emissions potential when uncontrolled than the other sources in the
boiler area source categories, even those that are synthetic minor
sources that took operational limits to attain area source status.
    For these reasons, we believe that the additional public
participation and compliance benefits of additional informational,
monitoring, reporting, certification, and enforcement requirements that
exist in title V should be the same for a major source that installed a
control device after 1990 to become an area source as for a source that
is major and installed a control device to comply with an applicable
major source NESHAP, and thereby reduced emissions below major source
levels (10 tpy of a single HAP and 25 tpy of total HAP). Many of the
synthetic area sources that became area sources by virtue of installing
add-on controls are large facilities with comprehensive compliance
programs in place because their uncontrolled emissions would far exceed
the major source threshold. We maintain that requiring additional
public involvement and compliance assurance requirements through title
V is important to ensure that these sources are maintaining their
emissions at the area source level.
    For these reasons above, this proposed rule requires title V
permits for major sources of HAP emissions that installed controls
after 1990 to become area sources of HAP emissions. We estimate that
approximately 170 sources that will be subject to this rule are either
required to have title V permits because of criteria pollutants or the
proposed rule will require the affected area sources to obtain title V
permits.
    We are not requiring title V permits for sources that reduced their
emissions to area source levels by taking operational restrictions,
such as restricting hours of operation or production, or for natural
area sources, for the reasons set forth above.

VI. Summary of the Impacts of This Proposed Rule

A. What are the air impacts?

    Table 2 of this preamble illustrates, for each subcategory, the
estimated emissions reductions achieved by this proposed rule (i.e.,
the difference in emissions between an area source boiler controlled to
the MACT/GACT level of control and boilers at the current baseline) for
new and existing sources. Nationwide emissions of total HAP (hydrogen
chloride, hydrogen fluoride, non-mercury metals, mercury, and VOC (for
organic HAP) will be reduced by about 1,200 tpy for existing units and
340 tpy for new units. Emissions of mercury will be reduced by about
0.7 tpy per year for existing units and by 0.1 tpy for new units.
Emissions of filterable PM will be reduced by about 6,300 tpy for
existing units and 1,300 tpy 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 about 210 tpy
for existing units and will be reduced by 40 tpy for new units.
Additionally, EPA has estimated that conducting an annual tune-up could
potentially reduce emissions of organic HAP as a result of improved
combustion and reduced fuel use. POM reductions are represented by 7-
PAH, a group of polycyclic aromatic hydrocarbons. EPA estimates that
the energy efficient work and management practices may reduce emissions
of 7-PAH by 8 tpy for existing units and that the CO emission limit may
reduce emissions of 7-PAH by 1 tpy for new units. A discussion of the
methodology used to estimate baseline emissions and emissions
reductions is presented in ``Estimation of Impacts for Industrial,
Commercial, and Institutional Boilers Area Source NESHAP'' in the
docket.

                 Table 2--Summary of HAP Emissions Reductions for Existing and New Sources (tpy)
----------------------------------------------------------------------------------------------------------------
                                                                    Non mercury
            Source                 Subcategory          PM          metals \a\        Mercury         POM \b\
----------------------------------------------------------------------------------------------------------------
Existing Units................  Coal............           5,350              24          0.6               0.2
                                Biomass.........             760              10          0.003             5
                                Oil.............             230             175          0.03              3
New Units.....................  Coal............             510               3          0.09              0.02
                                Biomass.........             690               8          0.0003            0.5
                                Oil.............             100              28          0.005             0.5
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\ POM is represented by total emissions of polycyclic aromatic hydrocarbons (7-PAH). It is assumed that
  compliance with work practice standard and management practice will reduce fuel usage by 1 percent, which may
  reduce emissions of 7-PAH by an equivalent amount.

B. What are the cost impacts?

    To estimate the national cost impacts of this proposed rule for
existing sources, EPA developed several model boilers and determined
the cost of control for these model boilers. The EPA assigned a model
boiler to each existing unit based on the fuel, size, and current
controls. The analysis considered all air pollution control equipment
currently in operation at existing boilers. Model costs were then
assigned to all existing units that could not otherwise meet the
proposed standards. The resulting total national cost impact of this
proposed rule for existing units is $696 million dollars in total
annualized costs. The total annualized costs (new and existing) for
installing controls, conducting biennial tune-ups and an energy
assessment, and implementing testing and monitoring requirements, is
$1.0 billion. Table 3 of this preamble shows the total annualized cost
impacts for each subcategory.

                          Table 3--Summary of Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Estimated/         Total
                                                                                projected      annualized
                    Source                                 Subcategory               number of     cost (10\6\$/
                                                                                affected units      yr) \a\
----------------------------------------------------------------------------------------------------------------
Existing Units................................  Coal............................           3,710             160
                                                Biomass.........................          10,958              48
                                                Oil.............................         168,003             436
Facility Energy Assessment....................  All.............................  ..............              52
New Units \b\.................................  Coal............................             155              54
                                                Biomass.........................             200              13
                                                Oil.............................           6,424             244
----------------------------------------------------------------------------------------------------------------
\a\ TAC does not include fuel savings from improving combustion efficiency.
\b\ Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013).

    Using DOE projections on fuel expenditures, as well as the history
of installation dates of area source boilers in the dataset, the number
of additional boilers that could be potentially constructed was
estimated. The resulting total national cost impact of this proposed
rule on new sources by the 3rd year, 2013, is $311 million dollars in
total annualized costs. When accounting for a 1 percent fuel savings
resulting from improvements to combustion efficiency, the total
national cost impact on new sources is $260 million.
    A discussion of the methodology used to estimate cost impacts is
presented in the memorandum ``Estimation of Impacts for Industrial,
Commercial, and Institutional Boilers Area Source NESHAP'' in the
Docket.

C. What are the economic impacts?

    The economic impact analysis (EIA) that is included in the RIA
shows that the expected prices for industrial sectors could be 0.01
percent higher and domestic production may fall by less than 0.01
percent. Because of higher domestic prices imports may rise by less
than 0.01 percent. Energy prices will not be affected.
    Social costs are estimated to also be $0.5 billion in 2008 dollars.
This is estimated to made up of a $0.3 billion loss in domestic
consumer surplus, a $0.3 billion loss in domestic producer surplus, a
$0.1 billion increase in rest of the world surplus, and a $0.1 billion
net loss associated with new source costs and fuel savings not modeled
in a way that can be used to attribute it to consumers and producers.
    EPA performed a screening analysis for impacts on small entities by
comparing compliance costs to sales/revenues (e.g., sales and revenue
tests). EPA's analysis found the tests were typically higher than 3
percent for small entities included in the screening analysis. EPA has
prepared an Initial Regulatory Flexibility Analysis (IRFA) that
discusses alternative regulatory or policy options that minimize the
rule's small entity impacts. It includes key information about key
results from the Small Business Advocacy Review (SBAR) panel.
    Precise job effect estimates cannot be estimated with certainty.
Morgenstern et al. (2002) identify three economic mechanisms by which
pollution abatement activities can indirectly influence jobs:
     Higher production costs raise market prices, higher prices
reduce consumption, and employment within an industry falls (``demand
effect'');
     Pollution abatement activities require additional labor
services to produce the same level of output (``cost effect''); and
     Post regulation production technologies may be more or
less labor intensive (i.e., more/less labor is required per dollar of
output) (``factor-shift effect'').
    Several empirical studies, including Morgenstern et al. (2002),
suggest the net employment decline is zero or economically small (e.g.,
Cole and Elliot, 2007; Berman and Bui, 2001). However, others show the
question has not been resolved in the literature (Henderson, 1996;
Greenstone, 2002). Morgenstern's paper uses a six-year panel (U.S.
Census data for plant-level prices, inputs (including labor), outputs,
and environmental expenditures) to econometrically estimate the
production technologies and industry-level demand elasticities. Their
identification strategy leverages repeat plant-level observations over
time and uses plant-level and year fixed effects (e.g., plant and time
dummy variables). After estimating their model, Morgenstern show and
compute the change in employment associated with an additional $1
million ($1987) in environmental spending. Their estimates covers four
manufacturing industries (pulp and paper, plastics, petroleum, and
steel) and Morgenstern, et al. present results separately for the cost,
factor shift, and demand effects, as well as the net effect. They also
estimate and report an industry-wide average parameter that combines
the four industry-wide estimates and weighting them by each industry's
share of environmental expenditures.
    EPA has most often estimated employment changes associated with
plant closures due to environmental regulation or changes in output for
the regulated industry (EPA, 1999a; EPA, 2000). This analysis goes
beyond what EPA has typically done in two ways. First, because the
multimarket model provides estimates for changes in output for sectors
not directly regulated, we were able to estimate a more comprehensive
``demand effect.'' Secondly, parameters estimated in the Morgenstern
paper were used to

estimate all three effects (``demand,'' ``cost,'' and ``factor
shift''). This transfer of results from the Morgenstern study is
uncertain but avoids ignoring the ``cost effect'' and the ``factor-
shift effect.''
    We calculated ``demand effect'' employment changes by assuming that
the number of jobs changes proportionally with multi-market model's
simulated output changes. These results were calculated for all sectors
in the EPA model that show a change in output. The total job losses are
estimated to be approximately 1,000.
    We also calculated a similar ``demand effect'' estimate that used
the Morgenstern paper. To do this, we multiplied the point estimate for
the total demand effect (-3.56 jobs per million ($1987) of
environmental compliance expenditure) by the total environmental
compliance expenditures used in the partial equilibrium model. For
example, the job loss estimate is approximately 1,000 jobs (-3.56 x
$0.5 billion x 0.60).\2\
---------------------------------------------------------------------------

    \2\ Since Morgenstern's analysis reports environmental
expenditures in $1987, we make an inflation adjustment to the
engineering cost analysis using GDP implicit price deflator (64.76/
108.48) = 0.60).
---------------------------------------------------------------------------

    We also present the results of using the Morgenstern paper to
estimate employment ``cost'' and ``factor-shift'' effects (Table 1).
Although using the Morgenstern parameters to estimate these ``cost''
and ``factor-shift'' employment changes is uncertain, it is helpful to
compare the potential job gains from these effects to the job losses
associated with the ``demand'' effect. Table 1 shows that using the
Morgenstern point estimates of parameters to estimate the ``cost'' and
``factor shift'' employment gains may be greater than the employment
losses using either of the two ways of estimating ``demand'' employment
losses. The 95 percent confidence intervals are shown for all of the
estimates based on the Morgenstern parameters. As shown, at the 95
percent confidence level, we cannot be certain if net employment
changes are positive or negative.
    Although the Morgenstern paper provides additional information
about the potential job effects of environmental protection programs,
there are several qualifications EPA considered as part of the
analysis. First, EPA has used the weighted average parameter estimates
for a narrow set of manufacturing industries (pulp and paper, plastics,
petroleum, and steel). Absent other data and estimates, this approach
seems reasonable and the estimates come from a respected peer-reviewed
source. However, EPA acknowledges the proposed rule covers a broader
set of industries not considered in original empirical study. By
transferring the estimates to other industrial sectors, we make the
assumption that estimates are similar in size. In addition, EPA assumes
also that Morgenstern et al.'s estimates derived from the 1979-1991
still applicable for policy taking place in 2013, almost 20 years
later. Second, the multi-market model only considers near term
employment effects in a U.S. economy where production technologies are
fixed. As a result, the modeling system places more emphasis on the
short term ``demand effect'' whereas the Morgenstern paper emphasizes
other important long term responses. For example, positive job gains
associated with ``factor shift effects'' are more plausible when
production choices become more flexible over time and industries can
substitute labor for other production inputs. Third, the Morgenstern
paper estimates rely on sector demand elasticities that are different
from the demand elasticity parameters used in the multi-market model.
As a result, the demand effects are not directly comparable with the
demand effects estimated by the multi-market model. Fourth, Morgenstern
identifies the industry average as economically and statistically
insignificant effect (i.e., the point estimates are small, measured
imprecisely, and not distinguishable from zero). EPA acknowledges this
fact and has reported the 95 percent confidence intervals in Table 1.
Fifth, Morgenstern's methodology assumes large plants bear most of the
regulatory costs. By transferring the estimates, EPA assumes a similar
distribution of regulatory costs by plant size and that the regulatory
burden does not disproportionately fall on smaller plants.

                    Table 4--Employment Changes: 2013
------------------------------------------------------------------------
              Estimation method                        1,000 jobs
------------------------------------------------------------------------
Partial equilibrium model (multiple markets)   -1.
 (demand effect only).
Literature-based estimate (net effect [A + B   +1 (-1 to +2).
 + C below]).
A. Literature-based estimate: Demand effect..  -1 (-3 to 0).
B. Literature-based estimate: Cost effect....  +1 (0 to +2).
C. Literature-based estimate: Factor shift     +1 (0 to +2).
 effect.
------------------------------------------------------------------------
Note: Totals may not add due to independent rounding. 95 percent
  confidence intervals for literature-based estimates are shown in
  parenthesis.

D. What are the social costs and benefits of this proposed rule?

    We estimated the monetized benefits of this proposed regulatory
action to be $1.0 billion to $2.4 billion (2008$, 3 percent discount
rate) in the implementation year (2013). The monetized benefits of this
proposed regulatory action at a 7 percent discount rate are $910
million to $2.2 billion (2008$). Using alternate relationships between
PM2.5 and premature mortality supplied by experts, higher
and lower benefits estimates are plausible, but most of the expert-
based estimates fall between these two estimates.\3\ A summary of the
monetized benefits estimates at discount rates of 3 percent and 7
percent is in Table 5 of this preamble.
---------------------------------------------------------------------------

    \3\ Roman et al., 2008. ``Expert Judgment Assessment of the
Mortality Impact of Changes in Ambient Fine Particulate Matter in
the U.S.'' Environ. Sci. Technol., 42, 7, 2268--2274.

      Table 5--Summary of the Monetized Benefits Estimates for the Proposed Boiler Area Source Rule in 2013
                                             [Billions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                             Estimated
                                             emission
                                            reductions     Total monetized benefits    Total monetized benefits
                                             (tons per        (3% discount rate)          (7% discount rate)
                                               year)
----------------------------------------------------------------------------------------------------------------
PM2.5...................................           2,682  $0.96 to $2.4.............  $0.88 to $2.1.
PM2.5 Precursors........................  ..............  ..........................  ..........................
SO2.....................................           1,539  $0.31 to $0.76............  $0.28 to $0.68.
VOC.....................................           1,179  $0.01 to $0.04............  $0.01 to $0.03.
    Total...............................  ..............  $1.0 to $2.4..............  $0.91 to $2.2.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers
  may not sum across rows. All fine particles are assumed to have equivalent health effects, but the benefit-per-
  ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form
  PM2.5. Benefits from reducing hazardous air pollutants (HAPs), ecosystem effects, and visibility impairment
  are not included.

    These benefits estimates represent the total monetized human health
benefits for populations exposed to less PM2.5 in 2013 from
controls installed to reduce air pollutants in order to meet these
standards. These estimates are calculated as the sum of the monetized
value of avoided premature mortality and morbidity associated with
reducing a ton of PM2.5 and PM2.5 precursor
emissions. To estimate human health benefits derived from reducing
PM2.5 and PM2.5 precursor emissions, we utilized
the general approach and methodology laid out in Fann et al. (2009).\4\
---------------------------------------------------------------------------

    \4\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ``The influence
of location, source, and emission type in estimates of the human
health benefits of reducing a ton of air pollution.'' Air Qual Atmos
Health (2009) 2:169-176.
---------------------------------------------------------------------------

    To generate the benefit-per-ton estimates, we used a model to
convert emissions of direct PM2.5 and PM2.5
precursors into changes in ambient PM2.5 levels and another
model to estimate the changes in human health associated with that
change in air quality. Finally, the monetized health benefits were
divided by the emission reductions to create the benefit-per-ton
estimates. Even though we assume that all fine particles have
equivalent health effects, the benefit-per-ton estimates vary between
precursors because each ton of precursor reduced has a different
propensity to form PM2.5. For example, SOX has a
lower benefit-per-ton estimate than direct PM2.5 because it
does not form as much PM2.5, thus the exposure would be
lower, and the monetized health benefits would be lower.
    For context, it is important to note that the magnitude of the PM
benefits is largely driven by the concentration response function for
premature mortality. Experts have advised EPA to consider a variety of
assumptions, including estimates based both on empirical
(epidemiological) studies and judgments elicited from scientific
experts, to characterize the uncertainty in the relationship between
PM2.5 concentrations and premature mortality. For this
proposed rule we cite two key empirical studies, one based on the
American Cancer Society cohort study \5\ and the extended Six Cities
cohort study.\6\ In the RIA for this proposed rule, which is available
in the docket, we also include benefits estimates derived from expert
judgments and other assumptions.
---------------------------------------------------------------------------

    \5\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary Mortality,
and Long-term Exposure to Fine Particulate Air Pollution.'' Journal
of the American Medical Association 287:1132-1141.
    \6\ Laden et al., 2006. ``Reduction in Fine Particulate Air
Pollution and Mortality.'' American Journal of Respiratory and
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    This analysis does not include the type of detailed uncertainty
assessment found in the 2006 PM2.5 NAAQS RIA because we lack
the necessary air quality input and monitoring data to run the benefits
model. However, the 2006 PM2.5 NAAQS benefits analysis \7\
provides an indication of the sensitivity of our results to various
assumptions.
---------------------------------------------------------------------------

    \7\ U.S. Environmental Protection Agency, 2006. Final Regulatory
Impact Analysis: PM2.5 NAAQS. Prepared by Office of Air
and Radiation. October. Available on the Internet at http://
www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------

    It should be emphasized that the monetized benefits estimates
provided above do not include benefits from several important benefit
categories, including reducing other air pollutants, ecosystem effects,
and visibility impairment. The benefits from reducing carbon monoxide
and hazardous air pollutants have not been monetized in this analysis,
including reducing 39,000 tons of carbon monoxide, 0.75 ton of mercury,
and 130 tons of HCl, 5 tons of HF, and 460 grams of dioxins/furans each
year. Although we do not have sufficient information or modeling
available to provide monetized estimates for this rulemaking, we
include a qualitative assessment of the health effects of these air
pollutants in the Regulatory Impact Analysis (RIA) for this proposed
rule, which is available in the docket.
    The social costs of this proposed rulemaking are estimated to be
$0.5 billion (2008$) in the implementation year, and the monetized
benefits are $1.0 billion to $2.4 billion (2008$, 3 percent discount
rate) for that same year. The benefits at a 7 percent discount rate are
$910 million to $2.2 billion (2008$). Thus, net benefits of this
rulemaking are estimated at $500 million to $1.9 billion (2008$, 3
percent discount rate) and $400 million to $1.7 billion (2008$, 7
percent discount rate).
    A summary of the monetized benefits, social costs, and net benefits
at discount rates of 3 percent and 7 percent is in Table 6 of this
preamble.

    Table 6--Summary of the Monetized Benefits, Social Costs, and Net
            Benefits for the Boiler Area Source Rule in 2013
                         [Billions of 2008$] \1\
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
                             Proposed Option
------------------------------------------------------------------------
Total Monetized Benefits \2\....  $1.0 to $2.4......  $0.91 to $2.2.
Total Social Costs \3\..........  $0.50.............  $0.5.
Net Benefits....................  $0.5 to $1.9......  $0.4 to $1.7.
                                 ---------------------------------------
Non-monetized Benefits..........  39,000 tons of carbon monoxide.
                                  130 tons of HCl.
                                  5 tons of HF.
                                  0.75 tons of mercury.
                                  250 tons of other metals.
                                  470 grams of dioxins/furans.
                                  Health effects from NO2 and SO2
                                   exposure.
                                  Ecosystem effects.
                                  Visibility impairment.
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
  rounded to two significant figures.
\2\ The total monetized benefits reflect the human health benefits
  associated with reducing exposure to PM2.5 through reductions of
  directly emitted PM2.5 and PM2.5 precursors such as NOX and SO2. It is
  important to note that the monetized benefits include many but not all
  health effects associated with PM2.5 exposure.
\3\ The methodology used to estimate social costs for one year in the
  multimarket model using surplus changes results in the same social
  costs for both discount rates.

    For more information on the benefits analysis, please refer to the
RIA for this rulemaking, which is available in the docket.

E. What are the water and solid waste impacts?

    The EPA estimated that no additional water usage would result from
the MACT floor level of control or GACT requirement. The fabric filter,
multiclone or combustion control devices used to meet the standards of
this proposed rule do not require any water to operate, nor do they
generate any wastewater.
    The EPA estimated the additional solid waste that would result from
this proposed rule to be 14,300 tpy for existing sources due to the
dust and flyash captured by mercury and PM control devices. The cost of
handling the additional solid waste generated from existing sources is
$602,000 per year. For new sources installed by 2013, the EPA estimated
the additional solid waste that would result from this proposed rule to
be 1,800 tpy for new sources due to the dust and flyash captured by
mercury and PM control devices. The cost of handling the additional
solid waste generated from existing sources is $75,900 per year. These
costs are also accounted for in the control costs estimates.
    A discussion of the methodology used to estimate impacts is
presented in ``Estimation of Impacts for Industrial, Commercial, and
Institutional Boilers Area Source NESHAP'' in the Docket.

F. What are the energy impacts?

    The EPA expects an increase of approximately 206 million kilowatt
hours (kWh) in national annual energy usage from existing sources as a
result of this proposed rule. The increase results from the electricity
required to operate control devices installed to meet this proposed
rule, such as fabric filters. Additionally, for new sources installed
by 2013, EPA expects an increase of approximately 22 million kWh in
national annual energy usage in order to operate the control devices.
    The Department of Energy has conducted energy assessments at
selected manufacturing facilities and reports that facilities can
reduce fuel/energy use by 10 to 15 percent by using best practices to
increase their energy efficiency. Additionally, the EPA expects work
practice standards such as boilers tune-ups and combustion controls
such as new replacement burners and will improve the efficiency of
boilers. The EPA estimates existing area source facilities can save 20
trillion BTU of fuel each year. For new sources online by 2013, the EPA
estimates 2.3 trillion BTU per year of fuel can be conserved. This fuel
savings estimates includes only those fuel savings resulting from
liquid and coal fuels and it is based on the assumption that the work
practice standards will achieve 1 percent improvement in efficiency.

VII. Relationship of This Proposed Action to CAA Section 112(c)(6)

    CAA section 112(c)(6) requires 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). 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 emits two of the seven CAA Section 112(c)(6)
pollutants: POM and mercury. (The POM emitted is composed of 16
polyaromatic hydrocarbons (PAH) and extractable organic matter (EOM).)
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), 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
category ``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.
    Specifically, as 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. Any POM that do
form during combustion are further

controlled by the various post-combustion controls. The add-on PM
control systems (fabric filter) used to reduce mercury and/or PM
emissions further reduce emissions of these organic pollutants, as is
evidenced by performance data. Specifically, the emission tests
obtained at currently operating major source boilers show that the
proposed MACT regulations for area source boilers will reduce Hg
emissions by about 86 percent. It is, therefore, reasonable to conclude
that POM emissions will be substantially controlled. Thus, while this
proposed 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 CAA section 112(c)(6).
    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, we believe CO serves as
an effective surrogate for this HAP, because CO, like POM, is formed as
a product 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 propose numerical emissions limits for POM with respect to
boilers to satisfy CAA Section 112(c)(6).
    To further address POM and mercury emissions, this proposed rule
also includes an energy assessment provision that encourages
modifications to the facility to reduce energy demand that lead to
these emissions.

VIII. Statutory and Executive Order Review

A. Executive Order 12866: Regulatory Planning and Review

    Under 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, EPA submitted this action to OMB for review under EO
12866 and any changes in response to OMB recommendations have been
documented in the docket for this action. For more information on the
costs and benefits for this rule, please refer to Table 5 of this
preamble.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have
been submitted for approval to OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by EPA has been assigned EPA ICR number 2253.01.
    The recordkeeping and reporting requirements in this proposed rule
would be based on the information collection requirements in EPA's
NESHAP General Provisions (40 CFR part 63, subpart A). The
recordkeeping and reporting requirements in the General Provisions are
mandatory pursuant to section 114 of the CAA (42 U.S.C. 7414). All
information other than emissions data submitted to EPA pursuant to the
information collection requirements for which a claim of
confidentiality is made is safeguarded according to CAA section 114(c)
and EPA's implementing regulations at 40 CFR part 2, subpart B.
    This proposed NESHAP would require applicable one-time
notifications according to the NESHAP General Provisions. Facility
owners or operators would be required to include compliance
certifications for the work practices and management practices in their
Notifications of Compliance Status. Recordkeeping would be required to
demonstrate compliance with emission limits, work practices, management
practices, monitoring, and applicability provisions. New affected
facilities would be required to comply with the requirements for
startup, shutdown, and malfunction plans/reports and to submit a
compliance report if a deviation occurred during the semiannual
reporting period.
    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 $523 million. This includes 3.6
million labor hours per year at a cost of $336 million and total non-
labor capital costs of $186 million per year. This estimate includes
initial and annual performance tests, conducting and documenting an
energy assessment, 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 were also included in the cost
estimates presented in the control costs impacts estimates in section
VI.B 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 767,403 hours per year at a total labor
cost of $37.6 million per year.
    Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless the collection
displays a currently valid OMB control number. The OMB control numbers
for EPA's regulations in 40 CFR part 63 are listed in 40 CFR part 9.
    To comment on EPA's need for this information, the accuracy of the
provided burden estimates, and any suggested methods for minimizing
respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this action, which
includes this ICR, under Docket ID number EPA-HQ-OAR-2006-0790. Submit
any comments related to the ICR to EPA and OMB. See ADDRESSES section
at the beginning of this preamble for where to submit comments to 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 EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after June 4, 2010, a comment to OMB is best assured of having its full
effect if OMB receives it by July 6, 2010. The final rule will respond
to any OMB or public comments on the information collection
requirements contained in this proposal.

C. Regulatory Flexibility Act (RFA)

    The 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.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed 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 40 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.
    Because an initial screening analysis for impact on small entities
indicated a likely significant impact for substantial numbers EPA
convened a SBAR Panel to obtain advice and recommendation of
representatives of the small entities that potentially would be subject
to the requirements of this rule.
(1) Panel Process and Panel Outreach
    As required by section 609(b) of the RFA, as amended by SBREFA, EPA
also has conducted outreach to small entities and. On January 22, 2009
EPA's Small Business Advocacy Chairperson convened a Panel under
section 609(b) of the RFA. In addition to the Chair, the Panel
consisted of the Director of the Sector Policies and Programs Division
within EPA's Office of Air and Radiation, the Chief Counsel for
Advocacy of the Small Business Administration, and the Administrator of
the Office of Information and Regulatory Affairs within the Office of
Management and Budget.
    As part of the SBAR Panel process we conducted outreach with
representatives from 14 various small entities that would be affected
by this rule. The small entity representatives (SERs) included
associations representing schools, churches, hotels/motels, wood
product facilities and manufacturers of home furnishings. We met with
these SERs to discuss the potential rulemaking approaches and potential
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials
included background on the rulemaking, possible regulatory approaches,
preliminary cost and economic impacts, and possible rulemaking
alternatives. The Panel met with SERs from the industries that will be
impacted directly by this rule on February 10, 2009 to discuss the
outreach materials and receive feedback on the approaches and
alternatives detailed in the outreach packet. (EPA also met with SERs
on November 13, 2008 for an initial outreach meeting.) The Panel
received written comments from the SERs following the meeting in
response to discussions at the meeting and the questions posed to the
SERs by the Agency. The SERs were specifically asked to provide comment
on regulatory alternatives that could help to minimize the rule's
impact on small businesses.
(2) Panel Recommendations for Small Business Flexibilities
    The Panel recommended that EPA consider and seek comment on a wide
range of regulatory alternatives to mitigate the impacts of the
rulemaking on small businesses, including those flexibility options
described below. The following section summarizes the SBAR Panel
recommendations. EPA has proposed provisions consistent with each of
the Panel's recommendations regarding area source facilities.
    Consistent with the RFA/SBREFA requirements, the Panel evaluated
the assembled materials and small-entity comments on issues related to
elements of the IRFA. A copy of the Final Panel Report (including all
comments received from SERs in response to the Panel's outreach meeting
as well as summaries of both outreach meetings that were held with the
SERs is included in the docket for this proposed rule. A summary of the
Panel recommendations is detailed below. As noted above, this proposal
includes proposed provisions for each of the Panel recommendations
regarding area source facilities.
(a) Work Practice Standards
    The panel recommended that EPA consider requiring annual tune-ups,
including standardized criteria outlining proper tune-up methods
targeted at smaller boiler operators. The panel further recommended
that EPA take comment on the efficacy of energy assessments/audits at
improving combustion efficiency and the cost of performing the
assessments, especially to smaller boiler operators.
    A work practice standard, instead of MACT emission limits, may be
proposed if it can be justified under CAA section 112(h), that is, it
is impracticable to enforce the emission standards due to technical and
economic limitations. Work practice standards could reduce fuel use and
improve combustion efficiency which would result in reduced emissions.
    In general, SERs commented that a regulatory approach to improve
combustion efficiency, such as work practice standards, would have
positive impacts with respect to the environment and energy use and
save on compliance costs. The SERs were concerned with work practice
standards that would require energy assessments and implementation of
assessment findings. The basis of these concerns rested upon the
uncertainty that there is no guarantee that there are available funds
to implement a particular assessment's findings.
(b) Subcategorization
    The Panel recommended that EPA allow subcategorizations suggested
by the SERs, unless EPA finds that a subcategorization is inconsistent
with the Clean Air Act.
    SERs commented that subcategorization is a key concept that could
ensure that like boilers are compared with similar boilers so that MACT
floors are more reasonable and could be achieved by all units within a
subcategory using appropriate emission reduction strategies. SERs
commented that EPA should subcategorize based on fuel type, boiler
type, duty cycle, and location.
(c) Compliance Costs
    The Panel recommended that EPA carefully weigh the potential burden
of compliance requirements and consider for small entities options such
as, emission averaging within facility, reduced monitoring/testing
requirements, or allowing more time for compliance.
    SERs noted that recordkeeping activities, as written in the vacated
boiler MACT, would be especially challenging for small entities that do
not have a dedicated environmental affairs department.

D. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit

analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year. Before promulgating a rule for which a written statement is
needed, section 205 of the UMRA generally requires us to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows us to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before we establish any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, we must develop a small
government agency plan under section 203 of the UMRA. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
    We have determined that this proposed rule contains 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 1 year. Accordingly, we have prepared a written statement
entitled ``Unfunded Mandates Reform Act Analysis for the Proposed
Industrial Boilers and Process Heaters NESHAP'' under section 202 of
the UMRA which is summarized below.
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 requires us to establish NESHAP for both
major and area sources of HAP that are listed for regulation under CAA
section 112(c). CAA section 112(k)(3)(B) calls for EPA to identify at
least 30 HAP which, as the result of emissions from area sources, pose
the greatest threat to public health in the largest number of urban
areas. CAA section 112(c)(3) requires EPA to list sufficient categories
or subcategories of area sources to ensure that area sources
representing 90 percent of the emissions of the 30 urban HAP are
subject to regulation.
    Under CAA section 112(d)(5), we may elect to promulgate standards
or requirements for area sources based on GACT used by those sources to
reduce emissions of HAP. Determining what constitutes GACT involves
considering the control technologies and management practices that are
generally available to the area sources in the source category. We also
consider the standards applicable to major sources in the analogous
source category and, as appropriate, the control technologies and
management practices at area and major sources in similar categories,
to determine if the standards, technologies, and/or practices are
transferable and generally available to area sources. In determining
GACT for a particular area source category, we consider the costs and
economic impacts of available control technologies and management
practices on that category.
    While GACT may be a basis for standards for most types of HAP
emitted from area source, CAA section 112(c)(6) requires that source
categories accounting for emissions of the HAP listed in CAA section
112(c)(6) be subject to standards under CAA section 112(d)(2) for the
listed pollutants. Thus, CAA section 112(c)(6) requires that emissions
of each listed HAP for the listed categories be subject to MACT
regulation. The CAA section 112(c)(6) list of source categories
includes industrial boilers and institutional/commercial boilers.
Within these two source categories, coal combustion, oil combustion,
and wood combustion have been on the CAA section 112(c)(6) list because
of emissions of mercury and POM. We currently believe that regulation
of coal-fired boilers will ensure that we fulfill our obligation under
CAA section 112(c)(6) with respect to mercury reductions. Consequently,
we deem it reasonable to propose to regulate the coal-fired boilers
under MACT, rather than the biomass and oil-fired boilers, to obtain
additional mercury reductions towards achieving the CAA section
112(c)(6) obligation. We propose to regulate biomass-fired and oil-
fired boilers under GACT.
    This proposed NESHAP would apply to all existing and new industrial
boilers, institutional boilers, and commercial boilers located at area
sources. In compliance with section 205(a) of the UMRA, we 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 proposed standards are
based represents the MACT floor for the listed CAA section 112(c)(6)
pollutants (mercury and POM) and GACT for the other urban HAP which
formed the basis for the listing of these two area source categories.
The proposed standards would require new coal-fired boilers to meet
MACT-based emission limits for mercury and CO (as a surrogate for POM)
and GACT-based emission limits for PM (as a surrogate for urban
metals). New biomass and oil-fired boilers would be required to meet
MACT-based CO emission limits and GACT-based emission limits for PM.
The emission limits for existing area source boilers are only
applicable to area source boilers that have a designed heat input
capacity of 10 MMBtu/h or greater. Existing large coal-fired boilers
would be required to meet MACT-based emission limits for mercury and
CO, and existing large biomass and oil-fired boilers would be subject
to MACT-based CO emission limits. As allowed under CAA section 112(h),
a work practice standard requiring the implementation of a tune-up
program is being proposed for existing area source boilers with a
designed heat input capacity of less than 10 MMBtu/h. An additional
``beyond-the-floor'' standard is being proposed for existing area
source facilities having an affected boiler with a heat input capacity
of 10 MMBtu/h or greater that requires the performance of an energy
assessment on the boiler and the facility to identify cost-effective
energy conservation measures.
2. Social Costs and Benefits
    The regulatory impact analysis prepared for the proposed rule
including the Agency's assessment of costs and benefits, is detailed in
the ``Regulatory Impact Analysis for the Proposed Industrial Boilers
and Process Heaters MACT'' in the docket. Based on estimated compliance
costs associated with the proposed rule and the predicted change in
prices and production in the affected industries, the estimated social
costs of the proposed rule are $0.5 billion (2008 dollars).
    It is estimated that 3 years after implementation of the proposed
rule, HAP would be reduced by hundreds of

tons, including reductions in metallic HAP including mercury,
hydrochloric acid, hydrogen fluoride, and several other organic HAP
from area source boilers. 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 reductions in PM2.5 and in
SO2 that would occur, including 2,700 tons of
PM2.5 and 1,500 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
2013 associated with the implementation of the proposed alternative
range from $1.0 billion (2008 dollars) to $2.4 billion (2008 dollars)
when using a 3 percent discount rate (or from $0.9 billion (2008
dollars) to $2.2 billion (2008 dollars) when using a 7 percent discount
rate. 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 proposed rulemaking, refer to the RIA in the
docket.
3. Future and Disproportionate Costs
    The Unfunded Mandates Reform Act requires that we estimate, where
accurate estimation is reasonably feasible, future compliance costs
imposed by the proposed rule and any disproportionate budgetary
effects. Our estimates of the future compliance costs of the proposed
rule are discussed previously in this preamble.
    We do not believe that there will be any disproportionate budgetary
effects of the 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 ``Economic
Impact Analysis of the Proposed Industrial Boilers and Process Heaters
NESHAP,'' the results of which are discussed previously in this
preamble.
4. Effects on the National Economy
    The Unfunded Mandates Reform Act requires that we estimate the
effect of the 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 the proposed rule is presented in
the ``Economic Impact Analysis for the Industrial Boilers and Process
Heaters MACT'' in the docket. This analysis provides estimates of the
effect of the proposed 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 (less than 0.01 percent). 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 Unfunded Mandates Reform Act 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. Consistent with the intergovernmental
consultation provisions of section 204 of the UMRA, EPA has initiated
consultations with governmental entities affected by this proposed
rule. EPA invited the following 10 national organizations representing
State and local elected officials to a meeting held on March 24, 2010
in Washington DC: (1) National Governors Association; (2) National
Conference of State Legislatures, (3) Council of State Governments, (4)
National League of Cities, (5) U.S. Conference of Mayors, (6) National
Association of Counties, (7) International City/County Management
Association, (8) National Association of Towns and Townships, (9)
County Executives of America, and (10) Environmental Council of States.
These 10 organizations of elected State and local officials have been
identified by EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. The
purposes of the consultation were to provide general background on the
proposal, answer questions, and solicit input from State/local
governments. During the meeting, officials expressed uncertainty with
regard to how boilers owned/operated by State and local entities would
be impacted, as well as with regard to the potential burden associated
with implementing the rule on State and local entities. To that end,
officials requested and EPA provided (1) model boiler costs, (2)
inventory of area source boilers (coal, oil, biomass only) for the 13
States for which we have an inventory, and (3) information on potential
size of boilers used for various facility types and sizes. EPA has not
received additional questions or requests from State or local
officials.
    Consistent with section 205, EPA has identified and considered a
reasonable number of regulatory alternatives. Because an initial
screening analysis for impact on small entities indicated a likely
significant impact for substantial numbers EPA convened a SBAR Panel to
obtain advice and recommendation of representatives of the small
entities that potentially would be subject to the requirements of the
rule. As part of that process, EPA considered several options. Those
options included establishing emission limits, establishing work
practice standards, and establishing work practice standards and
requiring an energy assessment. The regulatory alternative selected is
a combination of the options considered and includes proposed
provisions regarding each of the SBAR Panel's recommendations for area
source boilers. The recommendations regard subcategorization, work
practice standards, and compliance costs (see section VIII.C. of this
preamble for more detail).
    EPA determined subcategorization based on boiler type to be
appropriate because different types of units have different emission
characteristics which may affect the feasibility and effectiveness of
emission control. Thus, the proposal identifies three subcategories of
area source boilers: (1) Boilers designed for coal firing, (2) boilers
designed for biomass firing, and (3) boilers designed for oil firing.

    The regulatory alternative upon which the proposed standards are
based represents the MACT floor for mercury for coal-fired boilers, the
MACT floor for POM (CO is used as a surrogate for POM) for coal,
biomass, and oil-fired boilers, and GACT for the other urban HAP (PM is
used as a surrogate for urban HAP metals and CO is used as a surrogate
for urban organic pollutants) for coal, biomass, and oil-fired boilers.
The emission limits for existing area source boilers are only
applicable to area source boilers that have a designed heat input
capacity of 10 MMBtu/h or greater. A work practice standard (for
mercury from coal-fired boilers and for POM from all boilers) or
management practice (for all other HAP, including mercury from biomass-
fired and oil-fired boilers) requiring the implementation of a tune-up
program is being proposed for existing area source boilers with a
designed heat input capacity of less than 10 MMBtu/h. An additional
``beyond-the-floor'' standard is being proposed for existing area
source facilities having an affected boiler with a heat input capacity
of 10 MMBtu/h or greater that requires the performance of an energy
assessment on the boiler and the facility to identify cost-effective
energy conservation measures.
    The proposed use of surrogate pollutants would result in reduced
compliance costs because testing would only be required for the
surrogate pollutants (i.e., CO and PM) versus for the HAP (i.e., POM
and metals). The proposed work practice standard/management practice
also would result in reduced compliance costs with respect to
monitoring/testing for the smaller existing area source boilers. EPA's
proposed exemption of most area source facilities from title V permit
requirements also would reduce burden on area source boiler facilities.
    This proposed 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 boilers that would be affected by the proposed
rule, EPA's analysis shows that other public facilities that are
located at area source facilities owned by small entities would have
cost-to-revenue ratios exceeding 10 percent. Hospitals' and schools'
revenue tests fall below 1 percent. Because the proposed rule's
requirements apply equally to boilers owned and/or operated by
governments and to boilers owned and/or operated by private entities,
there would be no requirements that uniquely apply to such governments
or impose any disproportionate impacts on them.

E. Executive Order 13132: Federalism

    Under Executive Order 13132, EPA may not issue an action that has
federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by State and local governments, or EPA consults with
State and local officials early in the process of developing the
proposed action.
    EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on State or local governments, and the Federal government will not
provide the funds necessary to pay those costs. Accordingly, EPA
provides the following federalism summary impact statement as required
by section 6(b) of Executive Order 13132.
    Based on the estimates in EPA's RIA for today's action, the
proposed regulatory option, if promulgated, may have federalism
implications because the option may impose approximately $416 million
in annual direct compliance costs on an estimated 57,000 State or local
governments. Boiler inventories for the health services, educational
services, and government-owned buildings sectors from 13 States were
used to estimate the nationwide number of potentially impacted State or
local governments. Because the inventories for these sectors include
privately owned and Federal government owned facilities, the estimate
may include many facilities that are not State or local government
owned. Table 7 of this preamble presents estimates of the number of
potentially impacted State and local governments and their potential
annual compliance costs for each of the three sectors. In addition to
an estimate of the total number of potentially impacted facilities,
estimates for facilities with small boilers and for facilities with
large boilers are presented. Small boilers (boilers with heat input
capacity of less than 10 MMBtu/h) would be subject to a work practice
standard that requires a boiler tune-up every 2 years. Large coal-fired
boilers (boilers with heat input capacity of 10 MMBtu/h or greater)
would be subject to emission limits for mercury and CO, while large
biomass and oil-fired boilers would be subject to emission limits for
CO. All facilities with large boilers would be required to conduct a
one-time energy assessment.

 Table 7--State and Local Governments Potentially Impacted by the Proposed Standards for Boilers at Area Source
                                                   Facilities
----------------------------------------------------------------------------------------------------------------
                                                Number of potentially impacted
                                                          facilities                 Annual compliance costs to
                  Sector                   ---------------------------------------         meet standards
                                               Total        Small        Large
----------------------------------------------------------------------------------------------------------------
Health Services...........................       17,206       15,293        1,913  $143 million.
Educational Services......................       34,052       33,303          749  $200 million.
Government-Owned Buildings................        5,796        5,098          698  $73 million.
                                           ---------------------------------------------------------------------
    Total.................................       57,054       53,694        3,360  $416 million.
----------------------------------------------------------------------------------------------------------------

    EPA consulted with State and local officials in the process of
developing the proposed action to permit them to have meaningful and
timely input into its development. EPA met with 10 national
organizations representing State and local elected officials to provide
general background on the proposal, answer questions, and solicit input
from State/local governments. The UMRA discussion in this preamble
includes a description of the consultation.
    In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed action
from State and local officials.

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

    Executive Order 13175 (65 FR 67249, November 9, 2000), requires EPA
to develop an accountable process to

ensure ``meaningful and timely input by tribal officials in the
development of regulatory policies that have tribal implications.'' The
proposed rule 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.
The proposed rule imposes requirements on owners and operators of
specified area sources and not tribal governments. We do not know of
any industrial, commercial, or institutional boilers owned or operated
by Indian tribal governments. However, if there are any, the effect of
the proposed rule on communities of tribal governments would not be
unique or disproportionate to the effect on other communities. Thus,
Executive Order 13175 does not apply to the proposed rule. EPA
specifically solicits additional comment on the proposed rule from
tribal officials.

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

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that EPA has reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, the Agency must evaluate the environmental health or
safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
    The proposed rule is not subject to Executive Order 13045 because
the Agency does not believe the environmental health risks or safety
risks addressed by this action present a disproportionate risk to
children. The reason for this determination is that the proposed rule
is based solely on technology performance.
    The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of early life exposure to the
proposed rule.

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

    Executive Order 13211, (66 FR 28355, May 22, 2001), provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, OMB, a Statement of Energy Effects
for certain actions identified as significant energy actions. Section
4(b) of Executive Order 13211 defines ``significant energy actions'' as
``any action by an agency (normally published in the Federal Register)
that promulgates or is expected to lead to the promulgation of a final
rule or regulation, including notices of inquiry, advance notices of
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is
a significant regulatory action under Executive Order 12866 or any
successor order, and (ii) is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) that is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action.'' The proposed rule
is not a ``significant regulatory action'' because it is not likely to
have a significant adverse effect on the supply, distribution, or use
of energy. The basis for the determination is as follows.
    We estimate no significant changes for the energy sector for price,
production, or imports. For more information on the estimated energy
effects, please refer to the economic impact analysis for the proposed
rule. The analysis is available in the public docket.
    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 (NTTAA) of 1995 (Pub. L. 104-113, Section 12(d), 15 U.S.C. 272
note) directs EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. The VCS are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
VCS bodies. The NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency does not use available and applicable VCS.
    The proposed rule involves technical standards. The EPA cites the
following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A,
3B, 4, 5, 5D, 10, 10A, 10B, 17, 19, 29 of 40 CFR part 60; 101A of 40
CFR part 61; and voluntary consensus standards: American Society for
Testing and Materials (ASTM) D6522-00, American Society of Mechanical
Engineers (ASME) PTC 19 (manual methods only), ASTM D6784-02, ASTM
D2234-D2234M-03, ASTM D6323-98, ASTM D2013-04, ASTM d5198-92, ASTM
D5865-04, ASTM E711-87, ASTM D3173-03, ASTM E871-82, and ASTM D6722-01.
    Consistent with the NTTAA, EPA conducted searches to identify
voluntary consensus standards in addition to these EPA methods. No
applicable voluntary consensus standards were identified for EPA
Methods 2F, 2G, 5D, and 19. The search and review results are in the
docket for this rule.
    The search for emissions measurement procedures identified 16 other
voluntary consensus standards. The EPA determined that these 16
standards identified for measuring emissions of the HAP or surrogates
subject to emission standards in this rule were impractical
alternatives to EPA test methods for the purposes of this rule.
Therefore, EPA does not intend to adopt these standards for this
purpose. The reasons for the determinations for the 16 methods can be
found in the docket to this rule.
    Table 4 to subpart JJJJJJ of this proposed rule lists the testing
methods included in the regulation. Under section 3.7(f) and section
63.8(f) of Subpart A of the General Provisions, a source may apply to
EPA for permission to use alternative test methods or alternative
monitoring requirements in place of any required testing methods,
performance specifications, or procedures.
    EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.

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 (EJ). Its main
provision directs Federal agencies, to the greatest extent practicable
and permitted by law, to

make EJ 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, low-income, and Tribal populations in the United
States.
    This proposed action establishes national emission standards for
industrial, commercial, and institutional boilers that are area
sources. The industrial boiler source category includes boilers used in
manufacturing, processing, mining, refining, or any other industry. The
commercial boiler source category includes boilers used in commercial
establishments such as stores/malls, laundries, apartments,
restaurants, theaters, and hotels/motels. The institutional boiler
source category includes boilers used in medical centers (e.g.,
hospitals, clinics, nursing homes), educational and religious
facilities (e.g., schools, universities, places of worship), and
municipal buildings (e.g., courthouses, arts centers, prisons). There
are approximately 91,000 facilities affected by the proposed rule, most
of which are small entities. By the defined nature of the category,
many of these sources are located in close proximity to residential
areas, commercial centers, and other locations where large numbers of
people live and work.
    Due to the large number of these sources, their nation-wide
dispersal, and the absence of site specific coordinates, EPA is unable
to examine the distributions of exposures and health risks attributable
to these sources among different socio-demographic groups for this
rule, or to relate the locations of expected emission reductions to the
locations of current poor air quality. However, the rule is anticipated
to have substantial emissions reductions of toxic air pollutants (See
Table 2.), some of which are potential carcinogens, neurotoxins, and
respiratory irritants. The rule will also result in substantial
reductions in criteria pollutants such as CO, PM, SO2, as
well as ozone precursors.
    Because of the close proximity of these source categories to
people, the substantial emission reductions of air toxics resulting
from the implementation of this proposed rule is anticipated to have
health benefits for all persons living or going near these types of
sources. (Please refer to the RIA for this rulemaking, which is
available in the docket.) For example, there will be significant
reductions of mercury emissions which will reduce potential exposures
due to the atmospheric deposition of mercury for populations such as
subsistence fisherman. In addition, there will be substantial
reductions in other air toxics that can cause adverse health effects
such as ozone precursors which contribute to ``smog.'' This rule will
not cause an increase in any adverse human health or environmental
effects on any population, including any minority, low-income, or
Tribal populations.
    EPA defines ``Environmental Justice'' to include meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and polices. To promote
meaningful involvement, EPA has developed an EJ communication strategy
to ensure that interested communities have access to this proposed
rule, are aware of its content, and have an opportunity to comment.
During the comment period, EPA will publicize the rulemaking via EJ
newsletters, Tribal newsletters, EJ listserves, and the Internet,
including Office of Policy, Economics, and Innovation's (OPEI)
Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/rulegate.nsf/
content/index.html?opendocument). EPA will also provide general
rulemaking fact sheets (e.g., why is this important for my community)
for EJ community groups and conduct conference calls with interested
communities. In addition, State and Federal permitting requirements
will provide State, local governments and communities the opportunity
to provide their comments on the permit conditions associated with
permitting these sources.

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: April 29, 2010.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part
63 of the Code of Federal Regulations is proposed to be amended as
follows:

PART 63--[AMENDED]

    1. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

Subpart A--[Amended]

    2. Section 63.14 is amended by revising paragraphs (b)(27),
(b)(39), (b)(47), (b)(49), (b)(50), (b)(52), (b)(55), (b)(56), (b)(58),
(b)(61), (b)(62), and (i)(1) to read as follows:

63.14  Incorporation by reference.

* * * * *
    (b) * * *
    (27) ASTM D 6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers,\1\ IBR
approved for Sec.  63.9307(c)(2), Table 4 to subpart ZZZZ, Table 5 to
subpart DDDDD, and Table 4 to subpart JJJJJJ of this part.
* * * * *
    (39) ASTM Method D388-99 [egr]\1\, Standard Classification of Coals
by Rank\1\, IBR approved for Sec.  63.7575 and Sec.  63.11237.
* * * * *
    (47) ASTM D5198-92 (Reapproved 2003), Standard Practice for Nitric
Acid Digestion of Solid Waste,\1\ IBR approved for Table 6 to subpart
DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (49) ASTM D6323-98 (Reapproved 2003), Standard Guide for Laboratory
Subsampling of Media Related to Waste Management Activities,\1\ IBR
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of
this part.
    (50) ASTM E711-87 (Reapproved 1996), Standard Test Method for Gross
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter,\1\ IBR
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of
this part.
* * * * *
    (52) ASTM E871-82 (Reapproved 1998), Standard Method of Moisture
Analysis of Particulate Wood Fuels,\1\ IBR approved for Table 6 to
subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (55) ASTM D2013-04, Standard Practice for Preparing Coal Samples
for Analysis, IBR approved for Table 6 to subpart DDDDD and Table 5 to
subpart JJJJJJ of this part.
    (56) ASTM D2234-D2234M-03 [egr]\1\, Standard Practice for
Collection of a Gross Sample of Coal, IBR approved for Table 6 to
subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (58) ASTM D3173-03, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved

for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this
part.
    (61) ASTM D6722-01, Standard Test Method for Total Mercury in Coal
and Coal Combustion Residues by the Direct Combustion Analysis, IBR
approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of
this part.
    (62) ASTM D5865-04, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Table 6 to subpart DDDDD and Table 5
to subpart JJJJJJ of this part.
* * * * *
    (i) * * *
    (1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.
63.865(b), 63.3166(a), 63.3360(e)(1)(iii), 63.3545(a)(3),
63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3),
63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), Table
5 to subpart DDDDD, and Table 4 to subpart JJJJJJ of this part.
* * * * *
    3. Add subpart JJJJJJ to read as follows:

Subpart JJJJJJ--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
Area Sources

Sec.

What This Subpart Covers

63.11193 Am I subject to this subpart?
63.11194 What is the affected source of this subpart?
63.11195 Are any boilers not subject to this subpart?
63.11196 When do I have to comply with this subpart?

Emission Limits, Work Practice Standards, Emission Reduction Measures,
and Management Practices

63.11200 What are the subcategories of boilers?
63.11201 What standards must I meet?

Initial Compliance Requirements

63.11205 What are my general requirements for complying with this
subpart?
63.11210 What are my initial compliance requirements and by what
date must I conduct them?
63.11211 How do I demonstrate initial compliance with the emission
limits?
63.11212 What stack tests and procedures must I use for the
performance tests?
63.11213 What fuel analyses and procedures must I use for the
performance tests?
63.11214 When must I conduct subsequent performance tests?
63.11215 How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?

Continuous Compliance Requirements

63.11220 How do I monitor and collect data to demonstrate continuous
compliance?
63.11221 How do I demonstrate continuous compliance with the
emission limits?
63.11222 How do I demonstrate continuous compliance with the work
practice standards?
63.11223 What are my monitoring, installation, operation, and
maintenance requirements?
63.11225 What are my notification, reporting, and recordkeeping
requirements?

Other Requirements and Information

63.11235 What parts of the General Provisions apply to me?
63.11236 Who implements and enforces this subpart?
63.11237 What definitions apply to this subpart?
Table 1 to Subpart JJJJJJ of Part 63. Emission Limits
Table 2 to Subpart JJJJJJ of Part 63. Work Practice Standards
Table 3 to Subpart JJJJJJ of Part 63. Operating Limits for Boilers
With Emission Limits
Table 4 to Subpart JJJJJJ of Part 63. Performance (Stack) Testing
Requirements
Table 5 to Subpart JJJJJJ of Part 63. Fuel Analysis Requirements
Table 6 to Subpart JJJJJJ of Part 63. Applicability of General
Provisions to Subpart JJJJJJ

Subpart JJJJJJ--National Emission Standards for Hazardous Air
Pollutants for Industrial, Commercial, and Institutional Boilers
Area Sources

What This Subpart Covers

Sec.  63.11193 Am I subject to this subpart?
    You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler as defined in Sec.
63.11237 that is located at, or is part of, an area source of hazardous
air pollutants (HAP), as defined in Sec.  63.2.

Sec.  63.11194  What is the affected source of this subpart?

    (a) This subpart applies to each new or existing affected sources
as defined in paragraphs (a)(1) and (2) of this section.
    (1) The affected source is the collection of all existing
industrial, commercial, and institutional boilers within a subcategory
located at an area source.
    (2) The affected source of this subpart is each new or
reconstructed industrial, commercial, or institutional boiler located
at an area source.
    (b) An affected source is an existing source if you commenced
construction or reconstruction of the affected source on or before June
4, 2010.
    (c) An affected source is a new source if you commenced
construction or reconstruction of the affected source after June 4,
2010.
    (d) A boiler is a new affected source if you commenced fuel
switching from natural gas to coal, biomass, or oil after June 4, 2010.
    (e) Any source that was a major source and installed a control
device on a boiler after November 15, 1990, and, as a result, became an
area source under 40 CFR part 63 is required to obtain a permit under
40 CFR part 70 or 40 CFR part 71. Otherwise, you are exempt from the
obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71,
provided you are not otherwise required by law to obtain a permit under
40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous
sentence, you must continue to comply with the provisions of this
subpart.

Sec.  63.11195  Are any boilers not subject to this subpart?

    The types of boilers listed in paragraphs (a) through (e) of this
section are not subject to this subpart.
    (a) Any boiler specifically listed as an affected source in another
standard(s) under this part.
    (b) Any boiler specifically listed as an affected source in another
standard(s) established under section 129 of the Clean Air Act (CAA).
    (c) A boiler required to have a permit under section 3005 of the
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g.,
hazardous waste boilers).
    (d) A boiler that is used specifically for research and
development. This does not include boilers that only provide steam to a
process or for heating at a research and development facility.
    (e) A gas-fired boiler as defined in this subpart.

Sec.  63.11196  What are my compliance dates?

    (a) If you own or operate an existing affected source, you must
achieve compliance with the applicable provisions in this subpart no
later than [DATE 3 YEARS AFTER PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER].
    (b) If you start up a new affected source on or before [DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
achieve compliance with the provisions of this subpart no later than
[DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].
    (c) If you start up a new affected source after [DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
achieve compliance with the provisions of this

subpart upon startup of your affected source.

Emission Limits, Work Practice Standards, Emission Reduction Measures,
and Management Practices

Sec.  63.11200  What are the subcategories of boilers?

    The subcategories of boilers are coal, biomass, and oil. Each
subcategory is defined in Sec.  63.11237.

Sec.  63.11201  What standards must I meet?

    (a) You must comply with each emission limit specified in Table 1
of this subpart that applies to your boiler.
    (b) You must comply with each work practice standard, emission
reduction measure, and management practice specified in Table 2 of this
subpart that applies to your boiler.
    (c) These standards apply at all times.

Initial Compliance Requirements

Sec.  63.11205  What are my general requirements for complying with
this subpart?

    (a) 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. The general duty to
minimize emissions does not require you to make any further efforts to
reduce emissions if levels required by this standard have been
achieved. Determination of whether such operation and maintenance
procedures are being used will be based on information available to the
Administrator which 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) You can demonstrate compliance with any applicable mercury
emission limit using fuel analysis if the emission rate calculated
according to Sec.  63.11211(b) is less than the applicable emission
limit. Otherwise, you must demonstrate compliance using stack testing.

Sec.  63.11210  What are my initial compliance requirements and by what
date must I conduct them?

    (a) You must demonstrate initial compliance with each emission
limit specified in Table 1 of this subpart that applies to you by
either conducting performance (stack) tests, as applicable, according
to Sec.  63.11212 and Table 4 of this subpart or conducting fuel
analyses, as applicable, according to Sec.  63.11213 and Table 5 to
this subpart.
    (b) For affected sources that have an applicable carbon monoxide
(CO) emission limit, your initial compliance requirements depend on the
rated capacity of your boiler. If your boiler has a heat input capacity
between 10 and 100 million British thermal units (MMBtu) per hour, your
initial compliance demonstration is conducting a performance test for
CO according to Table 4 to this subpart. If your boiler has a heat
input capacity of 100 MMBtu per hour or greater, your initial
compliance demonstration is conducting a performance evaluation of your
continuous emission monitoring system (CEMS) for CO according to Sec.
63.11223.
    (c) For existing affected sources that have applicable emission
limits, you must demonstrate initial compliance no later than 180 days
after the compliance date that is specified in Sec.  63.11196 and
according to the applicable provisions in Sec.  63.7(a)(2).
    (d) For existing affected sources that have applicable work
practice standards or emission reduction measures, you must demonstrate
initial compliance no later than the compliance date that is specified
in Sec.  63.11196 and according to the applicable provisions in Sec.
63.7(a)(2).
    (e) For new affected sources, you must demonstrate initial
compliance no later than 180 calendar days after [INSERT THE DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 180
calendar days after startup of the source, whichever is later,
according to Sec.  63.7(a)(2)(ix).

Sec.  63.11211  How do I demonstrate initial compliance with the
emission limits?

    (a) For affected sources that elect to demonstrate compliance with
any of the emission limits of this subpart through performance (stack)
testing, your initial compliance requirements include conducting
performance tests according to Sec.  63.11212 and Table 4 to this
subpart and conducting CMS performance evaluations according to Sec.
63.11223.
    (b) If you elect to demonstrate compliance with an applicable
mercury emission limit through fuel analysis, you must conduct fuel
analyses according to Sec.  63.11213 and follow the procedures in
paragraphs (b)(1) through (3) of this section.
    (1) If you burn more than one fuel type, you must determine the
fuel mixture you could burn in your boiler that would result in the
maximum emission rates of mercury that you elect to demonstrate
compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel
mercury concentration of the composite samples analyzed for each fuel
type using Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.001

Where:

P90 = 90th percentile confidence level mercury
concentration, in pounds per million Btu;
mean = Arithmetic average of the fuel mercury concentration in the
fuel samples analyzed according to Sec.  63.11213, in units of
pounds per million Btu;
SD = Standard deviation of the mercury concentration in the fuel
samples analyzed according to Sec.  63.11213, in units of pounds per
million Btu;
t = t distribution critical value for 90th percentile (0.1)
probability for the appropriate degrees of freedom (number of
samples minus one) as obtained from a Distribution Critical Value
Table.

    (3) To demonstrate compliance with the applicable mercury emission
limit, the emission rate that you calculate for your boiler using
Equation 1 of this section must be less than the applicable mercury
emission limit.

Sec.  63.11212  What stack tests and procedures must I use for the
performance tests?

    (a) You must conduct all performance tests according to the
requirements in Sec.  63.7.
    (b) You must conduct each stack test according to the requirements
in Table 4 to this subpart.
    (c) You must conduct stack tests at the maximum normal operating
load while burning the type of fuel or mixture of fuels that have the
highest content of mercury, and you must demonstrate initial compliance
based on these tests.
    (d) You must conduct a minimum of three separate test runs for each
performance test required in this section, as specified in Sec.
63.7(e)(3). The sampling time for each test run must last at least 1
hour except that the sampling time for the test runs conducted for
mercury emissions must last at least 2 hours.
    (e) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 of appendix A to part 60 of this chapter to convert the
measured particulate matter concentrations and the measured mercury
concentrations that result from the initial performance test to pounds
per million Btu heat input emission rates.

Sec.  63.11213  What fuel analyses and procedures must I use for the
performance tests?

    (a) You must conduct fuel analyses according to the procedures in

paragraphs (b) and (c) of this section and Table 5 to this subpart, as
applicable.
    (b) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in Table 5 of this subpart.
Each composite sample will consist of a minimum of three samples
collected at approximately equal intervals during a test run period.
    (c) Determine the concentration of mercury in the fuel in units of
pounds per million Btu of each composite sample for each fuel type
according to the procedures in Table 5 to this subpart.

Sec.  63.11214  When must I conduct subsequent performance tests?

    (a) You must conduct all applicable performance (stack) tests
according to Sec.  63.11212 on an annual basis, unless you follow the
requirements listed in paragraphs (b) through (d) of this section.
Annual performance tests must be completed between 10 and 12 months
after the previous performance test, unless you follow the requirements
listed in paragraphs (b) through (d) of this section.
    (b) You can conduct performance stack tests less often for
particulate matter or mercury if your performance stack tests for the
pollutant for at least 3 consecutive years show that your emissions are
at or below 75 percent of the emission limit, and if there are no
changes in the operation of the affected source or air pollution
control equipment that could increase emissions. In this case, you do
not have to conduct a performance test for that pollutant for the next
2 years. You must conduct a performance test during the third year and
no more than 36 months after the previous performance test.
    (c) If your boiler continues to meet the emission limit for
particulate matter or mercury, you may choose to conduct performance
stack tests for the pollutant every third year if your emissions are at
or below 75 percent of the emission limit, and if there are no changes
in the operation of the affected source or air pollution control
equipment that could increase emissions, but each such performance test
must be conducted no more than 36 months after the previous performance
test.
    (d) If a performance test shows emissions exceeded 75 percent of
the emission limit, you must conduct annual performance tests for that
pollutant until all performance tests over consecutive 3-year period
show compliance.
    (e) If you have an applicable CO emission limit and your boiler has
a heat input capacity between 10 and 100 MMBtu per hour, you must
conduct annual performance tests for CO according to Sec.  63.11211.
Each annual performance test must be conducted between 10 and 12 months
after the previous performance test.
    (f) If you demonstrate compliance with the mercury based on fuel
analysis, you must conduct a fuel analysis according to Sec.  63.11213
for each type of fuel burned monthly. If you plan to burn a new type of
fuel or fuel mixture, you must conduct a fuel analysis before burning
the new type of fuel or mixture in your boiler. You must recalculate
the mercury emission rate using Equation 1 of Sec.  63.11211. The
recalculated mercury emission rate must be less than the applicable
emission limit.

Sec.  63.11215  How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?

    (a) If you own or operate an existing boiler with a heat input
capacity of less than 10 million Btu per hour, you must submit a signed
statement in the Notification of Compliance Status report that
indicates that you conducted a tune-up of the boiler.
    (b) If you own or operate an existing affected boiler with a heat
input capacity of 10 million Btu per hour or greater, you must submit
the energy assessment report, along with a signed certification that
the assessment is an accurate depiction of your facility.

Continuous Compliance Requirements

Sec.  63.11220  How do I monitor and collect data to demonstrate
continuous compliance?

    (a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec.  63.11223.
    (b) Except for monitor malfunctions, associated repairs, and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must monitor continuously (or collect data at all required
intervals) at all times that the affected source is operating.
    (c) You may not use data recorded during monitoring malfunctions,
associated repairs, or required quality assurance or control activities
in data averages and calculations used to report emission or operating
levels. You must use all the data collected during all other periods in
assessing the operation of the control device and associated control
system.

Sec.  63.11221  How do I demonstrate continuous compliance with the
emission limits?

    (a) You must demonstrate continuous compliance with each emission
limit and operating limit in Tables 1 and 3 to this subpart that
applies to you according to paragraphs (a)(1) through (5) of this
section.
    (1) Following the date on which the initial performance test is
completed or is required to be completed under Sec. Sec.  63.7 and
63.11196, whichever date comes first, you must not operate above any of
the applicable maximum operating limits or below any of the applicable
minimum operating limits listed in Table 3 to this subpart at all
times. Operation above the established maximum or below the established
minimum operating limits shall constitute a deviation of established
operating limits. Operating limits are confirmed or reestablished
during performance tests.
    (2) If you have an applicable mercury emission limit, you must keep
records of the type and amount of all fuels burned in each boiler
during the reporting period to demonstrate that all fuel types and
mixtures of fuels burned would result in lower emissions of mercury
than the applicable emission limit.
    (3) If you have you have an applicable mercury emission limit and
you plan to burn a new type of fuel, you must determine the mercury
concentration for any new fuel type in units of pounds per million Btu,
based on supplier data or your own fuel analysis and meet the
requirements in paragraphs (a)(3)(i) or (ii) of this section.
    (i) The recalculated mercury emission rate must be less than the
applicable emission limit.
    (ii) If the results are higher than mercury fuel input during the
previous performance test, then you must conduct a new performance test
within 60 days of burning the new fuel type or fuel mixture according
to the procedures in Sec.  63.11212 to demonstrate that the mercury
emissions do not exceed the emission limit.
    (4) If your unit is controlled with a fabric filter, and you
demonstrate continuous compliance using a bag leak detection system,
you must initiate corrective action within 1 hour of a bag leak
detection system alarm and operate and maintain the fabric filter
system such that the alarm does not sound more than 5 percent of the
operating time during a 6-month period. You must also keep records of
the date, time, and duration of each alarm, the time corrective action
was initiated and completed, and a brief description of the

cause of the alarm and the corrective action taken. You must also
record the percent of the operating time during each 6-month period
that the alarm sounds. In calculating this operating time percentage,
if inspection of the fabric filter demonstrates that no corrective
action is required, no alarm time is counted. If corrective action is
required, each alarm shall be counted as a minimum of 1 hour. If you
take longer than 1 hour to initiate corrective action, the alarm time
shall be counted as the actual amount of time taken to initiate
corrective action.
    (5) If you have an applicable CO emission limit and you are
required to install a CEMS according to Sec.  63.11223, then you must
continuously monitor CO according to Sec. Sec.  63.11223(a) and
63.11220 and maintain a CO emission level below your applicable CO
emission limit in Table 1 to this subpart at all times.
    (b) You must report each instance in which you did not meet each
emission limit and operating limit in Tables 1 and 3 to this subpart
that apply to you. These instances are deviations from the emission
limits in this subpart. These deviations must be reported according to
the requirements in Sec.  63.11224.

Sec.  63.11222  How do I demonstrate continuous compliance with the
work practice and management practice standards?

    (a) For affected sources subject to the work practice standard or
the management practices, you must keep records as required in Sec.
63.11224(c) to demonstrate continuous compliance.
    (b) You must conduct a tune-up of the boiler biennially to
demonstrate continuous compliance as specified in paragraphs (b)(1)
through (6) of this section.
    (1) Inspect the burner, and clean or replace any components of the
burner as necessary;
    (2) Inspect the flame pattern and make any adjustments to the
burner necessary to optimize the flame pattern consistent with the
manufacturer's specifications;
    (3) Inspect the system controlling the air-to-fuel ratio, and
ensure that it is correctly calibrated and functioning properly;
    (4) Minimize total emissions of CO consistent with the
manufacturer's specifications;
    (5) Measure the concentration in the effluent stream of CO in parts
per million, by volume, dry basis (ppmvd), before and after the
adjustments are made; and
    (6) Maintain on-site and submit, if requested by the Administrator,
an annual report containing the information in paragraphs (b)(6)(i)
through (iii) of this section,
    (i) The concentrations of CO in the effluent stream in ppmvd, and
oxygen in percent dry basis, measured before and after the adjustments
of the boiler;
    (ii) A description of any corrective actions taken as a part of the
combustion adjustment; and
    (iii) The type and amount of fuel used over the 12 months prior to
the annual adjustment.

Sec.  63.11223  What are my monitoring, installation, operation, and
maintenance requirements?

    (a) If you are using a control device to comply with the emission
limits specified in Table 1 of this subpart, you must maintain each
operating limit in Table 3 of this subpart that applies to your boiler.
If you use a control device not covered in Table 3, or you wish to
establish and monitor an alternative operating limit and alternative
monitoring parameters, you must apply to the United States
Environmental Protection Agency (EPA) Administrator for approval of
alternative monitoring under Sec.  63.8(f).
    (b) If you demonstrate compliance with any applicable emission
limit through stack testing, you must develop a site-specific
monitoring plan according to the requirements in paragraphs (b)(1)
through (4) of this section. This requirement also applies to you if
you petition the EPA Administrator for alternative monitoring
parameters under Sec.  63.8(f).
    (1) For each continuous monitoring system (CMS) required in this
section, you must develop, and submit to the EPA Administrator for
approval upon request, a site-specific monitoring plan that addresses
paragraphs (b)(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.
    (i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected 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).
    (2) In your site-specific monitoring plan, you must also address
paragraphs (b)(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), (3), and (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), (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.
    (c) If you have an operating limit that requires the use of a CMS,
you must install, operate, and maintain each continuous parameter
monitoring system (CPMS) according to the procedures in paragraphs
(c)(1) through (5) of this section.
    (1) The CPMS must complete a minimum of one cycle of operation for
each successive 15-minute period. You must have a minimum of four
successive cycles of operation to have a valid hour of data.
    (2) Except for monitoring malfunctions, associated repairs, and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must conduct all monitoring in continuous operation at all times
that the unit is operating. A monitoring malfunction is any sudden,
infrequent, not reasonably preventable failure of the monitoring to
provide valid data. Monitoring failures that are caused in part by poor
maintenance or careless operation are not malfunctions.
    (3) For purposes of calculating data averages, you must not use
data recorded during monitoring malfunctions, associated repairs, out
of control periods, or required quality assurance or control
activities. You must use all the data collected during all other
periods in assessing compliance. Any period for which the monitoring
system is out-of-control and data are not available for required
calculations constitutes a deviation from the monitoring requirements.
    (4) Determine the 3-hour block average of all recorded readings,
except as provided in paragraph (c)(3) of this section.
    (5) Record the results of each inspection, calibration, and
validation check.
    (d) If you have an applicable opacity operating limit, you must
install, operate, certify and maintain each

continuous opacity monitoring system (COMS) according to the procedures
in paragraphs (d)(1) through (7) of this section by the compliance date
specified in Sec.  63.11196.
    (1) Each COMS must be installed, operated, and maintained according
to PS 1 of 40 CFR part 60, appendix B.
    (2) You must conduct a performance evaluation of each COMS
according to the requirements in Sec.  63.8 and according to PS 1 of 40
CFR part 60, appendix B.
    (3) As specified in Sec.  63.8(c)(4)(i), each COMS must complete a
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
    (4) The COMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
COMS according to the requirements in Sec.  63.8(d). At a minimum, the
monitoring plan must include a daily calibration drift assessment, a
quarterly performance audit, and an annual zero alignment audit of each
COMS.
    (6) You must operate and maintain each COMS according to the
requirements in the monitoring plan and the requirements of Sec.
63.8(e). Identify periods the COMS is out of control including any
periods that the COMS fails to pass a daily calibration drift
assessment, a quarterly performance audit, or an annual zero alignment
audit.
    (7) You must determine and record all the 1-hour block averages
collected for periods during which the COMS is not out of control.
    (e) If you have an applicable CO emission limit and your boiler has
a heat input capacity of 100 MMBtu per hour or greater, you must
install, operate, and maintain a CEMS for CO and oxygen according to
the procedures in paragraphs (e)(1) through (6) of this section by the
compliance date specified in Sec.  63.11196. The CO and oxygen shall be
monitored at the same location at the outlet of the boiler.
    (1) Each CEMS must be installed, operated, and maintained according
to Performance Specification (PS) 4A of 40 CFR part 60, appendix B, and
according to the site-specific monitoring plan developed according to
Sec.  63.11223.
    (2) You must conduct a performance evaluation of each CEMS
according to the requirements in Sec.  63.8 and according to PS 4A of
40 CFR part 60, appendix B.
    (3) Each CEMS must complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period.
    (4) The CEMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must calculate and record all daily averages. A new daily
average emission rate is calculated as the average of all of the hourly
CO emission data for the calendar day.
    (6) For purposes of calculating data averages, you must not use
data recorded during periods of monitoring malfunctions, associated
repairs, out-of-control periods, required quality assurance or control
activities, or when your boiler is operating at less than 50 percent of
its rated capacity. You must use all the data collected during all
other periods in assessing compliance. Any period for which the
monitoring system is out of control and data are not available for
required calculations constitutes a deviation from the monitoring
requirements.
    (f) You must include in your site-specific monitoring plan
procedures and acceptance criteria for operating and maintaining each
CEMS according to the requirements in Sec.  63.8(d).

Sec.  63.11224  What are my notification, reporting, and recordkeeping,
requirements?

    (a) You must submit the notifications specified in paragraphs
(a)(1) through (a)(4) of this section.
    (1) You must submit all of the notifications in Sec. Sec.  63.5(b),
63.7(b): 63.8(e) and (f); 63.9(b) through (e); and 63.9(g) and (h) that
apply to you by the dates specified in those sections.
    (2) As specified in Sec.  63.9(b)(2), you must submit the Initial
Notification no later than 120 calendar days after [INSERT THE DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 120
days after the source becomes subject to the standard.
    (3) You must submit the Notification of Compliance Status in
accordance with Sec.  63.9(h) no later than 120 days after the
applicable compliance date specified in Sec.  63.11196 unless you must
conduct a performance test. If you must conduct a performance test, you
must submit the Notification of Compliance Status within 60 days of
completing the performance test. In addition to the information
required in Sec.  63.9(h)(2), your notification must include the
following certification(s) of compliance, as applicable, and signed by
a responsible official:
    (i) ``This facility complies with the requirements in Sec.
63.11222(b) to conduct a biennial tune-up of the boiler''.
    (ii) ``This facility has had an energy assessment performed
according to Sec.  63.11215.''
    (iii) This certification of compliance by the owner or operator
that installs bag leak detection systems: ``This facility has prepared
a bag leak detection system monitoring plan in accordance with Sec.
63.11221 and will operate each bag leak detection system according to
the plan.''
    (4) If you are using data from a previously conducted emission test
to serve as documentation of conformance with the emission standards
and operating limits of this subpart consistent with Sec.
63.7(e)(2)(iv), you must submit the test data in lieu of the initial
performance test results with the Notification of Compliance Status
required under paragraph (a)(3) of this section.
    (b) You must prepare, by March 1 of each year, an annual compliance
certification report for the previous calendar year containing the
information specified in paragraphs (b)(1) through (b)(3) of this
section. You must submit the report by March 15 if you had any instance
described by paragraph (b)(3) of this section.
    (1) Company name and address.
    (2) Statement by a responsible official, with the official's name,
title, phone number, e-mail address, and signature, certifying the
truth, accuracy and completeness of the notification and a statement of
whether the source has complied with all the relevant standards and
other requirements of this subpart.
    (3) If the source is not in compliance, include a description of
deviations from the applicable requirements, the time periods during
which the deviations occurred, and the corrective actions taken.
    (4) The total fuel use by each affected source subject to an
emission limit, for each calendar month within the reporting period,
including, but not limited to, a description of the fuel, including
whether the fuel has received a non-waste determination by you or EPA,
and the total fuel usage amount with units of measure.
    (c) You must maintain the records specified in paragraphs (c)(1)
through (5) of this section.
    (1) As required in Sec.  63.10(b)(2)(xiv), you must keep a copy of
each notification and report that you submitted to comply with this
subpart and all documentation supporting any Initial Notification or
Notification of Compliance Status that you submitted.
    (2) You must keep records to document conformance with the work
practices, emission reduction measures, and management practices
required by

Sec.  63.11215 as specified in paragraphs (c)(2)(i) through (iv) of
this section.
    (i) Records must identify each boiler, the date of tune-up, the
procedures followed for tune-up, and the manufacturer's specifications
to which the boiler was tuned.
    (ii) Records documenting monthly fuel use by each boiler, including
the type(s) of fuel, including, but not limited to, a description of
the fuel, including whether the fuel has received a non-waste
determination by you or EPA, and the total fuel usage amount with units
of measure.
    (3) For sources that demonstrate compliance through fuel analysis,
a copy of all calculations and supporting documentation that were done
to demonstrate compliance with the mercury emission limits. Supporting
documentation should include results of any fuel analyses. You can use
the results from one fuel analysis for multiple boilers provided they
are all burning the same fuel type.
    (4) You must keep the records of all inspection and monitoring data
required by Sec. Sec.  63.11221 and 63.11222, and the information
identified in paragraphs (c)(4)(i) through (vi) of this section for
each required inspection or monitoring.
    (i) The date, place, and time of the monitoring event;
    (ii) Person conducting the monitoring;
    (iii) Technique or method used;
    (iv) Operating conditions during the activity;
    (v) Results, including the date, time, and duration of the period
from the time the monitoring indicated a problem to the time that
monitoring indicated proper operation; and
    (vi) Maintenance or corrective action taken (if applicable).
    (5) If you use a bag leak detection system, you must keep the
records specified in paragraphs (c)(5)(i) through (iii) of this
section.
    (i) Records of the bag leak detection system output.
    (ii) Records of bag leak detection system adjustments, including
the date and time of the adjustment, the initial bag leak detection
system settings, and the final bag leak detection system settings.
    (iii) The date and time of all bag leak detection system alarms,
and for each valid alarm, the time you initiated corrective action, the
corrective action taken, and the date on which corrective action was
completed.
    (d) Your records must be in a form suitable and readily available
for expeditious review, according to Sec.  63.10(b)(1). As specified in
Sec.  63.10(b)(1), you must keep each record for 5 years following the
date of each recorded action. You must keep each record onsite for at
least 2 years after the date of each recorded action according to Sec.
63.10(b)(1). You may keep the records offsite for the remaining 3
years.
    (e) For affected facilities having applicable emission limits, you
must submit an electronic copy of stack test reports to EPA's WebFIRE
data base, the owner or operator of an affected facility shall enter
the test data into EPA's data base using the Electronic Reporting Tool
located at http://www.epa.gov/ttn/chief/ert/ert_tool.html.

Other Requirements and Information

Sec.  63.11235  What parts of the General Provisions apply to me?

    Table 6 to this subpart shows which parts of the General Provisions
in Sec. Sec.  63.1 through 63.15 apply to you.

Sec.  63.11236  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by EPA or a
delegated authority such as your State, local, or tribal agency. If the
EPA Administrator has delegated authority to your State, local, or
tribal agency, then that agency has the authority to implement and
enforce this subpart. You should contact your EPA Regional Office to
find out if implementation and enforcement of this subpart is delegated
to your State, local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this
subpart to a State, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities contained in paragraphs (c) of this section
are retained by the EPA Administrator and are not transferred to the
State, local, or tribal agency.
    (c) The authorities that cannot be delegated to State, local, or
tribal agencies are specified in paragraphs (c)(1) through (5) of this
section.
    (1) Approval of an alternative non-opacity emission standard and
work practice standards in Sec.  63.11223(a).
    (2) Approval of alternative opacity emission standard under Sec.
63.6(h)(9).
    (3) Approval of major change to test methods under Sec.
63.7(e)(2)(ii) and (f). A ``major change to test method'' is defined in
Sec.  63.90.
    (4) Approval of a major change to monitoring under Sec.  63.8(f). A
``major change to monitoring'' is defined in Sec.  63.90.
    (5) Approval of major change to recordkeeping and reporting under
Sec.  63.10(f). A ``major change to recordkeeping/reporting'' is
defined in Sec.  63.90.

Sec.  63.11237  What definitions apply to this subpart?

    Terms used in this subpart are defined in the CAA, in Sec.  63.2
(the General Provisions), and in this section as follows:
    Bag leak detection system means an instrument that is capable of
monitoring particulate matter loadings in the exhaust of a fabric
filter (i.e., baghouse) in order to detect bag failures. A bag leak
detection system includes, but is not limited to, an instrument that
operates on electrodynamic, triboelectric, light scattering, light
transmittance, or other principle to monitor relative particulate
matter loadings.
    Biomass means but is not limited to, wood residue, and wood
products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust,
sanderdust, chips, scraps, slabs, millings, and shavings); animal
manure, including litter and other bedding materials; vegetative
agricultural and silvicultural materials, such as logging residues
(slash), nut and grain hulls and chaff (e.g., almond, walnut, peanut,
rice, and wheat), bagasse, orchard prunings, corn stalks, coffee bean
hulls and grounds. This definition of biomass fuel is not intended to
suggest that these materials are or not solid waste.
    Biomass subcategory includes any boiler that burns any amount of
biomass, but no coal, either alone or in combination with liquid fuels
or gaseous fuels.
    Boiler means an enclosed combustion device in which water is heated
to recover thermal energy in the form of steam or hot water. A device
combusting solid waste, as defined in 40 CFR 241.3, is not a boiler.
Waste heat boilers are excluded from this definition.
    Boiler system means the boiler and associated components, such as,
the feedwater system, the combustion air system, the fuel system
(including burners), blowdown system, combustion control system, and
the energy consuming systems.
    Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by the American Society for Testing and
Materials in ASTM D388-99e1, ``Standard Specification for
Classification of Coals by Rank\1\'' (incorporated by reference, see
Sec.  63.14(b)) and synthetic fuels derived from coal including but not
limited to, solvent-refined coal, coal-oil mixtures, and coal-water
mixtures. Coal derived gases are excluded from this definition.
    Coal subcategory includes any boiler that burns any coal alone or
at least 10

percent coal on an annual heat input basis in combination with biomass,
liquid fuels, or gaseous fuels.
    Commercial boiler means a boiler used in commercial establishments
such as hotels, restaurants, and laundries to provide electricity,
steam, and/or hot water that does not combust solid waste, as that term
is defined by the Administrator under RCRA.
    Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
    (2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
    (3) A deviation is not always a violation. The determination of
whether a deviation constitutes a violation of the standard is up to
the discretion of the entity responsible for enforcement of the
standards.