent than the
existing source floor.11 Additional detail
about the determinations made at
9 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3946.
10 See National Assn. of Clean Water Agencies v.
EPA (NACWA) 734 F 3d 1115.
11 See 85 FR 52205–52207.
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proposal are discussed in the docketed
memorandum and no further analyses
were needed as part of the final rule.12
3. Solid and Liquid Fuel HCl Emission
Limits for New Sources
The proposed emission limits for HCl
in the new source solid fuel and liquid
fuel subcategories were both based on a
value equal to 3 times the representative
detection level (RDL) because the
calculated UPL from the best performing
similar source was less than this
value.13 In each case, the RDL value
established for these two subcategories
was based on the sampling times of the
single best performer in each
subcategory. For HCl, the detection level
decreases with longer sampling times.
For liquid fuels, the best performer had
a 4-hour stack test, resulting in a 3 times
RDL (3x RDL) of 5.4E–05 lb/MMBtu. For
solid fuels, the best performer had a 1hour stack test with an average oxygen
concentration of 10.2 percent, resulting
in a 3x RDL of 3.0E–04 lb/MMBtu.
In the case of liquid fuel boilers, the
3x RDL value was multiplied by a fuel
variability factor to establish the MACT
floor because the best performing unit
had paired test data and fuel analysis
data 14 to compare to fuel analysis used
at the unit over time. The EPA also
reviewed the data for the best performer
in additional detail given that this best
performing unit,
‘‘LAShellChemicaGeismar, Furnace F–
S801,’’ had a limited dataset of 3 test
runs. The EPA concluded that this unit
was indeed a best performing unit.15
In the case of solid fuel boilers, the
EPA proposed that the unit with the
second lowest emission test results but
the lowest variability,
‘‘TXDibollTemple-Inland, PB–44’’ (PB–
44) was the best performing similar
source.16 This unit did not have paired
test data and fuel analysis data to
develop an appropriate fuel variability
factor, so no fuel variability factor was
applied to this emission limit.
12 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3946.
13 In cases where the calculated UPL value is less
than three times the representative detection level
(3x RDL), where the RDL is the average detection
level of the best performing sources, the limit is
determined to be equivalent to the 3x RDL value.
Such a limit ensures measurement variability is
addressed and provides a limit that has a
measurement imprecision similar to other EPA test
methods.
14 Paired fuel and testing data means that there is
an analysis of the fuel that was being utilized
during the emissions testing. Unpaired fuel data
may be representative of fuel burned at the unit, but
not specifically the fuel burned during the
emissions testing.
15 See 85 FR 52206.
16 Ibid.
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Comment: Two commenters stated
that the 3x RDL emission limit for HCl
should have been calculated differently.
One of the commenters provided
specific suggestions, indicating they
believed it is not appropriate for the
EPA to set a RDL based on the operation
of the top performing boiler alone. The
commenter suggested that a more
representative approach to setting a
detection limit would be to derive an
RDL associated with all non-detect
emission tests for the best-performing
units in the subcategory.
Response: The EPA agrees with the
commenter that sample time data
should be analyzed for the entire top 12
percent of units, not just the single best
performer. However, the EPA disagrees
with the commenter’s suggested
approach which considers only data
that were reported as non-detect (i.e.,
the emissions results were below the
detection level of the instrumentation)
instead of all available reported
pollutant-specific method detection
levels from the best performing units in
each subcategory. As we stated in the
docketed memorandum, Data and
Procedure for Handling Below Detection
Level Data in Analyzing Various
Pollutant Emissions Databases for
MACT and RTR Emission Limits
(Revised 2012), our approach,
‘‘minimizes . . . effect of a test(s) with
an inordinately high method detection
level (e.g., the sample volume was too
small, the laboratory technique was
insufficiently sensitive, or the procedure
for determining the minimum value for
reporting was other than the detection
level).’’ 17
Therefore, the EPA revised the 3x
RDL values for new source solid and
new source liquid HCl 3x RDL to reflect
data from the top 12 percent of boilers.
The data were pulled from the 2013
dataset and supporting test report files
from the docket from the 2013 final rule.
Revised data and analysis for the 3x
RDL values are found in the docketed
memorandum Revised (2021) Analysis
of Minimum Detection Levels from
Industrial, Commercial, and
Institutional Boilers and Process Heaters
National Emission Standards for
Hazardous Air Pollutants—Major
Source. The revised methodology and
changes to the underlying data used for
the 3x RDL calculations resulted in a 30
percent lower 3x RDL value than what
was proposed for solid fuels, with the
3x RDL decreasing from 3.0E–04 to
2.1E–04 lb/MMBtu. For liquid fuels, the
revised 3x RDL value is 122 percent
higher than what we proposed,
17 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3839.
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increasing from 5.4E–05 to 1.2E–04 lb/
MMBtu.
Comment: Several commenters
disagreed with the EPA’s approach and
rationale for selecting PB–44 as the best
performing source for new solid fuel
units, arguing that the solid fuel HCl
limit calculations need to better account
for natural variability in biomass fuel
chloride levels as well as operational
variability. Commenters noted that PB–
44 only has a single three run test and
it has a homogenous dry biomass fuel,
sourced from on-site particleboard
byproducts.
Commenters differed in their
suggestions for what unit should be the
best performing similar source. Some
commenters suggested that Wellons
Boiler was the best performing boiler,
despite the larger variance in its HCl
emissions. Some commenters made
suggestions on how to adjust the
Wellons Boiler data with additional data
outside of the 2013 dataset. Other
commenters suggested that other units
in the top 12 percent for existing solid
fuel HCl best performers were better
choices than PB–44.
With regards to fuel variability, some
commenters noted that PB–44 has only
three test runs available and that a
dataset with six test runs is superior to
a dataset with three. One commenter
also added that both PB–44 and Wellons
Boiler do not have any HCl add-on
control devices and the variation in
emissions is directly related to fuel
chloride content. The commenter
argued that if the EPA had more data for
PB–44, the variability in its HCl
emission rates might be much higher
and noted that variability can be
determined more accurately with more
test runs. This commenter also
emphasized that the emissions of HCl at
the lowest emitting unit are related to
chloride variability in the fuel and not
to the performance of any add-on
control device. The commenter
suggested several ways to better
incorporate chloride variability in
biomass fuels in its detailed comments.
One commenter further disagreed
with the EPA’s selection of PB–44
which had the second lowest emission
test as the best performing similar
source in its limited dataset analysis
because it has lower variance in test
results. The commenter suggested that
variance is not the only consideration in
the selection of a best performing
similar source, especially where
emissions are dictated by the fuel
chloride variability and not by the use
of a control device. This commenter also
suggested that the EPA’s selection of
PB–44 to establish the new-source floor
directly contradicts its assessment of
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long-term fuel variability by ignoring
data related to fuel variability the
Agency had previously argued was
necessary. This commenter also
suggested that the EPA’s decision to
finalize a standard based on limited
dataset with only the UPL adjustment
would be arbitrary, given that the fuel
content must be taken into account to
determine the emissions level that
boiler actually achieved every day and
under all operating conditions.
Response: The EPA disagrees with
commenters that the PB–44 unit does
not reflect the emissions control that is
achieved in practice by the best
controlled similar source. As discussed
in section III.A of this preamble, the
court remanded for further explanation
the UPL methodology in NACWA v.
EPA, in part for the EPA to explain how
the UPL was appropriate for limited
data sets in the face of the ‘‘apparently
illogical’’ results where the emission
limit for new sources was less stringent
than the emission limit for existing
sources. NACWA v EPA, 734 F.3d at
1144. Following the NACWA decision,
the EPA issued the UPL memo and the
limited data sets memo to provide the
explanations requested by the court, and
both approaches have been
subsequently upheld by the D.C. Circuit.
The EPA has applied the UPL and the
limited data set approach in calculating
the solid fuel HCl limit. The EPA could
not determine that the Wellons Boiler,
which commenters point out has more
test runs available than the PB–44 unit,
was the best performing similar source
because it yielded the same ‘‘apparently
illogical’’ result that the NACWA court
questioned, i.e., a new source limit that
would be less stringent than the
corresponding existing source limit, due
to the variance in its data. In such
circumstances, the EPA’s limited data
set approach provides that the EPA will
further evaluate the individual dataset
to ensure that the uncertainty associated
with it does not cause the emissions
limit to be so high that it does not reflect
the emissions performance of the best
performing similar source, for new
source MACT standards.
Moreover, the EPA has broad
discretion to identify best performing
sources, and it is reasonable to consider
variability in emissions when choosing
the ‘‘best’’ sources from an emissions
perspective. For example, a source
could have the lowest average emissions
level based on a single very low data
point, but other very high emissions
points. It is reasonable for the EPA to
consider, in that circumstance, that a
second source with a slightly higher
average emissions level but consistently
low emissions is a ‘‘better’’ performer
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than the first source. Consistent with the
previous MACT floor methodology, the
EPA has determined that MACT floors
based on a single source must be based
on at least three runs of test data to
ensure that adequate variability can be
incorporated. The EPA has not thrown
out other MACT floor emission limits
that are based on a single three run
test.18 PB–44 has three valid test runs
and it is the unit with the second lowest
emissions test average results but has a
variance that is 5 times lower than the
Wellons boiler, and it did not yield a
new source limit that is less stringent
than the existing source limit. Therefore
the EPA continues to conclude PB–44 is
the best performing similar source for
new solid fuel units.
The EPA further disagrees with
commenters that it should incorporate
fuel variability into the revised emission
limit by evaluating fuel variability from
other units in the 2013 dataset. We have
previously stated that we can only apply
a fuel variability factor when we have
paired test data and fuel analysis data.19
PB–44 had no paired fuel analysis data
with its single 3-run HCl emission test
in the 2013 dataset, so a fuel variability
factor could not be developed according
to the historical methodology used in
the Boiler Rule.
The solid fuel subcategory
encompasses a wide variety of boilers
and process heaters and many of these
units have achieved this emission level
in practice, though each unit, depending
on facility- and unit-specific
circumstances, may employ different
fuel blends and control devices to do so.
18 Revised MACT Floor Analysis (November 2011)
for the Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission
Standards for Hazardous Air Pollutants—Major
Source. Revised November 2011. See Docket ID
Item No. EPA–HQ–OAR–2002–0058–3387.
19 The EPA explained the limited nature of using
only paired fuel variability data for the basis of its
fuel variability factors in the original 2010 proposal.
See Maximum Achievable Control Technology
(MACT) Floor Analysis (2010) for the Industrial,
Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for
Hazardous Air Pollutants—Major Source. See
Docket ID Item No. EPA–HQ–OAR–2002–0058–
0815. The EPA modified its approach slightly to
address comments received on the proposed fuel
analysis variability methodology as explained in the
final rule (76 FR 15627) but never changed its
fundamental criteria of looking only at paired fuel
analysis data. As noted in the December 2011
reconsideration proposal, the EPA continued a
consistent fuel variability methodology and at this
juncture only ‘‘[s]mall changes to fuel variability
. . . to accommodate the new TSM standard and
comments received during the reconsideration
process’’ were made, see Docket ID Item No. EPA–
HQ–OAR–2002–0058–3387. When the EPA issued
revised limits in the January 2013 final rule based
on submitted data corrections or new data, it noted
that the new data was incorporated that resulted in
revised values, but the general MACT floor setting
methodology remained the same (78 FR 7151).
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Both the revised CEDRI compliance
dataset and the 2013 dataset used to
establish the MACT floor calculations
present several examples of units in the
solid fuel subcategory that have
achieved this limit in practice.
According to compliance data submitted
to EPA via CEDRI through December 31,
2020, most of the new units in the solid
fuel subcategory are meeting this more
stringent emission limit that is based on
a 3x RDL value.20 Of the new units with
test data, 71 percent (10 of the 14 units
with HCl compliance test data) are
meeting the revised 3x RDL value.
The EPA also disagrees with some of
the commenter suggestions to bring in
new data from outside the 2013 dataset
to serve a targeted purpose for this
single subcategory. The EPA explains
earlier in this document why the
Agency is not required to consider new
data for purposes of this action.
4. Biomass Fluidized Bed PM Emission
Limits for Existing and New Sources
For existing biomass fluidized beds,
we proposed to make the PM emission
limit more stringent, decreasing from
1.1E–01 to 2.1E–02 lb/MMBtu. The
existing source floor was based on the
top 5 units in the subcategory since the
subcategory had fewer than 30 sources.
The units that were part of the top 5
changed after we re-ranked the data to
address the U.S. Sugar remand.
For new biomass fluidized beds, we
also proposed to make the PM emission
limit more stringent, decreasing from
9.8E–03 to 4.1E–03 lb/MMBtu. The unit
with the lowest minimum test average
was ‘‘ORGeorgiaPacificWaunaMill,
EU35—Fluidized Bed Boiler’’ (Wauna
boiler). The Wauna boiler had six
separate tests in the boiler dataset.
However, the calculated UPL for the
Wauna boiler was 3.2E–02 lb/MMBtu,
which exceeded the UPL calculated for
existing units in the same subcategory,
which was 2.1E–02. Since the new
source floor was less stringent than the
existing source floor, the EPA reviewed
the data further to evaluate if the unit
truly reflected the best controlled
similar source 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. The EPA conducted
additional analysis and determined that
the unit with the second lowest
minimum test, ‘‘WIGPGreenBay2818,
B10—Wastepaper Sludge-Fired Boiler
10’’ (B10), was the best controlled
20 Revised (2021) 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.
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similar source because it had a variance
three orders of magnitude lower than
the Wauna boiler and did not yield a
limit less stringent than the existing
source limit.
Comment: One commenter noted that
the EPA included 15 p.m. emission tests
for the unit LAGPPortHudson,
EQT0109—No. 6 CFB Boiler (Port
Hudson boiler), including two 2007
tests in which the dry scrubber was off
for one test and on for the other, and the
EPA only included data from the test
where the scrubber was off in the UPL
calculations. The commenter stated that
both tests should be included in the
UPL calculations.
Response: We reviewed the docket
record to evaluate the commenter’s
concerns with the test runs included for
the Port Hudson boiler. The Port
Hudson boiler had five different tests
included in the UPL calculations at
proposal. Four of the five tests, dated
September 11, 2007, December 18, 2008,
December 19, 2008, and July 29, 2009,
were all conducted with the sorbent
injection system control device
operating. The fifth test in August 2007
was conducted with the scrubber
control device off. Given that the
scrubber operating reflected the more
common unit operations, we also
evaluated CEDRI data for the purpose of
verifying that the unit typically operates
with its sorbent injection system
operating. We disagree with the
commenter that we should use the tests
from August 2007 with both the sorbent
injection control operating as well as
off. Since this unit typically operates the
sorbent injection system control device,
only the tests conducted while this
control device is operated are
representative of the emission levels
and typical operations employed by this
source. Introducing statistical variability
in UPL calculations by mixing test
results for different control
configurations would be inconsistent
with the MACT floor methodology 21
since the unit typically conducts its
compliance testing with the control
system operating. When we evaluated
the August 2007 test report available in
the docket in more detail, we found that
the August 2007 test report had four
different test scenarios. Scenario 1 and
2 were the only scenarios firing biomass
fuels (both fired a combination of
biomass and petroleum coke, but met
the threshold of at least 10 percent heat
21 Some facilities submitted emission test data
based on previous control configurations that are no
longer installed on the unit. Emission data reported
while using these previous control configurations
were not used to establish the MACT floor. See
Docket ID Item No. EPA–HQ–OAR–2002–0058–
3387.
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input from biomass). The test scenario
included in the proposal analysis had
the sorbent injection system turned off.
For the reasons discussed above, we
replaced the August 2007 test with the
test scenario which had the sorbent
injection system turned on. After
replacing this test scenario, the Port
Hudson boiler was no longer part of the
top five boilers in the existing source
floor calculations. The Port Hudson
boiler was removed from the existing
source floor calculation because it had
the eighth lowest mean emission test
after reviewing and correcting the test
scenarios used in the analysis, based on
public comment. The boiler that now
had the fifth lowest mean emission test
is PAPHGlatfelter, PB5 (PB5 boiler), so
we added the two emission tests from
the PB5 boiler into the analysis for the
UPL calculation for the existing source
MACT floor.
Comment: Two commenters requested
a data correction for the 2006 test from
the Wauna boiler. The commenters
noted that the PM test results in the
2013 dataset and MACT floor ranking
were listed incorrectly as lb/MMBtu in
the MACT floor analysis. They pointed
to the supporting test report, where the
values were actually in units of grains
per dry standard cubic foot (gr/dscf),
corrected to 7 percent oxygen, instead of
lb/MMBtu. These commenters requested
that the EPA revise the UPL calculation
after correcting the units of measure for
the 2006 test.
Response: We reviewed the docket
record to verify the units of measure for
the 2006 Wauna boiler test and agree
with the commenters that a correction is
needed to convert the gr/dscf into units
of lb/MMBtu. We made this correction
in the revised UPL calculation for both
new and existing sources.
Comment: One commenter stated the
Wauna boiler’s 2004 stack test is an
outlier and should be excluded from the
data. The commenter stated that the
EPA should remove this test and
recalculate the UPL with the remaining
15 test runs from the Wauna boiler.
Response: We reviewed the 2004
Wauna boiler test that the commenter
stated should be excluded to assess
whether or not this test is in fact an
outlier. The 2004 test had the same test
method and length of the test runs as
the other five tests. In addition, none of
the other five tests subtracted negative
filter weights or had weights less than
1 milligram. As the emissions limit is
expressed in terms of emissions per heat
input, we checked both the emissions
and heat input data for outliers. Our
general outlier test is conducted at the
5% significance level in log space, and
when a value is found to be an outlier
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at this level, we exclude it from further
calculations. We conducted an outlier
test with ProUCL 22 and determined that
none of the PM emission test runs had
outliers, either in normal or in log
space, at the 1, 5, and 10% significance
levels. Observing that the heat input for
the 2004 test was between 57 and 66
percent lower than the heat input for the
other five tests in normal space, we
conducted an outlier test with ProUCL
and found that the total heat input for
2004 was an outlier at the 5 and 10%
significance levels for both normal and
log space. Because the heat input
component of the 2004 emissions test is
an outlier, we agree with the commenter
that the heat input and the
corresponding emissions value from this
test should be excluded as an outlier.
Therefore, we removed the 2004 test
data from the UPL calculation for both
new and existing sources.
After making the corrections to the
2006 Wauna boiler test, removing the
outlier 2004 Wauna boiler test, and
correcting for the appropriate tests for
the Port Hudson boiler control device
configurations, the existing source floor
value calculations have changed since
proposal. The revised emission
calculations for existing sources
considering these public comments and
related data changes have resulted in a
more stringent UPL calculation of 7.4E–
03 lb/MMBtu.
Comment: One commenter requested
that the EPA revise its determination for
the best performer for the new source
PM limit for biomass fluidized beds.
The commenter noted that the EPA
chose to base the new source floor on
the second-best performing unit, despite
having a more robust dataset for the top
performer. The EPA selected the unit
with the second lowest mean because it
stated that the unit with the lowest
mean (Wauna boiler) exhibited too
much variance in its emissions data.
The commenter noted that the dataset
for the second-best performer (B10)
offered only six test runs, while the
Wauna boiler had 18 runs and better
represented true variability at the unit.
The commenter argued that the MACT
floor should be based on the topperforming unit which utilizes the best
control technology, a fabric filter, and
pointed out that five of the six stack
tests for the Wauna boiler exhibit
consistent performance.
Response: Based on the data
correction made for the units of measure
for the 2006 test and removal of the
2004 test as an outlier, the calculated 99
22 ProUCL is a comprehensive publicly available
statistical software package. See https://
www.epa.gov/land-research/proucl-software.
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60825
percent UPL for the Wauna boiler
decreased from the calculation in the
proposed rule, from 3.2E–02 to 8.4E–03
lb/MMBtu. This revised UPL calculation
for new sources still yields an
anomalous result, as the new source PM
limit is less stringent than the 7.4E–03
lb/MMBtu PM limit for existing sources.
Consistent with the 2020 proposal,
the EPA conducted additional
investigation of the revised Wauna
boiler dataset to determine whether the
Wauna boiler was indeed the best
performing similar source. 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 the
highest variance among the top five
performing boilers in the existing source
floor, even after making the corrections
for the 2004 and 2006 test data noted
above. The variance is 7 times higher
than the unit with the second lowest
ranked mean, B10. The overall average
(considering all stack tests, not just the
minimum stack test average) for the
Wauna boiler is also higher than the
units with the second, third, and fourth
lowest mean emission test results. The
overall average for the Wauna boiler is
1.5 times higher than the second ranked
unit, B10. This information indicates
that the second ranked unit, B10, has a
more consistent level of emissions
performance than the Wauna Boiler, and
the resulting UPL calculations support
this. The calculated UPL is lower for
B10 than for the Wauna boiler. For these
reasons, we continue to conclude that
the Wauna boiler is not the best
performing source for this subcategory
and pollutant and we are finalizing B10
as the best performing source.
Therefore, the EPA is finalizing the
proposed PM emission limit of 4.1E–03
lb/MMBtu for new sources.
More complete details of the revised
analysis for both new and existing
source PM emission limits are included
in the docketed memorandum, Revised
MACT Floor Analysis (2021) for the
Industrial, Commercial, and
Institutional Boilers and Process Heaters
National Emission Standards for
Hazardous Air Pollutants—Major
Source.
B. Beyond-the-Floor Emission Limits
We proposed beyond-the-floor limits
for 16 subcategory and pollutant
combinations. We compared the revised
emission limits to the limits from the
2013 final rule to assess whether a
beyond-the-floor option was technically
achievable and cost effective. Typically
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we would assess technical achievability
and cost effectiveness by assessing
various levels of stringency of emission
reductions, technical achievability of
options and associated costs. For this
rule, for subcategories where the 2013
limit was more stringent than the MACT
floor limit calculated in the 2020
proposal, we reviewed compliance data
available through CEDRI and WebFIRE
to assess whether the more stringent
limit was being achieved in practice.
There were nine subcategory and
pollutant combinations for existing
sources and seven subcategory and
pollutant combinations for new sources
where compliance data showed boilers
that already achieved the 2013 limits.
Then, to assess whether compliance
with the 2013 limits was cost effective,
we reviewed the control devices
currently installed to determine if any
cost savings would occur should we
finalize the less stringent limit. In all
cases, the controls that were already
installed were the same types of
controls that would be required to meet
either the 2013 limits or the less
stringent limits calculated in the
proposed rule and, therefore, no
additional costs would be incurred to
meet the more stringent limits. As a
result, we proposed 16 emission limits
from the 2013 final rule as beyond-thefloor limits.
There were six limits in three
subcategories—new and existing units
for PM for Gas 2 units, TSM for biomass
suspension burners, and TSM for dry
biomass stokers—where the 2013 limits
were more stringent than the MACT
floor limits calculated for the proposed
rule, but recent compliance data were
not available. Since no data were
available, we did not identify any
beyond-the-floor options for these
subcategories and beyond-the-floor
limits were not proposed for these
subcategories. For TSM, sources have
the option to comply with either PM or
TSM emission limits. The lack of
available TSM data indicates that
sources in these subcategories are all
complying with the PM emission limits
rather than the alternative TSM limits.
The lack of available PM data for Gas 2
units indicates that sources are all
meeting the Gas 1 subcategory
definition.
Comment: One commenter suggested
that the EPA’s proposed approach for
the beyond-the-floor analysis does not
satisfy section 112(d)(2) of the CAA,
which requires the ‘‘maximum’’ degree
of reduction that is ‘‘achievable’’
considering cost and other factors
through all potential reduction
measures. The commenter noted that
the EPA only considered whether the
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newly recalculated floors were less
stringent than the emission levels that
were already being achieved, and if ‘‘no
additional costs would be incurred to
meet the more stringent limits,’’ then
the EPA set beyond-the-floor standards
which are more stringent than the floors
and are equivalent to the current
standards that these boilers have already
been meeting. The commenter
acknowledged that the EPA is correct to
recognize that the current limits are
achievable but argued that the EPA’s
analysis does not actually consider what
the ‘‘maximum’’ achievable reductions
are, such as what reduction levels are
achievable through use of cleaner fuels
or control technologies.
This commenter also stated that it is
unlawful that the EPA proposed to
weaken six limits since all of the units
subject to those limits have already been
in compliance with them for more than
three years. The commenter argued that
any standards that are less stringent
than the 2013 limits do not represent
the average emission levels achieved by
the relevant best performing units.
Response: We disagree with the
commenter that the beyond-the-floor
analysis does not satisfy section
112(d)(2) of the CAA. In 2013, the EPA
conducted a subsequent beyond-thefloor analysis, evaluating whether any
recalculated emission limits were less
stringent than the 2011 rule in order to
assess whether a beyond-the-floor
option was technically achievable and
cost effective. This analysis resulted in
nine beyond-the-floor limits.23 The
beyond-the-floor analysis conducted in
the proposal used the same
methodology and resulted in 16
proposed beyond-the-floor limits.24
Most of the recalculated emission
limits resulting from the U.S. Sugar
remand resulted in more stringent limits
compared to the 2013 final rule. For
these limits, the EPA continues to
believe the analysis in the 2011 rule is
reasonable, and the EPA received no
information during the comment period
to demonstrate it is not. Further, for
most affected standards where the EPA’s
recalculation of the UPL resulted in a
less stringent numeric limit, the EPA is
retaining the more stringent limit based
on its authority to set standards beyond
the MACT floor. This is a reasonable
approach where sources have been
complying with the 2013 standards,
thus demonstrating that the standards
are achievable, considering the factors
enumerated in section 112(d)(2) of the
23 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3843.
24 See Docket ID Item No. EPA–HQ–OAR–2002–
0058–3948.
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CAA. The only exception to this
approach is for alternative standards
where there is no demonstration that
any source has been complying with the
standard since the 2016 compliance
date because no units are in the
subcategory or no units have chosen to
utilize the alternative limits.
Based on this, additional analyses of
compliance data, and the lack of
information on additional control
technologies provided by the
commenter, we continue to believe that
our beyond-the-floor analysis is
appropriate, and we are finalizing the 16
beyond-the-floor limits as proposed.
We further disagree with the
commenter that it is unlawful to finalize
the six emission limits that were
recalculated to be less stringent than the
2013 standards. First, the court in U.S.
Sugar determined that the 2013 limits
were incorrectly calculated and
remanded the standards to the EPA. The
recalculated MACT floors are a result of
addressing deficiencies identified by the
U.S. Sugar court and additionally by the
NACWA decision on limited datasets.
Second, we did not identify any
beyond-the-floor options for these
subcategories. We found that no
biomass suspension burners or dry
biomass stokers have been using the
alternative TSM limit for compliance—
all units have been complying with the
PM limit. In addition, we found that no
units have been subject to the PM limit
in the Gas 2 subcategory and therefore
have no information to conclude that
additional reductions are achievable.
In addition, we note that while these
six recalculated limits are slightly less
stringent than the 2013 limits, in
practice they are not effectively
different. Affected sources would install
the same control technology to meet
either the remanded or the recalculated
emissions limits, despite the slight
increase in the recalculated limits.
Furthermore, no emissions increases are
expected to result from finalizing less
stringent units in these subcategories
since no sources exist that are subject to
the Gas 2 limit, or that are choosing to
meet the alternative TSM limits.
C. Revisions to Output-Based Emission
Limits
In the proposed rule, the EPA recalculated the corresponding outputbased emission limits to update the
limits in the fourth column of Tables 1
and 2 of the regulatory text. Revisions
were not required for all the proposed
emission limits due to rounding and the
small amount of change in the
corresponding input-based limit
between the 2013 limits and the limits
in the proposed rule. The memorandum,
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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.
We received no comments on the
proposed changes to the output-based
standards. Therefore, we are finalizing
the revisions to the output-based
emission limits as proposed. We have
revised output-based emission limit
calculations to reflect the changes made
to the corresponding input-based
emission limits for existing source
biomass fluidized bed PM and new
sources solid and liquid fuel HCl. The
memorandum, Alternate Equivalent
Output-Based Emission Limits for
Boilers and Process Heaters Located at
Major Source Facilities—2021 Revision,
which is available in the docket for this
action, provides details of the outputbased emission limit revisions since
proposal.
D. CO as a Surrogate for Organic HAP
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 remanded to the EPA to
adequately explain how CO acts as a
reasonable surrogate for non-dioxin/
furan organic HAPs. To be reasonable,
the emission standard set for the
surrogate must reflect what the best
similar source or the best 12 percent of
sources in the relevant subcategory
achieved with regard to the HAP. This
requires the surrogate’s emissions to
share a close relationship with the
emissions of the HAP. The court
identified that one crucial factor for
determining whether that close
relationship exists is the availability of
alternative control technologies that
reduce the HAP emissions without
impacting that of the surrogate or,
conversely, reduce the surrogate
emissions without impacting the HAP
emissions. The court stated that the EPA
could not conclude that CO acts as a
reasonable surrogate in this statutory
context without considering whether
the best performing boilers might be
using alternative control technologies
and methods that reduce organic HAP
emissions beyond what they achieve by
reducing CO alone. The court asked that
EPA address concerns raised in public
comments that alternative control
technologies might further lower HAP
emissions.
In response to this remand, the EPA
provided further explanation to
substantiate its finding that CO is an
appropriate surrogate for non-dioxin/
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furan organic HAP. In the proposed
rule, the EPA noted that available
control technologies for organic HAP
emissions are either combustion devices
or recovery devices. Combustion is the
more commonly applied option for
controlling organic HAP because it is
capable of high removal (destruction)
efficiencies and its effectiveness does
not depend on the makeup of the
organic HAP stream or the organic HAP
concentration. Recovery devices are not
applicable for all organic HAP and are
not effective in treating low organic
HAP concentration streams, i.e., the
levels of concentrations seen in sources
with good combustion practices.
In the proposal, we indicated that
none of the best-performing units
employ an add-on, alternative control
device that was installed for controlling
emissions of either organic HAP or CO.
While many industrial boilers and
process heaters employ post combustion
controls for particulate matter, acid
gases, and/or mercury, these add on
controls are not designed to affect
emissions of either CO or non-dioxin
organic HAP. In any case, any add-on
controls that are downstream of the
combustion chamber of the boiler would
be secondary controls that would only
be effective (if at all) if the upstream
primary control (the combustor) was
ineffective. The presence of CO in the
flue gas stream is an indicator of
inefficient and incomplete combustion.
The presence of non-dioxin organic
HAP (or other organic compounds) in
the flue gas stream would also be an
indication that the upstream
combustion process was inefficient and
incomplete (i.e., perfectly complete
combustion of an organic compound
would result in only CO2 as a carboncontaining product). The best
performing industrial boilers do not
employ downstream controls for CO or
non-dioxin organic HAP because the
primary control (the combustor) is
effectively destroying the non-dioxin
organic HAP and downstream controls
are not needed to achieve additional
reductions. Minimum CO concentration
in the flue gas stream is evidence of that
the combustion process is efficient and
effective. For these reasons, the Agency
continued to conclude that CO is a
reasonable surrogate for non-dioxin/
furan organic HAP.
Comment: Commenters stated that not
all organic HAP are products of
incomplete combustion. Some organic
HAP—such as polychlorinated
biphenyls (PCBs) and polycyclic organic
matter (POM)—can be present in the
raw materials before combustion or can
be generated outside the combustion
unit or within the combustion unit but
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outside of the flame zone. In addition,
different organic HAPs can be formed,
destroyed, or reformed in various
physical regions of diffusion flames and
in different zones of premixed flames.
Commenters stated that minimizing CO
emissions will not minimize emissions
of all organic HAP other than dioxins
and furans because not all organic HAPs
are formed or destroyed in combustion
and post-combustion zones in the same
fashion or like CO. The commenters
further claimed that underlying
formation and destruction of just CO in
the simplest of situations involves
several hundred reactions and tens of
individual species are involved. The
kinetics and thermodynamics become
far more complex for other organic
HAPs. Thus, the commenters argued,
there is no basis in combustion science
to presume that even any one organic
HAP—much less all of them will behave
similarly to CO. Specifically, the
commenters claimed, pollutants like
PCBs and POM/polycyclic aromatic
hydrocarbon (PAH) will not be
minimized by good combustion or
through using a post-combustion
oxidation catalyst.
Response: We agree with the
commenter that organic compounds—
and perhaps even organic HAP—are
present in the fuels (coal, biomass, etc)
used in industrial boilers. With regard
to the PCBs mentioned by the
commenter, we note that PCBs are
commonly known as ‘‘dioxin-like’’
organic compounds 25 and their
formation should similarly be limited by
the work practice standards established
for dioxins and furans. Regarding the
POM/PAH mentioned by the
commenter, these compounds are well
known to be products of incomplete or
inefficient (i.e., oxygen-starved or fuelrich) combustion.26 27 28 29 30 Similarly,
CO is also the product of inefficient
combustion. In an oxygen-rich
environment, complete and efficient
combustion will produce CO2 rather
than CO. Regardless of whether organic
HAP are present in the boiler’s fuel
before combustion, or whether they are
generated within the combustion unit,
all organic HAP would be destroyed
under complete and efficient
25 ‘‘Dioxins’’ are often described as ‘‘dioxins,
furans, and dioxin-like compounds’’.
26 Serban C. Moldoveanu, in Pyrolysis of Organic
Molecules (Second Edition), 2019.
27 T.A. Abrajano Jr., V. O’Malley, in Treatise on
Geochemistry, 2007.’’
28 Z. Fan, L. Lin, in Encyclopedia of
Environmental Health (Second Edition), 2011.
29 M. Huang, T.M. Penning, in Encyclopedia of
Food Safety, 2014.
30 Tarek Saba, in Introduction to Environmental
Forensics (Third Edition), 2015.
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combustion conditions. Therefore, the
presence of organic HAP in the boiler
emission flue gas stream would be the
result of incomplete combustion and
higher emissions of CO (relative to CO2)
would be expected.
We also disagree with the comment
that minimizing CO emissions will not
minimize emissions of all organic HAP
other than dioxins and furans. The
Agency agrees that combustion is
complex and involves many reactions
causing many different organic
compounds to form and be themselves
combusted to form other organic
compounds. Combustion is the process
of breaking apart the organic (i.e.,
carbon-containing) molecules in the fuel
and converting them to CO2. Perfectly
complete combustion would convert all
the carbon in the fuel to CO2.
Completeness of the combustion process
is dependent on several variables,
including the temperature, the amount
of oxygen, and the mixing of the fuel
and oxygen. Incomplete combustion
results in production of partly broken
down and partially oxidized organic
compounds, including CO. Because the
conversion of CO to CO2 is a difficult
step, and the last one in the destruction
of hydrocarbons, including organic
HAPs, the EPA concluded it is a good
indicator of the completeness of
combustion. Thus, decreasing levels of
CO are correlated with increasing
destruction of organic compounds until
a threshold is reached where, because
combustion of CO is the last step in
combustion, the combustion of organic
materials, including organic HAP, is
essentially complete.
Comment: One commenter noted that
boilers are frequently the primary
control devices under many new source
performance standards (NSPS) and
NESHAP standards for control of
emission streams containing organic
compounds. Typically, vent gases
containing organic HAP emissions are
sent to boilers or process heaters as
supplemental fuel if they have sufficient
heating value, and boilers and process
heaters are accepted as emission control
devices because performance testing
routinely shows that they can provide
organic destruction efficiencies of
greater than 98 percent. Nearly all
boilers and process heaters use
monitoring of CO as a means to evaluate
whether the device is performing
effectively, and when CO increases, the
unit is not efficiently oxidizing CO to
CO2 and the organics are not being as
effectively oxidized.
Response: We agree with the
commenter that boilers have frequently
been identified as the best way of
reducing emissions of organic
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compounds. Combustion devices, such
as boilers, continue to be identified as
the best control option available for
reducing organic HAP from various
industrial processes.31
Comment: Commenters stated that
organic HAP can be reduced not only
through combustion controls but also
through post-combustion controls such
as fabric filters, wet scrubbers, and
activated carbon injection (ACI).
Commenters further stated that the EPA
has found that ACI reduces emissions of
all organic HAP by 80 to 90 percent.
Commenters stated that this refutes the
EPA’s claims that the measures for
controlling CO and organic HAP are the
same.
Response: The EPA agrees that some
downstream control devices have the
capacity to reduce organic emissions.
However, such downstream control
devices are only effective if the primary
control device—the combustor itself—is
not effectively destroying the organic
HAP before it reaches the downstream
controls. Further, the effectiveness of
the post-combustion techniques
identified by the commenter, unlike
thermal oxidation, depends specifically
on the organic HAP and on the
concentration of the particular organic
HAP. The commenter noted that the
EPA has previously stated that POM/
PAH that is emitted during combustion
can be further reduced by various postcombustion controls, including fabric
filters, wet scrubbers, and ACI.
However, as discussed previously,
POM/PAH compounds are the product
of incomplete and inefficient
combustion. Therefore, if the combustor
is optimized for combustion—as
indicated by its CO emissions—then
POM/PAH production will be
minimized, and the downstream control
equipment will be unnecessary.
We also disagree with the commenter
that the EPA found that ACI reduces
organic HAP emissions by 80 to 90
percent. The commenter is citing a
telecommunication from an ACI vendor
regarding organic HAP emissions from a
sinter plant in the Integrated Iron and
Steel Manufacturing source category,
not a statement by EPA (85 FR 42090).
In that action, for purposes of evaluating
cost-effectiveness, the EPA assumed
reductions at a level provided by the
vendor but did not itself conclude that
those reductions were achievable. The
issue being addressed in the remand is
whether the best performing units were
using post-combustion controls that
controlled organic HAP but did not
31 See, for example, 40 CFR part 63, subparts F,
G, H, I, and FFFF.
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control CO. None of the best performing
boilers use an ACI system.
E. CO 130 PPM Threshold Emission
Limits
On March 16, 2018, the D.C. Circuit
issued its decision in Sierra Club v.
EPA, 884 F.3d 1185. In that decision,
the court remanded the EPA’s decision
to set a limit of 130 ppm CO as a
surrogate for non-dioxin organic HAP
for certain subcategories, asking the
Agency to better explain its analysis
supporting its decision. 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 noted 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 why
130 ppm is the appropriate level if there
is a non-zero CO level below which
organic HAP levels cannot be further
reduced.
In response to this remand, the EPA
provided further explanation to
substantiate the 130 ppm threshold
emission limit. In the proposed rule, we
described the relationship that we
previously found between CO and
formaldehyde using the available data
obtained during the 2013 rulemaking.
The paired data showed decreasing
formaldehyde emissions with
decreasing CO emissions down to CO
levels around 300 ppm (with
formaldehyde emissions down to less
than 1 ppm). 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.
In the proposed rule, we corroborated
our observation that reducing CO
emissions also resulted in a reduction of
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formaldehyde emissions until a leveling
off in formaldehyde reductions is
reached after which further reduction of
CO levels appeared to result in higher
levels of formaldehyde emitted. The
proposed rule described in detail two
additional studies—the polycyclic
aromatic hydrocarbons (PAH) study 32
and the Multipollutant Control Research
Facility (MPCRF) study 33—that
observed this same trend. In addition, in
the proposed rule, we suggested a
potential explanation for this observed
trend. As has already been discussed,
near complete combustion (as
evidenced by very low CO
concentration) is possible under an
oxygen-rich environment. To achieve
that oxygen-rich environment, excess
combustion air must be provided to the
burners. As the combustion process
progresses, the increased combustion air
can increase the turbulence and mixing
within the boiler. This increased
turbulence can result in some molecules
of the reactants (i.e., the oxygen and
organic HAP) being forced near the
furnace walls which are somewhat
colder than the combustion zone. This
cooling, known as the ‘‘wall effect,’’
may be sufficient to impact the
combustion reaction, resulting in some
organic HAP molecules that are not
fully combusted, and thus emitted.
In the 2013 rulemaking, we
determined that there are no further
reductions of organic HAP available
below 130 ppm CO. This analysis relied
on our paired CO-formaldehyde data,
yet we also stated that the same data
were not a reliable indicator of organic
HAP emissions at very low levels. 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 in 2013 was
that imprecise formaldehyde
measurements at low concentrations
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, ‘‘[b]ased on this, we do not
believe that such measurements are
sufficiently reliable to use as a basis for
establishing an emissions limit.’’ 78 FR
7145. In that statement, we were
referring to the formaldehyde
measurements and, thus, to the decision
32 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.
33 Surrogacy Testing in the MPCRF, Prepared for
U.S. EPA by ARCADIS, March 30, 2011. See Docket
ID Item No. EPA–HQ–OAR–2002–0058–3942.
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to set a CO standard instead of a
formaldehyde standard.
Our evaluation of the PAH and
MPRCRF studies revealed that the
observed relationship in our COformaldehyde data was not due to
imprecise or unreliable measurements,
but in fact has been observed in other
studies. Because the same CO–HAP
relationship was presented in the PAH
and MPCRF studies (i.e., that organic
HAP levels decreased with decreasing
CO levels until a leveling off and
trending upward with further
decreasing CO levels), we concluded in
the proposed rule that our formaldehyde
data used in establishing the 130 ppm
CO standard was not imprecise or
unreliable and could be explained by
the wall effect described above. These
studies, combined with the relationship
found in our CO-formaldehyde data,
support that there is a non-zero CO level
below which organic HAP levels are not
further reduced.
Comment: One commenter opposed
the EPA’s claim that organic HAP are
effectively nonexistent when CO levels
are below 130 ppm. The commenter
stated that the EPA’s formaldehyde
emissions data shows that there are
significant formaldehyde emissions at
CO levels below 130 ppm, at 2 ppm or
more even with the limited data set
available. The commenter also stated
that the PAH study merely confirms that
there are significant PAH emissions
even at very high levels of excess air
when CO levels would be expected to be
very low. This data shows that gaseous
PAH emissions actually increase with
increasing excess air as it is increased
from 20 percent to 40 percent—when
CO levels would be dropping. The
commenter further stated that the
MPCRF study confirms that organic
HAP emissions are not nonexistent
when CO levels are at or below 130 ppm
and that they are not correlated with
CO.
Response: We disagree with the
commenter that the Sierra Club decision
requires the EPA to demonstrate that
organic HAP emissions are
‘‘nonexistent’’ at the level of the CO
standard. Rather, the court said that the
standard based on a surrogate must be
set at a level at which ‘‘the EPA can be
confident that the targeted HAP
emissions are reduced as far as possible
or, indeed, eliminated entirely.’’ Sierra
Club, 884 F.3d at 1195 (emphasis
added). We agree with the commenter
that organic HAP emissions can be nonzero when CO levels are below 130
ppm, but at that level, they are expected
to be reduced to the greatest extent. Our
CO-formaldehyde data for units
operating at a CO concentration level
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below 130 ppm ranged from a measured
high value of 2 ppm to a measured low
value of 0.1 part per billion (ppb). The
range of emissions from multiple tested
units is expected due to inherent
variability from unit-to-unit. In contrast,
the data presented from the PAH and
MPCRF studies were measured from a
single unit (i.e., each study used a single
boiler for the tests). The MPCRF study
shows the same trend with
formaldehyde levels increasing from 10
ppb, at 70 ppm CO, to 57 ppb, at 40
ppm CO. The MPCRF study also shows
that as the CO concentration levels at
around 130 ppm, organic HAP, as a
group, have been reduced to their
minimum levels. Some of the organic
HAP in the MPCRF study show the
same trend as the PAH study and the
EPA’s CO-formaldehyde data. Some
show no further reduction, but most of
these also show a spike in concentration
below 130 ppm CO. While some organic
HAP did show further reduction, as
stated earlier, as a group the organic
HAP had been reduced to minimum
levels by around 130 ppm. Based on the
overall consideration of each of these
organic HAP, we continue to conclude
that there are no further reductions of
organic HAP available below 130 ppm
CO.
Comment: Commenters also disagreed
with the EPA’s statement that organic
HAP cannot be further reduced when
CO levels are below 130 ppm. The
commenter stated that the EPA has
recognized that all organic HAP
emissions can be reduced with ACI, and
some organic HAP emissions can also be
reduced with other end-of-stack
controls, including fabric filters and wet
scrubbers.
Response: The EPA disagrees with the
comment that organic HAP can be
further reduced when emitted from a
boiler with CO levels below 130 ppm.
The level of organic HAP emitted, as
indicated in the MPCRF study are in a
range that is well below the inlet
concentration of the post-combustion
controls used for other pollutants. As
discussed in the proposal preamble,
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). Concentrations of
conventional pollutants (e.g., NOX, SO2,
PM) are present at much higher
concentrations (ppm or vol% levels as
opposed to ppb) at the inlet of their
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respective controls devices (e.g., SCR,
wet scrubber, fabric filter or ESP).34
Even mercury—which is a very low
concentration pollutant that is not
controlled by upstream combustion—is
often present in concentrations of
approximately 10 ppb at the inlet of the
control devices and at a concentrations
of approximately 1 ppb at the exit.
Fixed-bed activated carbon adsorption
units can be sized for controlling VOCcontaining streams at concentrations as
low as several ppb in the case of some
toxic chemicals. However, while fixedbed activated carbon adsorbers can be
sized to treat low concentrations
(several ppb) of VOC-containing gas
streams, they can also introduce
considerable pressure drop across the
system resulting in additional electricity
used by the system fans, which must be
appropriately sized to overcome the
pressure drop through the carbon beds.
Therefore, we maintain that the quantity
of organic HAPs being emitted below
CO levels of 130 ppm is not susceptible
to further control.
Furthermore, we disagree that all
organic HAP emissions can be reduced
with ACI and note that the commenter
is citing a quote from an ACI vendor and
not a statement from the EPA, as
explained above. The effectiveness of
ACI for air pollutant control is related
to contact between a sorbent particle
and a molecule of pollutant. The higher
the concentration of the air pollutant—
whether that be mercury or organic
HAP—the more effective the pollutant is
removed via adsorption to the carbon
surface. As the concentration of the
pollution decreases, the likelihood of
contact between a pollutant molecule
and a carbon sorbent particle declines
significantly; and the effectiveness is
diminished. Similar to the results that
were observed for mercury, low inlet
concentrations of organic HAP will
result in a similar impact on control
efficiency using ACI. In fact, none of the
best performing organic HAP units are
using ACI because those units are more
effectively reducing organic HAP
through combustion. It also is important
to note that combustion devices, such as
boilers, are among the best controls
available for reducing organic HAP from
various industrial processes.
F. New Source Definition
Several commenters requested that
the EPA revise its definition of ‘‘new
source’’ to base the determination of
which sources must meet revised new
source standards to only those sources
34 U.S. EPA. EPA Air Pollution Control Cost
Manual. Sixth Edition. January 2002. EPA/452/B–
02–001.
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that constructed or reconstructed after
the EPA’s 2020 proposed action for this
final rule. The EPA disagrees that this
is compelled by the statutory language
and believes this final rule reflects a
reasonable approach in these particular
circumstances.
One commenter refers to the EPA’s
part 63 General Provisions regulations,
which state that ‘‘[a] new affected
source for which construction
commences after proposal of a relevant
standard is subject to relevant standards
for new affected sources, including
compliance dates.’’ 40 CFR 63.5(b)(1).
The EPA disagrees that the statutory and
regulatory provisions the commenter
refers to are relevant here, or that those
provisions override the statutory
definition of ‘‘new source,’’ which is
expressly based on the date EPA ‘‘first
proposes’’ an emissions standard that
applies to the source. See also 40 CFR
63.2 (defining ‘‘new source’’ in same
manner). In fact, the different definition
of ‘‘new source’’ in section 111 to which
the commenter also refers only
underscores the fact that Congress
specifically defined ‘‘new source’’ in
section 112 to be based on the ‘‘first’’
proposal of an emissions standard,
rather than the more general ‘‘proposed
regulations’’ found in section 111.
Similarly, the other provisions the
commenter refers to are not dispositive
here. First, the General Provisions
regulations the commenter refers to
address pre-construction review
requirements (40 CFR 63.5) and define
‘‘emissions standard’’ to mean ‘‘a
national standard, limitation,
prohibition, or other regulation’’ issued
under section 112 (40 CFR 63.2).
Neither of these provisions addresses
the question here—whether the EPA
must always re-define new sources
when it revises a MACT standard.
Similarly, the statutory definition of
‘‘emission standard’’ contains nothing
that addresses whether the definition of
‘‘new source’’ under section 112
changes every time the EPA proposes to
revise a MACT standard (CAA section
302(k)).
The EPA agrees that section 112(i)(2)
does not address the commenter’s
request. That provision allows for a
longer compliance period for new
sources where the EPA’s proposed
standards are less stringent than the
standards in the final rule. The
commenter further claims that Congress
did not address a situation where the
EPA proposes to revise an emissions
standard ten years after its first proposal
of standards, and notes that this time
period is even longer than the periodic
review timeframe of 8 years. The
commenter also claims that the EPA did
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not establish the definition of ‘‘new
source’’ based on the arguably ‘‘first’’
proposal of MACT standards in 2003,
and that the Agency has therefore
conceded that ‘‘first proposes’’ can
mean a subsequent proposal. The EPA
believes its approach in the final rule is
a reasonable application of the
definition of ‘‘new source’’ in this
particular circumstance. The MACT
standards promulgated in 2004 were
vacated by the D.C. Circuit in an
opinion in which the court stated that
it expected the reissued standards to
change significantly based on a
fundamental error the EPA made in
defining which sources were subject to
section 112 emissions standards and
which sources were subject to section
129 emissions standards. NRDC v. EPA,
489 F.3d 1250 (D.C. Cir. 2007). Since the
vacatur voided the standards entirely,
and restored the status quo ante, there
was arguably no proposal remaining
after the vacatur. In response to the
NRDC decision, the EPA undertook an
entirely new rulemaking to replace the
vacated standards, including an
extensive data collection effort and,
importantly, a new MACT floor
calculation methodology. 76 FR 15608.
In that circumstance, it is reasonable to
consider the EPA as having ‘‘first
proposed’’ an emission standard
applicable to these sources in the
replacement rulemaking.35 Here, in
contrast, the U.S. Sugar court upheld
the UPL methodology the EPA used to
set the MACT floor standards in another
part of its opinion.36 Where the EPA is
undertaking an entirely new process to
establish ‘‘an emission standard’’
applicable to a source, it is reasonable
to interpret the definition of ‘‘new
source’’ as applying based on the date
when the EPA ‘‘first proposes’’ that new
standard. However, where the Agency is
simply recalculating emissions
standards based on the same data and
35 The EPA notes that no commenter raised this
issue in the 2011 rulemaking which was issued to
replace the vacated 2004 standards, and it was not
addressed in the record for the rule.
36 As part of its review of standards affected by
U.S. Sugar, the EPA also considered the court’s
prior decision in NACWA v. EPA, where the court
remanded EPA’s UPL methodology for further
explanation based in part of the ‘‘anomalous result’’
the court found based on the UPL calculation for
certain new source standards at a level that was less
stringent than the UPL calculation for existing
source standards. The EPA’s subsequent
explanation of the UPL methodology was upheld in
U.S. Sugar, and it is appropriate for the Agency to
consider standards where that ‘‘anomalous result’’
occurred and correct the calculation in those
circumstances. For the new source solid fuel HCl
standard, the EPA has done that through the
application of its UPL methodology as applied to
small data sets. The EPA’s ‘‘small data sets’’ UPL
approach was upheld by the D.C. Circuit in Sierra
Club v. EPA, 895 F.3d 1 (2018).
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same methodology, it is reasonable to
treat the prior standard as EPA’s ‘‘first
proposal’’ of ‘‘an emission standard’’ for
those sources.
One commenter claims that the EPA’s
proposed revised HCl standard for new
source solid fuel units is significantly
more stringent than the standard
vacated by the U.S. Sugar court, and the
significant change in stringency
demonstrates that the EPA is using a
new methodology which represents a
‘‘drastic new approach’’ that sources
which constructed or reconstructed after
the 2010 proposal could not have
foreseen. Contrary to the commenter’s
assertion, the EPA is not applying a new
methodology to revise the standards in
this action. Rather, the EPA is simply
correcting the error the court identified
in how the Agency selected the best
performing sources for each subcategory
affected by the decision. It is not
collecting any additional information or
undertaking a wholesale revision of the
standards. The fact that one standard
became significantly more stringent
does not mean the EPA has revised its
methodology—it has not. Both the
previous standard and the new standard
were calculated using the UPL
methodology.37 Moreover, in its grant of
rehearing on remedy, the court
explained that it was remanding rather
than vacating the standards affected by
its holding because vacating the
standards would remove important
environmental protections while the
EPA reissued the standards. U.S. Sugar
Corp. v. EPA, 844 F.3d 268 (2016). It
would be contrary to the court’s purpose
in revising its remedy to remand, rather
than vacate, the emissions standards for
the EPA to use the fact that its original
standards were found to be inconsistent
with the Act as a way to allow sources
to meet less stringent standards.
Some commenters also pointed to
other EPA rulemakings under sections
112 and 129 and requested that EPA
take the approaches in those actions
rather than the proposed approach. The
EPA is basing its decision in this action
on the facts and circumstances of this
rulemaking, consistent with relevant
provisions of CAA section 112. In the
other actions that the commenters refer
to, the circumstances were different and
warranted a different approach. For
example, the revision of EPA’s Hospital/
37 The commenter claims that the solid fuel HCl
standard for new sources was not vacated by the
U.S. Sugar court and therefore EPA is not revising
the standard based on that decision, but for other
reasons. However, as noted above, as part of its
review of standards affected by the U.S. Sugar
remand on this issue, the EPA also applied its
‘‘small data sets’’ UPL memorandum where
appropriate.
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Medical/Infectious Waste Incinerator
(HMIWI) standards in 2009 involved the
collection of additional emissions
information and a wholesale revision of
the standards, unlike this action.38
Further, actions taken to adopt MACT
standards in the context of the EPA’s
risk and technology reviews under
sections 112(d)(6) and (f)(2) also
generally involve the calculation of new
standards based on information that was
not previously used in MACT
calculations.
Commenters also express concern that
the cost of compliance with the revised
new source HCl standard for solid fuel
units could be significant. One
commenter refers to a specific unit
constructed in 2016 which the
commenter claims will need to add
controls in order to meet the revised
new source solid fuel HCl standard. The
commenter claims that this renders the
revised standard a ‘‘beyond-the-floor’’
MACT standard, and the EPA must
therefore consider costs before adopting
the revised standard. The EPA
disagrees. The commenter conflates the
two-step MACT standard-setting process
in section 112(d)(2) and (d)(3). Under
section 112(d)(3), the EPA’s MACT
standard can be no less stringent than
the average emissions limitation
achieved by the best performing twelve
percent of sources in the subcategory,
for existing sources, and the emissions
limitation achieved by the best
performing similar source, for new
sources. It is well-established that, in
setting these MACT floor standards, the
EPA cannot consider the cost of
achieving reductions. National Lime
Ass’n. v. EPA, 233 F.3d 625 (D.C. Cir.
2000) (minimum stringency MACT floor
requirements apply without regard to
costs). This action addresses the D.C.
Circuit’s remand of certain MACT floor
standards, and it is those floor standards
that EPA is recalculating in a manner
that is consistent with the court’s
decision. The fact that one particular
recalculated standard may require
sources to incur costs to comply does
not transform the standard into a
‘‘beyond-the-floor’’ standard, and to do
so would ignore the statute’s clear
directive establishing a minimum level
of emissions reductions below which
the MACT standard cannot be set,
regardless of cost. Moreover, virtually
all sources constructed or reconstructed
after the 2010 proposal are in fact
meeting the revised HCl standard and
38 The EPA notes that the definition of ‘‘new solid
waste incineration unit’’ in section 129(g)(2), which
was adopted in the 1990 CAAA, does not contain
any reference to EPA’s ‘‘first’’ proposal of
applicable standards.
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60831
will therefore not incur any compliance
costs.
Finally, contrary to commenters’
assertions, the EPA is not applying a
new standard retroactively. Every
source affected by these revised limits
has 3 years to come into compliance
with the revised standards following
promulgation, regardless of construction
date. The commenter does not explain
how the revised standard is a retroactive
standard, except to state that a source
that was constructed in 2016 could not
have foreseen that the EPA would
subsequently revise standards to make
them more stringent. Section 112(a)
defines ‘‘new source’’ based on when
EPA ‘‘first proposes’’ an emissions
standard for a source, and, as explained
above, in this particular circumstance it
is reasonable to consider EPA’s 2010
proposal as the date when the Agency
‘‘first proposed’’ an emissions standard
for these sources. In addition, the EPA
is revising the standards to respond to
the D.C. Circuit’s remand in U.S. Sugar,
and it was reasonable to assume, once
that remand was issued, that revised
standards would in some cases be more
stringent than the remanded standards.
G. Approval for CO2 in Lieu of O2
Monitoring for CO CEMS Compliance
Calculations
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. In
the proposed rule, we took 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. We further proposed
removing several requirements for the
continuous monitoring of moisture and
flow which we found to be unnecessary.
Commenters supported the proposal
to modify the requirement to obtain the
Administrator’s approval and allow this
change to become self-implementing.
Commenters further agreed with the
EPA’s proposal to remove requirements
for the continuous monitoring of
moisture and flow which were found to
be unnecessary.
We are finalizing these provisions as
proposed. Some commenters requested
that we remove the requirements for
continuous monitoring of moisture and
flow when CO2 measurements do not
require these values for compliance
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
calculations. We believe the revisions
accommodate the removal of moisture
and flow when a dry CO2 analyzer is
used, obviating the need to make any
additional changes to the rule language.
IV. Results and Final 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, the decisions to propose
certain limits as beyond-the-floor limits,
and consideration of public comments,
we are finalizing revisions to 34
different emission limits. The detailed
list of revisions to unit rankings and
revised MACT floor calculations are
presented in the docketed
memorandums, Revised MACT Floor
Analysis (2019) for the Industrial,
Commercial, and Institutional Boilers
and Process Heaters National Emission
Standards for Hazardous Air
Pollutants—Major Source and Revised
MACT Floor Analysis (2021) 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 limits are modestly less
stringent, with no more than a 25percent change from the corresponding
limit in the 2013 final rule. The final
limits are shown in Table 4, along with
corresponding limits from the 2013 final
rule.
TABLE 4—SUMMARY OF CHANGES TO EMISSION LIMITS IN THE FINAL ACTION
Subcategory
Pollutant
New—Solid ......................................................................................................................
New—Dry Biomass Stoker ..............................................................................................
New—Biomass Fluidized Bed .........................................................................................
New—Biomass Fluidized Bed .........................................................................................
New—Biomass Suspension Burner ................................................................................
New—Biomass Suspension Burner ................................................................................
New—Biomass Hybrid Suspension Grate .......................................................................
New—Biomass Dutch Oven/Pile Burner .........................................................................
New—Biomass Fuel Cell .................................................................................................
New—Wet Biomass Stoker .............................................................................................
New—Wet Biomass Stoker .............................................................................................
New—Liquid .....................................................................................................................
New—Heavy Liquid .........................................................................................................
New—Process Gas .........................................................................................................
Existing—Solid .................................................................................................................
Existing—Solid .................................................................................................................
Existing—Coal .................................................................................................................
Existing—Coal Stoker ......................................................................................................
Existing—Dry Biomass Stoker .........................................................................................
Existing—Wet Biomass Stoker ........................................................................................
Existing—Wet Biomass Stoker ........................................................................................
Existing—Biomass Fluidized Bed ....................................................................................
Existing—Biomass Fluidized Bed ....................................................................................
Existing—Biomass Suspension Burners .........................................................................
Existing—Biomass Dutch Oven/Pile Burner ....................................................................
Existing—Liquid ...............................................................................................................
Existing—Heavy Liquid ....................................................................................................
Existing—Non-Continental Liquid ....................................................................................
Existing—Process Gas ....................................................................................................
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B. What compliance dates are we
finalizing?
We are finalizing that facilities have
up to 3 years after the effective date of
the final rule to comply with the revised
emissions limits in this 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
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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
revised emission limits and to update
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2013 final rule
emission limit
(lb/MMBtu of heat
input or ppm at
3-percent oxygen
for CO)
Revised emission
limit
(lb/MMBtu of heat
input or ppm at
3-percent oxygen
for CO)
2.2E–02
4.0E–03
230
9.8E–03
(8.3E–05)
2,400
6.5E–03
1,100
3.2E–03
2.0E–02
620
0.03
4.4E–04
1.3E–02
(7.5E–05)
6.7E–03
2.2E–02
5.7E–06
4.0E–02
160
4.0E–03
1,500
3.7E–02
(2.4E–04)
470
1.1E–01
(1.2E–03)
5.1E–02
(6.5E–03)
2.8E–01
2.0E–06
6.2E–02
2.7E–01
6.7E–03
2.1E–04
5.0E–03
130
4.1E–03
(8.4E–06)
220
8.0E–03
180
2.5E–03
1.1E–02
590
0.013
1.5E–04
1.9E–03
(6.4E–06)
7.3E–03
2.0E–02
5.4E–06
3.9E–02
150
5.0E–03
1,100
3.4E–02
(2.0E–04)
210
7.4E–03
(6.4E–05)
4.1E–02
(8.0E–03)
1.8E–01
7.3E–07
5.9E–02
2.2E–01
7.3E–03
HCl
TSM
CO
PM
(TSM)
CO
TSM
CO
PM
PM
CO
PM
HCl
PM
(TSM)
PM
HCl
Hg
PM
CO
TSM
CO
PM
(TSM)
CO
PM
(TSM)
PM
(TSM)
PM
Hg
PM
PM
PM
reports to incorporate the revised
emission limits.
C. What other actions are we finalizing?
We proposed a number of technical
corrections to correct inadvertent errors
that were promulgated in the 2013 and
2015 final rules. Public commenters also
noted several additional technical
corrections to correct additional errors
in the final rule. In addition, we are
removing the references to the date of
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future final performance specifications
for HCl CEMS because PS 18, the
Performance Specifications for Gaseous
Hydrogen Chloride, and Procedure 6,
the Quality Assurance Requirements for
Gaseous Hydrogen Chloride (HCl)
Continuous Emission Monitoring
Systems Used for Compliance
Determination at Stationary Sources,
were promulgated on July 7, 2017 at 80
60833
FR 38628. The technical corrections we
are finalizing are summarized in Table
5.
TABLE 5—FINALIZED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD
Section of subpart DDDDD
Description of correction
40 CFR 63.7500(a) .........................
40 CFR 63.7521(c)(1)(ii) .................
40 CFR 63.7525(l) and 40 CFR
63.7540(a)(15).
40 CFR 63.7530(b)(4)(iii) ................
40 CFR 63.7540(a)(9) .....................
40 CFR 63.7575 .............................
Table 1 ............................................
Table 2 ............................................
Table 7 ............................................
Table 8 ............................................
Table 14 ..........................................
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Table 15 ..........................................
Revise this paragraph to remove the comma after ‘‘paragraphs (b).’’
Revise this paragraph to remove the requirement to collect samples during the test period at 1-hour intervals.
Remove the references to a date of a final performance specification for HCl CEMS.
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.
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.
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.’’
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.
Remove footnote ‘‘a’’ from item 12b for the TSM limit for fuel cell units designed to burn biomass/biobased solids.
Add footnote ‘‘a’’ to item 1a for the solid fuel HCl limit, item 14a for the liquid fuel HCl limit, and item 15b
for the light liquid fuel TSM limit.
Removed footnote ‘‘a’’ for item 14b for the liquid fuel mercury emission limit and 16b for light liquid PM
emission limit.
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.
Revise item 8.d to clarify that the correct equations to use are Equations 15 and Equations 16, 17, and/or
18 in 40 CFR 63.7530.
Remove footnote ‘‘a’’ from item 12b for the TSM limit for fuel cell units designed to burn biomass/biobased solids.
Add footnote ‘‘a’’ to item 15b for the light liquid fuel TSM limit.
Removed footnote ‘‘a’’ for item 14b for the liquid fuel mercury emission limit and 16b for light liquid PM
emission limit.
V. Summary of Cost, Environmental,
and Economic Impacts
constructed and subject to the revised
emission limits over the next 8 years.
A. What are the affected sources?
B. What are the air quality impacts?
According to CEDRI data through
December 31, 2020, there are 577 boilers
and process heaters, of which 485
remain operational and belong in one of
the subcategories that are subject to
numeric emission limits.39 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. Of these units, we estimate
that 54 units (individual boilers or
process heaters) will incur cost or
emissions impacts due to these final
amendments. In addition, the EPA
estimates that an additional six biomass
boilers or process heaters will be
Table 6 of this preamble shows the
incremental emissions reductions that
we estimate these final amendments
will achieve. The reductions are
incremental to the reductions accounted
for in the 2013 final rule. Nationwide
emissions of selected HAP (i.e., HCl,
hydrogen fluoride, Hg, and metals)
would be reduced by an additional 117
tpy as compared to the estimates in the
2013 final rule. This increase is due
mainly to changes to certain emission
limits that are anticipated to achieve
additional reductions. We estimate the
final amendments will result in an
additional 110 tpy of reductions in HCl
emissions. We estimate that the final
amendments will have a modest effect
on Hg, with an estimated additional
reduction of 7.5 lbs per year. Emissions
of filterable PM are estimated to
decrease by 586 tpy, of which 446 tpy
is PM2.5, due to this final action.
Emissions of non-Hg metals (i.e.,
arsenic, beryllium, cadmium,
chromium, lead, manganese, nickel, and
selenium) are estimated to decrease by
4.1 tpy. Estimates of reductions in
antimony and cobalt were not
quantified and are expected to be small.
In addition, the final amendments are
estimated to result in 1,141 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 (2021)
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.
39 EPA notes that it considered compliance
information from CEDRI for the purpose of
evaluating costs and impacts of this action, in order
to ensure that the actual costs of compliance are
accurately reflected. For the reasons explained
elsewhere, the Agency did not consider emissions
data in CEDRI to recalculate the MACT floor
standards affected by the D.C. Circuit remand in
U.S. Sugar. 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.
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 6—SUMMARY OF TOTAL EMISSIONS REDUCTIONS FOR THE FINAL RULE
[Tons per year]
Source
Subcategory
Exiting Units ......................................
Coal ..................................................
Biomass ............................................
Biomass ............................................
New Units .........................................
1 Arsenic,
HCl
Non-Hg
metals 1
PM
44.1
13.6
52.3
54.4
521
9.9
0.12
3.8
0.14
Hg
2.12E–03
1.65E–03
0
beryllium, cadmium, chromium, lead, manganese, nickel, and selenium.
C. What are the cost impacts?
We estimated the total capital costs of
the final amendments to be about $201
million and the total annualized costs to
be about $49.6 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 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 final action. Table 7 shows
the total capital and annual cost impacts
of the final rule for each subcategory.
The cost methodology and results are
documented in the memorandum,
Revised (2021) 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 7—SUMMARY OF TOTAL CAPITAL AND ANNUAL COSTS FOR AFFECTED NEW AND EXISTING SOURCES FOR THE
FINAL RULE
Source
Subcategory
Existing Units ....................................
Coal ..................................................
Biomass ............................................
Biomass ............................................
New Units .........................................
Another way to present compliance
costs is the present value (PV). A PV is
an estimate of costs that is a discounted
stream of the annualized costs for the
final action calculated for the present
day. The PV in 2016 of the costs is $265
million at a discount rate of 7 percent
and $315 million at a discount rate of
3 percent. Calculated as an EAV, which
is consistent with the PV of costs in
2016, the costs are $44 million at a
discount rate of 7 percent and $45
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 final action which is available in
the docket.
lotter on DSK11XQN23PROD with RULES2
Estimated
number of
affected units
incurring a
cost
D. What are the secondary impacts?
The EPA estimated the additional
water usage that would result from
installing wet scrubbers to meet the
amended emission limits for HCl would
be 0.75 million gallons per year for new
and existing sources compared to the
2013 baseline. In addition to the
increased water usage, an additional
0.29 million gallons per year of
wastewater will be produced for new
and existing sources. The annual costs
of treating the additional wastewater are
approximately $1,920. These additional
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5
33
11
costs are accounted for in the control
cost estimates.
The EPA estimated the additional
solid waste that would result due to the
final amendments to be 1,540 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 approximately $73,900.
These costs are also accounted for in the
control costs estimates.
The EPA estimated the final
amendments would result in an increase
of about 74.4 million kilowatts per year
in national energy usage from the
electricity required to operate control
devices, such as wet scrubbers, ESPs,
and fabric filters which are expected to
be installed to meet the revised
emission limits. This energy
requirement is estimated to result in an
increase of approximately 32,910 tpy
CO2 based on emissions related to
additional energy consumption.
A discussion of the methodology used
to estimate impacts is presented in the
Revised (2021) Methodology for
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Capital costs
(millions
2016$)
8.0
149.5
43.3
Testing and
monitoring
annualized
costs
(millions
2016$/yr)
0.057
0.511
0.043
Annualized
cost
(millions
2016$/yr)
2.1
35.1
12.3
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 final rule, as
detailed in the Regulatory Impact
Analysis for the ICI Boilers NESHAP
Final Amendments, which is available
in the docket for this action. The
economic impacts 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. Of
30 parent owners affected by this final
rule, two of them will incur total
annualized costs of 1 percent or greater
of their revenues. The median total
annualized cost of sales for affected
parent owners is less than 0.01 percent.
While two parent owners may
experience substantial economic
impacts as a result of complying with
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this final rule, neither one is a small
business according to Small Business
Administration (SBA) guidelines.
Overall, based on these estimated
impacts, we can conclude that the
economic impacts are relatively low for
the affected entities and the multiple
affected industries, and consumers of
affected output should experience
relatively low price changes.
F. What are the benefits?
There are no monetized benefits from
the HAP emissions reductions directly
regulated under this action due to lack
of necessary input data. However, the
EPA reports the estimated impact on
health benefits from changes in PM2.5
and SO2 emissions that occur as a result
of this final rule. The estimated health
benefits are the monetized value of the
human health benefits among
populations exposed to changes in
PM2.5. 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 40 in
which the economic value of human
health impacts is derived at the national
level based on previously established
source-receptor relationships from
photochemical air quality modeling.41
These BPT estimates provide the total
monetized human health benefits (the
sum of PM-attributable premature
deaths and premature morbidity) of
reducing 1 ton of PM2.5 (or PM2.5
precursor such as SO2) from a specified
source. Since proposal of this rule, the
EPA has updated its BPT estimates to
include state level estimates specifically
for the Industrial Boiler sector. The
method used to derive these estimates is
described in the Technical Support
Document on Estimating the Benefit per
Ton of Reducing Directly-Emitted PM2.5,
PM2.5 Precursors and Ozone Precursors
from 21 Sectors and its precursors from
21 sectors.42 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, or nitrogen dioxide.
The photochemical modeled emissions
of the industrial point source sectorattributable PM2.5 concentrations used
to derive the BPT values may not match
the change in air quality resulting from
the emissions controls.
Specifically, all national-average BPT
estimates reflect the geographic
60835
distribution of the modeled emissions,
which may not exactly match the
emission reductions that would occur
due to 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
new BPT estimates developed for the
Industrial Boiler sector in 2021
developed state-level estimates that
addressed some of the limitations of the
national analysis. Given the use of state
level, sector specific air quality
modeling and the small changes in
emissions considered in this
rulemaking, the difference in the
quantified health benefits that result
from the BPT approach compared with
those obtained using a full-form air
quality model should be minimal.
Table 8 summarizes the monetized
PM related health benefits per ton in the
states where units with emission
reductions are located, using discount
rates of 3 percent and 7 percent. Table
9 summarizes the monetized SO2related health benefits per ton of
reducing precursor pollutant emissions
in the states where units with emission
reductions are located, using discount
rates of 3 and 7 percent.
TABLE 8—ESTIMATED PM2.5-RELATED BENEFITS PER TON OF FINAL RULE
State
Benefit per ton
low
(3% discount
rate)
Benefit per ton
low
(7% discount
rate)
Benefit per ton
high
(3% discount
rate)
Benefit per ton
high
(7% discount
rate)
$503,000
140,000
151,000
117,000
48,200
259,000
171,000
103,000
227,000
148,000
$452,000
126,000
136,000
105,000
43,400
233,000
154,000
92,600
204,000
133,000
$510,000
141,000
156,000
123,000
50,500
262,000
173,000
106,000
235,000
156,000
$459,000
127,000
141,000
110,000
45,500
236,000
156,000
95,8000
212,000
140,000
CA ....................................................................................................................
FL .....................................................................................................................
GA ....................................................................................................................
LA .....................................................................................................................
ME ....................................................................................................................
MI .....................................................................................................................
NC ....................................................................................................................
OK ....................................................................................................................
TN ....................................................................................................................
WI .....................................................................................................................
TABLE 9—ESTIMATED SO2-RELATED BENEFITS PER TON OF FINAL RULE
State
Benefit per ton
low
(3% discount
rate)
Benefit per ton
low
(7% discount
rate)
Benefit per ton
high
(3% discount
rate)
Benefit per ton
high
(7% discount
rate)
$50,600
42,300
45,600
54,800
56,000
$45,500
38,100
41,000
49,300
50,300
$52,100
43,000
46,400
55,300
57,000
$46,900
38,700
41,800
51,300
49,800
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AL .....................................................................................................................
AR ....................................................................................................................
FL .....................................................................................................................
IL ......................................................................................................................
MI .....................................................................................................................
40 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
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Matter National Ambient Air Quality Standards;
December 2012.
41 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.
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42 U.S. EPA. 2021. Technical Support Document
(BPT TSD) on Estimating the Benefit per Ton of
Reducing Directly-Emitted PM2.5, PM2.5 Precursors
and Ozone Precursors from 21 Sectors and its
precursors from 21 sectors. Technical Support
Document. Available at: https://www.epa.gov/
benmap/reduced-form-tools-calculating-pm25benefits.
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TABLE 9—ESTIMATED SO2-RELATED BENEFITS PER TON OF FINAL RULE—Continued
State
Benefit per ton
low
(3% discount
rate)
Benefit per ton
low
(7% discount
rate)
Benefit per ton
high
(3% discount
rate)
Benefit per ton
high
(7% discount
rate)
45,300
14,900
53,400
20,300
40,700
13,400
48,100
18,300
45,600
15,100
54,100
20,800
41,000
13,600
48,700
18,700
NC ....................................................................................................................
TX ....................................................................................................................
VA ....................................................................................................................
WA ...................................................................................................................
TABLE 10—ANNUAL EMISSIONS REDUCTIONS OF PM2.5 AND SO2 BY STATE
Emission reductions
(tons)
State
AL .............................................................................................................................................................................
AR ............................................................................................................................................................................
CA ............................................................................................................................................................................
FL .............................................................................................................................................................................
GA ............................................................................................................................................................................
IL ..............................................................................................................................................................................
LA .............................................................................................................................................................................
ME ............................................................................................................................................................................
MI .............................................................................................................................................................................
NC ............................................................................................................................................................................
OK ............................................................................................................................................................................
TN ............................................................................................................................................................................
TX ............................................................................................................................................................................
VA ............................................................................................................................................................................
WA ...........................................................................................................................................................................
WI .............................................................................................................................................................................
Table 10 above provides the annual
emissions reductions of PM2.5 and SO2
by state. Table 11 summarizes the range
of estimated benefits of these annual
emission reductions by pollutant for the
PM2.5
SO2
........................
........................
33
17
10
........................
27
5
4
2
257
40
........................
........................
........................
51
26
<0.1
........................
557
........................
306
........................
........................
41
179
........................
........................
1
31
2
........................
two benefit per ton estimates at discount
rates of 3 percent and 7 percent.
TABLE 11—ESTIMATED PM2.5 AND SO2-RELATED ANNUAL HEALTH BENEFITS OF FINAL RULE
[Millions of 2016$]
Benefits low
(3% discount
rate)
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Pollutant
Benefits low
(7% discount
rate)
Benefits high
(3% discount
rate)
Benefits high
(7% discount
rate)
PM2.5 ................................................................................................................
SO2 ..................................................................................................................
$68
55
$62
50
$68
56
$62
51
Total ..........................................................................................................
123
112
124
113
There are also climate disbenefits
from the increase in CO2 emissions that
result from the increase in national
energy use from control device
operation. We estimate the social
disbenefits of CO2 emission increases
expected from this final rule using the
SC–CO2 estimates presented in the
Technical Support Document: Social
Cost of Carbon, Methane, and Nitrous
Oxide Interim Estimates under
Executive Order 13990.43 We have
43 Interagency Working Group on Social Cost of
Greenhouse Gases (IWG). 2021. Technical Support
Document: Social Cost of Carbon, Methane, and
Nitrous Oxide Interim Estimates under Executive
Order 13990. February. United States Government.
Available at: https://www.whitehouse.gov/briefing-
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evaluated the SC–CO2 estimates in the
February 2021 TSD and have
determined that these estimates are
appropriate for use in estimating the
social value of CO2 emission changes
expected from this final rule as part of
fulfilling analytical guidance with
respect to E.O. 12866. These SC–CO2
estimates are interim values developed
for use in benefit-cost analyses until an
improved estimate of the impacts of
climate change can be developed based
on the best available science and
economics.
room/blog/2021/02/26/a-return-to-scienceevidence-based-estimates-of-the-benefits-ofreducing-climate-pollution/.
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Table 12 shows the estimated
monetary value of the estimated changes
in CO2 emissions expected to occur for
the final rule. For 2022–2024, no
changes in CO2 emissions occur since
the control technologies included in the
cost analysis mentioned in the Cost
Methodology memo for the final rule are
not expected to begin operation until 3
years after the effective date of the final
rule, or 2025. Hence, there are no
climate disbenefits for these 3 years. In
2025, the EPA estimated the dollar
value of the CO2-related effects by
applying the SC–CO2 estimates,
included in the RIA’s benefits chapter,
to the estimated changes in CO2
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
emissions in the corresponding year
under the final rule.44 The EPA
calculated the present value and
annualized benefits from the
perspective of 2020 by discounting each
year-specific value to the year 2020
60837
using the same discount rate used to
calculate the SC–CO2.45
TABLE 12—ESTIMATED CLIMATE DISBENEFITS FROM CHANGES IN CO2 EMISSIONS FOR 2025
[Millions of 2016$] a
Discount rate and statistic
Final Rule .............................................................................
Year
5% average
3% average
2.5% average
3% 95th
percentile
2025
0.5
1.7
2.5
5.2
a Climate
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disbenefits are based on changes (reductions) in CO2 emissions and are calculated using four different estimates of the social cost
of carbon (SC–CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). We emphasize the importance and value of considering the disbenefits calculated using all four SC–CO2 estimates. As discussed in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990, a consideration of climate
benefits calculated using discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting intergenerational
impacts.
The climate disbenefits associated
with the additional 32,910 short tons (or
29,855 metric tons) per year of CO2
emissions generated as a result of the
requirements of this final rule are
therefore $1.7 million at a 3 percent
discount rate, and range from $0.5
million at a 2.5 percent discount rate to
$5.2 million at a 3 percent discount rate
(95th percentile), all in 2016 dollars.46
These disbenefits are estimated for
2025, the year of full implementation of
this final rule (3 years after the effective
date) using the interim social cost of
carbon (SC–CO2) for 2025 as shown in
Table 12 to be consistent with the year
for the PM2.5 and SO2 BPTs applied to
generate those monetized benefits
presented earlier in section V.F.47
These disbenefits are included in the
estimates of benefits and net benefits for
this final rule. The benefit analysis for
this final rule, which includes PV and
EAV estimates for the benefits and net
benefits, is detailed in the Regulatory
Impact Analysis for the ICI Boilers and
Process Heaters NESHAP Final
Amendments, which is available in the
docket for this action.
G. What analysis of environmental
justice did we conduct?
Executive Order 12898 directs the
EPA to identify the populations of
concern who are most likely to
experience unequal burdens from
environmental harms; specifically,
minority populations, low-income
populations, and indigenous peoples
(59 FR 7629, February 16, 1994).
Additionally, Executive Order 13985
was signed to advance racial equity and
support underserved communities
through Federal government actions (86
FR 7009, January 20, 2021). The EPA
defines environmental justice (EJ) as the
fair treatment and meaningful
involvement of all people regardless of
race, color, national origin, or income
with respect to the development,
implementation, and enforcement of
environmental laws, regulations, and
policies. The EPA further defines the
term fair treatment to mean that ‘‘no
group of people should bear a
disproportionate burden of
environmental harms and risks,
including those resulting from the
negative environmental consequences of
industrial, governmental, and
commercial operations or programs and
policies’’ (https://www.epa.gov/
environmentaljustice). In recognizing
that minority and low-income
44 CO emissions increases above the baseline as
2
a result of the modeled policy are first expected in
2025, as control technologies applied in response to
the final rule first begin operation in that year, and
those emissions increase remain at that level
afterwards, according to the cost analysis for this
rule.
45 According to OMB’s Circular A–4, an ‘‘analysis
should focus on benefits and costs that accrue to
citizens and residents of the United States’’, and
international effects should be reported separately.
Circular A–4 also reminds analysts that ‘‘[d]ifferent
regulations may call for different emphases in the
analysis, depending on the nature and complexity
of the regulatory issues.’’ To correctly assess the
total climate damages to U.S. citizens and residents,
an analysis must account for all the ways climate
impacts affect the welfare of U.S. citizens and
residents, how U.S. GHG mitigation activities affect
mitigation activities by other countries, and
spillover effects from climate action elsewhere. The
SC–CO2 estimates used in regulatory analysis under
revoked E.O. 13783, including in the RIA for the
proposed rule, were an approximation of some of
the U.S.-specific climate damages from GHG
emissions (e.g., $7/mtCO2 (2016 dollars) using a 3%
discount rate for emissions occurring in 2025).
Applying the same estimate (based on a 3%
discount rate) to the CO2 emissions expected under
the final rule would yield disbenefits from climate
impacts of $0.2 million (2016 dollars) in 2025.
However, as discussed at length in the February
2021 TSD, these estimates are an underestimate of
the damages of CO2 emissions accruing to U.S.
citizens and residents, as well as being subject to
a considerable degree of uncertainty due to the
manner in which they are derived. In particular, the
estimates developed under revoked E.O. 13783 did
not capture significant regional interactions,
spillovers, and other effects and so are incomplete
underestimates. As the U.S. Government
Accountability Office (GAO) concluded in a June
2020 report examining the SC–GHG estimates
developed under E.O. 13783, the models ‘‘were not
premised or calibrated to provide estimates of the
social cost of carbon based on domestic damages’’.
U.S. Government Accountability Office (GAO).
2020. Social Cost of Carbon: Identifying a Federal
Entity to Address the National Academies’
Recommendations Could Strengthen Regulatory
Analysis. GAO–20–254. Further, the report noted
that the National Academies found that countryspecific social costs of carbon estimates were
‘‘limited by existing methodologies, which focus
primarily on global estimates and do not model all
relevant interactions among regions’’. It is also
important to note that the SC–GHG estimates
developed under E.O. 13783 were never peer
reviewed, and when their use in a specific
regulatory action was challenged, the U.S. District
Court for the Northern District of California
determined that use of those values had been
‘‘soundly rejected by economists as improper and
unsupported by science,’’ and that the values
themselves omitted key damages to U.S. citizens
and residents including to supply chains, U.S.
assets and companies, and geopolitical security.
The Court found that by omitting such impacts,
those estimates ‘‘fail[ed] to consider . . . important
aspect[s] of the problem’’ and departed from the
‘‘best science available’’ as reflected in the global
estimates. California v. Bernhardt, 472 F. Supp. 3d
573, 613–14 (N.D. Cal. 2020). The EPA continues
to center attention in this regulatory analysis on the
global measures of the SC–GHG as the appropriate
estimates and as necessary for all countries to use
to achieve an efficient allocation of resources for
emissions reduction on a global basis, and so
benefit the U.S. and its citizens.
46 In order to calculate these values, it is
necessary to convert tons (short) of emissions to
metric tons. These values may be converted to $/
short ton using the conversion factor 0.90718474
metric tons per short ton for application to the short
ton CO2 emissions impacts provided in this
rulemaking. Hence, 32,910 short tons of emissions
become 29,855 metric tons (tonnes) of emissions.
47 These SC–CO values are stated in $/metric ton
2
CO2 and rounded to the nearest dollar. Such a
conversion does not change the underlying
methodology, nor does it change the meaning of the
SC–CO2 estimates. For both metric and short tons
denominated SC–CO2 estimates, the estimates vary
depending on the year of CO2 emissions and are
defined in real terms, i.e., adjusted for inflation
using the Gross Domestic Product (GDP) implicit
price deflator.
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
populations often bear an unequal
burden of environmental harms and
risks, the EPA continues to consider
ways of protecting them from adverse
public health and environmental effects
of air pollution.
To examine the potential for any EJ
issues that might be associated with the
source category, we performed a
demographic analysis, which is an
assessment of individual demographic
groups of the populations living within
5 kilometers (km) and within 50 km of
facilities with affected sources.48 The
EPA then compared the data from this
analysis to the national average for each
of the demographic groups.
The results of the demographic
analysis indicate that, for populations
within 5 km of the facilities in the
source category, the percent minority
population (being the total population
minus the white population) is smaller
than the national average (36 percent
versus 40 percent). Within minorities,
the percent of the population that is
African American, Other and
Multiracial, and Native American are
similar to the national averages. The
percent of the population that is
Hispanic or Latino is below the national
average (14 percent versus 19 percent).
The percent of people living below the
poverty level was higher than the
national average (18 percent versus 13
percent). The percent of people living in
linguistic isolation was less than the
national average. The results of the
analysis of populations within 50 km of
the facilities in the source category were
similar to the 5 km analysis, with the
exception of the percent of the
population living below the poverty
level and the percent of the population
over 25 without a high school diploma,
which were closer to the national
averages.
The EPA believes the human health or
environmental risk addressed by this
action will not have potential
disproportionately high and adverse
human health or environmental effects
on minority, low-income, or indigenous
populations, as specified in Executive
Order 12898 (59 FR 7629, February 16,
1994). Nationwide emissions of selected
HAP (i.e., HCl, hydrogen fluoride, Hg,
and metals) would be reduced by an
additional 117 tpy as compared to the
estimates in the 2013 final rule. We
estimate the final amendments will
result in an additional 110 tpy of
reductions in HCl emissions, and 7.5 lbs
per year of Hg. Emissions of filterable
PM are estimated to decrease by 586
tpy, of which 446 tpy is PM2.5.
Emissions of non-Hg metals (i.e.,
arsenic, beryllium, cadmium,
chromium, lead, manganese, nickel, and
selenium) are estimated to decrease by
4.1 tpy. In addition, the final
amendments are estimated to result in
1,141 tpy of reductions in SO2
emissions. A breakdown of emissions
reductions by facility is presented in
Appendix C of the memorandum,
Revised (2021) 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. This final rule increases the level
of environmental protection for all
affected populations, without having
any disproportionately high and adverse
human health or environmental effects
on any population, including any
minority, low-income, or indigenous
populations.
A summary of the proximity
demographic assessment performed for
Industrial, Commercial, and
Institutional Boilers and Process Heaters
facilities is included as Table 13. The
methodology and the results of the
demographic analysis are presented in a
technical report, Analysis of
Demographic Factors for Populations
Living Near Industrial, Commercial, and
Institutional Boilers and Process
Heaters, available in this docket for this
action (Docket ID EPA–HQ–OAR–2002–
0058).
TABLE 13—PROXIMITY DEMOGRAPHIC ASSESSMENT RESULTS
Demographic group
Population
within 50 km
of 40
facilities
Nationwide
Total Population ...........................................................................................................................
328,016,242
Population
within 5 km
of 40
facilities
14,889,295
635,825
White and Minority by Percent
White ............................................................................................................................................
Minority ........................................................................................................................................
60%
40%
65%
35%
64%
36%
Minority by Percent
African American .........................................................................................................................
Native American ..........................................................................................................................
Hispanic or Latino (includes white and nonwhite) .......................................................................
Other and Multiracial ...................................................................................................................
12%
0.7%
19%
8%
14%
0.5%
13%
7%
13%
0.8%
14%
8%
Income by Percent
Below Poverty Level ....................................................................................................................
Above Poverty Level ....................................................................................................................
13%
87%
14%
86%
18%
82%
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Education by Percent
Over 25 and without a High School Diploma ..............................................................................
Over 25 and with a High School Diploma ...................................................................................
12%
88%
12%
88%
Linguistically Isolated by Percent
48 Note that many facilities have more than one
affected boiler or process heater.
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60839
TABLE 13—PROXIMITY DEMOGRAPHIC ASSESSMENT RESULTS—Continued
Demographic group
Nationwide
Linguistically Isolated ...................................................................................................................
5%
Population
within 50 km
of 40
facilities
Population
within 5 km
of 40
facilities
3%
4%
Notes:
• The nationwide population count and all demographic percentages are based on the Census’ 2015–2019 American Community Survey fiveyear block group averages and include Puerto Rico. Demographic percentages based on different averages may differ. The total population
counts within 5 km and 50 km of all facilities are based on the 2010 Decennial Census block populations.
• Minority population is the total population minus the white population.
• To avoid double counting, the ‘‘Hispanic or Latino’’ category is treated as a distinct demographic category for these analyses. A person is
identified as one of five racial/ethnic categories above: White, African American, Native American, Other and Multiracial, or Hispanic/Latino. A
person who identifies as Hispanic or Latino is counted as Hispanic/Latino for this analysis, regardless of what race this person may have also
identified as in the Census.
VI. Statutory and Executive Order
Reviews
Additional information about these
statutes and Executive Orders can be
found at https://www.epa.gov/lawsregulations/laws-and-executive-orders.
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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
contains the estimated costs, benefits,
and other impacts associated with this
action, and it is available in the docket.
B. Paperwork Reduction Act (PRA)
The new information collection
activities in this 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 2028.12. OMB Control Number
2060–0551. You can find a copy of the
ICR in the docket for this rule, and it is
briefly summarized here.
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 final amendments changed
several emission limits as part of the
EPA’s response to the remand granted
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on December 23, 2016, by the D.C.
Circuit. The changes resulted 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 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 34
respondents operating existing large
solid fuel-fired boilers and 5
respondents operating new solid fuelfired 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 recordkeeping and
reporting burden changing records
associated with adjusting operating
parameter limit values, modifying
monitoring plans, and familiarizing
themselves with the changes in the final
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: 39.
Frequency of response: Semi-annual,
annual, periodic.
Total estimated burden: 1,553 hours
(per year). Burden is defined at 5 CFR
1320.3(b).
Total estimated cost: $1,130,000 (per
year), includes $949,000 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
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control number. The OMB control
numbers for the EPA’s regulations in 40
CFR are listed in 40 CFR part 9.
C. 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. Of the 30 entities
(ultimate parent entities, all but two
being in the private sector) determined
to be impacted by this action, two are
small entities. Of these two small
entities, none is expected to incur any
costs as a result of compliance with this
action. More information on these small
entity impacts is available in the RIA.
D. Unfunded Mandates Reform Act
(UMRA)
This action contains a Federal
mandate under UMRA, 2 U.S.C. 1531–
1538, that may result in expenditures of
$100 million or more for state, local,
and tribal governments, in the aggregate,
or the private sector in any one year.
Accordingly, the EPA has prepared a
written statement required under
section 202 of UMRA. The statement is
included in the RIA for this final rule
that is in the docket for this action. This
action is not subject to the requirements
of section 203 of UMRA because it
contains no regulatory requirements that
might significantly or uniquely affect
small governments.
E. Executive Order 13132: Federalism
This action does not have federalism
implications. It will not have substantial
direct effects on the states, on the
relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications as specified in Executive
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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.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
This action is not subject to Executive
Order 13045 because the EPA does not
believe the environmental health risks
or safety risks addressed by this action
present a disproportionate risk to
children. This action’s health and risk
assessments are contained in the RIA.
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H. 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
action 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 final
rule is not likely to have a significant
adverse effect on the supply,
distribution, or use of energy.
I. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
Part 51
This action does not involve any new
technical standards from those
contained in the March 21, 2011, final
rule. Therefore, the EPA did not
consider the use of any voluntary
consensus standards. See 76 FR 15660–
15662 for the NTTAA discussion in the
March 21, 2011, final rule. The EPA is,
however, formalizing the incorporation
of one technical standard that was
already incorporated in 40 CFR 63.14 as
well as in several existing tables in 40
CFR part 63, subpart DDDDD. This
standard is ASTM D6784–02
(Reapproved 2008), Standard Test
Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in
Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro
Method). This method, which describes
the measurement of particle-bound,
oxidized, elemental, and total mercury
in stationary-source flue gases provides
data that can be used for emissions
assessments and reporting as well as the
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certification of continuous mercury
monitoring systems. It describes
equipment and procedures for obtaining
samples of mercury from effluent ducts
and stacks, for laboratory analysis, and
for calculating results. It is applicable
for sampling elemental, oxidized, and
particle-bound mercury in flue gases of
coal-fired stationary sources. It may not
be suitable at all measurement locations,
particularly those with high particulate
loadings. Method applicability is
limited to flue gas stream temperatures
within the thermal stability range of the
sampling probe and filter components.
The standard is available to the public
for free viewing online in the Reading
Room section on ASTM’s website at
https://www.astm.org/
READINGLIBRARY/. Hardcopies and
printable versions are also available for
purchase from ASTM. Additional
information can be found at https://
www.astm.org/products-services/
standards-and-publications.html.
J. 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, lowincome 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 a technical report, Analysis
of Demographic Factors for Populations
Living Near Industrial, Commercial, and
Institutional Boilers and Process
Heaters, available in this docket for this
action (Docket ID EPA–HQ–OAR–2002–
0058).
K. Congressional Review Act (CRA)
This action is subject to the CRA, and
the EPA will submit a rule report to
each House of the Congress and to the
Comptroller General of the United
States. This action is a ‘‘major rule’’ as
defined by U.S.C. 804(2).
List of Subjects in 40 CFR Part 63
Environmental protection, Air
pollution control, Hazardous
substances, Incorporation by reference,
Reporting and recordkeeping
requirements.
Michael S. Regan,
Administrator.
For the reasons stated in the
preamble, 40 CFR part 63 is amended as
follows:
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PART 63—NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS FOR SOURCE
CATEGORIES
1. The authority citation for part 63
continuous to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
Subpart A—General Provisions
2. Section 63.14 is amended by
revising paragraph (h)(103) to read as
follows:
■
§ 63.14
Incorporations by reference.
*
*
*
*
*
(h) * * *
(103) ASTM D6784–02 (Reapproved
2008), Standard Test Method for
Elemental, Oxidized, Particle-Bound
and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary
Sources (Ontario Hydro Method),
Approved April 1, 2008; IBR approved
for §§ 63.2465(d); 63.11646(a); and
63.11647(a) and (d); and tables 1, 2, 5,
11, 12t, 13, 14, and 15 to subpart
DDDDD; tables 4 and 5 to subpart JJJJJ;
tables 4 and 6 to subpart KKKKK; table
5 to subpart UUUUU; appendix A to
subpart UUUUU; and table 4 to subpart
JJJJJJ.
*
*
*
*
*
Subpart DDDDD—National Emission
Standards for Hazardous Air Pollutants
for Major Sources: Industrial,
Commercial, and Institutional Boilers
and Process Heaters
3. Section 63.7500 is amended by
revising paragraphs (a) introductory
text, (a)(1), (c), and (e) to read as
follows:
■
§ 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 § 63.7522. The
output-based emission limits, in units of
pounds per million Btu of steam output,
in Table 1 or 2 to this subpart are an
alternative applicable only to boilers
and process heaters that generate either
steam, cogenerate steam with electricity,
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or both. The output-based emission
limits, in units of pounds per megawatthour, in Table 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 1 of § 63.7575 to
demonstrate compliance with the
output-based emission limits, in units of
pounds per million Btu of steam output,
in Table 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 (iv) of this
section, but on or after October 6, 2025,
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
paragraph (a)(1)(v) of this section, but
on or after October 6, 2025 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 must comply with
either the emission limits in Table 1 to
this subpart or the emission limits in
Table 14 to this subpart until you must
comply with the emission limits in
Table 1.
(v) If you operate an existing boiler or
process heater, you must comply with
either the emission limits in Table 2 to
this subpart or the emission limits in
Table 15 to this subpart until you must
comply with the emission limits in
Table 2.
*
*
*
*
*
(c) Limited-use boilers and process
heaters must complete a tune-up every
5 years as specified in § 63.7540. They
are not subject to the emission limits in
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Tables 1 and 2 or Tables 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 § 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
§ 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
Tables 11 through 15 to this subpart, or
the operating limits in Table 4 to this
subpart.
*
*
*
*
*
4. Section 63.7505 is amended by
revising paragraph (c) to read as follows:
■
§ 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
§ 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 Table 1 or 2 or
Tables 11 through 15 to this subpart.
*
*
*
*
*
5. Section 63.7510 is amended by
revising paragraphs (a) introductory
text, (b), (c), (f), and (j) to read as
follows:
■
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60841
§ 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 Table 1 or
2 or Tables 11 through 15 to 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 Table 1 or 2 or Tables
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 § 63.7521 and Table
6 to this subpart and establish operating
limits according to § 63.7530 and Table
8 to this subpart. The fuels described in
paragraphs (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
§ 63.7525(a). Boilers and process heaters
that use a CO CEMS to comply with the
applicable alternative CO CEMS
emission standard listed in Table 1 or 2
or Tables 11 through 15 to this subpart,
as specified in § 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 § 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 than the applicable
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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 than the applicable emission
limit in Table 1 to this subpart, you
must demonstrate compliance with the
applicable emission limit in Table 1 no
later than October 6, 2025.
*
*
*
*
*
(j) For existing affected sources (as
defined in § 63.7490) that have not
operated between the effective date of
the rule and the compliance date that is
specified for your source in § 63.7495,
you must complete the initial
compliance demonstration, if subject to
the emission limits in Table 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 § 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 § 63.7540(a)(10)(i) through
(vi) no later than 30 days after the restart 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 § 63.7495.
*
*
*
*
*
■ 6. Section 63.7515 is amended by
revising paragraphs (b), (c), (e), (g), and
(i) to read as follows:
§ 63.7515 When must I conduct
subsequent performance tests, fuel
analyses, or tune-ups?
lotter on DSK11XQN23PROD with RULES2
*
*
*
*
*
(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 § 63.7522, you must
continue to conduct performance tests
annually. The requirement to test at
maximum chloride input level is
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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).
*
*
*
*
*
(e) If you demonstrate compliance
with the mercury, HCl, or TSM based on
fuel analysis, you must conduct a
monthly fuel analysis according to
§ 63.7521 for each type of fuel burned
that is subject to an emission limit in
Table 1 or 2 or Tables 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 § 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
§ 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 Table 1 or 2 or
Tables 11 through 15 to this subpart, no
later than 180 days after the re-start of
the affected source and according to the
PO 00000
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Fmt 4701
Sfmt 4700
applicable provisions in § 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
§ 63.7540(a)(10)(i) through (vi) and the
schedule described in § 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 § 63.7525(a)(3) to
demonstrate compliance with the
applicable alternative CO CEMS
emission standard listed in Table 1 or 2
or Tables 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
§ 63.7510(a).
■ 7. Section 63.7520 is amended by
revising paragraph (d) to read as
follows:
§ 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 § 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.
*
*
*
*
*
■ 8. Section 63.7521 is amended by
revising paragraphs (a) and (c)(1)(ii) to
read as follows:
§ 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.
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
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.
*
*
*
*
*
9. Section 63.7522 is amended by
revising paragraphs (b) introductory
text, (d), (e)(1), (e)(2), (h), and (j)(1) to
read as follows:
■
§ 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
paragraphs (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
60843
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 § 63.7495.
(e) * * *
(1) You must use Equation 1a or 1b or
1c to this paragraph (e)(1) 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.
Equation 1a to paragraph (e)( 1)
.4wW~llltfftolu•1.h< 'f-(ErxHRt)+
f:t
(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
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
ta.
,.,,
(Sq.la)
HCl or mercury or TSM using the
applicable equation in § 63.7530(c).
Hm = Maximum rated heat input capacity of
unit, i, in units of million Btu per hour.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
Equation lb to paragraph (e)(l)
. 4 w W ~ • 1.1 x1:(Er xSo)+ 1:So
f•I
steam output. 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 § 63.7530(c). If
you are taking credit for energy
conservation measures from a unit
according to § 63.7533, use the adjusted
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
f«I
emission level for that unit, Eadj,
determined according to § 63.7533 for
that unit.
So = Maximum steam output capacity of
unit, i, in units of million Btu per hour,
as defined in § 63.7575.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
£ (Er x Bo)+£ Eo
lotter on DSK11XQN23PROD with RULES2
; .. t
Where:
AveWeightedEmissions = Average weighted
emissions for PM (or TSM), HCl, or
mercury, in units of pounds per
megawatt hour.
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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
PO 00000
Frm 00029
Fmt 4701
Sfmt 4700
(Bq. 1~)
I •I
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 § 63.7530(c). If you are taking
E:\FR\FM\06OCR2.SGM
06OCR2
ER06OC22.000</GPH>
AveWelglttffErnlsslons • 1.1 x
ER06OC22.001</GPH> ER06OC22.002</GPH>
Equation 1c to paragraph (e)( 1)
60844
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
credit for energy conservation measures
from a unit according to § 63.7533, use
the adjusted emission level for that unit,
Eadj, determined according to § 63.7533
for that unit.
Eo = Maximum electric generating output
capacity of unit, i, in units of megawatt
hour, as defined in § 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 to this paragraph (e)(2) as an
alternative to using Equation 1a of
paragraph (e)(1) 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.
Equation 2 to paragraph (e)(2)
A w W ~ • 1.1:oc
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
,..t(•
,ic
.Sau, QI)•
t(s.
..
,
TSM using the applicable equation in
§ 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
11
01)
(Bq. 2)
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
§ 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 to this paragraph (j)(1).
Equation 6 to paragraph G)(l)
&• 't,(ELtxHI)+
*
*
*
*
*
10. Section 63.7525 is amended by
revising paragraphs (a) introductory
text, (a)(1), (a)(2) introductory text,
(a)(2)(ii), (iv), and (vi), (l) introductory
text, and (m) introductory text to read as
follows:
■
lotter on DSK11XQN23PROD with RULES2
§ 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 Table
1 or 2 or Tables 11 through 15 to this
subpart, you must install, operate, and
maintain an oxygen analyzer system, as
defined in § 63.7575, or install, certify,
operate and maintain continuous
emission monitoring systems for CO and
oxygen (O2) (or carbon dioxide (CO2))
according to the procedures in
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paragraphs (a)(1) through (6) of this
section.
(1) Install the CO CEMS including an
O2 (or CO2) analyzer by the compliance
date specified in § 63.7495. The CO and
O2 (or CO2) levels shall be monitored at
the same location at the outlet of the
boiler or process heater. An owner or
operator may determine compliance
with the CO emissions limit using a CO2
analyzer as the diluent monitor. If a CO2
analyzer is used as the diluent monitor,
EPA Method 19 F-factors in 40 CFR part
60, appendix A–7, for the fuel type(s)
being burned in the unit and EPA
Method 19 equations in 40 CFR part 60,
appendix A–7, must be used to calculate
the emissions corrected to 3 percent O2
using the measured CO2 percentage, and
must also take into account that the 3
percent oxygen correction is to be done
on a dry basis. The equations used to
calculate the emissions, must also
account for any CO2 being added to, or
removed from, the emissions gas stream
as a result of limestone injection,
scrubber media, etc. The methodology
used to calculate the CO emissions and
the methodology used to account for
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{Bq. 6)
rst
any CO2 being added to, or removed
from the emissions gas stream shall be
detailed and approved in the sitespecific monitoring plan developed
according to § 63.7505(d).
(2) To demonstrate compliance with
the applicable alternative CO CEMS
emission standard listed in Table 1 or 2
or Tables 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 sitespecific monitoring plan developed
according to § 63.7505(d); and the
requirements in § 63.7540(a)(8) and this
paragraph (a). 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
§ 63.7505(d), and the requirements in
§ 63.7540(a)(8) and this paragraph (a)
must use the CO CEMS to comply with
the applicable alternative CO CEMS
E:\FR\FM\06OCR2.SGM
06OCR2
ER06OC22.004</GPH>
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.
!:,n,
ER06OC22.003</GPH>
,,.,
lotter on DSK11XQN23PROD with RULES2
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
emission standard listed in Table 1 or 2
or Tables 11 through 15 to this subpart.
*
*
*
*
*
(ii) During each relative accuracy test
run of the CO CEMS, you must collect
emission data for CO concurrently using
both the CO CEMS and Method 10, 10A,
or 10B at 40 CFR part 60, appendix A–
4. The relative accuracy testing must be
conducted at representative operating
conditions.
*
*
*
*
*
(iv) Any CO CEMS that does not
comply with this paragraph (a) cannot
be used to meet any requirement in this
subpart to demonstrate compliance with
a CO emission limit listed in Table 1 or
2 or Tables 11 through 15 to this
subpart.
*
*
*
*
*
(vi) When CO2 is used to correct CO
emissions and CO2 is measured on a wet
basis, if needed, correct for moisture as
follows: Install, operate, maintain, and
quality assure a continuous moisture
monitoring system for measuring and
recording the moisture content of the
flue gases, in order to correct the
measured hourly volumetric flow rates
for moisture when calculating CO
concentrations. The following
continuous moisture monitoring
systems are acceptable: a continuous
moisture sensor; an oxygen analyzer (or
analyzers) capable of measuring O2 both
on a wet basis and on a dry basis; or a
stack temperature sensor and a moisture
look-up table, i.e., a psychrometric chart
(for saturated gas streams following wet
scrubbers or other demonstrably
saturated gas streams, only). The
moisture monitoring system shall
include as a component the automated
data acquisition and handling system
(DAHS) for recording and reporting both
the raw data (e.g., hourly average wetand dry-basis O2 values) and the hourly
average values of the stack gas moisture
content derived from those data. When
a moisture look-up table is used, the
moisture monitoring system shall be
represented as a single component, the
certified DAHS, in the monitoring plan
for the unit or common stack.
*
*
*
*
*
(l) For each unit for which you decide
to demonstrate compliance with the
mercury or HCl emissions limits in
Table 1 or 2 or Tables 11 through 15 to
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
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
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on the date of approval of a site-specific
monitoring plan.
*
*
*
*
*
(m) If your unit is subject to a HCl
emission limit in Table 1 or 2 or Tables
11 through 15 to 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.
*
*
*
*
*
■ 11. Section 63.7530 is amended by
revising paragraphs (b)(4)(ii)(E),
(b)(4)(iii), and (h) to read as follows:
§ 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 Table 1 or 2 or
Tables 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 in 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 § 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
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60845
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 Table 1 or
2 or Tables 11 through 15 to this
subpart, you must meet the work
practice standard according to Table 3
to this subpart. During startup and
shutdown, you must only follow the
work practice standards according to
items 5 and 6 of Table 3 to this subpart.
*
*
*
*
*
12. Section 63.7533 is amended by
revising paragraphs (a), (e), and (f) to
read as follows:
■
§ 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 § 63.7522(e) and for
demonstrating monthly compliance
according to § 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 https://
www.epa.gov/ttn/atw/boiler/
boilerpg.html.
*
*
*
*
*
(e) The emissions rate as calculated
using Equation 20 in paragraph (f) 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
E:\FR\FM\06OCR2.SGM
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60846
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
the compliance date specified in
§ 63.7495.
(f) You must use Equation 20 of this
paragraph (f) 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.
Equation 20 to paragraph (f)
*
*
*
*
*
13. Section 63.7540 is amended by
revising paragraphs (a) introductory
text, (a)(8) introductory text, (a)(8)(ii),
(a)(9), (a)(15) introductory text, (a)(19)
introductory text, and (b) to read as
follows:
■
lotter on DSK11XQN23PROD with RULES2
§ 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 Table 1 or 2 or
Tables 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 Table 1 or
2 or Tables 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
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18:23 Oct 05, 2022
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your site-specific monitoring plan as
required in § 63.7505(d).
*
*
*
*
*
(15) If you are using a CEMS to
measure HCl emissions to meet
requirements of this subpart, you must
install, certify, operate, and maintain
the HCl CEMS as specified in
paragraphs (a)(15)(i) and (ii) of this
section. This option for an affected unit
takes effect on the date of approval of
a site-specific monitoring plan.
*
*
*
*
*
(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 Table 1 or 2 or Tables 11
through 15 to 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 § 63.7550.
*
*
*
*
*
14. Section 63.7545 is amended by
revising paragraph (e)(3) to read as
follows:
■
§ 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
Table 1 or 2 or Tables 11 through 15 to
this subpart, if you are not using a CO
CEMS to demonstrate compliance.
*
*
*
*
*
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15. Section 63.7555 is amended by
revising paragraphs (d) introductory text
and (d)(5) to read as follows:
■
§ 63.7555
What records must I keep?
*
*
*
*
*
(d) For each boiler or process heater
subject to an emission limit in Table 1
or 2 or Tables 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 § 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.
*
*
*
*
*
■ 16. Section 63.7575 is amended by:
■ a. Adding in alphabetical order the
definition for ‘‘12-month rolling
average’’;
■ b. Revising the definition of ‘‘Other
gas 1 fuel’’; and
■ c. Revising paragraphs (3) and (4)
under the definition of ‘‘Steam output.’’
The addition and revisions read as
follows:
§ 63.7575
subpart?
What definitions apply to this
*
*
*
*
*
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
E:\FR\FM\06OCR2.SGM
06OCR2
ER06OC22.005</GPH>
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 to paragraph (c)(3)(i) of this section
for the affected boiler.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
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,
2, 14, or 15 to 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
60847
only turbine as paragraph (3) of this
definition (MW3) and would be
calculated using Equation 1 to this
definition. 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 its (steam energy) contribution
(fraction of total steam energy) to the
common header.
Equation 1 to the definition Steam Output
SOM
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 paragraph (2) of this
definition, MMBtu.
MW(3) = Electricity generated according to
paragraph (3) of this definition, MWh.
= S1 + S2 + (MWc 3) x CFn)
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.
(Eq. 1)
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.
*
*
*
*
*
17. Table 1 to subpart DDDDD of part
63 is revised to read as follows:
■
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS c
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
1. Units in all subcategories designed to
burn solid fuel.
a. HCl ...........................
2.1E–04 a lb per MMBtu of heat
input.
2.9E–04 a lb per MMBtu of steam
output or 2.7E–03 a lb per MWh.
b. Mercury ....................
8.0E–07 a lb per MMBtu of heat
input.
8.7E–07a lb per MMBtu of steam
output or 1.1E–05 a lb per MWh.
2. Units designed to
burn coal/solid fossil
fuel.
a. Filterable PM (or
TSM).
1.1E–03 lb per MMBtu of heat
input; or (2.3E–05 lb per MMBtu
of heat input).
3. Pulverized coal boilers designed to burn
coal/solid fossil fuel.
a. Carbon monoxide
(CO) (or CEMS).
4. Stokers/others designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
5. Fluidized bed units
designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to
3-percent oxygen d, 30-day rolling
average).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
1.1E–03 lb per MMBtu of steam
output or 1.4E–02 lb per MWh; or
(2.7E–05 lb per MMBtu of steam
output or 2.9E–04 lb per MWh).
0.11 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
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Using this specified sampling
volume or test run duration . . .
For M26A, collect a minimum of 1
dscm per run; for M26 collect a
minimum of 120 liters per run.
For M29, collect a minimum of 4
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 4 dscm.
Collect a minimum of 3 dscm per
run.
0.12 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
0.11 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
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lotter on DSK11XQN23PROD with RULES2
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
60848
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS c—Continued
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
6. Fluidized bed units
with an integrated
heat exchanger designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
1.2E–01 lb per MMBtu of steam
output or 1.5 lb per MWh; 3-run
average.
1 hr minimum sampling time.
7. Stokers/sloped grate/
others designed to
burn wet biomass fuel.
a. CO (or CEMS) .........
140 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
590 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (390 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
1.3E–02 lb per MMBtu of heat
input; or (2.6E–05 lb per MMBtu
of heat input).
6.1E–01 lb per MMBtu of steam
output or 6.5 lb per MWh; 3-run
average.
1 hr minimum sampling time.
1.4E–02 lb per MMBtu of steam
output or 1.9E–01 lb per MWh; or
(2.7E–05 lb per MMBtu of steam
output or 3.7E–04 lb per MWh).
4.3E–01 lb per MMBtu of steam
output or 5.1 lb per MWh.
Collect a minimum of 2 dscm per
run.
3.5E–02 lb per MMBtu of steam
output or 4.2E–01 lb per MWh; or
(5.2E–03 lb per MMBtu of steam
output or 7.0E–02 lb per MWh).
1.3E–01 lb per MMBtu of steam
output or 1.5 lb per MWh; 3-run
average.
Collect a minimum of 2 dscm per
run.
b. Filterable PM (or
TSM).
8. Stokers/sloped grate/
others designed to
burn kiln-dried biomass fuel.
a. CO ...........................
460 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. Filterable PM (or
TSM).
3.0E–02 lb per MMBtu of heat
input; or (5.0E–03 lb per MMBtu
of heat input).
9. Fluidized bed units
a. CO (or CEMS) .........
designed to burn biomass/bio-based solids.
b. Filterable PM (or
TSM).
10. Suspension burners
a. CO (or CEMS) .........
designed to burn biomass/bio-based solids.
b. Filterable PM (or
TSM).
11. Dutch Ovens/Pile
burners designed to
burn biomass/biobased solids.
a. CO (or CEMS) .........
lotter on DSK11XQN23PROD with RULES2
b. Filterable PM (or
TSM).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
4.1E–03 lb per MMBtu of heat
input; or (8.4E–06 a lb per MMBtu
of heat input).
220 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (2,000 ppm by
volume on a dry basis corrected
to 3-percent oxygen,d 10-day rolling average).
3.0E–02 lb per MMBtu of heat
input; or (8.0E–03 lb per MMBtu
of heat input).
330 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to
3-percent oxygen,d 10-day rolling
average).
2.5E–03 lb per MMBtu of heat
input; or (3.9E–05 lb per MMBtu
of heat input).
12. Fuel cell units dea. CO ...........................
signed to burn biomass/bio-based solids.
b. Filterable PM (or
TSM).
910 ppm by volume on a dry basis
corrected to 3-percent oxygen.
13. Hybrid suspension
grate boiler designed
to burn biomass/biobased solids.
180 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (900 ppm by volume on a dry basis corrected to
3-percent oxygen d, 30-day rolling
average).
2.6E–02 lb per MMBtu of heat
input; or (4.4E–04 lb per MMBtu
of heat input).
a. CO (or CEMS) .........
b. Filterable PM (or
TSM).
14. Units designed to
burn liquid fuel.
VerDate Sep<11>2014
a. HCl ...........................
18:23 Oct 05, 2022
Jkt 259001
1.1E–02 lb per MMBtu of heat
input; or (2.9E–05 lb per MMBtu
of heat input).
1.5E–04 a lb per MMBtu of heat
input.
PO 00000
Frm 00034
Fmt 4701
Using this specified sampling
volume or test run duration . . .
1 hr minimum sampling time.
1 hr minimum sampling time.
5.0E–03 lb per MMBtu of steam Collect a minimum of 3 dscm per
run.
output or 5.8E–02 lb per MWh; or
(1.1E–05 a lb per MMBtu of steam
a
output or 1.2E–04 lb per MWh).
0.18 lb per MMBtu of steam output 1 hr minimum sampling time.
or 2.5 lb per MWh; 3-run average.
3.1E–02 lb per MMBtu of steam
output or 4.2E–01 lb per MWh; or
(8.1E–03 lb per MMBtu of steam
output or 1.2E–01 lb per MWh).
3.5E–01 lb per MMBtu of steam
output or 3.6 lb per MWh; 3-run
average.
3.4E–03 lb per MMBtu of steam
output or 3.5E–02 lb per MWh; or
(5.2E–05 lb per MMBtu of steam
output or 5.5E–04 lb per MWh).
1.1 lb per MMBtu of steam output
or 1.0E+01 lb per MWh.
Collect a minimum of 2 dscm per
run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per
run.
1 hr minimum sampling time.
2.0E–02 lb per MMBtu of steam Collect a minimum of 2 dscm per
output or 1.6E–01 lb per MWh; or
run.
(5.1E–05 lb per MMBtu of steam
output or 4.1E–04 lb per MWh).
0.22 lb per MMBtu of steam output 1 hr minimum sampling time.
or 2.0 lb per MWh; 3-run average.
3.3E–02 lb per MMBtu of steam
output or 3.7E–01 lb per MWh; or
(5.5E–04 lb per MMBtu of steam
output or 6.2E–03 lb per MWh).
1.7E–04 a lb per MMBtu of steam
output or 2.1E–03 a lb per MWh.
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
Collect a minimum of 3 dscm per
run.
For M26A: Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60849
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS c—Continued
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
If your boiler or process
heater is in this
subcategory . . .
15. Units designed to
burn heavy liquid fuel.
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
b. Mercury ....................
4.8E–07 a lb per MMBtu of heat
input.
5.3E–07 a lb per MMBtu of steam
output or 6.7E–06 a lb per MWh.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average.
1.9E–03 lb per MMBtu of heat
input; or (6.1E–06 a lb per MMBtu
of heat input).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
b. Filterable PM (or
TSM).
16. Units designed to
burn light liquid fuel.
a. CO ...........................
b. Filterable PM (or
TSM).
17. Units designed to
burn liquid fuel that
are non-continental
units.
18. Units designed to
burn gas 2 (other)
gases.
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
1.1E–03 a lb per MMBtu of heat
input; or (2.9E–05 lb per MMBtu
of heat input).
Using this specified sampling
volume or test run duration . . .
For M29, collect a minimum of 4
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 4 dscm.
1 hr minimum sampling time.
2.1E–03 lb per MMBtu of steam
output or 2.7E–02 lb per MWh; or
(6.7E–6 a lb per MMBtu of steam
output or 8.5E–5 a lb per MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh.
1.2E–03 a lb per MMBtu of steam
output or 1.6E–02 a lb per MWh;
or (3.2E–05 lb per MMBtu of
steam output or 4.0E–04 lb per
MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
Collect a minimum of 3 dscm per
run.
2.5E–02 lb per MMBtu of steam
output or 3.2E–01 lb per MWh; or
(9.4E–04 lb per MMBtu of steam
output or 1.2E–02 lb per MWh).
0.16 lb per MMBtu of steam output
or 1.0 lb per MWh.
Collect a minimum of 4 dscm per
run.
For M26A, collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 3 dscm.
Collect a minimum of 3 dscm per
run.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average based on stack test.
b. Filterable PM (or
TSM).
2.3E–02 lb per MMBtu of heat
input; or (8.6E–04 lb per MMBtu
of heat input).
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. HCl ...........................
1.7E–03 lb per MMBtu of heat input
2.9E–03 lb per MMBtu of steam
output or 1.8E–02 lb per MWh.
c. Mercury ....................
7.9E–06 lb per MMBtu of heat input
1.4E–05 lb per MMBtu of steam
output or 8.3E–05 lb per MWh.
d. Filterable PM (or
TSM).
7.3E–03 lb per MMBtu of heat
input; or (2.1E–04 lb per MMBtu
of heat input).
1.3E–02 lb per MMBtu of steam
output or 7.6E–02 lb per MWh; or
(3.5E–04 lb per MMBtu of steam
output or 2.2E–03 lb per MWh).
1 hr minimum sampling time.
Collect a minimum of 3 dscm per
run.
1 hr minimum sampling time.
1 hr minimum sampling time.
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 § 63.7515 if all of the other provisions of § 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 § 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 Table 11, 12, or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before October 6, 2025 you may
comply with the emission limits in Table 14 to this subpart. On and after October 6, 2025 you must comply with the emission limits in this Table 1.
d An owner or operator may determine compliance with the carbon monoxide emissions limit using CO as a diluent correction in place of oxygen as described in
2
§ 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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 methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
18. Table 2 to subpart DDDDD of part
63 is revised to read as follows:
■
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS d
lotter on DSK11XQN23PROD with RULES2
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
1. Units in all subcategories designed to
burn solid fuel.
a. HCl ...........................
2.0E–02 lb per MMBtu of heat input
2.3E–02 lb per MMBtu of steam
output or 0.26 lb per MWh.
VerDate Sep<11>2014
18:23 Oct 05, 2022
Jkt 259001
PO 00000
Frm 00035
Fmt 4701
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
Using this specified sampling
volume or test run duration . . .
For M26A, collect a minimum of 1
dscm per run; for M26, collect a
minimum of 120 liters per run.
60850
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS d—
Continued
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
b. Mercury ....................
5.4E–06 lb per MMBtu of heat input
6.2E–06 lb per MMBtu of steam
output or 6.9E–05 lb per MWh.
2. Units design to burn
coal/solid fossil fuel.
a. Filterable PM (or
TSM).
3.9E–02 lb per MMBtu of heat
input; or (5.3E–05 lb per MMBtu
of heat input).
3. Pulverized coal boilers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS) .........
4. Stokers/others designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
5. Fluidized bed units
designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
6. Fluidized bed units
with an integrated
heat exchanger designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
7. Stokers/sloped grate/
others designed to
burn wet biomass fuel.
a. CO (or CEMS) .........
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
150 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
140 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
1,100 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (720 ppm
by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average).
3.4E–02 lb per MMBtu of heat
input; or (2.0E–04 lb per MMBtu
of heat input).
4.1E–02 lb per MMBtu of steam
output or 4.8E–01 lb per MWh; or
(5.6E–05 lb per MMBtu of steam
output or 6.5E–04 lb per MWh).
0.11 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
If your boiler or process
heater is in this
subcategory . . .
b. Filterable PM (or
TSM).
8. Stokers/sloped grate/
others designed to
burn kiln-dried biomass fuel.
9. Fluidized bed units
designed to burn biomass/bio-based solid.
a. CO ...........................
460 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. Filterable PM (or
TSM).
3.2E–01 lb per MMBtu of heat
input; or (5.0E–03 lb per MMBtu
of heat input).
a. CO (or CEMS) .........
210 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
7.4E–03 lb per MMBtu of heat
input; or (6.4E–05 lb per MMBtu
of heat input).
b. Filterable PM (or
TSM).
lotter on DSK11XQN23PROD with RULES2
10. Suspension burners
designed to burn biomass/bio-based solid.
a. CO (or CEMS) .........
b. Filterable PM (or
TSM).
VerDate Sep<11>2014
18:23 Oct 05, 2022
Jkt 259001
2,400 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (2,000
ppm by volume on a dry basis
corrected to 3-percent oxygen,c
10-day rolling average).
4.1E–02 lb per MMBtu of heat
input; or (8.0E–03 lb per MMBtu
of heat input).
PO 00000
Frm 00036
Fmt 4701
Using this specified sampling
volume or test run duration . . .
For M29, collect a minimum of 3
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 3 dscm.
Collect a minimum of 2 dscm per
run.
0.14 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.6 lb per MWh; 3-run average.
0.12 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
1.3E–01 lb per MMBtu of steam
output or 1.5 lb per MWh; 3-run
average.
1 hr minimum sampling time.
1.1 lb per MMBtu of steam output
or 13 lb per MWh; 3-run average.
1 hr minimum sampling time.
4.0E–02 lb per MMBtu of steam
output or 4.8E–01 lb per MWh; or
(2.4E–04 lb per MMBtu of steam
output or 2.8E–03 lb per MWh).
4.2E–01 lb per MMBtu of steam
output or 5.1 lb per MWh.
Collect a minimum of 2 dscm per
run.
3.7E–01 lb per MMBtu of steam
output or 4.5 lb per MWh; or
(5.9E–03 lb per MMBtu of steam
output or 7.0E–02 lb per MWh).
2.1E–01 lb per MMBtu of steam
output or 2.3 lb per MWh; 3-run
average.
Collect a minimum of 1 dscm per
run.
9.2E–03 lb per MMBtu of steam
output or 0.11 lb per MWh; or
(8.0E–05 lb per MMBtu of steam
output or 9.0E–04 lb per MWh).
1.9 lb per MMBtu of steam output
or 27 lb per MWh; 3-run average.
4.2E–02 lb per MMBtu of steam
output or 5.8E–01 lb per MWh; or
(8.1E–03 lb per MMBtu of steam
output or 0.12 lb per MWh).
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 1 dscm per
run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per
run.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60851
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS d—
Continued
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
11. Dutch Ovens/Pile
burners designed to
burn biomass/biobased solid.
a. CO (or CEMS) .........
770 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to
3-percent oxygen,c 10-day rolling
average).
1.8E–01 lb per MMBtu of heat
input; or (2.0E–03 lb per MMBtu
of heat input).
8.4E–01 lb per MMBtu of steam
output or 8.4 lb per MWh; 3-run
average.
1 hr minimum sampling time.
2.5E–01 lb per MMBtu of steam
output or 2.6 lb per MWh; or
(2.8E–03 lb per MMBtu of steam
output or 2.8E–02 lb per MWh).
2.4 lb per MMBtu of steam output
or 12 lb per MWh.
Collect a minimum of 1 dscm per
run.
5.5E–02 lb per MMBtu of steam
output or 2.8E–01 lb per MWh; or
(1.6E–02 lb per MMBtu of steam
output or 8.1E–02 lb per MWh).
3.5 lb per MMBtu of steam output
or 39 lb per MWh; 3-run average.
Collect a minimum of 2 dscm per
run.
b. Filterable PM (or
TSM).
12. Fuel cell units designed to burn biomass/bio-based solid.
a. CO ...........................
b. Filterable PM (or
TSM).
13. Hybrid suspension
grate units designed
to burn biomass/biobased solid.
a. CO (or CEMS) .........
b. Filterable PM (or
TSM).
14. Units designed to
burn liquid fuel.
15. Units designed to
burn heavy liquid fuel.
lotter on DSK11XQN23PROD with RULES2
18. Units designed to
burn gas 2 (other)
gases.
...................................
VerDate Sep<11>2014
5.5E–01 lb per MMBtu of steam
output or 6.2 lb per MWh; or
(5.7E–04 lb per MMBtu of steam
output or 6.3E–03 lb per MWh).
1.4E–03 lb per MMBtu of steam
output or 1.6E–02 lb per MWh.
1.1E–03 lb per MMBtu of heat input
b. Mercury ....................
7.3E–07 lb per MMBtu of heat input
8.8E–07 lb per MMBtu of steam
output or 1.1E–05 lb per MWh.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average.
5.9E–02 lb per MMBtu of heat
input; or (2.0E–04 lb per MMBtu
of heat input).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
a. CO ...........................
b. Filterable PM (or
TSM).
17. Units designed to
burn liquid fuel that
are non-continental
units.
3,500 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (900 ppm
by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average).
4.4E–01 lb per MMBtu of heat
input; or (4.5E–04 lb per MMBtu
of heat input).
a. HCl ...........................
b. Filterable PM (or
TSM).
16. Units designed to
burn light liquid fuel.
1,100 ppm by volume on a dry
basis corrected to 3-percent oxygen.
2.0E–02 lb per MMBtu of heat
input; or (5.8E–03 lb per MMBtu
of heat input).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
7.9E–03 lb per MMBtu of heat
input; or (6.2E–05 lb per MMBtu
of heat input).
For M26A, collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 2 dscm.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. HCl ...........................
1.7E–03 lb per MMBtu of heat input
2.9E–03 lb per MMBtu of steam
output or 1.8E–02 lb per MWh.
c. Mercury ....................
7.9E–06 lb per MMBtu of heat input
1.4E–05 lb per MMBtu of steam
output or 8.3E–05 lb per MWh.
Fmt 4701
For M26A, collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B
collect a minimum sample as
specified in the method, for
ASTM D6784 b collect a minimum
of 2 dscm.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per
run.
2.2E–01 lb per MMBtu of heat
input; or (8.6E–04 lb per MMBtu
of heat input).
Frm 00037
Collect a minimum of 1 dscm per
run.
2.7E–01 lb per MMBtu of steam
output or 3.1 lb per MWh; or
(1.1E–03 lb per MMBtu of steam
output or 1.2E–02 lb per MWh).
0.16 lb per MMBtu of steam output
or 1.0 lb per MWh.
b. Filterable PM (or
TSM).
PO 00000
1 hr minimum sampling time.
Collect a minimum of 1 dscm per
run.
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average based on stack test.
Jkt 259001
1 hr minimum sampling time.
7.2E–02 lb per MMBtu of steam
output or 8.2E–01 lb per MWh; or
(2.5E–04 lb per MMBtu of steam
output or 2.8E–03 lb per MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh.
9.6E–03 lb per MMBtu of steam
output or 1.1E–01 lb per MWh; or
(7.5E–05 lb per MMBtu of steam
output or 8.6E–04 lb per MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
a. CO ...........................
18:23 Oct 05, 2022
Using this specified sampling
volume or test run duration . . .
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
1 hr minimum sampling time.
Collect a minimum of 3 dscm per
run.
1 hr minimum sampling time.
1 hr minimum sampling time.
60852
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS d—
Continued
[As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour
or greater]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
d. Filterable PM (or
TSM).
7.3E–03 lb per MMBtu of heat input
or (2.1E–04 lb per MMBtu of heat
input).
1.3E–02 lb per MMBtu of steam
output or 7.6E–02 lb per MWh; or
(3.5E–04 lb per MMBtu of steam
output or 2.2E–03 lb per MWh).
Using this specified sampling
volume or test run duration . . .
Collect a minimum of 3 dscm per
run.
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 § 63.7515 if all of the other provisions of § 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 § 63.14.
c An owner or operator may determine compliance with the carbon monoxide emissions limit be determined using CO as a diluent correction in place of oxygen as
2
described in § 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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 methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
d Before October 6, 2025 you may comply with the emission limits in Table 15 to this subpart. On and after October 6, 2025], you must comply with the emission
limits in this Table 2.
■ 19. Table 3 of subpart DDDDD of part
63 is amended by revising the entries
‘‘5.’’ and ‘‘6.’’ to read as follows:
*
*
*
*
*
TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS
If your unit is . . .
*
You must meet the following . . .
*
5. An existing or new boiler
or process heater subject
to emission limits in Table
1 or 2 or 11 through 15 to
this subpart during startup.
lotter on DSK11XQN23PROD with RULES2
6. An existing or new boiler
or process heater subject
to emission limits in Table
1 or 2 or Tables 11
through 15 to this subpart
during shutdown.
*
*
*
*
*
a. You must operate all CMS during startup.
b. For startup of a boiler or process heater, you must use 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, fuel oilsoaked 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.
(1) If you choose to comply using paragraph (1) of the definition of ‘‘startup’’ in § 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 paragraph (2) of the definition of ‘‘startup’’ in § 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 § 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 § 63.7535(b). You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.7555.
You must operate all CMS during shutdown.
While firing fuels that are not clean fuels during shutdown, you must vent emissions to the main stack(s) and 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.
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60853
TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS—Continued
If your unit is . . .
You must meet the following . . .
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
§ 63.7535(b). You must keep records during periods of shutdown. You must provide reports concerning activities and periods of shutdown, as specified in § 63.7555.
a As specified in § 63.7555(d)(13), the source may request an alternative timeframe with the PM controls requirement to the permitting authority
(state, local, or tribal agency) that has been delegated authority for this subpart by EPA. The source must provide evidence that (1) it is unable to
safely engage and operate the PM control(s) to meet the ‘‘fuel firing + 1 hour’’ requirement and (2) the PM control device is appropriately designed and sized to meet the filterable PM emission limit. It is acknowledged that there may be another control device that has been installed
other than ESP that provides additional PM control (e.g., scrubber).
20. Table 4 to subpart DDDDD of part
63 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
When complying with a numerical emission limit under Table 1, 2, 11, 12, 13, 14,
or 15 of this subpart using . . .
*
*
*
*
*
*
*
*
*
You must meet these operating limits . . .
*
*
*
21. Table 7 to subpart DDDDD of part
63 is revised to read as follows:
■
TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS a b
lotter on DSK11XQN23PROD with RULES2
[As stated in § 63.7520, you must comply with the following requirements for establishing operating limits:]
If you have an applicable emission limit
for . . .
And your operating
limits are based
on . . .
1. PM, TSM, or mercury
VerDate Sep<11>2014
You must . . .
Using . . .
According to the following
requirements
a. Wet scrubber operating parameters.
i. Establish a site-specific minimum
scrubber pressure drop and minimum flow rate operating limit according to § 63.7530(b).
(1) Data from the scrubber pressure drop and liquid flow rate
monitors and the PM, TSM, or
mercury performance test.
b. Electrostatic precipitator operating parameters (option only
for units that operate
wet scrubbers).
i. Establish a site-specific minimum
total secondary electric power
input according to § 63.7530(b).
(1) Data from the voltage and secondary amperage monitors during the PM or mercury performance test.
c. Opacity .....................
i. Establish a site-specific maximum
opacity level.
(1) Data from the opacity monitoring system during the PM performance test.
(a) You must collect scrubber pressure drop and liquid flow rate
data every 15 minutes during the
entire period of the performance
tests.
(b) Determine the lowest hourly average scrubber pressure drop
and liquid flow rate by computing
the hourly averages using all of
the 15-minute readings taken
during each performance test.
(a) You must collect secondary
voltage and secondary amperage
for each ESP cell and calculate
total secondary electric power
input data every 15 minutes during the entire period of the performance tests.
(b) Determine the average total
secondary electric power input by
computing the hourly averages
using all of the 15-minute readings taken during each performance test.
(a) You must collect opacity readings every 15 minutes during the
entire period of the performance
tests.
(b) Determine the average hourly
opacity reading by computing the
hourly averages using all of the
15-minute readings taken during
each performance test.
(c) Determine the highest hourly
average opacity reading measured during the test run demonstrating compliance with the
PM (or TSM) emission limitation.
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS a b—Continued
lotter on DSK11XQN23PROD with RULES2
[As stated in § 63.7520, you must comply with the following requirements for establishing operating limits:]
If you have an applicable emission limit
for . . .
And your operating
limits are based
on . . .
2. HCl ............................
You must . . .
Using . . .
According to the following
requirements
a. Wet scrubber operating parameters.
i. Establish site-specific minimum
effluent pH and flow rate operating
limits
according
to
§ 63.7530(b).
(1) Data from the pH and liquid
flow-rate monitors and the HCl
performance test.
b. Dry scrubber operating parameters.
i. Establish a site-specific minimum
sorbent injection rate operating
limit according to § 63.7530(b). If
different acid gas sorbents are
used during the HCl performance
test, the average value for each
sorbent becomes the site-specific
operating limit for that sorbent.
(1) Data from the sorbent injection
rate monitors and HCl or mercury
performance test.
(a) You must collect pH and liquid
flow-rate data every 15 minutes
during the entire period of the
performance tests.
(b) Determine the hourly average
pH and liquid flow rate by computing the hourly averages using
all of the 15-minute readings
taken during each performance
test.
(a) You must collect sorbent injection rate data every 15 minutes
during the entire period of the
performance tests.
c. Alternative Maximum
SO2 emission rate.
i. Establish a site-specific maximum
SO2 emission rate operating limit
according to § 63.7530(b).
(1) Data from SO2 CEMS and the
HCl performance test.
3. Mercury .....................
a. Activated carbon injection.
i. Establish a site-specific minimum
activated carbon injection rate
operating limit according to
§ 63.7530(b).
(1) Data from the activated carbon
rate monitors and mercury performance test.
4. Carbon monoxide for
which compliance is
demonstrated by a
performance test.
a. Oxygen .....................
i. Establish a unit-specific limit for
minimum oxygen level according
to § 63.7530(b).
(1) Data from the oxygen analyzer
system specified in § 63.7525(a).
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(b) Determine the hourly average
sorbent injection rate by computing the hourly averages using
all of the 15-minute readings
taken during each performance
test.
(c) Determine the lowest hourly average of the three test run averages established during the performance test as your operating
limit. When your unit operates at
lower loads, multiply your sorbent
injection rate by the load fraction,
as defined in § 63.7575, to determine the required injection rate.
(a) You must collect the SO2 emissions
data
according
to
§ 63.7525(m) during the most recent HCl performance tests.
(b) The maximum SO2 emission
rate is equal to the highest hourly
average SO2 emission rate
measured during the most recent
HCl performance tests.
(a) You must collect activated carbon injection rate data every 15
minutes during the entire period
of the performance tests.
(b) Determine the hourly average
activated carbon injection rate by
computing the hourly averages
using all of the 15-minute readings taken during each performance test.
(c) Determine the lowest hourly average established during the performance test as your operating
limit. When your unit operates at
lower loads, multiply your activated carbon injection rate by the
load fraction, as defined in
§ 63.7575, to determine the required injection rate.
(a) You must collect oxygen data
every 15 minutes during the entire period of the performance
tests.
(b) Determine the hourly average
oxygen concentration by computing the hourly averages using
all of the 15-minute readings
taken during each performance
test.
(c) Determine the lowest hourly average established during the performance test as your minimum
operating limit.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60855
TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS a b—Continued
[As stated in § 63.7520, you must comply with the following requirements for establishing operating limits:]
If you have an applicable emission limit
for . . .
And your operating
limits are based
on . . .
5. Any pollutant for
which compliance is
demonstrated by a
performance test.
a. Boiler or process
i. Establish a unit specific limit for
heater operating load.
maximum operating load according to § 63.7520(c).
You must . . .
Using . . .
According to the following
requirements
(1) Data from the operating load
monitors or from steam generation monitors.
(a) You must collect operating load
or steam generation data every
15 minutes during the entire period of the performance test.
(b) Determine the average operating load by computing the hourly averages using all of the 15minute readings taken during
each performance test.
(c) Determine the highest hourly
average of the three test run
averages during the performance
test, and multiply this by 1.1 (110
percent) as your operating limit.
a Operating
limits must be confirmed or reestablished during performance tests.
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.
■ 22. Table 8 to subpart DDDDD of part
63 is amended by revising entry ‘‘8.’’ to
read as follows:
*
*
*
*
*
TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE
If you must meet the following operating limits or
work practice standards . . .
*
You must demonstrate continuous compliance by . . .
*
*
8. Emission limits using fuel
analysis.
*
*
*
*
a. Conduct monthly fuel analysis for HCl 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 Equation 15 and Equations 16, 17, and/or 18 in § 63.7530.
*
*
*
*
*
*
*
23. Table 11 to subpart DDDDD of part
63 is revised to read as follows:
■
lotter on DSK11XQN23PROD with RULES2
TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011
If your boiler or process heater
is in this subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the following
emission limits, except during periods of
startup and shutdown . . .
Using this specified sampling volume or test
run duration . . .
1. Units in all subcategories designed to burn solid fuel.
a. HCl .......................................
0.022 lb per MMBtu of heat input ......................
2. Units in all subcategories designed to burn solid fuel that
combust at least 10 percent
biomass/bio-based solids on
an annual heat input basis
and less than 10 percent coal/
solid fossil fuels on an annual
heat input basis.
a. Mercury ................................
8.0E–07 a lb per MMBtu of heat input ...............
For M26A, collect a minimum of 1 dscm per
run; for M26 collect a minimum of 120 liters
per run.
For M29, collect a minimum of 4 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 4 dscm.
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60856
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued
If your boiler or process heater
is in this subcategory . . .
For the following pollutants
The emissions must not exceed the following
emission limits, except during periods of
startup and shutdown . . .
Using this specified sampling volume or test
run duration . . .
3. Units in all subcategories designed to burn solid fuel that
combust at least 10 percent
coal/solid fossil fuels on an
annual heat input basis and
less than 10 percent biomass/
bio-based solids on an annual
heat input basis.
4. Units design to burn coal/
solid fossil fuel.
5. Pulverized coal boilers designed to burn coal/solid fossil
fuel.
a. Mercury ................................
2.0E–06 lb per MMBtu of heat input .................
For M29, collect a minimum of 4 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 4 dscm.
a. Filterable PM (or TSM) ........
Collect a minimum of 3 dscm per run.
6. Stokers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS). ....................
7. Fluidized bed units designed
to burn coal/solid fossil fuel.
a. CO (or CEMS) .....................
8. Fluidized bed units with an integrated heat exchanger designed to burn coal/solid fossil
fuel.
9. Stokers/sloped grate/others
designed to burn wet biomass
fuel.
a. CO (or CEMS) .....................
1.1E–03 lb per MMBtu of heat input; or (2.3E–
05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (320
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (340
ppm by volume on a dry basis corrected to 3
percent oxygen ,c 10-day rolling average).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (230
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
140 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (150
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
620 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (390
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
3.0E–02 lb per MMBtu of heat input; or (2.6E–
05 lb per MMBtu of heat input).
560 ppm by volume on a dry basis corrected to
3 percent oxygen.
a. Carbon monoxide (CO) (or
CEMS).
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
10. Stokers/sloped grate/others
designed to burn kiln-dried
biomass fuel.
a. CO ........................................
b. Filterable PM (or TSM) ........
11. Fluidized bed units designed
to burn biomass/bio-based
solids.
a. HCl .......................................
3.0E–02 lb per MMBtu of heat input; or (4.0E–
03 lb per MMBtu of heat input).
230 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (310
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
9.8E–03 lb per MMBtu of heat input; or (8.3E–
05 a lb per MMBtu of heat input).
2,400 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or
(2,000 ppm by volume on a dry basis corrected to 3 percent oxygen c 10-day rolling
average).
3.0E–02 lb per MMBtu of heat input; or (6.5E–
03 lb per MMBtu of heat input).
1,010 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or (520
ppm by volume on a dry basis corrected to 3
percent oxygen c 10-day rolling average).
8.0E–03 lb per MMBtu of heat input; or (3.9E–
05 lb per MMBtu of heat input).
910 ppm by volume on a dry basis corrected to
3 percent oxygen.
2.0E–02 lb per MMBtu of heat input; or (2.9E–
05 lb per MMBtu of heat input).
1,100 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or (900
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
2.6E–02 lb per MMBtu of heat input; or (4.4E–
04 lb per MMBtu of heat input).
4.4E–04 lb per MMBtu of heat input .................
b. Mercury. ...............................
4.8E–07 a lb per MMBtu of heat input ...............
a. CO ........................................
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
12. Suspension burners designed to burn biomass/biobased solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
13. Dutch Ovens/Pile burners
designed to burn biomass/biobased solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
14. Fuel cell units designed to
a. CO ........................................
burn biomass/bio-based solids.
b. Filterable PM (or TSM) ........
15. Hybrid suspension grate
boiler designed to burn biomass/bio-based solids.
a. CO (or CEMS) .....................
lotter on DSK11XQN23PROD with RULES2
b. Filterable PM (or TSM) ........
16. Units designed to burn liquid
fuel.
17. Units designed to burn
heavy liquid fuel.
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1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run
For M26A: Collect a minimum of 2 dscm per
run; for M26, collect a minimum of 240 liters
per run
For M29, collect a minimum of 4 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
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60857
TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued
If your boiler or process heater
is in this subcategory . . .
18. Units designed to burn light
liquid fuel.
For the following
pollutants . . .
The emissions must not exceed the following
emission limits, except during periods of
startup and shutdown . . .
Using this specified sampling volume or test
run duration . . .
b. Filterable PM (or TSM) ........
Collect a minimum of 3 dscm per run.
b. HCl .......................................
1.3E–02 lb per MMBtu of heat input; or (7.5E–
05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen.
2.0E–03 a lb per MMBtu of heat input; or
(2.9E–05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average based on
stack test.
2.3E–02 lb per MMBtu of heat input; or (8.6E–
04 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen.
1.7E–03 lb per MMBtu of heat input .................
c. Mercury ................................
7.9E–06 lb per MMBtu of heat input .................
d. Filterable PM (or TSM) ........
6.7E–03 lb per MMBtu of heat input; or (2.1E–
04 lb per MMBtu of heat input).
a. CO ........................................
b. Filterable PM (or TSM) ........
19. Units designed to burn liquid
fuel that are non-continental
units.
a. CO ........................................
b. Filterable PM (or TSM) ........
20. Units designed to burn gas
2 (other) gases.
a. CO ........................................
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run
1 hr minimum sampling time.
Collect a minimum of 4 dscm per run
1 hr minimum sampling time.
For M26A, Collect a minimum of 2 dscm per
run; for M26, collect a minimum of 240 liters
per run.
For M29, collect a minimum of 3 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
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 § 63.7515 if all of the other provision of § 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 § 63.14.
c An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide as a diluent correction in place of oxygen as described in § 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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% oxygen correction is to
be done on a dry basis. The methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
■ 24. Table 12 to subpart DDDDD of part
63 is revised to read as follows:
lotter on DSK11XQN23PROD with RULES2
TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011
If your boiler or
process heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not
exceed the following
emission limits, except during periods of startup and shutdown . . .
1. Units in all subcategories designed to burn solid fuel.
a. HCl .......................................
0.022 lb per MMBtu of heat input ......................
b. Mercury ................................
3.5E–06 a lb per MMBtu of heat input ...............
2. Units design to burn coal/
solid fossil fuel.
3. Pulverized coal boilers designed to burn coal/solid fossil
fuel.
a. Filterable PM (or TSM) ........
4. Stokers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS) .....................
5. Fluidized bed units designed
to burn coal/solid fossil fuel.
a. CO (or CEMS) .....................
6. Fluidized bed units with an integrated heat exchanger designed to burn coal/solid fossil
fuel.
7. Stokers/sloped grate/others
designed to burn wet biomass
fuel.
a. CO (or CEMS) .....................
1.1E–03 lb per MMBtu of heat input; or (2.3E–
05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (320
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (340
ppm by volume on a dry basis corrected to 3
percent oxygen,c 10-day rolling average).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (230
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
140 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (150
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
620 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (390
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
VerDate Sep<11>2014
a. Carbon monoxide (CO) (or
CEMS).
a. CO (or CEMS) .....................
19:06 Oct 05, 2022
Jkt 259001
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Frm 00043
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Sfmt 4700
Using this specified sampling volume or test
run duration . . .
For M26A, collect a minimum of 1 dscm per
run; for M26 collect a minimum of 120 liters
per run.
For M29, collect a minimum of 3 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
E:\FR\FM\06OCR2.SGM
06OCR2
60858
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued
If your boiler or
process heater is in this
subcategory . . .
The emissions must not
exceed the following
emission limits, except during periods of startup and shutdown . . .
For the following
pollutants . . .
b. Filterable PM (or TSM) ........
8. Stokers/sloped grate/others
designed to burn kiln-dried
biomass fuel.
a. CO ........................................
b. Filterable PM (or TSM) ........
9. Fluidized bed units designed
to burn biomass/bio-based
solids.
a. HCl .......................................
3.0E–02 lb per MMBtu of heat input; or (4.0E–
03 lb per MMBtu of heat input).
260 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (310
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
9.8E–03 lb per MMBtu of heat input; or (8.3E–
05 a lb per MMBtu of heat input).
2,400 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or
(2,000 ppm by volume on a dry basis corrected to 3 percent oxygen,c 10-day rolling
average).
3.0E–02 lb per MMBtu of heat input; or (6.5E–
03 lb per MMBtu of heat input).
470 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (520
ppm by volume on a dry basis corrected to 3
percent oxygen,c 10-day rolling average).
3.2E–03 lb per MMBtu of heat input; or (3.9E–
05 lb per MMBtu of heat input).
910 ppm by volume on a dry basis corrected to
3 percent oxygen.
2.0E–02 lb per MMBtu of heat input; or (2.9E–
05 lb per MMBtu of heat input).
1,500 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or (900
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
2.6E–02 lb per MMBtu of heat input; or (4.4E–
04 lb per MMBtu of heat input).
4.4E–04 lb per MMBtu of heat input .................
b. Mercury ................................
4.8E–07 a lb per MMBtu of heat input ...............
a. CO ........................................
b. HCl .......................................
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average.
1.3E–02 lb per MMBtu of heat input; or (7.5E–
05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen.
1.3E–03 a lb per MMBtu of heat input; or
(2.9E–05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average based on
stack test.
2.3E–02 lb per MMBtu of heat input; or (8.6E–
04 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen.
1.7E–03 lb per MMBtu of heat input .................
c. Mercury ................................
7.9E–06 lb per MMBtu of heat input .................
d. Filterable PM (or TSM) ........
6.7E–03 lb per MMBtu of heat input; or (2.1E–
04 lb per MMBtu of heat input).
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
10. Suspension burners designed to burn biomass/biobased solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
11. Dutch Ovens/Pile burners
designed to burn biomass/biobased solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
12. Fuel cell units designed to
a. CO ........................................
burn biomass/bio-based solids.
b. Filterable PM (or TSM) ........
13. Hybrid suspension grate
boiler designed to burn biomass/bio-based solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
14. Units designed to burn liquid
fuel.
15. Units designed to burn
heavy liquid fuel.
b. Filterable PM (or TSM) ........
16. Units designed to burn light
liquid fuel.
a. CO ........................................
b. Filterable PM (or TSM) ........
17. Units designed to burn liquid
fuel that are non-continental
units.
a. CO ........................................
b. Filterable PM (or TSM) ........
lotter on DSK11XQN23PROD with RULES2
18. Units designed to burn gas
2 (other) gases.
3.0E–02 lb per MMBtu of heat input; or (2.6E–
05 lb per MMBtu of heat input).
460 ppm by volume on a dry basis corrected to
3 percent oxygen.
a. CO ........................................
Using this specified sampling volume or test
run duration . . .
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
For M26A: Collect a minimum of 2 dscm per
run; for M26, collect a minimum of 240 liters
per run.
For M29, collect a minimum of 4 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 4 dscm per run.
1 hr minimum sampling time.
For M26A, Collect a minimum of 2 dscm per
run; for M26, collect a minimum of 240 liters
per run.
For M29, collect a minimum of 3 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
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 § 63.7515 if all of the other provision of § 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 § 63.14.
VerDate Sep<11>2014
19:06 Oct 05, 2022
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E:\FR\FM\06OCR2.SGM
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Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60859
c An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide as a diluent correction in place of oxygen as described in § 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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% oxygen correction is to
be done on a dry basis. The methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
25. Table 13 to subpart DDDDD is of
part 63 is revised to read as follows:
■
TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND
BEFORE APRIL 1, 2013
If your boiler or process heater
is in this subcategory . . .
For the following pollutants
. . .
The emissions must not exceed the following
emission limits, except during periods of startup and shutdown . . .
Using this specified sampling volume or test
run duration . . .
1. Units in all subcategories designed to burn solid fuel.
a. HCl .......................................
0.022 lb per MMBtu of heat input ......................
b. Mercury ................................
8.6E–07 a lb per MMBtu of heat input ...............
a. Carbon monoxide (CO) (or
CEMS).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (320
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
1.1E–03 lb per MMBtu of heat input; or (2.8E–
05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (340
ppm by volume on a dry basis corrected to 3
percent oxygen,c 10-day rolling average).
2.8E–02 lb per MMBtu of heat input; or (2.3E–
05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (230
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
1.1E–03 lb per MMBtu of heat input; or (2.3E–
05 lb per MMBtu of heat input).
140 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (150
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
1.1E–03 lb per MMBtu of heat input; or (2.3E–
05 lb per MMBtu of heat input).
620 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (410
ppm by volume on a dry basis corrected to 3
percent oxygen,c 10-day rolling average).
3.0E–02 lb per MMBtu of heat input; or (2.6E–
05 lb per MMBtu of heat input).
460 ppm by volume on a dry basis corrected to
3 percent oxygen.
For M26A, collect a minimum of 1 dscm per
run; for M26 collect a minimum of 120 liters
per run.
For M29, collect a minimum of 4 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
2. Pulverized coal boilers designed to burn coal/solid fossil
fuel.
b. Filterable PM (or TSM) ........
3. Stokers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
4. Fluidized bed units designed
to burn coal/solid fossil fuel.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
5. Fluidized bed units with an integrated heat exchanger designed to burn coal/solid fossil
fuel.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
6. Stokers/sloped grate/others
designed to burn wet biomass
fuel.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
7. Stokers/sloped grate/others
designed to burn kiln-dried
biomass fuel.
a. CO ........................................
b. Filterable PM (or TSM) ........
8. Fluidized bed units designed
to burn biomass/bio-based
solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
9. Suspension burners designed
to burn biomass/bio-based
solids.
a. CO (or CEMS) .....................
lotter on DSK11XQN23PROD with RULES2
b. Filterable PM (or TSM) ........
10. Dutch Ovens/Pile burners
designed to burn biomass/biobased solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
11. Fuel cell units designed to
a. CO ........................................
burn biomass/bio-based solids.
b. Filterable PM (or TSM) ........
VerDate Sep<11>2014
18:23 Oct 05, 2022
Jkt 259001
PO 00000
3.2E–01 lb per MMBtu of heat input; or (4.0E–
03 lb per MMBtu of heat input).
230 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (310
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
9.8E–03 lb per MMBtu of heat input; or (8.3E–
05 a lb per MMBtu of heat input).
2,400 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or
(2,000 ppm by volume on a dry basis corrected to 3 percent oxygen,c 10-day rolling
average).
5.1E–02 lb per MMBtu of heat input; or (6.5E–
03 lb per MMBtu of heat input).
810 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (520
ppm by volume on a dry basis corrected to 3
percent oxygen,c 10-day rolling average).
3.6E–02 lb per MMBtu of heat input; or (3.9E–
05 lb per MMBtu of heat input).
910 ppm by volume on a dry basis corrected to
3 percent oxygen.
2.0E–02 lb per MMBtu of heat input; or (2.9E–
05 lb per MMBtu of heat input).
Frm 00045
Fmt 4701
Sfmt 4700
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
E:\FR\FM\06OCR2.SGM
06OCR2
60860
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND
BEFORE APRIL 1, 2013—Continued
If your boiler or process heater
is in this subcategory . . .
For the following pollutants
. . .
The emissions must not exceed the following
emission limits, except during periods of startup and shutdown . . .
Using this specified sampling volume or test
run duration . . .
12. Hybrid suspension grate
boiler designed to burn biomass/bio-based solids.
a. CO (or CEMS) .....................
1 hr minimum sampling time.
a. HCl .......................................
1,500 ppm by volume on a dry basis corrected
to 3 percent oxygen, 3-run average; or (900
ppm by volume on a dry basis corrected to 3
percent oxygen,c 30-day rolling average).
2.6E–02 lb per MMBtu of heat input; or (4.4E–
04 lb per MMBtu of heat input).
1.2E–03 lb per MMBtu of heat input .................
b. Mercury ................................
4.9E–07 a lb per MMBtu of heat input ...............
a. CO (or CEMS) .....................
b. HCl .......................................
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average; or (18 ppm
by volume on a dry basis corrected to 3 percent oxygen,c 10-day rolling average).
1.3E–03 lb per MMBtu of heat input; or (7.5E–
05 lb per MMBtu of heat input).
130 a ppm by volume on a dry basis corrected
to 3 percent oxygen; or (60 ppm by volume
on a dry basis corrected to 3 percent oxygen,c 1-day block average)..
1.1E–03 a lb per MMBtu of heat input; or
(2.9E–05 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen, 3-run average based on
stack test; or (91 ppm by volume on a dry
basis corrected to 3 percent oxygen,c 3-hour
rolling average).
2.3E–02 lb per MMBtu of heat input; or (8.6E–
04 lb per MMBtu of heat input).
130 ppm by volume on a dry basis corrected to
3 percent oxygen.
1.7E–03 lb per MMBtu of heat input .................
c. Mercury ................................
7.9E–06 lb per MMBtu of heat input .................
d. Filterable PM (or TSM) ........
6.7E–03 lb per MMBtu of heat input; or (2.1E–
04 lb per MMBtu of heat input).
b. Filterable PM (or TSM) ........
13. Units designed to burn liquid
fuel.
14. Units designed to burn
heavy liquid fuel.
b. Filterable PM (or TSM) ........
15. Units designed to burn light
liquid fuel.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
16. Units designed to burn liquid
fuel that are non-continental
units.
a. CO ........................................
b. Filterable PM (or TSM) ........
17. Units designed to burn gas
2 (other) gases.
a. CO ........................................
Collect a minimum of 3 dscm per run.
For M26A: Collect a minimum of 2 dscm per
run; for M26, collect a minimum of 240 liters
per run.
For M29, collect a minimum of 4 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 bcollect a minimum of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
For M26A, Collect a minimum of 2 dscm per
run; for M26, collect a minimum of 240 liters
per run.
For M29, collect a minimum of 3 dscm per run;
for M30A or M30B, collect a minimum sample as specified in the method; for ASTM
D6784 bcollect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
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 and you are not required to conduct testing for CEMS or CPMS monitor certification, you can skip testing according to § 63.7515 if all
of the other provision of § 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 § 63.14.
c An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide as a diluent correction in place of oxygen as described in § 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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% oxygen correction is to
be done on a dry basis. The methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
26. 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 c
lotter on DSK11XQN23PROD with RULES2
[As stated in § 63.7500, you may continue to comply with the following applicable emission limits until October 6, 2025: [Units with heat input
capacity of 10 million Btu per hour or greater]]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
1. Units in all subcategories designed to
burn solid fuel..
a. HCl ...........................
2.2E–02 lb per MMBtu of heat input
2.5E–02 lb per MMBtu of steam
output or 0.28 lb per MWh.
VerDate Sep<11>2014
19:06 Oct 05, 2022
Jkt 259001
PO 00000
Frm 00046
Fmt 4701
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
Using this specified sampling
volume or test run duration . . .
For M26A, collect a minimum of 1
dscm per run; for M26 collect a
minimum of 120 liters per run.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60861
TABLE 14 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS c—Continued
[As stated in § 63.7500, you may continue to comply with the following applicable emission limits until October 6, 2025: [Units with heat input
capacity of 10 million Btu per hour or greater]]
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
b. Mercury ....................
8.0E–07 a lb per MMBtu of heat
input.
8.7E–07 a lb per MMBtu of steam
output or 1.1E–05 a lb per MWh.
2. Units designed to
burn coal/solid fossil
fuel.
a. Filterable PM (or
TSM).
1.1E–03 lb per MMBtu of heat
input; or (2.3E–05 lb per MMBtu
of heat input).
3. Pulverized coal boilers designed to burn
coal/solid fossil fuel.
a. Carbon monoxide
(CO) (or CEMS).
4. Stokers/others designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
5. Fluidized bed units
designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
6. Fluidized bed units
with an integrated
heat exchanger designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
7. Stokers/sloped grate/
others designed to
burn wet biomass fuel.
a. CO (or CEMS) .........
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
140 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to
3- percent oxygen,d 30-day rolling average).
620 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (390 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
3.0E–02 lb per MMBtu of heat
input; or (2.6E–05 lb per MMBtu
of heat input).
1.1E–03 lb per MMBtu of steam
output or 1.4E–02 lb per MWh; or
(2.7E–05 lb per MMBtu of steam
output or 2.9E–04 lb per MWh).
0.11 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
If your boiler or process
heater is in this
subcategory . . .
b. Filterable PM (or
TSM).
8. Stokers/sloped grate/
others designed to
burn kiln-dried biomass fuel.
a. CO ...........................
460 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. Filterable PM (or
TSM).
3.0E–02 lb per MMBtu of heat
input; or (4.0E–03 lb per MMBtu
of heat input).
9. Fluidized bed units
a. CO (or CEMS) .........
designed to burn biomass/bio-based solids.
lotter on DSK11XQN23PROD with RULES2
b. Filterable PM (or
TSM).
10. Suspension burners
a. CO (or CEMS) .........
designed to burn biomass/bio-based solids.
b. Filterable PM (or
TSM).
VerDate Sep<11>2014
19:06 Oct 05, 2022
Jkt 259001
230 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to
3-percent oxygen,d 30-day rolling
average).
9.8E–03 lb per MMBtu of heat
input; or (8.3E–05 a lb per MMBtu
of heat input).
2,400 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (2,000
ppm by volume on a dry basis
corrected to 3-percent oxygen,d
10-day rolling average).
3.0E–02 lb per MMBtu of heat
input; or (6.5E–03 lb per MMBtu
of heat input).
PO 00000
Frm 00047
Fmt 4701
Using this specified sampling
volume or test run duration . . .
For M29, collect a minimum of 4
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 4 dscm.
Collect a minimum of 3 dscm per
run.
0.12 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
0.11 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
1.2E–01 lb per MMBtu of steam
output or 1.5 lb per MWh; 3-run
average.
1 hr minimum sampling time.
5.8E–01 lb per MMBtu of steam
output or 6.8 lb per MWh; 3-run
average.
1 hr minimum sampling time.
3.5E–02 lb per MMBtu of steam
output or 4.2E–01 lb per MWh; or
(2.7E–05 lb per MMBtu of steam
output or 3.7E–04 lb per MWh).
4.2E–01 lb per MMBtu of steam
output or 5.1 lb per MWh.
Collect a minimum of 2 dscm per
run.
3.5E–02 lb per MMBtu of steam
output or 4.2E–01 lb per MWh; or
(4.2E–03 lb per MMBtu of steam
output or 5.6E–02 lb per MWh).
2.2E–01 lb per MMBtu of steam
output or 2.6 lb per MWh; 3-run
average.
Collect a minimum of 2 dscm per
run.
1 hr minimum sampling time.
1 hr minimum sampling time.
1.2E–02 lb per MMBtu of steam
output or 0.14 lb per MWh; or
(1.1E–04 a lb per MMBtu of
steam output or 1.2E–03 a lb per
MWh).
1.9 lb per MMBtu of steam output
or 27 lb per MWh; 3-run average.
Collect a minimum of 3 dscm per
run.
3.1E–02 lb per MMBtu of steam
output or 4.2E–01 lb per MWh; or
(6.6E–03 lb per MMBtu of steam
output or 9.1E–02 lb per MWh).
Collect a minimum of 2 dscm per
run.
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
1 hr minimum sampling time.
60862
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 14 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS c—Continued
[As stated in § 63.7500, you may continue to comply with the following applicable emission limits until October 6, 2025: [Units with heat input
capacity of 10 million Btu per hour or greater]]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
11. Dutch Ovens/Pile
burners designed to
burn biomass/biobased solids.
a. CO (or CEMS) .........
330 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to
3-percent oxygen,d 10-day rolling
average).
3.2E–03 lb per MMBtu of heat
input; or (3.9E–05 lb per MMBtu
of heat input).
3.5E–01 lb per MMBtu of steam
output or 3.6 lb per MWh; 3-run
average.
1 hr minimum sampling time.
4.3E–03 lb per MMBtu of steam
output or 4.5E–02 lb per MWh; or
(5.2E–05 lb per MMBtu of steam
output or 5.5E–04 lb per MWh).
1.1 lb per MMBtu of steam output
or 1.0E+01 lb per MWh.
Collect a minimum of 3 dscm per
run.
3.0E–02 lb per MMBtu of steam
output or 2.8E–01 lb per MWh; or
(5.1E–05 lb per MMBtu of steam
output or 4.1E–04 lb per MWh).
1.4 lb per MMBtu of steam output
or 12 lb per MWh; 3-run average.
Collect a minimum of 2 dscm per
run.
b. Filterable PM (or
TSM).
12. Fuel cell units dea. CO ...........................
signed to burn biomass/bio-based solids.
b. Filterable PM (or
TSM).
910 ppm by volume on a dry basis
corrected to 3-percent oxygen.
13. Hybrid suspension
grate boiler designed
to burn biomass/biobased solids.
1,100 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (900 ppm
by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average).
2.6E–02 lb per MMBtu of heat
input; or (4.4E–04 lb per MMBtu
of heat input).
a. CO (or CEMS) .........
b. Filterable PM (or
TSM).
14. Units designed to
burn liquid fuel.
15. Units designed to
burn heavy liquid fuel.
4.4E–04 lb per MMBtu of heat input
b. Mercury ....................
4.8E–07
input.
lb per MMBtu of heat
5.3E–07 a lb per MMBtu of steam
output or 6.7E–06 a lb per MWh.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average.
1.3E–02 lb per MMBtu of heat
input; or (7.5E–05 a lb per MMBtu
of heat input).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
a. CO ...........................
b. Filterable PM (or
TSM).
17. Units designed to
burn liquid fuel that
are non-continental
units.
lotter on DSK11XQN23PROD with RULES2
18. Units designed to
burn gas 2 (other)
gases.
VerDate Sep<11>2014
3.3E–02 lb per MMBtu of steam
output or 3.7E–01 lb per MWh; or
(5.5E–04 lb per MMBtu of steam
output or 6.2E–03 lb per MWh).
4.8E–04 lb per MMBtu of steam
output or 6.1E–03 lb per MWh.
a. HCl ...........................
b. Filterable PM (or
TSM).
16. Units designed to
burn light liquid fuel.
2.0E–02 lb per MMBtu of heat
input; or (2.9E–05 lb per MMBtu
of heat input).
a
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
1.1E–03 a lb per MMBtu of heat
input; or (2.9E–05 lb per MMBtu
of heat input).
For M26A, Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 3 dscm.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. HCl ...........................
1.7E–03 lb per MMBtu of heat input
2.9E–03 lb per MMBtu of steam
output or 1.8E–02 lb per MWh.
c. Mercury ....................
7.9E–06 lb per MMBtu of heat input
1.4E–05 lb per MMBtu of steam
output or 8.3E–05 lb per MWh.
Fmt 4701
For M26A: Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 4
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 4 dscm per
run.
2.3E–02 lb per MMBtu of heat
input; or (8.6E–04 lb per MMBtu
of heat input).
Frm 00048
Collect a minimum of 3 dscm per
run.
2.5E–02 lb per MMBtu of steam
output or 3.2E–01 lb per MWh; or
(9.4E–04 lb per MMBtu of steam
output or 1.2E–02 lb per MWh).
0.16 lb per MMBtu of steam output
or 1.0 lb per MWh.
b. Filterable PM (or
TSM).
PO 00000
1 hr minimum sampling time.
Collect a minimum of 3 dscm per
run.
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average based on stack test.
Jkt 259001
1 hr minimum sampling time.
1.5E–02 lb per MMBtu of steam
output or 1.8E–01 lb per MWh; or
(8.2E–05 a lb per MMBtu of
steam output or 1.1E–03 a lb per
MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh.
1.2E–03 a lb per MMBtu of steam
output or 1.6E–02 a lb per MWh;
or (3.2E–05 lb per MMBtu of
steam output or 4.0E–04 lb per
MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
a. CO ...........................
19:06 Oct 05, 2022
Using this specified sampling
volume or test run duration . . .
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
1 hr minimum sampling time.
Collect a minimum of 3 dscm per
run.
1 hr minimum sampling time.
1 hr minimum sampling time.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60863
TABLE 14 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS c—Continued
[As stated in § 63.7500, you may continue to comply with the following applicable emission limits until October 6, 2025: [Units with heat input
capacity of 10 million Btu per hour or greater]]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and shutdown . . .
Or the emissions must not
exceed the following alternative
output-based limits, except during
startup and shutdown . . .
d. Filterable PM (or
TSM).
6.7E–03 lb per MMBtu of heat
input; or (2.1E–04 lb per MMBtu
of heat input).
1.2E–02 lb per MMBtu of steam
output or 7.0E–02 lb per MWh; or
(3.5E–04 lb per MMBtu of steam
output or 2.2E–03 lb per MWh).
Using this specified sampling
volume or test run duration . . .
Collect a minimum of 3 dscm per
run.
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 § 63.7515 if all of the other provisions of § 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 § 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 Table 11, 12, or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before October 6, 2025 you may
comply with the emission limits in this Table 14. On and after October 6, 2025, you must comply with the emission limits in Table 1 to this subpart.
d An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide as a diluent correction in place of oxygen as described in § 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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% oxygen correction is to
be done on a dry basis. The methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
27. 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 D
lotter on DSK11XQN23PROD with RULES2
[As stated in § 63.7500, you may continue to comply with following emission limits until October 6, 2025: [Units with heat input capacity of 10
million Btu per hour or greater]]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
The emissions must not exceed the
following emission limits, except
during startup and
shutdown . . .
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
1. Units in all subcategories designed to
burn solid fuel.
a. HCl ...........................
2.2E–02 lb per MMBtu of heat input
2.5E–02 lb per MMBtu of steam
output or 0.27 lb per MWh.
b. Mercury ....................
5.7E–06 lb per MMBtu of heat input
6.4E–06 lb per MMBtu of steam
output or 7.3E–05 lb per MWh.
2. Units design to burn
coal/solid fossil fuel.
a. Filterable PM (or
TSM).
4.0E–02 lb per MMBtu of heat
input; or (5.3E–05 lb per MMBtu
of heat input).
3. Pulverized coal boilers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS) .........
4. Stokers/others designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
5. Fluidized bed units
designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
6. Fluidized bed units
with an integrated
heat exchanger designed to burn coal/
solid fossil fuel.
a. CO (or CEMS) .........
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
160 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to
3- percent oxygen,c 30-day rolling average).
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to
3- percent oxygen,c 30-day rolling average).
140 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to
3-percent oxygen,c 30-day rolling
average).
4.2E–02 lb per MMBtu of steam
output or 4.9E–01 lb per MWh; or
(5.6E–05 lb per MMBtu of steam
output or 6.5E–04 lb per MWh).
0.11 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
VerDate Sep<11>2014
19:06 Oct 05, 2022
Jkt 259001
PO 00000
Frm 00049
Fmt 4701
Using this specified sampling
volume or test run duration . . .
For M26A, Collect a minimum of 1
dscm per run; for M26, collect a
minimum of 120 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum
of 3 dscm.
Collect a minimum of 2 dscm per
run.
0.14 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.7 lb per MWh; 3-run average.
0.12 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
1.3E–01 lb per MMBtu of steam
output or 1.5 lb per MWh; 3-run
average.
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
1 hr minimum sampling time.
60864
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
TABLE 15 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS
HEATERS D—Continued
[As stated in § 63.7500, you may continue to comply with following emission limits until October 6, 2025: [Units with heat input capacity of 10
million Btu per hour or greater]]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
7. Stokers/sloped grate/
others designed to
burn wet biomass fuel.
a. CO (or CEMS) .........
b. Filterable PM (or
TSM).
8. Stokers/sloped grate/
others designed to
burn kiln-dried biomass fuel.
9. Fluidized bed units
designed to burn biomass/bio-based solid.
lotter on DSK11XQN23PROD with RULES2
VerDate Sep<11>2014
4.3E–02 lb per MMBtu of steam
output or 5.2E–01 lb per MWh; or
(2.8E–04 lb per MMBtu of steam
output or 3.4E–04 lb per MWh).
4.2E–01 lb per MMBtu of steam
output or 5.1 lb per MWh.
Collect a minimum of 2 dscm per
run.
3.7E–01 lb per MMBtu of steam
output or 4.5 lb per MWh; or
(4.6E–03 lb per MMBtu of steam
output or 5.6E–02 lb per MWh).
4.6E–01 lb per MMBtu of steam
output or 5.2 lb per MWh; 3-run
average.
Collect a minimum of 1 dscm per
run.
a. CO (or CEMS) .........
470 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to
3- percent oxygen,c 30-day rolling average).
1.1E–01 lb per MMBtu of heat
input; or (1.2E–03 lb per MMBtu
of heat input).
a. CO (or CEMS) .........
a. CO (or CEMS) .........
a. CO ...........................
a. CO (or CEMS) .........
b. Filterable PM (or
TSM).
14. Units designed to
burn liquid fuel.
1 hr minimum sampling time.
3.2E–01 lb per MMBtu of heat
input; or (4.0E–03 lb per MMBtu
of heat input).
b. Filterable PM (or
TSM).
13. Hybrid suspension
grate units designed
to burn biomass/biobased solid.
1.4 lb per MMBtu of steam output
or 17 lb per MWh; 3-run average.
b. Filterable PM (or
TSM).
b. Filterable PM (or
TSM).
12. Fuel cell units designed to burn biomass/bio-based solid.
1,500 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (720 ppm
by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average).
3.7E–02 lb per MMBtu of heat
input; or (2.4E–04 lb per MMBtu
of heat input).
460 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. Filterable PM (or
TSM).
11. Dutch Ovens/Pile
burners designed to
burn biomass/biobased solid.
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
a. CO ...........................
b. Filterable PM (or
TSM).
10. Suspension burners
designed to burn biomass/bio-based solid.
The emissions must not exceed the
following emission limits, except
during startup and
shutdown . . .
2,400 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (2,000
ppm by volume on a dry basis
corrected to 3-percent oxygen,c
10-day rolling average).
5.1E–02 lb per MMBtu of heat
input; or (6.5E–03 lb per MMBtu
of heat input).
770 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to
3-percent oxygen,c 10-day rolling
average).
2.8E–01 lb per MMBtu of heat
input; or (2.0E–03 lb per MMBtu
of heat input).
1,100 ppm by volume on a dry
basis corrected to 3-percent oxygen.
2.0E–02 lb per MMBtu of heat
input; or (5.8E–03 lb per MMBtu
of heat input).
3,500 ppm by volume on a dry
basis corrected to 3-percent oxygen, 3-run average; or (900 ppm
by volume on a dry basis corrected to 3- percent oxygen,c 30day rolling average).
4.4E–01 lb per MMBtu of heat
input; or (4.5E–04 lb per MMBtu
of heat input).
a. HCl ...........................
1.1E–03 lb per MMBtu of heat input
b. Mercury ....................
2.0E–06 lb per MMBtu of heat input
18:23 Oct 05, 2022
Jkt 259001
PO 00000
Frm 00050
Fmt 4701
1.4E–01 lb per MMBtu of steam
output or 1.6 lb per MWh; or
(1.5E–03 lb per MMBtu of steam
output or 1.7E–02 lb per MWh).
1.9 lb per MMBtu of steam output
or 27 lb per MWh; 3-run average.
5.2E–02 lb per MMBtu of steam
output or 7.1E–01 lb per MWh; or
(6.6E–03 lb per MMBtu of steam
output or 9.1E–02 lb per MWh).
8.4E–01 lb per MMBtu of steam
output or 8.4 lb per MWh; 3-run
average.
Using this specified sampling
volume or test run duration . . .
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 1 dscm per
run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per
run.
1 hr minimum sampling time.
3.9E–01 lb per MMBtu of steam
output or 3.9 lb per MWh; or
(2.8E–03 lb per MMBtu of steam
output or 2.8E–02 lb per MWh).
2.4 lb per MMBtu of steam output
or 12 lb per MWh.
Collect a minimum of 1 dscm per
run.
5.5E–02 lb per MMBtu of steam
output or 2.8E–01 lb per MWh; or
(1.6E–02 lb per MMBtu of steam
output or 8.1E–02 lb per MWh).
3.5 lb per MMBtu of steam output
or 39 lb per MWh; 3-run average.
Collect a minimum of 2 dscm per
run.
5.5E–01 lb per MMBtu of steam
output or 6.2 lb per MWh; or
(5.7E–04 lb per MMBtu of steam
output or 6.3E–03 lb per MWh).
1.4E–03 lb per MMBtu of steam
output or 1.6E–02 lb per MWh.
2.5E–06 lb per MMBtu of steam
output or 2.8E–05 lb per MWh.
Sfmt 4700
E:\FR\FM\06OCR2.SGM
06OCR2
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 1 dscm per
run.
For M26A, collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B
collect a minimum sample as
specified in the method, for
ASTM D6784 b collect a minimum
of 2 dscm.
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 / Rules and Regulations
60865
TABLE 15 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS
HEATERS D—Continued
[As stated in § 63.7500, you may continue to comply with following emission limits until October 6, 2025: [Units with heat input capacity of 10
million Btu per hour or greater]]
If your boiler or process
heater is in this
subcategory . . .
For the following
pollutants . . .
15. Units designed to
burn heavy liquid fuel.
a. CO ...........................
b. Filterable PM (or
TSM).
16. Units designed to
burn light liquid fuel.
a. CO ...........................
b. Filterable PM (or
TSM).
17. Units designed to
burn liquid fuel that
are non-continental
units.
18. Units designed to
burn gas 2 (other)
gases.
The emissions must not exceed the
following emission limits, except
during startup and
shutdown . . .
The emissions must not exceed the
following alternative output-based
limits, except during startup and
shutdown . . .
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average.
6.2E–02 lb per MMBtu of heat
input; or (2.0E–04 lb per MMBtu
of heat input).
0.13 lb per MMBtu of steam output 1 hr minimum sampling time.
or 1.4 lb per MWh; 3-run average.
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
7.9E–03 lb per MMBtu of heat
input; or (6.2E–05 lb per MMBtu
of heat input).
Using this specified sampling
volume or test run duration . . .
7.5E–02 lb per MMBtu of steam
output or 8.6E–01 lb per MWh; or
(2.5E–04 lb per MMBtu of steam
output or 2.8E–03 lb per MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh.
9.6E–03 lb per MMBtu of steam
output or 1.1E–01 lb per MWh; or
(7.5E–05 lb per MMBtu of steam
output or 8.6E–04 lb per MWh).
0.13 lb per MMBtu of steam output
or 1.4 lb per MWh; 3-run average.
Collect a minimum of 1 dscm per
run.
3.3E–01 lb per MMBtu of steam
output or 3.8 lb per MWh; or
(1.1E–03 lb per MMBtu of steam
output or 1.2E–02 lb per MWh).
0.16 lb per MMBtu of steam output
or 1.0 lb per MWh.
Collect a minimum of 2 dscm per
run.
For M26A, collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3
dscm per run; for M30A or M30B,
collect a minimum sample as
specified in the method; for
ASTM D6784 b collect a minimum of 2 dscm.
Collect a minimum of three dscm
per run.
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen, 3run average based on stack test.
b. Filterable PM (or
TSM).
2.7E–01 lb per MMBtu of heat
input; or (8.6E–04 lb per MMBtu
of heat input).
a. CO ...........................
130 ppm by volume on a dry basis
corrected to 3-percent oxygen.
b. HCl ...........................
1.7E–03 lb per MMBtu of heat input
2.9E–03 lb per MMBtu of steam
output or 1.8E–02 lb per MWh.
c. Mercury ....................
7.9E–06 lb per MMBtu of heat input
1.4E–05 lb per MMBtu of steam
output or 8.3E–05 lb per MWh.
d. Filterable PM (or
TSM).
6.7E–03 lb per MMBtu of heat input
or (2.1E–04 lb per MMBtu of heat
input).
1.2E–02 lb per MMBtu of steam
output or 7.0E–02 lb per MWh; or
(3.5E–04 lb per MMBtu of steam
output or 2.2E–03 lb per MWh).
1 hr minimum sampling time.
Collect a minimum of 3 dscm per
run.
1 hr minimum sampling time.
1 hr minimum sampling time.
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 § 63.7515 if all of the other provisions of § 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 § 63.14.
c An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide as a diluent correction in place of oxygen as described in § 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR part 60, appendix A–7, and EPA Method 19 equations in 40 CFR part 60, appendix A–7, 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% oxygen correction is to
be done on a dry basis. The methodology must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to § 63.7505(d).
d Before October 6, 2025 you may comply with the emission limits in this Table 15. On and after October 6, 2025, you must comply with the emission limits in Table
2 to this subpart.
[FR Doc. 2022–19612 Filed 10–5–22; 8:45 am]
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]]>Agencies
[Federal Register Volume 87, Number 193 (Thursday, October 6, 2022)]
[Rules and Regulations]
[Pages 60816-60865]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-19612]
[[Page 60815]]
Vol. 87
Thursday,
No. 193
October 6, 2022
Part II
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Final Rule
Federal Register / Vol. 87, No. 193 / Thursday, October 6, 2022 /
Rules and Regulations
[[Page 60816]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-6312-02-OAR]
RIN 2060-AU20
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This action finalizes amendments to the national emission
standards for hazardous air pollutants (NESHAP) at major sources from
new and existing industrial, commercial, and institutional (ICI)
boilers and process heaters. Certain aspects of these standards were
challenged and subsequently remanded to the Agency by the United States
Court of Appeals for the District of Columbia Circuit (D.C. Circuit).
This action finalizes amendments to several numeric emission limits for
new and existing boilers and process heaters consistent with the
court's opinion and sets compliance dates for these new emission
limits. This action also provides further explanation of one aspect of
the Agency's use of carbon monoxide (CO) as a surrogate for organic
hazardous air pollutants (HAP) and its use of a CO threshold to
represent the application of the maximum achievable control technology
(MACT) for organic HAP. We are also finalizing several technical
clarifications and corrections.
DATES: This final rule is effective on December 5, 2022. The
incorporation by reference (IBR) of certain material listed in the rule
is approved by the Director of the Federal Register as of October 6,
2022. The incorporation by reference of this material was previously
approved by the Director of the Federal Register as of May 20, 2011.
FOR FURTHER INFORMATION CONTACT: For questions about this final action,
contact Lisa Thompson, 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) 541-9775; and email address:
[email protected] or Nick Hutson, 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) 541-2968; and email address:
[email protected].
SUPPLEMENTARY INFORMATION:
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 on the https://www.regulations.gov/ website. Although listed,
some information is not publicly available, e.g., Confidential Business
Information or other information whose disclosure is restricted by
statute. Certain other material, such as copyrighted material, is not
placed on the internet and will be publicly available only in hard copy
form. Publicly available docket materials are available electronically
through https://www.regulations.gov/. Out of an abundance of caution
for members of the public and our staff, the EPA Docket Center and
Reading Room are closed to the public, with limited exceptions, to
reduce the risk of transmitting COVID-19. Our Docket Center staff will
continue to provide remote customer service via email, phone, and
webform.
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?
D. Judicial Review and Administrative Reconsideration
II. Background
III. Summary of Final Action and Significant Changes Since Proposal
A. Revisions to MACT Floor Emission Limits
B. Beyond-the-Floor Emission Limits
C. Revisions to Output-Based Emission Limits
D. CO as a Surrogate for Organic HAP
E. CO 130 PPM Threshold Emission Limits
F. New Source Definition
G. Approval for CO2 in Lieu of O2
Monitoring for CO CEMS Compliance Calculations
IV. Results and Final Decisions
A. What are the resulting changes to emission limits?
B. What compliance dates are we finalizing?
C. What other actions are we finalizing?
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?
G. What analysis of environmental justice did we conduct?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
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
(ICI) and Process Heaters was promulgated on March 21, 2011 and amended
on January 31, 2013 and again on November 20, 2015. Environmental
groups and industry submitted petitions seeking judicial review of the
2013 NESHAP. On July 29, 2016, the D.C. Circuit remanded for further
explanation the use of CO as a surrogate for organic HAP due to the
EPA's failure to address a public comment received and vacated certain
emission standards where it held that the EPA had improperly excluded
certain units in establishing the emission standards. U.S. Sugar Corp.
v. EPA, 830 F.3d 579, 631. On December 23, 2016, the D.C. Circuit
amended its July 29, 2016 decision to remand those emission standards
instead of vacating them. 844 F.3d 268. In March 2018, the court, in a
separate challenge to the 2015 amended NESHAP, remanded for further
explanation the EPA's decision to set a limit of 130 parts per million
(ppm) CO as a minimum standard for certain subcategories of boilers and
process heaters. Sierra Club v. EPA, 884 F.3d 1185.
In response to these remands, the EPA is finalizing revisions to
several emission standards consistent with the court's opinion and
providing further explanation of the two issues remanded for that
purpose.
[[Page 60817]]
b. Legal Authority
The statutory authority for this final action is section 112 of the
Clean Air Act (CAA). 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\
---------------------------------------------------------------------------
\1\ See 75 FR 32016 and Sec. 63.7575 ``What definitions apply
to this subpart'' of 40 CFR part 63, subpart DDDDD, for definitions
of ICI boilers and process heaters.
---------------------------------------------------------------------------
2. Summary of the Major Provisions of the Regulatory Action in Question
The EPA is finalizing revisions to 34 different emission limits
which it had previously promulgated in 2011 and amended in 2013. Of
these 34 emission limits, 28 of the limits are more stringent and six
of the limits are less stringent than the previously promulgated
emission limits. The EPA is also finalizing a deadline of 3 years after
the effective date of the final rule for sources to demonstrate
compliance with these revised emission limits. A list of each
combination of subcategory and pollutant with revised limits is shown
in Table 1.
Table 1--Summary of Subcategories With Revised Emission Limits
------------------------------------------------------------------------
Subcategory Pollutant
------------------------------------------------------------------------
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 Fuel Cell.................... PM.
New-Wet Biomass Stoker................... 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.*
------------------------------------------------------------------------
* Indicates a less stringent limit compared to the previously
promulgated emission limits.
3. Costs and Benefits
We have estimated certain costs and benefits of the final rule, and
these are found in Table 2. All of these estimates are in 2016 dollars
(2016$). The monetized benefits estimate reflects an annual average of
446 tons of fine particulate matter (PM2.5) emission
reductions per year and 1,141 tons of sulfur dioxide (SO2)
emission reductions per year, both pollutants not directly regulated by
this final rule. The unmonetized benefits include reduced exposure to
directly regulated HAP, including mercury (Hg), hydrochloric acid
(HCl), non-Hg metals (e.g., antimony, cadmium), formaldehyde, benzene,
and polycyclic organic matter; reduced climate effects due to reduced
black carbon emissions; reduced ecosystem effects; and reduced
visibility impairments. These estimates also include climate
disbenefits resulting from an increase in carbon dioxide
(CO2) emissions, a secondary impact from electricity use by
additional control devices in response to the final amendments.
Table 2 presents estimates of the present values (PV) and
equivalent annualized values (EAV), calculated using discount rates of
3 and 7 percent as directed by OMB's Circular A-4, of the health
benefits, climate disbenefits, compliance costs, and net benefits of
the final rule, in 2016 dollars, discounted to 2020. The estimated net
benefits are the estimated benefits minus the estimated disbenefits and
the estimated costs of the final rule.
Table 2--Estimated Health Benefits, Climate Disbenefits, Compliance Costs, and Net Benefits of the Final Rule,
2022 Through 2029
[Millions 2016$, discounted to 2020] \a\
----------------------------------------------------------------------------------------------------------------
3% Discount rate 7% Discount rate
----------------------------------------------------------------------------------------------------------------
Present Value:
Health Benefits \b\............... $500 and $505...................... $350 and $353.
Climate Disbenefits \b\........... $7................................. $7.
Compliance Costs \c\.............. $315............................... $265.
Net Benefits \d\.................. $178 and $182 + B.................. $80 and $83 + B.
----------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value:
Health Benefits................... $71 and $72........................ $58 and $59.
Climate Disbenefits............... $1................................. $1.
Compliance Costs.................. $45................................ $44.
Net Benefits...................... $25 and $26 + C.................... $13 and $14 + C.
----------------------------------------------------------------------------------------------------------------
\a\ Numbers may not sum due to independent rounding.
\b\ The health benefits are associated with several point estimates and are presented at real discount rates of
3 and 7 percent. The health benefits are a result of the PM2.5 and SO2 emission reductions estimated for this
final rule, and are associated with several point estimates and are presented at real discount rates of 3 and
7 percent. The two benefits estimates are separated by the word ``and'' to signify that they are two separate
estimates. The estimates do not represent lower- and upper-bound estimates and should not be summed. Data,
resource, and methodological limitations prevented the EPA from monetizing the human health benefits from
reduced exposure to mercury, HCl, and other HAP whose emissions are directly regulated by this final rule. The
EPA provides a qualitative discussion of mercury, HCl, and other HAP benefits in the RIA. In addition, the
potential benefits from reduced ecosystem effects and reduced visibility impairment from the reduction in
emissions of non-HAP pollutants such as PM2.5 and SO2 are also not monetized here. Climate disbenefits are
based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social
cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th
percentile at 3 percent discount rate). For the presentational purposes of this table, we show the climate
disbenefits associated with the average SC-CO2 at a 3 percent discount rate, but the Agency does not have a
single central SC-CO2 point estimate. We emphasize the importance and value of considering the disbenefits
calculated using all four SC-CO2 estimates; the additional disbenefit estimates are presented in section V of
this preamble. As discussed in Chapter 4 of the Regulatory Impact Analysis (RIA) for this final rule, a
consideration of climate disbenefits calculated using discount rates below 3 percent, including 2 percent and
lower, are also warranted when discounting intergenerational impacts.
[[Page 60818]]
\c\ To estimate these annualized costs, the EPA uses a conventional and widely accepted approach, the equivalent
uniform annual cost (EUAC) approach, that applies a capital recovery factor (CRF) multiplier to capital
investments and adds that to the annual incremental operating expenses. Annual costs were calculated using a
5.5% nominal interest rate consistent with the rate used for the cost analysis done for the proposed rule.
\d\ The letter ``B'' captures the portion of the present value of net benefits due to the unmonetized benefits
from the emission reductions of directly regulated HAP and all other emission changes resulting from this
final rule. The letter ``C'' captures the portion of the equivalent annualized value of net benefits due to
the unmonetized benefits from the emission reductions of directly regulated HAP and all other emission changes
resulting from this final rule. The benefits from emission reductions of directly regulated HAP under this
final rule are not monetized due to lack of appropriate valuation estimates. More information on the
unmonetized benefits from HAP and non-HAP emission reductions can be found in Chapter 4 of the RIA.
As shown in Table 2, the PV of the health benefits of this final
rule, discounted at a 3-percent discount rate, is estimated to be about
$500 million and $505 million, with an EAV of about $71 million and $72
million. At a 7-percent discount rate, the PV of the health benefits is
estimated to be $350 million and $353 million, with an EAV of about $58
million and $59 million. The two health benefits estimates for each
discount rate reflect alternative PM2.5 mortality risk
estimates. The PV of the climate disbenefits of this final rule,
discounted at a 3-percent rate, is estimated to be about $7 million,
with an EAV of about $1 million. The PV of the compliance costs,
discounted at a 3-percent rate, is estimated to be about $315 million,
with an EAV of about $45 million. At a 7-percent discount rate, the PV
of the compliance costs is estimated to be about $265 million, with an
EAV of about $44 million.
More information on these impacts can be found in section V of this
preamble and in the Regulatory Impact Analysis (RIA) for this final
rule.
B. Does this action apply to me?
Table 3 lists the NESHAP and associated regulated industrial source
categories that are the subject of this action. Table 3 is not intended
to be exhaustive, but rather provides a guide for readers regarding the
entities that this action affects. The final standards 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/Commercial 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, and petroleum and chemical industry
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.
Table 3--Source Categories Affected by This Final Action
----------------------------------------------------------------------------------------------------------------
Examples of regulated
Source category NESHAP NAICS code \1\ entities
----------------------------------------------------------------------------------------------------------------
Any industry using a boiler or process Industrial, Commercial, 211 Extractors of crude petroleum
heater as defined in the final rule. and Institutional 321 and natural gas.
Boilers and Process 322 Manufacturers of lumber and
Heaters. wood products.
Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries, and
manufacturers of coal
products.
316, 326, 339 Manufacturers of rubber and
miscellaneous plastic
products.
331 Steel works, blast furnaces.
332 Electroplating, plating,
polishing, anodizing, and
coloring.
336 Manufacturers of motor
vehicle parts and
accessories.
221 Electric, gas, and sanitary
services.
622 Health services.
611 Educational services.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.
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 final action at
https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters. Following
publication in the Federal Register, the EPA will post the Federal
Register version of the action and key technical documents at this same
website.
A redline version of the regulatory language that incorporates the
finalized changes in this action is available in the docket for this
action (Docket ID No. EPA-HQ-OAR-2002-0058).
D. Judicial Review and Administrative Reconsideration
Under CAA section 307(b)(1), judicial review of this final action
is available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit by December 5,
2022. Under CAA section 307(b)(2), the requirements established by this
final rule may not be challenged separately in any civil or criminal
[[Page 60819]]
proceedings brought by the EPA to enforce the requirements.
Section 307(d)(7)(B) of the CAA further provides that only an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review. This section also
provides a mechanism for the EPA to reconsider the rule if the person
raising an objection can demonstrate to the Administrator that it was
impracticable to raise such objection within the period for public
comment or if the grounds for such objection arose after the period for
public comment (but within the time specified for judicial review) and
if such objection is of central relevance to the outcome of the rule.
Any person seeking to make such a demonstration should submit a
Petition for Reconsideration to the Office of the Administrator, U.S.
EPA, Room 3000, WJC South Building, 1200 Pennsylvania Ave. NW,
Washington, DC 20460, with a copy to both the person(s) listed in the
preceding FOR FURTHER INFORMATION CONTACT section, and the Associate
General Counsel for the Air and Radiation Law Office, Office of General
Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW,
Washington, DC 20460.
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 the maximum achievable control technology (MACT) (76 FR
15608). On January 31, 2013, the EPA promulgated final amendments (78
FR 7138), which were challenged by industry and environmental
petitioners. On November 20, 2015, the EPA promulgated additional
amendments (80 FR 72789) in response to certain reconsideration issues.
On July 29, 2016, the D.C. Circuit issued its decision in U.S.
Sugar Corp v. EPA. In that decision, the court upheld the EPA's 2013
final rule 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. As the court explained, ``[a]lthough the EPA allowed sources that
combust only 10 per cent of a subcategory defining fuel to join that
subcategory, it declined to consider emissions from any source that
burned less than 90 per cent of the subcategory-defining fuel when
determining the average emissions level of the best performing sources
in setting MACT floors for existing sources. And when it set a
subcategory's MACT floors for new sources, the Agency declined to
consider the emissions levels from any source that did not burn 100 per
cent of the fuel.'' Id. Because of this, ``several sources excluded
from the MACT floor determination were among the best performing
sources (or, in some cases, the single best performing source) in that
fuel-based subcategory.'' Id. The court concluded that because the
Clean Air Act requires the EPA to ``set the MACT floor at the level
achieved by the best performing source, or the average of the best
performing sources, in a subcategory,'' when ``the EPA includes a
source in a subcategory, it must take into account that source's
emissions levels in setting the MACT floor,'' no matter what percentage
of subcategory-defining fuel that source burns. The D.C. Circuit
therefore ``vacate[d] the MACT standards for all major boiler
subcategories that would have been affected had the EPA considered all
sources included in the subcategories.'' Id. at 632.
The D.C. Circuit subsequently granted EPA's motion for rehearing on
remedy, withdrew its vacatur, and instead remanded for the EPA ``to
identify those standards for which the MACT floor would have differed
if the EPA had included all best-performing sources in each subcategory
in its MACT-floor analysis'' and to ``revise those standards consistent
with our July 29, 2016 opinion in this case.'' 844 F.3d at 270.
Therefore, these standards have remained in effect since the court's
decision.
The court in U.S. Sugar also remanded the use of CO as a surrogate
for non-dioxin organic HAP to the EPA for the limited purpose of
addressing public comments on the potential availability of post-
combustion control technologies that could control CO. Id. at 628-30.
As the D.C. Circuit explained, ``the EPA used carbon monoxide (CO) as a
surrogate for several non-dioxin/furan organic HAPs when the Agency set
the MACT floors for major boilers. In support of this approach, the EPA
found that both CO and these HAPs were the products of `incomplete
combustion.' The Agency concluded as a result that CO was a reasonable
surrogate because: (1) minimizing CO emissions would minimize these
HAPs; (2) methods used for the control of these HAP emissions would be
the same methods used to control CO emissions (i.e., good combustion or
using an oxidation catalyst); (3) standards limiting CO emissions would
result in decreases in these HAP emissions; and (4) establishing
emission limits for individual organic HAPs would be impractical and
costly.'' Id. at 628 (citing 2010 Proposed Major Boilers Rule, 75 FR
32018). The environmental petitioners argued ``that the EPA has not
adequately explained how setting emission standards for CO will . . .
set emission standards for organic HAPs at the average level achieved
by the best performers with regard to those HAPs.'' Id. The D.C.
Circuit agreed, concluding that ``during notice and comment, the EPA
failed to directly consider and respond to several comments that
introduced evidence suggesting that other control technologies and
methods could be effectively used to reduce HAP emissions without also
impacting CO emissions, or vice versa.'' Id. at 629.
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, asking the Agency
to better explain its analysis supporting its decision. Sierra Club v.
EPA, 884 F.3d 1185. As the D.C. Circuit explained, in promulgating
``regulations that indirectly control a group of organic pollutants by
limiting carbon monoxide emissions as a proxy for the targeted
pollutants,'' and ``[a]fter calculating emissions limits for the
organic pollutants by reference to the amount of carbon monoxide
emitted by the best performing boilers in each subcategory, EPA
concluded that the lowest of the carbon monoxide limits were too low,
so it substituted a single, higher limit that it deemed sufficient to
control the pollutants.'' Id. at 1189. The D.C. Circuit concluded that
the ``EPA did not adequately justify its change of direction on the
carbon monoxide limits because it failed to explain how the revised
limits would minimize the targeted pollutants to the extent the Clean
Air Act requires.'' Id. On August 24, 2020, the EPA published a notice
of proposed rulemaking (NPRM) to address these issues remanded by the
D.C. Circuit, and to make several technical clarifications and
corrections (85 FR 52198). Section 112 of the CAA establishes a
regulatory process to address emissions of hazardous air pollutants
(HAP) from stationary sources. CAA section 112(d) requires the Agency
to promulgate technology-based national emission standards for
hazardous air pollutants (NESHAP) for major sources. ``Major sources''
are
[[Page 60820]]
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). The EPA 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.
III. Summary of Final Action and Significant Changes Since Proposal
In this action, we are finalizing amendments to certain emission
limits for new and existing boilers and process heaters. Most of these
changes are identical to the emission limits that were proposed. As
discussed further below at sections III.A.3 (HCl) and III.A.4 (PM),
three of the emission limits have been revised since proposal following
consideration of public comments received--New-Solid (HCl), New-Liquid
(HCl), and Existing-Biomass Fluidized Bed (PM). We are also providing
additional explanation to support the use of CO as a surrogate for
organic HAP and to set a minimum CO emission limit of 130 ppm. In
addition, we are finalizing approval of an alternative monitoring
provision allowing for use of CO2 as a diluent in lieu of
O2 when a continuous emission monitoring system (CEMS) is
used to comply with an emission limit. We are also finalizing a small
number of technical corrections based on our proposed action and our
consideration of public comments received.
A. Revisions to MACT Floor Emission Limits
On July 29, 2016, the D.C. Circuit issued its decision in U.S.
Sugar Corp v. EPA. In that decision, the court vacated those MACT
limits where it held that the EPA had improperly excluded certain units
in establishing the emission standards. Specifically, the court vacated
all MACT limits where the EPA had included certain units in a
subcategory but excluded those same units from its assessment of the
subcategory's best performing sources. On December 23, 2016, the D.C.
Circuit amended its July 29, 2016 decision, remanding those limits
instead of vacating them, and ordering the Agency ``to identify those
standards for which the MACT floor would have differed if the EPA had
included all best-performing sources in each subcategory in its MACT-
floor analysis'' and to ``revise those standards consistent with our
July 29, 2016 opinion in this case.'' 844 F.3d at 270.
Prior to the U.S. Sugar decision, on August 20, 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 upper prediction
limit (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 Boiler Rule, 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, EPA's Response to Remand of the Record for Major Source
Boilers,\2\ that provided a detailed rationale to use the UPL as the
basis of setting a MACT floor for new and existing sources. 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.
---------------------------------------------------------------------------
\2\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3892.
---------------------------------------------------------------------------
Accordingly, the EPA is finalizing changes to emission limits for
new and existing boilers and process heaters. These changes address the
court's concern regarding co-firing units that were included in a
subcategory but excluded from consideration of that subcategory's best-
performing sources in the 2013 analysis. In addition, these changes
apply the UPL to the MACT floor analysis for limited datasets as
explained in EPA's August 2019, memorandum titled ``Approach for
Applying the Upper Prediction Limit to Limited Datasets for Boilers and
Process Heaters at Major Sources.''
1. Overarching Methodology and Dataset Basis
In the 2020 proposal, the EPA based its revised analysis to address
the remand on the same dataset used as the basis for the 2013 final
rule.3 4 The 2013 final rule incorporated electronic
reporting requirements into the rule. As a result, numerous emission
test reports and other compliance data are now available through the
Compliance and Emissions Data Reporting Interface (CEDRI) and
WebFIRE.\5\ However, since the revisions to the MACT floor analysis
were conducted solely to address the remand in U.S. Sugar by correcting
the calculations the court found impermissible, the EPA did not update
its dataset to incorporate CEDRI compliance data into its revised MACT
floor analysis.
---------------------------------------------------------------------------
\3\ See 85 FR 52203.
\4\ 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). See Docket ID Item No. EPA-HQ-OAR-2002-0058-3830.
\5\ 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.
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While the EPA proposed to maintain the same dataset basis as the
2013 rule, the revisions to the rankings of emissions information to
identify the best-performing units to include in the MACT floor
calculation \6\ required that the EPA conduct a more detailed review of
the data available for the units in the dataset that had previously
been excluded from the rankings, focusing on the newly identified best
performers in
[[Page 60821]]
the 2020 proposal. While reviewing the underlying emissions test
reports, the EPA corrected some database errors, filled information
gaps on relative heat inputs from individual fuel types for certain co-
fired fuel blends in order to verify that units did indeed belong to a
specific fuel subcategory based on background combustion process
information provided in the test reports or database fuel heat input
background tables, and adjusted CO instrument span measurements since
some of the revised rankings showed test run values that were
incorrectly reported as zero, non-detect, or negative in the database.
The CO instrument span establishes the appropriate representative
detection level (RDL) to use in the MACT floor calculations and the
underlying emissions test reports in the record typically contained the
span information. In some cases, when the span information was not
available, default span values were assigned as discussed in the
memorandum, Incorporating Measurement Error in Reported Carbon Monoxide
(CO) and Total Hydrocarbon (THC) Data (Revised August 2012).\7\ These
adjustments were needed to ensure that we could use the data from the
newly identified best performers. Had these units been identified as
best performers in the original rulemaking, the EPA would have
conducted a similar review of the test data and made the same
corrections and adjustments. These data had not been previously
scrutinized since they were not used in the original UPL calculations.
While corrections were made to the original dataset for the purposes of
revising UPL calculations for this final rule, no recent compliance
data after January 31, 2013 (e.g., emission test reports and other
compliance data available through CEDRI and WebFIRE) were incorporated
into the rankings or UPL calculations for these final MACT floor
emission standards, for the reasons explained later in this subsection.
---------------------------------------------------------------------------
\6\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-0815 for
background on how the EPA calculates MACT emission limits, along
with the docketed memorandum, Revised MACT Floor Analysis (2021) for
the Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--
Major Source.
\7\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3833.
---------------------------------------------------------------------------
Commenters both agreed and disagreed with the EPA's use of the
original 2013 dataset for this reanalysis of the emission limits. Some
commenters provided limited, specific examples of where they believed
additional data should be incorporated to provide additional emission
test run variability in cases where there are limited datasets.
However, these same commenters also agreed that EPA's use of the 2013
dataset is reasonable. These commenters pointed out that the court's
decision in U.S. Sugar directed the EPA to correct its analysis of the
2013 dataset that established the emissions standards, not to collect
new data.
Another commenter disagreed with the proposed approach to base the
revisions to the MACT floor analysis on data from the 2013 final rule.
The commenter claims the data is obsolete and ignores several years of
compliance data available in CEDRI. This commenter did not dispute the
EPA's methodology in calculating revised MACT standards consistent with
the D.C. Circuit's opinion in U.S. Sugar v. EPA. The commenter's
criticism was that the EPA should have considered additional data
beyond those contained in the 2013 database for the remanded rule, and
they claimed that, in fact, section 112(d) of the CAA requires the
Agency to consider compliance data in its action on remand.
Another commenter also requested that the EPA consider certain
additional data. The commenter stated that, ``it is appropriate to
include only information that is relevant for setting the floor or
identifying appropriate variability and exclude data that represents
post-promulgation changes made to existing sources,'' \8\ and that
including the latter data would inappropriately redefine a standard
based on actions taken to comply with such standard. However, the
commenter believes that the EPA should not ignore units for which it
has emissions information without justifying why the result from more
limited data is sufficient. The commenter cites section 112(d)(3)(A) of
the CAA, which requires that the MACT floor be no less stringent than
the average emission limitation achieved by the best performing 12
percent of the existing sources for which the Administrator has
emissions information.
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\8\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3969.
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The commenters claiming that the EPA must consider on remand
additional data beyond the 2013 dataset that was used to establish the
2013 standards which were before the court misconstrue the D.C.
Circuit's instructions in its decision remanding those standards to the
EPA. The court stated that on remand, the EPA must ``identify those
standards for which the MACT floor would have differed if the EPA had
included all best-performing sources in each subcategory in its MACT-
floor analysis.'' U.S. Sugar v. EPA, 844 F.3d 268 (2016) (granting
EPA's motion for rehearing). The court further instructed the EPA to
``revise those standards consistent with'' the court's opinion. Id.
Nothing in the court's opinion or in its grant of rehearing instructs
or requires the EPA to initiate a new standard-setting process or to
assemble additional data. Rather, the remand was targeted to only those
standards affected by the court's decision, and the court did not
address the question of whether the EPA should--let alone must--
consider data that did not exist at the time the challenged rule was
issued. In contrast, the D.C. Circuit vacated--rather than remanded--
the EPA's 2004 emissions standards for commercial and industrial
boilers because it anticipated a ``wholesale revision'' of the rule
would be required. NRDC v. EPA, 489 F.3d 1250, 1262 (2007). Here, the
court neither vacated the standards, nor indicated that it anticipated
consideration of additional data.
The EPA further disagrees that section 112(d)(3)(A)'s reference to
sources ``for which the Administrator has emissions information''
requires consideration of additional data beyond the 2013 dataset, such
as compliance data. That qualifying language is intended to ensure that
the EPA need not obtain emissions data from 100 percent of the source
category or subcategory in order to identify the best performing 12
percent of the source category, consistent with the overall
Congressional intent in enacting the 1990 amendments to section 112 to
prevent delay in regulating emissions of hazardous air pollutants.
Rather, the EPA could identify the best performing 12 percent of the
sources for which it had emissions data, even if the Agency did not
have emissions data for all the sources in the source category or
subcategory and could set standards on that basis without having to
collect information from all sources. In other words, the language the
commenter refers to does not compel collection or consideration of
additional data, particularly here, where the EPA is revising standards
solely in response to a court remand on a very specific, limited issue.
The EPA further notes that some commenters would have the EPA
selectively consider additional data, such as data showing additional
variability. For example, one commenter claims that the EPA must
consider compliance data only for the purpose of accounting for
variability, but not otherwise. The EPA does not agree that it would be
reasonable or appropriate to consider compliance data only to account
for additional variability. Where the EPA uses data for the UPL
calculation, it uses that data for purposes of calculating the floor as
well as for accounting for variability, and it
[[Page 60822]]
would not be appropriate to take a different approach here. As
explained above, in this action the EPA is only correcting the flaw in
its 2013 final rule analysis identified by the U.S. Sugar court in
response to the court's remand. Further, while this action is limited
to the remand, the Agency disagrees that, as a general matter, data
representing compliance actions taken by sources to meet a previous
standard are necessarily inappropriate to consider when revising a
standard. However, that question is not at issue here.
The EPA's approach is reasonable given the limited nature of the
remand. In addition, if the EPA were to revise the affected standards
using newer emissions information, it could result in the potentially
inequitable outcome of some units being subject to more stringent
standards solely because of the EPA's error in its initial MACT floor
calculations, while other units unaffected by the court decision would
remain unchanged. Revising all of the boiler MACT standards, including
the standards that have not been remanded, would require EPA to incur a
significant resource burden and could result in wholesale changes to
standards that were largely upheld by the D.C. Circuit. Given its other
obligations under the statute and the EPA`s determination that using
new data is unnecessary to respond to the remand, the EPA has chosen to
maintain the original data set for purposes of calculating standards.
The revisions incorporate the co-fired boilers that met the subcategory
definition using a threshold of at least 10 percent of a subcategory-
defining fuel, on an annual heat input basis, but were excluded from
the ranking analysis in the 2013 final emission standards. The D.C.
Circuit in U.S. Sugar stated that, if the 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. The final
standards fully incorporate these sources in the development of
standards as required by the remand.
2. UPL Methodology for Limited Datasets
Some of the MACT floor emission limits the EPA proposed were based
on datasets with less than 7 test runs (``limited datasets''). There
were limited datasets for the following subcategories and pollutants
for both existing and new sources: process gas (Hg, HCl, total selected
metals (TSM), and PM), biomass suspension burner (TSM), dry biomass
stoker (TSM, PM, and CO), and coal fluidized bed coal refuse (CO).
Limited datasets also existed 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). On remand, these
limited datasets were reviewed in additional detail to determine
whether it was appropriate to make any modifications to the UPL
approach used to calculate the MACT floors.
In addition to the proposed MACT floors involving limited datasets,
the EPA also conducted a similar, more detailed review of the new
source standards to evaluate if the UPL calculations required any
adjustments to ensure that the resulting emission standards for new
sources were not less stringent than for existing sources. Based on
this review, the EPA found that the revised emission limits for three
new source subcategories and pollutants did not reasonably account for
variability and some changes were made to be consistent with EPA's
Approach for Applying the Upper Prediction Limit to Limited Dataset
Boiler and Process Heaters at Major Sources \9\ to avoid the anomalous
result the Court identified in NACWA v. EPA \10\ where the calculated
new source floor was less stringent than the existing source floor:
These new source subcategories and pollutants are the following: solid
(HCl), wet biomass stokers (TSM, PM), and biomass fluidized beds (PM).
---------------------------------------------------------------------------
\9\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3946.
\10\ See National Assn. of Clean Water Agencies v. EPA (NACWA)
734 F 3d 1115.
---------------------------------------------------------------------------
The only comments received on the proposed methodology for
analyzing limited datasets were made in the context of the new source
solid fuel HCl emission limit. Those comments are summarized in section
III.A.3 of this preamble.
The EPA is finalizing limited revisions to certain standards to
address the specific issue identified by the court in NACWA v. EPA. The
EPA is finalizing, as proposed, adjustments needed to three new source
standards--Solid (HCl) and wet biomass stokers (TSM, PM), and biomass
fluidized beds (PM)--to ensure that the new source floor is no less
stringent than the existing source floor.\11\ Additional detail about
the determinations made at proposal are discussed in the docketed
memorandum and no further analyses were needed as part of the final
rule.\12\
---------------------------------------------------------------------------
\11\ See 85 FR 52205-52207.
\12\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3946.
---------------------------------------------------------------------------
3. Solid and Liquid Fuel HCl Emission Limits for New Sources
The proposed emission limits for HCl in the new source solid fuel
and liquid fuel subcategories were both based on a value equal to 3
times the representative detection level (RDL) because the calculated
UPL from the best performing similar source was less than this
value.\13\ In each case, the RDL value established for these two
subcategories was based on the sampling times of the single best
performer in each subcategory. For HCl, the detection level decreases
with longer sampling times. For liquid fuels, the best performer had a
4-hour stack test, resulting in a 3 times RDL (3x RDL) of 5.4E-05 lb/
MMBtu. For solid fuels, the best performer had a 1-hour stack test with
an average oxygen concentration of 10.2 percent, resulting in a 3x RDL
of 3.0E-04 lb/MMBtu.
---------------------------------------------------------------------------
\13\ In cases where the calculated UPL value is less than three
times the representative detection level (3x RDL), where the RDL is
the average detection level of the best performing sources, the
limit is determined to be equivalent to the 3x RDL value. Such a
limit ensures measurement variability is addressed and provides a
limit that has a measurement imprecision similar to other EPA test
methods.
---------------------------------------------------------------------------
In the case of liquid fuel boilers, the 3x RDL value was multiplied
by a fuel variability factor to establish the MACT floor because the
best performing unit had paired test data and fuel analysis data \14\
to compare to fuel analysis used at the unit over time. The EPA also
reviewed the data for the best performer in additional detail given
that this best performing unit, ``LAShellChemicaGeismar, Furnace F-
S801,'' had a limited dataset of 3 test runs. The EPA concluded that
this unit was indeed a best performing unit.\15\
---------------------------------------------------------------------------
\14\ Paired fuel and testing data means that there is an
analysis of the fuel that was being utilized during the emissions
testing. Unpaired fuel data may be representative of fuel burned at
the unit, but not specifically the fuel burned during the emissions
testing.
\15\ See 85 FR 52206.
---------------------------------------------------------------------------
In the case of solid fuel boilers, the EPA proposed that the unit
with the second lowest emission test results but the lowest
variability, ``TXDibollTemple-Inland, PB-44'' (PB-44) was the best
performing similar source.\16\ This unit did not have paired test data
and fuel analysis data to develop an appropriate fuel variability
factor, so no fuel variability factor was applied to this emission
limit.
---------------------------------------------------------------------------
\16\ Ibid.
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[[Page 60823]]
Comment: Two commenters stated that the 3x RDL emission limit for
HCl should have been calculated differently. One of the commenters
provided specific suggestions, indicating they believed it is not
appropriate for the EPA to set a RDL based on the operation of the top
performing boiler alone. The commenter suggested that a more
representative approach to setting a detection limit would be to derive
an RDL associated with all non-detect emission tests for the best-
performing units in the subcategory.
Response: The EPA agrees with the commenter that sample time data
should be analyzed for the entire top 12 percent of units, not just the
single best performer. However, the EPA disagrees with the commenter's
suggested approach which considers only data that were reported as non-
detect (i.e., the emissions results were below the detection level of
the instrumentation) instead of all available reported pollutant-
specific method detection levels from the best performing units in each
subcategory. As we stated in the docketed memorandum, Data and
Procedure for Handling Below Detection Level Data in Analyzing Various
Pollutant Emissions Databases for MACT and RTR Emission Limits (Revised
2012), our approach, ``minimizes . . . effect of a test(s) with an
inordinately high method detection level (e.g., the sample volume was
too small, the laboratory technique was insufficiently sensitive, or
the procedure for determining the minimum value for reporting was other
than the detection level).'' \17\
---------------------------------------------------------------------------
\17\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3839.
---------------------------------------------------------------------------
Therefore, the EPA revised the 3x RDL values for new source solid
and new source liquid HCl 3x RDL to reflect data from the top 12
percent of boilers. The data were pulled from the 2013 dataset and
supporting test report files from the docket from the 2013 final rule.
Revised data and analysis for the 3x RDL values are found in the
docketed memorandum Revised (2021) Analysis of Minimum Detection Levels
from Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--Major
Source. The revised methodology and changes to the underlying data used
for the 3x RDL calculations resulted in a 30 percent lower 3x RDL value
than what was proposed for solid fuels, with the 3x RDL decreasing from
3.0E-04 to 2.1E-04 lb/MMBtu. For liquid fuels, the revised 3x RDL value
is 122 percent higher than what we proposed, increasing from 5.4E-05 to
1.2E-04 lb/MMBtu.
Comment: Several commenters disagreed with the EPA's approach and
rationale for selecting PB-44 as the best performing source for new
solid fuel units, arguing that the solid fuel HCl limit calculations
need to better account for natural variability in biomass fuel chloride
levels as well as operational variability. Commenters noted that PB-44
only has a single three run test and it has a homogenous dry biomass
fuel, sourced from on-site particleboard byproducts.
Commenters differed in their suggestions for what unit should be
the best performing similar source. Some commenters suggested that
Wellons Boiler was the best performing boiler, despite the larger
variance in its HCl emissions. Some commenters made suggestions on how
to adjust the Wellons Boiler data with additional data outside of the
2013 dataset. Other commenters suggested that other units in the top 12
percent for existing solid fuel HCl best performers were better choices
than PB-44.
With regards to fuel variability, some commenters noted that PB-44
has only three test runs available and that a dataset with six test
runs is superior to a dataset with three. One commenter also added that
both PB-44 and Wellons Boiler do not have any HCl add-on control
devices and the variation in emissions is directly related to fuel
chloride content. The commenter argued that if the EPA had more data
for PB-44, the variability in its HCl emission rates might be much
higher and noted that variability can be determined more accurately
with more test runs. This commenter also emphasized that the emissions
of HCl at the lowest emitting unit are related to chloride variability
in the fuel and not to the performance of any add-on control device.
The commenter suggested several ways to better incorporate chloride
variability in biomass fuels in its detailed comments.
One commenter further disagreed with the EPA's selection of PB-44
which had the second lowest emission test as the best performing
similar source in its limited dataset analysis because it has lower
variance in test results. The commenter suggested that variance is not
the only consideration in the selection of a best performing similar
source, especially where emissions are dictated by the fuel chloride
variability and not by the use of a control device. This commenter also
suggested that the EPA's selection of PB-44 to establish the new-source
floor directly contradicts its assessment of long-term fuel variability
by ignoring data related to fuel variability the Agency had previously
argued was necessary. This commenter also suggested that the EPA's
decision to finalize a standard based on limited dataset with only the
UPL adjustment would be arbitrary, given that the fuel content must be
taken into account to determine the emissions level that boiler
actually achieved every day and under all operating conditions.
Response: The EPA disagrees with commenters that the PB-44 unit
does not reflect the emissions control that is achieved in practice by
the best controlled similar source. As discussed in section III.A of
this preamble, the court remanded for further explanation the UPL
methodology in NACWA v. EPA, in part for the EPA to explain how the UPL
was appropriate for limited data sets in the face of the ``apparently
illogical'' results where the emission limit for new sources was less
stringent than the emission limit for existing sources. NACWA v EPA,
734 F.3d at 1144. Following the NACWA decision, the EPA issued the UPL
memo and the limited data sets memo to provide the explanations
requested by the court, and both approaches have been subsequently
upheld by the D.C. Circuit. The EPA has applied the UPL and the limited
data set approach in calculating the solid fuel HCl limit. The EPA
could not determine that the Wellons Boiler, which commenters point out
has more test runs available than the PB-44 unit, was the best
performing similar source because it yielded the same ``apparently
illogical'' result that the NACWA court questioned, i.e., a new source
limit that would be less stringent than the corresponding existing
source limit, due to the variance in its data. In such circumstances,
the EPA's limited data set approach provides that the EPA will further
evaluate the individual dataset to ensure that the uncertainty
associated with it does not cause the emissions limit to be so high
that it does not reflect the emissions performance of the best
performing similar source, for new source MACT standards.
Moreover, the EPA has broad discretion to identify best performing
sources, and it is reasonable to consider variability in emissions when
choosing the ``best'' sources from an emissions perspective. For
example, a source could have the lowest average emissions level based
on a single very low data point, but other very high emissions points.
It is reasonable for the EPA to consider, in that circumstance, that a
second source with a slightly higher average emissions level but
consistently low emissions is a ``better'' performer
[[Page 60824]]
than the first source. Consistent with the previous MACT floor
methodology, the EPA has determined that MACT floors based on a single
source must be based on at least three runs of test data to ensure that
adequate variability can be incorporated. The EPA has not thrown out
other MACT floor emission limits that are based on a single three run
test.\18\ PB-44 has three valid test runs and it is the unit with the
second lowest emissions test average results but has a variance that is
5 times lower than the Wellons boiler, and it did not yield a new
source limit that is less stringent than the existing source limit.
Therefore the EPA continues to conclude PB-44 is the best performing
similar source for new solid fuel units.
---------------------------------------------------------------------------
\18\ Revised MACT Floor Analysis (November 2011) for the
Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--
Major Source. Revised November 2011. See Docket ID Item No. EPA-HQ-
OAR-2002-0058-3387.
---------------------------------------------------------------------------
The EPA further disagrees with commenters that it should
incorporate fuel variability into the revised emission limit by
evaluating fuel variability from other units in the 2013 dataset. We
have previously stated that we can only apply a fuel variability factor
when we have paired test data and fuel analysis data.\19\ PB-44 had no
paired fuel analysis data with its single 3-run HCl emission test in
the 2013 dataset, so a fuel variability factor could not be developed
according to the historical methodology used in the Boiler Rule.
---------------------------------------------------------------------------
\19\ The EPA explained the limited nature of using only paired
fuel variability data for the basis of its fuel variability factors
in the original 2010 proposal. See Maximum Achievable Control
Technology (MACT) Floor Analysis (2010) for the Industrial,
Commercial, and Institutional Boilers and Process Heaters National
Emission Standards for Hazardous Air Pollutants--Major Source. See
Docket ID Item No. EPA-HQ-OAR-2002-0058-0815. The EPA modified its
approach slightly to address comments received on the proposed fuel
analysis variability methodology as explained in the final rule (76
FR 15627) but never changed its fundamental criteria of looking only
at paired fuel analysis data. As noted in the December 2011
reconsideration proposal, the EPA continued a consistent fuel
variability methodology and at this juncture only ``[s]mall changes
to fuel variability . . . to accommodate the new TSM standard and
comments received during the reconsideration process'' were made,
see Docket ID Item No. EPA-HQ-OAR-2002-0058-3387. When the EPA
issued revised limits in the January 2013 final rule based on
submitted data corrections or new data, it noted that the new data
was incorporated that resulted in revised values, but the general
MACT floor setting methodology remained the same (78 FR 7151).
---------------------------------------------------------------------------
The solid fuel subcategory encompasses a wide variety of boilers
and process heaters and many of these units have achieved this emission
level in practice, though each unit, depending on facility- and unit-
specific circumstances, may employ different fuel blends and control
devices to do so. Both the revised CEDRI compliance dataset and the
2013 dataset used to establish the MACT floor calculations present
several examples of units in the solid fuel subcategory that have
achieved this limit in practice. According to compliance data submitted
to EPA via CEDRI through December 31, 2020, most of the new units in
the solid fuel subcategory are meeting this more stringent emission
limit that is based on a 3x RDL value.\20\ Of the new units with test
data, 71 percent (10 of the 14 units with HCl compliance test data) are
meeting the revised 3x RDL value.
---------------------------------------------------------------------------
\20\ Revised (2021) 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.
---------------------------------------------------------------------------
The EPA also disagrees with some of the commenter suggestions to
bring in new data from outside the 2013 dataset to serve a targeted
purpose for this single subcategory. The EPA explains earlier in this
document why the Agency is not required to consider new data for
purposes of this action.
4. Biomass Fluidized Bed PM Emission Limits for Existing and New
Sources
For existing biomass fluidized beds, we proposed to make the PM
emission limit more stringent, decreasing from 1.1E-01 to 2.1E-02 lb/
MMBtu. The existing source floor was based on the top 5 units in the
subcategory since the subcategory had fewer than 30 sources. The units
that were part of the top 5 changed after we re-ranked the data to
address the U.S. Sugar remand.
For new biomass fluidized beds, we also proposed to make the PM
emission limit more stringent, decreasing from 9.8E-03 to 4.1E-03 lb/
MMBtu. The unit with the lowest minimum test average was
``ORGeorgiaPacificWaunaMill, EU35--Fluidized Bed Boiler'' (Wauna
boiler). The Wauna boiler had six separate tests in the boiler dataset.
However, the calculated UPL for the Wauna boiler was 3.2E-02 lb/MMBtu,
which exceeded the UPL calculated for existing units in the same
subcategory, which was 2.1E-02. Since the new source floor was less
stringent than the existing source floor, the EPA reviewed the data
further to evaluate if the unit truly reflected the best controlled
similar source 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. The EPA conducted additional analysis and
determined that the unit with the second lowest minimum test,
``WIGPGreenBay2818, B10--Wastepaper Sludge-Fired Boiler 10'' (B10), was
the best controlled similar source because it had a variance three
orders of magnitude lower than the Wauna boiler and did not yield a
limit less stringent than the existing source limit.
Comment: One commenter noted that the EPA included 15 p.m. emission
tests for the unit LAGPPortHudson, EQT0109--No. 6 CFB Boiler (Port
Hudson boiler), including two 2007 tests in which the dry scrubber was
off for one test and on for the other, and the EPA only included data
from the test where the scrubber was off in the UPL calculations. The
commenter stated that both tests should be included in the UPL
calculations.
Response: We reviewed the docket record to evaluate the commenter's
concerns with the test runs included for the Port Hudson boiler. The
Port Hudson boiler had five different tests included in the UPL
calculations at proposal. Four of the five tests, dated September 11,
2007, December 18, 2008, December 19, 2008, and July 29, 2009, were all
conducted with the sorbent injection system control device operating.
The fifth test in August 2007 was conducted with the scrubber control
device off. Given that the scrubber operating reflected the more common
unit operations, we also evaluated CEDRI data for the purpose of
verifying that the unit typically operates with its sorbent injection
system operating. We disagree with the commenter that we should use the
tests from August 2007 with both the sorbent injection control
operating as well as off. Since this unit typically operates the
sorbent injection system control device, only the tests conducted while
this control device is operated are representative of the emission
levels and typical operations employed by this source. Introducing
statistical variability in UPL calculations by mixing test results for
different control configurations would be inconsistent with the MACT
floor methodology \21\ since the unit typically conducts its compliance
testing with the control system operating. When we evaluated the August
2007 test report available in the docket in more detail, we found that
the August 2007 test report had four different test scenarios. Scenario
1 and 2 were the only scenarios firing biomass fuels (both fired a
combination of biomass and petroleum coke, but met the threshold of at
least 10 percent heat
[[Page 60825]]
input from biomass). The test scenario included in the proposal
analysis had the sorbent injection system turned off. For the reasons
discussed above, we replaced the August 2007 test with the test
scenario which had the sorbent injection system turned on. After
replacing this test scenario, the Port Hudson boiler was no longer part
of the top five boilers in the existing source floor calculations. The
Port Hudson boiler was removed from the existing source floor
calculation because it had the eighth lowest mean emission test after
reviewing and correcting the test scenarios used in the analysis, based
on public comment. The boiler that now had the fifth lowest mean
emission test is PAPHGlatfelter, PB5 (PB5 boiler), so we added the two
emission tests from the PB5 boiler into the analysis for the UPL
calculation for the existing source MACT floor.
---------------------------------------------------------------------------
\21\ Some facilities submitted emission test data based on
previous control configurations that are no longer installed on the
unit. Emission data reported while using these previous control
configurations were not used to establish the MACT floor. See Docket
ID Item No. EPA-HQ-OAR-2002-0058-3387.
---------------------------------------------------------------------------
Comment: Two commenters requested a data correction for the 2006
test from the Wauna boiler. The commenters noted that the PM test
results in the 2013 dataset and MACT floor ranking were listed
incorrectly as lb/MMBtu in the MACT floor analysis. They pointed to the
supporting test report, where the values were actually in units of
grains per dry standard cubic foot (gr/dscf), corrected to 7 percent
oxygen, instead of lb/MMBtu. These commenters requested that the EPA
revise the UPL calculation after correcting the units of measure for
the 2006 test.
Response: We reviewed the docket record to verify the units of
measure for the 2006 Wauna boiler test and agree with the commenters
that a correction is needed to convert the gr/dscf into units of lb/
MMBtu. We made this correction in the revised UPL calculation for both
new and existing sources.
Comment: One commenter stated the Wauna boiler's 2004 stack test is
an outlier and should be excluded from the data. The commenter stated
that the EPA should remove this test and recalculate the UPL with the
remaining 15 test runs from the Wauna boiler.
Response: We reviewed the 2004 Wauna boiler test that the commenter
stated should be excluded to assess whether or not this test is in fact
an outlier. The 2004 test had the same test method and length of the
test runs as the other five tests. In addition, none of the other five
tests subtracted negative filter weights or had weights less than 1
milligram. As the emissions limit is expressed in terms of emissions
per heat input, we checked both the emissions and heat input data for
outliers. Our general outlier test is conducted at the 5% significance
level in log space, and when a value is found to be an outlier at this
level, we exclude it from further calculations. We conducted an outlier
test with ProUCL \22\ and determined that none of the PM emission test
runs had outliers, either in normal or in log space, at the 1, 5, and
10% significance levels. Observing that the heat input for the 2004
test was between 57 and 66 percent lower than the heat input for the
other five tests in normal space, we conducted an outlier test with
ProUCL and found that the total heat input for 2004 was an outlier at
the 5 and 10% significance levels for both normal and log space.
Because the heat input component of the 2004 emissions test is an
outlier, we agree with the commenter that the heat input and the
corresponding emissions value from this test should be excluded as an
outlier. Therefore, we removed the 2004 test data from the UPL
calculation for both new and existing sources.
---------------------------------------------------------------------------
\22\ ProUCL is a comprehensive publicly available statistical
software package. See https://www.epa.gov/land-research/proucl-software.
---------------------------------------------------------------------------
After making the corrections to the 2006 Wauna boiler test,
removing the outlier 2004 Wauna boiler test, and correcting for the
appropriate tests for the Port Hudson boiler control device
configurations, the existing source floor value calculations have
changed since proposal. The revised emission calculations for existing
sources considering these public comments and related data changes have
resulted in a more stringent UPL calculation of 7.4E-03 lb/MMBtu.
Comment: One commenter requested that the EPA revise its
determination for the best performer for the new source PM limit for
biomass fluidized beds. The commenter noted that the EPA chose to base
the new source floor on the second-best performing unit, despite having
a more robust dataset for the top performer. The EPA selected the unit
with the second lowest mean because it stated that the unit with the
lowest mean (Wauna boiler) exhibited too much variance in its emissions
data. The commenter noted that the dataset for the second-best
performer (B10) offered only six test runs, while the Wauna boiler had
18 runs and better represented true variability at the unit. The
commenter argued that the MACT floor should be based on the top-
performing unit which utilizes the best control technology, a fabric
filter, and pointed out that five of the six stack tests for the Wauna
boiler exhibit consistent performance.
Response: Based on the data correction made for the units of
measure for the 2006 test and removal of the 2004 test as an outlier,
the calculated 99 percent UPL for the Wauna boiler decreased from the
calculation in the proposed rule, from 3.2E-02 to 8.4E-03 lb/MMBtu.
This revised UPL calculation for new sources still yields an anomalous
result, as the new source PM limit is less stringent than the 7.4E-03
lb/MMBtu PM limit for existing sources.
Consistent with the 2020 proposal, the EPA conducted additional
investigation of the revised Wauna boiler dataset to determine whether
the Wauna boiler was indeed the best performing similar source. 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 the highest variance
among the top five performing boilers in the existing source floor,
even after making the corrections for the 2004 and 2006 test data noted
above. The variance is 7 times higher than the unit with the second
lowest ranked mean, B10. The overall average (considering all stack
tests, not just the minimum stack test average) for the Wauna boiler is
also higher than the units with the second, third, and fourth lowest
mean emission test results. The overall average for the Wauna boiler is
1.5 times higher than the second ranked unit, B10. This information
indicates that the second ranked unit, B10, has a more consistent level
of emissions performance than the Wauna Boiler, and the resulting UPL
calculations support this. The calculated UPL is lower for B10 than for
the Wauna boiler. For these reasons, we continue to conclude that the
Wauna boiler is not the best performing source for this subcategory and
pollutant and we are finalizing B10 as the best performing source.
Therefore, the EPA is finalizing the proposed PM emission limit of
4.1E-03 lb/MMBtu for new sources.
More complete details of the revised analysis for both new and
existing source PM emission limits are included in the docketed
memorandum, Revised MACT Floor Analysis (2021) for the Industrial,
Commercial, and Institutional Boilers and Process Heaters National
Emission Standards for Hazardous Air Pollutants--Major Source.
B. Beyond-the-Floor Emission Limits
We proposed beyond-the-floor limits for 16 subcategory and
pollutant combinations. We compared the revised emission limits to the
limits from the 2013 final rule to assess whether a beyond-the-floor
option was technically achievable and cost effective. Typically
[[Page 60826]]
we would assess technical achievability and cost effectiveness by
assessing various levels of stringency of emission reductions,
technical achievability of options and associated costs. For this rule,
for subcategories where the 2013 limit was more stringent than the MACT
floor limit calculated in the 2020 proposal, we reviewed compliance
data available through CEDRI and WebFIRE to assess whether the more
stringent limit was being achieved in practice. There were nine
subcategory and pollutant combinations for existing sources and seven
subcategory and pollutant combinations for new sources where compliance
data showed boilers that already achieved the 2013 limits. Then, to
assess whether compliance with the 2013 limits was cost effective, we
reviewed the control devices currently installed to determine if any
cost savings would occur should we finalize the less stringent limit.
In all cases, the controls that were already installed were the same
types of controls that would be required to meet either the 2013 limits
or the less stringent limits calculated in the proposed rule and,
therefore, no additional costs would be incurred to meet the more
stringent limits. As a result, we proposed 16 emission limits from the
2013 final rule as beyond-the-floor limits.
There were six limits in three subcategories--new and existing
units for PM for Gas 2 units, TSM for biomass suspension burners, and
TSM for dry biomass stokers--where the 2013 limits were more stringent
than the MACT floor limits calculated for the proposed rule, but recent
compliance data were not available. Since no data were available, we
did not identify any beyond-the-floor options for these subcategories
and beyond-the-floor limits were not proposed for these subcategories.
For TSM, sources have the option to comply with either PM or TSM
emission limits. The lack of available TSM data indicates that sources
in these subcategories are all complying with the PM emission limits
rather than the alternative TSM limits. The lack of available PM data
for Gas 2 units indicates that sources are all meeting the Gas 1
subcategory definition.
Comment: One commenter suggested that the EPA's proposed approach
for the beyond-the-floor analysis does not satisfy section 112(d)(2) of
the CAA, which requires the ``maximum'' degree of reduction that is
``achievable'' considering cost and other factors through all potential
reduction measures. The commenter noted that the EPA only considered
whether the newly recalculated floors were less stringent than the
emission levels that were already being achieved, and if ``no
additional costs would be incurred to meet the more stringent limits,''
then the EPA set beyond-the-floor standards which are more stringent
than the floors and are equivalent to the current standards that these
boilers have already been meeting. The commenter acknowledged that the
EPA is correct to recognize that the current limits are achievable but
argued that the EPA's analysis does not actually consider what the
``maximum'' achievable reductions are, such as what reduction levels
are achievable through use of cleaner fuels or control technologies.
This commenter also stated that it is unlawful that the EPA
proposed to weaken six limits since all of the units subject to those
limits have already been in compliance with them for more than three
years. The commenter argued that any standards that are less stringent
than the 2013 limits do not represent the average emission levels
achieved by the relevant best performing units.
Response: We disagree with the commenter that the beyond-the-floor
analysis does not satisfy section 112(d)(2) of the CAA. In 2013, the
EPA conducted a subsequent beyond-the-floor analysis, evaluating
whether any recalculated emission limits were less stringent than the
2011 rule in order to assess whether a beyond-the-floor option was
technically achievable and cost effective. This analysis resulted in
nine beyond-the-floor limits.\23\ The beyond-the-floor analysis
conducted in the proposal used the same methodology and resulted in 16
proposed beyond-the-floor limits.\24\
---------------------------------------------------------------------------
\23\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3843.
\24\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3948.
---------------------------------------------------------------------------
Most of the recalculated emission limits resulting from the U.S.
Sugar remand resulted in more stringent limits compared to the 2013
final rule. For these limits, the EPA continues to believe the analysis
in the 2011 rule is reasonable, and the EPA received no information
during the comment period to demonstrate it is not. Further, for most
affected standards where the EPA's recalculation of the UPL resulted in
a less stringent numeric limit, the EPA is retaining the more stringent
limit based on its authority to set standards beyond the MACT floor.
This is a reasonable approach where sources have been complying with
the 2013 standards, thus demonstrating that the standards are
achievable, considering the factors enumerated in section 112(d)(2) of
the CAA. The only exception to this approach is for alternative
standards where there is no demonstration that any source has been
complying with the standard since the 2016 compliance date because no
units are in the subcategory or no units have chosen to utilize the
alternative limits.
Based on this, additional analyses of compliance data, and the lack
of information on additional control technologies provided by the
commenter, we continue to believe that our beyond-the-floor analysis is
appropriate, and we are finalizing the 16 beyond-the-floor limits as
proposed.
We further disagree with the commenter that it is unlawful to
finalize the six emission limits that were recalculated to be less
stringent than the 2013 standards. First, the court in U.S. Sugar
determined that the 2013 limits were incorrectly calculated and
remanded the standards to the EPA. The recalculated MACT floors are a
result of addressing deficiencies identified by the U.S. Sugar court
and additionally by the NACWA decision on limited datasets. Second, we
did not identify any beyond-the-floor options for these subcategories.
We found that no biomass suspension burners or dry biomass stokers have
been using the alternative TSM limit for compliance--all units have
been complying with the PM limit. In addition, we found that no units
have been subject to the PM limit in the Gas 2 subcategory and
therefore have no information to conclude that additional reductions
are achievable.
In addition, we note that while these six recalculated limits are
slightly less stringent than the 2013 limits, in practice they are not
effectively different. Affected sources would install the same control
technology to meet either the remanded or the recalculated emissions
limits, despite the slight increase in the recalculated limits.
Furthermore, no emissions increases are expected to result from
finalizing less stringent units in these subcategories since no sources
exist that are subject to the Gas 2 limit, or that are choosing to meet
the alternative TSM limits.
C. Revisions to Output-Based Emission Limits
In the proposed rule, the EPA re-calculated the corresponding
output-based emission limits to update the limits in the fourth column
of Tables 1 and 2 of the regulatory text. Revisions were not required
for all the proposed emission limits due to rounding and the small
amount of change in the corresponding input-based limit between the
2013 limits and the limits in the proposed rule. The memorandum,
[[Page 60827]]
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.
We received no comments on the proposed changes to the output-based
standards. Therefore, we are finalizing the revisions to the output-
based emission limits as proposed. We have revised output-based
emission limit calculations to reflect the changes made to the
corresponding input-based emission limits for existing source biomass
fluidized bed PM and new sources solid and liquid fuel HCl. The
memorandum, Alternate Equivalent Output-Based Emission Limits for
Boilers and Process Heaters Located at Major Source Facilities--2021
Revision, which is available in the docket for this action, provides
details of the output-based emission limit revisions since proposal.
D. CO as a Surrogate for Organic HAP
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 remanded
to the EPA to adequately explain how CO acts as a reasonable surrogate
for non-dioxin/furan organic HAPs. To be reasonable, the emission
standard set for the surrogate must reflect what the best similar
source or the best 12 percent of sources in the relevant subcategory
achieved with regard to the HAP. This requires the surrogate's
emissions to share a close relationship with the emissions of the HAP.
The court identified that one crucial factor for determining whether
that close relationship exists is the availability of alternative
control technologies that reduce the HAP emissions without impacting
that of the surrogate or, conversely, reduce the surrogate emissions
without impacting the HAP emissions. The court stated that the EPA
could not conclude that CO acts as a reasonable surrogate in this
statutory context without considering whether the best performing
boilers might be using alternative control technologies and methods
that reduce organic HAP emissions beyond what they achieve by reducing
CO alone. The court asked that EPA address concerns raised in public
comments that alternative control technologies might further lower HAP
emissions.
In response to this remand, the EPA provided further explanation to
substantiate its finding that CO is an appropriate surrogate for non-
dioxin/furan organic HAP. In the proposed rule, the EPA noted that
available control technologies for organic HAP emissions are either
combustion devices or recovery devices. Combustion is the more commonly
applied option for controlling organic HAP because it is capable of
high removal (destruction) efficiencies and its effectiveness does not
depend on the makeup of the organic HAP stream or the organic HAP
concentration. Recovery devices are not applicable for all organic HAP
and are not effective in treating low organic HAP concentration
streams, i.e., the levels of concentrations seen in sources with good
combustion practices.
In the proposal, we indicated that none of the best-performing
units employ an add-on, alternative control device that was installed
for controlling emissions of either organic HAP or CO. While many
industrial boilers and process heaters employ post combustion controls
for particulate matter, acid gases, and/or mercury, these add on
controls are not designed to affect emissions of either CO or non-
dioxin organic HAP. In any case, any add-on controls that are
downstream of the combustion chamber of the boiler would be secondary
controls that would only be effective (if at all) if the upstream
primary control (the combustor) was ineffective. The presence of CO in
the flue gas stream is an indicator of inefficient and incomplete
combustion. The presence of non-dioxin organic HAP (or other organic
compounds) in the flue gas stream would also be an indication that the
upstream combustion process was inefficient and incomplete (i.e.,
perfectly complete combustion of an organic compound would result in
only CO2 as a carbon-containing product). The best
performing industrial boilers do not employ downstream controls for CO
or non-dioxin organic HAP because the primary control (the combustor)
is effectively destroying the non-dioxin organic HAP and downstream
controls are not needed to achieve additional reductions. Minimum CO
concentration in the flue gas stream is evidence of that the combustion
process is efficient and effective. For these reasons, the Agency
continued to conclude that CO is a reasonable surrogate for non-dioxin/
furan organic HAP.
Comment: Commenters stated that not all organic HAP are products of
incomplete combustion. Some organic HAP--such as polychlorinated
biphenyls (PCBs) and polycyclic organic matter (POM)--can be present in
the raw materials before combustion or can be generated outside the
combustion unit or within the combustion unit but outside of the flame
zone. In addition, different organic HAPs can be formed, destroyed, or
reformed in various physical regions of diffusion flames and in
different zones of premixed flames. Commenters stated that minimizing
CO emissions will not minimize emissions of all organic HAP other than
dioxins and furans because not all organic HAPs are formed or destroyed
in combustion and post-combustion zones in the same fashion or like CO.
The commenters further claimed that underlying formation and
destruction of just CO in the simplest of situations involves several
hundred reactions and tens of individual species are involved. The
kinetics and thermodynamics become far more complex for other organic
HAPs. Thus, the commenters argued, there is no basis in combustion
science to presume that even any one organic HAP--much less all of them
will behave similarly to CO. Specifically, the commenters claimed,
pollutants like PCBs and POM/polycyclic aromatic hydrocarbon (PAH) will
not be minimized by good combustion or through using a post-combustion
oxidation catalyst.
Response: We agree with the commenter that organic compounds--and
perhaps even organic HAP--are present in the fuels (coal, biomass, etc)
used in industrial boilers. With regard to the PCBs mentioned by the
commenter, we note that PCBs are commonly known as ``dioxin-like''
organic compounds \25\ and their formation should similarly be limited
by the work practice standards established for dioxins and furans.
Regarding the POM/PAH mentioned by the commenter, these compounds are
well known to be products of incomplete or inefficient (i.e., oxygen-
starved or fuel-rich) combustion.26 27 28 29 30 Similarly,
CO is also the product of inefficient combustion. In an oxygen-rich
environment, complete and efficient combustion will produce
CO2 rather than CO. Regardless of whether organic HAP are
present in the boiler's fuel before combustion, or whether they are
generated within the combustion unit, all organic HAP would be
destroyed under complete and efficient
[[Page 60828]]
combustion conditions. Therefore, the presence of organic HAP in the
boiler emission flue gas stream would be the result of incomplete
combustion and higher emissions of CO (relative to CO2)
would be expected.
---------------------------------------------------------------------------
\25\ ``Dioxins'' are often described as ``dioxins, furans, and
dioxin-like compounds''.
\26\ Serban C. Moldoveanu, in Pyrolysis of Organic Molecules
(Second Edition), 2019.
\27\ T.A. Abrajano Jr., V. O'Malley, in Treatise on
Geochemistry, 2007.''
\28\ Z. Fan, L. Lin, in Encyclopedia of Environmental Health
(Second Edition), 2011.
\29\ M. Huang, T.M. Penning, in Encyclopedia of Food Safety,
2014.
\30\ Tarek Saba, in Introduction to Environmental Forensics
(Third Edition), 2015.
---------------------------------------------------------------------------
We also disagree with the comment that minimizing CO emissions will
not minimize emissions of all organic HAP other than dioxins and
furans. The Agency agrees that combustion is complex and involves many
reactions causing many different organic compounds to form and be
themselves combusted to form other organic compounds. Combustion is the
process of breaking apart the organic (i.e., carbon-containing)
molecules in the fuel and converting them to CO2. Perfectly
complete combustion would convert all the carbon in the fuel to
CO2. Completeness of the combustion process is dependent on
several variables, including the temperature, the amount of oxygen, and
the mixing of the fuel and oxygen. Incomplete combustion results in
production of partly broken down and partially oxidized organic
compounds, including CO. Because the conversion of CO to CO2
is a difficult step, and the last one in the destruction of
hydrocarbons, including organic HAPs, the EPA concluded it is a good
indicator of the completeness of combustion. Thus, decreasing levels of
CO are correlated with increasing destruction of organic compounds
until a threshold is reached where, because combustion of CO is the
last step in combustion, the combustion of organic materials, including
organic HAP, is essentially complete.
Comment: One commenter noted that boilers are frequently the
primary control devices under many new source performance standards
(NSPS) and NESHAP standards for control of emission streams containing
organic compounds. Typically, vent gases containing organic HAP
emissions are sent to boilers or process heaters as supplemental fuel
if they have sufficient heating value, and boilers and process heaters
are accepted as emission control devices because performance testing
routinely shows that they can provide organic destruction efficiencies
of greater than 98 percent. Nearly all boilers and process heaters use
monitoring of CO as a means to evaluate whether the device is
performing effectively, and when CO increases, the unit is not
efficiently oxidizing CO to CO2 and the organics are not
being as effectively oxidized.
Response: We agree with the commenter that boilers have frequently
been identified as the best way of reducing emissions of organic
compounds. Combustion devices, such as boilers, continue to be
identified as the best control option available for reducing organic
HAP from various industrial processes.\31\
---------------------------------------------------------------------------
\31\ See, for example, 40 CFR part 63, subparts F, G, H, I, and
FFFF.
---------------------------------------------------------------------------
Comment: Commenters stated that organic HAP can be reduced not only
through combustion controls but also through post-combustion controls
such as fabric filters, wet scrubbers, and activated carbon injection
(ACI). Commenters further stated that the EPA has found that ACI
reduces emissions of all organic HAP by 80 to 90 percent. Commenters
stated that this refutes the EPA's claims that the measures for
controlling CO and organic HAP are the same.
Response: The EPA agrees that some downstream control devices have
the capacity to reduce organic emissions. However, such downstream
control devices are only effective if the primary control device--the
combustor itself--is not effectively destroying the organic HAP before
it reaches the downstream controls. Further, the effectiveness of the
post-combustion techniques identified by the commenter, unlike thermal
oxidation, depends specifically on the organic HAP and on the
concentration of the particular organic HAP. The commenter noted that
the EPA has previously stated that POM/PAH that is emitted during
combustion can be further reduced by various post-combustion controls,
including fabric filters, wet scrubbers, and ACI. However, as discussed
previously, POM/PAH compounds are the product of incomplete and
inefficient combustion. Therefore, if the combustor is optimized for
combustion--as indicated by its CO emissions--then POM/PAH production
will be minimized, and the downstream control equipment will be
unnecessary.
We also disagree with the commenter that the EPA found that ACI
reduces organic HAP emissions by 80 to 90 percent. The commenter is
citing a telecommunication from an ACI vendor regarding organic HAP
emissions from a sinter plant in the Integrated Iron and Steel
Manufacturing source category, not a statement by EPA (85 FR 42090). In
that action, for purposes of evaluating cost-effectiveness, the EPA
assumed reductions at a level provided by the vendor but did not itself
conclude that those reductions were achievable. The issue being
addressed in the remand is whether the best performing units were using
post-combustion controls that controlled organic HAP but did not
control CO. None of the best performing boilers use an ACI system.
E. CO 130 PPM Threshold Emission Limits
On March 16, 2018, the D.C. Circuit issued its decision in Sierra
Club v. EPA, 884 F.3d 1185. In that decision, the court remanded the
EPA's decision to set a limit of 130 ppm CO as a surrogate for non-
dioxin organic HAP for certain subcategories, asking the Agency to
better explain its analysis supporting its decision. 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 noted 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 why 130 ppm is the appropriate
level if there is a non-zero CO level below which organic HAP levels
cannot be further reduced.
In response to this remand, the EPA provided further explanation to
substantiate the 130 ppm threshold emission limit. In the proposed
rule, we described the relationship that we previously found between CO
and formaldehyde using the available data obtained during the 2013
rulemaking. The paired data showed decreasing formaldehyde emissions
with decreasing CO emissions down to CO levels around 300 ppm (with
formaldehyde emissions down to less than 1 ppm). 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.
In the proposed rule, we corroborated our observation that reducing
CO emissions also resulted in a reduction of
[[Page 60829]]
formaldehyde emissions until a leveling off in formaldehyde reductions
is reached after which further reduction of CO levels appeared to
result in higher levels of formaldehyde emitted. The proposed rule
described in detail two additional studies--the polycyclic aromatic
hydrocarbons (PAH) study \32\ and the Multipollutant Control Research
Facility (MPCRF) study \33\--that observed this same trend. In
addition, in the proposed rule, we suggested a potential explanation
for this observed trend. As has already been discussed, near complete
combustion (as evidenced by very low CO concentration) is possible
under an oxygen-rich environment. To achieve that oxygen-rich
environment, excess combustion air must be provided to the burners. As
the combustion process progresses, the increased combustion air can
increase the turbulence and mixing within the boiler. This increased
turbulence can result in some molecules of the reactants (i.e., the
oxygen and organic HAP) being forced near the furnace walls which are
somewhat colder than the combustion zone. This cooling, known as the
``wall effect,'' may be sufficient to impact the combustion reaction,
resulting in some organic HAP molecules that are not fully combusted,
and thus emitted.
---------------------------------------------------------------------------
\32\ 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.
\33\ Surrogacy Testing in the MPCRF, Prepared for U.S. EPA by
ARCADIS, March 30, 2011. See Docket ID Item No. EPA-HQ-OAR-2002-
0058-3942.
---------------------------------------------------------------------------
In the 2013 rulemaking, we determined that there are no further
reductions of organic HAP available below 130 ppm CO. This analysis
relied on our paired CO-formaldehyde data, yet we also stated that the
same data were not a reliable indicator of organic HAP emissions at
very low levels. 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 in 2013 was that imprecise formaldehyde measurements at low
concentrations 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, ``[b]ased on this, we do
not believe that such measurements are sufficiently reliable to use as
a basis for establishing an emissions limit.'' 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.
Our evaluation of the PAH and MPRCRF studies revealed that the
observed relationship in our CO-formaldehyde data was not due to
imprecise or unreliable measurements, but in fact has been observed in
other studies. Because the same CO-HAP relationship was presented in
the PAH and MPCRF studies (i.e., that organic HAP levels decreased with
decreasing CO levels until a leveling off and trending upward with
further decreasing CO levels), we concluded in the proposed rule that
our formaldehyde data used in establishing the 130 ppm CO standard was
not imprecise or unreliable and could be explained by the wall effect
described above. These studies, combined with the relationship found in
our CO-formaldehyde data, support that there is a non-zero CO level
below which organic HAP levels are not further reduced.
Comment: One commenter opposed the EPA's claim that organic HAP are
effectively nonexistent when CO levels are below 130 ppm. The commenter
stated that the EPA's formaldehyde emissions data shows that there are
significant formaldehyde emissions at CO levels below 130 ppm, at 2 ppm
or more even with the limited data set available. The commenter also
stated that the PAH study merely confirms that there are significant
PAH emissions even at very high levels of excess air when CO levels
would be expected to be very low. This data shows that gaseous PAH
emissions actually increase with increasing excess air as it is
increased from 20 percent to 40 percent--when CO levels would be
dropping. The commenter further stated that the MPCRF study confirms
that organic HAP emissions are not nonexistent when CO levels are at or
below 130 ppm and that they are not correlated with CO.
Response: We disagree with the commenter that the Sierra Club
decision requires the EPA to demonstrate that organic HAP emissions are
``nonexistent'' at the level of the CO standard. Rather, the court said
that the standard based on a surrogate must be set at a level at which
``the EPA can be confident that the targeted HAP emissions are reduced
as far as possible or, indeed, eliminated entirely.'' Sierra Club, 884
F.3d at 1195 (emphasis added). We agree with the commenter that organic
HAP emissions can be non-zero when CO levels are below 130 ppm, but at
that level, they are expected to be reduced to the greatest extent. Our
CO-formaldehyde data for units operating at a CO concentration level
below 130 ppm ranged from a measured high value of 2 ppm to a measured
low value of 0.1 part per billion (ppb). The range of emissions from
multiple tested units is expected due to inherent variability from
unit-to-unit. In contrast, the data presented from the PAH and MPCRF
studies were measured from a single unit (i.e., each study used a
single boiler for the tests). The MPCRF study shows the same trend with
formaldehyde levels increasing from 10 ppb, at 70 ppm CO, to 57 ppb, at
40 ppm CO. The MPCRF study also shows that as the CO concentration
levels at around 130 ppm, organic HAP, as a group, have been reduced to
their minimum levels. Some of the organic HAP in the MPCRF study show
the same trend as the PAH study and the EPA's CO-formaldehyde data.
Some show no further reduction, but most of these also show a spike in
concentration below 130 ppm CO. While some organic HAP did show further
reduction, as stated earlier, as a group the organic HAP had been
reduced to minimum levels by around 130 ppm. Based on the overall
consideration of each of these organic HAP, we continue to conclude
that there are no further reductions of organic HAP available below 130
ppm CO.
Comment: Commenters also disagreed with the EPA's statement that
organic HAP cannot be further reduced when CO levels are below 130 ppm.
The commenter stated that the EPA has recognized that all organic HAP
emissions can be reduced with ACI, and some organic HAP emissions can
also be reduced with other end-of-stack controls, including fabric
filters and wet scrubbers.
Response: The EPA disagrees with the comment that organic HAP can
be further reduced when emitted from a boiler with CO levels below 130
ppm. The level of organic HAP emitted, as indicated in the MPCRF study
are in a range that is well below the inlet concentration of the post-
combustion controls used for other pollutants. As discussed in the
proposal preamble, 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). Concentrations of conventional pollutants (e.g.,
NOX, SO2, PM) are present at much higher
concentrations (ppm or vol% levels as opposed to ppb) at the inlet of
their
[[Page 60830]]
respective controls devices (e.g., SCR, wet scrubber, fabric filter or
ESP).\34\ Even mercury--which is a very low concentration pollutant
that is not controlled by upstream combustion--is often present in
concentrations of approximately 10 ppb at the inlet of the control
devices and at a concentrations of approximately 1 ppb at the exit.
Fixed-bed activated carbon adsorption units can be sized for
controlling VOC-containing streams at concentrations as low as several
ppb in the case of some toxic chemicals. However, while fixed-bed
activated carbon adsorbers can be sized to treat low concentrations
(several ppb) of VOC-containing gas streams, they can also introduce
considerable pressure drop across the system resulting in additional
electricity used by the system fans, which must be appropriately sized
to overcome the pressure drop through the carbon beds. Therefore, we
maintain that the quantity of organic HAPs being emitted below CO
levels of 130 ppm is not susceptible to further control.
---------------------------------------------------------------------------
\34\ U.S. EPA. EPA Air Pollution Control Cost Manual. Sixth
Edition. January 2002. EPA/452/B-02-001.
---------------------------------------------------------------------------
Furthermore, we disagree that all organic HAP emissions can be
reduced with ACI and note that the commenter is citing a quote from an
ACI vendor and not a statement from the EPA, as explained above. The
effectiveness of ACI for air pollutant control is related to contact
between a sorbent particle and a molecule of pollutant. The higher the
concentration of the air pollutant--whether that be mercury or organic
HAP--the more effective the pollutant is removed via adsorption to the
carbon surface. As the concentration of the pollution decreases, the
likelihood of contact between a pollutant molecule and a carbon sorbent
particle declines significantly; and the effectiveness is diminished.
Similar to the results that were observed for mercury, low inlet
concentrations of organic HAP will result in a similar impact on
control efficiency using ACI. In fact, none of the best performing
organic HAP units are using ACI because those units are more
effectively reducing organic HAP through combustion. It also is
important to note that combustion devices, such as boilers, are among
the best controls available for reducing organic HAP from various
industrial processes.
F. New Source Definition
Several commenters requested that the EPA revise its definition of
``new source'' to base the determination of which sources must meet
revised new source standards to only those sources that constructed or
reconstructed after the EPA's 2020 proposed action for this final rule.
The EPA disagrees that this is compelled by the statutory language and
believes this final rule reflects a reasonable approach in these
particular circumstances.
One commenter refers to the EPA's part 63 General Provisions
regulations, which state that ``[a] new affected source for which
construction commences after proposal of a relevant standard is subject
to relevant standards for new affected sources, including compliance
dates.'' 40 CFR 63.5(b)(1). The EPA disagrees that the statutory and
regulatory provisions the commenter refers to are relevant here, or
that those provisions override the statutory definition of ``new
source,'' which is expressly based on the date EPA ``first proposes''
an emissions standard that applies to the source. See also 40 CFR 63.2
(defining ``new source'' in same manner). In fact, the different
definition of ``new source'' in section 111 to which the commenter also
refers only underscores the fact that Congress specifically defined
``new source'' in section 112 to be based on the ``first'' proposal of
an emissions standard, rather than the more general ``proposed
regulations'' found in section 111. Similarly, the other provisions the
commenter refers to are not dispositive here. First, the General
Provisions regulations the commenter refers to address pre-construction
review requirements (40 CFR 63.5) and define ``emissions standard'' to
mean ``a national standard, limitation, prohibition, or other
regulation'' issued under section 112 (40 CFR 63.2). Neither of these
provisions addresses the question here--whether the EPA must always re-
define new sources when it revises a MACT standard. Similarly, the
statutory definition of ``emission standard'' contains nothing that
addresses whether the definition of ``new source'' under section 112
changes every time the EPA proposes to revise a MACT standard (CAA
section 302(k)).
The EPA agrees that section 112(i)(2) does not address the
commenter's request. That provision allows for a longer compliance
period for new sources where the EPA's proposed standards are less
stringent than the standards in the final rule. The commenter further
claims that Congress did not address a situation where the EPA proposes
to revise an emissions standard ten years after its first proposal of
standards, and notes that this time period is even longer than the
periodic review timeframe of 8 years. The commenter also claims that
the EPA did not establish the definition of ``new source'' based on the
arguably ``first'' proposal of MACT standards in 2003, and that the
Agency has therefore conceded that ``first proposes'' can mean a
subsequent proposal. The EPA believes its approach in the final rule is
a reasonable application of the definition of ``new source'' in this
particular circumstance. The MACT standards promulgated in 2004 were
vacated by the D.C. Circuit in an opinion in which the court stated
that it expected the reissued standards to change significantly based
on a fundamental error the EPA made in defining which sources were
subject to section 112 emissions standards and which sources were
subject to section 129 emissions standards. NRDC v. EPA, 489 F.3d 1250
(D.C. Cir. 2007). Since the vacatur voided the standards entirely, and
restored the status quo ante, there was arguably no proposal remaining
after the vacatur. In response to the NRDC decision, the EPA undertook
an entirely new rulemaking to replace the vacated standards, including
an extensive data collection effort and, importantly, a new MACT floor
calculation methodology. 76 FR 15608. In that circumstance, it is
reasonable to consider the EPA as having ``first proposed'' an emission
standard applicable to these sources in the replacement rulemaking.\35\
Here, in contrast, the U.S. Sugar court upheld the UPL methodology the
EPA used to set the MACT floor standards in another part of its
opinion.\36\ Where the EPA is undertaking an entirely new process to
establish ``an emission standard'' applicable to a source, it is
reasonable to interpret the definition of ``new source'' as applying
based on the date when the EPA ``first proposes'' that new standard.
However, where the Agency is simply recalculating emissions standards
based on the same data and
[[Page 60831]]
same methodology, it is reasonable to treat the prior standard as EPA's
``first proposal'' of ``an emission standard'' for those sources.
---------------------------------------------------------------------------
\35\ The EPA notes that no commenter raised this issue in the
2011 rulemaking which was issued to replace the vacated 2004
standards, and it was not addressed in the record for the rule.
\36\ As part of its review of standards affected by U.S. Sugar,
the EPA also considered the court's prior decision in NACWA v. EPA,
where the court remanded EPA's UPL methodology for further
explanation based in part of the ``anomalous result'' the court
found based on the UPL calculation for certain new source standards
at a level that was less stringent than the UPL calculation for
existing source standards. The EPA's subsequent explanation of the
UPL methodology was upheld in U.S. Sugar, and it is appropriate for
the Agency to consider standards where that ``anomalous result''
occurred and correct the calculation in those circumstances. For the
new source solid fuel HCl standard, the EPA has done that through
the application of its UPL methodology as applied to small data
sets. The EPA's ``small data sets'' UPL approach was upheld by the
D.C. Circuit in Sierra Club v. EPA, 895 F.3d 1 (2018).
---------------------------------------------------------------------------
One commenter claims that the EPA's proposed revised HCl standard
for new source solid fuel units is significantly more stringent than
the standard vacated by the U.S. Sugar court, and the significant
change in stringency demonstrates that the EPA is using a new
methodology which represents a ``drastic new approach'' that sources
which constructed or reconstructed after the 2010 proposal could not
have foreseen. Contrary to the commenter's assertion, the EPA is not
applying a new methodology to revise the standards in this action.
Rather, the EPA is simply correcting the error the court identified in
how the Agency selected the best performing sources for each
subcategory affected by the decision. It is not collecting any
additional information or undertaking a wholesale revision of the
standards. The fact that one standard became significantly more
stringent does not mean the EPA has revised its methodology--it has
not. Both the previous standard and the new standard were calculated
using the UPL methodology.\37\ Moreover, in its grant of rehearing on
remedy, the court explained that it was remanding rather than vacating
the standards affected by its holding because vacating the standards
would remove important environmental protections while the EPA reissued
the standards. U.S. Sugar Corp. v. EPA, 844 F.3d 268 (2016). It would
be contrary to the court's purpose in revising its remedy to remand,
rather than vacate, the emissions standards for the EPA to use the fact
that its original standards were found to be inconsistent with the Act
as a way to allow sources to meet less stringent standards.
---------------------------------------------------------------------------
\37\ The commenter claims that the solid fuel HCl standard for
new sources was not vacated by the U.S. Sugar court and therefore
EPA is not revising the standard based on that decision, but for
other reasons. However, as noted above, as part of its review of
standards affected by the U.S. Sugar remand on this issue, the EPA
also applied its ``small data sets'' UPL memorandum where
appropriate.
---------------------------------------------------------------------------
Some commenters also pointed to other EPA rulemakings under
sections 112 and 129 and requested that EPA take the approaches in
those actions rather than the proposed approach. The EPA is basing its
decision in this action on the facts and circumstances of this
rulemaking, consistent with relevant provisions of CAA section 112. In
the other actions that the commenters refer to, the circumstances were
different and warranted a different approach. For example, the revision
of EPA's Hospital/Medical/Infectious Waste Incinerator (HMIWI)
standards in 2009 involved the collection of additional emissions
information and a wholesale revision of the standards, unlike this
action.\38\ Further, actions taken to adopt MACT standards in the
context of the EPA's risk and technology reviews under sections
112(d)(6) and (f)(2) also generally involve the calculation of new
standards based on information that was not previously used in MACT
calculations.
---------------------------------------------------------------------------
\38\ The EPA notes that the definition of ``new solid waste
incineration unit'' in section 129(g)(2), which was adopted in the
1990 CAAA, does not contain any reference to EPA's ``first''
proposal of applicable standards.
---------------------------------------------------------------------------
Commenters also express concern that the cost of compliance with
the revised new source HCl standard for solid fuel units could be
significant. One commenter refers to a specific unit constructed in
2016 which the commenter claims will need to add controls in order to
meet the revised new source solid fuel HCl standard. The commenter
claims that this renders the revised standard a ``beyond-the-floor''
MACT standard, and the EPA must therefore consider costs before
adopting the revised standard. The EPA disagrees. The commenter
conflates the two-step MACT standard-setting process in section
112(d)(2) and (d)(3). Under section 112(d)(3), the EPA's MACT standard
can be no less stringent than the average emissions limitation achieved
by the best performing twelve percent of sources in the subcategory,
for existing sources, and the emissions limitation achieved by the best
performing similar source, for new sources. It is well-established
that, in setting these MACT floor standards, the EPA cannot consider
the cost of achieving reductions. National Lime Ass'n. v. EPA, 233 F.3d
625 (D.C. Cir. 2000) (minimum stringency MACT floor requirements apply
without regard to costs). This action addresses the D.C. Circuit's
remand of certain MACT floor standards, and it is those floor standards
that EPA is recalculating in a manner that is consistent with the
court's decision. The fact that one particular recalculated standard
may require sources to incur costs to comply does not transform the
standard into a ``beyond-the-floor'' standard, and to do so would
ignore the statute's clear directive establishing a minimum level of
emissions reductions below which the MACT standard cannot be set,
regardless of cost. Moreover, virtually all sources constructed or
reconstructed after the 2010 proposal are in fact meeting the revised
HCl standard and will therefore not incur any compliance costs.
Finally, contrary to commenters' assertions, the EPA is not
applying a new standard retroactively. Every source affected by these
revised limits has 3 years to come into compliance with the revised
standards following promulgation, regardless of construction date. The
commenter does not explain how the revised standard is a retroactive
standard, except to state that a source that was constructed in 2016
could not have foreseen that the EPA would subsequently revise
standards to make them more stringent. Section 112(a) defines ``new
source'' based on when EPA ``first proposes'' an emissions standard for
a source, and, as explained above, in this particular circumstance it
is reasonable to consider EPA's 2010 proposal as the date when the
Agency ``first proposed'' an emissions standard for these sources. In
addition, the EPA is revising the standards to respond to the D.C.
Circuit's remand in U.S. Sugar, and it was reasonable to assume, once
that remand was issued, that revised standards would in some cases be
more stringent than the remanded standards.
G. Approval for CO2 in Lieu of O2 Monitoring for CO CEMS Compliance
Calculations
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. In the proposed rule, we took
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. We further proposed removing several requirements
for the continuous monitoring of moisture and flow which we found to be
unnecessary.
Commenters supported the proposal to modify the requirement to
obtain the Administrator's approval and allow this change to become
self-implementing. Commenters further agreed with the EPA's proposal to
remove requirements for the continuous monitoring of moisture and flow
which were found to be unnecessary.
We are finalizing these provisions as proposed. Some commenters
requested that we remove the requirements for continuous monitoring of
moisture and flow when CO2 measurements do not require these
values for compliance
[[Page 60832]]
calculations. We believe the revisions accommodate the removal of
moisture and flow when a dry CO2 analyzer is used, obviating
the need to make any additional changes to the rule language.
IV. Results and Final 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, the decisions
to propose certain limits as beyond-the-floor limits, and consideration
of public comments, we are finalizing revisions to 34 different
emission limits. The detailed list of revisions to unit rankings and
revised MACT floor calculations are presented in the docketed
memorandums, Revised MACT Floor Analysis (2019) for the Industrial,
Commercial, and Institutional Boilers and Process Heaters National
Emission Standards for Hazardous Air Pollutants--Major Source and
Revised MACT Floor Analysis (2021) 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 limits are modestly less
stringent, with no more than a 25-percent change from the corresponding
limit in the 2013 final rule. The final limits are shown in Table 4,
along with corresponding limits from the 2013 final rule.
Table 4--Summary of Changes to Emission Limits in the Final Action
----------------------------------------------------------------------------------------------------------------
2013 final rule
emission limit Revised emission
(lb/MMBtu of heat limit (lb/MMBtu
Subcategory Pollutant input or ppm at 3- of heat input or
percent oxygen ppm at 3-percent
for CO) oxygen for CO)
----------------------------------------------------------------------------------------------------------------
New--Solid................................................ HCl 2.2E-02 2.1E-04
New--Dry Biomass Stoker................................... TSM 4.0E-03 5.0E-03
New--Biomass Fluidized Bed................................ CO 230 130
New--Biomass Fluidized Bed................................ PM 9.8E-03 4.1E-03
(TSM) (8.3E-05) (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 1.5E-04
New--Heavy Liquid......................................... PM 1.3E-02 1.9E-03
(TSM) (7.5E-05) (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 3.7E-02 3.4E-02
(TSM) (2.4E-04) (2.0E-04)
Existing--Biomass Fluidized Bed........................... CO 470 210
Existing--Biomass Fluidized Bed........................... PM 1.1E-01 7.4E-03
(TSM) (1.2E-03) (6.4E-05)
Existing--Biomass Suspension Burners...................... PM 5.1E-02 4.1E-02
(TSM) (6.5E-03) (8.0E-03)
Existing--Biomass Dutch Oven/Pile Burner.................. PM 2.8E-01 1.8E-01
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
----------------------------------------------------------------------------------------------------------------
B. What compliance dates are we finalizing?
We are finalizing that facilities have up to 3 years after the
effective date of the final rule to comply with the revised emissions
limits in this 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 revised
emission limits and to update reports to incorporate the revised
emission limits.
C. What other actions are we finalizing?
We proposed a number of technical corrections to correct
inadvertent errors that were promulgated in the 2013 and 2015 final
rules. Public commenters also noted several additional technical
corrections to correct additional errors in the final rule. In
addition, we are removing the references to the date of
[[Page 60833]]
future final performance specifications for HCl CEMS because PS 18, the
Performance Specifications for Gaseous Hydrogen Chloride, and Procedure
6, the Quality Assurance Requirements for Gaseous Hydrogen Chloride
(HCl) Continuous Emission Monitoring Systems Used for Compliance
Determination at Stationary Sources, were promulgated on July 7, 2017
at 80 FR 38628. The technical corrections we are finalizing are
summarized in Table 5.
Table 5--Finalized Technical Corrections to 40 CFR Part 63, Subpart
DDDDD
------------------------------------------------------------------------
Section of subpart DDDDD Description of 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 63.7525(l) and 40 CFR Remove the references to a date of a
63.7540(a)(15). final performance specification for
HCl CEMS.
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........................... 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.
Remove footnote ``a'' from item 12b
for the TSM limit for fuel cell
units designed to burn biomass/bio-
based solids.
Add footnote ``a'' to item 1a for
the solid fuel HCl limit, item 14a
for the liquid fuel HCl limit, and
item 15b for the light liquid fuel
TSM limit.
Table 2........................... Removed footnote ``a'' for item 14b
for the liquid fuel mercury
emission limit and 16b for light
liquid PM emission limit.
Table 7........................... 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........................... Revise item 8.d to clarify that the
correct equations to use are
Equations 15 and Equations 16, 17,
and/or 18 in 40 CFR 63.7530.
Table 14.......................... Remove footnote ``a'' from item 12b
for the TSM limit for fuel cell
units designed to burn biomass/bio-
based solids.
Add footnote ``a'' to item 15b for
the light liquid fuel TSM limit.
Table 15.......................... Removed footnote ``a'' for item 14b
for the liquid fuel mercury
emission limit and 16b for light
liquid PM emission limit.
------------------------------------------------------------------------
V. Summary of Cost, Environmental, and Economic Impacts
A. What are the affected sources?
According to CEDRI data through December 31, 2020, there are 577
boilers and process heaters, of which 485 remain operational and belong
in one of the subcategories that are subject to numeric emission
limits.\39\ 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. Of these units, we estimate that 54 units (individual boilers or
process heaters) will incur cost or emissions impacts due to these
final amendments. In addition, the EPA estimates that an additional six
biomass boilers or process heaters will be constructed and subject to
the revised emission limits over the next 8 years.
---------------------------------------------------------------------------
\39\ EPA notes that it considered compliance information from
CEDRI for the purpose of evaluating costs and impacts of this
action, in order to ensure that the actual costs of compliance are
accurately reflected. For the reasons explained elsewhere, the
Agency did not consider emissions data in CEDRI to recalculate the
MACT floor standards affected by the D.C. Circuit remand in U.S.
Sugar. 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.
---------------------------------------------------------------------------
B. What are the air quality impacts?
Table 6 of this preamble shows the incremental emissions reductions
that we estimate these final amendments will achieve. The reductions
are incremental to the reductions accounted for in the 2013 final rule.
Nationwide emissions of selected HAP (i.e., HCl, hydrogen fluoride, Hg,
and metals) would be reduced by an additional 117 tpy as compared to
the estimates in the 2013 final rule. This increase is due mainly to
changes to certain emission limits that are anticipated to achieve
additional reductions. We estimate the final amendments will result in
an additional 110 tpy of reductions in HCl emissions. We estimate that
the final amendments will have a modest effect on Hg, with an estimated
additional reduction of 7.5 lbs per year. Emissions of filterable PM
are estimated to decrease by 586 tpy, of which 446 tpy is
PM2.5, due to this final action. Emissions of non-Hg metals
(i.e., arsenic, beryllium, cadmium, chromium, lead, manganese, nickel,
and selenium) are estimated to decrease by 4.1 tpy. Estimates of
reductions in antimony and cobalt were not quantified and are expected
to be small. In addition, the final amendments are estimated to result
in 1,141 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
(2021) 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.
[[Page 60834]]
Table 6--Summary of Total Emissions Reductions for the Final Rule
[Tons per year]
----------------------------------------------------------------------------------------------------------------
Non-Hg metals
Source Subcategory HCl PM \1\ Hg
----------------------------------------------------------------------------------------------------------------
Exiting Units................. Coal............ 44.1 54.4 0.12 2.12E-03
Biomass......... 13.6 521 3.8 1.65E-03
New Units..................... Biomass......... 52.3 9.9 0.14 0
----------------------------------------------------------------------------------------------------------------
\1\ Arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium.
C. What are the cost impacts?
We estimated the total capital costs of the final amendments to be
about $201 million and the total annualized costs to be about $49.6
million in 2016 dollars. The total capital and annual costs include
costs for control devices, testing, and monitoring associated with the
changes to the emission limits. These costs are incremental to the
costs presented in the 2013 final rule in the sense that they show
where units with compliance data must install add-on controls or modify
compliance strategies in order to meet the more stringent limits in
this final action. Table 7 shows the total capital and annual cost
impacts of the final rule for each subcategory. The cost methodology
and results are documented in the memorandum, Revised (2021)
Methodology for Estimating Impacts for Industrial, Commercial,
Institutional Boilers and Process Heaters National Emission Standards
for Hazardous Air Pollutants, which is available in the docket for this
action.
Table 7--Summary of Total Capital and Annual Costs for Affected New and Existing Sources for the Final Rule
----------------------------------------------------------------------------------------------------------------
Testing and
Estimated monitoring
number of Capital costs annualized Annualized
Source Subcategory affected units (millions costs cost (millions
incurring a 2016$) (millions 2016$/yr)
cost 2016$/yr)
----------------------------------------------------------------------------------------------------------------
Existing Units................ Coal............ 5 8.0 0.057 2.1
Biomass......... 33 149.5 0.511 35.1
New Units..................... Biomass......... 11 43.3 0.043 12.3
----------------------------------------------------------------------------------------------------------------
Another way to present compliance costs is the present value (PV).
A PV is an estimate of costs that is a discounted stream of the
annualized costs for the final action calculated for the present day.
The PV in 2016 of the costs is $265 million at a discount rate of 7
percent and $315 million at a discount rate of 3 percent. Calculated as
an EAV, which is consistent with the PV of costs in 2016, the costs are
$44 million at a discount rate of 7 percent and $45 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 final action which is available in the docket.
D. What are the secondary impacts?
The EPA estimated the additional water usage that would result from
installing wet scrubbers to meet the amended emission limits for HCl
would be 0.75 million gallons per year for new and existing sources
compared to the 2013 baseline. In addition to the increased water
usage, an additional 0.29 million gallons per year of wastewater will
be produced for new and existing sources. The annual costs of treating
the additional wastewater are approximately $1,920. These additional
costs are accounted for in the control cost estimates.
The EPA estimated the additional solid waste that would result due
to the final amendments to be 1,540 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 approximately
$73,900. These costs are also accounted for in the control costs
estimates.
The EPA estimated the final amendments would result in an increase
of about 74.4 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 revised emission limits. This energy requirement is
estimated to result in an increase of approximately 32,910 tpy
CO2 based on emissions related to additional energy
consumption.
A discussion of the methodology used to estimate impacts is
presented in the Revised (2021) 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 final rule,
as detailed in the Regulatory Impact Analysis for the ICI Boilers
NESHAP Final Amendments, which is available in the docket for this
action. The economic impacts 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. Of 30 parent owners
affected by this final rule, two of them will incur total annualized
costs of 1 percent or greater of their revenues. The median total
annualized cost of sales for affected parent owners is less than 0.01
percent. While two parent owners may experience substantial economic
impacts as a result of complying with
[[Page 60835]]
this final rule, neither one is a small business according to Small
Business Administration (SBA) guidelines. Overall, based on these
estimated impacts, we can conclude that the economic impacts are
relatively low for the affected entities and the multiple affected
industries, and consumers of affected output should experience
relatively low price changes.
F. What are the benefits?
There are no monetized benefits from the HAP emissions reductions
directly regulated under this action due to lack of necessary input
data. However, the EPA reports the estimated impact on health benefits
from changes in PM2.5 and SO2 emissions that
occur as a result of this final rule. The estimated health benefits are
the monetized value of the human health benefits among populations
exposed to changes in PM2.5. 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 \40\ in which the
economic value of human health impacts is derived at the national level
based on previously established source-receptor relationships from
photochemical air quality modeling.\41\ These BPT estimates provide the
total monetized human health benefits (the sum of PM-attributable
premature deaths and premature morbidity) of reducing 1 ton of
PM2.5 (or PM2.5 precursor such as SO2)
from a specified source. Since proposal of this rule, the EPA has
updated its BPT estimates to include state level estimates specifically
for the Industrial Boiler sector. The method used to derive these
estimates is described in the Technical Support Document on Estimating
the Benefit per Ton of Reducing Directly-Emitted PM2.5, PM2.5
Precursors and Ozone Precursors from 21 Sectors and its precursors from
21 sectors.\42\ 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, or nitrogen dioxide. 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.
---------------------------------------------------------------------------
\40\ 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.
\41\ 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.
\42\ U.S. EPA. 2021. Technical Support Document (BPT TSD) on
Estimating the Benefit per Ton of Reducing Directly-Emitted
PM2.5, PM2.5 Precursors and Ozone Precursors
from 21 Sectors and its precursors from 21 sectors. Technical
Support Document. Available at: https://www.epa.gov/benmap/reduced-form-tools-calculating-pm25-benefits.
---------------------------------------------------------------------------
Specifically, all national-average BPT estimates reflect the
geographic distribution of the modeled emissions, which may not exactly
match the emission reductions that would occur due to 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 new BPT estimates developed for
the Industrial Boiler sector in 2021 developed state-level estimates
that addressed some of the limitations of the national analysis. Given
the use of state level, sector specific air quality modeling and the
small changes in emissions considered in this rulemaking, the
difference in the quantified health benefits that result from the BPT
approach compared with those obtained using a full-form air quality
model should be minimal.
Table 8 summarizes the monetized PM related health benefits per ton
in the states where units with emission reductions are located, using
discount rates of 3 percent and 7 percent. Table 9 summarizes the
monetized SO2-related health benefits per ton of reducing
precursor pollutant emissions in the states where units with emission
reductions are located, using discount rates of 3 and 7 percent.
Table 8--Estimated PM2.5-Related Benefits per Ton of Final Rule
----------------------------------------------------------------------------------------------------------------
Benefit per Benefit per Benefit per Benefit per
State ton low (3% ton low (7% ton high (3% ton high (7%
discount rate) discount rate) discount rate) discount rate)
----------------------------------------------------------------------------------------------------------------
CA.............................................. $503,000 $452,000 $510,000 $459,000
FL.............................................. 140,000 126,000 141,000 127,000
GA.............................................. 151,000 136,000 156,000 141,000
LA.............................................. 117,000 105,000 123,000 110,000
ME.............................................. 48,200 43,400 50,500 45,500
MI.............................................. 259,000 233,000 262,000 236,000
NC.............................................. 171,000 154,000 173,000 156,000
OK.............................................. 103,000 92,600 106,000 95,8000
TN.............................................. 227,000 204,000 235,000 212,000
WI.............................................. 148,000 133,000 156,000 140,000
----------------------------------------------------------------------------------------------------------------
Table 9--Estimated SO2-Related Benefits per Ton of Final Rule
----------------------------------------------------------------------------------------------------------------
Benefit per Benefit per Benefit per Benefit per
State ton low (3% ton low (7% ton high (3% ton high (7%
discount rate) discount rate) discount rate) discount rate)
----------------------------------------------------------------------------------------------------------------
AL.............................................. $50,600 $45,500 $52,100 $46,900
AR.............................................. 42,300 38,100 43,000 38,700
FL.............................................. 45,600 41,000 46,400 41,800
IL.............................................. 54,800 49,300 55,300 51,300
MI.............................................. 56,000 50,300 57,000 49,800
[[Page 60836]]
NC.............................................. 45,300 40,700 45,600 41,000
TX.............................................. 14,900 13,400 15,100 13,600
VA.............................................. 53,400 48,100 54,100 48,700
WA.............................................. 20,300 18,300 20,800 18,700
----------------------------------------------------------------------------------------------------------------
Table 10--Annual Emissions Reductions of PM2.5 and SO2 by State
------------------------------------------------------------------------
Emission reductions (tons)
State -------------------------------
PM2.5 SO2
------------------------------------------------------------------------
AL...................................... .............. 26
AR...................................... .............. <0.1
CA...................................... 33 ..............
FL...................................... 17 557
GA...................................... 10 ..............
IL...................................... .............. 306
LA...................................... 27 ..............
ME...................................... 5 ..............
MI...................................... 4 41
NC...................................... 2 179
OK...................................... 257 ..............
TN...................................... 40 ..............
TX...................................... .............. 1
VA...................................... .............. 31
WA...................................... .............. 2
WI...................................... 51 ..............
------------------------------------------------------------------------
Table 10 above provides the annual emissions reductions of
PM2.5 and SO2 by state. Table 11 summarizes the
range of estimated benefits of these annual emission reductions by
pollutant for the two benefit per ton estimates at discount rates of 3
percent and 7 percent.
Table 11--Estimated PM2.5 and SO2-Related Annual Health Benefits of Final Rule
[Millions of 2016$]
----------------------------------------------------------------------------------------------------------------
Benefits low Benefits low Benefits high Benefits high
Pollutant (3% discount (7% discount (3% discount (7% discount
rate) rate) rate) rate)
----------------------------------------------------------------------------------------------------------------
PM2.5........................................... $68 $62 $68 $62
SO2............................................. 55 50 56 51
---------------------------------------------------------------
Total....................................... 123 112 124 113
----------------------------------------------------------------------------------------------------------------
There are also climate disbenefits from the increase in
CO2 emissions that result from the increase in national
energy use from control device operation. We estimate the social
disbenefits of CO2 emission increases expected from this
final rule using the SC-CO2 estimates presented in the
Technical Support Document: Social Cost of Carbon, Methane, and Nitrous
Oxide Interim Estimates under Executive Order 13990.\43\ We have
evaluated the SC-CO2 estimates in the February 2021 TSD and
have determined that these estimates are appropriate for use in
estimating the social value of CO2 emission changes expected
from this final rule as part of fulfilling analytical guidance with
respect to E.O. 12866. These SC-CO2 estimates are interim
values developed for use in benefit-cost analyses until an improved
estimate of the impacts of climate change can be developed based on the
best available science and economics.
---------------------------------------------------------------------------
\43\ Interagency Working Group on Social Cost of Greenhouse
Gases (IWG). 2021. Technical Support Document: Social Cost of
Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive
Order 13990. February. United States Government. Available at:
https://www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-of-the-benefits-of-reducing-climate-pollution/.
---------------------------------------------------------------------------
Table 12 shows the estimated monetary value of the estimated
changes in CO2 emissions expected to occur for the final
rule. For 2022-2024, no changes in CO2 emissions occur since
the control technologies included in the cost analysis mentioned in the
Cost Methodology memo for the final rule are not expected to begin
operation until 3 years after the effective date of the final rule, or
2025. Hence, there are no climate disbenefits for these 3 years. In
2025, the EPA estimated the dollar value of the CO2-related
effects by applying the SC-CO2 estimates, included in the
RIA's benefits chapter, to the estimated changes in CO2
[[Page 60837]]
emissions in the corresponding year under the final rule.\44\ The EPA
calculated the present value and annualized benefits from the
perspective of 2020 by discounting each year-specific value to the year
2020 using the same discount rate used to calculate the SC-
CO2.\45\
---------------------------------------------------------------------------
\44\ CO2 emissions increases above the baseline as a
result of the modeled policy are first expected in 2025, as control
technologies applied in response to the final rule first begin
operation in that year, and those emissions increase remain at that
level afterwards, according to the cost analysis for this rule.
\45\ According to OMB's Circular A-4, an ``analysis should focus
on benefits and costs that accrue to citizens and residents of the
United States'', and international effects should be reported
separately. Circular A-4 also reminds analysts that ``[d]ifferent
regulations may call for different emphases in the analysis,
depending on the nature and complexity of the regulatory issues.''
To correctly assess the total climate damages to U.S. citizens and
residents, an analysis must account for all the ways climate impacts
affect the welfare of U.S. citizens and residents, how U.S. GHG
mitigation activities affect mitigation activities by other
countries, and spillover effects from climate action elsewhere. The
SC-CO2 estimates used in regulatory analysis under
revoked E.O. 13783, including in the RIA for the proposed rule, were
an approximation of some of the U.S.-specific climate damages from
GHG emissions (e.g., $7/mtCO2 (2016 dollars) using a 3%
discount rate for emissions occurring in 2025). Applying the same
estimate (based on a 3% discount rate) to the CO2
emissions expected under the final rule would yield disbenefits from
climate impacts of $0.2 million (2016 dollars) in 2025. However, as
discussed at length in the February 2021 TSD, these estimates are an
underestimate of the damages of CO2 emissions accruing to
U.S. citizens and residents, as well as being subject to a
considerable degree of uncertainty due to the manner in which they
are derived. In particular, the estimates developed under revoked
E.O. 13783 did not capture significant regional interactions,
spillovers, and other effects and so are incomplete underestimates.
As the U.S. Government Accountability Office (GAO) concluded in a
June 2020 report examining the SC-GHG estimates developed under E.O.
13783, the models ``were not premised or calibrated to provide
estimates of the social cost of carbon based on domestic damages''.
U.S. Government Accountability Office (GAO). 2020. Social Cost of
Carbon: Identifying a Federal Entity to Address the National
Academies' Recommendations Could Strengthen Regulatory Analysis.
GAO-20-254. Further, the report noted that the National Academies
found that country-specific social costs of carbon estimates were
``limited by existing methodologies, which focus primarily on global
estimates and do not model all relevant interactions among
regions''. It is also important to note that the SC-GHG estimates
developed under E.O. 13783 were never peer reviewed, and when their
use in a specific regulatory action was challenged, the U.S.
District Court for the Northern District of California determined
that use of those values had been ``soundly rejected by economists
as improper and unsupported by science,'' and that the values
themselves omitted key damages to U.S. citizens and residents
including to supply chains, U.S. assets and companies, and
geopolitical security. The Court found that by omitting such
impacts, those estimates ``fail[ed] to consider . . . important
aspect[s] of the problem'' and departed from the ``best science
available'' as reflected in the global estimates. California v.
Bernhardt, 472 F. Supp. 3d 573, 613-14 (N.D. Cal. 2020). The EPA
continues to center attention in this regulatory analysis on the
global measures of the SC-GHG as the appropriate estimates and as
necessary for all countries to use to achieve an efficient
allocation of resources for emissions reduction on a global basis,
and so benefit the U.S. and its citizens.
Table 12--Estimated Climate Disbenefits From Changes in CO2 Emissions for 2025
[Millions of 2016$] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Discount rate and statistic
---------------------------------------------------------------------------------------------------------------------------------------------------------
3% 95th
Year 5% average 3% average 2.5% average percentile
--------------------------------------------------------------------------------------------------------------------------------------------------------
Final Rule......................................................... 2025 0.5 1.7 2.5 5.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Climate disbenefits are based on changes (reductions) in CO2 emissions and are calculated using four different estimates of the social cost of
carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). We emphasize the
importance and value of considering the disbenefits calculated using all four SC-CO2 estimates. As discussed in the Technical Support Document: Social
Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990, a consideration of climate benefits calculated using
discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting intergenerational impacts.
The climate disbenefits associated with the additional 32,910 short
tons (or 29,855 metric tons) per year of CO2 emissions
generated as a result of the requirements of this final rule are
therefore $1.7 million at a 3 percent discount rate, and range from
$0.5 million at a 2.5 percent discount rate to $5.2 million at a 3
percent discount rate (95th percentile), all in 2016 dollars.\46\ These
disbenefits are estimated for 2025, the year of full implementation of
this final rule (3 years after the effective date) using the interim
social cost of carbon (SC-CO2) for 2025 as shown in Table 12
to be consistent with the year for the PM2.5 and
SO2 BPTs applied to generate those monetized benefits
presented earlier in section V.F.\47\
---------------------------------------------------------------------------
\46\ In order to calculate these values, it is necessary to
convert tons (short) of emissions to metric tons. These values may
be converted to $/short ton using the conversion factor 0.90718474
metric tons per short ton for application to the short ton
CO2 emissions impacts provided in this rulemaking. Hence,
32,910 short tons of emissions become 29,855 metric tons (tonnes) of
emissions.
\47\ These SC-CO2 values are stated in $/metric ton
CO2 and rounded to the nearest dollar. Such a conversion
does not change the underlying methodology, nor does it change the
meaning of the SC-CO2 estimates. For both metric and
short tons denominated SC-CO2 estimates, the estimates
vary depending on the year of CO2 emissions and are
defined in real terms, i.e., adjusted for inflation using the Gross
Domestic Product (GDP) implicit price deflator.
---------------------------------------------------------------------------
These disbenefits are included in the estimates of benefits and net
benefits for this final rule. The benefit analysis for this final rule,
which includes PV and EAV estimates for the benefits and net benefits,
is detailed in the Regulatory Impact Analysis for the ICI Boilers and
Process Heaters NESHAP Final Amendments, which is available in the
docket for this action.
G. What analysis of environmental justice did we conduct?
Executive Order 12898 directs the EPA to identify the populations
of concern who are most likely to experience unequal burdens from
environmental harms; specifically, minority populations, low-income
populations, and indigenous peoples (59 FR 7629, February 16, 1994).
Additionally, Executive Order 13985 was signed to advance racial equity
and support underserved communities through Federal government actions
(86 FR 7009, January 20, 2021). The EPA defines environmental justice
(EJ) as the fair treatment and meaningful involvement of all people
regardless of race, color, national origin, or income with respect to
the development, implementation, and enforcement of environmental laws,
regulations, and policies. The EPA further defines the term fair
treatment to mean that ``no group of people should bear a
disproportionate burden of environmental harms and risks, including
those resulting from the negative environmental consequences of
industrial, governmental, and commercial operations or programs and
policies'' (https://www.epa.gov/environmentaljustice). In recognizing
that minority and low-income
[[Page 60838]]
populations often bear an unequal burden of environmental harms and
risks, the EPA continues to consider ways of protecting them from
adverse public health and environmental effects of air pollution.
To examine the potential for any EJ issues that might be associated
with the source category, we performed a demographic analysis, which is
an assessment of individual demographic groups of the populations
living within 5 kilometers (km) and within 50 km of facilities with
affected sources.\48\ The EPA then compared the data from this analysis
to the national average for each of the demographic groups.
---------------------------------------------------------------------------
\48\ Note that many facilities have more than one affected
boiler or process heater.
---------------------------------------------------------------------------
The results of the demographic analysis indicate that, for
populations within 5 km of the facilities in the source category, the
percent minority population (being the total population minus the white
population) is smaller than the national average (36 percent versus 40
percent). Within minorities, the percent of the population that is
African American, Other and Multiracial, and Native American are
similar to the national averages. The percent of the population that is
Hispanic or Latino is below the national average (14 percent versus 19
percent). The percent of people living below the poverty level was
higher than the national average (18 percent versus 13 percent). The
percent of people living in linguistic isolation was less than the
national average. The results of the analysis of populations within 50
km of the facilities in the source category were similar to the 5 km
analysis, with the exception of the percent of the population living
below the poverty level and the percent of the population over 25
without a high school diploma, which were closer to the national
averages.
The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income,
or indigenous populations, as specified in Executive Order 12898 (59 FR
7629, February 16, 1994). Nationwide emissions of selected HAP (i.e.,
HCl, hydrogen fluoride, Hg, and metals) would be reduced by an
additional 117 tpy as compared to the estimates in the 2013 final rule.
We estimate the final amendments will result in an additional 110 tpy
of reductions in HCl emissions, and 7.5 lbs per year of Hg. Emissions
of filterable PM are estimated to decrease by 586 tpy, of which 446 tpy
is PM2.5. Emissions of non-Hg metals (i.e., arsenic,
beryllium, cadmium, chromium, lead, manganese, nickel, and selenium)
are estimated to decrease by 4.1 tpy. In addition, the final amendments
are estimated to result in 1,141 tpy of reductions in SO2
emissions. A breakdown of emissions reductions by facility is presented
in Appendix C of the memorandum, Revised (2021) 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. This
final rule increases the level of environmental protection for all
affected populations, without having any disproportionately high and
adverse human health or environmental effects on any population,
including any minority, low-income, or indigenous populations.
A summary of the proximity demographic assessment performed for
Industrial, Commercial, and Institutional Boilers and Process Heaters
facilities is included as Table 13. The methodology and the results of
the demographic analysis are presented in a technical report, Analysis
of Demographic Factors for Populations Living Near Industrial,
Commercial, and Institutional Boilers and Process Heaters, available in
this docket for this action (Docket ID EPA-HQ-OAR-2002-0058).
Table 13--Proximity Demographic Assessment Results
----------------------------------------------------------------------------------------------------------------
Population
within 50 km Population
Demographic group Nationwide of 40 within 5 km of
facilities 40 facilities
----------------------------------------------------------------------------------------------------------------
Total Population................................................ 328,016,242 14,889,295 635,825
-----------------------------------------------
White and Minority by Percent
-----------------------------------------------
White........................................................... 60% 65% 64%
Minority........................................................ 40% 35% 36%
-----------------------------------------------
Minority by Percent
-----------------------------------------------
African American................................................ 12% 14% 13%
Native American................................................. 0.7% 0.5% 0.8%
Hispanic or Latino (includes white and nonwhite)................ 19% 13% 14%
Other and Multiracial........................................... 8% 7% 8%
-----------------------------------------------
Income by Percent
-----------------------------------------------
Below Poverty Level............................................. 13% 14% 18%
Above Poverty Level............................................. 87% 86% 82%
-----------------------------------------------
Education by Percent
-----------------------------------------------
Over 25 and without a High School Diploma....................... 12% 12% 14%
Over 25 and with a High School Diploma.......................... 88% 88% 86%
-----------------------------------------------
Linguistically Isolated by Percent
-----------------------------------------------
[[Page 60839]]
Linguistically Isolated......................................... 5% 3% 4%
----------------------------------------------------------------------------------------------------------------
Notes:
The nationwide population count and all demographic percentages are based on the Census' 2015-2019
American Community Survey five-year block group averages and include Puerto Rico. Demographic percentages
based on different averages may differ. The total population counts within 5 km and 50 km of all facilities
are based on the 2010 Decennial Census block populations.
Minority population is the total population minus the white population.
To avoid double counting, the ``Hispanic or Latino'' category is treated as a distinct demographic
category for these analyses. A person is identified as one of five racial/ethnic categories above: White,
African American, Native American, Other and Multiracial, or Hispanic/Latino. A person who identifies as
Hispanic or Latino is counted as Hispanic/Latino for this analysis, regardless of what race this person may
have also identified as in the Census.
VI. 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 contains
the estimated costs, benefits, and other impacts associated with this
action, and it is available in the docket.
B. Paperwork Reduction Act (PRA)
The new information collection activities in this 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 2028.12. OMB Control Number 2060-0551. You can find a copy of
the ICR in the docket for this rule, and it is briefly summarized here.
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 final amendments changed 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 resulted 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 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 34 respondents operating
existing large solid fuel-fired boilers and 5 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 recordkeeping and reporting burden
changing records associated with adjusting operating parameter limit
values, modifying monitoring plans, and familiarizing themselves with
the changes in the final 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: 39.
Frequency of response: Semi-annual, annual, periodic.
Total estimated burden: 1,553 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $1,130,000 (per year), includes $949,000
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.
C. 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. Of the
30 entities (ultimate parent entities, all but two being in the private
sector) determined to be impacted by this action, two are small
entities. Of these two small entities, none is expected to incur any
costs as a result of compliance with this action. More information on
these small entity impacts is available in the RIA.
D. Unfunded Mandates Reform Act (UMRA)
This action contains a Federal mandate under UMRA, 2 U.S.C. 1531-
1538, that may result in expenditures of $100 million or more for
state, local, and tribal governments, in the aggregate, or the private
sector in any one year. Accordingly, the EPA has prepared a written
statement required under section 202 of UMRA. The statement is included
in the RIA for this final rule that is in the docket for this action.
This action is not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications as specified in
Executive
[[Page 60840]]
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.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to Executive Order 13045 because the EPA
does not believe the environmental health risks or safety risks
addressed by this action present a disproportionate risk to children.
This action's health and risk assessments are contained in the RIA.
H. 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
action 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 final rule is not likely to have a significant adverse effect
on the supply, distribution, or use of energy.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This action does not involve any new technical standards from those
contained in the March 21, 2011, final rule. Therefore, the EPA did not
consider the use of any voluntary consensus standards. See 76 FR 15660-
15662 for the NTTAA discussion in the March 21, 2011, final rule. The
EPA is, however, formalizing the incorporation of one technical
standard that was already incorporated in 40 CFR 63.14 as well as in
several existing tables in 40 CFR part 63, subpart DDDDD. This standard
is ASTM D6784-02 (Reapproved 2008), Standard Test Method for Elemental,
Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from
Coal-Fired Stationary Sources (Ontario Hydro Method). This method,
which describes the measurement of particle-bound, oxidized, elemental,
and total mercury in stationary-source flue gases provides data that
can be used for emissions assessments and reporting as well as the
certification of continuous mercury monitoring systems. It describes
equipment and procedures for obtaining samples of mercury from effluent
ducts and stacks, for laboratory analysis, and for calculating results.
It is applicable for sampling elemental, oxidized, and particle-bound
mercury in flue gases of coal-fired stationary sources. It may not be
suitable at all measurement locations, particularly those with high
particulate loadings. Method applicability is limited to flue gas
stream temperatures within the thermal stability range of the sampling
probe and filter components. The standard is available to the public
for free viewing online in the Reading Room section on ASTM's website
at https://www.astm.org/READINGLIBRARY/. Hardcopies and printable
versions are also available for purchase from ASTM. Additional
information can be found at https://www.astm.org/products-services/standards-and-publications.html.
J. 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 a technical report,
Analysis of Demographic Factors for Populations Living Near Industrial,
Commercial, and Institutional Boilers and Process Heaters, available in
this docket for this action (Docket ID EPA-HQ-OAR-2002-0058).
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by U.S.C.
804(2).
List of Subjects in 40 CFR Part 63
Environmental protection, Air pollution control, Hazardous
substances, Incorporation by reference, Reporting and recordkeeping
requirements.
Michael S. Regan,
Administrator.
For the reasons stated in the preamble, 40 CFR part 63 is 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 A--General Provisions
0
2. Section 63.14 is amended by revising paragraph (h)(103) to read as
follows:
Sec. 63.14 Incorporations by reference.
* * * * *
(h) * * *
(103) ASTM D6784-02 (Reapproved 2008), Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
Approved April 1, 2008; IBR approved for Sec. Sec. 63.2465(d);
63.11646(a); and 63.11647(a) and (d); and tables 1, 2, 5, 11, 12t, 13,
14, and 15 to subpart DDDDD; tables 4 and 5 to subpart JJJJJ; tables 4
and 6 to subpart KKKKK; table 5 to subpart UUUUU; appendix A to subpart
UUUUU; and table 4 to subpart JJJJJJ.
* * * * *
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Major Sources: Industrial, Commercial, and
Institutional Boilers and Process Heaters
0
3. Section 63.7500 is amended by revising paragraphs (a) introductory
text, (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
Table 1 or 2 to this subpart are an alternative applicable only to
boilers and process heaters that generate either steam, cogenerate
steam with electricity,
[[Page 60841]]
or both. The output-based emission limits, in units of pounds per
megawatt-hour, in Table 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 1 of Sec. 63.7575 to demonstrate compliance with
the output-based emission limits, in units of pounds per million Btu of
steam output, in Table 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 (iv) of this
section, but on or after October 6, 2025, 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 paragraph (a)(1)(v) of this section, but on or
after October 6, 2025 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 must comply
with either the emission limits in Table 1 to this subpart or the
emission limits in Table 14 to this subpart until you must comply with
the emission limits in Table 1.
(v) If you operate an existing boiler or process heater, you must
comply with either the emission limits in Table 2 to this subpart or
the emission limits in Table 15 to this subpart until you must comply
with the emission limits in Table 2.
* * * * *
(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 Tables 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
Tables 11 through 15 to this subpart, or the operating limits in Table
4 to this subpart.
* * * * *
0
4. 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 Table 1 or 2 or Tables 11 through
15 to this subpart.
* * * * *
0
5. Section 63.7510 is amended by revising paragraphs (a) introductory
text, (b), (c), (f), and (j) to read as follows:
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 Table 1 or 2 or Tables 11 through 15 to 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 Table 1 or 2 or
Tables 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 paragraphs (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 Table 1 or 2 or Tables 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 than the
applicable
[[Page 60842]]
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 than the applicable
emission limit in Table 1 to this subpart, you must demonstrate
compliance with the applicable emission limit in Table 1 no later than
October 6, 2025.
* * * * *
(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 Table 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
6. 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).
* * * * *
(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 Table 1 or 2 or Tables 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 Table 1 or 2 or Tables 11 through 15 to this
subpart, 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 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) to demonstrate
compliance with the applicable alternative CO CEMS emission standard
listed in Table 1 or 2 or Tables 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
7. 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
8. 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.
[[Page 60843]]
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
9. Section 63.7522 is amended by revising paragraphs (b) introductory
text, (d), (e)(1), (e)(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 paragraphs (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 to this paragraph (e)(1)
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] TR06OC22.000
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] TR06OC22.001
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 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] TR06OC22.002
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
[[Page 60844]]
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 to this paragraph (e)(2) as an alternative to using Equation
1a of paragraph (e)(1) 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] TR06OC22.003
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 to this
paragraph (j)(1).
[GRAPHIC] [TIFF OMITTED] TR06OC22.004
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
10. Section 63.7525 is amended by revising paragraphs (a) introductory
text, (a)(1), (a)(2) introductory text, (a)(2)(ii), (iv), and (vi), (l)
introductory text, 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 Table 1 or 2 or Tables 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 (O2) (or
carbon dioxide (CO2)) according to the procedures in
paragraphs (a)(1) through (6) of this section.
(1) Install the CO CEMS including an O2 (or
CO2) analyzer by the compliance date specified in Sec.
63.7495. The CO and O2 (or CO2) levels shall be
monitored at the same location at the outlet of the boiler or process
heater. An owner or operator may determine compliance with the CO
emissions limit using a CO2 analyzer as the diluent monitor.
If a CO2 analyzer is used as the diluent monitor, EPA Method
19 F-factors in 40 CFR part 60, appendix A-7, for the fuel type(s)
being burned in the unit and EPA Method 19 equations in 40 CFR part 60,
appendix A-7, must be used to calculate the emissions corrected to 3
percent O2 using the measured CO2 percentage, and
must also take into account that the 3 percent oxygen correction is to
be done on a dry basis. The equations used to calculate the emissions,
must also account for any CO2 being added to, or removed
from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. The methodology used to calculate the CO emissions
and the methodology used to account for any CO2 being added
to, or removed from the emissions gas stream shall be detailed and
approved in the site-specific monitoring plan developed according to
Sec. 63.7505(d).
(2) To demonstrate compliance with the applicable alternative CO
CEMS emission standard listed in Table 1 or 2 or Tables 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 this
paragraph (a). 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 this
paragraph (a) must use the CO CEMS to comply with the applicable
alternative CO CEMS
[[Page 60845]]
emission standard listed in Table 1 or 2 or Tables 11 through 15 to
this subpart.
* * * * *
(ii) During each relative accuracy test run of the CO CEMS, you
must collect emission data for CO concurrently using both the CO CEMS
and Method 10, 10A, or 10B at 40 CFR part 60, appendix A-4. The
relative accuracy testing must be conducted at representative operating
conditions.
* * * * *
(iv) Any CO CEMS that does not comply with this paragraph (a)
cannot be used to meet any requirement in this subpart to demonstrate
compliance with a CO emission limit listed in Table 1 or 2 or Tables 11
through 15 to this subpart.
* * * * *
(vi) When CO2 is used to correct CO emissions and
CO2 is measured on a wet basis, if needed, correct for
moisture as follows: Install, operate, maintain, and quality assure a
continuous moisture monitoring system for measuring and recording the
moisture content of the flue gases, in order to correct the measured
hourly volumetric flow rates for moisture when calculating CO
concentrations. The following continuous moisture monitoring systems
are acceptable: a continuous moisture sensor; an oxygen analyzer (or
analyzers) capable of measuring O2 both on a wet basis and
on a dry basis; or a stack temperature sensor and a moisture look-up
table, i.e., a psychrometric chart (for saturated gas streams following
wet scrubbers or other demonstrably saturated gas streams, only). The
moisture monitoring system shall include as a component the automated
data acquisition and handling system (DAHS) for recording and reporting
both the raw data (e.g., hourly average wet-and dry-basis O2
values) and the hourly average values of the stack gas moisture content
derived from those data. When a moisture look-up table is used, the
moisture monitoring system shall be represented as a single component,
the certified DAHS, in the monitoring plan for the unit or common
stack.
* * * * *
(l) For each unit for which you decide to demonstrate compliance
with the mercury or HCl emissions limits in Table 1 or 2 or Tables 11
through 15 to 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 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 of approval
of a site-specific monitoring plan.
* * * * *
(m) If your unit is subject to a HCl emission limit in Table 1 or 2
or Tables 11 through 15 to 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
11. Section 63.7530 is amended by revising paragraphs (b)(4)(ii)(E),
(b)(4)(iii), and (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 Table 1 or 2 or Tables 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 in 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
Table 1 or 2 or Tables 11 through 15 to this subpart, you must meet the
work practice standard according to Table 3 to this subpart. During
startup and shutdown, you must only follow the work practice standards
according to items 5 and 6 of Table 3 to this subpart.
* * * * *
0
12. 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 https://www.epa.gov/ttn/atw/boiler/boilerpg.html.
* * * * *
(e) The emissions rate as calculated using Equation 20 in paragraph
(f) 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
[[Page 60846]]
the compliance date specified in Sec. 63.7495.
(f) You must use Equation 20 of this paragraph (f) 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] TR06OC22.005
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 to paragraph
(c)(3)(i) of this section for the affected boiler.
* * * * *
0
13. Section 63.7540 is amended by revising paragraphs (a) introductory
text, (a)(8) introductory text, (a)(8)(ii), (a)(9), (a)(15)
introductory text, (a)(19) introductory text, and (b) to 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 Table 1 or 2 or Tables 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 Table 1 or 2 or Tables 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 your site-specific monitoring plan as required in Sec.
63.7505(d).
* * * * *
(15) If you are using a CEMS to measure HCl emissions to meet
requirements of this subpart, you must install, certify, operate, and
maintain the HCl CEMS as specified in paragraphs (a)(15)(i) and (ii) of
this section. This option for an affected unit takes effect on the date
of approval of a site-specific monitoring plan.
* * * * *
(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 Table 1 or 2 or Tables 11 through 15
to 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
14. 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 Table 1 or 2 or Tables 11 through 15 to this subpart, if
you are not using a CO CEMS to demonstrate compliance.
* * * * *
0
15. Section 63.7555 is amended by revising paragraphs (d) introductory
text and (d)(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 Table 1 or 2 or Tables 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
16. Section 63.7575 is amended by:
0
a. Adding in alphabetical order the 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 addition 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
[[Page 60847]]
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, 2, 14, or 15 to 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 1 to this definition. 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 its (steam energy) contribution (fraction of total steam
energy) to the common header.
[GRAPHIC] [TIFF OMITTED] TR06OC22.006
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 paragraph (2) of this
definition, 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
17. Table 1 to subpart DDDDD of part 63 is revised to read as follows:
Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters \c\
[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............ 2.1E-04 \a\ lb per 2.9E-04 \a\ lb per For M26A, collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 2.7E-03 dscm per run; for
\a\ 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; 3-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; 3-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; 3-run
run average; or average.
(230 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\d\ 30-day
rolling average).
[[Page 60848]]
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; 3-run
run average; or 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; 3-run
run average; or 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; 3-run
run average; or 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; 3-run
run average; or average.
(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 (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; 3-run
run average; or 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 lb per MMBtu lb per MWh; or
of heat input). (5.1E-05 lb per
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, 3- MWh; 3-run
run average; or average.
(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............ 1.5E-04 \a\ lb per 1.7E-04 \a\ lb per For M26A: Collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 2.1E-03 dscm per run; for
\a\ lb per MWh. M26, collect a
minimum of 240
liters per run.
[[Page 60849]]
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, 3- MWh; 3-run
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 \a\ lb per lb per MWh; or
MMBtu of heat (6.7E-6 \a\ lb
input). per MMBtu of
steam output or
8.5E-5 \a\ 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; 3-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.
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 Table
11, 12, or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before October 6,
2025 you may comply with the emission limits in Table 14 to this subpart. On and after October 6, 2025 you
must comply with the emission limits in this Table 1.
\d\ An owner or operator may determine compliance with the carbon monoxide emissions limit using CO2 as a
diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors in 40 CFR
part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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 methodology must account for any CO2
being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber media,
etc. This methodology must be detailed in the site-specific monitoring plan developed according to Sec.
63.7505(d).
0
18. Table 2 to subpart DDDDD of part 63 is revised to read as follows:
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing Boilers and Process Heaters \d\
[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.
[[Page 60850]]
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, 3- MWh; 3-run
run average; or average.
(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, 3- MWh; 3-run
run average; or average.
(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, 3- MWh; 3-run
run average; or average.
(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, 3- per MWh; 3-run
run average; or average.
(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 3-run average.
oxygen, 3-run
average; or (720
ppm by volume on
a dry basis
corrected to 3-
percent
oxygen,\c\ 30-day
rolling average).
b. Filterable PM 3.4E-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, 3- per MWh; 3-run
run average; or average.
(310 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\c\ 30-day
rolling average).
b. Filterable PM 7.4E-03 lb per 9.2E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (6.4E- output or 0.11 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 3-run average.
oxygen, 3-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).
[[Page 60851]]
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, 3- per MWh; 3-run
run average; or average.
(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 3-run average.
oxygen, 3-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 lb per 8.8E-07 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, 3- MWh; 3-run
run average. average.
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 lb per 9.6E-03 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 lb per MWh; or
of heat input). (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, 3- MWh; 3-run
run average based average.
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.
[[Page 60852]]
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 determine compliance with the carbon monoxide emissions limit be determined using
CO2 as a diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors
in 40 CFR part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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 methodology must account
for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
scrubber media, etc. This methodology must be detailed in the site-specific monitoring plan developed
according to Sec. 63.7505(d).
\d\ Before October 6, 2025 you may comply with the emission limits in Table 15 to this subpart. On and after
October 6, 2025], you must comply with the emission limits in this Table 2.
0
19. Table 3 of subpart DDDDD of part 63 is amended by revising the
entries ``5.'' and ``6.'' to read as follows:
* * * * *
Table 3 to Subpart DDDDD of Part 63--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 15 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.
(1) If you choose to comply using
paragraph (1) of the definition 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
paragraph (2) of the definition 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 Table 1 fuels during shutdown, you must vent
or 2 or Tables 11 through 15 emissions to the main stack(s) and
to this subpart during operate all applicable control devices,
shutdown. 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.
[[Page 60853]]
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.
------------------------------------------------------------------------
\a\ As specified in Sec. 63.7555(d)(13), the source may request an
alternative timeframe with the PM controls requirement to the
permitting authority (state, local, or tribal agency) that has been
delegated authority for this subpart by EPA. The source must provide
evidence that (1) it is unable to safely engage and operate the PM
control(s) to meet the ``fuel firing + 1 hour'' requirement and (2)
the PM control device is appropriately designed and sized to meet the
filterable PM emission limit. It is acknowledged that there may be
another control device that has been installed other than ESP that
provides additional PM control (e.g., scrubber).
0
20. Table 4 to subpart DDDDD of part 63 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
------------------------------------------------------------------------
When complying with a numerical emission
limit under Table 1, 2, 11, 12, 13, 14, or You must meet these
15 of this subpart using . . . operating limits . . .
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
* * * * *
0
21. Table 7 to subpart DDDDD of part 63 is revised 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:]
----------------------------------------------------------------------------------------------------------------
And your
If you have an applicable operating limits According to the
emission limit for . . . are based on . . You must . . . Using . . . following
. requirements
----------------------------------------------------------------------------------------------------------------
1. PM, TSM, or mercury.......... a. Wet scrubber i. Establish a (1) Data from the (a) You must
operating site-specific scrubber pressure collect scrubber
parameters. minimum scrubber drop and liquid pressure drop and
pressure drop and flow rate liquid flow rate
minimum flow rate monitors and the data every 15
operating limit PM, TSM, or minutes during
according to Sec. mercury the entire period
63.7530(b). performance test. of the
performance
tests.
(b) Determine the
lowest hourly
average scrubber
pressure drop and
liquid flow rate
by computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
b. Electrostatic i. Establish a (1) Data from the (a) You must
precipitator site-specific voltage and collect secondary
operating minimum total secondary voltage and
parameters secondary amperage monitors secondary
(option only for electric power during the PM or amperage for each
units that input according mercury ESP cell and
operate wet to Sec. performance test. calculate total
scrubbers). 63.7530(b). secondary
electric power
input data every
15 minutes during
the entire period
of the
performance
tests.
(b) Determine the
average total
secondary
electric power
input by
computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
c. Opacity........ i. Establish a (1) Data from the (a) You must
site-specific opacity collect opacity
maximum opacity monitoring system readings every 15
level. during the PM minutes during
performance test. the entire period
of the
performance
tests.
(b) Determine the
average hourly
opacity reading
by computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
(c) Determine the
highest hourly
average opacity
reading measured
during the test
run demonstrating
compliance with
the PM (or TSM)
emission
limitation.
[[Page 60854]]
2. HCl.......................... a. Wet scrubber i. Establish site- (1) Data from the (a) You must
operating specific minimum pH and liquid collect pH and
parameters. effluent pH and flow-rate liquid flow-rate
flow rate monitors and the data every 15
operating limits HCl performance minutes during
according to Sec. test. the entire period
63.7530(b). of the
performance
tests.
(b) Determine the
hourly average pH
and liquid flow
rate by computing
the hourly
averages using
all of the 15-
minute readings
taken during each
performance test.
b. Dry scrubber i. Establish a (1) Data from the (a) You must
operating site-specific sorbent injection collect sorbent
parameters. minimum sorbent rate monitors and injection rate
injection rate HCl or mercury data every 15
operating limit performance test. minutes during
according to Sec. the entire period
63.7530(b). If of the
different acid performance
gas sorbents are tests.
used during the
HCl performance
test, the average
value for each
sorbent becomes
the site-specific
operating limit
for that sorbent.
(b) Determine the
hourly average
sorbent injection
rate by computing
the hourly
averages using
all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
lowest hourly
average of the
three test run
averages
established
during the
performance test
as your operating
limit. When your
unit operates at
lower loads,
multiply your
sorbent injection
rate by the load
fraction, as
defined in Sec.
63.7575, to
determine the
required
injection rate.
c. Alternative i. Establish a (1) Data from SO2 (a) You must
Maximum SO2 site-specific CEMS and the HCl collect the SO2
emission rate. maximum SO2 performance test. emissions data
emission rate according to Sec.
operating limit 63.7525(m)
according to Sec. during the most
63.7530(b). recent HCl
performance
tests.
(b) The maximum
SO2 emission rate
is equal to the
highest hourly
average SO2
emission rate
measured during
the most recent
HCl performance
tests.
3. Mercury...................... a. Activated i. Establish a (1) Data from the (a) You must
carbon injection. site-specific activated carbon collect activated
minimum activated rate monitors and carbon injection
carbon injection mercury rate data every
rate operating performance test. 15 minutes during
limit according the entire period
to Sec. of the
63.7530(b). performance
tests.
(b) Determine the
hourly average
activated carbon
injection rate by
computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
(c) Determine the
lowest hourly
average
established
during the
performance test
as your operating
limit. When your
unit operates at
lower loads,
multiply your
activated carbon
injection rate by
the load
fraction, as
defined in Sec.
63.7575, to
determine the
required
injection rate.
4. Carbon monoxide for which a. Oxygen......... i. Establish a (1) Data from the (a) You must
compliance is demonstrated by a unit-specific oxygen analyzer collect oxygen
performance test. limit for minimum system specified data every 15
oxygen level in Sec. minutes during
according to Sec. 63.7525(a). the entire period
63.7530(b). of the
performance
tests.
(b) Determine the
hourly average
oxygen
concentration by
computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
(c) Determine the
lowest hourly
average
established
during the
performance test
as your minimum
operating limit.
[[Page 60855]]
5. Any pollutant for which a. Boiler or i. Establish a (1) Data from the (a) You must
compliance is demonstrated by a process heater unit specific operating load collect operating
performance test. operating load. limit for maximum monitors or from load or steam
operating load steam generation generation data
according to Sec. monitors. every 15 minutes
63.7520(c). during the entire
period of the
performance test.
(b) Determine the
average operating
load by computing
the hourly
averages using
all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
highest hourly
average of the
three test run
averages during
the performance
test, and
multiply this by
1.1 (110 percent)
as your operating
limit.
----------------------------------------------------------------------------------------------------------------
\a\ Operating limits must be confirmed or reestablished during performance tests.
\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
22. Table 8 to subpart DDDDD of part 63 is amended by revising entry
``8.'' to read as follows:
* * * * *
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
------------------------------------------------------------------------
If you must meet the
following operating limits or You must demonstrate continuous
work practice standards . . . compliance by . . .
------------------------------------------------------------------------
* * * * * * *
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
Equation 15 and Equations 16, 17, and/or
18 in Sec. 63.7530.
* * * * * * *
------------------------------------------------------------------------
0
23. Table 11 to subpart DDDDD of part 63 is revised to read as follows:
Table 11 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After June 4, 2010, and Before May 20, 2011
----------------------------------------------------------------------------------------------------------------
The emissions must not
exceed the following
If your boiler or process heater is For the following emission limits, except Using this specified
in this subcategory . . . pollutants . . . during periods of sampling volume or test
startup and shutdown . run duration . . .
. .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl................. 0.022 lb per MMBtu of For M26A, collect a
designed to burn solid fuel. heat input. minimum of 1 dscm per
run; for M26 collect a
minimum of 120 liters
per run.
2. Units in all subcategories a. Mercury............. 8.0E-07 \a\ lb per For M29, collect a
designed to burn solid fuel that MMBtu of heat input. minimum of 4 dscm per
combust at least 10 percent biomass/ run; for M30A or M30B,
bio-based solids on an annual heat collect a minimum
input basis and less than 10 percent sample as specified in
coal/solid fossil fuels on an annual the method; for ASTM
heat input basis. D6784 \b\ collect a
minimum of 4 dscm.
[[Page 60856]]
3. Units in all subcategories a. Mercury............. 2.0E-06 lb per MMBtu of For M29, collect a
designed to burn solid fuel that heat input. minimum of 4 dscm per
combust at least 10 percent coal/ run; for M30A or M30B,
solid fossil fuels on an annual heat collect a minimum
input basis and less than 10 percent sample as specified in
biomass/bio-based solids on an the method; for ASTM
annual heat input basis. D6784 \b\ collect a
minimum of 4 dscm.
4. Units design to burn coal/solid a. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
fossil fuel. TSM). heat input; or (2.3E- dscm per run.
05 lb per MMBtu of
heat input).
5. Pulverized coal boilers designed a. Carbon monoxide (CO) 130 ppm by volume on a 1 hr minimum sampling
to burn coal/solid fossil fuel. (or CEMS). dry basis corrected to time.
3 percent oxygen, 3-
run average; or (320
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
6. Stokers designed to burn coal/ a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (340
ppm by volume on a dry
basis corrected to 3
percent oxygen ,\c\ 10-
day rolling average).
7. Fluidized bed units designed to a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
burn coal/solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (230
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
8. Fluidized bed units with an a. CO (or CEMS)........ 140 ppm by volume on a 1 hr minimum sampling
integrated heat exchanger designed dry basis corrected to time.
to burn coal/solid fossil fuel. 3 percent oxygen, 3-
run average; or (150
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
9. Stokers/sloped grate/others a. CO (or CEMS)........ 620 ppm by volume on a 1 hr minimum sampling
designed to burn wet biomass fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (390
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.6E- dscm per run.
05 lb per MMBtu of
heat input).
10. Stokers/sloped grate/others a. CO.................. 560 ppm by volume on a 1 hr minimum sampling
designed to burn kiln-dried biomass dry basis corrected to time.
fuel. 3 percent oxygen.
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (4.0E- dscm per run
03 lb per MMBtu of
heat input).
11. Fluidized bed units designed to a. CO (or CEMS)........ 230 ppm by volume on a 1 hr minimum sampling
burn biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (310
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 9.8E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (8.3E- dscm per run
05 \a\ lb per MMBtu of
heat input).
12. Suspension burners designed to a. CO (or CEMS)........ 2,400 ppm by volume on 1 hr minimum sampling
burn biomass/bio-based solids. a dry basis corrected time.
to 3 percent oxygen, 3-
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 (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (6.5E- dscm per run.
03 lb per MMBtu of
heat input).
13. Dutch Ovens/Pile burners designed a. CO (or CEMS)........ 1,010 ppm by volume on 1 hr minimum sampling
to burn biomass/bio-based solids. a dry basis corrected time.
to 3 percent oxygen, 3-
run average; or (520
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\ 10-
day rolling average).
b. Filterable PM (or 8.0E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (3.9E- dscm per run.
05 lb per MMBtu of
heat input).
14. Fuel cell units designed to burn a. CO.................. 910 ppm by volume on a 1 hr minimum sampling
biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 2.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.9E- dscm per run.
05 lb per MMBtu of
heat input).
15. Hybrid suspension grate boiler a. CO (or CEMS)........ 1,100 ppm by volume on 1 hr minimum sampling
designed to burn biomass/bio-based a dry basis corrected time.
solids. to 3 percent oxygen, 3-
run average; or (900
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 2.6E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (4.4E- dscm per run
04 lb per MMBtu of
heat input).
16. Units designed to burn liquid a. HCl................. 4.4E-04 lb per MMBtu of For M26A: Collect a
fuel. heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run
b. Mercury............. 4.8E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
17. Units designed to burn heavy a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average.
[[Page 60857]]
b. Filterable PM (or 1.3E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (7.5E- dscm per run.
05 lb per MMBtu of
heat input).
18. Units designed to burn light a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 2.0E-03 \a\ lb per Collect a minimum of 3
TSM). MMBtu of heat input; dscm per run
or (2.9E-05 lb per
MMBtu of heat input).
19. Units designed to burn liquid a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
fuel that are non-continental units. dry basis corrected to time.
3 percent oxygen, 3-
run average based on
stack test.
b. Filterable PM (or 2.3E-02 lb per MMBtu of Collect a minimum of 4
TSM). heat input; or (8.6E- dscm per run
04 lb per MMBtu of
heat input).
20. Units designed to burn gas 2 a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
(other) gases. dry basis corrected to time.
3 percent oxygen.
b. HCl................. 1.7E-03 lb per MMBtu of For M26A, Collect a
heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
c. Mercury............. 7.9E-06 lb per MMBtu of For M29, collect a
heat input. minimum of 3 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
d. Filterable PM (or 6.7E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.1E- dscm per run.
04 lb per MMBtu of
heat input).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provision of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or 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 determine compliance with the carbon monoxide emissions limit using carbon dioxide
as a diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors in 40
CFR part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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% oxygen correction is to be done on a dry basis. The methodology must account for any
CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber
media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to Sec.
63.7505(d).
0
24. Table 12 to subpart DDDDD of part 63 is revised to read as follows:
Table 12 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After May 20, 2011, and Before December 23, 2011
----------------------------------------------------------------------------------------------------------------
The emissions must not
exceed the following
If your boiler or process heater is For the following emission limits, except Using this specified
in this subcategory . . . pollutants . . . during periods of sampling volume or test
startup and shutdown . run duration . . .
. .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl................. 0.022 lb per MMBtu of For M26A, collect a
designed to burn solid fuel. heat input. minimum of 1 dscm per
run; for M26 collect a
minimum of 120 liters
per run.
b. Mercury............. 3.5E-06 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 3 dscm per
run; for M30A 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/solid a. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
fossil fuel. TSM). heat input; or (2.3E- dscm per run.
05 lb per MMBtu of
heat input).
3. Pulverized coal boilers designed a. Carbon monoxide (CO) 130 ppm by volume on a 1 hr minimum sampling
to burn coal/solid fossil fuel. (or CEMS). dry basis corrected to time.
3 percent oxygen, 3-
run average; or (320
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
4. Stokers designed to burn coal/ a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (340
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 10-
day rolling average).
5. Fluidized bed units designed to a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
burn coal/solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run 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 on a 1 hr minimum sampling
integrated heat exchanger designed dry basis corrected to time.
to burn coal/solid fossil fuel. 3 percent oxygen, 3-
run 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)........ 620 ppm by volume on a 1 hr minimum sampling
designed to burn wet biomass fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (390
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
[[Page 60858]]
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.6E- dscm per run.
05 lb per MMBtu of
heat input).
8. Stokers/sloped grate/others a. CO.................. 460 ppm by volume on a 1 hr minimum sampling
designed to burn kiln-dried biomass dry basis corrected to time.
fuel. 3 percent oxygen.
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (4.0E- dscm per run.
03 lb per MMBtu of
heat input).
9. Fluidized bed units designed to a. CO (or CEMS)........ 260 ppm by volume on a 1 hr minimum sampling
burn biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (310
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 9.8E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (8.3E- dscm per run.
05 \a\ lb per MMBtu of
heat input).
10. Suspension burners designed to a. CO (or CEMS)........ 2,400 ppm by volume on 1 hr minimum sampling
burn biomass/bio-based solids. a dry basis corrected time.
to 3 percent oxygen, 3-
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 (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (6.5E- dscm per run.
03 lb per MMBtu of
heat input).
11. Dutch Ovens/Pile burners designed a. CO (or CEMS)........ 470 ppm by volume on a 1 hr minimum sampling
to burn biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (520
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 10-
day rolling average).
b. Filterable PM (or 3.2E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (3.9E- dscm per run.
05 lb per MMBtu of
heat input).
12. Fuel cell units designed to burn a. CO.................. 910 ppm by volume on a 1 hr minimum sampling
biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 2.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.9E- dscm per run.
05 lb per MMBtu of
heat input).
13. Hybrid suspension grate boiler a. CO (or CEMS)........ 1,500 ppm by volume on 1 hr minimum sampling
designed to burn biomass/bio-based a dry basis corrected time.
solids. to 3 percent oxygen, 3-
run average; or (900
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 2.6E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (4.4E- dscm per run.
04 lb per MMBtu of
heat input).
14. Units designed to burn liquid a. HCl................. 4.4E-04 lb per MMBtu of For M26A: Collect a
fuel. heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
b. Mercury............. 4.8E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm per
run; for M30A 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 on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average.
b. Filterable PM (or 1.3E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (7.5E- dscm per run.
05 lb per MMBtu of
heat input).
16. Units designed to burn light a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 1.3E-03 \a\ lb per Collect a minimum of 3
TSM). MMBtu of heat input; dscm per run.
or (2.9E-05 lb per
MMBtu of heat input).
17. Units designed to burn liquid a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
fuel that are non-continental units. dry basis corrected to time.
3 percent oxygen, 3-
run average based on
stack test.
b. Filterable PM (or 2.3E-02 lb per MMBtu of Collect a minimum of 4
TSM). heat input; or (8.6E- dscm per run.
04 lb per MMBtu of
heat input).
18. Units designed to burn gas 2 a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
(other) gases. dry basis corrected to time.
3 percent oxygen.
b. HCl................. 1.7E-03 lb per MMBtu of For M26A, Collect a
heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
c. Mercury............. 7.9E-06 lb per MMBtu of For M29, collect a
heat input. minimum of 3 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
d. Filterable PM (or 6.7E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.1E- dscm per run.
04 lb per MMBtu of
heat input).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provision of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
[[Page 60859]]
\c\ An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide
as a diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors in 40
CFR part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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% oxygen correction is to be done on a dry basis. The methodology must account for any
CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber
media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to Sec.
63.7505(d).
0
25. Table 13 to subpart DDDDD is of part 63 is revised to read as
follows:
Table 13 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After December 23, 2011, and Before April 1, 2013
----------------------------------------------------------------------------------------------------------------
The emissions must not
exceed the following
If your boiler or process heater is For the following emission limits, except Using this specified
in this subcategory . . . pollutants . . . during periods of sampling volume or test
startup and shutdown . run duration . . .
. .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl................. 0.022 lb per MMBtu of For M26A, collect a
designed to burn solid fuel. heat input. minimum of 1 dscm per
run; for M26 collect a
minimum of 120 liters
per run.
b. Mercury............. 8.6E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
2. Pulverized coal boilers designed a. Carbon monoxide (CO) 130 ppm by volume on a 1 hr minimum sampling
to burn coal/solid fossil fuel. (or CEMS). dry basis corrected to time.
3 percent oxygen, 3-
run average; or (320
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.8E- dscm per run.
05 lb per MMBtu of
heat input).
3. Stokers designed to burn coal/ a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (340
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 10-
day rolling average).
b. Filterable PM (or 2.8E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.3E- dscm per run.
05 lb per MMBtu of
heat input).
4. Fluidized bed units designed to a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
burn coal/solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (230
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.3E- dscm per run.
05 lb per MMBtu of
heat input).
5. Fluidized bed units with an a. CO (or CEMS)........ 140 ppm by volume on a 1 hr minimum sampling
integrated heat exchanger designed dry basis corrected to time.
to burn coal/solid fossil fuel. 3 percent oxygen, 3-
run average; or (150
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.3E- dscm per run.
05 lb per MMBtu of
heat input).
6. Stokers/sloped grate/others a. CO (or CEMS)........ 620 ppm by volume on a 1 hr minimum sampling
designed to burn wet biomass fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (410
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 10-
day rolling average).
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.6E- dscm per run.
05 lb per MMBtu of
heat input).
7. Stokers/sloped grate/others a. CO.................. 460 ppm by volume on a 1 hr minimum sampling
designed to burn kiln-dried biomass dry basis corrected to time.
fuel. 3 percent oxygen.
b. Filterable PM (or 3.2E-01 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (4.0E- dscm per run.
03 lb per MMBtu of
heat input).
8. Fluidized bed units designed to a. CO (or CEMS)........ 230 ppm by volume on a 1 hr minimum sampling
burn biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (310
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 9.8E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (8.3E- dscm per run.
05 \a\ lb per MMBtu of
heat input).
9. Suspension burners designed to a. CO (or CEMS)........ 2,400 ppm by volume on 1 hr minimum sampling
burn biomass/bio-based solids. a dry basis corrected time.
to 3 percent oxygen, 3-
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 (or 5.1E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (6.5E- dscm per run.
03 lb per MMBtu of
heat input).
10. Dutch Ovens/Pile burners designed a. CO (or CEMS)........ 810 ppm by volume on a 1 hr minimum sampling
to burn biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (520
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 10-
day rolling average).
b. Filterable PM (or 3.6E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (3.9E- dscm per run.
05 lb per MMBtu of
heat input).
11. Fuel cell units designed to burn a. CO.................. 910 ppm by volume on a 1 hr minimum sampling
biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 2.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.9E- dscm per run.
05 lb per MMBtu of
heat input).
[[Page 60860]]
12. Hybrid suspension grate boiler a. CO (or CEMS)........ 1,500 ppm by volume on 1 hr minimum sampling
designed to burn biomass/bio-based a dry basis corrected time.
solids. to 3 percent oxygen, 3-
run average; or (900
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 30-
day rolling average).
b. Filterable PM (or 2.6E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (4.4E- dscm per run.
04 lb per MMBtu of
heat input).
13. Units designed to burn liquid a. HCl................. 1.2E-03 lb per MMBtu of For M26A: Collect a
fuel. heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
b. Mercury............. 4.9E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\collect a
minimum of 4 dscm.
14. Units designed to burn heavy a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (18
ppm by volume on a dry
basis corrected to 3
percent oxygen,\c\ 10-
day rolling average).
b. Filterable PM (or 1.3E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (7.5E- dscm per run.
05 lb per MMBtu of
heat input).
15. Units designed to burn light a. CO (or CEMS)........ 130 \a\ ppm by volume 1 hr minimum sampling
liquid fuel. on a dry basis time.
corrected to 3 percent
oxygen; or (60 ppm by
volume on a dry basis
corrected to 3 percent
oxygen,\c\ 1-day block
average)..
b. Filterable PM (or 1.1E-03 \a\ lb per Collect a minimum of 3
TSM). MMBtu of heat input; dscm per run.
or (2.9E-05 lb per
MMBtu of heat input).
16. Units designed to burn liquid a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
fuel that are non-continental units. dry basis corrected to time.
3 percent oxygen, 3-
run average based on
stack test; or (91 ppm
by volume on a dry
basis corrected to 3
percent oxygen,\c\ 3-
hour rolling average).
b. Filterable PM (or 2.3E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (8.6E- dscm per run.
04 lb per MMBtu of
heat input).
17. Units designed to burn gas 2 a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
(other) gases. dry basis corrected to time.
3 percent oxygen.
b. HCl................. 1.7E-03 lb per MMBtu of For M26A, Collect a
heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
c. Mercury............. 7.9E-06 lb per MMBtu of For M29, collect a
heat input. minimum of 3 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\collect a
minimum of 3 dscm.
d. Filterable PM (or 6.7E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.1E- dscm per run.
04 lb per MMBtu of
heat input).
----------------------------------------------------------------------------------------------------------------
\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 and you are not required
to conduct testing for CEMS or CPMS monitor certification, you can skip testing according to Sec. 63.7515 if
all of the other provision of Sec. 63.7515 are met. For all other pollutants that do not contain a footnote
``a'', your performance tests for this pollutant for at least 2 consecutive years must show that your
emissions are at or 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 determine compliance with the carbon monoxide emissions limit using carbon dioxide
as a diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors in 40
CFR part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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% oxygen correction is to be done on a dry basis. The methodology must account for any
CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber
media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to Sec.
63.7505(d).
0
26. 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 \c\
[As stated in Sec. 63.7500, you may continue to comply with the following applicable emission limits until
October 6, 2025: [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
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 0.28 lb dscm per run; for
per MWh. M26 collect a
minimum of 120
liters per run.
[[Page 60861]]
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; 3-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; 3-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; 3-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; 3-run
run average; or 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)... 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, 3- per MWh; 3-run
run average; or average.
(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).
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, 3- per MWh; 3-run
run average; or average.
(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 3-run average.
oxygen, 3-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).
[[Page 60862]]
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; 3-run
run average; or average.
(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 lb per MMBtu lb per MWh; or
of heat input). (5.1E-05 lb per
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 3-run average.
oxygen, 3-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, 3- MWh; 3-run
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 \a\ lb per lb per MWh; or
MMBtu of heat (8.2E-05 \a\ lb
input). per MMBtu of
steam output or
1.1E-03 \a\ 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; 3-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 60863]]
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).
----------------------------------------------------------------------------------------------------------------
\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 Table
11, 12, or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before October 6,
2025 you may comply with the emission limits in this Table 14. On and after October 6, 2025, you must comply
with the emission limits in Table 1 to this subpart.
\d\ An owner or operator may determine compliance with the carbon monoxide emissions limit using carbon dioxide
as a diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors in 40
CFR part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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% oxygen correction is to be done on a dry basis. The methodology must account for any
CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber
media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to Sec.
63.7505(d).
0
27. 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 \d\
[As stated in Sec. 63.7500, you may continue to comply with following emission limits until October 6, 2025:
[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............ 2.2E-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, 3- MWh; 3-run
run average; or average.
(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, 3- MWh; 3-run
run average; or average.
(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, 3- MWh; 3-run
run average; or average.
(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, 3- per MWh; 3-run
run average; or average.
(150 ppm by
volume on a dry
basis corrected
to 3-percent
oxygen,\c\ 30-day
rolling average).
[[Page 60864]]
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 3-run average.
oxygen, 3-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, 3- per MWh; 3-run
run average; or average.
(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 3-run average.
oxygen, 3-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, 3- per MWh; 3-run
run average; or average.
(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 3-run average.
oxygen, 3-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........ 2.0E-06 lb per 2.5E-06 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.
[[Page 60865]]
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, 3- MWh; 3-run
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 lb per 9.6E-03 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 lb per MWh; or
of heat input). (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, 3- MWh; 3-run
run average based average.
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).
----------------------------------------------------------------------------------------------------------------
\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 determine compliance with the carbon monoxide emissions limit using carbon dioxide
as a diluent correction in place of oxygen as described in Sec. 63.7525(a)(1). EPA Method 19 F-factors in 40
CFR part 60, appendix A-7, and EPA Method 19 equations in 40 CFR part 60, appendix A-7, 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% oxygen correction is to be done on a dry basis. The methodology must account for any
CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber
media, etc. This methodology must be detailed in the site-specific monitoring plan developed according to Sec.
63.7505(d).
\d\ Before October 6, 2025 you may comply with the emission limits in this Table 15. On and after October 6,
2025, you must comply with the emission limits in Table 2 to this subpart.
[FR Doc. 2022-19612 Filed 10-5-22; 8:45 am]
BILLING CODE 6560-50-P
