located on-site and associated with the affected boilers and process
heaters. The final definition for ``Energy

use system'' was intended only to list examples of potential systems
that may use the energy generated by affected boilers and process
heaters. We did not intend that the energy assessment would include
energy use systems using electricity purchased from an off-site source.
We also did not intend that the energy assessment include energy use
systems located off-site. We are proposing to revise the definition of
``Energy assessment'' to clarify our intent.
    2. Compliance Date. Petitioners requested that the EPA clarify the
due date of the energy assessment. All emission standards must be met
by the compliance date, even if compliance demonstrations are sometimes
allowed after the compliance date. In order to meet the requirements of
the rule, energy assessments must, therefore, be completed by the
compliance date for existing sources.
    3. Maximum Duration Requirements. Petitioners requested that the
EPA reconsider the stated ``maximum time'' to conduct the energy
assessment because the maximum times were not included in the proposal,
and stakeholders had no opportunity to comment. The concern raised by
petitioners is that, as the final definition of ``Energy assessment''
is worded, a deviation and a potential violation could occur if the
energy assessment effort exceeds these time limits. Our intent for
including the ``maximum time'' in the final rule definition was to
minimize the burden on the smaller fuel use facilities, many of which
are likely small entities, by limiting the extent of the energy
assessment. Our concern was that if there was no time limit, these
small facilities would have no means to limit the time/effort of an
outside energy assessor that is contracted to perform the energy
assessment. We have revised the definition of ``Energy assessment'' to
change the maximum time from 1 day to 8 technical hours and from three
days to 24 technical hours. This would allow sources to perform longer
assessments at their discretion.

I. Affirmative Defense Provisions During Malfunctions

    The EPA finalized affirmative defense provisions for malfunctions.
As part of this reconsideration proposal, we are soliciting comments on
the affirmative defense provisions that were included in the final
rule. The rationale for the affirmative defense provisions is provided
in the preamble to the final rule. See 76 FR 15642.

J. Work Practices During Startup and Shutdown

    1. Work Practices. The EPA finalized a work practice standard for
periods of startup and shutdown that requires facilities to minimize
emissions consistent with manufacturers' recommended procedures.
Petitioners requested that the EPA clarify whether the requirement
applies to the boiler or the control device manufacturer. The EPA is
proposing to amend the work practice standard so that manufacturers'
recommended procedures are no longer referenced, although the EPA
expects that facilities will follow such procedures for both the boiler
system and any air pollution control devices. The EPA is proposing to
amend the work practice standard as described in section III.E of this
preamble. The rationale for justifying work practice standards for
periods of startup and shutdown is described in the preamble to the
final rule. See 76 FR 15642. Additionally, we do not have emissions
data for startup and shutdown periods sufficient to establish numeric
emissions standards for these periods. The only available data is
limited CO emissions data, which is unlikely to reflect actual
emissions of the best performing units during startup and shutdown. The
rationale for the proposed changes to the work practice standard is
discussed below. The EPA is now proposing to define startup and
shutdown periods and is proposing more specific requirements than those
in the final rule. The definitions of startup and shutdown would
provide clarity regarding which periods of operation are subject to the
work practice standards rather than numeric emission limits and the
associated requirements. The proposed definitions specify that only the
periods of time between a complete shutdown of a unit (no fuel being
combusted) and the time that a unit first reaches 25 percent load
qualify as startup, and only the periods of time between the time that
a unit last reaches 25 percent load and the time when a unit is
completely shut down (no fuel being combusted) qualify as shutdown.
These definitions are intended to ensure that units cannot cycle in and
out of startup or shutdown. The EPA recognizes that it may be necessary
to establish a maximum time period to ensure that units cannot operate
in startup or shutdown mode for extended periods of time, and is
soliciting comment on the appropriate time period or time periods for
the various unit designs. The EPA believes that a work practice
standard that applies during such periods should require more than a
general duty to reduce emissions, which is essentially what was
required in the final rule. General duty requirements do not constitute
appropriate work practice standards under section 112(h). We are
soliciting comment on the rationale for work practice standards during
periods of startup and shutdown as well as the proposed work practice
standard and the rationale for proposing changes to the standard. We
also are soliciting comment on whether other work practices should be
required during startup and shutdown, including requirements to operate
using specific fuels to reduce emissions during such periods. Because
the EPA did not propose work practice standards for startup and
shutdown periods in the June 4, 2010, proposed rule, members of the
public did not have the opportunity to comment on those standards or
the rationale for the standards prior to issuance of the final rule.
    2. Operating Parameters and Opacity Limits. Petitioners requested
that EPA clarify that the operating limits and opacity limits do not
apply during periods of startup and shutdown. Having finalized work
practice standards for these periods of time, EPA agrees that the
requested clarification is what was intended in the final rule.

K. Applicability

    1. Exemption for Units Serving as Control Devices. In the final
rule, the EPA exempted any boiler or process heater that is used as a
control device to comply with another subpart of part 63, provided that
at least 50 percent of the heat input to the boiler is provided by the
gas stream that is regulated under another subpart. Petitioners
requested that EPA extend the exemption to units that serve as control
devices for EPA standards issued under parts 60 or 61 of the CAA. We
recognize that part 61 is another part relevant to the NESHAP program
and should be treated the same as the exemption provided for part 63.
Although part 60 does not regulate HAP, the EPA does want to continue
to use combustion controls for organic pollutants that part 60
addresses, as it provides a pollution prevention strategy and reduces
the need for facilities to install other combustion equipment to serve
as dedicated control devices for NSPS and NESHAP regulated gas streams
(e.g., thermal oxidizers and flares). In addition, many of the
potential add-on combustion technologies do not recover energy, and the
resulting combustion using these technologies would emit approximately
the same level of contaminants as a boiler without the added benefit of

energy recovery. Therefore, the EPA is now proposing to exempt any
boiler or process heater that is used as a control device to comply
with standards issued under part 60, part 61, or part 63 of the CAA,
provided that at least 50 percent of the heat input to the boiler is
provided by a gas stream that is subject to standards under those
parts.
    2. Waste Heat Boilers and Process Heaters. Petitioners requested
that the EPA clarify that waste heat process heaters, like waste heat
boilers, are not subject to the standards. Petitioners are correct that
the EPA intended to exempt waste heat process heaters from the rule,
and the EPA is amending the definition of process heater to exclude
waste heat process heaters. We also are clarifying that waste heat
boilers and process heaters can include supplemental burners as long as
those burners combust only Gas 1 fuels, up to 50 percent of their heat
input.
    3. Units Firing Comparable Fuels. Petitioners requested that the
EPA clarify whether boilers and process heaters burning comparable
fuels, as defined under the Resource Conservation and Recovery Act
(RCRA), are subject to the NESHAP for industrial, commercial, and
institutional boilers and process heaters. Section 261.38 states that
hazardous secondary materials (i.e., spent materials, sludges and
byproducts) that have fuel value and whose hazardous constituent levels
are comparable to those found in fuel oil that could be burned in their
place are not solid wastes and hence not hazardous wastes under
Subtitle C of RCRA. These materials are called comparable fuels. Since
comparable fuels are not hazardous waste, boilers and process heaters
burning comparable fuels are not subject to the NESHAP for hazardous
waste combustors (part 63, Subpart EEE), which includes boilers and
process heaters that burn RCRA hazardous waste. Therefore, boilers and
process heaters burning comparable fuels are covered by the NESHAP for
industrial, commercial, and institutional boilers and process heaters.
    4. Residential Unit Exemption. During the initial phases of
implementation of the area source boiler rule, stakeholders requested
clarification from the EPA on the applicability of the area source rule
to residential boilers, particularly those units at individual
residences located at institutional facilities. The EPA's intent was
not to cover such units, and during reconsideration, the EPA is
amending the area source rule accordingly. Similarly, the final major
source rule could be interpreted to cover residential boilers at large
institutions, which was not the intent of the rule. Accordingly, the
EPA is proposing to exempt residential boilers from the rule and is
proposing the following definition of residential boiler to the major
source rule: Residential boiler means a boiler, used in a dwelling
containing four or fewer family units, to provide heat and/or hot
water. This definition includes boilers used primarily to provide heat
and/or hot water for a dwelling containing four or fewer families
located at an institutional facility (e.g., university campus, military
base, church grounds) or commercial/industrial facility (e.g., farm).

L. Compliance

    1. Extending Compliance Dates. On May 18, 2011, the EPA issued a
stay of the effective date of the final rule. The EPA is proposing
several revisions to the standards in this rule. As such, we are
proposing to revise the compliance date for existing sources to three
years after the date of publication of the final reconsideration rule.
This date is being proposed in order to enable facilities sufficient
time to install controls and make compliance-related decisions. For new
sources, the EPA is proposing that the compliance date is 60 days after
the date of publication of the final reconsideration rule, or upon
startup, whichever is later. This date assumes that the final
reconsideration rule will be subject to the Congressional Review Act,
which will delay the effective date of the rule by 60 days. We are
proposing to extend the compliance dates for all standards for several
reasons. First, the proposed changes to the emission limits for units
in every subcategory and the proposed use of work practice standards
for dioxin/furan emissions for all subcategories will have a
significant impact on the compliance strategies that are selected by
the affected sources. For instance, the proposed changes in PM emission
limits for existing biomass fluidized bed, hybrid suspension grate, and
the newly proposed dry stoker subcategories would require different PM
control selections than the emission limits finalized in March 2011.
The proposed changes in Hg, HCl and PM emission limits for units
designed to burn liquid fuels are likely to result in different
compliance responses and control selections for all of these
pollutants. For coal stoker units, the increased stringency of the
proposed PM and HCl emission limits would require increased control
efficiencies that, while not necessarily changing the types of controls
needed, may impact the design of those controls. Second, when the EPA
announced the reconsideration and postponed the effective date, it
indicated to industry that requirements could change significantly. The
resulting uncertainty has limited the ability of affected sources to
begin making appropriate selections of control technologies and other
compliance decisions. Even if significant changes were not being
proposed, an extended compliance date would likely be necessary to
provide enough time for facilities to achieve compliance. Third, most
of the dioxin emission limits that were finalized in March 2011 were
below the level that the EPA has now determined can be accurately
measured using the required test method. This was pointed out by
stakeholders who petitioned the EPA to move to a work practice approach
because the levels of dioxin/furan were too low to accurately measure
and resulted in a high degree of uncertainty regarding how to meet the
limits. The uncertainty resulted in the inability of sources to select
dioxin/furan control technology, and also prevented sources from
selecting controls for other pollutants because the emission controls
must be designed to work properly when operated together. For instance,
if a source required an ESP for PM control but needed carbon injection
to potentially meet a very low dioxin/furan emission limit, the source
may choose a fabric filter for PM control instead of an ESP.
Alternatively, if a source no longer needed carbon injection, the
particulate loading to the PM control device would be decreased, which
may result in a different design or possibly a selection of a different
control technology. Finally, the EPA has received comments that the
availability of control equipment and vendors to install control
equipment for boilers is in question due to the large number of units
requiring controls in conjunction with the parallel rulemaking for
electric generating units that will require controls from many of the
same vendors. While the EPA believes that the maximum time allotted
under section 112, 3 years after promulgation along with an additional
year for installation of controls that must be approved on a case-by-
case basis by the permitting authority, provides enough time for
boilers to achieve compliance, the EPA recognizes that maintaining the
compliance dates from the March 2011 final rule would essentially
provide less than 2 years for sources to meet the final standards,
whose stringency will not be determined until the reconsideration is
final. For all of the reasons discussed above, the EPA is proposing
that the compliance date for existing sources is three years after the
date of publication of the final reconsideration rule. The

EPA is requesting comment on the proposed changes to the compliance
dates.
    2. Reduced Testing Frequency and Detection Levels. In the final
rule, the EPA changed the stack testing requirements to allow units
that demonstrate compliance for a particular pollutant at a level at or
below 75 percent of the emission limit for 2 consecutive years to
forego stack testing for up to 37 months. The EPA is maintaining this
provision for most of the emission limits and is soliciting comment on
this provision. The EPA also included, in the final rule analyses, a
method to ensure that emission limits are set at levels that can be
measured by the available test methods. During the development of the
rule, the EPA carefully considered comments regarding the very low
levels of some of the finalized emission limits that were based on a
level no less than 3 times the ``representative detection limit'' or
RDL. In cases where the calculated MACT floors were lower than the 3
times the RDL value, the calculated floor value was replaced by the 3
times the RDL value. For these values, which again represent the lowest
level that can be measured, units can qualify for skip testing by
meeting the limit rather than a level that cannot be accurately
measured.
    3. Fuel Analysis of Gaseous Fuels at Co-Fired Units. Petitioners
requested that the EPA clarify the fuel analysis requirements for co-
fired units that combust Gas 1 fuels along with either solid or liquid
fuels. The EPA is clarifying that Gas 1 fuels are not included in the
fuel analysis requirement.
    4. Coal Sampling Techniques. Petitioners requested that the EPA
allow for automated coal sampling systems. The EPA did not intend to
exclude these techniques in the final rule and is adding clarifying
language to allow for automated coal sampling techniques.

M. Other Issues Open for Comment

    1. Stakeholders asked the EPA to consider, for units that are
retrofitted to switch to natural gas as a compliance option, allowing
those units to average emissions with units of the original unit
design. These parties suggested that continuing to allow such averaging
would be consistent with EPA's general approach of specifying emission
standards for affected facilities, but otherwise allowing the
facilities to comply however they see fit. They also pointed out that
this may allow for more effective controls overall. For example, they
suggested that without allowing for averaging of units that switch to
cleaner fuels as a compliance option, natural gas conversion is a less
attractive option than if such averaging was allowed, because a
facility would not have the ability to offset emissions using that
unit. In this case, these stakeholders believe that installing controls
that result in fewer emissions reductions than switching to natural gas
may be a perverse outcome. They suggested that continuing to allow
averaging across subcategories in cases where fuel switching has been
used to achieve compliance would instead encourage fuel switching to
cleaner fuels, which is environmentally beneficial. The EPA is
requesting comment on the potential benefit of this suggested approach,
and how such an approach could be justified and incorporated into the
rule.
    2. Stakeholders requested that EPA consider creating a subcategory
for units that are installed and used in place of flares that are
currently used to combust process gases. The EPA is requesting comment
on how such a subcategory could be justified and incorporated into the
rule. The stakeholders also suggested that it would be appropriate to
assume that the emissions from process gases diverted from flares to
boilers have ``zero emissions'' for the purposes of classifying the
boiler they are combusted in. Since the process gases must be combusted
in either event, they requested that the EPA develop an approach where
we use a concept similar to the emissions averaging provisions, for
example, to simply assume that combustion of such process gases in a
boiler rather than a flare should not be counted as emissions from the
boiler because there is no net increase in emissions. The EPA requests
comment on how such an approach could be justified and incorporated
into the rule.

VI. Technical Corrections and Clarifications

    We are proposing several technical corrections. These amendments
are being proposed to correct inaccuracies and oversights that were
promulgated in the final rule and to make the rule language consistent
with provisions addressed through this reconsideration. These proposed
changes are described in Table 3 of this preamble. We request comment
on all of these proposed changes.

Table 3--Miscellaneous Proposed Technical Corrections to 40 CFR Part 63,
                              Subpart DDDDD
------------------------------------------------------------------------
   Section of subpart DDDDD        Description of proposed correction
------------------------------------------------------------------------
40 CFR 63.7491(m)............  Clarify the language in this paragraph to
                                use the word ``unit'' instead of
                                ``boiler.''
40 CFR 63.7495(b)............  Revise this paragraph to include a
                                provision in Sec.   63.6(i)
40 CFR 63.7499(f)-(s)........  Revise and add new paragraphs to
                                accommodate the addition of new
                                subcategories of boilers and process
                                heaters.
40 CFR 63.7499(d)............  Revise the term ``stokers'' to ``stokers/
                                sloped grate/other units'' consistent
                                with how the data for this rule was
                                analyzed.
40 CFR 63.7500(d)............  Revise this paragraph by adding a new
                                paragraph (d) to clarify that the
                                emission standards apply at all times,
                                except during startup and shutdown,
                                during which time you must comply only
                                with Table 3.
40 CFR 63.7501(b)............  Revise terms in this paragraph to correct
                                spelling errors.
40 CFR 63.7505(c)............  Revise this paragraph by removing the
                                reference to Table 12; this table is not
                                included because this is a proposed
                                rule.
40 CFR 63.7510(a)............  Revise this paragraph to create four
                                subparagraphs (1)-(4) to clarify our
                                intent on fuel analysis requirements for
                                gaseous fuels.
40 CFR 63.7510(b)............  Revise this paragraph to clarify that
                                certain fuels are not subject to the
                                fuel analysis requirements and that
                                units using a continuous emission
                                monitoring system for mercury or
                                hydrogen chloride are exempt from the
                                performance testing and operating limit
                                requirements.
40 CFR 63.7510(c)............  Revise this paragraph to clarify that
                                units using a continuous emission
                                monitoring system for carbon monoxide
                                are exempt from the performance testing
                                and operating limit requirements.
40 CFR 63.7510(d)............  Revise this paragraph to clarify that
                                owners and operators electing to comply
                                with the alternative total selected
                                metals limit are not required to install
                                a PM CPMS.

40 CFR 63.7510(g) and (h)....  Insert a new paragraph (g) and renumber
                                (g) to (h). Paragraph (g) will clarify
                                the compliance provisions for new
                                sources with respect to the work
                                practice and tune-up provisions.
40 CFR 63.7510(f),             Revise these paragraphs by removing the
 63.7515(f), and 63.7520(d).    references to Table 12; this table is
                                not included because this is a proposed
                                rule.
40 CFR 63.7521(a)............  Revise this paragraph to clarify that
                                fuel analysis cannot be used with
                                gaseous fuels to demonstrate compliance
                                with the limits for total selected
                                metals or hydrogen chloride given method
                                limitations. We are also proposing to
                                revise this paragraph to clarify that a
                                fuel gas system consisting of multiple
                                gaseous fuels collected and mixed with
                                each other is considered a single fuel
                                type and sampling and analysis is only
                                required of the combined fuel gas
                                system.
40 CFR 63.7521(b)............  Revise this paragraph to clarify that the
                                fuel monitoring plan is needed only if
                                you are required to conduct fuel
                                analyses.
40 CFR 63.7521(b)(1).........  Revise this paragraph to add a cross
                                reference to the section describing the
                                initial compliance demonstration.
40 CFR 63.7521(b)(2)(ii)       Revise the subparagraphs to clarify that
 through (iv).                  the requirements apply to each
                                anticipated fuel type.
40 CFR 63.7521(c)(1)(ii).....  Revise this paragraph by changing wording
                                from ``1-hour'' to ``one-hour''.
                               Clarify the different sampling
                                circumstances for performance stack
                                testing and monthly sampling.
40 CFR 63.7521(c)(2)(ii) and   Revise this paragraph by clarifying
 63.7521(d)(2).                 wording describing sampling requirements
                                to provide more flexibility for
                                automated sampling and reduce overly
                                prescriptive language.
40 CFR 63.7521(e)............  Reference equations 7, 8, and 9 within
                                this paragraph to add clarity.
40 CFR 63.7521(f)............  Add three sub-paragraphs to this
                                paragraph to organize exemptions from
                                fuel specification analyses.
40 CFR 63.7521(g)(1).........  Revise this paragraph to add a cross
                                reference to the section describing the
                                initial compliance demonstration.
40 CFR 63.7521(g)(2)(ii)       Revise the subparagraphs to clarify that
 through (iv).                  the requirements apply to each
                                anticipated fuel type.
40 CFR 63.7522(b)............  Revise this paragraph to add several
                                subparagraphs to clarify that emissions
                                averaging may not include units using
                                CEMS or PM CPMS; that averaging may only
                                be within units in a subcategory subject
                                to the same numerical emission limit;
                                and that emissions averaging is not
                                allowed for certain subcategories of
                                units for certain emission limits.
40 CFR 63.7522(e)(2).........  Add the units for emission limits to add
                                clarity (pounds per million Btu).
                               Revise the definition of the term ``Sm''
                                in Equation 2 to clarify that maximum
                                steam generation is in units of pounds
                                per hour.
40 CFR 63.7525(a)............  Remove a reference to Table 12; this
                                table is not included because this is a
                                proposed rule.
40 CFR 63.7525(b)(3).........  Change language from ``concentrations''
                                to ``rates'' to provide clarity.
40 CFR 63.7525(b)(5).........  Revise this paragraph by changing wording
                                from ``1-hour'' to ``one-hour''.
40 CFR 63.7525(d)(3).........  Revise the paragraph to add a reference
                                to 65.7535(d) to replace a description
                                of other situations that constitute a
                                monitoring deviation.
40 CFR 63.7525(d)(4).........  Change from the 12-hour block average to
                                30-day rolling average as specified in
                                the revised Table 8 to subpart DDDDD.
40 CFR 63.7530(b)............  Revise this paragraph to clarify which
                                fuels are exempt from analysis by cross-
                                referencing 40 CFR 63.7510(a)(2),
                                instead of repeating the information in
                                that paragraph.
40 CFR 63.7530(b)(4)           Revise this paragraph to: 1. Clarify that
 [formerly (b)(3)].             you are not required to establish and
                                comply with the operating parameter
                                limits when you are using a CEMS to
                                monitor and demonstrate compliance with
                                the applicable emission limit.
                               2. Clarify in the subparagraphs which
                                parameters are applicable to specific
                                types of control devices.
                               3. Add a new subparagraph to address PM
                                controls used in conjunction with a PM
                                CPMS.
                               4. Add a new paragraph to address
                                particulate wet scrubbers as distinct
                                from acid-gas wet scrubbers.
40 CFR 63.7530(c)(2).........  Revise the references to Equation 9 to be
                                Equation 10, to accommodate the change
                                in numbering of equations.
40 CFR 63.7530(c)(3).........  Revise the references to Equation 9 to be
                                Equation 10, to accommodate the change
                                in numbering of equations.
40 CFR 63.7530(c)(4).........  Revise the references to Equation 9 to be
                                Equation 10, to accommodate the change
                                in numbering of equations.
40 CFR 63.7530(h)............  Remove a reference to Table 12; this
                                table is not included because this is a
                                proposed rule.
40 CFR 63.7533(b)(2).........  Amend this paragraph to clarify that the
                                use of emission credits from
                                implementation of energy conservation
                                measures can only be used by existing
                                units, and that these credits can be
                                used to demonstrate initial and on-going
                                compliance.
40 CFR 63.7533(c), (c)(1)(i),  Amend these paragraphs to change the date
 and (c)(3).                    after which energy conservation measures
                                can be used to generate credits from
                                January 14, 2011, to January 1, 2008.
                                January 1, 2008 is the same cut-off date
                                for using a pre-existing energy
                                assessment to satisfy the energy
                                assessment requirement in Table 3 to
                                subpart DDDDD.
40 CFR 63.7533(c)(2)(i) and    Revise the reference to Equation 12 to
 (c)(3).                        Equation 14, to accommodate the change
                                in numbering of equations.
40 CFR 63.7533(c)(3)(i)......  Revise Equation 12 in this section to
                                clarify the summation to be performed in
                                that equation, and to clarify that the
                                energy credits are expressed as a
                                decimal fraction of the baseline energy
                                input.
40 CFR 63.7533(c)(3)(i) and    Revise the names and definitions of the
 (f).                           terms in Equations 12 and 13 to be
                                consistent.
40 CFR 63.7533(c)(f).........  Revise the paragraph to remove the
                                reference to (f)(1) and (2) because
                                there is no paragraph (2) and only a
                                single paragraph is needed.

                               Change the reference to Equation 13 to
                                Equation 15, to accommodate the change
                                in numbering of equations.
40 CFR 63.7535...............  Revise the title of this section to add
                                clarity.
40 CFR 63.7535(b)............  Add language to the paragraph to clarify
                                that you must operate monitoring systems
                                while the unit is operating and
                                compliance is required. Add ``scheduled
                                CMS maintenance'' to the list of periods
                                during which you are not required to
                                collect data from a monitoring system.
40 CFR 63.7535(c)............  Amend this paragraph to clarify that
                                operators must record results of CMS
                                performance audits, dates and duration
                                of periods when the CMS is out of
                                control to completion of the corrective
                                actions necessary to return the CMS to
                                normal operation. Also adding language
                                to clarify that all collected data must
                                be used to assess compliance.
40 CFR 63.7535(d)............  Revise the paragraph to remove references
                                to ``out-of-control periods'' and to add
                                ``system accuracy audits'' to the list
                                of periods during which data do not need
                                to be collected.
40 CFR 63.7540(a)............  Add references to Tables 1, 2, 3, and 4
                                to add clarity.
40 CFR 63.7540(a)(2).........  Split this paragraph into two
                                subparagraphs for clarity.
40 CFR 63.7540(a)(3).........  Revise the paragraph to clarify that fuel
                                analysis for hydrogen chloride is
                                applicable for only solid and liquid
                                fuels, and to clarify that certain fuels
                                are not subject to the fuel analysis
                                requirements.
40 CFR 63.7540(a)(3) and       Change the references to Equation 9 to
 (a)(3)(iii).                   Equation 11 to accommodate the change in
                                numbering of equations.
40 CFR 63.7540(a)(4), (a)(5),  Revise these paragraphs to clarify that
 and (a)(6).                    certain fuels are not subject to the
                                fuel analysis requirements.
40 CFR 63.7540(a)(5) and       Change the reference to Equation 11 to
 (a)(5)(iii).                   Equation 12 to accommodate the change in
                                numbering of equations.
40 CFR 63.7540(a)(9).........  Revise this paragraph and the
                                subparagraphs to remove the references
                                to the EPA performance specifications
                                for a PM CEMS, and replace them with a
                                reference to the PM CPMS provisions in
                                the facility's site-specific monitoring
                                plan required by 40 CFR 63.7505.
40 CFR 63.7540(a)(10)(i) and   Revise this paragraph to specify that
 (a)(12).                       required burner inspections be done at
                                the next burner shutdown, whether it is
                                scheduled or unscheduled.
40 CFR 63.7541 (a)(3) and (4)  Change the 3-hour parameter averages to
                                30-day rolling parameter averages to
                                match Table 8 to subpart DDDDD.
40 CFR 63.7545(e)(3).........  Remove a reference to Table 12 (this
                                table is not included because this is a
                                proposed rule), and adding language to
                                clarify that this applies to facilities
                                ``not using a CO CEMS to demonstrate
                                compliance.''
40 CFR 63.7545(f)............  Revise the paragraph to include units
                                that burn ``gaseous fuel subject to
                                another subpart of this part'' to add
                                clarity.
40 CFR 63.7550(c)(6).........  Change the reference to Equation 10 to
                                Equation 11, to accommodate the change
                                in numbering of equations.
40 CFR 63.7550(h), (i), and    Revise paragraph (h) and adding
 (j).                           paragraphs (i) and (j) to provide
                                additional instruction on submitting
                                data to EPA from performance emission
                                tests, CEMS performance evaluations, and
                                quarterly data from CEMS and CPMS
                                consistent with the proposed monitoring
                                requirements.
40 CFR 63.7555(d)............  Remove a reference to Table 12; this
                                table is not included because this is a
                                proposed rule.
40 CFR 63.7555(d)(2).........  Correct an inaccurate reference to 40 CFR
                                241.3(b)(1)and (2), and to add a
                                sentence to clarify that certain units
                                exempt from the incinerator standards
                                under section 129(g)(1) of the Clean Air
                                Act do not need to maintain the records
                                described in this paragraph.
40 CFR 63.7555(d)(4).........  Change the reference to Equation 10 to
                                Equation 11, to accommodate the change
                                in numbering of equations.
40 CFR 63.7555(d)(5).........  Change the reference to Equation 11 to
                                Equation 12, to accommodate the change
                                in numbering of equations.
40 CFR 63.7555(h)............  Revise the paragraph to include units
                                that burn ``gaseous fuel subject to
                                another subpart of this part'' to add
                                clarity.
40 CFR 63.7575...............  Revise the definition of process heater
                                to include units heating hot water as a
                                process heat transfer medium.
                               Edit the definition of each solid fuel
                                combustor design-based subcategory to
                                establish a hierarchy and assisted
                                affected sources by clarifying
                                applicability for units with multiple
                                combustor types.
                               Revise the definition of ``dutch oven''
                                to clarify that fluidized bed boilers
                                are not part of the dutch oven design
                                category.
                               Revise the definition of ``energy
                                assessment'' to clarify the length of
                                days for each category of facilities.
                               Revise the definition of ``equivalent''
                                to remove references to hydrogen
                                sulfide.
                               Revise the definition of ``fluidized bed
                                boiler'' to clarify that pulverized coal
                                boilers are not included.
                               Revise the definition of ``hybrid
                                suspension grate boiler'' to clarify
                                that ``the fuel combusted in these units
                                exceed a moisture content of 40 percent
                                on an as-fired basis'' and ``Fluidized
                                bed, dutch oven, and pile burner designs
                                are not part of the hybrid suspension
                                grate boiler design category.''
                               Revise the definition of ``fuel cell'' to
                                clarify that ``fluidized bed, dutch
                                oven, pile burner, hybrid suspension
                                grate, and suspension burners are not
                                part of the fuel cell subcategory.''
                               Revise the definition of ``liquid fuel''
                                to include vegetable oil.

                               Revise the definition of ``process
                                heater'' to include ``units heating hot
                                water as a process heat transfer
                                medium'' and to clarify that ``waste
                                heat process heaters are excluded from
                                this definition'' similar to the
                                exemption allowed for waste heat
                                boilers.
                               Revise the definition of ``steam output''
                                to include a description of the total
                                energy output for a boiler that
                                generates only electricity.
                               Revise the definition of ``stoker'' to
                                clarify that ``fluidized bed, dutch
                                oven, pile burner, hybrid suspension
                                grate, suspension burners, and fuel
                                cells are not considered to be a stoker
                                design.''
                               Revise the term ``suspension boiler'' to
                                instead be ``suspension burner'', to
                                provide consistent terminology
                                throughout the rule and to clarify that
                                ``fluidized bed, dutch oven, pile
                                burner, and hybrid suspension grate
                                units are not part of the suspension
                                burner subcategory.''
                               Revise the definition of ``waste heat
                                boiler'' to clarify that the definition
                                includes fired and unfired waste heat
                                boilers.
                               Revise the definition of ``waste heat
                                process heater to clarify that the
                                definition includes fired and unfired
                                waste heat process heaters.
                               Add new definitions of ``30-day rolling
                                average'', ``average annual heat input
                                rate'', ``biodiesel'', ``daily block
                                average'', ``heavy liquid'', ``light
                                liquid'', ``other combustor'', ``oxygen
                                analyzer'', ``oxygen trim system'',
                                ``pile burner'', ``residential boiler'',
                                ``sloped grate'', ``stoker/sloped grate/
                                other unit designed to burn kiln dried
                                biomass'', ``stoker/sloped grate/other
                                unit designed to burn wet biomass'',
                                ``total selected metals'', ``unit
                                designed to burn heavy liquid
                                subcategory'', ``unit designed to burn
                                light liquid subcategory'', and
                                ``vegetable oil''.
                               Remove the definition of ``liquid fuel
                                subcategory.''
Tables 1 and 2 to subpart      Revise the sampling volumes collected and
 DDDDD.                         also the prescribed span values
                                associated with the emission measurement
                                methods to account for changes in the
                                numerical emission limits and to be
                                consistent with the proposed emission
                                limits.
Table 3 to subpart DDDDD.....  Revise items 1, 2, and 3 to account for
                                the proposed changes in the tune-up
                                requirements.
                               Revise item 4c to clarify the major
                                systems ``consuming energy from affected
                                boilers and process heaters and which
                                are under the control of the boiler/
                                process heater owner/operator.''
                               Revise item 5 to remove the reference to
                                Table 12; this table is not included
                                because this is a proposed rule.
Table 4 to subpart DDDDD.....  Revise the operating limits for items 1
                                and 2 to read ``one-hour'' instead of
                                ``1-hour''.
                               Revise certain items in the table to
                                clarify the applicability of the
                                parameter operating limits, and to
                                reflect that replace PM CEMS with PM
                                CPMS requirements.
                               Revise items 1, 2, and 4 in the table to
                                reflect the fact that we are proposing
                                that compliance with the operating
                                limits is based on a 30-day rolling
                                average.
Table 6 to subpart DDDDD.....  Revise items 1, 2, and 3 to provide
                                additional instruction on demonstrating
                                compliance.
                               Revise item 4 to replace the requirements
                                for hydrogen sulfide in other gas 1
                                fuels with requirements for total
                                selected metals in solid fuels.
Table 7 to subpart DDDDD.....  Revise item 1 to include total selected
                                metals with PM and mercury, and to
                                clarify the applicability of the
                                operating limits described in that item.
Table 8 to subpart DDDDD.....  Include provisions for demonstrating
                                continuous compliance with a PM CPMS, to
                                reflect proposed changes elsewhere in
                                the rule.
                               Revise various items to reflect the
                                proposed change from 12-hour block
                                averages to 30-day rolling averages for
                                demonstrating compliance.
                               Revise the operating load compliance
                                provisions to be consistent with the
                                operating limit in Table 4 to subpart
                                DDDDD.
Table 11 to subpart DDDDD....  Delete Table 11 to subpart DDDDD to be
                                consistent with the proposal to remove
                                the numerical emission limits for dioxin/
                                furan emissions.
Table 12 to subpart DDDDD....  Remove Table 12 to subpart DDDDD because
                                this is a proposed rule and Table 12 was
                                needed only because the rule published
                                on March 21, 2011 (76 FR 15608) was a
                                final rule.
------------------------------------------------------------------------

VII. Impacts of This Proposed Rule

A. What are the air impacts?

    Table 4 of this preamble illustrates, for each basic fuel
subcategory, the emissions reductions achieved by the proposed rule
(i.e., the difference in emissions between a boiler or process heater
controlled to the floor level of control and boilers or process heaters
at the current baseline) for new and existing sources. Nationwide
emissions of selected HAP (i.e., HCl, HF, Hg, metals, and volatile
organic compound (VOC)) will be reduced by 45,000 tons per year for
existing units and 19 tons per year for new units. Emissions of HCl
will be reduced by 37,000 tons per year for existing units and 0 tons
per year for new units. Emissions of Hg will be reduced between 0.5 to
1.8 tons per year for existing units and 20.2 pounds per year for new
units. Emissions of filterable PM will be reduced by 41,200 tons per
year for existing units and 1,500 tons per year for new units.
Emissions of non-mercury metals (i.e., antimony, arsenic, beryllium,
cadmium, chromium, cobalt, lead, manganese, nickel, and selenium) will
be reduced by 2,200 tons per year for existing units and 19 tons per
year for new units. In addition, emissions of SO2 are
estimated to be reduced by 558,400 tons per year for existing sources
and 0 tons per year for new sources. A discussion of the methodology
used to estimate emissions and emissions reductions is presented in
``Revised (November 2011) Methodology for Estimating Cost and Emission
Impacts for Industrial, Commercial, and Institutional Boilers and
Process Heaters NESHAP--Major Source'' in the docket.

                                          Table 4--Summary of Emissions Reductions for Existing and New Sources
                                                                        [Tons/yr]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Non
                   Source                           Subcategory            HCl           PM        mercury             Mercury \b\               VOC
                                                                                metals \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing Units.............................  Limited Use.............            1            2         0.45  2.2E-04......................            1
                                             Solid units.............       34,815       34,830          271  0.4 to 1.4...................        2,487
                                             Liquid units............        2,039        6,240        1,905  0.04 to 0.3..................        1,815
                                             Non-Continental Liquid            158           29            4  0.001 to 0.01................          169
                                              units.
                                              Gas 1 (NG/RG) units....           21          118          0.9  0.01.........................           85
                                             Gas 1 Metallurgical               0.4            3         0.02  0.001........................           23
                                              Furnaces.
                                             Gas 2 (other) units.....            4           11         0.07  0.004 to 0.005...............          138
--------------------------------------------------------------------------------------------------------------------------------------------------------
New Units..................................  Solid units.............            0        1,462           19  0.01.........................            0
                                             Liquid units............            0            0            0  0............................            0
                                             Gas 1 units.............            0            0            0  0............................            0
                                             Gas 1 Metallurgical                 0            0            0  0............................            0
                                              Furnaces.
                                             Gas 2 (other) units.....            0            0            0  0............................            0
--------------------------------------------------------------------------------------------------------------------------------------------------------

\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\Hg reductions are presented as a range due to adjustments on reported fractions and limits of detection. See memorandum entitled ``Revised (November
  2011) Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission
  Standards for Hazardous Air Pollutants--Major Source'' for a description of the two methods for estimating Hg reductions.

B. What are the water and solid waste impacts?

    The EPA estimated the additional water usage that would result from
installing wet scrubbers to meet the emission limits for HCl would be
1.2 billion gallons per year for existing sources and 0 gallons per
year for new sources. In addition to the increased water usage, an
additional 416 million gallons per year of wastewater would be produced
for existing sources and 0 gallons per year for new sources. The annual
costs of treating the additional wastewater are $2.3 million for
existing sources and $0 for new sources. These costs are accounted for
in the control costs estimates.
    The EPA estimated the additional solid waste that would result from
the MACT floor level of control to be 286,000 tons per year for
existing sources and 1,700 tons per year for new sources. Solid waste
is generated from flyash and dust captured in PM and Hg controls as
well as from spent carbon that is injected into exhaust streams or used
to filter gas streams. The costs of handling the additional solid waste
generated are $12.0 million for existing sources and $70,600 for new
sources. These costs are also accounted for in the control costs
estimates.
    A discussion of the methodology used to estimate impacts is
presented in ``Revised (November 2011) Methodology for Estimating Cost
and Emission Impacts for Industrial, Commercial, and Institutional
Boilers and Process Heaters NESHAP--Major Source'' in the Docket.

C. What are the energy impacts?

    The EPA expects an increase of approximately 1.5 billion kilowatt
hours (kWh) in national annual energy usage as a result of the proposed
rule. Of this amount, 1.4 billion kWh would be from existing sources
and 120 million kWh from new sources. The increase results from the
electricity required to operate control devices, such as wet scrubbers,
electrostatic precipitators, and fabric filters which are expected to
be installed to meet the proposed rule. Additionally, the EPA expects
work practice standards such as boilers tune-ups and combustion
controls will improve the efficiency of boilers, resulting in an
estimated fuel savings of 47.3 trillion BTU each year from existing
sources. The EPA did not estimate fuel savings and efficiency
improvements on new boilers since new boilers are expected to be tuned-
up up upon installation and will not achieve additional fuel savings in
the first year. This fuel savings estimate includes only those fuel
savings resulting from Gas 1, liquid, and coal fuels and it is based on
the assumption that the work practice standards will achieve 1 percent
improvement in efficiency.

D. What are the cost impacts?

    To estimate the national cost impacts of the proposed rule for
existing sources, we developed average baseline emission factors for
each fuel type/control device combination based on the emission data
obtained and contained in the Boiler MACT emission database. If a unit
reported emission data, we assigned its unit-specific emission data as
its baseline emissions. For units that did not report emission data, we
assigned the appropriate emission factors to each existing unit in the
inventory database, based on the average emission factors for boilers
with similar fuel, design, and control devices. We then compared each
unit's baseline emission factors to the proposed MACT floor emission
limit to determine if control devices were needed to meet the emission
limits. The control analysis considered fabric filters and activated
carbon injection to be the primary control devices for Hg control;
electrostatic precipitators for units meeting Hg limits but requiring
additional control to meet the PM or total selected metals limits; wet
scrubbers or fabric filters with dry injection to meet the HCl limits;
tune-ups, replacement burners, combustion controls, and oxidation
catalysts for CO and organic HAP control; and tune-ups for dioxin/furan
control. We identified where one control device could achieve
reductions in multiple pollutants, for example a fabric filter was
expected to achieve both PM and Hg control, in order to avoid
overestimating the costs. We also included costs for testing and
monitoring requirements contained in the proposed rule. The resulting
total national cost impact of the proposed rule is 5.4 billion dollars
in capital expenditures and 1.9 billion dollars per year in total
annual costs. Considering estimated fuel savings resulting from work
practice standards and combustion controls, the total annualized costs
are reduced to 1.5 billion dollars. The total capital and annual costs
include costs for control devices, work practices, testing and
monitoring. While these

costs are higher than the costs estimated for the final rule, these
estimates are based on an inventory that includes 300 additional units
that were identified after the final rule was completed. The costs
associated with the final rule inventory are just under $5.0 billion in
capital expenditures and $1.75 billion in total annual costs ($1.35
billion considering fuel savings). Table 5 of this preamble shows the
capital and annual cost impacts for each subcategory. Costs include
testing and monitoring costs, but not recordkeeping and reporting
costs.

                    Table 5--Summary of Capital and Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Testing and     Annualized
                                                    Estimated/                      monitoring    cost(10 \6\ $/
            Source                 Subcategory       Projected     Capital costs    annualized          yr)
                                                     number of      (10 \6\ $)     costs (10 \6\   (considering
                                                  affected units                       $/yr)       fuel savings)
----------------------------------------------------------------------------------------------------------------
Existing Units................  Coal units......             616           2,713              46             953
                                Biomass units...             508             639              33             169
                                Heavy Liquid                 322             769             8.4             264
                                 units.
                                Light Liquid                 581             930             5.1             277
                                 units.
                                Non-Continental               44             181             1.5              42
                                 Liquid units.
                                Gas 1 (NG/RG)             11,911              77             0.9           (295)
                                 units.
                                Gas 2 (other)                129             132             2.3              55
                                 units.
Energy Assessment.............  ALL.............           1,704             N/A             N/A              28
                                                    (Facilities)
New Units.....................  Coal units......               0               0               0               0
                                Biomass units...              82             381             5.6          \a\ 99
                                Liquid units....               0               0               0               0
                                Gas 1 (NG/RG)              1,762              11               0         \a\ 5.1
                                 units.
                                Gas 2 (other)                  0               0               0               0
                                 units.
----------------------------------------------------------------------------------------------------------------
\a\ Total annualized costs for new units do not account for fuel savings since no fuel savings are estimated in
  the first year for new units.

    Using Department of Energy projections on fuel expenditures, the
number of additional boilers that could be potentially constructed was
estimated. The resulting total national cost impact of the proposed
rule for new boilers in the 3rd year is 393 million dollars in capital
expenditures and 104 million dollars per year in total annual costs.
    Potential control device cost savings and increased recordkeeping
and reporting costs associated with the emissions averaging provisions
in the proposed rule are not accounted for in either the capital or
annualized cost estimates.
    A discussion of the methodology used to estimate cost impacts is
presented in ``Revised (November 2011) Methodology for Estimating Cost
and Emission Impacts for Industrial, Commercial, and Institutional
Boilers and Process Heaters NESHAP--Major Source'' in the Docket.

E. What are the economic impacts?

    The EPA analyzed the economic impacts of this proposed rule using
the methodology that was discussed in the final rule RIA and in the
preamble to the final rule. See FR 76 15651. The market impact results
are very similar to the results presented in the final rule and the
RIA. The agency's economic model suggests the average national price
increases for industrial sectors are less than 0.01 percent, while
average annual domestic production may fall by less than 0.01 percent.
Because of higher domestic prices, imports slightly rise. The increase
in US trade deficit is now 1.93 billion dollars (2006$). For the RIA,
it was 1.86 billion dollars (2006$). The results for sales tests for
small businesses were somewhat reduced. For the sales tests using small
companies identified in the Combustion Survey, the mean cost to
receipts dropped from 4 percent in the RIA to 2 percent for this
proposed rule and the median was 0.2 percent for both. The number of
parent companies with sales tests exceeding 3 percent dropped from 8 in
the RIA to 6 for this proposed rule. There was no change in the results
for small public entities. Median cost is still about $1.1 million and
representative small major public entities would have cost-to-revenue
ratios above 10 percent. The change in employment estimates between the
RIA and the proposal is minimal. In the RIA for the final rule, we
estimated employment changes ranging between -3100 to +6,500 employees,
with a central estimate of +1,700. For this proposal, we estimate
employment changes ranging between -3000 to +6,300 employees, with a
central estimate of +1,600. These estimated annual employment changes
compared to the baseline employment, and are for the time period for
which the annualized cost applies (2015 to 2029).
    The benefits estimates increased for this proposal. In the RIA for
the final rule, we estimated benefits ranging from $22 billion (2008$)
to 54 billion (2008$) at a 3 percent discount rate. For this proposal,
we estimate benefits ranging from $27 billion (2008$) to 67 billion
(2008$) at a 3 percent discount rate. The range for the RIA was $20
billion (2008$) to 49 billion (2008$) at a 7 percent discount rate. The
range for this proposal is $25 billion (2008$) to 61 billion (2008$) at
a 7 percent discount rate.

F. What are the benefits of this proposed rule?

    We calculated health benefits using the methodology described in
the RIA prepared for the March 21, 2011, final rule. We incorporated
the revised emission reductions estimated for this reconsideration
proposal into the analysis. We were unable to estimate the benefits
from reducing exposure to HAP and ozone, ecosystem impairment, and
visibility impairment, including reducing 187,000 tons of carbon
monoxide, 37,000 tons of HCl, 1,000 tons of HF, 1,000 to 3,600 pounds
of Hg, and 2,200 tons of other metals. Please refer to the full
description in the final Boiler RIA of the unquantified benefits as
well as technical details of the analysis and its limitations and
uncertainties. These monetized benefits are approximately 23 percent
higher than the final rule benefits due to the increase in
SO2 emission reductions associated with the additional units
affected by the rule and the revised HCl limit. We estimate the total
monetized benefits of this proposed regulatory action to be $27 billion
to $67 billion (2008$, 3 percent discount rate) in the implementation
year (2015). A summary

of the monetized benefits estimates at discount rates of 3 percent and
7 percent is provided in Table 6 of this preamble. A summary of the
avoided health incidences is provided in Table 7 of this preamble.

                 Table 6--Summary of the Monetized Benefits Estimates for the Final Boiler MACT
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                    Emissions      Total monetized
           Pollutant               reductions      benefits (at 3%     Total monetized benefits (at 7% discount
                                     (tons)        discount rate)                       rate)
----------------------------------------------------------------------------------------------------------------
PM2.5-related benefits:
Direct PM2.5...................          25,601  $1,800 to $4,500..  $1,700 to $4,100.
SO2............................         558,430  $25,000 to $63,000  $23,000 to $57,000.
                                =================
    Total......................      $27,000 to  $25,000 to
                                        $67,000   $61,000..
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are rounded to two significant figures so numbers
  may not sum across rows. All fine particles are assumed to have equivalent health effects. Benefits from
  reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy disbenefits
  valued at $5.8 to $75 million depending on the discount rate. These benefits reflect existing boilers and new
  boilers anticipated to come online by 2015.

 Table 7--Summary of the Avoided Health Incidences for the Final Boiler
                                MACT \1\
------------------------------------------------------------------------
                                                          Avoided health
                                                            incidences
------------------------------------------------------------------------
Avoided Premature Mortality.............................     3,100-8,000
Avoided Morbidity.......................................  ..............
Chronic Bronchitis......................................           2,000
Acute Myocardial Infarction.............................           4,900
Hospital Admissions, Respiratory........................             750
Hospital Admissions, Cardiovascular.....................           1,600
Emergency Room Visits, Respiratory......................           3,000
Acute Bronchitis........................................           4,600
Work Loss Days..........................................         390,000
Asthma Exacerbation.....................................          51,000
Minor Restricted Activity Days..........................       2,300,000
Lower Respiratory Symptoms..............................          55,000
Upper Respiratory Symptoms..............................          41,000
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
  rounded to two significant figures. All fine particles are assumed to
  have equivalent health effects. Benefits from reducing HAP are not
  included. These benefits reflect existing boilers and new boilers
  anticipated to come online by 2015.

G. What are the secondary air impacts?

    For units adding controls to meet the proposed emission limits, we
anticipate very minor secondary air impacts. The combustion of fuel
needed to generate additional electricity would yield slight increases
in emissions, including nitrogen oxide (NOX), CO and
SO2 and an increase in carbon dioxide (CO2)
emissions. Since NOX and SO2 are covered by
capped emissions trading programs, these pollutants do not contribute
disbenefits from additional electricity demand. Additional
CO2 emissions from increased electricity consumption are
estimated to be 931,000 tons per year from existing units and 79,700
tons per year from new units. Energy disbenefits due to increased
CO2 emissions range from $5.8 million to $75 million
depending on the discount rate, and thus do not affect the rounded
monetized benefits.

VIII. Relationship of This Proposed Action to Section 112(c)(6) of the
Clean Air Act

    Section 112(c)(6) of the CAA requires the EPA to identify
categories of sources of seven specified pollutants to assure that
sources accounting for not less than 90 percent of the aggregate
emissions of each such pollutant are subject to standards under CAA
Section 112(d)(2) or 112(d)(4). The EPA has identified ``Industrial
Coal Combustion,'' ``Industrial Oil Combustion,'' Industrial Wood/Wood
Residue Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil
Combustion'' and ``Commercial Wood/Wood Residue Combustion'' as source
categories that emit two of the seven CAA Section 112(c)(6) pollutants:
polycyclic organic matter (POM) and Hg. (The POM emitted is composed of
16 polyaromatic hydrocarbons and extractable organic matter.) In the
Federal Register notice Source Category Listing for Section 112(d)(2)
Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838,
17849, Table 2 (1998), the EPA identified ``Industrial Coal
Combustion,'' ``Industrial Oil Combustion,'' ``Industrial Wood/Wood
Residue Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil
Combustion'' and ``Commercial Wood/Wood Residue Combustion'' as source
categories ``subject to regulation'' for purposes of CAA Section
112(c)(6) with respect to the CAA Section 112(c)(6) pollutants that
these units emit.
    For Hg, the 112(c)(6) requirement is directly met through the
proposed emission limits for Hg. Through these emission limits, the
types of boilers and process heaters listed in section 112(c)(6) are
subject to regulation.
    For POM, which are byproducts of combustion, the formation of POM
is effectively reduced by the combustion and post-combustion practices
required to comply with the CAA Section 112 standards. The tune-up
requirement for all major source units and the CO emission limits will
ensure that good combustion practices are followed, thus minimizing
emissions of organic HAP, including POM. Any POM that do form

during combustion would be reduced by the various post-combustion
controls. The add-on PM control systems (either fabric filter or wet
scrubber) and activated carbon injection in the fabric filter-based
systems would reduce emissions of these organic pollutants. It is,
therefore, reasonable to conclude that POM emissions will be
substantially controlled. Thus, while this final rule does not identify
specific numerical emission limits for POM, emissions of POM are, for
the reasons noted below, nonetheless ``subject to regulation'' for
purposes of Section 112(c)(6) of the CAA. In lieu of establishing
numerical emissions limits for pollutants such as POM, we regulate
surrogate substances. While we have not identified specific numerical
limits for POM, CO serves as an effective surrogate for this HAP,
because CO, like POM, is formed as a byproduct of combustion, and both
would increase with an increase in the level of incomplete combustion.
Consequently, we have concluded that the emissions limits for CO
function as a surrogate for control of POM, such that it is not
necessary to require numerical emissions limits for POM with respect to
boilers and process heaters to satisfy CAA Section 112(c)(6).
    To further address POM and Hg emissions, this final rule also
includes an energy assessment provision that encourage modifications to
the facility to reduce energy demand that lead to these emissions.

IX. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    Under section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more or adversely affect in a material
way the economy, a sector of the economy, productivity, competition,
jobs, the environment, public health or safety, or State, local, or
tribal governments or communities. Accordingly, the EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
    Because this action is proposing changes to a final rule and does
not increase costs by an amount that would qualify the proposed rule,
by itself, as a major rule, the EPA did not prepare a new RIA for this
action. Instead, the EPA prepared an assessment of the changes in the
costs and benefits of this proposed rule compared to the costs and
benefits associated with the March 21, 2011, final rule. Overall, the
costs and impacts are estimated to be similar to the costs and impacts
associated with the final rule, although the distribution is somewhat
different and the number of affected units in the inventory has
increased by about 300 units. When comparing the costs using only those
sources that were part of the final rule inventory, the costs have
decreased. The EPA re-ran the multimarket model to assess changes in
economic impacts, and this analysis confirmed that the overall economic
impacts are similar to the final rule. The benefits are projected to
increase by about 23 percent because of the increase in the estimated
SO2 reductions. A summary of the costs and benefits of the
final rule is provided in the preamble to the final rule (see 76 FR
15658) and the detailed analysis for the final rule is provided in the
RIA for the final rule. In addition, memoranda are provided in the
docket to document the changes in costs, economic impacts, and benefits
associated with this proposed rule.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule will
be submitted for approval to the OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by the EPA has been assigned EPA ICR number 2028.07.
The information collection requirements are not enforceable until OMB
approves them.
    The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the CAA (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to agency
policies set forth in 40 CFR part 2, subpart B.
    This proposed rule would require maintenance inspections of the
control devices but would not require any notifications or reports
beyond those required by the General Provisions aside from a
notification of intent to commence burning solid waste materials and
notification of alternative fuel use for those units that are in the
Gas 1 subcategory but burn liquid fuels for periodic testing, or during
periods of gas curtailment or gas supply emergencies. The recordkeeping
requirements require only the specific information needed to determine
compliance. The annual monitoring, reporting, and recordkeeping burden
for this collection (averaged over the first 3 years after the
effective date of the standards) is estimated to be $96.2 million. This
includes 324,954 labor hours per year at a total labor cost of $30.7
million per year, and total non-labor capital costs of $65.5 million
per year. This estimate includes initial and annual performance test,
conducting an documenting an energy assessment, conducting fuel
specifications for Gas 1 units, repeat testing under worst-case
conditions for solid fuel units, conducting and documenting a tune-up,
semiannual excess emission reports, maintenance inspections, developing
a monitoring plan, notifications, and recordkeeping. Monitoring,
testing, tune-up and energy assessment costs and cost were also
included in the cost estimates presented in the control costs impacts
estimates in section VII.D of this preamble. The total burden for the
Federal government (averaged over the first 3 years after the effective
date of the standard) is estimated to be 97,613 hours per year at a
total labor cost of $5.1 million per year. Burden is defined at 5 CFR
1320.3(b).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2002-0058. Submit any comments related to the ICR to the EPA and
OMB. See ADDRESSES section at the beginning of this notice for where to
submit comments to the EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after December 23, 2011, a comment to OMB

is best assured of having its full effect if OMB receives it by January
23, 2012. The final rule will respond to any OMB or public comments on
the information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities.\3\ The RFA also allows an agency to
``consider a series of closely related rules as one rule for the
purposes of sections'' 603 (initial regulatory flexibility analysis)
and 604 (final regulatory flexibility analysis) in order to avoid
``duplicative action.'' 5 U.S.C. 605(c). This proposed rule is closely
related to the final major source rule, which the EPA signed on
February 21, 2011. The EPA prepared initial regulatory flexibility
analyses in connection with the major source rule. Therefore, pursuant
to Sec.  605(c), the EPA is not required to complete an initial
regulatory flexibility analysis for this rule.
---------------------------------------------------------------------------

    \3\ Small entities include small businesses, small
organizations, and small governmental jurisdictions. For purposes of
assessing the impacts of today's rule on small entities, small
entity is defined as: (1) A small business according to Small
Business Administration (SBA) size standards by the North American
Industry Classification System category of the owning entity. The
range of small business size standards for the affected industries
ranges from 500 to 1,000 employees, except for petroleum refining
and electric utilities. In these latter two industries, the size
standard is 1,500 employees and a mass throughput of 75,000 barrels/
day or less, and 4 million kilowatt-hours of production or less,
respectively; (2) a small governmental jurisdiction that is a
government of a city, county, town, school district or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
---------------------------------------------------------------------------

    The EPA has been concerned with potential small entity impacts
since it began developing the major source rule. The EPA conducted
outreach to small entities and, pursuant to Sec.  609 of RFA, convened
a Small Business Advocacy Review Panel to obtain advice and
recommendations from small entity representatives.
    Pursuant to the RFA, the EPA used the Panel's report and prepared
both an initial regulatory flexibility analysis and a final regulatory
flexibility analysis in connection with the closely related major
source rule. Convening an additional Panel and preparing an additional
initial regulatory flexibility analysis would be procedurally
duplicative and is unnecessary given that the issues here are within
the scope of those considered by the Panel. In addition, this
reconsideration proposal would decrease capital and annualized costs on
small entities by about 3 percent and 10 percent, respectively,
relative to the closely related final rule. We invite comments on the
aspects of the proposal outlined in section V of this preamble and
their impacts on small entities.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
state, local, and tribal governments and the private sector. This March
21, 2011, final rule contained a federal mandate that may result in
expenditures of $100 million or more for state, local, and tribal
governments, in the aggregate, or the private sector in any one year.
Accordingly, the EPA prepared under section 202 of the UMRA a written
statement for the final rule. The discussion below has been updated to
reflect the proposed changes.
1. Statutory Authority
    As discussed in section I of this preamble, the statutory authority
for this proposed rulemaking is section 112 of the CAA. Title III of
the CAA Amendments was enacted to reduce nationwide air toxic
emissions. Section 112(b) of the CAA lists the 188 chemicals,
compounds, or groups of chemicals deemed by Congress to be HAP. These
toxic air pollutants are to be regulated by NESHAP.
    Section 112(d) of the CAA directs us to develop NESHAP which
require existing and new major sources to control emissions of HAP
using MACT based standards. This NESHAP applies to all ICI boilers and
process heaters located at major sources of HAP emissions.
2. Social Costs and Benefits
    The regulatory impact analysis prepared for the final rule, which
we have not revised for this proposed rule, including the agency's
assessment of costs and benefits, is detailed in the ``Regulatory
Impact Analysis for the Final Industrial Boilers and Process Heaters
MACT (2011)'' in the docket. Based on estimated compliance costs
associated with this proposed rule and the predicted change in prices
and production in the affected industries, the estimated social costs
of this proposed rule are $1.49 billion (2008 dollars).
    It is estimated that 3 years after implementation of this proposed
rule, HAP would be reduced by 45,000 tons per year, including
reductions in HCl, hydrogen fluoride, metallic HAP including Hg, and
several other organic HAP from boilers and process heaters. Studies
have determined a relationship between exposure to these HAP and the
onset of cancer, however, the agency is unable to provide a monetized
estimate of the HAP benefits at this time. In addition, there are
significant annual reductions in fine particulate matter
(PM2.5) and in SO2 that would occur, including
25,000 thousand tons of PM2.5 and 558 thousand tons of
SO2. These reductions occur within 3 years after the
implementation of the proposed regulation and are expected to continue
throughout the life of the affected sources. The major health effect
associated with reducing PM2.5 and PM2.5
precursors (such as SO2) is a reduction in premature
mortality. Other health effects associated with PM2.5
emission reductions include avoiding cases of chronic bronchitis, heart
attacks, asthma attacks, and work-lost days (i.e., days when employees
are unable to work). While we are unable to monetize the benefits
associated with the HAP emissions reductions, we are able to monetize
the benefits associated with the PM2.5 and SO2
emissions reductions. For SO2 and PM2.5, we
estimated the benefits associated with health effects of PM but were
unable to quantify all categories of benefits (particularly those
associated with ecosystem and visibility effects). Our estimates of the
monetized benefits in 2015 associated with the implementation of the
proposed alternative range from $27 billion (2008 dollars) to $67
billion (2008 dollars) when using a 3 percent discount rate (or from
$25 billion (2008 dollars) to $61 billion (2008 dollars) when using a 7
percent discount rate). This estimate, at a 3 percent discount rate, is
about $25 billion (2008 dollars) to $65 billion (2008 dollars) higher
than the estimated social costs shown earlier in this section. The
general approach used to value benefits is discussed in more detail
earlier in this preamble. For more detailed information on the benefits
estimated for the rulemaking, refer to the RIA and the memos updating
the impacts and benefits in the docket.
3. Future and Disproportionate Costs
    The UMRA requires that we estimate, where accurate estimation is
reasonably feasible, future compliance costs imposed by this proposed
rule and any

disproportionate budgetary effects. Our estimates of the future
compliance costs of the rule are discussed previously in this preamble.
    We do not believe that there will be any disproportionate budgetary
effects of this proposed rule on any particular areas of the country,
state or local governments, types of communities (e.g., urban, rural),
or particular industry segments. See the results of the ``Regulatory
Impact Analysis for the Final Industrial Boilers and Process Heaters
MACT (2011).''
4. Effects on the National Economy
    The UMRA requires that we estimate the effect of this proposed rule
on the national economy. To the extent feasible, we must estimate the
effect on productivity, economic growth, full employment, creation of
productive jobs, and international competitiveness of the U.S. goods
and services, if we determine that accurate estimates are reasonably
feasible and that such effect is relevant and material.
    The nationwide economic impact of this proposed rule is presented
in the ``Regulatory Impact Analysis for the Final Industrial Boilers
and Process Heaters MACT (2011)'' and two memoranda that are included
in the docket, entitled ``Health Benefits for Boiler MACT
Reconsideration Proposal'' and ``Regulatory Impact Results for the
Reconsideration Proposal for National Emission Standards for Hazardous
Air Pollutants for Industrial, Commercial, and Institutional Boilers
and Process Heaters at Major Sources,'' which update the RIA analyses.
This analysis provides estimates of the effect of this rule on some of
the categories mentioned above. The results of the economic impact
analysis are summarized previously in this preamble. The results show
that there will be a small impact on prices and output, and little
impact on communities that may be affected by this proposed rule. In
addition, there should be little impact on energy markets (in this
case, coal, natural gas, petroleum products, and electricity). Hence,
the potential impacts on the categories mentioned above should be
small.
5. Consultation With Government Officials
    The UMRA requires that we describe the extent of the agency's prior
consultation with affected state, local, and tribal officials,
summarize the officials' comments or concerns, and summarize our
response to those comments or concerns. In addition, section 203 of the
UMRA requires that we develop a plan for informing and advising small
governments that may be significantly or uniquely impacted by a
proposal. We consulted with State and local air pollution control
officials during the development of the final rule. We have also held
meetings on this proposed rule with many of the stakeholders from
numerous individual companies, institutions, environmental groups,
consultants and vendors, labor unions, and other interested parties. We
have added materials to the docket to document these meetings.
    Consistent with section 205, the EPA has identified and considered
a reasonable number of regulatory alternatives. Additional information
on the costs and environmental impacts of these regulatory alternatives
is presented in the docket. The regulatory alternative upon which the
emission limits in this proposed rule are based represents the MACT
floors for all subcategories and, as a result, it is the least costly
and least burdensome alternative.
    This rule is not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments. While some small governments may
have some sources affected by this proposed rule, the impacts are not
expected to be significant. Therefore, this proposed rule is not
subject to the requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This proposed rule will not impose
direct compliance costs on state or local governments, and will not
preempt state law. Thus, Executive Order 13132 does not apply to this
action.
    In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between the EPA and state and local
governments, the EPA specifically solicits comment on this proposed
action from state and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial direct effects on tribal governments, on the relationship
between the federal government and Indian tribes, or on the
distribution of power and responsibilities between the federal
government and Indian tribes, as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
    The EPA specifically solicits additional comment on this proposed
action from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying only to those regulatory actions that concern health
or safety risks, such that the analysis required under section 5-501 of
the Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it is based
solely on technology performance.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. For the March 21, 2011, final rule, we
estimated a 0.05 percent price increase for the energy sector and a -
0.02 percent percentage change in production. We estimated a 0.09
percent increase in energy imports. For more information on the
estimated energy effects, please refer to the ``Regulatory Impact
Analysis for the Final Industrial Boilers and Process Heaters MACT
(2011).'' The analysis is available in the public docket. While we did
not redo the RIA for this proposed action, the energy impacts for
existing sources decreased slightly, and the energy impacts for new
source increased due to the increased number of new sources that is now
projected. Overall, the projected energy use increased slightly but
would not change the analysis that was conducted for the final rule.
Therefore, we conclude that the proposed rule when implemented is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement

Act of 1995 (NTTAA), Public Law 104-113,(15 U.S.C. 272 note) directs
the EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs the EPA to provide
Congress, through OMB, explanations when the agency decides not use
available and applicable voluntary consensus standards. The EPA is not
proposing the use of any additional EPA test methods, and, therefore,
the NTTAA discussion in the March 21, 2011, final rule is still valid.
See 76 FR 15660-15662.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    For the March 2011 final rule, the EPA determined that rule would
not have disproportionately high and adverse human health or
environmental effects on minority or low-income populations because it
increases the level of environmental protection for all affected
populations without having any disproportionately high and adverse
human health or environmental effects on any population, including any
minority or low-income population. Compared to the final rule, while
the proposed amendments are somewhat less stringent for some
subcategories of units and more stringent for some others, the overall
increased health benefits demonstrate that the conclusions from the
environmental justice analysis conducted for the final rule are still
valid.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.

    Dated: December 2, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons cited in the preamble, and under the authority of
42 U.S.C. 7401 et seq., Subpart DDDDD of 40 CFR part 63 is proposed to
be revised to read as follows:

PART 63--[AMENDED]

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

Sec.

What This Subpart Covers

63.7480 What is the purpose of this subpart?
63.7485 Am I subject to this subpart?
63.7490 What is the affected source of this subpart?
63.7491 Are any boilers or process heaters not subject to this
subpart?
63.7495 When do I have to comply with this subpart?

Emission Limitations and Work Practice Standards

63.7499 What are the subcategories of boilers and process heaters?
63.7500 What emission limitations, work practice standards, and
operating limits must I meet?
63.7501 How can I assert an affirmative defense if I exceed an
emission limitations during a malfunction?

General Compliance Requirements

63.7505 What are my general requirements for complying with this
subpart?

Testing, Fuel Analyses, and Initial Compliance Requirements

63.7510 What are my initial compliance requirements and by what date
must I conduct them?
63.7515 When must I conduct subsequent performance tests, fuel
analyses, or tune-ups?
63.7520 What stack tests and procedures must I use?
63.7521 What fuel analyses, fuel specification, and procedures must
I use?
63.7522 Can I use emissions averaging to comply with this subpart?
63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission
limitations, fuel specifications and work practice standards?
63.7533 Can I use emission credits earned from implementation of
energy conservation measures to comply with this subpart?

Continuous Compliance Requirements

63.7535 Is there a minimum amount of monitoring data I must obtain?
63.7540 How do I demonstrate continuous compliance with the emission
limitations, fuel specifications and work practice standards?
63.7541 How do I demonstrate continuous compliance under the
emissions averaging provision?

Notification, Reports, and Records

63.7545 What notifications must I submit and when?
63.7550 What reports must I submit and when?
63.7555 What records must I keep?
63.7560 In what form and how long must I keep my records?

Other Requirements and Information

63.7565 What parts of the General Provisions apply to me?
63.7570 Who implements and enforces this subpart?
63.7575 What definitions apply to this subpart?

Tables to Subpart DDDDD of Part 63

Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or
Reconstructed Boilers and Process Heaters
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing
Boilers and Process Heaters (Units with heat input capacity of 10
million Btu per hour or greater)
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers
and Process Heaters
Table 5 to Subpart DDDDD of Part 63--Performance Testing
Requirements
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous
Compliance
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
Table 10 to Subpart DDDDD of Part 63--Applicability of General
Provisions to Subpart DDDDD

What This Subpart Covers

Sec.  63.7480  What is the purpose of this subpart?

    This subpart establishes national emission limitations and work
practice standards for hazardous air pollutants (HAP) emitted from
industrial, commercial, and institutional boilers and process heaters
located at major sources of HAP. This subpart also establishes
requirements to demonstrate initial and continuous compliance with the
emission limitations and work practice standards.

Sec.  63.7485  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler or process heater as
defined in Sec.  63.7575 that is located at, or is part of, a major
source of HAP, except as specified in

Sec.  63.7491. For purposes of this subpart, a major source of HAP is
as defined in Sec.  63.2, except that for oil and natural gas
production facilities, a major source of HAP is as defined in Sec.
63.761 (subpart HH of this part, National Emission Standards for
Hazardous Air Pollutants from Oil and Natural Gas Production
Facilities).

Sec.  63.7490  What is the affected source of this subpart?

    (a) This subpart applies to new, reconstructed, and existing
affected sources as described in paragraphs (a)(1) and (2) of this
section.
    (1) The affected source of this subpart is the collection at a
major source of all existing industrial, commercial, and institutional
boilers and process heaters within a subcategory as defined in Sec.
63.7575.
    (2) The affected source of this subpart is each new or
reconstructed industrial, commercial, or institutional boiler or
process heater, as defined in Sec.  63.7575, located at a major source.
    (b) A boiler or process heater is new if you commence construction
of the boiler or process heater after June 4, 2010, and you meet the
applicability criteria at the time you commence construction.
    (c) A boiler or process heater is reconstructed if you meet the
reconstruction criteria as defined in Sec.  63.2, you commence
reconstruction after June 4, 2010, and you meet the applicability
criteria at the time you commence reconstruction.
    (d) A boiler or process heater is existing if it is not new or
reconstructed.

Sec.  63.7491  Are any boilers or process heaters not subject to this
subpart?

    The types of boilers and process heaters listed in paragraphs (a)
through (n) of this section are not subject to this subpart.
    (a) An electric utility steam generating unit.
    (b) A recovery boiler or furnace covered by subpart MM of this
part.
    (c) A boiler or process heater that is used specifically for
research and development. This does not include units that provide heat
or steam to a process at a research and development facility.
    (d) A hot water heater as defined in this subpart.
    (e) A refining kettle covered by subpart X of this part.
    (f) An ethylene cracking furnace covered by subpart YY of this
part.
    (g) Blast furnace stoves as described in EPA-453/R-01-005
(incorporated by reference, see Sec.  63.14).
    (h) Any boiler or process heater that is part of the affected
source subject to another subpart of this part (i.e., another National
Emission Standards for Hazardous Air Pollutants in 40 CFR part 63).
    (i) Any boiler or process heater that is used as a control device
to comply with another subpart of this part, or part 60 or part 61 of
this chapter provided that at least 50 percent of the heat input to the
boiler or process heater is provided by the gas stream that is
regulated under another subpart.
    (j) Temporary boilers as defined in this subpart.
    (k) Blast furnace gas fuel-fired boilers and process heaters as
defined in this subpart.
    (l) Any boiler specifically listed as an affected source in any
standard(s) established under section 129 of the Clean Air Act.
    (m) A unit that burns hazardous waste covered by Subpart EEE of
this part. A unit that is exempt from Subpart EEE as specified in Sec.
63.1200(b) is not covered by Subpart EEE.
    (n) Residential boilers as defined in this subpart.

Sec.  63.7495  When do I have to comply with this subpart?

    (a) If you have a new or reconstructed boiler or process heater,
you must comply with this subpart by [DATE 60 DAYS AFTER THE FINAL RULE
IS PUBLISHED IN THE Federal Register] or upon startup of your boiler or
process heater, whichever is later.
    (b) If you have an existing boiler or process heater, you must
comply with this subpart no later than [DATE 3 YEARS AFTER PUBLICATION
OF THE FINAL RULE IN THE Federal Register], except as provided in Sec.
63.6(i).
    (c) If you have an area source that increases its emissions or its
potential to emit such that it becomes a major source of HAP,
paragraphs (c)(1) and (2) of this section apply to you.
    (1) Any new or reconstructed boiler or process heater at the
existing source must be in compliance with this subpart upon startup.
    (2) Any existing boiler or process heater at the existing source
must be in compliance with this subpart within 3 years after the source
becomes a major source.
    (d) You must meet the notification requirements in Sec.  63.7545
according to the schedule in Sec.  63.7545 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limits and work practice standards
in this subpart.
    (e) If you own or operate an industrial, commercial, or
institutional boiler or process heater and would be subject to this
subpart except for the exemption in Sec.  63.7491(l) for commercial and
industrial solid waste incineration units covered by part 60, subpart
CCCC or subpart DDDD, and you cease combusting solid waste, you must be
in compliance with this subpart on the effective date of the switch
from waste to fuel.

Emission Limitations and Work Practice Standards

Sec.  63.7499  What are the subcategories of boilers and process
heaters?

    The subcategories of boilers and process heaters, as defined in
Sec.  63.7575 are:
    (a) Pulverized coal/solid fossil fuel units.
    (b) Stokers designed to burn coal/solid fossil fuel.
    (c) Fluidized bed units designed to burn coal/solid fossil fuel.
    (d) Stokers/sloped grate/other units designed to burn kiln dried
biomass/bio-based solids.
    (e) Stokers/sloped grate/other units designed to burn wet biomass/
bio-based solids.
    (f) Fluidized bed units designed to burn biomass/bio-based solid.
    (g) Suspension burners designed to burn biomass/bio-based solid.
    (h) Dutch ovens/pile burners designed to burn biomass/bio-based
solid.
    (i) Fuel cells designed to burn biomass/bio-based solid.
    (j) Hybrid suspension/grate burners designed to burn wet biomass/
bio-based solid.
    (k) Units designed to burn solid fuel.
    (l) Units designed to burn liquid fuel.
    (m) Units designed to burn heavy liquid fuel.
    (n) Units designed to burn light liquid fuel.
    (o) Units designed to burn liquid fuel in non-continental states or
territories.
    (p) Units designed to burn natural gas, refinery gas or other gas 1
fuels.
    (q) Units designed to burn gas 2 (other) gases.
    (r) Metal process furnaces.
    (s) Limited-use boilers and process heaters.

Sec.  63.7500  What emission limitations, work practice standards, and
operating limits must I meet?

    (a) You must meet the requirements in paragraphs (a)(1) through (3)
of this section, except as provided in paragraphs (b), (c), and (d) of
this section. You must meet these requirements at all times, except as
provided in paragraph (e) of this section.
    (1) You must meet each emission limit and work practice standard in

Tables 1 through 3 to this subpart that applies to your boiler or
process heater, for each boiler or process heater at your source,
except as provided under Sec.  63.7522. The output-based emission
limits (i.e., in units of pounds per million Btu of steam output) in
Tables 1 or 2 to this subpart are an alternative applicable only to
boilers that generate steam. The output-based emission limits are not
applicable to process heaters that do not generate steam.
    (2) You must meet each operating limit in Table 4 to this subpart
that applies to your boiler or process heater. If you use a control
device or combination of control devices not covered in Table 4 to this
subpart, or you wish to establish and monitor an alternative operating
limit and alternative monitoring parameters, you must apply to the EPA
Administrator for approval of alternative monitoring under Sec.
63.8(f).
    (3) At all times, you must operate and maintain any affected
source, including associated air pollution control equipment and
monitoring equipment, in a manner consistent with safety and good air
pollution control practices for minimizing emissions. Determination of
whether such operation and maintenance procedures are being used will
be based on information available to the Administrator that may
include, but is not limited to, monitoring results, review of operation
and maintenance procedures, review of operation and maintenance
records, and inspection of the source.
    (b) As provided in Sec.  63.6(g), EPA may approve use of an
alternative to the work practice standards in this section.
    (c) Limited-use boilers and process heaters must complete a
biennial tune-up as specified in Sec.  63.7540. They are not subject to
the emission limits in Tables 1 and 2 to this subpart, the annual tune-
up requirement in Table 3 to this subpart, or the operating limits in
Table 4 to this subpart. Major sources that have limited-use boilers
and process heaters must complete an energy assessment as specified in
Table 3 to this subpart if the source has other existing boilers
subject to this subpart that are not limited-use boilers.
    (d) Boilers and process heaters with a heat input capacity of less
than 5 million Btu per hour in the units designed to burn natural gas,
refinery gas or other gas 1 fuels subcategory; units designed to burn
gas 2 (other) fuels subcategory, or units designed to burn light liquid
fuels subcategory must complete a tune-up every 5 years as specified in
Sec.  63.7540.
    (e) These standards apply at all times, except during periods of
startup and shutdown, during which time you must comply only with Table
3 to this subpart.

Sec.  63.7501  How can I assert an affirmative defense if I exceed an
emission limitations during a malfunction?

    In response to an action to enforce the emission limitations and
operating limits set forth in Sec.  63.7500 you may assert an
affirmative defense to a claim for civil penalties for exceeding such
standards that are caused by malfunction, as defined at Sec.  63.2.
Appropriate penalties may be assessed, however, if you fail to meet
your burden of proving all of the requirements in the affirmative
defense. The affirmative defense shall not be available for claims for
injunctive relief.
    (a) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
paragraph (b) of this section, and must prove by a preponderance of
evidence that:
    (1) The excess emissions:
    (i) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner, and
    (ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
    (iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
    (iv) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
    (3) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
    (4) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
    (5) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment and human
health; and
    (6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
    (7) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
    (8) At all times, the facility was operated in a manner consistent
with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
    (b) Notification. The owner or operator of the facility
experiencing an exceedance of its emission limitation(s) during a
malfunction shall notify the Administrator by telephone or facsimile
(fax) transmission as soon as possible, but no later than 2 business
days after the initial occurrence of the malfunction, if it wishes to
avail itself of an affirmative defense to civil penalties for that
malfunction. The owner or operator seeking to assert an affirmative
defense shall also submit a written report to the Administrator within
45 days of the initial occurrence of the exceedance of the standard in
Sec.  63.7500 to demonstrate, with all necessary supporting
documentation, that it has met the requirements set forth in paragraph
(a) of this section. The owner or operator may seek an extension of
this deadline for up to 30 additional days by submitting a written
request to the Administrator before the expiration of the 45-day
period. Until a request for an extension has been approved by the
Administrator, the owner or operator is subject to the requirement to
submit such report within 45 days of the initial occurrence of the
exceedance.

General Compliance Requirements

Sec.  63.7505  What are my general requirements for complying with this
subpart?

    (a) You must be in compliance with the emission limits, work
practice standards, and operating limits in this subpart. These limits
apply to you at all times except for the periods noted in Sec.
63.7500(e).
    (b) [Reserved]
    (c) You must demonstrate compliance with all applicable emission
limits using performance testing, fuel analysis, or continuous
monitoring systems (CMS), including a continuous emissions monitoring
system (CEMS), continuous opacity monitoring system (COMS), continuous
parameter

monitoring system (CPMS), or particulate matter continuous parameter
monitoring system (PM CPMS), where applicable. You may demonstrate
compliance with the applicable emission limit for hydrogen chloride,
mercury, or total selected metals using fuel analysis if the emission
rate calculated according to Sec.  63.7530(c) is less than the
applicable emission limit. (For gaseous fuels, you may not use fuel
analyses to comply with the total selected metals alternative standard
or the hydrogen chloride standard.) Otherwise, you must demonstrate
compliance for hydrogen chloride, mercury, or total selected metals
using performance testing, if subject to an applicable emission limit
listed in Table 1 or 2 to this subpart.
    (d) If you demonstrate compliance with any applicable emission
limit through performance testing and subsequent compliance with
operating limits (including the use of CPMS), or with a CEMS, or COMS,
you must develop a site-specific monitoring plan according to the
requirements in paragraphs (d)(1) through (4) of this section for the
use of any CEMS, COMS, or CPMS. This requirement also applies to you if
you petition the EPA Administrator for alternative monitoring
parameters under Sec.  63.8(f).
    (1) For each CMS required in this section (including CEMS, COMS, or
CPMS), you must develop, and submit to the delegated authority for
approval upon request, a site-specific monitoring plan that addresses
design, data collection, and the quality assurance and quality control
elements outlined in Sec.  63.8(d) and the elements described in
paragraphs (d)(1)(i) through (iii) of this section. You must submit
this site-specific monitoring plan, if requested, at least 60 days
before your initial performance evaluation of your CMS. This
requirement to develop and submit a site specific monitoring plan does
not apply to affected sources with existing monitoring plans that apply
to CEMS and COMS prepared under appendix B to part 60 of this chapter
and that meet the requirements of Sec.  63.7525. Using the process
described in Sec.  63.8(f)(4), you may request approval of alternative
monitoring system quality assurance and quality control procedures in
place of those specified in this paragraph and, if approved, include
the alternatives in your site-specific monitoring plan.
    (i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
    (ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
    (iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations, accuracy audits, analytical drift).
    (2) In your site-specific monitoring plan, you must also address
paragraphs (d)(2)(i) through (iii) of this section.
    (i) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec.  63.8(c)(1)(ii), (c)(3), and
(c)(4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec.  63.10(c) (as applicable in Table
10 to this subpart), (e)(1), and (e)(2)(i).
    (3) You must conduct a performance evaluation of each CMS in
accordance with your site-specific monitoring plan.
    (4) You must operate and maintain the CMS in continuous operation
according to the site-specific monitoring plan.

Testing, Fuel Analyses, and Initial Compliance Requirements

Sec.  63.7510  What are my initial compliance requirements and by what
date must I conduct them?

    (a) For affected sources that are required to or elect to
demonstrate compliance with any of the applicable emission limits in
Tables 1 or 2 of this subpart through performance testing, your initial
compliance requirements include all the following:
    (1) Conduct performance tests according to Sec.  63.7520 and Table
5 to this subpart.
    (2) Conduct a fuel analysis for each type of fuel burned in your
boiler or process heater according to Sec.  63.7521 and Table 6 to this
subpart, except as specified in paragraphs (a)(2)(i) through (iii) of
this section.
    (i) For affected sources that burn a single type of fuel, you are
not required to conduct a fuel analysis for each type of fuel burned in
your boiler or process heater according to Sec.  63.7521 and Table 6 to
this subpart. For purposes of this subpart, units that use a
supplemental fuel only for startup, unit shutdown, and transient flame
stability purposes still qualify as affected sources that burn a single
type of fuel, and the supplemental fuel is not subject to the fuel
analysis requirements under Sec.  63.7521 and Table 6 to this subpart.
    (ii) When natural gas, refinery gas, other gas 1 fuels are co-fired
with other fuels, you are not required to conduct a fuel analysis of
those fuels according to Sec.  63.7521 and Table 6 to this subpart. If
gaseous fuels other than natural gas, refinery gas, or other gas 1
fuels are co-fired with other fuels and those gaseous fuels are subject
to another subpart of this part, you are not required to conduct a fuel
analysis of those fuels according to Sec.  63.7521 and Table 6 to this
subpart.
    (iii) You are not required to conduct a chlorine fuel analysis for
any gaseous fuels. You must still conduct a fuel analysis for mercury
on gaseous fuels unless the fuel is exempted in paragraphs (a)(2)(i)
through (iii) of this section.
    (3) Establish operating limits according to Sec.  63.7530 and Table
7 to this subpart.
    (4) Conduct CMS performance evaluations according to Sec.  63.7525.
    (b) For affected sources that elect to demonstrate compliance with
the applicable emission limits in Tables 1 or 2 of this subpart for
hydrogen chloride, mercury or total selected metals through fuel
analysis, your initial compliance requirement is to conduct a fuel
analysis for each type of fuel burned in your boiler or process heater
according to Sec.  63.7521 and Table 6 to this subpart and establish
operating limits according to Sec.  63.7530 and Table 8 to this
subpart. The fuels described in paragraph (a)(2)(i) through (iii) of
this section are exempt from these fuel analysis and operating limit
requirements. Boilers and process heaters that use a CEMS for mercury
or hydrogen chloride are exempt from the performance testing and
operating limit requirements specified in paragraph (a) of this
section.
    (c) If your boiler or process heater is subject to a carbon
monoxide limit, your initial compliance demonstration for carbon
monoxide is to conduct a performance test for carbon monoxide according
to Table 5 to this subpart, or conduct a performance evaluation of your
continuous carbon monoxide monitor, if applicable, according to Sec.
63.7525(a). Boilers and process heaters that use a continuous emission
monitoring system for carbon monoxide are exempt from the initial
carbon monoxide performance testing and oxygen concentration operating
limit requirements specified in paragraph (a) of this section.
    (d) If your boiler or process heater subject to a PM limit has an
average annual heat input rate greater than 250 MMBtu per hour from
solid fossil fuel and/or residual oil, your initial

compliance demonstration for PM is to conduct a performance test in
accordance with Sec.  63.7520 and Table 5 to this subpart. Owners of
boilers and process heaters who elect to comply with the alternative
total selected metals limit are not required to install a CPMS.
    (e) For existing affected sources, you must complete the initial
compliance demonstration, as specified in paragraphs (a) through (d) of
this section, no later than 180 days after the compliance date that is
specified for your source in Sec.  63.7495 and according to the
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this
subpart. You must complete an initial tune-up by following the
procedures described in Sec.  63.7540(a)(10)(i) through (vi) and
complete the one-time energy assessment specified in Table 3 to this
subpart, both no later than the compliance date specified in Sec.
63.7495.
    (f) For new or reconstructed affected sources, you must complete
the initial compliance demonstration with the emission limits no later
than [DATE 240 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE Federal
Register] or within 180 days after startup of the source, whichever is
later.
    (g) For new or reconstructed affected sources, you must demonstrate
initial compliance with the applicable work practice standards in Table
3 to this subpart no later than the compliance date that is specified
in Sec.  63.7595 and according to the applicable provisions in Sec.
63.7(a)(2). You must conduct the initial tune-up within 365 days after
startup of the source. Thereafter, you are required to complete the
applicable annual, biennial, or 5-year tune-up as specified in Sec.
63.7540(a).
    (h) For affected sources that ceased burning solid waste consistent
with Sec.  63.7495(e) and for which your initial compliance date has
passed, you must demonstrate compliance within 60 days of the effective