Tracking System''), and ``continuous emission monitoring system.''
    One example of a definition in the final rules that is the same as
in the proposed rule, but that clarifies the definition used in prior
trading programs is the definition of ``fossil fuel.'' In the final
rule, the term ``fossil fuel'' is defined in general as including
natural gas, petroleum, coal, or any form of fuel derived from such
material, regardless of the purpose for which such material is derived.
For example, with regard to consumer products that are made of
materials derived from natural gas, petroleum, or coal, are used by
consumers, and then are used as fuel, these materials in the consumer
products qualify as fossil fuel. The definition in the final rules also
includes language establishing a narrower meaning of ``fossil fuel''
that is not generally applicable, but rather is applicable only for
purposes of applying the limitation on fossil-fuel use under the solid
waste incineration unit exemption (which is discussed elsewhere in this
preamble). This latter portion of the ``fossil fuel'' definition makes
explicit an interpretation that EPA adopted in CAIR that--solely for
purposes of applying the fossil-fuel use limitation in that exemption--
the term ``fossil fuel'' is limited to natural gas, petroleum, coal, or
any form of fuel derived from such material ``for the purpose of
creating useful heat.'' For example, applying this narrower meaning,
consumer products made from natural gas, petroleum, or coal are not
fossil fuel, for purposes of determining qualification under the
fossil-fuel use limitation, because the products (e.g., tires) were
derived from natural gas, petroleum, or coal in order to meet certain
consumer needs (e.g., to meet transportation needs), not in order to
create fuel (i.e., material that would be combusted to produce useful
heat).
    As noted above, some of definitions in the final rules clarify
definitions in the proposed rules. The definitions of ``allowable
NOX emission rate'' and ``allowable SO2 emission
rate'' are clarified by explaining that such a rate is the most
stringent state or federal emission rate limitation, expressed in lb/
MWhr or, if originally expressed in lb/mmBtu, converted to lb/MWhr by
multiplying it by the unit's heat rate in mmBtu/MWhr. This
clarification ensures consistency from unit to unit in determining a
unit's allowable rate.
    By further example, while the proposed rules used the same
definition of ``commence commercial operation'' as in prior EPA-
administered trading programs, the final rules clarify the definition.
Under the definition in the proposed rules, a unit that is physically
changed is treated as the same unit. However, the proposed rules were
unclear about the treatment of a unit that is replaced and whether
moving a unit to a different location or source constitutes a physical
change. The definition of ``commence commercial operation'' in the
final rules clarifies that a unit that is physically changed (which
includes a unit that is replaced) continues to be treated, for purposes
of this final rule, as the same unit with the same commence-commercial-
operation date. The definition also clarifies that moving a unit to a
different location or source is treated the same as a physical change,
and so the unit continues to be treated as the same unit. The
definition also clarifies that a unit (the replaced unit) that is
replaced, whether at the same source or a different source, is treated
as the same unit, while the unit (the replacement unit) that replaces
the unit is treated as a separate unit with a new commence-commercial-
operation date. (The definition of ``commence operation'' is removed in
the final rules because they do not use this term.)
    By further example, while the proposed rules used the same
definition of ``unit'' as in prior EPA-administered trading programs,
the final rules clarify the definition. The ``unit'' definition is
clarified by expanding it to incorporate explicitly the concepts--set
forth in the definition in the final rules of ``commence commercial
operation'' and thus already applicable to all units--that a unit that
is physically changed, moved to a different location or source, or
replaced at the same or a different source continues to be treated as
the same unit and that a replacement unit at the same source is treated
as a separate unit. EPA believes that it is preferable to provide a
comprehensive definition of ``unit'' in one place because the term is
used so frequently in the final rules.
    By further example, the definition of ``nameplate capacity'' is
clarified in the final rules by explaining that it is expressed in MWe
rounded to the nearest tenth. This is the same rounding convention that
is used in the reporting of nameplate capacity to the Energy
Information Administration.
    As noted above, some of the definitions in the final rules are
similar to those in the proposed rules but have some substantive
differences. For example, in the proposed rules, the definitions of
``cogeneration unit'' and ``fossil-fuel-fired'' are similar to those in
prior trading programs but with changes to minimize the need for data
concerning individual units or combustion devices for periods before
1990. In order to qualify as fossil-fuel-fired, a unit would have to
combust any amount of fossil fuel in 1990 or thereafter. In order to
qualify as a cogeneration unit, a unit would have to meet certain
efficiency and operating standards during the later of: the 12-month
period starting when the unit begins producing electricity, or 1990.
For a topping-cycle unit, useful power plus one-half of useful thermal
energy output of the unit must equal no less than a certain percentage
of the total energy input and useful thermal energy must be no less
than a certain percentage of total energy output, and, for a bottoming-
cycle unit, useful power must be no less than a certain percentage of
total energy input. EPA proposed to limit to 1990 or later the
historical period for which information on fuel consumption and on
cogeneration unit efficiency and operations would be required to apply
the ``fossil-fuel-fired'' and ``cogeneration unit'' definitions. This
limitation was proposed because EPA was concerned that some owners and
operators could have difficulty obtaining pre-1990 information about
older units, particularly for units whose ownership has changed over
time.
    While EPA proposed to use 1990 as the earliest year for which
information

would be required under these definitions, EPA requested comment on
whether a more recent year should be used. As discussed elsewhere in
this preamble, the final rules use 2005 (about 5 years before this
rule's promulgation), rather than 1990, as the reference year. Further,
because the language describing the historical time period used
(including the reference year), appeared in the proposal both in the
``cogeneration unit'' definition and the provisions concerning
cogeneration units in the applicability provisions, the final rules
removed any language about the historical time period from the
``cogeneration unit'' definition and revised the language in the
applicability provisions to use the 2005 reference year for the
requirements for meeting the exemption for cogeneration units from the
Transport Rule trading programs. Further, consistent with this use of
2005 as the reference year, the ``fossil-fuel-fired'' definition in the
final rule specifically references 2005, rather than 1990, and as
discussed elsewhere in this preamble, the final rules also use January
1, 2005 (rather than November 15, 1990) as the reference date
throughout the applicability provisions.
    With this change in the reference date for the requirement to meet
the operating and efficiency standards under the ``cogeneration unit''
definition, a unit would have to meet these standards throughout the
later of 2005 or the 12-month period starting when the unit begins
producing electricity and continuing thereafter. EPA requested comment
on whether these standards should be applied to a calendar year when
the unit involved did not combust any fuel, i.e., did not operate at
all. As discussed elsewhere in this preamble, the final rules expressly
provide that the operating and efficiency standards do not have to be
met for a calendar year throughout which a unit did not operate at all.
    In addition, under the proposed rules, if a group of cogeneration
units operating as an integrated cogeneration system met the efficiency
standards, a topping-cycle unit in that system would be deemed to meet
those standards. EPA requested comment on whether this provision should
also apply to a bottoming-cycle unit. As discussed elsewhere in this
preamble, this provision in the final rules is not limited to topping-
cycle units.
    By further example of definitions in the final rules that have
substantive differences from the definitions in the proposed rules, the
proposed definitions of ``TR NOX Annual allowance,'' ``TR
NOX Ozone Season allowance,'' ``TR SO2 Group 1
allowance,'' ``TR SO2 Group 1 allowance,'' ``TR
NOX Annual Trading Program,'' ``TR NOX Ozone
Season Trading Program,'' ``TR SO2 Group 1 Trading
Program,'' and ``TR SO2 Group 1 Trading Program'' are
changed in the final rules. Language is added to the definitions in
order to reference comparable allowances and trading programs
established through SIP revisions submitted by states and approved by
the Administrator. As discussed elsewhere in this preamble, the final
Transport Rule provides that, if a state submits SIP revisions meeting
certain specified requirements, the state or permitting authority
(rather than the Administrator) will allocate allowances, and the
covered sources in the state will participate--along with covered
sources in states remaining subject to the Transport Rule FIPs--in an
integrated, region-wide air quality-assured trading program under which
both any allowance allocated by the Administrator and any allowance
allocated by the state or permitting authority will each authorize one
ton of emissions of the relevant pollutant and will be usable by any
source for compliance with the requirement to hold allowances covering
emissions.
    As noted above, the final rules include some definitions that were
not used in prior EPA-administered trading programs and that reflect
unique provisions of the Transport Rule trading programs. For example,
the terms, ``assurance account,'' ``TR NOX Annual unit,''
``TR NOX Ozone Season unit,'' ``TR SO2 Group 1
unit,'' ``TR SO2 Group 2 unit,'' ``common designated
representative,'' ``common designated representative's assurance
level,'' and ``common designated representative's share'' are used and
defined in the final rule.
    While the proposed rules included definitions for the terms,
``owner's assurance level'' and ``owner's share,'' the final rules
replace these terms and instead define the terms, ``common designated
representative,'' ``common designated representative's assurance
level,'' and ``common designated representative's share.'' This is
because, as discussed elsewhere in this preamble, the final rules
include assurance provisions similar to those in the proposed rules but
that are implemented based on groups of units having a common
designated representative, instead of being implemented on an owner-by-
owner basis. The definition of ``common designated representative'' in
the final rules reflects that the determination of what groups of units
and sources in a State have a common designated representative is made
based on the identity of units' and sources' designated representatives
as of April 1 of the year after the year of the control period when a
state triggers the assurance provisions. EPA believes that the use of
this reference date will give owners and operators greater flexibility
to select common designated representatives after information about
total state control period emissions is available and after the
allowance transfer deadline when owners and operators may prefer to
have a designated representative for their specific source (rather than
a common designated representative for a larger group) who is focused
on ensuring that sufficient allowances are held in or transferred to
the source's account to cover the sources' emissions. EPA notes that
the definition of ``common designated representative's share'' is
simpler than the definition of ``owner's share'' because implementing
the assurance provisions at the designated representative level means
it is no longer necessary to address, in the definition, owner- and
unit-level issues that may arise when a unit has multiple owners or
where two or more units emit through the same stack.
    Finally, some definitions are added to the final rules that are not
in the proposed rules. For example, because the term, ``business day,''
was used, but not defined, in the proposed rule, its meaning was
unclear. Specifically, it was unclear whether a day that was uniquely a
state holiday, and not a federal holiday, was a business day for
purposes of the federally administered Transport Rule trading programs,
e.g., whether the allowance transfer deadline applicable to all sources
in all states in a Transport Rule trading program could fall on a day
that was a unique state holiday in one or a few states or whether the
allowance transfer deadline would be advanced to the next business day
for all sources in all states or perhaps only for sources in the state
with the state holiday. EPA believes that, for a federally administered
trading program covering sources in multiple states, the deadlines
should be clear and uniform for all sources, regardless of the state in
which the sources are located, and should not be affected by unique
state holidays of which owners and operators of sources in other states
may not even be aware. Consequently, the ``business day'' definition is
added in the final rules and means a day that does not fall on a
weekend or a federal holiday.
    By further example, a definition for ``natural gas'' was added in
the final rules. That definition, as well as the definition for
``coal,'' incorporate the

corresponding definitions in Part 72 of the Acid Rain Program
regulations. The Part 72 definitions are incorporated because they are
also used in the Part 75 monitoring, reporting, and recordkeeping
provisions, which provisions are already incorporated in the final
Transport Rule Trading Program rules. (ii) Sec. Sec.  97.404 and
97.405, 97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705--
Applicability and Retired Units
    The applicability provisions in the final rules are, except as
discussed herein, essentially the same as in the proposed rules and for
each of the Transport Rule trading programs. Of course, for each
trading program, the definition of ``State'' reflects differences in
the specific states whose electric generating units are covered by the
respective trading program.
    Under the general applicability provisions of the proposed rules,
the Transport Rule trading programs would cover fossil-fuel-fired
boilers and combustion turbines serving--at any time starting November
15, 1990 or later--an electrical generator with a nameplate capacity
exceeding 25 MWe and producing power for sale, with the exception of
certain cogeneration units and solid waste incineration units. As
discussed elsewhere in this preamble, the general applicability
provisions in the final rules reference January 1, 2005 (about 5 years
before this rule's promulgation), rather than November 15, 1990.
    Cogeneration unit exemption. Under the final rules (as well as the
proposed rules) certain cogeneration units or solid waste incinerators
otherwise covered by the general category of covered units are exempt
from the FIP requirements. In particular, the final rules include an
exemption for a unit that qualifies as a cogeneration unit throughout
the later of 2005 or the first 12 months during which the unit first
produces electricity and continues to qualify throughout each calendar
year ending after the later of 2005 or such 12-month period and that
meets the limitation on electricity sales to the grid. In order to
qualify as a cogeneration unit (i.e., meet the definition of
``cogeneration unit'') in the final rules, a unit (i.e., a boiler or
combustion turbine) must operate as part of a ``cogeneration system,''
which is defined as an integrated group of equipment at a source
(including a boiler or combustion turbine, and a steam turbine
generator) designed to produce useful thermal energy for industrial,
commercial, heating, or cooling purposes and electricity through the
sequential use of energy. In addition, in order to qualify, a unit must
be a topping-cycle unit or a bottoming cycle unit because units that
produce useful thermal energy and useful power through sequential use
of energy either produce useful power first (i.e., are topping-cycle
units) or produce thermal energy first (i.e., are bottom-cycle units).
    Further, in order to qualify as a cogeneration unit, a unit also
must meet, on a 12-month or annual basis, the above described
efficiency and operating standards. As discussed elsewhere in this
preamble, EPA clarifies that the electricity sales limitation under the
exemption is applied in the same way whether a unit serves only one
generator or serves more than one generator. In both cases, the total
amount of electricity produced annually by a unit and sold to the grid
cannot exceed the greater of one-third of the unit's potential electric
output capacity or 219,000 MWhr.
    The final rules also clarify when a unit that meets the
requirements for the cogeneration unit exemption and subsequently fails
to meet all these requirements loses the exemption and becomes a
covered unit. Such a unit loses the exemption starting the earlier of
January 1 (or May 1 for the NOX ozone season trading
program) after the first year during which the unit no longer meets the
``cogeneration unit'' definition or January 1 (or May 1) of the first
year during which the unit no longer meets the electricity sales
limitation.
    Solid waste incineration unit exemption. The final rules also
include an exemption for a unit that qualifies as a solid waste
incineration unit during the later of 2005 or the first 12 months
during which the unit first produces electricity, that continues to
qualify throughout each calendar year ending after the later of 2005 or
such 12-month period, and that meets the limitation on fossil-fuel use.
In contrast, the exemption for solid waste incineration units in the
proposed rules distinguished between units commencing operation before
January 1, 1985 and those commencing operation on or after that date
and established somewhat different criteria for these two categories of
units. As discussed elsewhere in this preamble, the final rules remove
the distinction based on whether a solid waste incineration unit
commences operation before January 1, 1985 or on or after January 1,
1985. In order to be exempt, the unit must qualify as a solid waste
incineration units during the later of 2005 or the first 12 months
during which the unit first produces electricity, must continue to
qualify throughout each calendar year ending after the later of 2005 or
such 12-month period, and must meet the limitation on fossil-fuel use
on a three-year average basis during the first 3 years of operation
starting no earlier than 2005 and every 3 years of operation
thereafter.
    Retired unit exemption. The final rule provisions exempting
permanently retired units from most of the requirements of the
Transport Rule trading programs are essentially the same as in the
proposed rules and for each of the Transport Rule trading programs. The
retired unit provisions exempt these units from the requirements for
emission monitoring, recordkeeping, and reporting and for holding
allowances, as of the allowance transfer deadline, sufficient to cover
their emissions. However, the permanently retired units in a state must
be included in determining whether owners and operators must surrender
allowances, and, if so, how many, to comply with the assurance
provisions (which are discussed elsewhere in this preamble) if the
state's total covered-unit emissions exceed the state assurance level.
    Specifically, a common designated representative must include these
units in determining whether his or her share of total emissions of
covered units in a state exceed his or her share (generally based on
the allowances allocated to the units that he or she represents) of the
state trading budget with the variability limit and thus whether the
owners and operators of the units that he or she represents have to
surrender allowances under the assurance provisions.
(iii) Sec. Sec.  97.406, 97.506, 97.606, and 97.706--Standard
Requirements
    The basic requirements applicable to owners and operators of units
and sources covered by the Transport Rule trading programs and
presented as standard requirements in the final rules are, except as
discussed herein, essentially the same as in proposed rules and for
each of the Transport Rule trading programs. These basic requirements
include: designated representative requirements; emissions monitoring,
reporting, and recordkeeping requirements; emissions requirements
comprising emissions limitations and assurance provisions; permit
requirements; additional recordkeeping and reporting requirements;
liability provisions; and provisions describing the effect of the
Transport Rule trading program requirements on other CAA provisions.
    In particular, the paragraphs addressing emissions requirements for
owners and operators describe these requirements in detail and
reference

other sections of the final rules that set forth the procedures for
determining compliance with the emissions limitations and assurance
provisions. The paragraphs in the final rules concerning compliance
with the emissions limitations clarify that owners and operators of a
source and each covered unit at the source must hold allowances at
least equaling the total control period emissions of all covered units
at the source. Further, the paragraphs in the final rules concerning
compliance with the assurance provisions differ from those in the
proposed rules in that, as discussed elsewhere in this preamble, the
final rules implement the assurance provisions based on groups of units
with a common designated representative, instead of being implemented
on an owner-by-owner basis, as proposed. Under the final rules, the
assurance provisions are triggered when total control period emissions
by covered units in a state (starting in 2012) exceed the state trading
budget plus variability limit. If the assurance provisions are
triggered for a state for a control period in a given year, owners' and
operators' responsibility for the resulting penalty (i.e., the
surrender of allowances for deduction through the transfer of such
allowances to the assurance account created by the Administrator for
such owners and operators) is determined on a common designated
representative basis.
    For purposes of implementing the assurance provisions, covered
units in a state are in effect grouped by common designated
representative (which is defined as an individual (i.e., a natural
person) who is the designated representative, as distinguished from the
alternate designated representative, for a group of one or more units
and sources as of April 1 after the control period for which the state
exceeds the state assurance level). The control period emissions of all
covered units with a common designated representative are compared with
the allowance allocations of such units plus their share of the state
variability limit. The owners and operators of the units and sources in
each group that has emissions in excess of allocations plus share of
variability are subject to the assurance provisions penalty. The owners
and operators of the units and sources in each group must transfer to
the assurance account created for such owners and operators a total
amount of allowances equal to two times such owners' and operators'
proportionate share of the state's excess of covered-unit emissions
over the state trading budget plus variability.
    The group's proportionate share is the percentage resulting from
division of the amount of the group's excess of emissions over
allocations plus share of variability by the sum of these excess
amounts for all groups of units with a common designated representative
in the state. The final rule makes it clear that this percentage is not
rounded to the nearest whole number, but rather that the calculated
amount of allowances resulting from application of this percentage is
rounded to the nearest whole number because, in the Transport Rule
trading programs, only whole (not fractional) allowances are used. If
instead this percentage were rounded before its application, each
group's share would be either 100 percent or 0 percent, which would be
contrary to the intent of the assurance provisions in both the final
rules and the proposed rules.
    The provisions addressing the assurance requirements in the final
rules reflect this common-designated-representative-based approach. For
example, as discussed elsewhere in this preamble, these provisions use
the terms, ``common designated representative's share'' and ``common
designated representative's assurance level,'' in lieu of the terms,
``owner's share'' and ``owner's assurance level,'' used in the proposed
rules. By further example, these final rule provisions refer to both
``common designated representatives'' and ``owners and operators,''
rather than simply ``owners.''
    The final rules also explain what vintage year (i.e., allocation
year) of allowances can be used in order to comply with the requirement
to cover emissions and with the requirements of the assurance
provisions. With regard to emissions during a control period in a given
year, only allowances allocated for that year or any prior year can be
used to cover such emissions. Further, only allowances of the following
vintage can be used to meet excess emissions penalties and assurance
penalties concerning emissions during a control period in a given year:
allowances allocated for that year, any year before that year, or the
year immediately after that year. This approach makes the vintage years
usable for excess emissions and assurance penalties consistent and
helps ensure that allowances will be available to meet these
obligations.
    The final rules also clarify the standard emission requirements by
explaining further what is meant by the provision that an allowance is
a limited authorization to emit. The final rules clarify that an
allowance provides authorization to emit during the control period in
one year and is limited in both its use and its duration. For example,
each Transport Rule trading program's final rules state that an
allowance provides an emission authorization that can only be used in
accordance with the requirements of the respective trading program,
such as the requirements specifying what allowances are available for
use, and how such allowances must be held or transferred, in order to
cover emissions or meet the assurance provisions. By further example,
under the final rules, an allowance continues to provide an
authorization to emit one ton of the relevant pollutant until the
allowance is deducted, e.g., in order to be used for compliance with
the requirement to cover emissions or the requirements of the assurance
provisions. Moreover, under the final rules, the Administrator has the
express authority to terminate or limit the authorization to emit, and
thereby change the use and duration of the authorization, described in
the final rules, to the extent he or she determines to be necessary or
appropriate to implement any provision of the CAA.
    The remaining paragraphs in the standard requirements section
address permitting, recordkeeping and reporting, liability provisions,
and the effect on other CAA provisions. For example, the paragraphs
concerning permitting requirements are limited to stating that no title
V permit revisions are necessary to account for allowance allocation,
holding, deduction, or transfer and that the minor permit modification
procedures can be used to add or change general descriptions in the
title V permits of the monitoring and reporting approach used by the
units covered by each title V permit. These provisions remain
essentially the same in the final rules as in the proposed rules.
(iv) Sec. Sec.  96.407, 97.507, 97.607, and 97.707--Computation of Time
    These sections address how to determine the deadlines referenced in
the Transport Rule trading program rules and are, except as discussed
herein, essentially the same as in the proposed rules and for each of
the Transport Rule trading programs. The final rules revise the
proposed rule provisions concerning the treatment of the final date in
any time period in order to make the provision consistent with the
approach discussed above with regard to the new definition of
``business day.'' The revised provision states that, if the final date
is not a

``business day'', then the time period is extended to the next
``business day.''
(v) Sec. Sec.  97.408, 97.508, 97.608, 97.708 and Part 78--
Administrative Appeal Procedures
    Under the final Transport Rule, final decisions of the
Administrator under the Transport Rule trading programs are appealable
to EPA's Environmental Appeals Board under the regulations set forth in
Part 78 (40 CFR part 78), which are revised by the final Transport Rule
to accommodate such appeals. The provisions in the final Transport Rule
concerning appeals are, except as discussed herein, essentially the
same as in the proposed Transport Rule. The proposed Transport Rule
would add a provision in Part 78 explaining who is an ``interested
person'' with regard to a decision, i.e., a person who submitted
comments, testimony, or objections as part of the process of making the
decision or a person who submitted his or her name to the Administrator
to be placed to an interested persons list. The final Transport Rule
includes that provision, but with additional language that clarifies
the process for submitting a name to be placed on such a list.
(2) Allowance Allocations
    Sections 97.410 through 97.412, 97.510 through 97.512, 97.610
through 97.612, and 97.710 through 97.712 set forth: certain
information related to allowance allocation and for implementation of
the assurance provisions; the timing for allocation of allowances to
existing and new units; and the procedures for new unit allocations. In
particular, these sections include tables providing, for each state
covered by the particular Transport Rule trading program and for each
year, the state trading budget (without the variability limit), new
unit set-aside, Indian country new unit set-aside (where applicable),
and variability limit. These provisions in the final rules differ in
several ways, from the proposed rules and are essentially the same for
each of the Transport Rule trading programs.
    With regard to the tables in the final rules for the state trading
budgets (without the variability limits), new unit set-asides, and
variability limits, the identity of the specific states involved and
the values for each state differ from the tables in the proposed rules.
The final rule values reflect the determinations and modeling
underlying the final rules and discussed elsewhere in this preamble.
Further, as discussed elsewhere in this preamble, the variability
limits are only those based on one-year variability and not those
proposed to be based on three-year variability, and Indian country set-
asides are shown for states with Indian country within their borders.
    With regard to existing unit allocations, the final rules provide
that these allocations will be set forth in a notice of data
availability to be issued by the Administrator. In contrast, the
proposed rules stated that existing unit allocations would be set forth
in an appendix to the rules for each Transport Rule trading program.
EPA believes that including these allocations in a notice of data
availability referencing the EPA Web site (rather than publishing them
in tables requiring a large number of pages in the Federal Register for
each Transport Rule trading program) is a more efficient method of
making these allocations public, particularly since these allocations
may be changed for 2013 and thereafter by states through SIP revisions.
In addition, under the final rules the allocations for an existing unit
can change if the unit does not operate (i.e., has no heat input) for 2
consecutive years starting in 2012. In that case, the unit continues to
receive its existing unit allocation for those years plus only 2 more
years. As explained elsewhere in this preamble, this is a modification
of the proposed rules, under which a unit that did not operate for 3
consecutive years would continue to receive its existing unit
allocation for those years plus 3 more years.
    Under the final rule provisions for new units, the Administrator
allocates allowances from the new unit set-aside for the state where
the respective unit is located and for each year when the unit first
becomes eligible for an allocation and each year thereafter. The units
eligible for new unit set-aside allocations include units commencing
commercial operation on or after January 1, 2010, as well as several
other categories of units, such as, for example, existing units that
were not initially but then become covered units, existing units whose
allocations are lost due to lack of unit operation and that
subsequently begin operating again, and units that lost their
allocations because they changed location from one state to another.
The approach in the final rules differs from the proposed rules, which
required that owners and operators initially request allowances from
the new unit set-aside when the unit first became eligible for an
allocation. As discussed elsewhere in this preamble, under the final
rules, EPA identifies which units become eligible and when they become
eligible, based on information provided in other submissions (e.g.,
certificates of representation, monitoring system certifications, and
quarterly emissions reports) that such units must make to EPA, and the
requirement that owners and operators submit requests for new unit set-
aside allocations is removed in the final rules.
    The final rules also provide for two rounds of allocations from the
new unit set-aside, in contrast with the proposed rules that provided
for only one round. In the first round in the final rules (as in the
single round in the proposed rules), a unit's new unit set-aside
allocation initially equals that unit's emissions--as determined in
accordance with Sec. Sec.  97.430-97.435, 97.530-97.535, 97.630-97.635,
and 97.730-97.735 of the final rules and Part 75 (40 CFR part 75)--for
the control period (annual or ozone season, depending on the Transport
Rule trading program involved) in the preceding year. If the new unit
set-aside lacks sufficient allowances to provide this initial
allocation for all of the new units, then each new unit is allocated
its proportionate share (based on its initial allocation amount) of the
allowances in the new unit set-aside. The Administrator issues a notice
of data availability informing the public of the specific new unit
allocations and provides an opportunity for submission of objections on
the grounds that the allocations are not consistent with the
requirements of the relevant final rule provisions. A second notice of
data availability is subsequently issued in order to make any necessary
corrections in the specific new unit allocations. As discussed
elsewhere in this preamble, the final rules establish a somewhat
different schedule for issuance of these notices of data availability
than the proposed rules. In particular, a single set of dates (i.e.,
for the first notice, June 1 of the year for which the new unit
allocations are described in the notice and, for the second notice,
August 1 of that year) is established for all of the Transport Rule
trading programs. For the reasons discussed elsewhere in this preamble,
the final rules provide for a second round of allocations to the extent
that any allowances remain in the new unit set-aside after the
allocations are made to new units in the first round. (In the proposed
rules, remaining allowances were immediately allocated to existing
units.) The units eligible for allocations in the second round are new
units that commenced commercial operation during the control period for
which allocations are being made and during the prior control period.
The second round allocation for each such unit initially equals the
positive difference (if any) between the unit's

first round allocation (if any) and the unit's emissions during the
control period for which allocations are being made. If the amount of
allowances remaining in the new unit set-aside after the first round is
insufficient to provide this initial allocation for all of the second
round new units, then each such new unit is allocated its proportionate
share of the allowances remaining in the new unit set-aside. The
Administrator uses notices of data availability (which are issued by
December 15 (for the annual trading programs) and September 15 (for the
ozone season trading program) of the control period involved and
February 15 (for the annual trading programs) and November 15 (for the
ozone season trading program) before the allowance transfer deadline
for the control period involved, in a manner analogous to the use of
such notices in the first round, to inform the public about the
identification of the new units in the second round allocations and
obtain and consider any objections. The February 15 and November 15
notices also inform the public about the amounts of the second round
allocations. If, after both rounds of allocations, any allowances
remain in the new unit set-aside, those allowances are allocated to
existing units in proportion to such units' allocations.
    The final rules also establish a separate Indian country new unit
set-aside in each state where Indian country is located (i.e., in
Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi,
Nebraska, New York, North Carolina, South Carolina, Texas, and
Wisconsin). As discussed elsewhere in this preamble, the Administrator
operates the Indian country new unit set-aside in essentially the same
manner as state new unit set-aside, except that unallocated allowances
remaining in the Indian country new unit set-aside after the two rounds
of new unit set-aside allocations are first placed in the new unit set-
aside in the state where the Indian country involved is located and
then, if still unallocated, are allocated to existing units in the
state. As with the state new unit set-aside, EPA will identify the new
units qualifying for the Indian country new unit set-aside, calculate
the allocations, and issue notices of data availability using the same
schedules as notices for the state new unit set-aside.
    Under the final rules (like under the proposed rules), if a unit in
certain specified categories is allocated allowances that should not
have received them, the Administrator applies procedures under which
the allocation is not recorded or the amount of the recorded
allocations is deducted as an incorrect allocation, with one exception.
The exception is where the determination of compliance with the
emissions limitation (i.e., requirement to hold allowances covering
emissions, as distinguished from the assurance provisions) for the
source that includes the unit has already been completed, in which case
no action is taken to account for the erroneous allocation for the
control period involved.
    While this procedure concerning recordation or deduction of
allocations is the same as under the proposed rules, the final rules
change the description of the circumstances under which this procedure
concerning recordation or deduction of allocations is applied. Under
both the final rules and the proposed rules, this procedure is applied
to a unit (whether an existing unit or a new unit) that receives an
allocation but is not actually a covered unit. However, under the final
rules, another category of units--i.e., any existing unit that is not
located--as of January 1 of the control period for which the allocation
is received--in the state from whose trading budget the allocation was
made is also subject to this procedure. Although relatively few units
are moved from one state to another, EPA believes that it is important
to address what happens to such units' allocations, both because each
state has a limited trading budget out of which all allocations for a
year to existing and new units in that state must be made and because,
under the assurance provisions, determinations are made about owners'
and operators' surrender of allowances based on, among other things,
the allocations for units in a specific state. Because, under the final
rules, a unit that is moved from one state to another may lose its
existing unit allocation in the first state under the above-described
procedure, the final rules also makes such a unit eligible for
allocations from the new-unit set-aside of the second state.
    Finally, the final rules remove, as no longer necessary, one
category of units that the proposed rules included as subject to this
procedure. The proposed rules, treated, as existing units, some units
that had not yet operated but were projected to operate by January 1,
2012, and so the proposed rules made these units subject to the
procedure for not recording or for deducting allocations if they
actually were not required to certify their monitoring systems and hold
allowances covering emissions starting January 1, 2012. The final rule
does not treat projected units as existing units and so this category
of units no longer needs to be made subject to this procedure.
(3) Designated Representatives and Alternate Designated Representatives
    Sections 97.413 through 97.418, 97.513 through 97.518, 97.613
through 97.618, and 97.713 through 97.718 establish the procedures for
certifying and authorizing the designated representative, and alternate
designated representative, of the owners and operators of a source and
the units at the source, and for changing the designated representative
and alternate designated representative. These sections also describe
the designated representative's and alternate designated
representative's responsibilities and the process through which he or
she can delegate to an agent the authority to make electronic
submissions to the Administrator. Except as discussed herein, the
provisions in the final rules are essentially the same as in the
proposed rules and for each of the Transport Rule trading programs.
    The designated representative is the individual (i.e., the natural
person) authorized to represent the owners and operators of each
covered source and covered unit at the source in matters pertaining to
all Transport Rule trading programs to which the source and units were
subject. One alternate designated representative (also an individual)
can be selected to act on behalf of, and legally bind, the designated
representative and thus the owners and operators. Because the actions
of the designated representative and alternate legally bind the owners
and operators, the designated representative and alternate must submit
a certificate of representation certifying that each was selected by an
agreement binding on all such owners and operators and is authorized to
act on their behalf.
    In the final rules (like in the proposed rules), the certificate of
representation must contain: Specified identifying information for the
covered source (including location) and the covered units at the source
and for the designated representative and alternate; the name of every
owner and operator of the source and units; and certification language
and signatures of the designated representative and alternate. The
final rules require an additional piece of identifying information,
i.e., whether the unit is located in Indian country. This is necessary
in order for the Administrator to implement the above-described Indian
country new unit set-aside. All submissions (e.g., monitoring plans,
monitoring system certifications, and allowance transfers) under the
final rules for a covered

source or covered unit must be submitted, signed, and certified by the
designated representative or alternate, except that electronic
submission may be delegated.
    In order to change the designated representative or alternate, a
new certificate of representation must be received by the
Administrator. A new certificate of representation must also be
submitted to reflect changes in the owners and operators of the source
and units involved. The new certificate must be submitted within 30
days of such changes.
    The final rules make explicit an implied requirement of the
proposed rules, i.e., that, if a unit is added to a source or is moved
from one source to a second source, a certificate of representation
needs to be submitted to reflect the change. This requirement is
implicit in the proposed rules when a unit is added to a source because
the designated representative would not be authorized to make
submissions concerning the added unit unless that unit were included on
the certificate of representation. Similarly, where a unit is moved to
another source, new certificates of representation would need to be
submitted in order for the correct designated representative to be
authorized to make submissions concerning the moved unit. Moreover,
because compliance accounts in the Allowance Management System would
cover all units at a given source and would be based on the information
in the certificate of representation submitted by the designated
representative for the source, when a unit is moved from a source to a
second source, the designated representative of the second source would
need to submit a certificate of representation removing the moved unit
from the list of units.
    The final rules explicitly require that a new certificate of
representation be submitted to reflect changes (whether caused by the
addition or removal of units) in which units are located at a source.
In addition, the final rules impose a deadline on the submission
requirement of 30 days from the date of the change in the units. This
is analogous to the maximum time period between a change in a unit's
owner or operator and the deadline for submission of a new certificate
of representative reflecting to the change. Long before any actual move
of a unit to a new location, owners and operators will need to make
decisions about, and plan the implementation of, such a move.
Consequently, EPA believes that a 30-day deadline after any move for
reflecting the move in the certificate of representation is reasonable.
In the event the change involves the addition of a unit that operated
before being located at the source, the final Transport Rule also
requires that the designated representative provide in the certificate
of representation information on the entity from which the unit was
obtained, the date on which the unit was obtained, and the date on
which the unit became located at the source. In the event of a change
involving the removal of a unit, the designated representative must
provide in the certificate of representation information on the entity
that obtained the unit, the date on which that entity obtained the
unit, and the date on which the unit became no longer located at the
source. This information will enable the Administrator to determine
what actions are necessary to reflect the change in units located at
the sources involved. For example, if a covered unit is moved from one
source to second source, the Administrator will have the information
necessary to determine whether the unit's allocation should be changed
to reflect movement of the unit from one state to another.
(4) Allowance Management System
    Sections 97.420 through 97.428, 97.520 through 97.528, 97.620
through 97.628, and 97.720 through 97.728 establish the procedures and
requirements for using and operating the Allowance Management System
(which is the electronic data system through which the Administrator
handles allowance allocation, holding, transfer, and deduction), and
for determining compliance with the emissions limitations and assurance
provisions, in an efficient and transparent manner. The Allowance
Management System also provides the allowance markets with a record of
ownership of allowances, dates of allowance transfers, buyer and seller
information, and the serial numbers of allowances transferred. Except
as discussed herein, these sections of the final rules are essentially
the same as in the proposed rules and for each of the Transport Rule
trading programs.
(i) Sec. Sec.  97.420, 97.520, 97.620, and 97.720--Compliance,
Assurance, and General Accounts
    Under the final rules, the Allowance Management System contains
three types of accounts. One type comprises compliance accounts, one of
which the Administrator establishes for each covered source upon
receipt of the certificate of representation for the source. A
compliance account is the account in which all allowance allocations
must be recorded and in which any allowances used by the covered source
for compliance with the emission limitations must be held. The
designated representative and alternate for the source are also the
authorized account representative and alternate for the compliance
account.
    A second type comprises general accounts, which can be established
by any entity upon receipt by the Administrator of an application for a
general account. General accounts can be used by any person or group
for holding or trading allowances. To open a general account, a person
or group must submit an application for a general account, which is
similar in many ways to a certificate of representation. The provisions
for changing the authorized account representative and alternate, for
submitting a superseding application to take account of changes in the
persons having an ownership interest with respect to allowances, and
for delegating authority to make electronic submissions are analogous
to those applicable to comparable matters for designated
representatives and alternates.
    A third type comprises assurance accounts. The Administrator
establishes one assurance account for each group of units having a
common designated representative and located in a state where the
assurance provisions are triggered by total emissions exceeding the
state trading budget plus variability.
(ii) Sec. Sec.  97.421 Through 97.423, 97.521 Through 97.523, 97.621
Through 97.623, and 97.721 Through 97.723--Recordation of Allowance
Allocations and Transfers
    Under the final rules, by November 7, 2011, the Administrator must
record allowance allocations for existing units, as set forth in a
required notice of data availability, for the Transport Rule annual
NOX, ozone-season NOX, and SO2 trading
programs for 2012 and 2013, unless, as discussed elsewhere in this
preamble, a state notifies the Administrator that the state will submit
a SIP revision with existing-unit allocations for 2013 by May 1, 2012.
If the Administrator approves that SIP revision by October 1, 2012, the
Administrator will record the state-determined existing-unit
allocations for 2013, and, in the absence of such approval by that
date, the Administrator will record the EPA-determined existing-unit
allocations for 2013. By July 1, 2013, the Administrator must record
existing-unit allowance allocations (whether EPA- or state-determined)
for each Transport Rule trading program for 2014 and 2015. By July 1,
2014, the Administrator must

record existing-unit allowance allocations for each Transport Rule
trading program for 2016 and 2017. By July 1, 2015, the Administrator
must record existing-unit allowance allocations for each Transport Rule
trading program for 2018 and 2019. By July 1, 2016 and July 1 of each
year thereafter, the Administrator must record existing-unit allowance
allocations for each Transport Rule trading program for the control
period in the fourth year after the year of the applicable recordation
deadline. By August 1, 2012 and August 1 of each year thereafter, the
Administrator must record new-unit allowance allocations for each
Transport Rule trading program for that year. These recordation
deadlines differ from those in the proposed rules for two reasons.
First, as discussed elsewhere in this preamble, EPA is adopting
provisions that allow states to submit, and EPA to approve, SIP
revisions (abbreviated or full SIPs) under which the state, rather than
the Administrator, determines the distribution of allowances under one
or more of the Transport Rule trading programs applicable in the state.
In selecting allocation recordation deadlines, EPA took into account
and balanced certain countervailing factors. On one hand, EPA
considered the need to provide a reasonable time for a state to
develop, propose, and finalize, and for EPA to review and propose and
finalize approval of, the SIP revision and the desirability of
providing a reasonable opportunity for state distributions to become
effective for a year relatively soon after the 2012 commencement of the
Transport Rule trading programs. EPA's experience with prior trading
programs has shown that the process for development and submission of
SIP revisions by states and approval by EPA in many cases is about 18
months and in some cases even longer. On the other hand, EPA considered
the desirability of owners and operators having allocations in their
compliance accounts a reasonable time before the year for which the
allocations are made (i.e., the vintage year). Having the allocations
recorded, to the extent possible, before the vintage year facilitates
compliance decisions and use of the allowance market in implementing
such decisions. EPA believes that optimally allocations would be
recorded at least 3 years in advance of the vintage year.
    In balancing these countervailing factors, EPA is adopting an
allocation recordation schedule that provides initially for recordation
ranging from 6 months to 18 months before the beginning of the control
period in the first 2 years (i.e., 2012 and 2013) for which allocations
are made and that, as allocations for control periods in subsequent
years are recorded, gradually increases the amount of time between
recordation and the beginning of the year of the control period
involved until allocations are recorded about three and one-half years
in advance. With regard to the need to facilitate states' distribution
of allowances, this approach gives states multiple opportunities to
develop, submit, and obtain EPA approval for SIPs under which the
states (rather than EPA) will distribute allowances under the Transport
Rule trading programs for control periods relatively early in the
programs. Because of time (which has in the past ranged from about 6
months to about 2 years) it may take for a state to develop and submit
such a SIP and because of the time (which has in the past been at least
6 months) it will likely take EPA to review and approve such a SIP, EPA
believes that 2013 is the first year for which a state can determine
allowance distributions and have them recorded some minimal time before
the control period involved. With regard to the need to record
allowances in advance, this approach achieves recordation at least 6
months in advance and eventually achieves recordation by what EPA
believes is an optimal amount of time (greater than 3 years) before the
control period for which recorded allowances are issued.
    As discussed elsewhere in this preamble, the approach to allowance
recordation in the final rules results in following schedule for
submission of abbreviated or full SIPs under the final Transport Rule.
SIP revisions with existing-unit allocations for 2013 control periods
must be submitted to the Administrator by April 1, 2012. Complete
abbreviated and full SIPs must be submitted to the Administrator by:
December 1, 2012 in order to govern allowance allocation and auction
for control periods in 2014 and 2015; December 1, 2013 in order to
govern control periods in 2016 and 2017; December 1, 2014 in order to
govern allowance allocation and auction for control periods in 2018 and
2019; and December 1, 2015 and by January 1 of any year thereafter in
order to govern allowance allocation and auction for control periods in
the fifth year after the year of such submission deadline.
    The second reason for the differences in the recordation deadlines
in the final rules, as compared to the proposed rules, is that, in
order to simplify the recordation schedule for owners and operators and
EPA, EPA set uniform recordation deadlines for all of the Transport
Rule trading programs. EPA believes that these deadlines provide the
Agency sufficient time, after receipt of any information necessary to
determine allocations (e.g., for new unit set-aside allocations, the
emission data from the control period in the prior year), to complete
the recordation of allocations and, as discussed above, makes the
allocations available to owners and operators before the year for which
the allocations are made. EPA notes that these are deadlines and that
the Administrator has the discretion, where feasible and appropriate,
to record allocations before such deadlines.
    Under the final rules (as under the proposed rules), the process
for transferring allowances from one account to another is quite
simple. A transfer is submitted providing, in a format prescribed by
the Administrator, the account numbers of the accounts involved, the
serial numbers of the allowances involved, and the name and signature
of the transferring authorized account representative or alternate. If
the transfer form containing all the required information is submitted
to the Administrator and, when the Administrator attempts to record the
transfer, the transferor account includes the allowances identified in
the form, the Administrator records the transfer by moving the
allowances from the transferor account to the transferee account within
5 business days of the receipt of the transfer form.
(iii) Sec. Sec.  97.424, 97.524, 97.624, and 97.724--Compliance With
Emissions Limitations
    Under the final rules (as under the proposed rules), once a control
period has ended (i.e., December 31 for the Transport Rule
NOX and SO2 annual trading programs and September
30 for the ozone-season NOX trading program), covered
sources have a window of opportunity--until the allowance transfer
deadline of midnight on March 1 or December 1 following the control
period for the annual and ozone season trading programs respectively--
to evaluate their reported emissions and obtain any allowances that
they need to cover their emissions during that control period. Each
allowance issued in each Transport Rule trading program authorizes
emission of one ton of the pollutant involved, and so is usable for
compliance in that trading program, for a control period in the year
for which the allowance was allocated or a later year. Consequently,
each source needs--as of the allowance transfer deadline--to have in
its compliance account, or

properly submit a transfer that moves into its compliance account,
enough allowances usable for compliance to authorize the source's total
emissions for the control period.
    If a source fails to hold sufficient allowances for compliance to
cover the emissions, then the owners and operators must provide, for
deduction by the Administrator, two allowances allocated for the
control period, in the year of when the emissions occurred, any prior
year, or the year immediately after the year of the emissions, for
every allowance that the owners and operators failed to hold as
required to cover emissions. In addition, the owners and operators are
subject to discretionary civil penalties for each violation.
(iv) Sec. Sec.  97.425, 97.525, 97.625, and 97.725--Compliance With
Assurance Provisions
    Under the final rules (as under the proposed rules), the assurance
provisions ensure that each state will eliminate its significant
contribution to nonattainment and interference with maintenance that
EPA identifies in this action. A requirement that owners and operators
surrender allowances under the assurance provisions is triggered only
for certain owners and operators of sources and units in a state where
the total state covered-unit emissions for a control period exceed the
applicable state trading budget with the variability limit. Moreover,
the surrender requirement is implemented based on groups of sources and
units with a common designated representative. For each group of
sources and units with a common designated representative, the owners
and operators of such sources and units must surrender allowances only
if the units' emissions (referred to as the common designated
representative's share of emissions) during the control period involved
exceed the units' allocations plus share of the state variability limit
(referred to as the common designated representative's share of the
state trading budget with variability).
    As discussed elsewhere in this preamble, EPA decided to implement
the assurance provisions on a common designated representative basis,
rather than on an owner basis. The final rules implement in a series of
steps the process of determining which states have total covered-unit
emissions sufficient to trigger the allowance surrender requirement for
a given control period and determining, using the approach based on
common designated representatives, which owners and operators are
subject to the allowance surrender and whether those owners and
operators are in compliance. This common-designated-representative-
based process is more streamlined than the owner-based process in the
proposed rules.
    First, the Administrator performs the calculations necessary to
determine whether any state has total covered-unit emissions for a
control period greater than the state trading budget with the 1-year
variability limit. As discussed elsewhere in this preamble, EPA decided
not to use a 3-year variability limit because, among other things, such
a limit seems unnecessary to ensuring elimination of significant
contribution to nonattainment and interference with maintenance and
would make compliance planning extremely difficult for owners and
operators. By June 1, 2013 and June 1 of each year thereafter, the
Administrator promulgates a notice of data availability of the results
of these calculations.
    Second, by July 1, for states identified in the June 1 notice of
data availability as having emissions exceeding the state trading
budget with variability, the designated representative of each new unit
in the state that operated during but did not receive an allocation for
the year involved must submit a statement to the Administrator with
certain information about the unit. This information--i.e., the unit's
allowable emission rate for the pollutant involved (NOX or
SO2) and heat rate--is used to calculate a surrogate
allocation for the unit to be used solely for the purposes of
determining whether the group of units with a common designated
representative that includes the unit had emissions exceeding
allocations plus share of the state's variability limit.
    Third, the Administrator calculates, for each state identified in
the June 1 notice of data availability and for each common designated
representative of a group of units (which groups can include one or
more units and sources) in the state, the common designated
representative's share of emissions, the common designated
representative's share of the state trading budget with the variability
limit, and the amount (if any) that the groups of owners and operators
of units represented by the common designated representative (which
groups can include one or more owners and operators) in the state must
surrender under the assurance provisions (i.e., the common designated
representative's proportionate share of the excess of state emissions
over the state trading budget with the variability limit). The
Administrator promulgates by August 1 a notice of data availability of
the results of these calculations, provides an opportunity for
submission of objections, and promulgates by October 1 a second notice
of data availability of any necessary adjustments to the calculations.
In contrast with the proposed rules, objections may be submitted
concerning information in the August 1 notice, whether or not that
information was also provided in the June 1 notice. In short, the
process of issuing notices is shortened in the final rules by providing
one, comprehensive opportunity to submit objections to the June 1 and
August 1 notices, rather than two separate opportunities, one for each
notice.
    Also in contrast with the proposed rules, the deadlines for
issuance of notices of data availability for implementation of the
assurance provisions are made uniform under the final rules for all of
the Transport Rule trading programs. EPA is taking this approach for
the same reasons that the deadlines for issuance of notices of data
availability for new unit set-aside allocations are made uniform for
all of these trading programs.
    Fourth, the owners and operators identified in the October 1 notice
of data availability as being required to surrender allowances under
the assurance provisions must transfer, by November 1, to the assurance
account created by the Administrator for such owners and operators the
amount of allowances (usable for compliance) that the Administrator
determined in the October 1 notice of data availability. Where the
October 1 notice indicates that a specified surrender amount is owed by
a group of two or more owners and operators, all the group members are
liable for the surrender amount, and it is up to the owners and
operators in the group to decide who will actually surrender
allowances. This is analogous to the situation where a group of two or
more owners and operators of covered units at a source is required to
hold allowances covering the unit's emissions and therefore the group
of owners and operators is liable. See 58 FR 3590, 3599 (January 11,
1993) (discussing liability of owners and operators under allowance-
holding requirements of the Acid Rain Program).
    EPA believes that the approach of making the owners and operators
responsible for deciding which of them will actually surrender the
necessary allowances under the assurance provisions is reasonable
because the identity of who is an owner or operator (particularly who
is an owner) of a unit or source and the percentage of an owner's share
can change during the year and this information is available to the
owners and operators on an ongoing

basis, and not to EPA unless EPA were to impose new requirements for
reporting this information. Further, EPA believes that it is reasonable
to leave to private agreements the establishment of procedures for
determining when, and under what conditions, specific owners and
operators will provide the allowances for surrender. Owners and
operators already make these types of determinations with regard to the
surrender requirements in meeting the emissions limitations and any
excess emission penalties.
    As part of implementing the common-designated-representative-based
approach of the assurance provisions in the final Transport Rule, the
final rules provide that the Administrator (instead of the owners, as
in the proposed rules) will create an assurance account for each group
of the owners and operators of units and sources with a common
designated representative in each state where the assurance provisions
are triggered. Because the final rules require owners and operators to
transfer surrendered allowances to the appropriate assurance account
(rather than requiring the Administrator to deduct from accounts
established by the owners), there is no need for the proposed rule
provisions concerning identification of which allowances are to be
deducted and first-in, first-out deduction in the absence of such
identification.
    The final rules provide that, in general, the surrender amounts
specified in the October 1 notice for owners and operators are final
and will not be revised even if the underlying data (e.g., emission
data) used in the calculations underlying the October 1 notice are
subsequently revised. However, the final rules set forth limited
exceptions to this: Where such data are revised as a result of a
decision in or settlement of litigation concerning the data on appeal.
EPA believes that the limitation on revisions of the surrender amounts
specified in the October 1 notice are necessary to provide some
certainty to owners and operators and avoid the potential for multiple
changes in owners' and operators' required surrender amounts. Because
the surrender amount for each group of owners and operators of units
and sources with a common designated representative in a state is
calculated using emission data from all of the covered units in that
state, each change in one or a few units' emission data that might
occur after issuance of the October 1 notice could otherwise change the
calculated surrender amounts for all or many groups in the state. For
the limited exceptions where the final rules provide that the surrender
amounts specified in the August 1 notice may be revised, the final
rules require the Administrator to set a new surrender deadline for any
additional surrender required and to transfer allowances back out of
the assurance account involved for any reduced surrender requirement,
as appropriate.
    Under the final rules (as under the proposed rules), it is not a
violation of the CAA for total state covered-unit emissions to exceed
the state trading budget with the variability limit or for a group of
owners and operators to become subject to the allowance surrender
requirement under the assurance provisions. However, the failure of any
group of owners and operators to surrender the required amount of
allowances in the assurance account created for such owners and
operators violates the CAA and is subject to discretionary penalties,
with each required allowance that was not surrendered and each day of
the control period involved constituting a violation.
(v) Sec. Sec.  97.426 Through 97.428, 97.526 Through 97.528, 97.626
Through 97.628, and 97.726 Through 97.728--Miscellaneous Provisions
    These sections in the final rules (as in the proposed rules)
include provisions allowing banking of the allowances issued in the
Transport Rule trading programs, i.e., the retention of unused
Transport Rule allowances allocated for a given control period for use
or trading in a later control period. While this can potentially cause
emissions from sources in some states in some control periods to be
greater than the allowances allocated for those control periods, the
assurance provisions limit such emissions in a way that ensures that
each state's significant contribution to nonattainment and interference
with maintenance that EPA has identified in this action will be
eliminated.
    These sections also include provisions stating that the
Administrator can, at his or her discretion and on his or her own
motion, correct any type of error that he or she finds in an account in
the Allowance Management System. In addition, the Administrator can
review any submission under the Transport Rule trading programs, make
adjustments to the information in the submission, and deduct or
transfer allowances based on such adjusted information.
(5) Emissions Monitoring, Recordkeeping, and Reporting
    Sections 97.430 through 97.435, 97.530 through 97.535, 97.630
through 97.635, and 97.730 through 97.735 establish emissions
monitoring, recordkeeping, and reporting requirements for Transport
Rule units. These provisions reference the relevant sections of Part 75
(40 CFR part 75), where the specific procedures and requirements for
monitoring and reporting NOX and SO2 mass
emissions are set forth. The provisions in the final rules are
virtually the same as the monitoring, recordkeeping, and reporting
requirements in the proposed rules and under previous EPA-administered
trading programs, e.g., the Acid Rain Program and NOX Budget
and CAIR trading programs. The final rule provisions are also
essentially the same for each of the Transport Rule trading programs,
except for differences reflecting the different pollutants and control
periods involved.
    Under the provisions of the final rules and under Part 75, a unit
has several options for monitoring and reporting. A unit's options are
to use: a CEMS; an excepted monitoring methodology (NOX mass
monitoring for certain peaking units and SO2 mass monitoring
for certain oil- and gas-fired units); low mass emissions monitoring
for certain, non-coal-fired, low emitting units; or an alternative
monitoring system approved by the Administrator through a petition
process. In addition, unit owners and operators may submit, and the
Administrator can approve, petitions for alternatives to Transport Rule
and Part 75 monitoring, recordkeeping, and reporting requirements.
    As discussed elsewhere in this preamble, the final rules and Part
75 specify that each CEMS must undergo rigorous initial certification
testing and periodic quality assurance testing thereafter. In addition,
when a monitoring system is not operating properly, standard substitute
data procedures are applied and result in a conservative estimate of
emissions for the period involved. Further, the final rules and Part 75
require electronic submission, to the Administrator and in a format
prescribed by the Administrator, of a quarterly emissions report.
    The final rules include revised language in Sec. Sec.
97.430(b)(3), 97.530(b)(3), 97.630(b)(3), and 97.730(b)(3) that
incorporates by reference, and thereby applies to units in the
Transport Rule trading programs, clarification that EPA recently
adopted in Sec.  75.4(e) of Part 75 (for Acid Rain Program units)

concerning the requirements for certification, recertification, and
diagnostic testing of emission monitoring systems when a unit adds a
new stack or new add-on SO2 or NOX emission
control device. See 76 FR 17288, 17298-300 (March 28, 2011). The
revised language is adopted for the reasons set forth in the preamble
of that Acid Rain Program final rule and in order to continue the
approach, in the Transport Rule trading program rules, of adopting
monitoring, recordkeeping, and reporting requirements that are
generally consistent with those in the Acid Rain Program, which covers
many units in the Transport Rule trading programs.

XII. Statutory and Executive Order Reviews

    The projected impacts of this final rule as presented throughout
the preamble do not reflect minor technical corrections to
SO2 budgets in three states (KY, MI, and NY) made after the
impact analyses were conducted. These projections also assumed
preliminary variability limits that were smaller than the variability
limits finalized in this rule. EPA conducted sensitivity analysis
confirming that these differences do not meaningfully alter any of the
Agency's findings or conclusions based on the projected cost, benefit,
and air quality impacts presented for the final Transport Rule. The
results of this sensitivity analysis are presented in Appendix F in the
final Transport Rule RIA.

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

    Under EO 12866 (58 FR 51735, October 4, 1993), this action is an
``economically significant regulatory action'' because it is likely to
have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or state, local, or tribal governments or
communities.
    Accordingly, EPA submitted this action to the OMB for review under
EO 12866 and EO 13563 (76 FR 3821, January 21, 2011) and any changes in
response to OMB recommendations have been documented in the docket for
this action. In addition, EPA prepared an analysis of the potential
costs and benefits for this action. This analysis is contained in the
Regulatory Impact Analysis (RIA) for this action. For more information
on the costs and benefits for this rule, please refer to Table VIII.C-3
of this preamble.
    When estimating the human health benefits and compliance costs in
Table VIII.C-3 of this preamble, EPA applied methods and assumptions
consistent with the state-of-the-science for human health impact
assessment, economics, and air quality analysis. EPA applied its best
professional judgment in performing this analysis and believes that
these estimates provide a reasonable indication of the expected
benefits and costs to the nation of this rulemaking. The RIA available
in the docket describes in detail the empirical basis for EPA's
assumptions and characterizes the various sources of uncertainties
affecting the estimates below. In doing what is laid out above in this
paragraph, EPA adheres to EO 13563, ``Improving Regulation and
Regulatory Review,'' (76 FR 3,821, January 21, 2011), which is a
supplement to EO 12866.
    In addition to estimating costs and benefits, EO 13563 focuses on
the importance of a ``regulatory system [that] * * * promote[s]
predictability and reduce[s] uncertainty'' and that ``identify[ies] and
use[s] the best, most innovative, and least burdensome tools for
achieving regulatory ends.'' EO 13563 also states that ``[i]n
developing regulatory actions and identifying appropriate approaches,
each agency shall attempt to promote such coordination, simplification,
and harmonization. Each agency shall also seek to identify, as
appropriate, means to achieve regulatory goals that are designed to
promote innovation.'' We recognize that the utility sector has
compliance obligations related to multiple environmental statutes
authorizing regulatory action, including this rule's requirements to
reduce interstate transport of harmful ozone and fine particles and
their precursors, as well as other rules' requirements to reduce air
toxic emissions, to reduce greenhouse gas emissions, to safely manage
coal combustion wastes, and to protect aquatic wildlife from water
intake procedures. In the wake of promulgating this final rule, EPA
recognizes that moving forward the agency needs to approach these
rulemakings in ways that allow the industry to make practical
investment decisions that minimize costs in complying with all of the
final rules, while still securing the fundamentally important
environmental and public health benefits that led Congress to enact
those authorities in the first place. At the same time, EPA notes that
the flexibility inherent in the allowance-trading mechanism included in
this rule affords utilities themselves a degree of latitude to
determine how best to integrate compliance with the emission reduction
requirements of this rule and those of the other rules.
    The final rule will also reduce emissions of directly emitted PM
and ozone precursors, and estimates of the PM2.5-related
benefits of these air quality improvements may be found in Tables
VIII.C-1 and VIII.C-2 of this preamble. When characterizing uncertainty
in the PM-mortality relationship, EPA has historically presented a
sensitivity analysis applying alternate assumed thresholds in the PM
concentration-response relationship. In its synthesis of the current
state of the PM science, EPA's 2009 Integrated Science Assessment for
Particulate Matter concluded that a no-threshold log-linear model most
adequately portrays the PM-mortality concentration-response
relationship. In the RIA accompanying this rulemaking, rather than
segmenting out impacts predicted to be associated levels above and
below a ``bright line'' threshold, EPA includes a ``lowest measured
level'' (LML) analysis that illustrates the increasing uncertainty that
characterizes exposure attributed to levels of PM2.5 below
the LML of each epidemiological study used to estimate
PM2.5-related premature death. Figures provided in the RIA
show the distribution of baseline exposure to PM2.5, as well
as the lowest air quality levels measured in each of the epidemiology
cohort studies. This information provides a context for considering the
likely portion of PM-related mortality benefits occurring above or
below the LML of each study; in general, our confidence in the size of
the estimated reduction PM2.5-related premature mortality
diminishes as baseline concentrations of PM2.5 are lowered.
Approximately 69 percent of the avoided impacts occur at or above an
annual mean PM2.5 level of 10 [mu]g/m\3\ (the LML of the
Laden et al. 2006 study); about 96 percent occur at or above an annual
mean PM2.5 level of 7.5 [mu]g/m\3\ (the LML of the Pope et
al. 2002 study). Although the LML analysis provides some insight into
the level of uncertainty in the estimated PM mortality benefits, EPA
does not view the LML as a threshold and continues to quantify PM-
related mortality impacts using a full range of modeled air quality
concentrations. It is important to note that the monetized benefits
include many but not all health effects associated with
PM2.5 exposure. Benefits are shown as a range from Pope, et
al., (2002) to Laden, et al., (2006). These models assume that all fine
particles,

regardless of their chemical composition, are equally potent in causing
premature mortality because there is no clear scientific evidence that
would support the development of differential effects estimates by
particle type.
    The cost analysis is also subject to uncertainties. Estimating the
cost conversion from one process to another is more difficult than
estimating the cost of adding control equipment because it is more
dependent on plant specific information. More information on the cost
uncertainties can be found in the RIA.
    A summary of the monetized benefits and net benefits for the final
rule at discount rates of 3 percent and 7 percent is in Table VIII.C-3
of this preamble. For more information on the benefits analysis, please
refer to the RIA for this rulemaking, which is available in the docket.

B. Paperwork Reduction Act

    EPA is required to document the information collection burden
imposed by the Transport Rule on industry, states, and EPA in an
information collection request (ICR). The ICR describes the information
collection requirements associated with the Transport Rule and
estimates the incremental costs of compliance with all such
requirements, such as the requirement for industry to monitor, record,
and report emission data to EPA.
    The ICR for the final Transport Rule has been submitted for
approval by OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq., and the information collection requirements it documents are not
enforceable until such approval has been granted. An ICR was also
submitted to OMB in support of the proposed Transport Rule; no adverse
comment was received by EPA on either the information collection
requirements or their associated cost estimates as described in that
document.
    The costs associated with the information collection requirements
of the Transport Rule include start-up and capital costs for units
newly affected by an emission trading program, or whose reporting
status has changed (e.g., from ozone-season-only to annual reporting),
as well as the additional operation and maintenance costs for Transport
Rule-affected units already participating in an EPA-administered cap
and trade program. More information on the ICR analysis is included in
the final Transport Rule docket.
    The records and reports generated by these activities will be used
by EPA and states to ensure that affected facilities comply with
emission limits and other requirements. Such records and reports are
also helpful to EPA and states in both identifying affected facilities
that may not be in compliance with applicable requirements and in
discerning which units and what records or processes should be
inspected.
    The incremental capital and operating costs associated with the
recordkeeping and reporting burden to Transport Rule-affected sources
in states participating in the Transport Rule trading programs are
approximately $26 million annually in 2010 dollars. The total number of
burden hours associated with the recordkeeping and reporting burden to
Transport Rule-affected sources in states participating in the
Transport Rule trading programs is approximately 185,000 hours
annually. These estimates include the annualized cost of installing and
operating appropriate SO2 and NOX emission
monitoring equipment to measure and report the total emissions of these
pollutants from affected EGUs (serving generators greater than 25 MW).
The burden to state and local air agencies, as documented in the ICR,
includes any necessary SIP revisions, performance of monitor
certifications, and fulfillment of audit responsibilities. Burden is
defined at 5 CFR 1320.3(b).
    The amendments do not require any notifications or reports beyond
those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance, which is specifically authorized by CAA section 114 (42
U.S.C. 7414). All information submitted to EPA for which a claim of
confidentiality is made will be safeguarded according to EPA policies
in 40 CFR part 2, subpart B, Confidentiality of Business Information.
An Agency may not conduct or sponsor, and a person is not required to
respond to a collection of information unless it displays a currently
valid OMB control number. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in
the Federal Register to display the OMB control number for the approved
information collection requirements contained in this final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this final rule on small
entities, small entity is defined as:
    (1) A small business as defined by the Small Business
Administration's (SBA) regulations at 13 CFR 121.201. For the electric
power generation industry, the small business size standard is an
ultimate parent entity defined as having a total electric output of 4
million megawatt-hours (MWh) or less in the previous fiscal year.
    (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.

     Table XII.C-1--Potentially Regulated Categories and Entities a
------------------------------------------------------------------------
                                                 Examples of potentially
            Category             NAICS code \b\     regulated entities
------------------------------------------------------------------------
Industry.......................          221112  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units.
Federal Government.............      \c\ 221112  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by the federal
                                                  government.
State/Local Government.........      2\c\ 21112  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by municipalities.
Tribal Government..............          921150  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units in
                                                  Indian Country.
------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate
  electric generating units only.
\b\ North American Industry Classification System.
\c\ Federal, state, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

    EPA used Velocity Suite's Ventyx data as a basis for identifying
plant ownership and compiling the list of potentially affected small
entities. For plants burning fossil fuel as the primary fuel, plant-
level boiler and generator capacity, heat input, generation, and
emission data were aggregated by owner and then parent company. For
cooperatives, investor-owned utilities, and subdivisions that generate
less than 4 billion kWh of electricity annually but 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.
    After considering the economic impacts of this final rule on small
entities, EPA certifies that this action will not have a significant
economic impact on a substantial number of small entities (No SISNOSE).
This certification is based on the economic impact of this final rule
to all affected small entities across all industries affected. EPA
assessed the potential impact of this action on small entities and
found that there are about 660 potentially affected small units (i.e.,
greater than 25 MW and generating less than 4 million MWh) out of 3,625
existing units in the Transport Rule states. The majority of these EGUs
are owned by entities that do not meet the small entity definition. The
remaining 271 of the 660 EGUs are owned by 108 potentially affected
small entities and are likely to be affected by this rule. EPA
estimates that 24 of the 108 identified small entities will have
annualized costs greater than 1 percent of their revenues, and the
other 84 are projected to incur costs less than 1 percent of revenues.
Eleven small entities out of 108--approximately 10 percent--are
estimated to have annualized costs greater than 3 percent of their
revenues. EPA has lessened the impacts for small entities by excluding
all units smaller than 25 MWe. This exclusion, in addition to the
exemptions for cogeneration units and solid waste incineration units,
eliminates the burden of higher costs for a substantial number of small
entities located in the Transport Rule states.
    While the total number of small entities has increased compared to
the proposal as a result of updated modeling and changes in geographic
coverage, the number with compliance costs greater than 1 percent of
revenues has fallen, and both the number and percentage of
significantly impacted small entities (costs greater than 3 percent of
revenues) are lower--now 10 percent compared to 17 percent in the
proposal. The share of significantly impacted small entities has fallen
because of updated modeling and the change in the allowance allocation
methodology (see section VII.D for more information about allowance
allocations).
    Although this final rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of this rule on small entities. In EPA's
modeling, most of the cost impacts for these small entities and their
associated units are driven by lower electricity generation relative to
the base case. Specifically, two small units reduce their generation by
significant amounts, driving the bulk of the costs for all small
entities. Excluding these two units, one of the main drivers of small
entity impacts is higher fuel costs, which the affected units would
incur irrespective of whether they had to comply with this rule. In
addition, EPA's decision to exclude units smaller than 25 MWe has
already significantly reduced the burden on approximately 390 small
entities.
    For more information on the small entity impacts associated with
the final rule, refer to the Regulatory Impact Analysis for this final
rule, which can be found in the docket for this rule and on the Web
site http://www.epa.gov/airtransport.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
state, local, and tribal governments, and the private sector. This 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, EPA has
prepared, under section 202 of the UMRA, a written statement which is
summarized later.
    Consistent with the intergovernmental consultation provisions of
section 204 of the UMRA, EPA held consultations with the governmental
entities affected by this rule during the proposal phase. Subsequently,
EPA sent a letter to the ten Representative National Organizations to
draw their attention to the Transport Rule Notice of Data Availability
(NODA) on allowance allocations and other related matters and to invite
their comments. During the NODA comment period, EPA participated in
informational calls with the Environmental Council of the States (ECOS)
and the National Governors Association to provide information about the
NODA directly to state and local officials. There were no new concerns
raised during these informational calls. In addition, EPA also
conducted consultations with federally recognized tribes prior to
finalizing this rule and invited them to comment on the allowance
allocation NODA. EPA has added a new unit set-aside provision to this
final rule specifically for EGUs constructed in Indian country to
ensure allowances are available to tribes and tribal sovereignty is
respected.
    Consistent with section 205, EPA identified and considered a
reasonable number of regulatory alternatives. In the proposal, EPA
included three remedy options that it considered when developing this
final rule: (1) The preferred remedy trading programs, (2) State
Budgets/Intrastate Trading, and (3) Direct Controls. Moreover, section
205 allows EPA 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.
    EPA examined the potential economic impacts on state- and
municipality-owned entities associated with this rulemaking based on
assumptions of how the affected states will implement control measures
to meet program requirements. Although EPA does not conclude that the
requirements of the UMRA apply to the Transport Rule, these impacts
have been calculated to provide additional understanding of the nature
of potential impacts and additional information.
    EPA has determined that this rule contains a federal mandate that
may result in expenditures of $100 million or more in 1 year. EPA has
determined that this rule contains no regulatory requirements that
might significantly or uniquely affect small governments and that
development of a small government plan under section 203 of the Act is
not required. The costs of compliance will be borne predominately by
sources in the private sector although a small number of sources owned
by state and local governments may also be impacted. The requirements
in this action do not distinguish EGUs based on ownership, either for
those units that are included within the scope of the rule or for those
units that are exempted by the generating capacity cut-off. Therefore,
this rule is not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments.

E. Executive Order 13132: Federalism

    This final rule does not have federalism implications. It will not
have substantial direct effects on the states, on the relationship
between the national government and the states, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. The final rule primarily affects
private industry, and does not impose significant economic costs on
state or local governments. Thus, Executive Order 13132 does not apply
to the final rule.
    Although section 6 of Executive Order 13132 does not apply to the
final rule, EPA did provide information to state and local officials
during development of both the proposal and final rule. EPA sent a
letter to the ten Representative National Organizations to draw their
attention to the Transport Rule NODA on allowance allocations and other
related matters and to invite their comments. Following that letter in
early 2011, EPA participated in informational calls with the
Environmental Council of the States (ECOS) and the National Governors
Association to provide information about the NODA directly to state and
local officials. There were no new concerns raised during these
informational calls.

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

    Under Executive Order 13175 (65 FR 67249, November 9, 2000), 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 EPA
consults with tribal officials early in the process of developing the
proposed regulation and develops a tribal summary impact statement.
    EPA has concluded that this action may have tribal implications if
a new unit covered by the rule is built in Indian country.
Additionally, tribes have a vested interest in how this final rule
affects their air quality. However, it will neither impose substantial
direct compliance costs on tribal governments, nor preempt tribal law.
EPA consulted with tribal officials during the process of finalizing
this regulation to permit them to have meaningful and timely input into
its development.
    EPA received comments on the proposed Transport Rule that the
Agency did not properly conduct consultation during the proposal phase
of the rulemaking process. In response to these comments, EPA sent a
letter to all federally-recognized tribes in the country offering
consultation. In addition, several commenters also noted that the
Agency did not adequately consider opportunities for tribes to enter
into any of the trading programs and, in particular, did not consider
sovereignty issues when addressing how to distribute allowances to
potential new units in Indian country. On January 7, 2011, EPA issued a
NODA requesting comment on allocations for new units in Indian country,
among other topics.
    The Agency held a consultation call with three tribes on January
21, 2011. A follow-up call was held on February 4, 2011 with two of the
three original tribes plus 13 additional tribes, as well as
representatives from the National Tribal Air Association. In all ten
tribes participated in these calls as consultation and six participated
as information-sharing. EPA considered the additional input from these
consultation and information calls, in conjunction with the public
comments, in the development of the final rule. Accordingly, EPA
created an Indian country new unit set-aside to specifically address
tribes' concerns regarding the protection of tribal sovereignty in the
distribution of allowances for new units in Indian country. See section
VII.D.2 of this preamble for details on the Indian country set-aside
for new units constructed in Indian country within states covered by
the Transport Rule.
    As required by section 7(a) of the Executive Order, EPA's Tribal
Consultation Official has certified that the requirements of the
Executive Order have been met in a meaningful and timely manner. A copy
of the certification is included in the docket for this action.

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

    Executive Order 13045 (62 FR 19,885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under EO 12866, and (2) concerns an environmental health or
safety risk that EPA has reason to believe may have a disproportionate
effect on children. If the regulatory action meets both criteria, the
Agency must evaluate the environmental health or safety effects of this
planned rule on children, and explain why this planned regulation is
preferable to other potentially effective and reasonably feasible
alternatives considered by the Agency.
    This action is not subject to Executive Order 13045 because it does
not involve decisions on environmental health or safety risks that may
disproportionately affect children. EPA believes that the emission
reductions from the strategies in this rule will further improve air
quality and will further improve children's health. Analyses by EPA
that show how the emission reductions from the strategies in this rule
will further improve air quality and children's health can be found in
the RIA for this rule.

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

    Executive Order 13211 (66 FR 28355, May 22, 2001) provides that
agencies shall prepare and submit to the Administrator of the Office of
Regulatory Affairs, OMB, a Statement of Energy Effects for certain
actions identified as ``significant energy actions.'' Section 4(b) of
Executive Order 13211 defines ``significant energy action'' as ``any
action by an agency (normally published in the Federal Register) that
promulgates or is expected to lead to the promulgation of a final rule
or regulation, including notices of inquiry, advance notices of
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is
a significant regulatory action under Executive Order 12866 or any
successor order, and (ii) is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) that is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action.'' This rule is a
significant regulatory action under Executive Order 12866, and this
rule is likely to have a significant adverse effect on the supply,
distribution, or use of energy. EPA prepared a Statement of Energy
Effects for this action as follows.
    Under the provisions of this rule, EPA projects that approximately
4.8 GW of additional coal-fired generation may be removed from
operation by 2014. In practice, however, the units projected to be
uneconomic to maintain may be ``mothballed,'' retired, or kept in
service to ensure transmission reliability in certain parts of the
grid. These units are predominantly small and infrequently-used
generating units dispersed throughout the area affected by the rule. If
current forecasts of either natural gas prices or electricity demand
were revised in the future to be higher, that would create a greater
incentive to keep these units operational.
    EPA estimates that average retail electricity prices could increase
in the

contiguous U.S. by about 1.7 percent in 2012 and 0.8 percent in 2014.
This is generally less of an increase than often occurs with
fluctuating fuel prices and other market factors. Related to this, EPA
projects limited impacts on coal and gas prices. The average delivered
coal price decreases by about 1.4 percent in 2012 and 0.9 percent in
2014 relative to the base case as a result of decreased coal demand and
shifts in the type of coal demanded. EPA also projects that the
electric power sector-delivered natural gas price will increase by
about 0.3 percent over the 2012-2030 timeframe and that natural gas use
for electricity generation will increase by approximately 200 billion
cubic feet (BCF) by 2014. These impacts are well within the range of
price variability that is regularly experienced in natural gas markets.
Finally, under the Transport Rule, EPA projects that coal production
for use by the power sector will increase above 2009 levels by 21
million tons in 2012 and a further 14 million tons in 2014, as opposed
to 30 million tons in 2012 and a further 26 million tons in 2014
without the Transport Rule in place. The Transport Rule is not
projected to impact production of coal for uses outside the power
sector (e.g., export, industrial sources), which represent
approximately 6 percent of total coal production in 2009. EPA does not
believe that this rule will have any other impacts (e.g., on oil
markets) that exceed the significance criteria.
    EPA believes that a number of features of the rulemaking serve to
reduce its impact on energy supply. First, the trading component of the
Transport Rule provides flexibility to the power sector and enables
industry to comply with the emission reduction requirements in the most
cost-effective manner compared to the alternative remedy approaches on
which EPA took comment in the proposal, thus minimizing overall costs
and the ultimate impact on energy supply. Second, the more stringent
budgets for SO2 are set in two phases, providing adequate
time for EGUs to install pollution controls. In addition, both the
operational flexibility of trading and the ability to bank allowances
for future years helps industry plan for and ensure reliability in the
electrical system.
    For more details concerning energy impacts, see the RIA for the
Transport Rule.

I. National Technology Transfer Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards. This rule will
require all sources to meet the applicable monitoring requirements of
40 CFR part 75. Part 75 already incorporates a number of voluntary
consensus standards. Consistent with the Agency's Performance Based
Measurement System (PBMS), Part 75 sets forth performance criteria that
allow the use of alternative methods to the ones set forth in Part 75.
The PBMS approach is intended to be more flexible and cost effective
for the regulated community; it is also intended to encourage
innovation in analytical technology and improved data quality. At this
time, EPA is not recommending any revisions to Part 75; however, EPA
periodically revises the test procedures set forth in Part 75. When EPA
revises the test procedures set forth in Part 75 in the future, EPA
will address the use of any new voluntary consensus standards that are
equivalent. Currently, even if a test procedure is not set forth in
Part 75, EPA is not precluding the use of any method, whether it
constitutes a voluntary consensus standard or not, as long as it meets
the performance criteria specified; however, any alternative methods
must be approved through the petition process under 40 CFR 75.66 before
they are used.

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority, low-income, and Tribal
populations in the United States. During development of this final
Transport Rule, EPA considered its impacts on low-income, minority, and
tribal communities in several ways and provided multiple opportunities
for these communities to meaningfully participate in the rulemaking
process. The proposed Transport Rule included an analysis of its
effects on these populations; this section describes additional
analysis conducted since proposal, EPA's responses to key comments on
environmental justice issues raised during the comment period, and the
public outreach and comment opportunities for this rule.
    A summary of the history, statutory authority, and key components
of this final Transport Rule are described in the Executive Summary
(section III) of this preamble. That section also summarizes a
supplemental notice of proposed rulemaking (SNPR) that EPA is
publishing to correct a procedural flaw by providing an opportunity for
public comment on issues that arose from new analyses with updated
inventories and modeling platforms.
    Briefly, this final Transport Rule will reduce emissions of
SO2 and NOX in 23 eastern and central states in
2012 and 2014 that contribute to annual and/or 24-hour PM2.5
nonattainment or interfere with maintenance in downwind states. It will
also reduce emissions of ozone-season NOX in 20 eastern and
central states in 2012 and 2014 that contribute to the 1997 ozone
nonattainment or interfere with maintenance in downwind states. This
rule is replacing an earlier rule (the 2005 Clean Air Interstate Rule
(CAIR)) that was first vacated and then remanded to EPA by the U.S.
Court of Appeals for the District of Columbia Circuit in 2008.
1. Consideration of Environmental Justice in the Transport Rule
Development Process and Response to Comments
    The effects of this final Transport Rule on the most highly exposed
populations were integral in its development. This rule uses EPA's
authority in CAA section 110(a)(2)(d) to reduce sulfur dioxide
(SO2) and (nitrogen oxides) NOX pollution that
significantly contributes to downwind PM2.5 and ozone
nonattainment or maintenance areas. As a result, the rule will reduce
exposures to ozone and PM2.5 in the most-contaminated areas
(i.e., areas that are not meeting the 1997 ozone and 1997 and 2006
PM2.5 National Ambient Air Quality Standards (NAAQS)). In
addition, the rule separately identifies both nonattainment areas and
maintenance areas (maintenance areas are those that are projected to
meet the NAAQS but that, based on past data, are in danger of

exceeding the standards in the future). This requirement reduces the
likelihood that any areas close to the level of the standard will
exceed the current health-based standards in the future.
    This final Transport Rule implements these emission reductions
using an emission trading mechanism with assurance provisions for power
plants. EPA recognizes that many environmental justice communities have
voiced concerns in the past about emission trading and the potential
for any emission increases in any location. EPA also received several
comments on this issue during the comment period for the proposed
Transport Rule. As described below, we believe this final rule
addresses the concerns raised on this issue during the comment period.
    PM2.5 and ozone pollution from power plants have both
local and regional components: Part of the pollution in a given
location--even in locations near emission sources--is due to emissions
from nearby sources and part is due to emissions that travel hundreds
of miles and mix with emissions from other sources. Therefore, in many
instances the exact location of the upwind reductions does not affect
the levels of air pollution downwind.
    It is important to note that the section of the Clean Air Act
providing authority for this rule, section 110(a)(2)(D), unlike some
other provisions, does not dictate levels of control for particular
facilities. As at least one commenter noted, none of the alternatives
put forward by EPA in the proposed rule could have ensured no emission
increases at any facility. Under the direct control alternative, the
emission rate for each facility would have been limited but each
facility could emit more by increasing their power output in order to
meet electricity reliability or other goals. Under the intrastate
trading option, sources could not trade allowances with sources in
other states but individual facilities within each state could have
increased their emissions as long as another facility in the state had
decreased theirs at some time.
    The final Transport Rule allows sources to trade allowances with
other sources in the same or different states while firmly constraining
any emissions shifting that may occur by requiring a strict emission
ceiling in each state (the budget plus variability limit). In addition,
assurance provisions in the rule outline the allowance surrender
penalties for failing to meet the budget plus variability limits; there
are additional allowance penalties as well as financial penalties for
failing to hold an adequate number of allowances to cover emissions.
This approach eliminates emissions in each state that significantly
contribute to downwind nonattainment or maintenance areas, while
allowing power companies to adjust generation as needed and ensure that
the country's electricity needs will continue to be met. EPA maintains
that the existence of these assurance provisions, including the
penalties imposed when triggered, will ensure that state emissions will
stay below the level of the budget plus variability limit.
    In addition, all sources must hold enough allowances to cover their
emissions. Therefore, if a source emits more than its allocation in a
given year, either another source must have used less than its
allocation and be willing to sell some of its excess allowances, or the
source itself had emitted less than its allocation in one or more
previous years (i.e., banked allowances for future use).
    In summary, the final remedy addresses commenter concerns about
localized hot spots and reduces ambient concentrations of pollution
where they are most needed by sensitive and vulnerable populations by:
Considering the science of ozone and PM2.5 transport to set
strict state budgets to eliminate significant contributions to ozone
and PM2.5 nonattainment and maintenance (i.e., the most
polluted) areas; implementing air quality-assured trading; requiring
any emissions above the level of the allocations to be offset by
emission decreases; and imposing strict penalties for sources that
contribute to a state's exceedance of its budget plus variability
limit. In addition, it is important to note that nothing in this final
rule allows sources to violate their title V permit or any other
federal, state, or local emissions or air quality requirements.
    EPA received comments from several tribal commenters regarding the
lack of allocations in the proposal to new units in Indian Country. EPA
responded to these comments by changing the allocation approach in the
final rule to create Indian country new unit set-asides. In order to
protect tribal sovereignty, these set-asides will be managed and
distributed by the federal government regardless of whether the
Transport Rule in the adjoining or surrounding state is implemented
through a FIP or SIP. While there are no existing power plants in
Indian country covered by this Transport Rule, the Indian country set-
asides will ensure that any future new units built in Indian country
will be able to get the necessary allowances. A full discussion of the
Indian country new unit set-asides can be found in section VII.D.2.
    EPA also received several comments during the comment period from
individuals and groups requesting additional emission reductions to
further protect sensitive and vulnerable communities. While EPA has
adjusted the emission requirements somewhat in the final rule to
accommodate revised data and updated modeling results, we are
finalizing emission reductions very similar to the level in the
proposal. This is because EPA believes that the emission reductions
required by this final rule are appropriate to meet the statutory
requirements of CAA section 110(a)(2)(d) and respond to the concerns
raised by the Court's opinion in North Carolina that remanded CAIR to
the Agency in 2008.
    In addition, it is important to note that CAA section 110(a)(2)(d),
which addresses transport of criteria pollutants between states, is
only one of many provisions of the CAA that provide EPA, states, and
local governments with authorities to reduce exposure to ozone and
PM2.5 in communities. These legal authorities work together
to reduce exposure to these pollutants in communities, including for
minority, low-income, and tribal populations, and provide substantial
health benefits to both the general public and sensitive sub-
populations.
    For example, the recently-proposed Mercury and Air Toxics Standards
(MATS) would also result in significant reductions in SO2
emissions and provide significant health and environmental benefits
nationwide. This and other actions described in section III 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
environmental justice communities, among many others. EPA will continue
to provide multiple opportunities for comment on these actions, similar
to the opportunities provided during the comment process for this rule,
detailed at the end of this section. We encourage environmental justice
communities to review and comment on these actions.
2. Potential Environmental and Public Health Impacts Among Populations
Susceptible or Vulnerable to Air Pollution
    EPA expects that this final rule will provide significant health
and environmental benefits to, among others, people with asthma, people
with heart disease, and people living in ozone or PM2.5
nonattainment areas. EPA's analysis of the effects of this rule,
including information on air quality changes and the resulting health
benefits, is presented both in section

VIII of this preamble and in the Regulatory Impact Analysis (RIA) for
this rule. These documents can be accessed through the rule docket No.
EPA-HQ-OAR-2009-0491 and from the main EPA webpage for the rule at
http://www.epa.gov/airtransport.
    EPA considered several aspects of the effects of the Transport Rule
on minority, low-income, and tribal populations. These included: amount
of emission reductions and where they take place (including any
potential for areas of increased emissions); the changes in ambient
concentrations across the affected area; the estimated health benefits;
and how the estimated health benefits are distributed among different
populations, including those susceptible and vulnerable to air
pollution health impacts.
a. Emission Reductions
    EPA's emission modeling data indicate that implementation of the
Transport Rule will substantially reduce SO2 emissions from
electric generating units (EGUs). As noted in section III, emissions in
states covered by the Transport Rule will decrease by 6.4 million tons
(73 percent) in 2014 compared to 2005 (the year the Clean Air
Interstate Rule was finalized). Emissions are also projected to
decrease when compared to the base case (the base case estimates
emissions in 2014 in the absence of this rule or the Clean Air
Interstate Rule it is replacing). EPA estimates that SO2
emissions in 2014 in covered states will be 3.9 million tons lower (62
percent lower) compared to the base case.
    EPA also assessed emission changes in states not covered by the
Transport Rule. Emissions in the states not covered by the Transport
Rule are also projected to decrease substantially compared to 2005
levels; in 2014 SO2 emissions are projected to be
approximately 430,000 tons lower (30 percent lower) than in 2005.
    As described in section VI.C, EPA's modeling does project that some
states not covered by any of the fine particle control programs in the
final Transport Rule may experience increases of SO2
emissions greater than 5,000 tons compared to the base case. These
states are Arkansas, Colorado, Louisiana, Montana, and Wyoming. These
emission increases are the result of forecasted changes in operation of
power plant units outside of the Transport Rule states due to the
interconnected nature of the utility grid (i.e., shifts in generation
of electricity to sources outside the Transport Rule states) or
influence of the rule on the market for lower sulfur coal. For example,
EPA projects that the rule will raise demand for lower sulfur coal in
the states covered by the Transport Rule for PM2.5 (thereby
raising its price), which may lead sources in states not covered for
PM2.5 to choose higher-sulfur coals that increase
SO2 emissions in those states.
    EPA is not requiring SO2 emission reductions in these
states under this rule because our modeling indicates none of these
states' contributions would increase enough to cause them to meet or
exceed the thresholds described in section V.D for either of the
PM2.5 standards. EPA's authority under CAA section
110(a)(2)(d) is limited to addressing this significant contribution to
nonattainment and interference with maintenance. However, as noted
above, EPA has recently proposed the Mercury and Air Toxics Standards
that will apply nationwide and result in substantial additional
SO2 emission reductions, including in states not covered by
the Transport Rule.
    EPA's emission modeling data indicates that ozone-season
NOX emissions from EGUs in states covered by the Transport
Rule will be approximately 340,000 tons lower (36 percent lower) in
2014 than they were in 2005. Emissions in states not covered by the
Transport Rule are also expected to decrease somewhat (approximately
82,000 tons or 25 percent). EPA's modeling does project that two states
(California and Pennsylvania) may experience increases of
NOX emissions greater than 5,000 tons in 2014 compared to
2005 levels. California is not covered by the Transport Rule; in
Pennsylvania, 2005 was an unusually low-emitting year and sources are
projected to increase their heat input slightly (usually meaning they
are generating more power) after the rule takes effect.
    EPA also assessed the expected changes in seasonal NOX
emissions with implementation of the Transport Rule compared to the
base case (i.e., without the rule) in 2014. The modeling indicates
ozone-season NOX emissions from EGUs in both covered states
and non-Transport Rule states under this rule will be lower than they
would have been in 2014 in the base case. Ozone-season NOX
emissions in covered states are projected to decrease by approximately
74,000 tons (11 percent); ozone-season NOX emissions in non-
Transport Rule states are projected to decrease by approximately 10,000
tons (4 percent). Both California and Pennsylvania are projected to
have lower NOX emissions in 2014 under the Transport Rule as
compared to the base case. In addition, EPA anticipates that additional
upcoming actions, including likely additional interstate transport
reductions to help states attain the upcoming new ozone NAAQS, will
result in significant additional NOX reductions in the
future.
b. Air Quality Improvements
    EPA assessed the air quality metrics (called ``design values'') for
each NAAQS addressed in this rule: 24-hour PM2.5, annual
PM2.5, and ozone. We then compared these metrics for the
final rule to the same metrics in the recent past (2003-2007 average
ambient air quality) and for the 2014 base case to assess improvements
in air quality.
    EPA's modeling indicates that there will be significant
improvements in air quality as measured by the 24-hour PM2.5
standard. Throughout much of the eastern half of the U.S., 24-hour
PM2.5 design values are projected to improve more than 10
[mu]g/m\3\ compared to the 2003-2007 average levels. In addition,
compared to the 2014 base case levels, we project the Transport Rule
will result in improvements of 8-10 [mu]g/m\3\ in a broad swath of
states stretching from far southwestern New York through Pennsylvania,
Ohio, West Virginia, Maryland, Indiana, southern Illinois, eastern
Missouri, eastern Arkansas, Kentucky, Tennessee, northern Alabama, and
northern Mississippi. Isolated areas of Virginia and northern New