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Rule2022-19612

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

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Published

October 6, 2022

Effective

December 5, 2022

Issuing agencies

Environmental Protection Agency

Abstract

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.

Full Text

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[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 [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[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]]

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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.

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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:
<a href="/cdn-cgi/l/email-protection#2f5b4740425f5c40410143465c4e6f4a5f4e01484059">[email&#160;protected]</a> 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:
<a href="/cdn-cgi/l/email-protection#9af2efeee9f5f4b4f4f3f9f1daffeafbb4fdf5ec">[email&#160;protected]</a>.

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 <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> 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 <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. 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 CO<INF>2</INF> in Lieu of O<INF>2</INF>
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\
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\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.
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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 (PM<INF>2.5</INF>) emission
reductions per year and 1,141 tons of sulfur dioxide (SO<INF>2</INF>)
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
(CO<INF>2</INF>) 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\
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3% Discount rate 7% Discount rate
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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.
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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 PM<INF>2.5</INF> 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
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Examples of regulated
Source category NESHAP NAICS code \1\ entities
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Any industry using a boiler or process Industrial, Commercial, 211 Extractors of crude petroleum
heater as defined in the final rule. and Institutional 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.
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\1\ North American Industry Classification System.

C. Where can I get a copy of this document and other related
information?

In addition to being available in the docket, an electronic copy of
this action is available on the internet. Following signature by the
EPA Administrator, the EPA will post a copy of this final action at
<a href="https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters">https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters</a>. 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 CO<INF>2</INF> as a diluent in lieu of
O<INF>2</INF> 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) <a href="https://www.epa.gov/electronic-reporting-air-emissions/cedri">https://www.epa.gov/electronic-reporting-air-emissions/cedri</a> and WebFIRE database
<a href="https://www.epa.gov/electronic-reporting-air-emissions/webfire">https://www.epa.gov/electronic-reporting-air-emissions/webfire</a>.
---------------------------------------------------------------------------

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

\8\ See Docket ID Item No. EPA-HQ-OAR-2002-0058-3969.
---------------------------------------------------------------------------

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 <a href="https://www.epa.gov/land-research/proucl-software">https://www.epa.gov/land-research/proucl-software</a>.
---------------------------------------------------------------------------

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 CO<INF>2</INF> 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
CO<INF>2</INF> 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 CO<INF>2</INF>)
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 CO<INF>2</INF>. Perfectly
complete combustion would convert all the carbon in the fuel to
CO<INF>2</INF>. 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 CO<INF>2</INF>
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 CO<INF>2</INF> 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.,
NO<INF>X</INF>, SO<INF>2</INF>, 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 CO<INF>2</INF> 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
CO<INF>2</INF> in lieu of oxygen as the diluent for CO which would
account for any changes in CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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
PM<INF>2.5</INF>, 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 SO<INF>2</INF> 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
CO<INF>2</INF> 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 PM<INF>2.5</INF> and SO<INF>2</INF> 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 PM<INF>2.5</INF>. This rule is expected to alter
the emissions of PM<INF>2.5</INF> (and SO<INF>2</INF>). 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
PM<INF>2.5</INF> (or PM<INF>2.5</INF> precursor such as SO<INF>2</INF>)
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 PM<INF>2.5</INF> 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
PM<INF>2.5,</INF> PM<INF>2.5</INF> Precursors and Ozone Precursors
from 21 Sectors and its precursors from 21 sectors. Technical
Support Document. Available at: <a href="https://www.epa.gov/benmap/reduced-form-tools-calculating-pm25-benefits">https://www.epa.gov/benmap/reduced-form-tools-calculating-pm25-benefits</a>.
---------------------------------------------------------------------------

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 SO<INF>2</INF>-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
PM<INF>2.5</INF> and SO<INF>2</INF> 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
CO<INF>2</INF> emissions that result from the increase in national
energy use from control device operation. We estimate the social
disbenefits of CO<INF>2</INF> emission increases expected from this
final rule using the SC-CO<INF>2</INF> 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-CO<INF>2</INF> estimates in the February 2021 TSD and
have determined that these estimates are appropriate for use in
estimating the social value of CO<INF>2</INF> emission changes expected
from this final rule as part of fulfilling analytical guidance with
respect to E.O. 12866. These SC-CO<INF>2</INF> 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:
<a href="https://www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-of-the-benefits-of-reducing-climate-pollution/">https://www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-of-the-benefits-of-reducing-climate-pollution/</a>.
---------------------------------------------------------------------------

Table 12 shows the estimated monetary value of the estimated
changes in CO<INF>2</INF> emissions expected to occur for the final
rule. For 2022-2024, no changes in CO<INF>2</INF> 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 CO<INF>2</INF>-related
effects by applying the SC-CO<INF>2</INF> estimates, included in the
RIA's benefits chapter, to the estimated changes in CO<INF>2</INF>

[[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-
CO<INF>2</INF>.\45\
---------------------------------------------------------------------------

\44\ CO<INF>2</INF> 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-CO<INF>2</INF> 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/mtCO<INF>2</INF> (2016 dollars) using a 3%
discount rate for emissions occurring in 2025). Applying the same
estimate (based on a 3% discount rate) to the CO<INF>2</INF>
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 CO<INF>2</INF> 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 CO<INF>2</INF> 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-CO<INF>2</INF>) for 2025 as shown in Table 12
to be consistent with the year for the PM<INF>2.5</INF> and
SO<INF>2</INF> 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
CO<INF>2</INF> 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<INF>2</INF> values are stated in $/metric ton
CO<INF>2</INF> and rounded to the nearest dollar. Such a conversion
does not change the underlying methodology, nor does it change the
meaning of the SC-CO<INF>2</INF> estimates. For both metric and
short tons denominated SC-CO<INF>2</INF> estimates, the estimates
vary depending on the year of CO<INF>2</INF> 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'' (<a href="https://www.epa.gov/environmentaljustice">https://www.epa.gov/environmentaljustice</a>). 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 PM<INF>2.5</INF>. 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 SO<INF>2</INF>
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:
<bullet> 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.
<bullet> Minority population is the total population minus the white population.
<bullet> 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 <a href="https://www.epa.gov/laws-regulations/laws-and-executive-orders">https://www.epa.gov/laws-regulations/laws-and-executive-orders</a>.

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 <a href="https://www.astm.org/READINGLIBRARY/">https://www.astm.org/READINGLIBRARY/</a>. Hardcopies and printable
versions are also available for purchase from ASTM. Additional
information can be found at <a href="https://www.astm.org/products-services/standards-and-publications.html">https://www.astm.org/products-services/standards-and-publications.html</a>.

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 discuss

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This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.