electric utility producing 4 billion kilowatt-hours or less as defined
by NAICS codes 221122 (fossil fuel-fired electric utility steam
generating units) and 921150 (fossil fuel-fired electric utility steam
generating units in Indian country); (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.
    Pursuant to RFA section 603, the EPA prepared an initial regulatory
flexibility analysis (IRFA) for the proposed rule and convened a Small
Business Advocacy Review Panel to obtain advice

and recommendations of representatives of the regulated small entities.
A detailed discussion of the Panel's advice and recommendations is
found in the Panel Report (EPA-HQ-OAR-2009-0234-2921). A summary of the
Panel's recommendations is presented at 76 FR 24975.
    As required by RFA section 604, we also prepared a final regulatory
flexibility analysis (FRFA) for the final rule. The FRFA addresses the
issues raised by public comments on the IRFA, which was part of the
proposal of this rule. The FRFA is summarized below and in the RIA.
1. Reasons Why Action Is Being Taken
    In 2000, the EPA made a finding that it was appropriate and
necessary to regulate coal- and oil-fired EGUs under CAA section 112
and listed EGUs pursuant to CAA section 112(c). On March 29, 2005 (70
FR 15994), the EPA published a final rule (2005 Action) that removed
EGUs from the list of sources for which regulation under CAA section
112 was required. That rule was published in conjunction with a rule
requiring reductions in emissions of Hg from EGUs pursuant to CAA
section 111, i.e., CAMR, May 18, 2005, 70 FR 28606). The 2005 Action
was vacated on February 8, 2008, by the U.S. Court of Appeals for the
District of Columbia Circuit. As a result of that vacatur, CAMR was
also vacated and EGUs remain on the list of sources that must be
regulated under CAA section 112. This action provides the EPA's final
NESHAP and NSPS for EGUs.
2. Statement of Objectives and Legal Basis for Final Rules
    The MATS will protect air quality and promote public health by
reducing emissions of HAP. In the December 2000 regulatory
determination, the EPA made a finding that it was appropriate and
necessary to regulate EGUs under CAA section 112. The February 2008
vacatur of the 2005 Action reverted the status of the rule to the
December 2000 regulatory determination. Section 112(n)(1)(A) of the CAA
and the 2000 determination do not differentiate between EGUs located at
major versus area sources of HAP. Thus, the NESHAP for EGUs will
regulate units at both major and area sources. Major sources of HAP are
those that have the potential to emit at least 10 tons per year (tpy)
of any one HAP or at least 25 tpy of any combination of HAP. Area
sources are any stationary sources of HAP that are not major sources.
3. Summary of Issues Raised During the Public Comment Process on the
IRFA
    The EPA received a number of comments related to the Regulatory
Flexibility Act during the public comment process. A consolidated
version of the comments received is reproduced below. These comments
can also be found in their entirety in the response to comment document
in the docket.
    Comment: Several commenters expressed concern with the SBAR panel.
Some believe Small Entity Representatives (SERs) were not provided with
regulatory alternatives including descriptions of significant
regulatory options, differing timetables, or simplifications of
compliance and reporting requirements, and subsequently were not
presented with an opportunity to respond. One commenter believes the
EPA's formal SBAR Panel notification and subsequent information
provided by the EPA to the Panel did not include information on the
potential impacts of the rule as required by CAA section 609(b)(1).
Additional commenters suggested that the EPA's rulemaking schedule put
pressure on the SBAR Panel through the abbreviated preparation for the
Panel. Commenters also expressed concerns that the EPA did not provide
participants more than cursory background information on which to base
their comments. One commenter stated that the EPA did not provide
deliberative materials, including draft proposed rules or discussions
of regulatory alternatives, to the SBAR Panel members. One commenter
stated the SBAR Panel Report does not meet the statutory obligation to
recommend less burdensome alternatives. The commenter suggested the EPA
panel members declined to make recommendations that went further than
consideration or investigation of broad regulatory alternatives, with
the exception of those recommendations in which the EPA rejected
alternative interpretations of the CAA section 112 and relevant court
cases. Two stated that the EPA did not respond to the concerns of the
small business community, the SBA, or OMB, ignoring concerns expressed
by the SER panelists. One commenter believes the EPA failed to convene
required meetings and hearings with affected parties as required by law
for small business entities. One commenter stated that the SERs' input
is very important because more than 90 percent of public power utility
systems meet the definition and qualify as small businesses under the
SBREFA.
    Response: The RFA requires that SBAR Panels collect advice and
recommendations from SERs on the issues related to:

--The number and description of the small entities to which the
proposed rule will apply;
--The projected reporting, recordkeeping and other compliance
requirements of the proposed rule;
--Duplication, overlap or conflict between the proposed rule and other
federal rules; and
--Alternatives to the proposed rule that accomplish the stated
statutory objectives and minimize any significant economic impact on
small entities.
    The RFA does not require a covered agency to create or assemble
information for SERs or for the government panel members. Although CAA
section 609(b)(4) requires that the government Panel members review any
material the covered agency has prepared in connection with the RFA,
the law does not prescribe the materials to be reviewed. The EPA's
policy, as reflected in its RFA guidance, is to provide as much
information as possible, given time and resource constraints, to enable
an informed Panel discussion. In this rulemaking, because of a court-
ordered deadline, the EPA was unable to hold a pre-panel meeting but
still provided SERs with the information available at the time, held a
standard Panel Outreach meeting to collect verbal advice and
recommendations from SERs, and provided the standard 14-day written
comment period to SERs. The EPA received substantial input from the
SERs, and the Panel report describes recommendations made by the Panel
on measures the Administrator should consider that would minimize the
economic impact of the proposed rule on small entities. The EPA
complied with the RFA. In addition, we met with representatives of
small businesses, small rural cooperatives, and small governments a
number of times during the regulatory development process to discuss
their issues and concerns regarding the proposed MATS rule for EGUs.
    Comment: One commenter requested that the EPA work with utilities
such that new regulations are as flexible and cost efficient as
possible.
    Response: In developing the final rule, the EPA has considered all
information provided prior to, as well as in response to, the proposed
rule. The EPA has endeavored to make the final regulations flexible and
cost-efficient while adhering to the requirements of

the CAA. The final rule includes a number of flexibilities, such as
those related to monitoring requirements, that will lower costs and
simplify compliance for small businesses and local governments.
    Comment: One commenter was concerned about the ability of small
entities or nonprofit utilities such as those owned and/or operated by
rural electric co-op utilities, and municipal utilities to comply with
the proposed standards within 3 years. The commenter believes that the
EPA disregarded the SER panelists who explained that under these
current economic conditions they have constraints on their ability to
raise capital for the construction of control projects and to acquire
the necessary resources in order to meet a 3-year compliance deadline.
Two commenters expressed concern that smaller utilities and those in
rural areas will be unable to get vendors to respond to their requests
for proposals, because they will be able to make more money serving
larger utilities.
    Response: The preamble to the proposed rule (76 FR 25054; May 3,
2011) provides a detailed discussion of how the EPA determined
compliance times for the proposed (and final) rule. The EPA has
provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period
for sources to come into compliance. Sources may also seek a 1-year
extension of the compliance period from their Title V permitting
authority if the source needs that time to install controls. See CAA
section 112(i)(3)(B). If the situation described by commenters (i.e.,
where small entities or nonprofit utilities constraints on ability to
raise capital for construction of control projects and to acquire
necessary resources) results in the source needing additional time to
install controls, they would be in a position to request the 1-year
extension.
    Comment: Several commenters believe the EPA did not adequately
consider the disproportionately large impact on smaller generating
units. The commenters note the diseconomies in scale for pollution
controls for such units. One commenter noted the rule will create a
more serious compliance hurdle for small communities that depend on
coal-fired generation to meet their base load demand. The commenter
notes that by not subcategorizing units, the EPA is dictating a fuel
switch due to the disproportionately high cost on small communities.
The other commenter believes the MACT and NSPS standards are
unachievable by going too far without really considering the impacts on
small municipal units, as public power is critical to communities,
jobs, economic viability and electric reliability. A generating and
transmissions electric cooperative which qualifies as a small entity
believes the rule will ultimately result in increased electricity costs
to its members and will negatively impact the economies of the
primarily rural areas that they serve. Another commenter believes there
is no legal or factual basis for creating subcategories or weaker
standards for state, tribal, or municipal governments or small entities
that are operating obsolete units, particularly given the current
market situation and applicable equitable factors. The commenter
suggests both the EPA's and SBA's analyses focus exclusively on the
effects on entities causing HAP emissions and primarily on those
operating obsolete EGUs, and fail to consider either impacts on
downwind businesses and governments or the positive impacts on small
entities and governments owning and operating competing, clean and
modern EGUs.
    Response: The EPA disagrees with the commenters' belief that the
impacts on smaller generating units were not adequately considered when
developing the rule. The EPA determined the number of potentially
impacted small entities and assessed the potential impact of the
proposed action on small entities, including municipal units. A similar
assessment was conducted in support of the final action. Specifically,
the EPA estimated the incremental net annualized compliance cost, which
is a function of the change in capital and operating costs, fuel costs,
and change in revenue. The projected compliance cost was considered
relative to the projected revenue from generation. Thus, the EPA's
analysis accounts not only for the additional costs these entities face
resulting from compliance, but also the impact of higher electricity
prices. The EPA evaluated suggestions from SERs, including
subcategorization recommendations. In the preamble to the proposed
rule, the EPA explains that, normally, any basis for subcategorizing
must be related to an effect on emissions, rather than some difference
which does not affect emissions performance. The EPA does not see a
distinction between emissions from smaller generating units versus
larger units. The EPA acknowledges the comment that there is no legal
or factual basis for creating subcategories or weaker standards for
state, tribal, or municipal governments or small entities that are
operating obsolete units.
    Comment: One commenter notes that the EPA recognizes LEEs in the
rule such that they should receive less onerous monitoring
requirements; however, the EPA does not recognize that small and LEEs
also need and merit more flexible and achievable pollution control
requirements. The commenter notes that the capital costs for emissions
control at small utility units is disproportionately high due to
inefficiencies in Hg removal, space constraints for control technology
retrofits, and the fact that small units have fewer rate base customers
across which to spread these costs. The commenter cites the Michigan
Department of Environmental Quality report titled ``Michigan's Mercury
Electric Utility Workgroup, Final Report on Mercury Emissions from
Coal-Fired Power Plants,'' (June 2005). The commenter notes that the
EPA has addressed such concerns previously, citing the RIA for the 1997
8-hour ozone standard. The commenter also suggests smaller utility
systems generally have less capital to invest in pollution control than
larger, investor-owned systems, due to statutory inability to borrow
from the private capital markets, statutory debt ceilings, limited
bonding capacity, borrowing limitations related to fiscal strain posed
by other, non-environmental factors, and other limitations.
    Response: The EPA acknowledges that the rule contains reduced
monitoring requirements for existing units that qualify as LEEs.
Although the EPA does not believe that reduced pollution control
requirements are warranted for LEEs, including small entity LEEs, we
believe that flexible and achievable pollution control requirements are
promoted through alternative standards, alternative compliance options,
and emissions averaging as a means of demonstrating compliance with the
standards for existing EGUs.
    Comment: One commenter believes that the EPA should develop more
limited monitoring requirements for small EGUs. The commenter notes
small entities do not possess the monetary resources, manpower, or
technical expertise needed to operate cutting-edge monitoring
techniques such as Hg CEMS and PM CEMS. The commenter notes the EPA
could have identified monitoring alternatives to the SER panel for
consideration.
    Response: The EPA provided monitoring alternatives to using PM
CEMS, HCl CEMS, and Hg CEMS in its proposed standards and in this final
rule. The continuous compliance alternatives are available to all
affected sources, including small entities. As alternatives to the use
of PM CEMS and HCl CEMS, sources are allowed to

conduct additional performance testing. Sorbent trap monitoring is
allowed in lieu of Hg CEMS.
    Comment: Several commenters believe the EPA has not sufficiently
complied with the requirements of the RFA or adequately considered the
impact this rulemaking would have on small entities. One commenter
believes the EPA has not engaged in meaningful outreach and
consultation with small entities and therefore recommends that the EPA
seek to revise the court-ordered deadlines to which this rulemaking is
subject, re-convene the SBAR panel, prepare a new initial regulatory
flexibility analysis (IRFA), and issue it for additional public comment
prior to final rulemaking. The commenter believes the IRFA does not
sufficiently consider impacts on small entities as identified in the
SBAR Panel Report. The commenter believes it is not apparent that the
EPA considered the recommendations of the Panel. The commenter believes
the description of significant alternatives in the IRFA is almost
entirely quoted from the SBAR Panel Report, which the commenter does
not believe is an adequate substitute for the EPA's own analysis of
alternatives. The commenter also notes the EPA does not discuss the
potential impacts of its decisions on small entities or the impacts of
possible flexibilities. Where the EPA does consider regulatory
alternatives in principle, the commenter believes it does not provide
sufficient support for its decisions to understand on what basis the
EPA rejected alternatives that may or may not have reduced burden on
small entities while meeting the stated objectives of the rule.
Additionally, the commenter notes that the EPA did not evaluate the
economic or environmental impacts of significant alternatives to the
proposed rule. One commenter believes that the EPA's stated reasons for
declining to specify or analyze an area source standard are inadequate
under the RFA. The commenter believes the EPA must give serious
consideration to regulatory alternatives that accomplish the stated
objectives of the CAA while minimizing any significant economic impacts
on small entities and that the EPA has a duty to specify and analyze
this option or to more clearly state its policy reasons for excluding
serious consideration of a separate standard for area sources. A
commenter believes the EPA did not fully consider the subcategorization
of sources such as boilers designed to burn lignite coals versus other
fossil fuels, especially in regard to non-mercury metal and acid gas
emissions. The commenter references the SBAR Panel Report suggestion
provided in the preamble of the proposed rule that the EPA consider
developing an area source vs. major source distinction for the source
category and the EPA's response. Another commenter is concerned that
the recommendations made by the SER participants were ignored and not
discussed in the rulemaking. Specifically, the commenter notes the EPA
did not discuss subcategorizing by age, type of plant, fuel, physical
space constraints or useful anticipated life of the plant. Nor did the
EPA establish GACT for smaller emitters to alleviate regulatory costs
and operational difficulties. A commenter believes it is likely that
different numerical or work practice standards are appropriate for area
sources of HAP.
    Response: The EPA disagrees with one commenter's assertion that the
agency has not complied with the requirements of the RFA. The EPA
complied with both the letter and spirit of the RFA, notwithstanding
the constraints of the court-ordered deadline. For example, the EPA
notified the Chief Counsel for Advocacy of the SBA of its intent to
convene a Panel; compiled a list of SERs for the Panel to consult with;
and convened the Panel. The Panel met with SERs to collect their advice
and recommendations; reviewed the EPA materials; and drafted a report
of Panel findings. The EPA further disagrees with the commenter's
assertion that the EPA's IRFA does not sufficiently consider impacts on
small entities. The EPA's IRFA, which is included in chapter 10 of the
RIA for the proposed rule, addresses the statutorily required elements
of an IRFA, such as the economic impact of the proposed rule on small
entities and the Panel's findings.
    The EPA disagrees with the comment that recommendations made by the
SERs were not considered or discussed in the proposed rulemaking such
as recommendations regarding subcategorization and separate GACT
standards for area sources. The preamble to the proposed standards
includes a detailed discussion of how the EPA determined which
subcategories and sources would be regulated (76 FR 25036-25037; May 3,
2011). In that discussion, the EPA explains the rationale for its
proposed subcategories based on five unit design types. In addition,
the EPA acknowledges the subcategorization suggestions from the SERs
and explains its reasons for not subcategorizing on those bases. The
preamble to the proposed standards also includes a discussion of the
SERs' suggestion that area source EGUs be distinguished from major-
source EGUs and the EPA's reasons for not making that distinction (76
FR 25020-25021; May 3, 2011).
    The EPA also disagrees with the suggestion that the Agency pursue
an extension of the timeline for final rulemaking such that the SBAR
Panel can be reconvened and a new IRFA can be prepared and released for
public comment prior to the final rulemaking. The EPA entered into a
Consent Decree to resolve litigation alleging that the EPA failed to
perform a non-discretionary duty to promulgate CAA section 112(d)
standards for EGUs. See American Nurses Ass'n v. EPA, 08-2198 (D.D.C.).
That Decree required the EPA to sign the final MATS rule by November
16, 2011, unless the agency sought to extend the deadline consistent
with the requirements of the modification provision of the Consent
Decree. The EPA and Plaintiffs stipulated to a 30-day extension
consistent with the modification provisions of the Consent Decree and
the rule must be signed no later than December 16, 2011. If plaintiffs
in the American Nurses litigation objected to an additional extension
request, which we believe would have been likely, the Agency would have
had to file a motion with the Court seeking an extension of the
deadline. Consistent with governing case law, the Agency would have
been required to demonstrate in its motion for extension that it was
impossible to finalize the rule by the deadline provided in the Consent
Decree. See Sierra Club v. Jackson, Civil Action No. 01-1537 (D.D.C.)
(Opinion of the Court denying EPA's motion to extend a consent decree
deadline). The EPA negotiated a 30-day extension and was able to
complete the rule by December 16, 2011; accordingly, the Agency had no
basis for seeking a further extension of time.
    A detailed description of the changes made to the rule since
proposal, including those made as a result of feedback received during
the public comment process can be found in sections VI (NESHAP) and X
(NSPS) of this preamble. Changes explained in the identified sections
include those related to applicability; subcategorization; work
practices; periods of startup, shutdown, and malfunction; initial
testing and compliance; continuous compliance; and notification,
recordkeeping, and reporting.
4. Description and Estimate of the Affected Small Entities
    For the purposes of assessing the impacts of MATS on small
entities, a small entity is defined as:

    (1) A small business according to the Small Business Administration
size standards by the North American Industry Classification System
(NAICS) category of the owning entity. The range of small business size
standards for electric utilities is 4 billion kilowatt hours (kWh) of
production or less;
    (2) A small government jurisdiction that is a government of a city,
county, town, district, or special district with a population of less
than 50,000; and
    (3) A small organization that is any not for profit enterprise that
is independently owned and operated and is not dominant in its field.
    The EPA examined the potential economic impacts to small entities
associated with this rulemaking based on assumptions of how the
affected entities will install control technologies in compliance with
MATS. This analysis does not examine potential indirect economic
impacts associated with this rule, such as employment effects in
industries providing fuel and pollution control equipment, or the
potential effects of electricity price increases on industries and
households.
    The EPA used Velocity Suite's Ventyx data as a basis for
identifying plant ownership and compiling the list of potentially
affected small entities. The Ventyx dataset contains detailed ownership
and corporate affiliation information. The analysis focused only on
those EGUs affected by the rule, which includes units burning coal,
oil, petroleum coke, or coal refuse as the primary fuel, and excludes
any combustion turbine units or EGUs burning natural gas. Also, because
the rule does not affect combustion units with an equivalent
electricity generating capacity up to 25 MW, small entities that do not
own at least one combustion unit with a capacity greater than 25 MW
were removed from the dataset. For the affected units remaining, boiler
and generator capacity, heat input, generation, and emissions data were
aggregated by owner and then by parent company. Entities with more than
4 billion kWh of annual electricity generation were removed from the
list, as were municipal owned entities with a population greater than
50,000. For cooperatives, investor owned utilities, and subdivisions
that generate less than 4 billion kWh of electricity annually but which
may be part of a large entity, additional research on power sales,
operating revenues, and other business activities was performed to make
a final determination regarding size. Finally, small entities for which
the IPM does not project generation in 2015 in the base case were
omitted from the analysis because they are not projected to be
operating and, thus, are not projected to face the costs of compliance
with the rule. After omitting entities for the reasons above, the EPA
identified a total of 82 potentially affected small entities that are
affiliated with 102 EGUs.
5. Compliance Cost Impacts
    The number of potentially affected small entities by ownership type
and potential impacts of MATS are presented in Chapter 7 of the RIA and
summarized here. The EPA estimated the annualized net compliance cost
to small entities to be approximately $106 million in 2015 (2007$).
    The EPA assessed the economic and financial impacts of the final
rule using the ratio of compliance costs to the value of revenues from
electricity generation, and our results focus on those entities for
which this measure could be greater than 1 percent or 3 percent. Of the
82 small entities identified, The EPA's analysis shows 40 entities may
experience compliance costs greater than 1 percent of base generation
revenues in 2015, and 35 may experience compliance costs greater than 3
percent of base revenues. Also, all generating capacity at 3 small
entities is projected to be uneconomic to maintain. In this analysis,
the cost of withdrawing a unit as uneconomic is estimated as the base
case profit that is forgone by not operating under the policy case.
Because 35 of the 82 total units, or more than 40 percent, are
estimated to incur compliance cost greater than 3 percent of base
revenues, the EPA has concluded that it cannot certify that there will
be no significant economic impact on a substantial number of small
entities (SISNOSE) for this rule. Results for small entities discussed
here do not account for the reality that electricity markets are
regulated in parts of the country. Entities operating in regulated or
cost-of-service markets should be able to recover all of their costs of
compliance through rate adjustments.
    Note that the estimated costs for small entities are significantly
lower than those estimated by the EPA for the MATS proposal (which were
$379 million). This is driven by a small group of units (less than 6
percent) which were projected to be uneconomic to operate under the
proposal (and hence incurred lost profits due to lost electricity
revenues), but are now projected to continue their operations under
MATS. In addition, the EPA's modeling indicates one unit that would
have operated at a low capacity factor under the base case would find
it economical to increase its generation significantly under MATS to
meet electricity demand in its region. Excluding this unit, the total
cost impacts across all entities would be roughly $175 million. Changes
in compliance behavior for this small group of units, in particular the
one unit which operates at a higher capacity factor, has a substantial
impact on total costs as their increased generation revenues offsets a
large portion of the compliance costs.
    The most significant components of incremental costs to these
entities are changes in electricity revenues, followed by the increased
capital and operating costs for retrofits. Capital and operating costs
increase across all ownership types, but the direction of changes in
electricity revenues varies among ownership types. All ownership types,
with the exception of private entities, experience a net gain in
electricity revenues under the MATS, unlike projections from the EPA's
modeling during the proposal, where only municipals benefitted from
higher electricity revenues. The change in electricity revenue takes
into account both the profit lost from units that do not operate under
the policy case and the difference in revenue for operating units under
the policy case. According to the EPA's modeling, an estimated 274 MW
of capacity owned by small entities are considered uneconomic to
operate under the policy case, resulting in a net loss of $13 million
(in 2007$) in profits. On the other hand, many operating units actually
increase their electricity revenue due to higher electricity prices
under MATS. In addition, as mentioned above, the EPA's modeling
indicates one unit finds it economical to increase its capacity factor
significantly under the policy case which results in significantly
higher revenues offsetting the costs.
6. Description of Steps To Minimize Impacts on Small Entities
    Consistent with the requirements of the RFA and SBREFA, the EPA has
taken steps to minimize the significant economic impact on small
entities. Because this rule does not affect units with a generating
capacity of less than 25 MW, small entities that do not own at least
one generating unit with a capacity greater than 25 MW are not subject
to the rule. According to the EPA's analysis, among the coal- and oil-
fired EGUs (i.e., excluding combined cycle gas turbines and gas
combustion turbines) about 26 potentially small entities only own EGUs
with a capacity less than or equal to 25 MW, and none of those entities
are subject to the final

rule based on the statutory definition of potentially regulated units.
    For units affected by the proposed rule, the EPA considered a
number of comments received, both during the Small Business Advocacy
Review (SBAR) Panel and the public comment period. While none of the
alternatives adopted is specifically applied to small entities, the EPA
believes these modifications will make compliance less onerous for all
regulated units, including those owned by small entities.
    a. Work practice standards. The EPA proposed numerical emission
standards that would apply at all times, including during periods of
startup and shutdown. After reviewing comments and other data regarding
the nature of these periods of operation, the EPA is finalizing a work
practice standard for periods of startup and shutdown. The EPA is also
finalizing work practice standards for organic HAP from all
subcategories of EGUs. Descriptions of the work practice requirements
for startup and shutdown, as well as organic HAP and limited-use liquid
oil-fired EGUs, can be found in section VI.D-E. of the preamble.
    b. Continuous compliance and notification, record-keeping, and
reporting. The final rule greatly simplifies the continuous compliance
requirements and provides two basic approaches for most situations: use
of continuous monitoring and periodic testing. The frequency of
periodic testing has been decreased from monthly in the proposal to
quarterly in the final rule. In addition to simplifying compliance, the
EPA believes these changes considerably reduce the overall burden
associated with recordkeeping and reporting. These changes to the final
rule are described in more detail in Section VI.G-H of this preamble.
    c. Subcategorization. The Small Entity Representatives on the SBAR
Panel were generally supportive of subcategorization and suggested a
number of additional subcategories the EPA should consider when
developing the final rule. Although it was not consistent with the
statute to adopt the proposed subcategories, the EPA maintained the
existing subcategories and split the ``liquid oil-fired units''
subcategory into three subcategories--continental, non-continental
units, and limited-use units.
    d. MACT floor calculations. As recommended by the EPA SBAR Panel
representative, the EPA established the MACT floors using all the
available ICR data that was received to the maximum extent possible
consistent with the CAA requirements. The Agency believes this approach
reasonably ensures that the emission limits selected as the MACT floors
adequately represent the level of emissions actually achieved by the
average of the units in the top 12 percent, considering operational
variability of those units.
    e. Alternatives not adopted. The EPA did not adopt several of the
suggestions posed either during the SBAR Panel or public comment
period. The EPA did not propose a percent reduction standard as an
alternative to the concentration-based MACT floor. The percent
reduction format for Hg and other HAP emissions would not have
addressed the EPA's consideration of coal preparation practices that
remove Hg and other HAP before firing. Also, to account for the coal
preparation practices, sources would be required to track the HAP
concentrations in coal from the mine to the stack, and not just before
and after the control device(s), and such an approach would be
difficult to implement and enforce. Furthermore, the EPA does not
believe the percent reduction standard is in line with the Court's
interpretation of the CAA section 112 requirements. Even if we believed
it was appropriate to establish a percent reduction standard, we do not
have the data necessary to establish percent reduction standards for
HAP, as explained further in the response to comments document.
    The EPA determined not to establish GACT standards for area sources
for a number of reasons. The data show that similar HAP emissions and
control technologies are found on both major and area sources greater
than 25 MW, and some large units are synthetic area sources. In fact,
because of the significant number of well-controlled EGUs of all sizes,
we believe it would be difficult to make a distinction between MACT and
GACT. Moreover, the EPA believes the standards for area source EGUs
should reflect MACT, rather than GACT, because there is no essential
difference between area source and major source EGUs with respect to
emissions of HAP.
    The EPA determined not to exercise its discretionary authority to
establish health-based emission standards for HCl and other HAP acid
gases. Given the limitations of the currently available information
(e.g., the HAP mix where EGUs are located, and the cumulative impacts
of respiratory irritants from nearby sources), the environmental
effects of HCl and the other acid gas HAP, and the significant co-
benefits from reductions in criteria pollutants the EPA determined that
setting a conventional MACT standard for HCl and the other acid gas HAP
was the appropriate course of action.
    As required by SBREFA section 212, the EPA also is preparing a
Small Entity Compliance Guide to help small entities comply with this
rule. Small entities will be able to obtain a copy of the Small Entity
Compliance guide at the following Web site: http://www.epa.gov/airquality/powerplanttoxics/actions.html.

D. Unfunded Mandates Reform Act of 1995

    Title II of the UMRA of 1995, 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 UMRA section 202, 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, UMRA
section 205 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 UMRA section 205 do not apply
when they are inconsistent with applicable law. Moreover, UMRA 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 UMRA
section 203. 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 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'' under

UMRA section 202 that is within the RIA and which is summarized below.
1. Statutory Authority
    As discussed elsewhere in this preamble, the statutory authority
for this rulemaking is CAA section 112. Title III of the CAA Amendments
was enacted to reduce nationwide air toxic emissions. CAA section
112(b) 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.
    CAA section 112(d) 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 coal- and oil-fired EGUs.
    In compliance with UMRA section 205(a), we identified and
considered a reasonable number of regulatory alternatives. Additional
information on the costs and environmental impacts of these regulatory
alternatives were presented in the RIA for the rulemaking.
    The regulatory alternative upon which this rule is based represents
the MACT floor for all regulated pollutants for all but one EGU
subcategory for all but one regulated pollutant for that subcategory.
These MACT floor-based standards represent the least costly and least
burdensome alternative. Beyond-the-floor emission limits for Hg are for
existing coal-fired EGUs in the subcategory for low rank virgin coal
EGUs.
2. Social Costs and Benefits
    The RIA prepared for this rule including the Agency's assessment of
costs and benefits is in the docket.
    It is estimated that HAP would be reduced by thousands of tons in
2015, relative to the base case, including reductions in HCl, HF,
metallic HAP (including Hg), and several other organic HAP from EGUs.
Studies have determined a relationship between exposure to certain of
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, significant reductions in PM2.5 and SO2
will occur, including approximately 53 thousand tons of
PM2.5 and over 1 million tons of SO2. These
reductions will occur by 2016 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).
Although we are unable to monetize the benefits associated with the HAP
emissions reductions other than for Hg or all benefits associated with
Hg 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
2016 associated with the implementation of the final rule range from
$37 billion to $90 billion (2007 dollars) when using a 3 percent
discount rate or from $33 billion to $81 billion (2007 dollars) when
using a 7 percent discount rate). Our estimate of costs is $9.6 billion
(2007 dollars). For more detailed information on the benefits and costs
estimated for this rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
    The UMRA requires that we estimate, where accurate estimation is
reasonably feasible, future compliance costs imposed by this rule and
any disproportionate budgetary effects. Our estimates of the future
compliance costs of this rule are discussed previously in this
preamble.
    The EPA assessed the economic and financial impacts of the rule on
government-owned entities using the ratio of compliance costs to the
value of revenues from electricity generation, and our results focus on
those entities for which this measure could be greater than 1 percent
or 3 percent of base revenues. The EPA projects that 42 government
entities will have compliance costs greater than 1 percent of base
generation revenue in 2016, and 32 may experience compliance costs
greater than 3 percent of base revenues. Overall, 6 units owned by
government entities are expected to retire. The most significant
components of incremental costs to these entities are the increased
capital and operating costs, followed by changes in electricity
revenues. For more details on these results and the methodology behind
their estimation, see the results included in chapter 7 of the RIA.
4. Effects on the National Economy
    The UMRA requires that we estimate the effect of this rule on the
national economy. To the extent feasible, we must estimate the effect
on productivity, economic growth, full employment, creation of
productive jobs, and international competitiveness of the U.S. goods
and services, if we determine that accurate estimates are reasonably
feasible and that such effect is relevant and material.
    The nationwide economic impact of this rule is presented in the RIA
in the docket. This analysis provides estimates of the effect of this
rule on some of the categories mentioned above.
    The results of the economic impact analysis are summarized
previously in this preamble. The results show that, relative to
baseline, there will be an average 3.1 percent increase in electricity
price on average nationwide in 2016, with the range of increases from
1.3 percent to 6.3 percent in regions throughout the U.S., and a less
than 1 percent increase in natural gas price nationwide in 2016. The
roughly 3 percent incremental price effect of this rule is small
relative to the changes observed in the absolute levels of electricity
prices over the last 50 years, which have ranged from as much as 23
percent lower (in 1969) to as much as 23 percent higher (in 1982) than
prices observed in 2010.\377\ Power generation from coal-fired plants
will fall by about 2 percent nationwide in 2016. No region of the U.S.
is expected to experience a double-digit increase in retail electricity
prices in 2015 or in any year later than that, according to the
Agency's analysis, as a result of this rule. To put the electricity
price effects in context, the roughly 3 percent incremental increase in
aggregate end-user electricity prices projected to occur over the next
4 years is about the same as the 3 percent absolute average change in
total end-user electricity prices observed on an annual basis.\378\
Furthermore, the roughly 3 percent incremental price effect of this
rule is small relative to the changes observed in the absolute levels
of electricity prices over the last 50 years, which have ranged from as
much as 23 percent lower (in 1969) to as much as 23 percent higher (in
1982) than prices observed in 2010.\379\ Even with this rule in effect,
electricity prices are projected to be lower in 2015 and 2020 than they
were in 2010.\380\
---------------------------------------------------------------------------

    \377\ EIA Annual Energy Outlook 2010 annual total electricity
prices from 1960 to 2010, Table 8-10.
    \378\ EIA Annual Energy Outlook 2010 annual total electricity
prices from 1960 t0 2010, Table 8-10.
    \379\ Ibid.
    \380\ Ibid., EIA AEO 2010, Table-10 for price levels; and
Chapterr 3 of the RIA for electricity price differential.
---------------------------------------------------------------------------

5. Consultation With Government
    The UMRA requires that we describe the extent of the Agency's prior
consultation with affected state, local,

and tribal officials, summarize the officials' comments or concerns,
and summarize our response to those comments or concerns. In addition,
UMRA section 203 requires that we develop a plan for informing and
advising small governments that may be significantly or uniquely
impacted by a regulatory action. Consistent with the intergovernmental
consultation provisions of UMRA section 204, the EPA initiated
consultations with governmental entities affected by this rule. The EPA
invited the following 10 national organizations representing state and
local elected officials to a meeting held on October 27, 2010, in
Washington, DC: (1) National Governors Association; (2) National
Conference of State Legislatures, (3) Council of State Governments, (4)
National League of Cities, (5) U.S. Conference of Mayors, (6) National
Association of Counties, (7) International City/County Management
Association, (8) National Association of Towns and Townships, (9)
County Executives of America, and (10) Environmental Council of States.
These 10 organizations of elected state and local officials have been
identified by the EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. The
purposes of the consultation were to provide general background on the
rule, answer questions, and solicit input from state/local governments.
During the meeting, officials asked clarifying questions regarding CAA
section 112 requirements and central decision points presented by the
EPA (e.g., use of surrogate pollutants to address HAP,
subcategorization of source category, assessment of emissions
variability). They also expressed uncertainty with regard to how
utility boilers owned/operated by state and local entities would be
impacted, as well as with regard to the potential burden associated
with implementing the rule on state and local entities (i.e., burden to
re-permit affected EGUs or update existing permits). Officials
requested, and the EPA provided, addresses associated with the 112
state and local governments estimated to be potentially impacted by the
rule. The EPA has not received additional questions or requests from
state or local officials.
    Consistent with UMRA section 205, the EPA has identified and
considered a reasonable number of regulatory alternatives. Because the
potential existed for a significant impact for substantial number of
small entities, the EPA convened a SBAR Panel to obtain advice and
recommendation of representatives of the small entities that
potentially would be subject to the requirements of the rule. As part
of that process, the EPA considered several options, which are
discussed previously in this preamble. Those options included
establishing emission limits, establishing work practice standards,
establishing subcategories, and consideration of monitoring options.
The regulatory alternative selected is a combination of the options
considered and includes provisions regarding a number of the
recommendations resulting from the SBAR Panel process as described
below (see the Regulatory Flexibility Act discussion in this section of
the preamble for more detail).

E. Executive Order 13132, Federalism

    Under EO 13132, the EPA may not issue an action that has federalism
implications, that imposes substantial direct compliance costs, and
that is not required by statute, unless the federal government provides
the funds necessary to pay the direct compliance costs incurred by
state and local governments, or the EPA consults with state and local
officials early in the process of developing the final action.
    The EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on state or local governments, and the federal government will not
provide the funds necessary to pay those costs. Accordingly, the EPA
provides the following federalism summary impact statement as required
by section 6(b) of EO 13132.
    Based on estimates in the RIA, provided in the docket, the final
rule may have federalism implications because the rule may impose
approximately $294 million in annual direct compliance costs on an
estimated 96 state or local governments. Specifically, we estimate that
there are 80 municipalities, 5 states, and 11 political subdivisions
(i.e., a public district with territorial boundaries embracing an area
wider than a single municipality and frequently covering more than one
county for the purpose of generating, transmitting and distributing
electric energy) that may be directly impacted by this final rule.
Responses to the EPA's 2010 ICR were used to estimate the nationwide
number of potentially impacted state or local governments. As
previously explained, this 2010 survey was submitted to all coal- and
oil-fired EGUs listed in the 2007 version of DOE/EIA's ``Annual
Electric Generator Report,'' and ``Power Plant Operations Report.''
    The EPA consulted with state and local officials in the process of
developing the rule to permit them to have meaningful and timely input
into its development. The EPA met with 10 national organizations
representing state and local elected officials to provide general
background on the rule, answer questions, and solicit input. In the
final rule, EPA has provided flexibilities that will lower compliance
costs for these entities. The EPA also recognizes that municipalities
may need a longer compliance timeframe because of required approval
processes.

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

    Subject to EO 13175 (65 FR 67249; November 9, 2000) the EPA may not
issue a regulation that has tribal implications, that imposes
substantial direct compliance costs, and that is not required by
statute, unless the federal government provides the funds necessary to
pay the direct compliance costs incurred by tribal governments, or the
EPA consults with tribal officials early in the process of developing
the proposed regulation and develops a tribal summary impact statement.
Executive Order 13175 requires the EPA to develop an accountable
process to ensure ``meaningful and timely input by Tribal officials in
the development of regulatory policies that have Tribal implications.''
    The EPA has concluded that this action may have tribal
implications. The EPA offered consultation with tribal officials early
in the regulation development process to permit them an opportunity to
have meaningful and timely input. Consultation letters were sent to 584
tribal leaders and provided information regarding the EPA's development
of this rule and offered consultation. At the request of the tribes,
three consultation meetings were held: December 7, 2010, with the Upper
Sioux Community of Minnesota; December 13, 2010, with Moapa Band of
Paiutes, Forest County Potawatomi, Standing Rock Sioux Tribal Council,
and Fond du Lac Band of Chippewa; January 5, 2011, with the Forest
County Potawatomi, and a representative from the National Tribal Air
Association (NTAA). In these meetings, the EPA presented the authority
under the CAA used to develop these rules and an overview of the
industry and the industrial processes that have the potential for
regulation. Tribes expressed concerns about the impact of EGUs in
Indian country. Specifically, they were concerned about potential Hg
deposition and the impact on the water resources of the tribes, with
particular concern about the impact on subsistence

lifestyles for fishing communities, the cultural impact of impaired
water quality for ceremonial purposes, and the economic impact on
tourism. In light of these concerns, the tribes expressed interest in
an expedited implementation of the rule. Other concerns expressed by
tribes related to how the Agency would consider variability in setting
the standards, and the use of tribal-specific fish consumption data
from the tribes in our assessments. They were not supportive of using
work practice standards as part of the rule, and asked the Agency to
consider going beyond the MACT floor to offer more protection for the
tribal communities.
    In addition to these consultations, the EPA also conducted outreach
on this rule through presentations at the National Tribal Forum in
Milwaukee, WI; phone calls with the NTAA; and a webinar for tribes on
the proposed rule. The EPA specifically requested tribal data that
could support the appropriate and necessary analyses and the RIA for
this rule. In addition, the EPA held individual consultations with the
Navajo Nation on October 12, 2011; as well as the Gila River Indian
Community, Ak-Chin Indian Community, and the Hopi Nation on October 14,
2011. These tribes expressed concerns about the impact of the rule on
the Navajo Generating Station (NGS), the impact on the cost of the
water allotted to the tribes from the Central Arizona Project (CAP),
the impact on tribal revenues from the coal mining operations (i.e.,
assumptions about reduced mining if NGS were to retire one or more
units), and the impacts on employment of tribal members at both the NGS
and the mine. More specific comments can be found in the docket.
    The EPA will continue to work with these and other potentially
affected tribes as this final rule is implemented.

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

    This final rule is subject to EO 13045 (62 FR 19885; April 23,
1997) because it is an economically significant regulatory action as
defined by EO 12866, and EPA believes that the environmental health or
safety risk addressed by this action may have a disproportionate effect
on children. Accordingly, we have evaluated the environmental health or
safety effects of the standards on children.
    Although this final rule is based on technology performance, the
standards are designed to protect against hazards to public health with
an adequate margin of safety as described in Section III of this
preamble. The protection offered by this rule is particularly important
for children, especially the developing fetus. As referenced in Chapter
4 of the RIA, ``Mercury and Other HAP Benefits Analysis,'' children are
more vulnerable than adults to many HAP emitted by EGUs due to
differential behavior patterns and physiology. These unique
susceptibilities were carefully considered in a number of different
ways in the analyses associated with this rulemaking, and are
summarized in the RIA. We also estimate substantial health improvements
for children in the form of 130,000 fewer asthma attacks, 3,100 fewer
emergency room visits due to asthma, 6,300 fewer cases of acute
bronchitis, and approximately 140,000 fewer cases of upper and lower
respiratory illness.

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

    Executive Order 13211 (66 FR 28355; May 22, 2001) requires EPA to
prepare and submit a Statement of Energy Effects to the Administrator
of the Office of Information and Regulatory Affairs, OMB, for actions
identified as ``significant energy actions.'' This action, which is a
significant regulatory action under EO 12866, is likely to have a
significant adverse effect on the supply, distribution, or use of
energy. We have prepared a Statement of Energy Effects for this action
as follows.
    We estimate a 3.1 percent price increase for electricity nationwide
in 2016 and a less than 2 percent percentage fall in coal-fired power
production as a result of this rule. The EPA projects that electric
power sector-delivered natural gas prices will increase by about 0.6
percent over the 2015 to 2030 timeframe. For more information on the
estimated energy effects, please refer to the economic impact analysis
for this final rule. The analysis is available in the RIA, which is in
the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use voluntary consensus standards in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices) that are developed or adopted by voluntary
consensus standards bodies. The NTTAA directs the EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
    This rulemaking involves technical standards. The EPA cites the
following standards in the final rule: EPA Methods 1, 2, 2A, 2C, 2F,
2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of 40 CFR part 60
and Method 320 of 40 CFR part 63. Consistent with the NTTAA, the 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 final rule.
    The voluntary consensus standard American National Standards
Institute (ANSI)/American Society of Mechanical Engineers (ASME) PTC
19-10-1981, ``Flue and Exhaust Gas Analyses [part 10, Instruments and
Apparatus]'' is cited in the final rule for its manual method for
measuring the O2, CO2, and CO content of exhaust
gas. This part of ANSI/ASME PTC 19-10-1981 is an acceptable alternative
to Method 3B.
    The voluntary consensus standard ASTM D6348-03 (Reapproved 2010),
``Standard Test Method for Determination of Gaseous Compounds by
Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy'' is
acceptable as an alternative to Method 320 and is cited in the final
rule, but with several conditions: (1) The test plan preparation and
implementation in the Annexes to ASTM D6348-03, Sections A1 through A8
are mandatory; and (2) In ASTM D6348-03 Annex A5 (Analyte Spiking
Technique), the percent (%) R must be determined for each target
analyte (Equation A5.5). In order for the test data to be acceptable
for a compound, %R must be 70% >= R <= 130%. If the %R value does not
meet this criterion for a target compound, the test data are not
acceptable for that compound and the test must be repeated for that
analyte (i.e., the sampling and/or analytical procedure should be
adjusted before a retest). The %R value for each compound must be
reported in the test report, and all field measurements must be
corrected with the calculated %R value for that compound by using the
following

equation: Reported Result = (Measured Concentration in the Stack x
100)/% R.
    The voluntary consensus standard ASTM D6784-02, ``Standard Test
Method for Elemental, Oxidized, Particle-Bound and Total Mercury in
Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro
Method),'' is an acceptable alternative to use of EPA Method 29 for Hg
only or Method 30B for the purpose of conducting relative accuracy
tests of Hg continuous monitoring systems under this final rule.
Because of the limitations of this method in terms of total sampling
volume, it is not appropriate for use in performance testing under this
rule. In addition to the voluntary consensus standards the EPA used in
the final rule, the search for emissions measurement procedures
identified 16 other voluntary consensus standards. The EPA determined
that 14 of these 16 standards identified for measuring emissions of the
HAP or other pollutants subject to emission standards in the final rule
were impractical alternatives to EPA test methods for the purposes of
this final rule. Therefore, the EPA did not adopt these standards for
this purpose. The reasons for this determination for the 14 methods are
discussed below, and the remaining 2 methods are discussed later in
this section.
    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 this
rulemaking because 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 (Reapproved 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 this 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 the
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
this rule. The standard recommends the use of an L-shaped pitot, which
historically has not been recommended by the 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 because 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 non-mandatory 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 require drift checks after each run.
    Two very similar voluntary consensus standards, ASTM D5835-95
(Reapproved 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 this final 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 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 not an acceptable alternative to EPA Method 3A
for measuring CO and O2 concentrations for this final rule
as the method is designed for application to sources firing natural
gas.
    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 pros and cons 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 PM. 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 milligram (mg), while CAN/CSA Z223.1 requires
reporting 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. The 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 Hg 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 16 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the final 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.
    Finally, in addition to the three voluntary consensus standards
identified as acceptable alternatives to EPA methods required in the
final rule, the EPA is also specifying four voluntary consensus
standards in the rule for use in sampling and analysis of liquid oil
samples for moisture content. These standards are: ASTM D95-05
(Reapproved 2010), ``Standard Test Method for Water in Petroleum
Products and Bituminous Materials by Distillation,'' ASTM D4006-11,
``Standard Test Method for Water in Crude Oil by Distillation,'' ASTM
D4177-95 (Reapproved 2010), ``Standard Practice for Automatic Sampling
of Petroleum and Petroleum Products,'' and ASTM D4057-06 (Reapproved
2011), ``Standard Practice for Manual Sampling of Petroleum and
Petroleum Products.''
    Table 5, section <IP_ADDRESS> of appendix A, and section 3.1.2 of
appendix B to subpart UUUUU, 40 CFR part 63, list the EPA testing
methods included in the final rule. Under section 63.7(f) and section
63.8(f) of subpart A of the General Provisions, a source may apply to
the 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 specified.

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

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice (EJ). Its main
provision directs federal agencies, to the greatest extent practicable
and permitted by law, to make EJ part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
U.S.
    The EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority, low income, and indigenous populations because it
increases the level of environmental protection for all affected
populations without having any disproportionately

high and adverse human health or environmental effects on any
population, including any minority, low income, and indigenous
populations.
    This final rule establishes national emission standards for new and
existing EGUs that combust coal and oil. The EPA estimates that there
are approximately 1,400 units located at 600 facilities covered by this
final rule.
    This final rule will reduce emissions of all the listed HAP that
come from EGUs. This includes metals (Hg, As, Be, Cd, Cr, Pb, Mn, Ni,
and Se), organics (POM, acetaldehyde, acrolein, benzene, dioxins,
ethylene dichloride, formaldehyde, and PCB), and acid gases (HCl and
HF). At sufficient levels of exposure, these pollutants can cause a
range of health effects including cancer; irritation of the lungs,
skin, and mucous membranes; effects on the central nervous system such
as memory and IQ loss and learning disabilities; damage to the kidneys;
and other acute health disorders.
    The final rule will also result in substantial reductions of
criteria pollutants such as CO, PM, and SO2. Sulfur dioxide
is a precursor pollutant that is often transformed into fine PM
(PM2.5) in the atmosphere. Reducing direct emissions of
PM2.5 and SO2 will, as a result, reduce
concentrations of PM2.5 in the atmosphere. These reductions
in PM2.5 will provide large health benefits, such as
reducing the risk of premature mortality for adults, chronic and acute
bronchitis, childhood asthma attacks, and hospitalizations for other
respiratory and cardiovascular diseases. (For more details on the
health effects of metals, organics, and PM2.5, please refer
to the RIA contained in the docket for this rulemaking.) This final
rule will also have a small effect on electricity and natural gas
prices but has the potential to affect the cost structure of the
utility industry and could lead to shifts in how and where electricity
is generated.
    This final rule is one of a group of regulatory actions that the
EPA has taken and will take over the next several years to respond to
statutory and judicial mandates that will reduce exposure to HAP and
PM2.5, as well as to other pollutants, from EGUs and other
sources. In addition, the EPA will pursue energy efficiency
improvements throughout the economy, along with other federal agencies,
states and other groups. This will contribute to additional
environmental and public health improvements while lowering the costs
of realizing those improvements. Together, these rules and actions will
have substantial and long-term effects on both the U.S. power industry
and on communities currently breathing dirty air. Therefore, we
anticipate significant interest in many, if not most, of these actions
from EJ communities, among many others.
1. Key EJ Aspects of the Rule
    This is an air toxics rule; therefore, it does not permit emissions
trading among sources. Instead, this final rule will place a limit on
the rates of Hg and other HAP emitted from each affected EGU. As a
result, emissions of Hg and other HAP such as HCl will be substantially
reduced in the vast majority of states. In some states, however, there
may be small increases in Hg and other HAP emissions due to shifts in
electricity generation from EGUs with higher emission rates to EGUs
with already low emission rates. Hydrogen chloride emissions are
projected to increase at a small number of sources but that does not
lead to any increased emissions at the state level.
    The primary risk analysis to support the finding that this final
rule is both appropriate and necessary includes an analysis of the
effects of Hg from EGUs on people who rely on freshwater fish they
catch as a regular and frequent part of their diet. These groups are
characterized as subsistence level fishing populations or fishers. A
significant portion of the data in this analysis came from published
studies of EJ communities where people frequently consume locally-
caught freshwater fish. These communities included: (1) White and black
populations (including female and poor strata) surveyed in South
Carolina; (2) Hispanic, Vietnamese and Laotian populations surveyed in
California; and (3) Great Lakes tribal populations (Chippewa and
Ojibwe) active on ceded territories around the Great Lakes. These data
were used to help estimate risks to similar populations beyond the
areas where the study data were collected. For example, while the
Vietnamese and Laotian survey data were collected in California, given
the ethnic (heritage) nature of these high fish consumption rates, we
assumed that they could also be associated with members of these ethnic
groups living elsewhere in the U.S. Therefore, the high-end consumption
rates referenced in the California study for these ethnic groups were
used to model risk at watersheds elsewhere in the U.S. As a result of
this approach, the specific fish consumption patterns of several
different EJ groups are fundamental to the EPA's assessment of both the
underlying risks that make this final rule appropriate and necessary,
and of the analysis of the benefits of reducing exposure to Hg and the
other HAP.
    The EPA's full analysis of risks from consumption of Hg-
contaminated fish is contained in the RIA for this rule. The effects of
this final rule on the health risks from Hg and other HAP are presented
in the preamble and in the RIA for this rule.
2. Potential Environmental and Public Health Impacts to Minority, Low
Income, or Tribal Populations
    The EPA has conducted several analyses that provide additional
insight on the potential effects of this rule on EJ communities. These
include: (1) The socio-economic distribution of people living close to
affected EGUs who may be exposed to pollution from these sources; and
(2) an analysis of the distribution of health effects expected from the
reductions in PM2.5 that will result from implementation of
this final rule (co-benefits).
    a. Socio-Economic Distribution. As part of the analysis for this
final rule, the EPA reviewed the aggregate demographic makeup of the
communities near EGUs covered by this final rule. Although this
analysis gives some indication of populations that may be exposed to
levels of pollution that cause concern, it does not identify the
demographic characteristics of the most highly affected individuals or
communities. Electric generating units usually have very tall emission
stacks; this tends to disperse the pollutants emitted from these stacks
fairly far from the source. In addition, several of the pollutants
emitted by these sources, such as a common form of Hg and
SO2, are known to travel long distances and contribute to
adverse impacts on both the environment and human health hundreds or
even thousands of miles from where they were emitted (in the case of
elemental Hg, globally).
    The proximity-to-the-source review is included in the analysis for
this final rule because some EGUs emit enough HAP such as Ni or Cr(VI)
to cause elevated lifetime cancer risks greater than 1 in a million in
nearby communities. In addition, the EPA's analysis indicates that
there are localized areas with potential for elevated levels of Hg
deposition around most U.S. EGUs.\381\
---------------------------------------------------------------------------

    \381\ See Excess Local Deposition TSD for more detail.
---------------------------------------------------------------------------

    The analysis of demographic data used proximity-to-the-source as a
surrogate for exposure to identify those populations considered to be
living near affected sources, such that they have notable exposures to
current HAP

emissions from these sources. The demographic data for this analysis
were extracted from the 2000 census data which were provided to the EPA
by the U.S. Census Bureau. Distributions by race are based on
demographic information at the census block level, and all other
demographic groups are based on the extrapolation of census block group
level data to the census block level. The socio-demographic parameters
used in the analysis included the following categories: Racial (White,
African American, Native American, Other or Multiracial, and All Other
Races); Ethnicity (Hispanic); and Other (Number of people below the
poverty line, Number of people with ages between 0 and 18, Number of
people greater than or equal to 65, Number of people with no high
school diploma).
    In determining the aggregate demographic makeup of the communities
near affected sources, the EPA focused on those census blocks within
three miles of affected sources and determined the demographic
composition (e.g., race, income, etc.) of these census blocks and
compared them to the corresponding compositions nationally. The radius
of 3 miles (or approximately 5 kilometers) is consistent with other
demographic analyses focused on areas around potential sources. In
addition, air quality modeling experience has shown that the area
within three miles of an individual source of emissions can generally
be considered the area with the highest ambient air levels of the
primary pollutants being emitted for most sources, both in absolute
terms and relative to the contribution of other sources (assuming there
are other sources in the area, as is typical in urban areas). Although
facility processes and fugitive emissions may have more localized
impacts, the EPA acknowledges that because of various stack heights
there is the potential for dispersion beyond 3 miles. To the extent
that any minority, low income, and indigenous 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. The results of the EPA's
demographic analysis for affected sources are shown in the following
table: 382 383

                             Table 12--Comparative Summary of the Demographics Within 5 KM (3 Miles) of the Affected Sources
                                                              [Population in millions] 382
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              African         Native         Other and                                     Below poverty
                                               White         American        American       multiracial      Hispanic      Minority 383        line
--------------------------------------------------------------------------------------------------------------------------------------------------------
Near Source Total (3 mi)................            8.78            2.51            0.10            2.52            2.86            5.13            2.43
% of Near Source Total..................           63              18               1              18              21              37              17
National Total..........................          215              35               2.49           33.3            39.1            70.8            37.1
% of National Total.....................           75              12               1              12              14              25              13
--------------------------------------------------------------------------------------------------------------------------------------------------------
\382\ Racial and ethnic categories overlap and cannot be summed.
\383\ The ``Minority'' population is the overall population (in the first row) minus white population (in the second row).

    The data indicate that coal-fired EGUs are located in areas where
the minority share of the population living within a three mile buffer
is higher than the national average by 12 percentage points or 48
percent. For these same areas, the percent of the population below the
poverty line is also higher than the national average by 4 percentage
points or 31 percent. These results are presented in more detail in the
``Review of Proximity Analysis,'' February 2011, a copy of which is
available in the docket.
    b. PM2.5 (Co-Benefits) Analysis. As mentioned above,
many of the steps EGUs will take to reduce their emissions of air
toxics as required by this final rule will also reduce emissions of PM
and SO2. As a result, this final rule will reduce
concentrations of PM2.5 in the atmosphere. Exposure to
PM2.5 can cause or contribute to adverse health effects,
such as asthma and heart disease, that significantly affect many
minority, low-income, and tribal individuals and their communities.
Fine PM (PM2.5) is particularly (but not exclusively)
harmful to children, the elderly, and people with existing heart and
lung diseases, including asthma. Exposure can cause premature death and
trigger heart attacks, asthma attacks in children and adults with
asthma, chronic and acute bronchitis, and emergency room visits and
hospitalizations, as well as milder illnesses that keep children home
from school and adults home from work. Missing work due to illness or
the illness of a child is a particular problem for people who have jobs
that do not provide paid sick days. Low-wage employees also risk losing
their jobs if they are absent too often, even if it is due to their own
illness or the illness of a child or other relative. Finally, many
individuals in these communities lack access to high quality health
care to treat these types of illnesses. Due to all these factors, many
minority and low-income communities are particularly susceptible to the
health effects of PM2.5 and receive a variety of benefits
from reducing it.
    We estimate that in 2016 the annual PM-related benefits of the
final rule for adults include approximately 4,200 to 11,000 fewer
premature mortalities, 2,900 fewer cases of chronic bronchitis, 4,800
fewer non-fatal heart attacks, 2,600 fewer hospitalizations (for
respiratory and cardiovascular disease combined), 3.2 million fewer
days of restricted activity due to respiratory illness and
approximately 540,000 fewer lost work days. As described in EO 13045,
Protection of Children from Environmental Health Risks and Safety
Risks, we also estimate substantial health improvements for children.
    We also examined the PM2.5 mortality risks according to
race, income, and educational attainment. We then estimated the change
in PM2.5 mortality risk as a result of this final rule among
people living in the counties with the highest (top 5 percent)
PM2.5 mortality risk in 2005. We then compared the change in
risk among the people living in these ``high-risk'' counties with
people living in all other counties.
    In 2005, people living in the highest risk counties and in the
poorest counties had a substantially higher risk of PM2.5-
related death than people living in the other 95 percent of counties.
This was

true regardless of race; the difference between the groups of counties
for each race was large while the differences among races in both
groups of counties was very small. In contrast, the analysis found that
people with less than high school education had a significantly greater
risk from PM2.5 mortality than people with a greater than
high school education. This was true both for the highest-risk counties
and for the other counties. In summary, the analysis indicates that in
2005, educational status, living in one of the poorest counties, and
living in a high-risk county are associated with higher
PM2.5 mortality risk while race is not.
    Our analysis demonstrates that this final rule will significantly
reduce the PM2.5 mortality among all populations of
different races living throughout the U.S. compared to both 2005 and
2016 pre-rule (i.e., base case) levels. The analysis indicates that
people living in counties with the highest rates (top 5 percent) of
PM2.5 mortality risk in 2005 receive the largest reduction
in mortality risk after this rule takes effect. We also find that
people living in the poorest 5 percent of the counties receive a larger
reduction in PM2.5 mortality risk than all other counties.
More information can be found in Section 7.11 of the RIA.
    The EPA estimates that the benefits of the final rule are
distributed among races, income levels, and levels of education fairly
evenly. However, the analysis does indicate that this final rule in
conjunction with the implementation of existing or final rules (e.g.,
the CSAPR) will reduce the disparity in risk between those in the
highest-risk counties and the other 95 percent of counties for all
races and educational levels. In addition, in many cases implementation
of this final rule and other rules will, together, reduce risks in the
highest-risk counties to the approximate level of risk for the rest of
the counties as it existed before implementation of the rule.
    These results are presented in more detail in Section 7.11 of the
RIA.
3. Meaningful Public Participation
    The 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 policies. To
promote meaningful involvement, the EPA publicized the rulemaking via
newsletters, EJ listserves, and the internet, including the Office of
Policy's (OP) Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/RuleGate.nsf/). During the comment period, the EPA discussed the
proposed rule via a conference call with communities, conducted a
community-oriented webinar on the proposed rule, and posted the webinar
presentation on- line. The EPA also held three public hearings to
receive additional input on the proposal.
    There will continue to be opportunities for public notice and
comment as the utilities move forward with implementation of this rule.
Once the rule is finalized, affected EGUs will need to update their
Title V operating permits to reflect their new emission limits, any
other new applicable requirements, and the associated monitoring and
recordkeeping from this rule. The Title V permitting process provides
that when most permits are reopened (for example, to incorporate new
applicable requirements) or renewed, there must be opportunity for
public review and comments. In addition, after the public review
process, the EPA has an opportunity to review the proposed permit and
object to its issuance if it does not meet CAA requirements.
4. Additional Analysis
    In addition to the previously described assessment of EJ impacts,
the EPA conducted an analysis of sub-populations with particularly high
potential risks of Hg exposure due to high rates of fish consumption.
These populations overlap in many cases with traditional EJ populations
and would benefit from Hg reductions resulting from this rule. The EPA
also conducted an analysis of the distribution of PM2.5-
related mortality risk according to the race, income and education of
the population and how MATS changes this distribution. These analyses
can be found in Section 7.12 of the RIA.
5. Summary
    This final rule strictly limits the emissions rate of Hg and other
HAP from every affected EGU. The EPA's analysis indicates substantial
health benefits, including for minority, low income, and indigenous
populations, from reductions in PM2.5.
    The EPA's analysis also indicates reductions in risks for
individuals, including for members of minority populations, who eat
fish frequently from U.S. lakes and rivers and who live near affected
sources. Based on all the available information, the EPA has determined
that this final rule will not have disproportionately high and adverse
human health or environmental effects on minority, low income, and
indigenous populations. The EPA is providing multiple opportunities for
EJ communities to both learn about and comment on this rule and
welcomes their participation as implementation of the rule proceeds.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
U.S. The EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective April 16, 2012.

List of Subjects

40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.

40 CFR Part 63

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

    Dated: December 16, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, of the
Code of the Federal Regulations is amended as follows:

PART 60--[AMENDED]

0
1. The authority citation for part 60 continues to read as follows:

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

Subpart A--[Amended]

0
2. Section 60.17 is amended:
0
a. By redesignating paragraph (a)(93), added March 21, 2011, at 76 FR
15750, and delayed indefinitely at 76 FR 28664, May 18, 2011, as
paragraph (a)(96);

0
b. By redesignating paragraphs (a)(91) and (a)(92) as paragraphs
(a)(94) and (a)(95);
0
c. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs
(a)(91) and (a)(92);
0
d. By redesignating paragraphs (a)(54) through (a)(88) as paragraphs
(a)(55) through (a)(89);
0
e. By adding paragraph (a)(54);
0
f. By adding paragraph (a)(90); and
0
g. By adding paragraph (a)(93) to read as follows:

Sec.  60.17  Incorporations by reference.

* * * * *
    (a) * * *
    (54) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, approved September 1, 2008, IBR approved for Sec. Sec.
60.41b of subpart Db of this part and 60.41c of subpart Dc of this
part.
* * * * *
    (90) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, approved July 15, 2011, IBR approved for Sec. Sec.  60.41b
of subpart Db of this part and 60.41c of subpart Dc of this part.
* * * * *
    (93) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
approved August 1, 2010, IBR approved for Sec. Sec.  60.41b of subpart
Db of this part and 60.41c of subpart Dc of this part.
* * * * *

Subpart B--[Amended]

0
3. Section 60.21 is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (f).
0
c. By removing paragraph (k).

Sec.  60.21  Definitions.

* * * * *
    (a) Designated pollutant means any air pollutant, the emissions of
which are subject to a standard of performance for new stationary
sources, but for which air quality criteria have not been issued and
that is not included on a list published under section 108(a) or
section 112(b)(1)(A) of the Act.
* * * * *
    (f) Emission standard means a legally enforceable regulation
setting forth an allowable rate of emissions into the atmosphere,
establishing an allowance system, or prescribing equipment
specifications for control of air pollution emissions.
* * * * *

0
4. Section 60.24 is amended as follows:
0
a. By revising paragraph (b)(1).
0
b. By removing paragraph (h).

Sec.  60.24  Emission standards and compliance schedules.

* * * * *
    (b) * * *
    (1) Emission standards shall either be based on an allowance system
or prescribe allowable rates of emissions except when it is clearly
impracticable. Such cases will be identified in the guideline documents
issued under Sec.  60.22. Where emission standards prescribing
equipment specifications are established, the plan shall, to the degree
possible, set forth the emission reductions achievable by
implementation of such specifications, and may permit compliance by the
use of equipment determined by the State to be equivalent to that
prescribed.
* * * * *

Subpart D--[Amended]

0
5. The subpart heading for Subpart D is revised to read as follows:

Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators

0
6. Section 60.40 is amended by revising paragraph (e) to read as
follows:

Sec.  60.40  Applicability and designation of affected facility.

* * * * *
    (e) Any facility subject to either subpart Da or KKKK of this part
is not subject to this subpart.

0
7. Section 60.41 is amended by adding the definition of ``natural gas''
in alphabetical order to read as follows:

Sec.  60.41  Definitions.

* * * * *
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
* * * * *

0
8. Section 60.42 is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By adding paragraph (d).
0
c. By adding paragraph (e).

Sec.  60.42  Standard for particulate matter (PM).

    (a) Except as provided under paragraphs (b), (c), (d), and (e) of
this section, on and after the date on which the performance test
required to be conducted by Sec.  60.8 is completed, no owner or
operator subject to the provisions of this subpart shall cause to be
discharged into the atmosphere from any affected facility any gases
that:
* * * * *
    (d) An owner or operator of an affected facility that combusts only
natural gas is exempt from the PM and opacity standards specified in
paragraph (a) of this section.
    (e) An owner or operator of an affected facility that combusts only
gaseous or liquid fossil fuel (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and
that does not use post-combustion technology to reduce emissions of
SO2 or PM is exempt from the PM standards specified in
paragraph (a) of this section.

0
9. Section 60.45 is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraphs (b)(1) through (5).
0
d. By revising paragraph (b)(6) introductory text.
0
e. By revising paragraphs (b)(7)(i)(A) through (C).
0
f. By revising paragraph (b)(7)(ii)(B).
0
g. By adding paragraph (b)(8).

Sec.  60.45  Emissions and fuel monitoring.

    (a) Each owner or operator of an affected facility subject to the
applicable emissions standard shall install, calibrate, maintain, and
operate continuous opacity monitoring system (COMS) for measuring
opacity and a continuous emissions monitoring system (CEMS) for
measuring SO2 emissions, NOX emissions, and
either oxygen (O2) or carbon dioxide (CO2) except
as provided in paragraph (b) of this section.
    (b) Certain of the CEMS and COMS requirements under paragraph (a)
of this section do not apply to owners or operators under the following
conditions:
    (1) For a fossil-fuel-fired steam generator that combusts only
gaseous or liquid fossil fuel (excluding residual oil)

with potential SO2 emissions rates of 26 ng/J (0.060 lb/
MMBtu) or less and that does not use post-combustion technology to
reduce emissions of SO2 or PM, COMS for measuring the
opacity of emissions and CEMS for measuring SO2 emissions
are not required if the owner or operator monitors SO2
emissions by fuel sampling and analysis or fuel receipts.
    (2) For a fossil-fuel-fired steam generator that does not use a
flue gas desulfurization device, a CEMS for measuring SO2
emissions is not required if the owner or operator monitors
SO2 emissions by fuel sampling and analysis.
    (3) Notwithstanding Sec.  60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec.  60.8 have been conducted. If the owner or operator
demonstrates during the performance test that emissions of
NOX are less than 70 percent of the applicable standards in
Sec.  60.44, a CEMS for measuring NOX emissions is not
required. If the initial performance test results show that
NOX emissions are greater than 70 percent of the applicable
standard, the owner or operator shall install a CEMS for NOX
within one year after the date of the initial performance tests under
Sec.  60.8 and comply with all other applicable monitoring requirements
under this part.
    (4) If an owner or operator is not required to and elects not to
install any CEMS for either SO2 or NOX, a CEMS
for measuring either O2 or CO2 is not required.
    (5) For affected facilities using a PM CEMS, a bag leak detection
system to monitor the performance of a fabric filter (baghouse)
according to the most current requirements in Sec.  60.48Da of this
part, or an ESP predictive model to monitor the performance of the ESP
developed in accordance and operated according to the most current
requirements in section Sec.  60.48Da of this part a COMS is not
required.
    (6) A COMS for measuring the opacity of emissions is not required
for an affected facility that does not use post-combustion technology
(except a wet scrubber) for reducing PM, SO2, or carbon
monoxide (CO) emissions, burns only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight percent sulfur, and is
operated such that emissions of CO to the atmosphere from the affected
source are maintained at levels less than or equal to 0.15 lb/MMBtu on
a boiler operating day average basis. Owners and operators of affected
sources electing to comply with this paragraph must demonstrate
compliance according to the procedures specified in paragraphs
(b)(6)(i) through (iv) of this section.
* * * * *
    (7) * * *
    (i) * * *
    (A) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
    (B) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
    (C) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
* * * * *
    (ii) * * *
    (B) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
* * * * *
    (8) A COMS for measuring the opacity of emissions is not required
for an affected facility at which the owner or operator installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
* * * * *

Subpart Da--[Amended]

0
10. The subpart heading for Subpart Da is revised to read as follows:

Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units

0
11. Section 60.40Da is amended by revising paragraphs (b)(1) and (e) to
read as follows:

Sec.  60.40Da  Applicability and designation of affected facility.

* * * * *
    (b) * * *
    (1) The IGCC electric utility steam generating unit is capable of
combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel
(either alone or in combination with any other fuel) in the combustion
turbine engine and associated heat recovery steam generator; and
* * * * *
    (e) Applicability of this subpart to an electric utility combined
cycle gas turbine other than an IGCC electric utility steam generating
unit is as specified in paragraphs (e)(1) through (3) of this section.
    (1) Affected facilities (i.e. heat recovery steam generators used
with duct burners) associated with a stationary combustion turbine that
are capable of combusting more than 73 MW (250 MMBtu/h) heat input of
fossil fuel are subject to this subpart except in cases when the
affected facility (i.e. heat recovery steam generator) meets the
applicability requirements of and is subject to subpart KKKK of this
part.
    (2) For heat recovery steam generators use with duct burners
subject to this subpart, only emissions resulting from the combustion
of fuels in the steam generating unit (i.e. duct burners) are subject
to the standards under this subpart. (The emissions resulting from the
combustion of fuels in the stationary combustion turbine engine are
subject to subpart GG or KKKK, as applicable, of this part.)
    (3) Any affected facility that meets the applicability requirements
and is subject to subpart Eb or subpart CCCC of this part is not
subject to the emission standards under subpart Da.

0
12. Section 60.41Da is amended as follows:
0
a. By revising the definitions of ``boiler operating day'', ``gaseous
fuel'', ``integrated gasification combined cycle electric utility steam
generating unit'', ``natural gas'', ``petroleum'', ``potential
combustion concentration'', and ``steam generating unit''.
0
b. By adding the definitions of ``affirmative defense'', ``combined
heat and power'', ``gross energy output'', ``net energy output'',
``out-of-control period'', and ``petroleum coke'' in alphabetical
order.

0
c. By removing the definitions of ``available purchase power'',
``cogeneration'', ``dry flue gas desulfurization technology ``,
``electric utility company'', ``emergency condition'', ``emission rate
period'', ``gross output'', ``interconnected'', ``net system
capacity'', ``principal company'', ``responsible official'', ``spare
flue gas desulfurization system module'', ``spinning reserve'',
``system emergency reserves'', and ``system load''.

Sec.  60.41Da  Definitions.

* * * * *
    Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
* * * * *
    Boiler operating day for units constructed, reconstructed, or
modified before February 29, 2005, means a 24-hour period during which
fossil fuel is combusted in a steam-generating unit for the entire 24
hours. For units constructed, reconstructed, or modified after February
28, 2005, boiler operating day means a 24-hour period between 12
midnight and the following midnight during which any fuel is combusted
at any time in the steam-generating unit. It is not necessary for fuel
to be combusted the entire 24-hour period.
* * * * *
    Combined heat and power, also known as ``cogeneration,'' means a
steam-generating unit that simultaneously produces both electric (and
mechanical) and useful thermal energy from the same primary energy
source.
* * * * *
    Gaseous fuel means any fuel that is present as a gas at standard
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
* * * * *
    Gross energy output means:
    (1) For facilities constructed, reconstructed, or modified before
May 4, 2011, the gross electrical or mechanical output from the
affected facility plus 75 percent of the useful thermal output measured
relative to ISO conditions that is not used to generate additional
electrical or mechanical output or to enhance the performance of the
unit (i.e., steam delivered to an industrial process);
    (2) For facilities constructed, reconstructed, or modified after
May 3, 2011, the gross electrical or mechanical output from the
affected facility minus any electricity used to power the feedwater
pumps and any associated gas compressors (air separation unit main
compressor, oxygen compressor, and nitrogen compressor) plus 75 percent
of the useful thermal output measured relative to ISO conditions that
is not used to generate additional electrical or mechanical output or
to enhance the performance of the unit (i.e., steam delivered to an
industrial process);
    (3) For combined heat and power facilities constructed,
reconstructed, or modified after May 3, 2011, the gross electrical or
mechanical output from the affected facility divided by 0.95 minus any
electricity used to power the feedwater pumps and any associated gas
compressors (air separation unit main compressor, oxygen compressor,
and nitrogen compressor) plus 75 percent of the useful thermal output
measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process);
    (4) For a IGCC electric utility generating unit that coproduces
chemicals constructed, reconstructed, or modified after May 3, 2011,
the gross useful work performed is the gross electrical or mechanical
output from the unit minus electricity used to power the feedwater
pumps and any associated gas compressors (air separation unit main
compressor, oxygen compressor, and nitrogen compressor) that are
associated with power production plus 75 percent of the useful thermal
output measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process). Auxiliary loads that are associated with power production are
determined based on the energy in the coproduced chemicals compared to
the energy of the syngas combusted in combustion turbine engine and
associated duct burners.
* * * * *
    Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means an
electric utility combined cycle gas turbine that is designed to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction or repair. No solid fuel is directly
burned in the unit during operation.
* * * * *
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
    Net energy output means the gross energy output minus the parasitic
load associated with power production. Parasitic load includes, but is
not limited to, the power required to operate the equipment used for
fuel delivery systems, air pollution control systems, wastewater
treatment systems, ash handling and disposal systems, and other
controls (i.e., pumps, fans, compressors, motors, instrumentation, and
other ancillary equipment required to operate the affected facility).
* * * * *
    Out-of-control period means any period beginning with the quadrant
corresponding to the completion of a daily calibration error, linearity
check, or quality assurance audit that indicates that the instrument is
not measuring and recording within the applicable performance
specifications and ending with the quadrant corresponding to the
completion of an additional calibration error, linearity check, or
quality assurance audit following corrective action that demonstrates
that the instrument is measuring and recording within the applicable
performance specifications.
    Petroleum for facilities constructed, reconstructed, or modified
before May 4, 2011, means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate oil, and residual oil. For
units constructed, reconstructed, or modified after May 3, 2011,
petroleum means crude oil or a fuel derived from crude oil, including,
but not limited to, distillate oil, residual oil, and petroleum coke.
    Petroleum coke, also known as ``petcoke,'' means a carbonization
product of high-boiling hydrocarbon fractions obtained in petroleum
processing (heavy residues). Petroleum

coke is typically derived from oil refinery coker units or other
cracking processes.
    Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result
from combustion of a fuel in an uncleaned state without emission
control systems. For sulfur dioxide (SO2) the potential
combustion concentration is determined under Sec.  60.50Da(c).
* * * * *
    Steam generating unit for facilities constructed, reconstructed, or
modified before May 4, 2011, means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included). For units
constructed, reconstructed, or modified after May 3, 2011, steam
generating unit means any furnace, boiler, or other device used for
combusting fuel for the purpose of producing steam (including fossil-
fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included) plus any
integrated combustion turbines and fuel cells.
* * * * *
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13. Section 60.42Da is revised to read as follows:

Sec.  60.42Da  Standards for particulate matter (PM).

    (a) Except as provided in paragraph (f) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
an owner or operator of an affected facility shall not cause to be
discharged into the atmosphere from any affected facility for which
construction, reconstruction, or modification commenced before March 1,
2005, any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu)
heat input.
    (b) Except as provided in paragraphs (b)(1) and (b)(2) of this
section, on and after the date the initial PM performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, an owner or operator of an affected facility shall not
cause to be discharged into the atmosphere any gases which exhibit
greater than 20 percent opacity (6-minute average), except for one 6-
minute period per hour of not more than 27 percent opacity.
    (1) An owner or operator of an affected facility that elects to
install, calibrate, maintain, and operate a continuous emissions
monitoring system (CEMS) for measuring PM emissions according to the
requirements of this subpart is exempt from the opacity standard
specified in this paragraph (b) of this section.
    (2) An owner or operator of an affected facility that combusts only
natural gas is exempt from the opacity standard specified in paragraph
(b) of this section.
    (c) Except as provided in paragraphs (d) and (f) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after February
28, 2005, but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility any gases that contain PM in
excess of either:
    (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
    (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the
combustion of solid, liquid, or gaseous fuel.
    (d) As an alternative to meeting the requirements of paragraph (c)
of this section, the owner or operator of an affected facility for
which construction, reconstruction, or modification commenced after
February 28, 2005, but before May 4, 2011, may elect to meet the
requirements of this paragraph. On and after the date on which the
initial performance test is completed or required to be completed under
Sec.  60.8, whichever date comes first, no owner or operator of an
affected facility shall cause to be discharged into the atmosphere from
that affected facility any gases that contain PM in excess of:
    (1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel, and
    (2) For an affected facility that commenced construction or
reconstruction, 0.1 percent of the combustion concentration determined
according to the procedure in Sec.  60.48Da(o)(5) (99.9 percent
reduction) when combusting solid, liquid, or gaseous fuel, or
    (3) For an affected facility that commenced modification, 0.2
percent of the combustion concentration determined according to the
procedure in Sec.  60.48Da(o)(5) (99.8 percent reduction) when
combusting solid, liquid, or gaseous fuel.
    (e) Except as provided in paragraph (f) of this section, the owner
or operator of an affected facility that commenced construction,
reconstruction, or modification commenced after May 3, 2011, shall meet
the requirements specified in paragraphs (e)(1) and (2) of this
section.
    (1) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator shall cause to be discharged into the
atmosphere from that affected facility at all times except during
periods of startup and shutdown, any gases that contain PM in excess of
the applicable emissions limit specified in paragraphs (e)(1)(i) or
(ii) of this section.
    (i) For an affected facility which commenced construction or
reconstruction, any gases that contain PM in excess of either:
    (A) 11 ng/J (0.090 lb/MWh) gross energy output; or
    (B) 12 ng/J (0.097 lb/MWh) net energy output.
    (ii) For an affected facility which commenced modification, any
gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat input.
    (2) During periods of startup and shutdown, the owner or operator
shall meet the work practice standards specified in Table 3 to subpart
UUUUU of part 63.
    (f) An owner or operator of an affected facility that meets the
conditions in either paragraphs (f)(1) or (2) of this section is exempt
from the PM emissions limits in this section.
    (1) The affected facility combusts only gaseous or liquid fuels
(excluding residual oil) with potential SO2 emissions rates
of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-
combustion technology to reduce emissions of SO2 or PM.
    (2) The affected facility is operated under a PM commercial
demonstration permit issued by the Administrator according to the
provisions of Sec.  60.47Da.

0
14. Section 60.43Da is amended as follows:
0
a. The section heading is revised.
0
b. By revising paragraphs (a)(1) and (2).
0
c. By adding paragraphs (a)(3) and (4).
0
d. By removing and reserving paragraph (c).
0
e. By revising paragraph (f).
0
f. By revising paragraph (i).
0
g. By revising paragraph (k).
0
h. By adding paragraph (l).
0
i. By adding paragraph (m).

Sec.  60.43Da  Standards for sulfur dioxide (SO2).

    (a) * * *
    (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction);
    (2) 30 percent of the potential combustion concentration (70
percent

reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat
input;
    (3) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (4) 65 ng/J (0.15 lb/MMBtu) heat input.
* * * * *
    (f) The SO2 standards under this section do not apply to
an owner or operator of an affected facility that is operated under an
SO2 commercial demonstration permit issued by the
Administrator in accordance with the provisions of Sec.  60.47Da.
* * * * *
    (i) Except as provided in paragraphs (j) and (k) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility for which
construction, reconstruction, or modification commenced after February
28, 2005, but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility, any gases that contain
SO2 in excess of the applicable emissions limit specified in
paragraphs (i)(1) through (3) of this section.
    (1) For an affected facility which commenced construction, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 5 percent of the potential combustion concentration (95
percent reduction).
    (2) For an affected facility which commenced reconstruction, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 5 percent of the potential combustion concentration (95
percent reduction).
    (3) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 10 percent of the potential combustion concentration (90
percent reduction).
* * * * *
    (k) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date