Note: Totals may not add due to independent rounding. 95 percent
  confidence intervals for literature-based estimates are shown in
  parenthesis.

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

    We estimate the monetized benefits of this proposed regulatory
action to be $17 billion to $41 billion (2008$, 3 percent discount
rate) in the implementation year (2013). The monetized benefits of the
proposed regulatory action at a 7 percent discount rate are $15 billion
to $37 billion (2008$). 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.\22\ A summary of the
monetized benefits estimates at discount rates of 3 percent and 7
percent is in Table 13 of this preamble.
---------------------------------------------------------------------------

    \22\ 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 13--Summary of the Monetized Benefits Estimates for the Proposed Boiler MACT for Major Sources 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....................................       29,020  $6.6 to $16................  $6.0 to $15.
PM2.5 Precursors
    SO2..................................      339,996  $10 to $25.................  $9.1 to $22.
    VOC..................................        1,786  $0.002 to $0.005...........  $0.002 to $0.005.
                                          ----------------------------------------------------------------------
        Total............................  ...........  $17 to $41.................  $15 to $37.
----------------------------------------------------------------------------------------------------------------
\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) 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 on the laid out in Fann et al.
(2009).\23\
---------------------------------------------------------------------------

    \23\ 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 \24\ and the extended Six Cities
cohort study.\25\ 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.
---------------------------------------------------------------------------

    \24\ 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.
    \25\ 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 \26\
provides an indication of the sensitivity of our results to various
assumptions.
---------------------------------------------------------------------------

    \26\ 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 330,000 tons of carbon monoxide, 37,000 tons of HCl,
1,000 tons of HF each year, 7.5 tons of mercury, 3,200 tons of other
metals, and 720 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
$2.9 billion (2008$) in the implementation year, and the monetized
benefits are $17 billion to $41 billion (2008$, 3 percent discount
rate) for that same year. The benefits at a 7 percent discount rate are
$15 billion to $37 billion (2008$). Thus, net benefits of this
rulemaking are estimated at $14 billion to $38 billion (2008$, 3
percent discount rate) and $12 billion to $34 billion (2008$, 7 percent
discount rate). EPA believes that the benefits of the proposed rule are
likely to exceed the costs even when taking into account the
uncertainties in the cost and benefit estimates. A summary of the
monetized benefits, social costs, and net benefits at discount rates of
3 percent and 7 percent is in Table 14 of this preamble.

   Table 14--Summary of the Monetized Benefits, Social Costs, and Net
          Benefits for the Boiler MACT (Major Sources) in 2013
                         [Millions of 2008$] \1\
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
                             Proposed Option
------------------------------------------------------------------------
Total Monetized Benefits \2\....  $17 to $41........  $15 to $37.
------------------------------------------------------------------------
Total Social Costs \3\..........  $2.9..............  $2.9.
------------------------------------------------------------------------
Net Benefits....................  $14 to $38........  $12 to $34.
------------------------------------------------------------------------
Non-monetized Benefits..........  340,000 tons of carbon monoxide.
                                  37,000 tons of HCl.
                                  1,000 tons of HF.
                                  7.5 tons of mercury.
                                  3,200 tons of other metals.
                                  720 grams of dioxins/furans.
                                  Health effects from NO2 and SO2
                                   exposure.
                                  Ecosystem effects.
                                  Visibility impairment.

         sProposed Option with Alternate Solid Waste Definition
------------------------------------------------------------------------
Total Monetized Benefits \2\....  $3.1 to $7.7......  $2.8 to $6.9.
------------------------------------------------------------------------
Total Social Costs \3\..........  $2.2..............  $2.2.
------------------------------------------------------------------------
Net Benefits....................  $0.93 to $5.5.....  $0.64 to $4.7.
------------------------------------------------------------------------
Non-monetized Benefits..........  280,000 tons of carbon monoxide.
                                  5,100 tons of HCl.
                                  1,100 tons of HF.
                                  7.1 tons of mercury.
                                  1,600 tons of other metals.
                                  290 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.

VI. Public Participation and Requests for Comment

    We request comment on all aspects of this proposed rule.
    In 2004 we published a final rule for boilers and process heaters
located at major source facilities (69 FR 55218, September 13, 2004).
The final rule was vacated and remanded by the Court on June 19, 2007.
We are reissuing our proposal, in response to the Court's decisions, in
this notice. We received many comments on that vacated rule during its
rulemaking and have attempted to take all those comments into account
in this action. This proposal includes a variety of changes from the
vacated rule, mostly centered on emission limits for the various HAP
and subcategories.
    During this rulemaking, we conducted outreach to small entities and
convened a Small Business Advocacy Review (SBAR) Panel to obtain advice
and recommendation of representatives of the small entities that
potentially would be subject to the requirements of this proposed rule.
As part of the SBAR Panel process we conducted outreach with
representatives from various small entities that would be affected by
this proposed rule. We met with these small entity representatives
(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. We met with SERs from the industries that will be
impacted directly by this proposed rule to discuss the outreach
materials and receive feedback on the approaches and alternatives
detailed in the outreach packet. 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.

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

    Section 112(c)(6) of the CAA 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 and extractable organic matter.) In the
Federal Register notice Source Category Listing for Section 112(d)(2)
Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838,
17849, Table 2 (1998), 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 (either fabric
filter or wet scrubber) and activated carbon injection in the fabric
filter-based systems further reduce emissions of these organic
pollutants, and also reduce mercury emissions, as is evidenced by
performance data. Specifically, the emission tests obtained at
currently operating units show that the proposed MACT regulations will
reduce mercury 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 Section 112(c)(6) of the CAA.
    In lieu of establishing numerical emissions limits for pollutants
such as POM, we regulate surrogate substances. While we have not
identified specific numerical limits for POM, we believe CO serves as
an effective surrogate for this HAP, because CO, like POM, is formed as
a byproduct of 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 and process heaters 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 Reviews

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 the Office of Management
and Budget (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 14 of this preamble.

B. Executive Order 13132, Federalism

    Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications.'' ``Policies that have
federalism implications'' is defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.
    This proposed rule does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Thus, Executive Order 13132 does
not apply to this proposed rule. In the spirit of Executive Order
13132, and consistent with EPA policy to promote communications between
EPA and State and local governments, EPA specifically solicited comment
on this proposed rule from State and local officials.

C. 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.'' This 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. This 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 this 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 this proposed rule. EPA specifically
solicits additional comment on this proposed rule from tribal
officials.

D. 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 this planned rule on children, and explain why this
planned regulation is preferable to other potentially effective

and reasonably feasible alternatives considered by the Agency.
    This 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 this 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 this
proposed rule.

E. 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 directs us to develop NESHAP which
require existing and new major sources to control emissions of HAP
using MACT based standards. This NESHAP applies to all industrial,
commercial, and institutional boilers and process heaters located at
major sources of HAP emissions.
    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 rule is based
represents the MACT floor for industrial boilers and process heaters
and, as a result, it is the least costly and least burdensome
alternative.
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 $2.9 billion (2008 dollars).
    It is estimated that 3 years after implementation of the proposed
rule, HAPs would be reduced by thousands of tons, including reductions
in hydrochloric acid, hydrogen fluoride, metallic HAP including
mercury, and several other organic HAP from boilers and process
heaters. Studies have determined a relationship between exposure to
these HAP and the onset of cancer, however, the Agency is unable to
provide a monetized estimate of the HAP benefits at this time. In
addition, there are significant reductions in PM2.5 and in
SO2 that would occur, including 29 thousand tons of
PM2.5 and 340 thousand tons of SO2. These
reductions occur within 3 years after the implementation of the
proposed regulation and are expected to continue throughout the life of
the affected sources. The major health effect associated with reducing
PM2.5 and PM2.5 precursors (such as
SO2) is a reduction in premature mortality. Other health
effects associated with PM2.5 emission reductions include
avoiding cases of chronic bronchitis, heart attacks, asthma attacks,
and work-lost days (i.e., days when employees are unable to work).
While we are unable to monetize the benefits associated with the HAP
emissions reductions, we are able to monetize the benefits associated
with the PM2.5 and SO2 emissions reductions. For
SO2 and PM2.5, we estimated the benefits
associated with health effects of PM but were unable to quantify all
categories of benefits (particularly those associated with ecosystem
and visibility effects). Our estimates of the monetized benefits in
2013 associated with the implementation of the proposed alternative is
a range from $17 billion (2008 dollars) to $41 billion (2008 dollars)
when using a 3 percent discount rate (or from $15 billion (2008
dollars) to $37 billion (2008 dollars) when using a 7 percent discount
rate). This estimate, at a 3 percent discount rate, is about $14
billion (2008 dollars) to $38 billion (2008 dollars) higher than the
estimated social costs shown earlier in this section. The general
approach used to value benefits is discussed in more detail earlier in
this preamble. For more detailed information on the benefits estimated
for the proposed rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
    The Unfunded Mandates 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 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, and little impact on communities that may be
affected by the proposed rule. In addition, there should be little
impact on energy markets (in this case, coal, natural gas, petroleum
products, and electricity). Hence, the potential impacts on the
categories mentioned above should be small.
5. Consultation With Government Officials
    The Unfunded Mandates 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. Although the proposed rule does not affect any State, local,
or Tribal governments, we have consulted with State and local air
pollution control officials. We also have held meetings on the proposed
rule with many of the stakeholders from numerous individual companies,
environmental groups, consultants and vendors, labor unions, and other
interested parties. We have added materials to the Air Docket to
document these meetings.
    In addition, we have determined that the proposed rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. While some small governments may have some sources
affected by the proposed rule, the impacts are not expected to be
significant. Therefore, today's proposed rule is not subject to the
requirements of section 203 of the UMRA.

F. Regulatory Flexibility Act (RFA), as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et
seq.

    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.
(a) 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.
(1) 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 four of
the Panel's recommendations.
    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 all but one of the Panel
recommendations.
(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 section 112(h) of the CAA, that
is, it is impracticable to enforce the emission standards due to
technical or 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) Health Based Compliance Alternatives (HBCA)
    The Panel recommended that EPA adopt the HBCA as a regulatory
flexibility option for the Boiler MACT rulemaking. The panel
recognized, however, that EPA has concerns about its legal authority to
provide an HBCA under the Clean Air Act, and EPA may ultimately
determine that this flexibility is inconsistent with the Clean Air Act.
    SERs commented that adopting an HBCA would perhaps be the most
important step EPA could take to mitigate the serious financial harm
the Boiler MACT would otherwise inflict on small entities using solid
fuels nationwide and, therefore, HBCA should be a critical component of
any future rule to lessen impact on small entities.
(d) Emissions Averaging
    The Panel recommended that EPA consider a provision for emission
averaging and long averaging times for the proposed emission limits.
    SERs commented that a measure EPA should consider to lessen the
regulatory burden of complying with Boiler MACT is to allow emissions
averaging at sources with multiple regulated units. SERs commented that
another approach that can aide small entity compliance is to set longer
averaging times (i.e., 30-days or more) rather than looking at a mere
3-run (hour) average for performance. Given the inherent variability in
boiler performance, an annual or quarterly averaging period for all HAP
would prevent a single spike in emissions from throwing a unit into
non-compliance.
(e) 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.

G. Paperwork Reduction Act

    The information collection requirements in the proposed rule will
be submitted for approval to the Office of Management and Budget under
the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information
Collection Request (ICR) document has been prepared by EPA (ICR No.
2028.05).
    The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant
to the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
    The proposed rule would require maintenance inspections of the
control devices but would not require any notifications or reports
beyond those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance.
    The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after the effective date of
the standards) is estimated to be $87.6 million. This includes 208,832
labor hours per year at a total labor cost of $19.8 million per year,
and total non-labor capital costs of $67.8 million per year. This
estimate includes initial and annual performance test, 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 and cost were also
included in the cost estimates presented in the control costs impacts
estimates in section IV.D of this preamble. The total burden for the
Federal government (averaged over the first 3 years after the effective
date of the standard) is estimated to be 93,648 hours per year at a
total labor cost of $4.9 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 it displays a
currently valid OMB control number. The OMB control

numbers for our regulations are listed in 40 CFR part 9 and 48 CFR
chapter 15.
    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-2002-0058. 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.

H. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to the Office of Management and
Budget, with explanations when an agency does not use available and
applicable voluntary consensus standards.
    This rulemaking involves technical standards. The EPA cites the
following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A,
3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. 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 have been documented and are placed in
the docket for the proposed rule.
    The three voluntary consensus standards described below were
identified as acceptable alternatives to EPA test methods for the
purposes of the proposed rule.
    The voluntary consensus standard ASME PTC 19-10-1981-Part 10,
``Flue and Exhaust Gas Analyses,'' is cited in the proposed rule for
its manual method for measuring the oxygen, carbon dioxide, and carbon
monoxide content of exhaust gas. This part of ASME PTC 19-10-1981--Part
10 is an acceptable alternative to Method 3B.
    The voluntary consensus standard ASTM D6522-00, ``Standard Test
Method for the 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'' is an acceptable alternative to EPA Method 3A for
identifying carbon monoxide and oxygen concentrations for the proposed
rule when the fuel is natural gas.
    The voluntary consensus standard ASTM Z65907, ``Standard Method for
Both Speciated and Elemental Mercury Determination,'' is an acceptable
alternative to EPA Method 29 (portion for mercury only) for the purpose
of the proposed rule. This standard can be used in the proposed rule to
determine the mercury concentration in stack gases for boilers with
rated heat input capacities of greater than 250 MMBtu per hour.
    In addition to the voluntary consensus standards EPA uses in the
proposed rule, the search for emissions measurement procedures
identified 15 other voluntary consensus standards. The EPA determined
that 13 of these 15 standards identified for measuring emissions of the
HAP or surrogates subject to emission standards in the proposed rule
were impractical alternatives to EPA test methods for the purposes of
the rule. Therefore, EPA does not intend to adopt these standards for
this purpose. The reasons for this determination for the 13 methods are
discussed below.
    The voluntary consensus standard ASTM D3154-00, ``Standard Method
for Average Velocity in a Duct (Pitot Tube Method),'' is impractical as
an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the
proposed rulemaking since the standard appears to lack in quality
control and quality assurance requirements. Specifically, ASTM D3154-00
does not include the following: (1) Proof that openings of standard
pitot tube have not plugged during the test; (2) if differential
pressure gauges other than inclined manometers (e.g., magnehelic
gauges) are used, their calibration must be checked after each test
series; and (3) the frequency and validity range for calibration of the
temperature sensors.
    The voluntary consensus standard ASTM D3464-96 (2001), ``Standard
Test Method Average Velocity in a Duct Using a Thermal Anemometer,'' is
impractical as an alternative to EPA Method 2 for the purposes of the
proposed rule primarily because applicability specifications are not
clearly defined, e.g., range of gas composition, temperature limits.
Also, the lack of supporting quality assurance data for the calibration
procedures and specifications, and certain variability issues that are
not adequately addressed by the standard limit EPA's ability to make a
definitive comparison of the method in these areas.
    The voluntary consensus standard ISO 10780:1994, ``Stationary
Source Emissions-Measurement of Velocity and Volume Flowrate of Gas
Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in
the proposed rule. The standard recommends the use of an L-shaped
pitot, which historically has not been recommended by EPA. The EPA
specifies the S-type design which has large openings that are less
likely to plug up with dust.
    The voluntary consensus standard, CAN/CSA Z223.2-M86(1999),
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide,
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed
Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA
Method 3A since it does not include quantitative specifications for
measurement system performance, most notably the calibration procedures
and instrument performance characteristics. The instrument performance
characteristics that are provided are nonmandatory and also do not
provide the same level of quality assurance as the EPA methods. For
example, the zero and span/calibration drift is only checked weekly,
whereas the EPA methods requires drift checks after each run.
    Two very similar voluntary consensus standards, ASTM D5835-95
(2001), ``Standard Practice for Sampling Stationary Source Emissions
for Automated Determination of Gas Concentration,'' and ISO 10396:1993,
``Stationary Source Emissions: Sampling for the Automated Determination
of Gas Concentrations,'' are impractical alternatives to EPA Method 3A
for the purposes of the proposed rule because they lack in detail and
quality assurance/quality control requirements. Specifically, these two
standards do not

include the following: (1) Sensitivity of the method; (2) acceptable
levels of analyzer calibration error; (3) acceptable levels of sampling
system bias; (4) zero drift and calibration drift limits, time span,
and required testing frequency; (5) a method to test the interference
response of the analyzer; (6) procedures to determine the minimum
sampling time per run and minimum measurement time; and (7)
specifications for data recorders, in terms of resolution (all types)
and recording intervals (digital and analog recorders, only).
    The voluntary consensus standard ISO 12039:2001, ``Stationary
Source Emissions--Determination of Carbon Monoxide, Carbon Dioxide, and
Oxygen--Automated Methods,'' is not acceptable as an alternative to EPA
Method 3A. This ISO standard is similar to EPA Method 3A, but is
missing some key features. In terms of sampling, the hardware required
by ISO 12039:2001 does not include a 3-way calibration valve assembly
or equivalent to block the sample gas flow while calibration gases are
introduced. In its calibration procedures, ISO 12039:2001 only
specifies a two-point calibration while EPA Method 3A specifies a
three-point calibration. Also, ISO 12039:2001 does not specify
performance criteria for calibration error, calibration drift, or
sampling system bias tests as in the EPA method, although checks of
these quality control features are required by the ISO standard.
    The voluntary consensus standard ASME PTC-38-80 R85 (1985),
``Determination of the Concentration of Particulate Matter in Gas
Streams,'' is not acceptable as an alternative for EPA Method 5 because
ASTM PTC-38-80 is not specific about equipment requirements, and
instead presents the options available and the pro's and con's of each
option. The key specific differences between ASME PTC-38-80 and the EPA
methods are that the ASME standard: (1) Allows in-stack filter
placement as compared to the out-of-stack filter placement in EPA
Methods 5 and 17; (2) allows many different types of nozzles, pitots,
and filtering equipment; (3) does not specify a filter weighing
protocol or a minimum allowable filter weight fluctuation as in the EPA
methods; and (4) allows filter paper to be only 99 percent efficient,
as compared to the 99.95 percent efficiency required by the EPA
methods.
    The voluntary consensus standard ASTM D3685/D3685M-98, ``Test
Methods for Sampling and Determination of Particulate Matter in Stack
Gases,'' is similar to EPA Methods 5 and 17, but is lacking in the
following areas that are needed to produce quality, representative
particulate data: (1) Requirement that the filter holder temperature
should be between 120[deg]C and 134[deg]C, and not just ``above the
acid dew-point;'' (2) detailed specifications for measuring and
monitoring the filter holder temperature during sampling; (3)
procedures similar to EPA Methods 1, 2, 3, and 4, that are required by
EPA Method 5; (4) technical guidance for performing the Method 5
sampling procedures, e.g., maintaining and monitoring sampling train
operating temperatures, specific leak check guidelines and procedures,
and use of reagent blanks for determining and subtracting background
contamination; and (5) detailed equipment and/or operational
requirements, e.g., component exchange leak checks, use of glass
cyclones for heavy particulate loading and/or water droplets, operating
under a negative stack pressure, exchanging particulate loaded filters,
sampling preparation and implementation guidance, sample recovery
guidance, data reduction guidance, and particulate sample calculations
input.
    The voluntary consensus standard ISO 9096:1992, ``Determination of
Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying
Ducts--Manual Gravimetric Method,'' is not acceptable as an alternative
for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods
1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA
Method 5 for collection of particulate matter. The standard ISO 9096
does not provide applicable technical guidance for performing many of
the integral procedures specified in Methods 1, 2, and 5. Major
performance and operational details are lacking or nonexistent, and
detailed quality assurance/quality control guidance for the sampling
operations required to produce quality, representative particulate data
(e.g., guidance for maintaining and monitoring train operating
temperatures, specific leak check guidelines and procedures, and sample
preparation and recovery procedures) are not provided by the standard,
as in EPA Method 5. Also, details of equipment and/or operational
requirements, such as those specified in EPA Method 5, are not included
in the ISO standard, e.g., stack gas moisture measurements, data
reduction guidance, and particulate sample calculations.
    The voluntary consensus standard CAN/CSA Z223.1-M1977, ``Method for
the Determination of Particulate Mass Flows in Enclosed Gas Streams,''
is not acceptable as an alternative for EPA Method 5. Detailed
technical procedures and quality control measures that are required in
EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second,
CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing
requirement to repeat weighing every 6 hours until a constant weight is
achieved. Third, EPA Method 5 requires the filter weight to be reported
to the nearest 0.1 mg, while CAN/CSA Z223.1 requires only to the
nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot
for velocity measurement when plugging of the tube opening is not
expected to be a problem. Whereas, EPA Method 5 requires an S-shaped
pitot.
    The voluntary consensus standard EN 1911-1,2,3 (1998), ``Stationary
Source Emissions-Manual Method of Determination of HCl--Part 1:
Sampling of Gases Ratified European Text--Part 2: Gaseous Compounds
Absorption Ratified European Text--Part 3: Adsorption Solutions
Analysis and Calculation Ratified European Text,'' is impractical as an
alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot
be considered equivalent to EPA Method 26 or 26A because the sample
absorbing solution (water) would be expected to capture both HCl and
chlorine gas, if present, without the ability to distinguish between
the two. The EPA Methods 26 and 26A use an acidified absorbing solution
to first separate HCl and chlorine gas so that they can be selectively
absorbed, analyzed, and reported separately. In addition, in EN 1911
the absorption efficiency for chlorine gas would be expected to vary as
the pH of the water changed during sampling.
    The voluntary consensus standard EN 13211 (1998), is not acceptable
as an alternative to the mercury portion of EPA Method 29 primarily
because it is not validated for use with impingers, as in the EPA
method, although the method describes procedures for the use of
impingers. This European standard is validated for the use of fritted
bubblers only and requires the use of a side (split) stream arrangement
for isokinetic sampling because of the low sampling rate of the
bubblers (up to 3 liters per minute, maximum). Also, only two bubblers
(or impingers) are required by EN 13211, whereas EPA Method 29 require
the use of six impingers. In addition, EN 13211 does not include many
of the quality control procedures of EPA Method 29, especially for the
use and calibration of temperature sensors and controllers, sampling
train assembly and disassembly, and filter weighing.

    Two of the 15 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the proposed rule because they are under development by a
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot
Primary Flowmeters,'' for EPA Method 2.
    Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR
part 63, list the EPA testing methods included in the proposed rule.
Under Sec.  63.7(f) and Sec.  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 of
the EPA testing methods, performance specifications, or procedures.

I. 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, Office of Management and Budget, 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 a 0.14% price increase for the energy sector and a
0.07% percentage change in production. We estimate a 0.18% increase in
energy 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.

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 environmental justice part of their
mission by identifying and addressing, as appropriate,
disproportionately high and adverse human health or environmental
effects of their programs, policies, and activities on minority
populations, low-income, and Tribal populations in the United States.
    This proposed action establishes national emission standards for
new and existing industrial, commercial, institutional boilers and
process heaters that combust non-waste materials (i.e. natural gas,
process gas, fuel oil, biomass, and coal) and that are located at a
major source. The EPA estimates that there are approximately 13,555
units located at 1,608 facilities covered by this rule.
    The proposed rule will reduce emissions of all the listed HAP that
come from boilers and process heaters. This includes metals (mercury,
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and
selenium), organics (POM, acetaldehyde, acrolein, benzene, dioxins,
ethylene dichloride, formaldehyde, and PCB), hydrochloric acid, and
hydrofluoric acid. Adverse health effects from these pollutants include
cancer, irritation of the lungs, skin, and mucus membranes; effects on
the central nervous system, damage to the kidneys, and other acute
health disorders. The rule will also result in substantial reductions
of criteria pollutants such as carbon monoxide (CO), nitrogen oxides
(NOX), particulate matter (PM), and sulfur dioxide
(SO2). Sulfur dioxide and NO2 are precursors for
the formation of PM2.5 and ozone. Reducing these emissions
will reduce ozone and PM2.5 formation and associated health
effects, such as adult premature mortality, chronic and acute
bronchitis, asthma, and other respiratory and cardiovascular diseases.
(Please refer to the RIA contained in the docket for this rulemaking.)
    Pursuant to E.O. 12898 EPA has undertaken to determine the
aggregate demographic makeup of the communities near affected sources.
This analysis used ``proximity-to-a-source'' to identify the
populations considered to be living near affected sources, such that
they have notable exposures to current emissions from these sources. In
this approach EPA reviewed the distributions of different socio-
demographic groups in the locations of the expected emission reductions
from this rule. The review identified those census blocks within a
circular distance of 3 miles of affected sources and determined the
demographic and socio-economic composition (e.g. race, income,
education, etc) of these census blocks. The radius of 3 miles (or
approximately 5 kilometers) has been used in other demographic analyses
focused on areas around potential sources.27 28 29 30 In
addition, air modeling experience has shown that beyond 3 miles the
influence of an individual source of emissions can generally be
considered to be small, both in absolute terms and relative to the
influence of other sources (assuming there are other sources in the
area, as is typical in urban areas).
---------------------------------------------------------------------------

    \27\ U.S. GAO (Government Accountability Office). Demographics
of People Living Near Waste Facilities. Washington DC: Government
Printing Office; 1995.
    \28\ Mohai P, Saha R. ``Reassessing Racial and Socio-economic
Disparities in Environmental Justice Research''. Demography.
2006;43(2): 383-399.
    \29\ Mennis J. ``Using Geographic Information Systems to Create
and Analyze Statistical Surfaces of Populations and Risk for
Environmental Justice Analysis''. Social Science Quarterly,
2002;83(1):281-297.
    \30\ Bullard RD, Mohai P, Wright B, Saha R, et al. Toxic Waste
and Race at Twenty 1987-2007. United Church of Christ. March, 2007.
---------------------------------------------------------------------------

    EPA's demographic analysis showed that major source boilers are
located in areas where minorities' share of the population living
within a three-mile buffer is higher than the national average. For
these same areas, the percent of the population below the poverty line
is also higher than the national average.\31\ Based on the fact that
the rule does not allow emission increases, the EPA has determined that
the proposed rule will not have disproportionately high and adverse
human health or environmental effects on minority, low-income, or
Tribal populations. However, to the extent that any minority, low
income, or Tribal subpopulation is disproportionately impacted by the
current emissions as a result of the proximity of their homes to these
sources, that subpopulation also

stands to see increased environmental and health benefit from the
emissions reductions called for by this rule.
---------------------------------------------------------------------------

    \31\ The results of the demographic analysis are presented in
``Review of Environmental Justice Impacts'', April 2010, a copy of
which is available in the docket.
---------------------------------------------------------------------------

    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 a communication and outreach
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. During the comment period, EPA will
publicize the rulemaking via EJ newsletters, Tribal newsletters, EJ
listservs, and the Internet, including the Office of Policy, Economics,
and Innovation's (OPEI) Rulemaking Gateway Web site (http://
yosemite.epa.gov/opei/RuleGate.nsf/). 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 and local governments and members of affected
communities the opportunity to provide comments on the permit
conditions associated with permitting the sources affected by this
rulemaking.

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 the 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.

    2. Part 63 is amended by revising subpart DDDDD to read as follows:

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

Sec.

What This Subpart Covers

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

Emission Limitations and Work Practice Standards

63.7499 What are the subcategories of boilers and process heaters?
63.7500 What emission limitations, work practice standards, and
operating limits must I meet?

General Compliance Requirements

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

Testing, Fuel Analyses, and Initial Compliance Requirements

63.7510 What are my initial compliance requirements and by what date
must I conduct them?
63.7515 When must I conduct subsequent performance tests or fuel
analyses?
63.7520 What stack tests and procedures must I use for the
performance tests?
63.7521 What fuel analyses and procedures must I use for the
performance tests?
63.7522 Can I use emission averaging to comply with this subpart?
63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
63.7530 How do I demonstrate initial compliance with the emission
limitations and work practice standards?

Continuous Compliance Requirements

63.7535 How do I monitor and collect data to demonstrate continuous
compliance?
63.7540 How do I demonstrate continuous compliance with the emission
limitations and work practice standards?
63.7541 How do I demonstrate continuous compliance under the
emission averaging provision?

Notifications, Reports, and Records

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

Other Requirements and Information

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

Tables to Subpart DDDDD of Part 63

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

What This Subpart Covers

Sec.  63.7480  What is the purpose of this subpart?

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

Sec.  63.7485  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler or process heater as
defined in Sec.  63.7575 that is located at, or is part of, a major
source of HAP as defined in Sec.  63.2 or Sec.  63.761 (40 CFR part 63,
subpart HH, National Emission Standards for Hazardous Air Pollutants
from Oil and Natural Gas Production Facilities), except as specified in
Sec.  63.7491.

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

    (a) This subpart applies to new, reconstructed, and existing
affected sources as described in paragraphs (a)(1) and (2) of this
section.
    (1) The affected source of this subpart is the collection of all
existing industrial, commercial, and institutional boilers and process
heaters within a subcategory located at a major source as defined in
Sec.  63.7575.
    (2) The affected source of this subpart is each new or
reconstructed industrial, commercial, or institutional boiler or
process heater located at a major source as defined in Sec.  63.7575.
    (b) A boiler or process heater is new if you commence construction
of the boiler or process heater after June 4, 2010, and you meet the
applicability

criteria at the time you commence construction.
    (c) A boiler or process heater is reconstructed if you meet the
reconstruction criteria as defined in Sec.  63.2, you commence
reconstruction after June 4, 2010, and you meet the applicability
criteria at the time you commence reconstruction.
    (d) A boiler or process heater is existing if it is not new or
reconstructed.

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

    The types of boilers and process heaters listed in paragraphs (a)
through (j) of this section are not subject to this subpart.
    (a) An electric utility steam generating unit.
    (b) A recovery boiler or furnace covered by 40 CFR part 63, subpart
MM.
    (c) A boiler or process heater that is used specifically for
research and development. This does not include units that provide heat
or steam to a process at a research and development facility.
    (d) A hot water heater as defined in this subpart.
    (e) A refining kettle covered by 40 CFR part 63, subpart X.
    (f) An ethylene cracking furnace covered by 40 CFR part 63, subpart
YY.
    (g) Blast furnace stoves as described in the EPA document, entitled
``National Emission Standards for Hazardous Air Pollutants (NESHAP) for
Integrated Iron and Steel Plants--Background Information for Proposed
Standards,'' (EPA-453/R-01-005).
    (h) Any boiler or process heater specifically listed as an affected
source in another standard(s) under 40 CFR part 63.
    (i) Temporary boilers as defined in this subpart.
    (j) Blast furnace gas fuel-fired boilers and process heaters as
defined in this subpart.

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

    (a) If you have a new or reconstructed boiler or process heater,
you must comply with this subpart by [DATE THE FINAL RULE IS PUBLISHED
IN THE FEDERAL REGISTER] or upon startup of your boiler or process
heater, whichever is later.
    (b) If you have an existing boiler or process heater, you must
comply with this subpart no later than [3 YEARS AFTER DATE THE FINAL
RULE IS PUBLISHED IN THE FEDERAL REGISTER].
    (c) If you have an area source that increases its emissions or its
potential to emit such that it becomes a major source of HAP,
paragraphs (c)(1) and (2) of this section apply to you.
    (1) Any new or reconstructed boiler or process heater at the
existing source must be in compliance with this subpart upon startup.
    (2) Any existing boiler or process heater at the existing source
must be in compliance with this subpart within 3 years after the source
becomes a major source.
    (d) You must meet the notification requirements in Sec.  63.7545
according to the schedule in Sec.  63.7545 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limits and work practice standards
in this subpart.

Emission Limitations and Work Practice Standards

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

    (a) The subcategories of boilers and process heaters are:
    (1) Pulverized coal units,
    (2) Stokers designed to burn coal,
    (3) Fluidized bed units designed to burn coal,
    (4) Stokers designed to burn biomass,
    (5) Fluidized bed units designed to burn biomass,
    (6) Suspension burners/Dutch Ovens designed to burn biomass,
    (7) Fuel Cells designed to burn biomass,
    (8) Units designed to burn liquid fuel,
    (9) Units designed to burn natural gas/refinery gas,
    (10) Units designed to burn other gases, and
    (11) Metal process furnaces.
    (b) Each subcategory is defined in Sec.  63.7575.

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

    (a) You must meet the requirements in paragraphs (a)(1) and (2) of
this section. You must meet these requirements at all times.
    (1) You must meet each emission limit and work practice standard in
Table 1 through 3 to this subpart that applies to your boiler or
process heater, for each boiler or process heater at your source,
except as provided under Sec.  63.7522.
    (2) You must meet each operating limit in Table 4 to this subpart
that applies to your boiler or process heater. If you use a control
device or combination of control devices not covered in Table 4 to this
subpart, or you wish to establish and monitor an alternative operating
limit and alternative monitoring parameters, you must apply to the
United States Environmental Protection Agency (EPA) Administrator for
approval of alternative monitoring under Sec.  63.8(f).
    (b) As provided in Sec.  63.6(g), EPA may approve use of an
alternative to the work practice standards in this section.

General Compliance Requirements

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

    (a) You must be in compliance with the emission limits and
operating limits in this subpart. These limits apply to you at all
times.
    (b) 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.
    (c) You can demonstrate compliance with the applicable emission
limit for HCl or mercury using fuel analysis if the emission rate
calculated according to Sec.  63.7530(d) is less than the applicable
emission limit. Otherwise, you must demonstrate compliance for HCl or
mercury using performance stack testing. You must demonstrate
compliance with all other applicable limits using performance stack
testing, or the continuous monitoring system (CMS) where applicable.
    (d) If you demonstrate compliance with any applicable emission
limit through performance stack testing, you must develop a site-
specific monitoring plan according to the requirements in paragraphs
(d)(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 CMS required in this section, you must develop, and
submit to the permitting authority for approval upon request, a site-
specific monitoring plan that addresses paragraphs (d)(1)(i) through
(iii) of this section. You must submit this site-specific monitoring
plan, if requested, at least 60 days before

your initial performance evaluation of your CMS.
    (i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
    (ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
    (iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations).
    (2) In your site-specific monitoring plan, you must also address
paragraphs (d)(2)(i) through (iii) of this section.
    (i) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec.  63.8(c)(1)(i) and (ii), (c)(3), and
(c)(4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (3) You must conduct a performance evaluation of each CMS in
accordance with your site-specific monitoring plan.
    (4) You must operate and maintain the CMS in continuous operation
according to the site-specific monitoring plan.

Testing, Fuel Analyses, and Initial Compliance Requirements

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

    (a) For affected sources that elect to demonstrate compliance with
any of the emission limits of this subpart through performance stack
testing, your initial compliance requirements include conducting
performance stack tests according to Sec.  63.7520 and Table 5 to this
subpart, conducting a fuel analysis for each type of fuel burned in
your boiler or process heater according to Sec.  63.7521 and Table 6 to
this subpart, establishing operating limits according to Sec.  63.7530
and Table 7 to this subpart, and conducting CMS performance evaluations
according to Sec.  63.7525. For affected sources that burn a single
type of fuel, you are exempted from the initial compliance requirements
of conducting a fuel analysis for each type of fuel burned in your
boiler or process heater according to Sec.  63.7521 and Table 6 to this
subpart.
    (b) For affected sources that elect to demonstrate compliance with
the emission limits for HCl or mercury through fuel analysis, your
initial compliance requirement is to conduct a fuel analysis for each
type of fuel burned in your boiler or process heater according to Sec.
63.7521 and Table 6 to this subpart and establish operating limits
according to Sec.  63.7530 and Table 8 to this subpart.
    (c) If your boiler or process heater has a heat input capacity less
than 100 MMBtu per hour, your initial compliance demonstration for CO
is conducting a performance stack test for CO according to Table 5 to
this subpart. If your boiler or process heater has a heat input
capacity of 100 MMBtu per hour or greater, your initial compliance
demonstration for CO is conducting a performance evaluation of your
continuous emission monitoring system for CO according to Sec.
63.7525(a).
    (d) If your boiler or process heater has a heat input capacity of
250 MMBtu per hour or greater and combusts coal, biomass, or residual
oil, your initial compliance demonstration for PM is conducting a
performance evaluation of your continuous emission monitoring system
for PM according to Sec.  63.7525(b).
    (e) For existing affected sources, you must demonstrate initial
compliance no later than 180 days after the compliance date that is
specified for your source in Sec.  63.7495 and according to the
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this
subpart.
    (f) If your new or reconstructed affected source commenced
construction or reconstruction between June 4, 2010 and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
demonstrate initial compliance with either the proposed emission limits
or the promulgated emission limits no later than 180 days after [DATE
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or
within 180 days after startup of the source, whichever is later,
according to Sec.  63.7(a)(2)(ix).
    (g) If your new or reconstructed affected source commenced
construction or reconstruction between June 4, 2010, and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], and you
chose to comply with the proposed emission limits when demonstrating
initial compliance, you must conduct a second compliance demonstration
for the promulgated emission limits within 3 years after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within
3 years after startup of the affected source, whichever is later.
    (h) If your new or reconstructed affected source commences
construction or reconstruction after [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER], you must demonstrate initial
compliance with the promulgated emission limits no later than 180 days
after startup of the source.

Sec.  63.7515  When must I conduct subsequent performance tests or fuel
analyses?

    (a) You must conduct all applicable performance tests according to
Sec.  63.7520 on an annual basis, unless you follow the requirements
listed in paragraphs (b) through (e) 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 (e) of this section.
    (b) You can conduct performance stack tests less often for a given
pollutant 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. This reduced testing option
does not apply to performance stack tests for dioxin/furan. If you
elect to demonstrate compliance using emission averaging under Sec.
63.7522, you must continue to conduct performance stack tests annually.
    (c) If your boiler or process heater continues to meet the emission
limit for the pollutant, 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.
This reduced testing option does not apply to performance stack tests
for dioxin/furan. If you elect to demonstrate compliance using emission
averaging under Sec.  63.7522, you must continue to conduct performance
stack tests annually.

    (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 a consecutive 3-year period
show compliance.
    (e) If you are required to meet an applicable work practice
standard, you must conduct annual performance tune-ups according to
Sec.  63.7520. Each annual tune-up must be conducted between 10 and 12
months after the previous tune-up.
    (f) If you demonstrate compliance with the mercury or HCl based on
fuel analysis, you must conduct a monthly fuel analysis according to
Sec.  63.7521 for each type of fuel burned. If you burn a new type of
fuel, you must conduct a fuel analysis before burning the new type of
fuel in your boiler or process heater. You must still meet all
applicable continuous compliance requirements in Sec.  63.7540.
    (g) You must report the results of performance tests (stack test
and fuel analyses) within 60 days after the completion of the
performance tests. This report must also verify that the operating
limits for your affected source have not changed or provide
documentation of revised operating parameters established according to
Sec.  63.7530 and Table 7 to this subpart, as applicable. The reports
for all subsequent performance tests must include all applicable
information required in Sec.  63.7550.

Sec.  63.7520  What stack tests and procedures must I use for the
performance tests?

    (a) You must conduct all performance tests according to Sec.
63.7(c), (d), (f), and (h). You must also develop a site-specific test
plan according to the requirements in Sec.  63.7(c).
    (b) You must conduct each performance test according to the
requirements in Table 5 to this subpart.
    (c) You must conduct each performance stack test under the specific
conditions listed in Tables 5 and 7 to this subpart. You must conduct
performance stack tests at the maximum normal operating load while
burning the type of fuel or mixture of fuels that has the highest
content of chlorine and mercury, and you must demonstrate initial
compliance and establish your operating limits based on these tests.
These requirements could result in the need to conduct more than one
performance test.
    (d) You must conduct three separate test runs for each performance
test required in this section, as specified in Sec.  63.7(e)(3). Each
test run must last at least 4 hours.
    (e) To determine compliance with the emission limits, you must use
the F[dash]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, the measured HCl
concentrations, and the measured mercury concentrations that result
from the initial performance test to pounds per million Btu heat input
emission rates using F-factors.

Sec.  63.7521  What fuel analyses and procedures must I use for the
performance tests?

    (a) You must conduct performance fuel analysis tests according to
the procedures in paragraphs (b) through (e) of this section and Table
6 to this subpart, as applicable.
    (b) You must develop and submit a site-specific fuel analysis plan
to the EPA Administrator for review and approval according to the
following procedures and requirements in paragraphs (b)(1) and (2) of
this section.
    (1) You must submit the fuel analysis plan no later than 60 days
before the date that you intend to demonstrate compliance.
    (2) You must include the information contained in paragraphs
(b)(2)(i) through (vi) of this section in your fuel analysis plan.
    (i) The identification of all fuel types anticipated to be burned
in each boiler or process heater.
    (ii) For each fuel type, the notification of whether you or a fuel
supplier will be conducting the fuel analysis.
    (iii) For each fuel type, a detailed description of the sample
location and specific procedures to be used for collecting and
preparing the composite samples if your procedures are different from
paragraph (c) or (d) of this section. Samples should be collected at a
location that most accurately represents the fuel type, where possible,
at a point prior to mixing with other dissimilar fuel types.
    (iv) For each fuel type, the analytical methods from Table 6, with
the expected minimum detection levels, to be used for the measurement
of chlorine or mercury.
    (v) If you request to use an alternative analytical method other
than those required by Table 6 to this subpart, you must also include a
detailed description of the methods and procedures that you are
proposing to use. Methods in Table 6 shall be used until the requested
alternative is approved.
    (vi) If you will be using fuel analysis from a fuel supplier in
lieu of site-specific sampling and analysis, the fuel supplier must use
the analytical methods required by Table 6 to this subpart.
    (c) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in paragraph (c)(1) or (2)
of this section.
    (1) If sampling from a belt (or screw) feeder, collect fuel samples
according to paragraphs (c)(1)(i) and (ii) of this section.
    (i) Stop the belt and withdraw a 6-inch wide sample from the full
cross-section of the stopped belt to obtain a minimum two pounds of
sample. You must collect all the material (fines and coarse) in the
full cross-section. You must transfer the sample to a clean plastic
bag.
    (ii) Each composite sample will consist of a minimum of three
samples collected at approximately equal 1-hour intervals during the
testing period.
    (2) If sampling from a fuel pile or truck, you must collect fuel
samples according to paragraphs (c)(2)(i) through (iii) of this
section.
    (i) For each composite sample, you must select a minimum of five
sampling locations uniformly spaced over the surface of the pile.
    (ii) At each sampling site, you must dig into the pile to a depth
of 18 inches. You must insert a clean flat square shovel into the hole
and withdraw a sample, making sure that large pieces do not fall off
during sampling.
    (iii) You must transfer all samples to a clean plastic bag for
further processing.
    (d) You must prepare each composite sample according to the
procedures in paragraphs (d)(1) through (7) of this section.
    (1) You must thoroughly mix and pour the entire composite sample
over a clean plastic sheet.
    (2) You must break sample pieces larger than 3 inches into smaller
sizes.
    (3) You must make a pie shape with the entire composite sample and
subdivide it into four equal parts.
    (4) You must separate one of the quarter samples as the first
subset.
    (5) If this subset is too large for grinding, you must repeat the
procedure in paragraph (d)(3) of this section with the quarter sample
and obtain a one-quarter subset from this sample.
    (6) You must grind the sample in a mill.
    (7) You must use the procedure in paragraph (d)(3) of this section
to obtain a one-quarter subsample for analysis. If the quarter sample
is too large, subdivide it further using the same procedure.
    (e) You must determine the concentration of pollutants in the fuel
(mercury and/or chlorine) in units of

pounds per million Btu of each composite sample for each fuel type
according to the procedures in Table 6 to this subpart.

Sec.  63.7522  Can I use emission averaging to comply with this
subpart?

    (a) As an alternative to meeting the requirements of Sec.  63.7500
for particulate matter, HCl, or mercury on a boiler or process heater-
specific basis, if you have more than one existing boiler or process
heater in any subcategory located at your facility, you may demonstrate
compliance by emission averaging, if your averaged emissions are within
90 percent of the applicable emission limit, according to the
procedures in this section.
    (b) Separate stack requirements. For a group of two or more
existing boilers or process heaters in the same subcategory that each
vent to a separate stack, you may average particulate matter, HCl, and
mercury emissions to demonstrate compliance with the limits in Table 2
to this subpart if you satisfy the requirements in paragraphs (c), (d),
(e), (f), and (g) of this section.
    (c) For each existing boiler or process heater in the averaging
group, the emission rate achieved during the initial compliance test
for the HAP being averaged must not exceed the emission level that was
being achieved on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER] or the control technology employed during the
initial compliance test must not be less effective for the HAP being
averaged than the control technology employed on [THE DATE 30 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] .
    (d) The averaged emissions rate from the existing boilers and
process heaters participating in the emissions averaging option must be
in compliance with the limits in Table 2 to this subpart at all times
following the compliance date specified in Sec.  63.7495.
    (e) You must demonstrate initial compliance according to paragraph
(e)(1) or (2) of this section.
    (1) You must use Equation 1 of this section to demonstrate that the
particulate matter, HCl, and mercury emissions from all existing units
participating in the emissions averaging option do not exceed the
emission limits in Table 2 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP04JN10.003

Where:

Ave Weighted Emissions = Average weighted emissions for particulate
matter, HCl, or mercury, in units of pounds per million Btu of heat
input.
Er = Emission rate (as calculated according to Table 5 to this
subpart for particulate matter, HCl, or mercury or by fuel analysis
for HCl or mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Hm = Maximum rated heat input capacity of unit, i, in units of
million Btu per hour.
n = Number of units participating in the emissions averaging option.
0.90 = Required discount factor.

    (2) If you are not capable of monitoring heat input, and the boiler
generates steam, you may use Equation 2 of this section as an
alternative to using Equation 1 of this section to demonstrate that the
particulate matter, HCl, and mercury emissions from all existing units
participating in the emissions averaging option do not exceed the
emission limits in Table 2 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP04JN10.004

Where:

Ave Weighted Emissions = Average weighted emission level for PM,
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as calculated according to Table 5 to this
subpart for particulate matter, HCl, or mercury or by fuel analysis
for HCl or mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Sm = Maximum steam generation by unit, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance
test, in units of million Btu of heat input per pounds of steam
generated for unit, i.
0.90 = Required discount factor.

    (f) You must demonstrate compliance on a monthly basis determined
at the end of every month (12 times per year) according to paragraphs
(f)(1) through (3) of this section. The first monthly period begins on
the compliance date specified in Sec.  63.7495.
    (1) For each calendar month, you must use Equation 3 of this
section to calculate the monthly average weighted emission rate using
the actual heat capacity for each existing unit participating in the
emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TP04JN10.005

Where:

Ave Weighted Emissions = monthly average weighted emission level for
particulate matter, HCl, or mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate, (as calculated during the most recent compliance
test, (as calculated according to Table 5 to this subpart for
particulate matter, HCl, or mercury or by fuel analysis for HCl or
mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Hb = The average heat input for each calendar month of boiler, i, in
units of million Btu.
n = Number of units participating in the emissions averaging option.

0.90 = Required discount factor.

    (2) If you are not capable of monitoring heat input, you may use
Equation 4 of this section as an alternative to using Equation 3 of
this section to calculate the monthly weighted emission rate using the
actual steam generation from the units participating in the emissions
averaging option.
[GRAPHIC] [TIFF OMITTED] TP04JN10.006

Where:

Ave Weighted Emissions = monthly average weighted emission level for
PM, HCl, or mercury, in units of pounds per million Btu of heat
input.
Er = Emission rate, (as calculated during the most recent compliance
test (as calculated according to Table 5 to this subpart for
particulate matter, HCl, or mercury or by fuel analysis for HCl or
mercury as calculated by the applicable equation in Sec.
63.7530(c)) for unit, i, for particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat input.
Sa = Actual steam generation for each calendar month by boiler, i,
in units of pounds.
Cf = Conversion factor, as calculated during the most recent
compliance test, in units of million Btu of heat input per pounds of
steam generated for unit, i.
0.90 = Required discount factor.

    (3) Until 12 monthly weighted average emission rates have been
accumulated, calculate and report only the monthly average weighted
emission rate determined under paragraph (f)(1) or (2) of this section.
After 12 monthly weighted average emission rates have been accumulated,
for each subsequent calendar month, use Equation 5 of this section to
calculate the 12-month rolling average of the monthly weighted average
emission rates for the current month and the previous 11 months.
[GRAPHIC] [TIFF OMITTED] TP04JN10.007

Where:

Eavg = 12-month rolling average emission rate, (pounds per million
Btu heat input)
ERi = Monthly weighted average, for month ``i'', (pounds per million
Btu heat input)(as calculated by (f)(1) or (2))

    (g) You must develop, and submit to the applicable regulatory
authority for review and approval upon request, an implementation plan
for emission averaging according to the following procedures and
requirements in paragraphs (g)(1) through (4).
    (1) You must submit the implementation plan no later than 180 days
before the date that the facility intends to demonstrate compliance
using the emission averaging option.
    (2) You must include the information contained in paragraphs
(g)(2)(i) through (vii) of this section in your implementation plan for
all emission sources included in an emissions average:
    (i) The identification of all existing boilers and process heaters
in the averaging group, including for each either the applicable HAP
emission level or the control technology installed as of [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] and the
date on which you are requesting emission averaging to commence;
    (ii) The process parameter (heat input or steam generated) that
will be monitored for each averaging group;
    (iii) The specific control technology or pollution prevention
measure to be used for each emission boiler or process heater in the
averaging group and the date of its installation or application. If the
pollution prevention measure reduces or eliminates emissions from
multiple boilers or process heaters, the owner or operator must
identify each boiler or process heater;
    (iv) The test plan for the measurement of particulate matter, HCl,
or mercury emissions in accordance with the requirements in Sec.
63.7520;
    (v) The operating parameters to be monitored for each control
system or device consistent with 63.7500 and Table 4, and a description
of how the operating limits will be determined;
    (vi) If you request to monitor an alternative operating parameter
pursuant to Sec.  63.7525, you must also include:
    (A) A description of the parameter(s) to be monitored and an
explanation of the criteria used to select the parameter(s); and
    (B) A description of the methods and procedures that will be used
to demonstrate that the parameter indicates proper operation of the
control device; the frequency and content of monitoring, reporting, and
recordkeeping requirements; and a demonstration, to the satisfaction of
the applicable regulatory authority, that the proposed monitoring
frequency is sufficient to represent control device operating
conditions; and
    (vii) A demonstration that compliance with each of the applicable
emission limit(s) will be achieved under representative operating
conditions.
    (3) The regulatory authority shall review and approve or disapprove
the plan according to the following criteria:
    (i) Whether the content of the plan includes all of the information
specified in paragraph (g)(2) of this section; and
    (ii) Whether the plan presents sufficient information to determine
that compliance will be achieved and maintained.
    (4) The applicable regulatory authority shall not approve an
emission averaging implementation plan containing any of the following
provisions:
    (i) Any averaging between emissions of differing pollutants or
between differing sources; or
    (ii) The inclusion of any emission source other than an existing
unit in the same subcategory.
    (h) Common stack requirements. For a group of two or more existing
affected units, each of which vents through a single common stack, you
may average particulate matter, HCl and mercury emissions to
demonstrate compliance with the limits in Table 2 to this subpart if
you satisfy the requirements in paragraph (i) or (j) of this section.
    (i) For a group of two or more existing units in the same
subcategory, each of which vents through a common emissions control
system to a common stack, that does not receive emissions from units in
other subcategories or categories, you may treat such averaging group
as a single existing unit for

purposes of this subpart and comply with the requirements of this
subpart as if the group were a single unit.
    (j) For all other groups of units subject to paragraph (h) of this
section, the owner or operator may elect to:
    (1) Conduct performance tests according to procedures specified in
Sec.  63.7520 in the common stack if affected units from other
subcategories vent to the common stack. The emission limits that the
group must comply with are determined by the use of equation 6.
[GRAPHIC] [TIFF OMITTED] TP04JN10.008

Where:

En = HAP emission limit, lb/MMBtu, ppm, or ng/dscm;
ELi = Appropriate emission limit from Table 2 to this
subpart for unit i, in units of lb/MMBtu, ppm or ng/dscm;
Hi = Heat input from unit i, MMBtu;

    (2) Conduct performance tests according to procedures specified in
Sec.  63.7520 in the common stack. If affected units from nonaffected
units vent to the common stack, the units from nonaffected units must
be shut down or vented to a different stack during the performance
test); and
    (3) Meet the applicable operating limit specified in Sec.  63.7540
and Table 8 to this subpart for each emissions control system (except
that, if each unit venting to the common stack has an applicable
opacity operating limit, then a single continuous opacity monitoring
system may be located in the common stack instead of in each duct to
the common stack).
    (k) Combination requirements. The common stack of a group of two or
more existing boilers or process heaters in the same subcategory
subject to paragraph (h) of this section may be treated as a separate
stack for purposes of paragraph (b) of this section and included in an
emissions averaging group subject to paragraph (b) of this section.

Sec.  63.7525  What are my monitoring, installation, operation, and
maintenance requirements?

    (a) If your boiler or process heater has a heat input capacity of
100 MMBtu per hour or greater, you must install, operate, and maintain
a continuous emission monitoring system (CEMS) for CO and oxygen
according to the procedures in paragraphs (a)(1) through (6) of this
section by the compliance date specified in Sec.  63.7495. The CO and
oxygen shall be monitored at the same location at the outlet of the
boiler or process heater.
    (1) Each CEMS must be installed, operated, and maintained according
to the applicable procedures under Performance Specification (PS) 3 or
4A of 40 CFR part 60, appendix B, and according to the site-specific
monitoring plan developed according to Sec.  63.7505(d).
    (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 a 30-day rolling average emission
rate on a daily basis. A new 30-day rolling average emission rate is
calculated as the average of all of the hourly CO emission data for the
preceding 30 operating days.
    (6) For purposes of calculating data averages, you must use all the
data collected during all 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.
    (b) If your boiler or process heater has a heat input capacity of
250 MMBtu per hour or greater and combusts coal, biomass, or residual
oil, you must install, certify, maintain, and operate a CEMS measuring
PM emissions discharged to the atmosphere and record the output of the
system as specified in paragraphs (b)(1) through (b)(6) of this
section.
    (1) Each CEMS shall be installed, certified, operated, and
maintained according to the requirements in Sec.  63.7540(a)(8).
    (2) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of a new unit or within
180 days of the compliance date for an existing unit, as specified
under Sec.  63.7495 of this subpart.
    (3) Compliance with the applicable emissions limit shall be
determined based on the 24-hour daily (block) average of the hourly
arithmetic average emissions concentrations using the continuous
monitoring system outlet data. The 24-hour block arithmetic average
emission concentration shall be calculated using EPA Reference Method
19 of appendix A of 40 CFR part 60.
    (4) Obtain valid CEMS hourly averages for all operating hours on a
30-day rolling average basis. At least two data points per hour shall
be used to calculate each 1-hour arithmetic average.
    (5) The 1-hour arithmetic averages required shall be expressed in
lb/MMBtu and shall be used to calculate the boiler operating day daily
arithmetic average emissions.
    (6) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of 40 CFR part 60 to provide, as necessary, valid emissions data for
all operating hours per 30-day rolling average.
    (c) 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
(c)(1) through (7) of this section by the compliance date specified in
Sec.  63.7495.
    (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). You must 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. Any 6-minute 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.
    (7) You must determine and record all the 6-minute averages (and 1-
hour block

averages as applicable) collected for periods during which the COMS is
not out of control.
    (d) 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
(d)(1) through (5) of this section by the compliance date specified in
Sec.  63.7495.
    (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 15-minute 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) You must determine the 3-hour block average of all recorded
readings, except as provided in paragraph (c)(3) of this section.
    (5) You must record the results of each inspection, calibration,
and validation check.
    (e) If you have an operating limit that requires the use of a flow
measurement device, you must meet the requirements in paragraphs (d)
and (e)(1) through (4) of this section.
    (1) You must locate the flow sensor and other necessary equipment
in a position that provides a representative flow.
    (2) You must use a flow sensor with a measurement sensitivity of 2
percent of the flow rate.
    (3) You must reduce swirling flow or abnormal velocity
distributions due to upstream and downstream disturbances.
    (4) You must conduct a flow sensor calibration check at least
semiannually.
    (f) If you have an operating limit that requires the use of a
pressure measurement device, you must meet the requirements in
paragraphs (d) and (f)(1) through (6) of this section.
    (1) Locate the pressure sensor(s) in a position that provides a
representative measurement of the pressure.
    (2) Minimize or eliminate pulsating pressure, vibration, and
internal and external corrosion.
    (3) Use a gauge with a minimum tolerance of 1.27 centimeters of
water or a transducer with a minimum tolerance of 1 percent of the
pressure range.
    (4) Check pressure tap pluggage daily.
    (5) Using a manometer, you must check gauge calibration quarterly
and transducer calibration monthly.
    (6) Conduct calibration checks any time the sensor exceeds the
manufacturer's specified maximum operating pressure range or install a
new pressure sensor.
    (g) If you have an operating limit that requires the use of a pH
measurement device, you must meet the requirements in paragraphs (d)
and (g)(1) through (3) of this section.
    (1) Locate the pH sensor in a position that provides a
representative measurement of scrubber effluent pH.
    (2) Ensure the sample is properly mixed and representative of the
fluid to be measured.
    (3) Check the pH meter's calibration on at least two points every 8
hours of process operation.
    (h) If you have an operating limit that requires the use of
equipment to monitor voltage and secondary amperage (or total power
input) of an electrostatic precipitator (ESP), you must use voltage and
secondary current monitoring equipment to measure voltage and secondary
current to the ESP.
    (i) If you have an operating limit that requires the use of
equipment to monitor sorbent injection rate (e.g., weigh belt, weigh
hopper, or hopper flow measurement device), you must meet the
requirements in paragraphs (c) and (i)(1) through (3) of this section.
    (1) Locate the device in a position(s) that provides a
representative measurement of the total sorbent injection rate.
    (2) Install and calibrate the device in accordance with
manufacturer's procedures and specifications.
    (3) At least annually, calibrate the device in accordance with the
manufacturer's procedures and specifications.
    (j) If you elect to use a fabric filter bag leak detection system
to comply with the requirements of this subpart, you must install,
calibrate, maintain, and continuously operate a bag leak detection
system as specified in paragraphs (j)(1) through (8) of this section.
    (1) You must install and operate a bag leak detection system for
each exhaust stack of the fabric filter.
    (2) Each bag leak detection system must be installed, operated,
calibrated, and maintained in a manner consistent with the
manufacturer's written specifications and recommendations and in
accordance with the guidance provided in EPA-454/R-98-015, September
1997.
    (3) The bag leak detection system must be certified by the
manufacturer to be capable of detecting particulate matter emissions at
concentrations of 10 milligrams per actual cubic meter or less.
    (4) The bag leak detection system sensor must provide output of
relative or absolute particulate matter loadings.
    (5) The bag leak detection system must be equipped with a device to
continuously record the output signal from the sensor.
    (6) The bag leak detection system must be equipped with an alarm
system that will sound automatically when an increase in relative
particulate matter emissions over a preset level is detected. The alarm
must be located where it is easily heard by plant operating personnel.
    (7) For positive pressure fabric filter systems that do not duct
all compartments of cells to a common stack, a bag leak detection
system must be installed in each baghouse compartment or cell.
    (8) Where multiple bag leak detectors are required, the system's
instrumentation and alarm may be shared among detectors.

Sec.  63.7530  How do I demonstrate initial compliance with the
emission limits and work practice standards?

    (a) You must demonstrate initial compliance with each emission
limit that applies to you by conducting initial performance tests
(performance stack tests and fuel analyses) and establishing operating
limits, as applicable, according to Sec.  63.7520, paragraph (c) of
this section, and Tables 5 and 7 to this subpart.
    (b) If you demonstrate compliance through performance stack
testing, you must establish each site-specific operating limit in Table
2 to this subpart that applies to you according to the requirements in
Sec.  63.7520, Table 7 to this subpart, and paragraph (c)(4) of this
section, as applicable. You must also

conduct fuel analyses according to Sec.  63.7521 and establish maximum
fuel pollutant input levels according to paragraphs (c)(1) through (3)
of this section, as applicable.
    (1) You must establish the maximum chlorine fuel input
(Cinput) during the initial performance testing according to
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
chlorine.
    (ii) During the performance testing for HCl, you must determine the
fraction of the total heat input for each fuel type burned
(Qi) based on the fuel mixture that has the highest content
of chlorine, and the average chlorine concentration of each fuel type
burned (Ci).
    (iii) You must establish a maximum chlorine input level using
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.009

Where:

Clinput = Maximum amount of chlorine entering the boiler
or process heater through fuels burned in units of pounds per
million Btu.
Ci = Arithmetic average concentration of chlorine in fuel
type, i, analyzed according to Sec.  63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest content of chlorine.
If you do not burn multiple fuel types during the performance
testing, it is not necessary to determine the value of this term.
Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.

    (2) You must establish the maximum mercury fuel input level
(Mercuryinput) during the initial performance testing using
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
mercury.
    (ii) During the compliance demonstration for mercury, you must
determine the fraction of total heat input for each fuel burned
(Qi) based on the fuel mixture that has the highest content
of mercury, and the average mercury concentration of each fuel type
burned (HGi).
    (iii) You must establish a maximum mercury input level using
Equation 8 of this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.010

Where:

Mercuryinput = Maximum amount of mercury entering the
boiler or process heater through fuels burned in units of pounds per
million Btu.
HGi = Arithmetic average concentration of mercury in fuel
type, i, analyzed according to Sec.  63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest mercury content. If
you do not burn multiple fuel types during the performance test, it
is not necessary to determine the value of this term. Insert a value
of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of mercury.

    (3) You must establish parameter operating limits according to
paragraphs (c)(4)(i) through (iv) of this section.
    (i) For a wet scrubber, you must establish the minimum scrubber
effluent pH, liquid flowrate, and pressure drop as defined in Sec.
63.7575, as your operating limits during the three-run performance
test. If you use a wet scrubber and you conduct separate performance
tests for particulate matter, HCl, and mercury emissions, you must
establish one set of minimum scrubber effluent pH, liquid flowrate, and
pressure drop operating limits. The minimum scrubber effluent pH
operating limit must be established during the HCl performance test. If
you conduct multiple performance tests, you must set the minimum liquid
flowrate and pressure drop operating limits at the highest minimum
values established during the performance tests.
    (ii) For an electrostatic precipitator, you must establish the
minimum voltage and secondary current (or total power input), as
defined in Sec.  63.7575, as your operating limits during the three-run
performance test.
    (iii) For a dry scrubber, you must establish the minimum sorbent
injection rate for each sorbent, as defined in Sec.  63.7575, as your
operating limit during the three-run performance test.
    (iv) The operating limit for boilers or process heaters with fabric
filters that choose to demonstrate continuous compliance through bag
leak detection systems is that a bag leak detection system be installed
according to the requirements in Sec.  63.7525, and that each fabric
filter must be operated such that the bag leak detection system alarm
does not sound more than 5 percent of the operating time during a 6-
month period.
    (c) If you elect to demonstrate compliance with an applicable
emission limit through fuel analysis, you must conduct fuel analyses
according to Sec.  63.7521 and follow the procedures in paragraphs
(c)(1) through (5) of this section.
    (1) If you burn more than one fuel type, you must determine the
fuel mixture you could burn in your boiler or process heater that would
result in the maximum emission rates of the pollutants that you elect
to demonstrate compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel
pollutant concentration of the composite samples analyzed for each fuel
type using the one-sided z-statistic test described in Equation 9 of
this section.
[GRAPHIC] [TIFF OMITTED] TP04JN10.011

Where:

P90 = 90th percentile confidence level pollutant
concentration, in pounds per million Btu.
mean = Arithmetic average of the fuel pollutant concentration in the
fuel samples analyzed according to Sec.  63.7521, in units of pounds
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel
samples analyzed according to Sec.  63.7521, 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 emission limit
for HCl, the HCl emission rate that you calculate for your boiler or
process heater using Equation 10 of this section must not exceed the
applicable emission limit for HCl.

[GRAPHIC] [TIFF OMITTED] TP04JN10.012

Where:

HCl = HCl emission rate from the boiler or process heater in units
of pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of
chlorine in fuel type, i, in units of pounds per million Btu as
calculated according to Equation 8 of this section.
     Qi= Fraction of total heat input from fuel type, i,
based on the fuel mixture that has the highest content of chlorine.
If you do not burn multiple fuel types, it is not necessary to
determine the value of this term. Insert a value of ``1'' for
Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.

    (4) To demonstrate compliance with the applicable emission limit
for mercury, the mercury emission rate that you calculate for your
boiler or process heater using Equation 11 of this section must not
exceed the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TP04JN10.013