submission of objections, and promulgate by November 15 a second notice
of availability of any necessary adjustments to the calculations and
the reasons for accepting or rejecting any properly submitted
objections.
    By December 1, each owner identified in the November 15 notice as
being required to hold allowances for surrender under the assurance
provisions would designate a compliance account of one of its covered
units in the state, and the authorized account representative of the
compliance account would submit to the Administrator a statement
designating the compliance account, as the account in which the
required allowances would be held.
    As of midnight of December 15, the owner would have to have in its
designated compliance account, or have a properly submitted transfer
that would move into that compliance account, the amount of allowances
(usable for compliance) that the Administrator determined (in the
calculations referenced in the November 15 notice) were required to be
held by the owner for surrender. The authorized account representative
could identify specific allowances to be deducted but, in the absence
of such identification or in the case of a partial identification, the
Administrator would deduct allowances on a first-in, first-out basis.
    The potential effect of subsequent data revisions that would
otherwise change the data used in and the results of the
Administrator's calculations referenced in the August 1 or November 15
notices discussed previously would be limited. If data used in a notice
applying the assurance provisions to a given year were revised as a
result of a decision in, or settlement of, litigation (such as an
administrative appeal resulting in such decision or settlement or an
administrative appeal whose results were in turn appealed in a judicial
proceeding resulting in such decision or settlement) initiated within
30 days of the promulgation of the notice involved, then the
Administrator would use the revised data for the calculations in the
respective notice. Any other data revisions would not be used to revise
the calculations. The revised data could be used, if relevant, in the
Administrator's calculations in future notices promulgated for a later
year. If the revised calculations increased the amount of allowances
that an owner was required to hold for surrender, the Administrator
would set a new, reasonable deadline for the owner to hold the
additional allowances in the owner's designated compliance account. The
Administrator believes that this limitation on the effect of data
revisions on the calculation of the amount of allowances owners would
have to surrender under the assurance provisions is necessary. Because
an owner's surrender obligation would be calculated using large amounts
of data involving all the covered units in a state (including
potentially many units owned by other owners), each owner would face
the potential that changes in data outside of the owner's
responsibility and control could change--after the December 15
allowance-holding deadline--in a way that would increase his surrender
obligation after that deadline and put him in violation of the
regulations and the Act. EPA believes that this potential risk would be
significant enough that it could make many owners reluctant to consider
any compliance options involving even the limited interstate trading
allowed under the proposed remedy. The proposal would limit this risk
by having the Administrator only take account of data revisions
resulting from decisions in, or settlement of, litigation initiated
soon after promulgation of the notice involved.

Owners' potential allowance surrender obligations as of the December 15
allowance-holding deadline under the assurance provisions would still
be significant even with this limitation on the potential for the
surrender obligations to increase after December 15 due to data
revisions.
    As discussed previously, it would not be a violation of the CAA for
total state EGU emissions to exceed the state budget with the
variability limit or for an owner to become subject to allowance
surrender under the assurance provisions. However, the failure of an
owner to hold in the designated compliance account a sufficient amount
of allowances to satisfy this allowance surrender would violate the CAA
and be subject to discretionary penalties, with each required allowance
that was not held and each day of the control period involved
constituting a violation. EPA believes that the allowance surrender
requirement alone--and certainly when coupled with the potential for
large discretionary penalties--would ensure that owners would take
actions to avoid having total state EGU emissions exceed the level that
would trigger the allowance surrender.
(x) 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 would allow 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. Banking would allow sources to
make emissions reductions beyond required levels and bank the unused
allowances for use or trading later. This would encourage development
of emissions reductions techniques and technologies and implementation
of early reductions, stimulate the allowance markets, and provide
flexibility to owners and operators. While this could also 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 would limit such emissions in a way that would
ensure that the part of each state's significant contribution and
interference with maintenance that EPA has identified in today's
proposed action would be eliminated.
    These sections also would provide that the Administrator could, 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 could 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 would establish emissions
monitoring, recordkeeping, and reporting requirements for Transport
Rule units that would result in clear, consistent, rigorous, and
transparent monitoring and reporting of all emissions. Such monitoring
and reporting would be the basis for holding sources accountable for
their emissions and would be essential to the success of the Transport
Rule trading programs. This is because consistent and accurate
measurement of emissions would be necessary to ensure that each
allowance would actually represent one ton of emissions and that one
ton of reported emissions from one source would be equivalent to one
ton of reported emissions from another source. This would establish the
integrity of each allowance and instill confidence in the underlying
market mechanisms that would be central to providing sources with
flexibility in achieving compliance. Moreover, given the variation in
the type, operation, and fuel mix of sources covered by the proposed
Transport Rule trading programs, EPA believes that emissions would need
to be monitored continuously in order to ensure the precision,
reliability, accuracy, and timeliness of emissions data supporting the
trading programs.
    In Sec. Sec.  97.430 through 97.435, 97.530 through 97.535, 97.630
through 97.635, and 97.730 through 97.735, EPA proposes the monitoring,
recordkeeping, and reporting requirements for the Transport Rule
NOX annual, NOX ozone season, SO2
Group 1, and SO2 Group 2 trading programs, respectively.
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
found. The proposed provisions are virtually the same as the
monitoring, recordkeeping, and reporting requirements under previous
EPA-administered trading programs, e.g., the ARP and NOX
Budget and CAIR trading programs.
    Part 75 was originally developed for the ARP and addressed
SO2 mass emissions and NOX emissions rate. The
ARP, as established by Congress in CAA Title IV, requires the use of
continuous emission monitoring systems (CEMS) or an alternative
monitoring system that is demonstrated to provide information with the
same precision, reliability, accuracy, and timeliness as a CEMS.
Subsequently, Part 75 was expanded, for purposes of the NOX
Budget Trading Program under the NOX SIP Call, to address
monitoring and reporting of NOX mass emissions. Under Part
75, a unit has several options for monitoring and reporting, namely the
use of: 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, under Part 75, the Administrator can approve
petitions for alternatives to Part 75 requirements.
    The proposed monitoring and reporting provisions for the Transport
Rule trading programs would allow use of these same options and
petition procedures and would reference the applicable provisions in
Part 75. Existing Transport Rule units would be required to install and
certify monitoring systems by the beginning of the relevant Transport
Rule trading program. New Transport Rule units have separate deadlines
based upon the date of commencement of commercial operation.
Recognizing that many of the Transport Rule units are already
monitoring NOX and/or SO2 under Part 75 through
existing trading programs, continued use of previously certified
monitoring systems would be allowed when appropriate rather than
automatically requiring recertification.
    The quality assurance (QA) requirements for the ARP that were
mandated by Congress under CAA Title IV are codified in Appendices A
and B of Part 75. Part 75 specifies that each CEMS must undergo
rigorous initial certification testing and periodic quality assurance
testing thereafter, including the use of relative accuracy test audits
(RATAs) and daily calibrations. A standard set of data validation rules
apply to all of the monitoring methodologies. These stringent
requirements result in an accurate accounting of the mass emissions
from each unit, and EPA provides prompt feedback if the monitoring
system is not operating properly. In addition, when the monitoring
system is not operating

properly, standard substitute data procedures are applied and result in
a conservative estimate of emissions for the period involved. This
ensures a level playing field among the regulated units, with
consistent accounting for every ton of emissions, and also provides an
incentive to properly maintain, and meet the QA requirements for, each
monitoring system. The monitoring and reporting provisions in the
proposed Transport Rule trading program regulations would contain the
same QA requirements and substitute data procedures as in Part 75 and
would reference the applicable provisions in Part 75.
    Part 75 requires electronic submission, to the Administrator and in
a format prescribed by the Administrator, of a quarterly emissions
report containing all of the emissions data specified in the
recordkeeping provisions of Part 75. EPA has found that centralized,
electronic reporting using a consistent format is necessary to ensure
consistent review and public posting of the emissions data for covered
units, which contribute to the integrity, efficiency, and transparency
of trading programs. Further, the inclusion of all emissions data in a
single quarterly report for each unit means that, if the same data are
needed for multiple trading programs, the unit only needs to report it
once in the form of one comprehensive report. The reporting provisions
in the proposed Transport Rule trading program regulations would
contain the same requirements for submission to the Administrator of
electronic, comprehensive quarterly reports as in Part 75. As discussed
above, the reporting provisions would also include a process for
resubmission of quarterly reports where appropriate.
5. State Budgets/Intrastate Trading Remedy Option
    As noted earlier in this preamble, in addition to the remedy option
included in the proposed FIPs, EPA is taking comment on two alternative
options for eliminating all or part of the emissions in upwind states
that significantly contribute to nonattainment or interfere with
maintenance in downwind states. The first of these alternative options
is the State Budgets/Intrastate Trading option described below. EPA is
considering the relative merits of this option and requests comment on
whether it should be included in the final FIPs. EPA also identifies
below a number of disadvantages that raise concerns for EPA and are
explained later in this section. EPA requests comment on these issues
and their impacts on and significance for any final rule.
a. Description of Option
    The State Budgets/Intrastate Trading option would set state-
specific caps for SO2, NOX annual, and
NOX ozone season emissions from EGUs and create separate
allowance trading programs within each state in the respective regions
starting in 2012. The state-specific caps would ensure that all
required reductions occur within the state and thus would address the
Court's concerns about abating each individual upwind state's unlawful
emissions under CAA section 110(a)(2)(D)(i)(I). Similar to other
trading programs, the owners and operators of each source would be
required to surrender to EPA one allowance for every ton of emissions
after the end of every control period. However, a source could only
use, for compliance with this requirement, an allowance issued for the
state where the source was located. For purposes of obtaining
allowances usable in compliance, sources within each state could trade
allowances amongst themselves, but not with sources located in other
states. Total emissions in each state could not exceed that state's
budget and there would be no shifting of emissions to other states thus
ensuring that each state's contribution to nonattainment and
interference with maintenance with regard to downwind states would be
adequately addressed. Banking of allowances for use in a later period
would be permitted under this remedy option.
    Under this option, EPA would allocate allowances to the covered
sources within each state, and sources in the state could use for
compliance only allowances issued for the same state. Even a company
that operates EGUs in multiple states would not be permitted to use for
compliance for one of its sources allowances issued to another of its
sources in a different state. In essence, this approach, if
implemented, would result in 28 separate trading programs for
NOX annual, 26 trading programs for NOX ozone
season, and 28 trading programs for SO2 for a total of 82
new trading programs to be administered by EPA. These 82 trading
programs would require 82 separate sets of allowances. Companies that
own EGUs in more than one state would also be responsible for managing
their allowances for each program in each state separately.
    Unlike the remedy option in the proposed FIPs or the other
alternative remedy option, this option does not include assurance
provisions based on the variability limits described in section IV.
This option includes a ``hard'' cap for each state equal to its budget,
which provides assurance that reductions will occur in each state and
which EPA believes makes additional assurance provisions unnecessary.
The State Budgets/Intrastate Trading option does allow banking and the
use of banked allowances to provide sources with some degree of
operational flexibility in complying with the program. Because this
option includes provisions for banking emissions allowances (as does
the proposed State Budgets/Limited Trading remedy), limited year-to-
year (temporal) emissions variability is allowed. EPA requests comment
on this approach to providing for emissions variability. EPA also
requests comment on whether assurance provisions based on variability
limits should be included in this option.
b. How the Option Would Be Implemented
(1) Applicability
    Applicability would be the same for the proposed remedy and for the
two alternative options, including this one. Refer to section V.D.4
above for detailed discussion on applicability.
(2) Allocation of Emissions Allowances
    While the general approach for calculating allowance allocations
would be the same as described above for State Budgets/Limited Trading,
EPA would not distribute all of the allowances into the source accounts
each period. The distribution of allowances would be modified because
of the concentrated nature of numerous state power markets, which would
be reflected in the state allowance markets if all allowances were
distributed in each state based on factors reflecting generation in
that state. The electric power sector tends to be highly concentrated,
and, within a state, the majority of generation is often owned by a
relatively small number of companies. This assessment of state
electricity markets is supported by analysis using the Herfindahl-
Hirschman Index, a way to measure the size of firms in relation to the
industry and an indicator of the amount of competition among them (see
Electric Generation Ownership, Market Concentration and Auction Size
Technical Support Document). To address this potential issue concerning
the allowance markets in many states, under this option some allowances
would be withheld from certain sources in each state that control a
large share of fossil-fueled power generation and

would be made available for companies with a small share of generation
in the state.
    The reason for including this provision is that the dominant power
generation companies in each state would likely receive a large share
of the allocated allowances and as a result might be able to exert
control over allowance prices in the state's allowance market. This
market power and potential for allowance price manipulation could pose
a threat to the transparency and liquidity of allowance markets and put
small owners of fossil-fuel fired generation at a disadvantage
regarding their compliance costs unless the owners were given
sufficient access to allowances other than through direct purchase from
the state's dominant companies. Some of these owners of a small share
of generation might already face higher control costs, higher
transaction costs, and less flexibility regarding compliance options.
    Moreover, the use of allowance market power to manipulate prices
could have wider impacts on electricity markets as a whole, electricity
prices, and electricity reliability both within and across state
borders. Therefore, the State Budgets/Intrastate Trading approach needs
to address the potential for excessive market power and ensure that
allowances would be available to all covered sources at reasonable
market prices.
    In order to address the potential market power issue, under this
option, not all allowances would be allocated using the allocation
method described above in section V.D.4. Rather, a small portion of
allowances would be withheld from companies with a large share of a
state's total fossil-fuel fired electricity generation. These
allowances would be made available for purchase by companies with a
small share of generation through an annual auction.
    EPA is soliciting comments on whether a potential market power
problem could arise or reasons why market manipulation would not be a
concern under this alternative remedy. EPA is also soliciting comments
on whether the approach of using an annual auction to make allowances
available to small generators would satisfactorily address this
potential issue. This approach is detailed in subsection (3) below.
    The approach described for new unit set-asides and allocations to
non-operating units above for State Budgets/Limited Trading in section
V.D.4 would remain the same for this option.
(3) Auction of Emissions Allowances
    The use of an annual allowance auction would ensure that companies
with a small market share in a state would have access to additional
allowances, if needed, other than through direct purchase from a large
owner of generation and would reduce the opportunity for market price
manipulation by dominant companies. This means that EPA would hold a
total of 82 auctions every year to separately auction SO2
and NOX ozone season and NOX annual allowances in
each of the 82 intrastate trading programs. The auction format would be
single-round, uniform-price, sealed bid with an initial reserve price
of 70 to 80 percent of the modeled allowance price. Reserve prices
would be updated at regular intervals to reflect changes in average
market prices over time. Any unsold allowances would be returned to the
sources from which they were withheld on a proportional basis. Revenues
from the auctions would be deposited in the U.S. Treasury, in
accordance with 31 U.S.C. 3302.
    EPA would use auctions to address market power concerns rather than
other options it considered. The Agency considered using a different
allowance allocation method that would take into account an owner's
share of total generation and distribute proportionally more allowances
to owners of a small share of the total generation in each state. This
would also ensure that small owners had sufficient allowances without
relying on the open markets. However, EPA opted to use an allocation
methodology based directly on the approach used to quantify each
state's significant contribution to ensure that a direct link exists
between allocations and significant contribution to nonattainment or
interference with maintenance. EPA also considered direct sales of
allowances withheld from dominant sources but believes that auctions
would be better suited for determining the appropriate prices for
allowances than EPA would be at setting fixed allowance prices for all
trading programs in all states. For these reasons, EPA believes the use
of auctions would be the best method to address the issue of potential
allowance market manipulation.
    EPA prefers to use the single-round, uniform-price, sealed bid
format because it is simple for all participants to understand,
relatively simple to implement and administer, and deters collusion
among bidders. In addition, the utility sector already is familiar with
this type of format, and EPA has several years of experience running
single-round, sealed-bid auctions for Title IV SO2
allowances. Other formats considered such as multi-round auctions are
believed to be more complicated for participants to understand and more
complex to administer and do not discourage collusion.
    Entities that meet the following criteria would be eligible to
participate in the allowance auction: (1) They are required to hold
allowances in the state for compliance; and (2) they own no more than
10 percent of the total fossil-fuel fired generation within the state
based on EPA's modeled generation for 2014. EPA considered a range from
5 to 20 percent share of ownership for all states and believes that 10
percent ownership is appropriate for determining what constitutes a
small market share for this rule. EPA believes that by limiting the
auction to entities that own no more than 10 percent of the fossil-fuel
fired generation in a state, it would ensure that each auction has
enough participants to make auctions viable and competitive and also
ensure that the allowances are available only to those companies that
may be at a disadvantage in the open markets. Companies with more than
a 10 percent share of generation tend to operate several units, have
more flexibility, receive a significant share of allowances, and face
lower control and transaction costs. EPA is requesting comment on the
share of electric generation used as a threshold for determining
participation in auctions and also the percentage of allowances
available through auctions.
    To implement this option, EPA would withhold 2 to 5 percent of the
allowances that would be allocated to companies with more than 10
percent of the generation in order to supply allowances for auction
each period. This amount is small enough not to have a significant
impact on those EGUs from which the allowances are withheld and large
enough to provide a sufficient number of allowances for auction. In
more highly concentrated states where few companies control much of the
generation, a relatively greater number of allowances would be
available through the auction to the smaller, potentially disadvantaged
companies. Conversely, in states where the electricity sector is less
concentrated, there is less threat of market manipulation and greater
likelihood of liquid markets. Thus, in these states relatively fewer
allowances would be withheld for auction.
    Another variation on this alternative option would be to divide
companies in each state into three groups, instead of

just two. The first group would be the companies that own no more than
10 percent of the total fossil-fuel generation within the state and
would be able to participate in EPA's allowance auctions. The second
group would be companies that own a medium amount of fossil-fuel fired
generation (for example, between 10 to 20 percent of the total). These
companies would not be allowed to participate in auctions but also
would not have to contribute any allowances to the auctions. Finally,
the third group would be those remaining companies that own a large
share of fossil-fuel generation (for example, more than 20 percent of
the total). A small percentage of the allowances allocated to these
companies would be withheld to supply the auctions. EPA is asking for
comments on this variation on the alternative option and other ways to
address potential market power problems and on this alternative option.
(4) Allowance Management System
    The allowance management system for the State Budgets/Intrastate
Trading option would be consistent with the allowance management system
for the State Budgets/Limited Trading programs described above, and
with the data system structure EPA has developed for allowance
management under its existing cap and trade programs such as the CAIR
and the Acid Rain Program.
(5) Monitoring and Reporting
    Monitoring and reporting provisions would require complete,
quality-assured monitoring, and timely reporting of emissions to assure
accountability and provide public access to data, and would be the same
for EPA's proposed remedy and the State Budgets/Intrastate Trading
option. Refer to section V.D.4 above for detailed discussion on
monitoring and reporting requirements.
(6) Penalties
    Under the State Budgets/Intrastate Trading option for an annual
control program (i.e., any of the 28 SO2 or 28
NOX annual programs), the requirement that each source hold
in its compliance account one allowance for each ton of emissions, and
the penalties for failure to meet this requirement, would be the same
as described previously in the Penalties section for the State Budgets/
Limited Trading remedy option. However, because sources in a given
state can only use allowances issued for that state, the penalties
associated with failure to hold one allowance for each ton of emissions
are adequate to ensure that emissions from the state do not exceed the
state budget (except for some temporal variability due to banking). For
this reason, EPA does not believe that any other penalties or assurance
provisions (such as the assurance provisions used in the State Budgets/
Limited Trading remedy) are necessary to ensure that each state
eliminates the portion of significant contribution and interference
with maintenance that EPA has identified in today's action. EPA
requests comment on this conclusion.
c. How the State Budgets/Intrastate Trading Remedy is Consistent With
the Court's Opinions
    The state budgets/intrastate trading remedy, by establishing state-
specific caps on annual or ozone-season EGU emissions, directly
implements the section 110(a)(2)(D)(i)(I) requirement that emissions
from sources that contribute significantly to nonattainment in, or
interfere with maintenance by, any other state with respect to any such
national primary or secondary ambient air quality standard be
prohibited. Of the three remedy options considered, this option
provides the most certainty regarding total annual or ozone-season
emissions from each state. For this reason, it most directly addresses
the statutory mandate that the emissions reductions occur ``within the
State.''
    To implement this remedy option, EPA would use the state budgets
without variability limits, developed in accordance with the procedures
described in sections IV.D and IV.E. These budgets represent EPA's
projection of each affected state's EGU emissions in an average year
(before accounting for the inherent variability in power system
operations) after the elimination of all emissions that EPA has
identified as significantly contributing to nonattainment or
interference with maintenance.
    The number of allowances in each state budget would be distributed
or made available (through an auction or otherwise) to sources in that
state. Only allowances distributed or made available to sources in a
particular state could be used by sources in that state to satisfy the
requirement to hold one allowance for every ton of emissions. Thus,
annual (or ozone season) emissions in the state would be capped at the
level of the state budget. The limited variability due to banking of
emissions could allow limited temporal shifting of emissions, but would
not alter the requirement that reductions occur within the state. This
remedy is thus sufficient to ensure that all significant contribution
and interference with maintenance identified by EPA in today's action
is eliminated.
d. Electric Reliability Issues
    EPA requests comments about whether the State Budgets/Intrastate
Trading alternative option could have adverse consequences for electric
reliability. The grid regions, and the movement of electricity within
each grid region, do not correspond with, and are not limited by, state
borders. For example, an increase in electricity demand (e.g., due to a
hot summer), or a decrease in electricity supply (e.g., due to a major
generation capacity outage), in a given state will not necessarily be
met, or offset, through increased electricity generation in that same
state. Instead, the increased demand or reduced supply may well result
in increased generation outside that state. The sources of the
increased generation will be determined by availability and economics
and will not necessarily be confined to generation sources in that
state. In fact, the ability to obtain additional or replacement supply
from sources in another part of the state or from another state
enhances electric reliability.
    Although companies in one state obtain electricity from sources in
multiple states, the State Budgets/Intrastate Trading option would
establish emissions budgets on a state basis and would not allow
sources in one state to use allowances issued to sources in other
states. A source could use, in covering emissions for the current year,
both allowances allocated for the current year and banked allowances
issued by its state for a past year. However, this option would provide
sources less trading flexibility than the proposed State Budgets/
Limited Trading remedy. The other remedy options allow for emissions
variability, which should largely address electric reliability
concerns.
    EPA requests comment on whether the State Budgets/Intrastate
Trading alternative would provide sufficient flexibility for reliable
operation of the integrated grid and, if not, whether there would be
ways of preventing or reducing adverse effects such as including
additional emissions variability provisions in this option or other
approaches. EPA requests comment on approaches to provide additional
emissions variability, or other approaches to increasing flexibility,
in this option that would be consistent with eliminating all or part of
the significant contribution and interference with maintenance that EPA
has identified.

e. How Smaller Market Trading Programs Have Worked
    These examples of small trading programs below are relevant to
further understanding of the State Budgets/Intrastate Trading remedy
option. While small trading programs can succeed, they can also have
serious consequences for allowance and electricity markets. Budgets and
caps, allowance availability, and prices all can have a profound impact
on generation and energy prices for consumers in addition to any air
quality benefits. In addition, states range in size and number of
potential program participants making each state's circumstances unique
and more challenging for EPA to monitor.
(1) Texas Mass Emissions Cap and Trade (MECT)
    EPA has approved a NOX cap and trade program as part of
an ozone attainment SIP for the Houston Galveston Brazoria (HGB)
nonattainment area in Texas. The program knows as the Mass Emissions
Cap and Trade (MECT) program establishes a mandatory NOX
annual emissions cap for stationary facilities in the HGB area located
at sites with a collective uncontrolled design capacity to emit 10 tons
per year or more of NOX. The MECT program source population
is relatively small but very diverse and covers, among others, EGUs,
refineries, chemical plants, and industrial and commercial boilers. The
diverse source population allows the MECT program to be a viable means
of reducing NOX emissions without impacting electric
reliability. Overall, the MECT program has not encountered major
problems caused by its small size and has resulted in environmental
benefits for the HGB area.
    The MECT program establishes a hard cap for NOX
emissions at a level modeled as necessary for the area to reach ozone
attainment. The MECT program started January 1, 2002 and the
NOX cap stepped down each subsequent year until reaching the
final cap level of 80 percent of the baseline NOX emissions
in January 2007. In the MECT program one allowance is equivalent to one
ton of NOX emissions. Allowances are allocated to existing
facilities on January 1 of each control period, which spans the
calendar year. Facilities that do not receive allowances as ``existing
facilities'' (those in operation at the time of program inception) must
purchase excess allowances from other covered sources to operate and
demonstrate compliance. All covered sources are required to hold
sufficient allowances at the end of each control period to equal
NOX emissions during the same time period. Allowances can be
used in the control period of allocation, traded to another covered
source in the MECT for use in the same time period, or banked for use
in the following control period.
    Allowances can be traded in one of four ways: Vintage trades,
current year trades, individual future year trades, or stream trades.
Vintage trades involve the immediate transfer of vintage allowances.
Current year trades involve the immediate transfer of current
allowances. Individual future year and stream trades involve the
transfer of future allowances, with stream trades involving a transfer
of allowances in perpetuity. Analysis conducted by the Texas Commission
on Environmental Quality of the MECT program trading history shows that
approximately 20 percent of the allowances allocated each year are
traded and that nearly 50 percent of all program participants have
participated in allowance trading. Allowance prices are set by market
demand. Prices of individual year allowances have steadily increased as
the program has progressed, showing that the value of the allowances
increases as the cap tightens. Stream trade prices have fluctuated
throughout the program, but have steadily increased as the final cap
level has been reached.
(2) Regional Clean Air Incentives Market (RECLAIM)
    In comparison to MECT, RECLAIM is a small trading program that has
faced a number of challenges due to initial program design decisions.
In 1994, RECLAIM established a cap and trade program for NOX
and SO2 emissions as part of an effort to improve air
quality in the Los Angeles area. Every year the caps decline to meet
the objective of getting the area into compliance with ozone and
particulate matter NAAQS. One noteworthy feature of the RECLAIM trading
programs is the two overlapping cycles. Roughly equal numbers of
facilities were assigned to each of the two compliance cycles.
Facilities in compliance cycle 1 complete their twelve month cycle at
the end of the calendar year (December 31), while facilities in
compliance cycle 2 complete their twelve-month cycle at the end of the
fiscal year (June 30). Around 300 facilities have participated annually
in the RECLAIM NOX trading program. Every facility then
complied using valid credits of either cycle, but banking of allowances
for use in a later period was not allowed.
    RECLAIM Trading Credits (RTC) prices for NOX rose from
about $3,000 per ton early in 2000 to nearly $20,000 per ton in June
and up to about $70,000 per ton in August of that year. Prices of RTCs
during the California energy crisis during 2000 and 2001 averaged in
the $50,000 per ton range.\102\ While the California crisis was the
result of several malfunctions in the market, the RTC price spike was
exacerbated by a number of factors starting with the fact that few
emissions reductions had been made in earlier years. Prior to the
California crisis, RTCs had been over-allocated, RTC prices had
remained low, and utilities had taken little action to install costly
controls. When emissions increased and exceeded the level of allocated
RTCs, prices shot up to very high levels. In addition, there has been
speculation that high RTC prices at the time were partly caused by the
high demand for credits resulting directly from the manipulation of the
power market by generators.\103\
---------------------------------------------------------------------------

    \102\ Joskow, Paul and Edward Kahn, 2002. A Quantitative
Analysis of Pricing Behavior In California's Wholesale Electricity
Market During Summer 2000: The Final Word.
    \103\ Kolstad, Jonathan T. and Frank A. Wolak, 2003. Using
Environmental Emissions Permit Prices to Raise Electricity Prices:
Evidence from the California Electricity Market. Published by
University of California Energy Institute.
---------------------------------------------------------------------------

    The operation of the RECLAIM market also contributed to the high
prices in the overall power markets. During this period, generators
would pay excessively high prices for RTCs in order to raise the price
of southern California generation needed to meet demand in the
California Independent System Operator (CAISO). Subsequently,
generation with high RTC costs in the RECLAIM area would be used to set
the electricity price for all of California. The result was that
generators could then collect excessive profits on their generation
located outside the RECLAIM area. In addition, RECLAIM's overlapping
compliance cycles and assignment of facilities to one of two compliance
cycles appears to have contributed to some confusion among the
participants in the markets.\104\ Since that time, significant changes
have been adopted to improve the program.
---------------------------------------------------------------------------

    \104\ Holland, Stephen P. and Michael Moore, 2008. When to
Pollute, When to Abate? Intertemporal Permit Use in the Los Angeles
NOX Market. Published by University of California Energy
Institute.
---------------------------------------------------------------------------

    According to the audit report for the 2007 compliance period, total
aggregate NOX emissions were below total allocations by 21
percent and total aggregate SOX emissions were below total allocations
by 13 percent. Since January 2008, NOX RTCs prices have been
declining and have not exceeded $15,000 per ton.

f. Why This Is Not the Preferred Option
    As explained above, EPA is requesting comment on a State Budgets/
Intrastate Trading remedy as an alternative option because this option
would provide certainty regarding emissions from each state. However,
this option would be more resource intensive, more complex, less
flexible, and potentially more susceptible to market manipulation than
the other options on which EPA is taking comment.
    Although this remedy may be perceived as relatively easy to
understand and follow, it would actually be more burdensome to
administer due to the number of trading programs that would be required
to operate simultaneously and annual auctions that would be held every
year to address the issues of market power within states. It would also
result in a greater burden for participants operating EGUs in several
states. Finally, EPA is asking for comment on whether this option
raises electric reliability issues since sources would have less
flexibility and fewer options for compliance. EPA is requesting
comments on this approach, specifically on alterations that could
address the drawbacks identified above or on any other weaknesses of
this option not identified by EPA. EPA also welcomes comments regarding
the validity of the concerns with this approach identified above.
6. Direct Control Remedy Option
    The second alternative option on which EPA is requesting comment is
the direct control option described in this section. EPA is considering
the relative merits of this option and requests comment on whether a
direct control remedy option should be included in the final FIPs.
    There are a variety of ways to construct a direct control option.
The approach that EPA is presenting as an alternative to the remedy in
the proposed FIPs would assign emissions rate limits to individual
sources. Emissions limits would take the form of input-based emissions
rate limits (lb/mmBtu).
    EPA requests comments on the direct control remedy summarized later
and the approach for determining emissions rate limits, which is
described in greater detail in the ``State Budgets, Unit Allocations,
and Unit Emissions Rates'' TSD in the docket for this rulemaking.
Specifically, EPA requests comment on the general use of a direct
control remedy as well as the specific rate-based direct control
approach described later. EPA also requests comment on the potential
weakness of this remedy option identified in the discussion later. In
addition, EPA requests comment on alternate methodologies which could
be used to implement a direct control remedy.
    See section V.E. later for projected costs and emissions associated
with this option.
a. Description of Option
    Unlike the proposed remedy option (State Budgets/Limited Trading)
and the other alternative remedy option (Intrastate Trading) discussed
previously, which both use flexible cap-and-trade approaches, a direct
control remedy would directly regulate individual sources. Under this
direct control remedy alternative, each owner of EGUs would be required
to meet specified average emissions rate limits covering all of its
EGUs in each covered state. In a state covered for the 24-hour and/or
annual PM2.5 NAAQS, the direct control remedy option would
require each company within the state to meet specified EGU annual
emissions rate limits for SO2 and NOX. In a state
covered for the 8-hour ozone NAAQS, this remedy would require each
company within the state to meet specified EGU ozone season emissions
rate limits for NOX. EPA would set emissions rates on a
unit-by-unit basis in all covered states (see approach to determine
emissions rate limits, later).
    While emissions rates in all states would be set on a unit-by-unit
level, a company would be allowed to average the emissions at its units
within each state to meet the specified within-the-state rate limits.
Company-level average rates would be calculated as company-level total
emissions divided by company-level total heat input in each state.
Analogously, allowable company-level average rates would be calculated
using unit-specific rate limits and the heat inputs used to determine
those allowable rates (as discussed in 6.b.1). A company that exceeded
the applicable average rate limits would be subject to penalties
(described later).
    In addition, to address the potential variability in annual
emissions associated with emissions rate limits (i.e., not all years
are average), starting in 2012, each state's total annual (or ozone
season, as applicable) EGU emissions would also be capped. Emissions
from EGUs in each state would be limited to the state's emissions
budget with the variability limit. Each state's EGU emissions would be
capped in the following two ways. First, the state's EGU emissions
would not be permitted to exceed the state budget with the state's 1-
year variability limit in any year (or ozone season, as applicable).
Second, on average, the state's EGU emissions would not be permitted to
exceed the budget with the state's 3-year variability limit, evaluated
as a 3-year rolling annual (or ozone season) average (or, in
SO2 group 1 states during 2012 and 2013, a 2-year rolling
average). See section IV.E for lists of each state's emissions budgets.
Section IV.F describes EPA's proposed approach to variability. Tables
IV.F-1 through IV.F-3 present 1-year and 3-year variability limits.
Table IV.F-4 presents 1-year and 2-year variability limits for
SO2 group 1 states during 2012 and 2013.
    If total EGU emissions in a state exceed either of these limits
(i.e., budget with 1-year variability limit in any year, or budget with
2-or 3-year variability limit on average), then each company with units
in the state whose emissions in the state exceeded the company's share
of the state budget with variability limit would be subject to a
penalty. These assurance provisions are designed to assure that
emissions in each covered state do not exceed the state's budget with
variability limit. They are described later. EPA also believes the
penalty provisions described later are sufficient to ensure that these
caps would not be exceeded.
    To implement this remedy option, EPA would determine unit-level
emissions rate limits for SO2, NOX annual, and
NOX ozone season at levels such that, if the units operated
at the levels assumed in determining the state budgets, total emissions
of each pollutant from these units would sum to each state's emissions
budget for the pollutant without the variability limit. The method for
determining these rate limits is described later.
    An alternative direct control approach would be to create
individual unit-level annual emissions caps (e.g., tons/year) in order
to cap emissions in each state. However, this approach would greatly
limit operational flexibility and increase risk to electric
reliability. For example, a unit-level annual emissions cap approach
could prevent a peaking unit from running at a time when the unit is
necessary for electric reliability. EPA does not believe that a unit-
level annual emissions cap approach is workable.
b. How the Option Would Be Implemented
(1) Approach To Determine Emissions Rate Limits
    To implement this remedy option, EPA would determine unit-level
emissions rate limits for SO2, NOX annual, and
NOX ozone season, for covered EGUs in the covered states.

Emissions rate limits would be set at levels such that, if the units
operated at the levels assumed in determining the state budgets, total
emissions from these units would sum to the state budgets. In a state
covered for purposes of the PM2.5 NAAQS, EPA would determine
SO2 and NOX annual emissions rate limits for each
covered EGU. In a state covered for purposes of the 8-hour ozone NAAQS,
EPA would determine NOX ozone season emissions rate limits
for each covered EGU.
    Emissions rate limits for Phase I (2012 and 2013). State budgets
were derived from the lower of available 2007-2009 quarterly emissions
or IPM base case projections for 2012, at the state level. Analogous to
state budget calculation, EPA would base the Phase I annual emissions
rate limit on either the unit's reported annual emissions rate or the
IPM projected rate. Rates based on reported data would be calculated
using the most recent first, second, third, and fourth quarters of
emissions data reported to EPA, between the first quarter of 2007 and
the third quarter of 2009, where four such quarters of reported data
are available. EPA would determine ozone season rates based on a unit's
most recent ozone season emissions reported to EPA during the period of
2007-2009, if available, and projections or source-specific judgments
otherwise.
    For units where EPA is aware that SO2 or NOX
controls will be installed by 2012 and such controls were not reflected
in the unit's reported emissions rate as determined previously (i.e.,
the control was not in operation during the period of time on which
emissions limits were based), EPA would determine the Phase I emissions
rate limit as the historic rate adjusted (reduced) to reflect operation
of the planned control equipment at an emissions rate consistent with
operation of that equipment. Emissions rate limits would be determined
based on the assumption that units operate all existing SO2
and NOX control equipment, and the assumption that the type
of fuel used does not change from that used in determining the
unadjusted rate limit.
    For those EGUs which did not report a first, second, third, and
fourth quarter of SO2, NOX, and/or a complete
ozone season of NOX emissions data to EPA during the 2007-
2009 period, or for those units located in states where budgets are
based on IPM projections, EPA would determine emissions rate limits
based on modeling projections. Based on the analysis conducted for this
proposed rule, EPA would use modeling projections to determine
SO2 rates for approximately 1,600 units, annual
NOX rates for 1,800 units, and ozone season NOX
rates for 1,900 units. EPA seeks comment on the ability of all such
units to achieve these limits based on IPM projections. See table
entitled ``Phase I and Phase II unit-level emission rate limits''
located in the ``State Budgets, Unit Allocations, and Unit Emissions
Rates'' TSD in the docket for this rulemaking.
    For those units that did not report data for a given pollutant and
time frame combination and also were not included in IPM modeling, EPA
would need to determine permissible rates based on unit characteristics
(e.g., types and sizes of units, fuel type). The approach would also
need to take into account the variety of controls and measures that can
be used to limit emissions, including available fuels. While EPA does
not believe that such units exist, EPA is taking comment on the
existence of units that did not report first, second, third, and fourth
quarter data to EPA between the first quarter of 2007 and the third
quarter of 2009, and are not included in IPM modeling. If EPA is made
aware of such units, the unit-level analysis required to establish such
limits would be extremely complex, and could impact the ability of EPA
to require the reductions as quickly as under other remedy approaches.
    EPA is also taking comment on an alternative approach for setting
emissions rate limits for those units which did not report a first,
second, third, and fourth quarter of SO2, NOX,
and/or a complete ozone season of NOX emissions data to EPA
during the 2007-2009 period. In this alternative approach, EPA could
develop specific limits that would apply to a large group of units with
varying characteristics. The numerous variables that contribute to
differences in units'' emissions rates complicate development of limits
for a large group of units. Therefore, to ensure that all units in a
broadly-defined group could achieve their rate limits, it would be
necessary to either establish limits that are fairly weak so that the
poorest-performing units could meet the requirements (``lowest-common-
denominator'' effect), or, design more stringent requirements but
include provisions for exceptions to the requirements. At this time,
EPA believes using IPM projections and source-specific judgments is
preferable to the alternative of group-based limits, and seeks comments
on this alternative.
    Emissions rate limits for Phase II (2014 and onward). For EGUs in
states that are in SO2 group 1 (i.e., the more stringent
SO2 group), EPA would further adjust (reduce) SO2
emissions rates for certain EGUs that EPA projects would install FGD in
modeling of the proposed remedy option (at less than $2000 per ton);
for such units EPA would determine emissions rate limits at rates
consistent with FGD operation. For other covered units, Phase II
emissions rate limits would be the same as Phase I limits. Again,
emissions rate limits would be determined based on the assumption that
units operate all existing SO2 and NOX control
equipment, and that the type of fuel used does not change from that
used in determining the unadjusted rate limit. Note that for ozone
season NOX there is only one phase.
    Emissions rate limits for new units. The emissions rate limits for
covered new units would be set equal to the permit rates for these
units.
    EPA has calculated specific emissions rate limits for each existing
unit that would be covered under this direct control remedy option.
These unit-level emissions rate limits appear in a table entitled
``Phase I and Phase II unit-level emissions rate limits'' located in
the ``State Budgets, Unit Allocations, and Unit Emissions Rates'' TSD
in the docket for this rulemaking. More detailed description of the
approach is also provided in the TSD. EPA is requesting comment on this
approach for determining the emissions rate limits described in the TSD
and on the limits themselves.
(2) Applicability
    Applicability would be the same for all three remedies. Refer to
section V.D.4 previously for detailed discussion on applicability.
(3) Monitoring and Reporting
    Monitoring provisions would be the same for all three remedies. The
direct control option would require minor changes to the reporting and
record keeping requirements due to the need to collect information on
both emissions rates and mass. The provisions would require complete,
accurate measurement and timely reporting of emissions to assure
accountability and provide public access to data. Refer to section
V.D.4 previously for detailed discussion on monitoring and reporting
requirements.
(4) Assurance Provisions
    As discussed previously, starting in 2012, the direct control
remedy alternative would include assurance provisions designed to
assure that emissions in each covered state do not exceed the state's
emissions budget with variability limit. The state's EGU emissions
would not be permitted to

exceed the state budget with 1-year variability limit in any year (or
ozone season, as applicable). Additionally, on a 3-year rolling average
basis, the state's EGU emissions would not be permitted to exceed the
budget with the 3-year variability limit (evaluated on an annual or
ozone season basis, as appropriate). Furthermore, during 2012 and 2013,
SO2 emissions from EGUs in group 1 states (i.e., the more
stringent SO2 group) would not be permitted to exceed the
budget with the state's 2-year variability limit, evaluated as a 2-year
rolling annual average. Section IV.E in this preamble lists each
state's emissions budget, and section IV.F lists the 1-, 2-, and 3-year
variability limits, as applicable.
    Note that for EGUs in states that are in SO2 group 2
(i.e., the less stringent SO2 group) and/or states required
to reduce NOX emissions, EPA would apply only the 1-year
variability limit in 2012 and 2013, and not a 2-year variability limit.
Because emissions would be evaluated against the 3-year variability
limit on a 3-year rolling average basis, the application of the 3-year
variability limit in 2014 would also serve to limit emissions in 2012
and 2013. For EGUs in SO2 group 1 states (i.e., the more
stringent SO2 group) EPA would apply a different 1-year
SO2 variability limit in 2012 and 2013 than for 2014 and
later. Furthermore, in these group 1 states, EPA would apply a 2-year
SO2 variability limit in 2012 and 2013, and a 3-year limit
for later years (section IV.F discusses why variability limits for the
group 1 states would differ in 2012 and 2013).
    If total EGU emissions in a state exceed either the state's budget
with 1-year variability limit in any year, or budget with 3-year
variability limit (or 2-year limit, as appropriate) on average, then
each company with units in the state whose emissions in the state
exceeded its share of the state budget with variability limit would be
subject to a penalty for its share of emissions above the budget with
variability limit.
    In the State Budgets/Limited Trading remedy described previously,
the proposed assurance provisions include an allowance surrender
requirement. Those assurance provisions would require a company to
surrender one allowance for each ton of the company's proportional
share of the amount the state's EGU emissions exceed the budget with
variability limit. This allowance surrender requirement is in addition
to the trading program requirement to surrender one allowance for every
ton emitted.
    In the direct control alternative, however, allowances are not
allocated to units therefore an allowance surrender requirement is not
feasible. Instead, for this alternative, a company with emissions over
its share of the budget with variability limit would be in violation of
the CAA and subject to discretionary penalties. The tonnage amount of
the company's violation, i.e., the company's excess emissions under the
assurance provisions, would be its proportional share of the amount
that the state's EGU emissions exceed the budget with the variability
limit. Each ton of the company's excess emissions, as well as each day
in the averaging period, would be a violation.
    In this direct control remedy alternative, a company's share of the
state budget with variability limit would be determined using the same
approach described in the State Budgets/Limited Trading option,
previously. That approach is based on allowance allocations; although
the direct control remedy would not allocate allowances to sources,
this remedy would use the allocation method described in State Budgets/
Limited Trading in determining a company's share of the state budget.
    The assurance provisions would commence in 2012 for this direct
control option. In contrast and for the reasons explained in section
V.D.4, for the proposed State Budgets/Limited Trading remedy, EPA is
proposing to start applying the assurance provisions in 2014. The
combination of circumstances for State Budgets/Limited Trading--known
locations of controls and a price on each ton emitted--provides greater
certainty of where reductions will occur during 2012 and 2013 than
would be provided by the direct control program. In contrast to the
State Budgets/Limited Trading remedy, the direct control program does
not put a price on emitting SO2 or NOX so does
not provide that incentive to reduce emissions. Sources can increase
generation, while meeting the emissions rate limits, and increase their
emissions. For these reasons, the direct control program provides less
certainty regarding the location of emissions in the short term. For
this reason, EPA believes that it would be appropriate to apply the
assurance provisions under this remedy option beginning in 2012.
    EPA requests comment on these assurance provisions.
(5) Penalties
    As explained previously, under this direct control remedy approach,
each owner of EGUs within a covered state would be required to meet
specified average emissions rate limits for SO2 and/or
NOX emission for all of its EGUs. For the annual
SO2 or NOX control programs, if a company were to
exceed the applicable company-wide annual average rate limit, the
company would be in violation of the CAA and subject to discretionary
civil penalties.
    The excess emissions of the owner's EGUs would be calculated as the
EGUs'' actual annual average emissions rate minus the applicable annual
average emissions rate limit, with the difference multiplied by the
EGUs'' total actual annual heat input. Each ton of excess emissions, as
well as each day in the averaging period (e.g., 365 days for an annual
program), would be a violation of the CAA. The maximum discretionary
penalty under CAA Section 113 is $25,000 (inflation-adjusted to $37,500
for 2009) per violation.
    For the ozone season NOX program, the penalty provisions
would work in the same manner described herein except on an ozone
season basis rather than annual.
    In addition, any company with EGU emissions exceeding its share of
the state budget with variability limit for SO2,
NOX annual or NOX ozone season would also be in
violation of the CAA and subject to discretionary civil penalties
explained earlier in this section if, in any year (or ozone season, as
applicable), the state as a whole exceeds its budget with variability
limit (see description of assurance provisions, previously).
    EPA requests comment on the penalty provisions.
c. How the Direct Control Remedy Is Consistent With the Court's
Opinions
    The direct control remedy option would implement the section
110(a)(2)(D)(i)(I) requirement that ``emissions from sources that
contribute significantly and interfere with maintenance in downwind
nonattainment areas'' be prohibited. It would do so by establishing for
covered EGUs specific emissions rate limits, with company-wide within
state averaging. Emissions rates in all states would be set on a unit-
by-unit basis at levels such that, if the units operated at the levels
assumed in determining the state budgets, total emissions from these
units would sum to each state's emissions budgets without the
variability limits. A company could average the emissions at its units
within each state to meet specified within-the-state rate limits. This
approach would directly limit emissions from EGUs in each covered
state, providing assurance that emissions reductions would occur within
each state consistent with the mandate of section 110(a)(2)(D)(i)(I).

    Because individual EGUs would be required to meet specific
emissions rate limits (with within-state company-wide averaging), this
option would ensure that required controls and measures are installed
and implemented within the state. The fact that emissions, after
implementation of all controls required to meet the emissions rate
limits, may vary based on the amount of generation in each state is not
inconsistent with the section 110(a)(2)(D)(i)(I) requirement that all
significant contribution and interference with maintenance be
eliminated. As noted previously, changes in generation due to changing
meteorology, demand growth, or disruptions in electricity supply from
other units can all affect the amount of generation needed in a
specific state and thus the baseline emissions from that state. Because
baseline emissions are variable, emissions after the elimination of all
significant contribution are also somewhat variable.
    Further, any such variation in emissions would be limited. As with
the State Budgets/Limited Trading option described previously, no
state's EGU emissions would be permitted to exceed the state budget
with variability limit in any year (or ozone season, as applicable).
Nor would any state's EGU emissions be permitted, on average, to exceed
the budget plus a specified portion of the state's variability limit,
evaluated as a 3-year rolling annual (or ozone season) average (or, in
SO2 group 1 states during 2012-2013, a 2-year rolling annual
average). Section IV in this preamble lists each state's emissions
budget, and 1-, 2-, and 3-year variability limit, as applicable.
d. Electric Reliability Issues
    The risk to electric reliability is considered low under the direct
control remedy option. Specifically, the provisions for the variability
limits and company averaging within each state help to alleviate
electric reliability concerns. Therefore, EGUs are expected to be able
to both comply with their emissions rate limits and reliably provide
electricity to customers. EPA requests comment on electric reliability
issues.
e. Why This Is Not the Preferred Option
    As explained previously, EPA is requesting comment on the merits
and weaknesses of this direct control remedy option. EPA did not
include this remedy option in the proposed FIPs; however, we continue
to consider this option and are taking comment on whether this option
should be included in the FIPs. This option would provide assurance
that companies in each state are meeting specific emissions rate limits
and would also ensure that annual emissions from each state are capped.
Additionally, the direct control option may be perceived as easy to
understand and follow. Nonetheless, at this time, EPA believes the
direct control option is inferior to the preferred approach. EPA
requests comments on the validity of EPA's concerns regarding this
option and alternative methods for addressing those concerns.
    EPA modeling projects fewer emissions reductions under the direct
control alternative than the proposed State Budgets/Limited Trading
remedy. Additionally, the reductions would be achieved at a higher cost
than the proposed remedy. See section V.E. for projected costs and
emissions.
    A direct control program must account for outliers, e.g., units
that can not install controls due to space limitations. EPA believes
that the within-the-state company-wide averaging in the direct control
alternative on which EPA is taking comment likely mitigates this
concern. However, this averaging approach may put an owner with a small
number of units within a state at a disadvantage compared to an owner
with a larger number of units. EPA requests comment on this issue.
    Within the direct control approach on which EPA is taking comment,
the assurance provisions (which limit a company's emissions within a
state to its share of the budget with the variability limit if the
state's budget with variability limit is exceeded) may also put an
owner with a small number of units at a disadvantage compared to an
owner with a larger number of units within a state. EPA seeks comment
on this issue.
    A direct control program based on emissions rate limits does not
cap annual emissions; if there is growth in fossil generation within a
state, a rate-based approach alone could allow emissions increases. In
the direct control approach on which EPA requests comment, the
assurance provisions provide some assurance of achieving required
reductions.
    Notably, the direct control approach described herein restricts
compliance options more than a trading approach. EPA generally believes
that granting more flexibility to companies in meeting an emissions
reductions goal results in the ability of those companies to meet that
goal at a lower cost and decreases reliability risks in the electric
power system. While some portion of this effect is captured in IPM
modeling (see section V.E. for projected costs and emissions), some
types of unforeseen innovations in technology, fuel switching, and
management cannot be captured by modeling. Any potential innovations
and resulting cost savings are more likely to be found and utilized in
the presence of regulatory flexibility. Based on historical experience,
EPA believes that the benefits offered by a flexible trading approach
are large and should be considered qualitatively, even if they cannot
be quantified. Many of these benefits would be foregone under the
direct control approach.

E. Projected Costs and Emissions for Each Remedy Option

    Emission and cost projections for the three remedies discussed
previously come from the Integrated Planning Model (IPM), a dynamic
linear programming model of electric generation in the contiguous U.S.
For each remedy, projected costs relative to the base case appear in
Table V.E-1. The following section explains these projections in light
of how the remedies differ and how they were represented in the model.
The emissions projections below comprise fossil generation above 25
megawatts of capacity, the units that would be subject to the rule.
More detail on the modeling of costs and emissions can be found in the
Regulatory Impact Analysis for the proposed Transport Rule and in the
IPM Documentation.

 Table V.E-1--Projected Incremental Costs Due to Transport Rule Remedies
           Compared to Baseline Without Transport Rule or CAIR
                         [Billion 2006 dollars]
------------------------------------------------------------------------
                                           2012    2014    2020    2025
------------------------------------------------------------------------
Limited Interstate Trading (proposed)...     3.7     2.8     2.0     2.0
Intrastate Trading......................     4.2     2.7     2.2     2.2
Direct Control..........................     4.3     3.4     2.5     2.3
------------------------------------------------------------------------

1. State Budgets/Limited Trading
    The proposed remedy of State Budgets/Limited Trading was modeled
with regional emissions caps beginning in 2012 and state-specific
emissions limits beginning in 2014. The state-specific emissions limits
represent state budgets plus 3-year average variability limits. Because
banking early reductions beyond the budget levels is allowed, 2012
SO2 reductions are greater overall than state budgets alone
would require in that year. Table V.E-2 shows the projected emissions
reductions from this remedy.

 Table V.E-2--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the Transport Rule Compared to Baseline Without
                                                                 Transport Rule or CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               2012 base case    2012 transport    2012 emissions    2014 base case    2014 transport    2014 emissions
                                                  emissions      rule emissions      reductions         emissions      rule emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.........................................               8.4               3.4               5.0               7.2               2.6               4.6
Annual NOX..................................               2.0               1.3               0.7               2.0               1.3               0.7
Ozone Season NOX............................               0.7               0.6               0.1               0.7               0.6               0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. State Budgets/Intrastate Trading
    Though based on the same state budgets as State Budgets/Limited
trading, the alternative remedy of State Budgets/Intrastate Trading
costs approximately 0.5 billion 2006 dollars more in 2012 and achieves
slightly more SO2 reduction in 2012 (and slightly less in
2014), as Table V.E-3 shows. In modeling this remedy, each state's
emissions were restricted to the state budget without variability.
Without the opportunity for even limited trading of allowances across
state borders, more banking was projected in some states. In other
states, more immediate emissions reductions (relative to the base case)
are projected so that state budgets are met exactly. Both of these
factors drive 2012 costs higher than those of limited interstate
trading and lead to slightly greater SO2 reductions in 2012.

    Table V.E-3--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the Intrastate Trading Alternative Remedy
                                                   Compared to Baseline Without Transport Rule or CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               2012 base case    2012 transport    2012 emissions    2014 base case    2014 transport    2014 emissions
                                                  emissions      rule emissions      reductions         emissions      rule emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.........................................               8.4               3.2               5.2               7.2               2.7               4.5
Annual NOX..................................               2.0               1.3               0.7               2.0               1.2               0.8
Ozone Season NOX............................               0.7               0.6               0.1               0.7               0.6               0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

3. Direct Control
    The direct control alternative remedy consists of source-specific
emissions rate limits commensurate with those used in the derivation of
state budgets (see sections IV.D and IV.E). To represent assurance
provisions, the emissions from each state were also constrained to the
state's budget plus 3-year average variability limit beginning in 2012.
For states with more stringent SO2 budgets in 2014, FGD
retrofits were required on units shown to have cost-effective retrofit
opportunities at $2,000 per ton.
    Compared to the proposed remedy of State Budgets/Limited Trading,
the direct control alternative costs approximately 0.6 billion 2006
dollars more and results in less SO2 reduction in 2012, as
shown in Table V.E-4. Unlike remedies allowing banking for early
reductions, the direct control alternative does not result in
reductions below state budgets in 2012. At the same time, meeting
specific rate requirements for every source means there is little
incentive to achieve additional reductions with fuel switching.

 Table V.E-4--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the Direct Control Alternative Remedy Compared
                                                       to Baseline Without Transport Rule or CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               2012 base case    2012 transport    2012 emissions    2014 base case    2014 transport    2014 emissions
                                                  emissions      rule emissions      reductions         emissions      rule emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.........................................               8.4               3.8               4.6               7.2               2.6               4.6
Annual NOX..................................               2.0               1.3               0.7               2.0               1.2               0.8
Ozone Season NOX............................               0.7               0.6               0.1               0.7               0.6               0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

4. State-Level Emissions Projections
    Tables V.E-5, V.E-6, and V.E-7 show projected emissions at the
state level from all EGUs in 2014.
---------------------------------------------------------------------------

    \105\ The modeling presented in Tables V.E-5, V.E-6, and V.E-7
differs from the proposed Transport Rule because the District of
Columbia (DC) is included neither in the annual SO2 and
NOX requirements nor in the ozone season NOX
requirement. Modeled units in DC include two small facilities, one
of which has only units below 25 MW capacity. EPA believes the
addition of emissions limits in DC would have little to no effect on
the modeling results.

          Table V.E-5--Projected State-level \105\ SO2 Emissions From Electric Generating Units in 2014
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                               State budgets/
                                              Base case      State budgets/      intrastate      Direct control
                                                             limited trading       trading
----------------------------------------------------------------------------------------------------------------
Alabama.................................           322,362           172,430           162,103           172,430
Connecticut.............................             6,160             3,234             3,208             3,208
Delaware................................             8,079             9,185             8,974             9,110
District of Columbia....................               176               179               180               180
Florida.................................           194,723           139,805           159,120           135,366
Georgia.................................           173,257            92,375            89,706            92,375
Illinois................................           200,484           164,741           156,049           163,902
Indiana.................................           804,425           240,730           267,564           239,852
Iowa....................................           163,966           102,419           102,096           106,569
Kansas..................................            65,125            51,248            52,501            53,275
Kentucky................................           739,595           123,837           128,318           123,833
Louisiana...............................            94,866            94,933            92,647            96,390
Maryland................................            45,294            45,449            45,304            45,752
Massachusetts...........................            17,265            10,306             8,595             8,909
Michigan................................           275,961           173,828           188,796           172,986
Minnesota...............................            62,033            49,413            49,836            58,925
Missouri................................           500,649           192,645           190,815           190,532
Nebraska................................           115,695            75,095            73,219            75,061
New Jersey..............................            39,721            16,562            14,935            16,569
New York................................           142,762            58,455            53,373            58,455
North Carolina..........................           140,924            97,262           109,385            97,262
Ohio....................................           841,199           232,964           269,547           228,514
Pennsylvania............................           974,644           154,852           183,276           154,855
South Carolina..........................           156,200           131,232           123,525           131,232
Tennessee...............................           600,071           106,767           100,012            94,078
Virginia................................           136,573            58,329            51,633            58,330
West Virginia...........................           496,307           127,646           147,580           127,646
Wisconsin...............................           117,397            85,933            87,328            83,709
----------------------------------------------------------------------------------------------------------------

         Table V.E-6--Projected State-Level Annual NOX Emissions From Electric Generating Units in 2014
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                               State budgets/
                                              Base case      State budgets/      intrastate      Direct control
                                                             limited trading       trading
----------------------------------------------------------------------------------------------------------------
Alabama.................................           118,955            61,793            61,618            61,865
Connecticut.............................             7,991             8,003             7,986             8,004
Delaware................................             5,790             6,176             6,126             6,074
District of Columbia....................               933               946               948               948
Florida.................................           196,373           126,155           126,065            94,646
Georgia.................................            48,267            44,461            44,462            44,611
Illinois................................            80,451            57,589            54,773            57,949
Indiana.................................           201,027           112,502           112,721           108,675
Iowa....................................            68,259            53,072            50,146            52,069
Kansas..................................            79,018            40,020            40,074            39,558
Kentucky................................           148,551            71,371            71,692            69,882
Louisiana...............................            45,551            37,255            36,594            37,164
Maryland................................            36,089            36,326            33,778            36,532
Massachusetts...........................            12,650            13,047            12,219            13,064
Michigan................................            98,941            65,066            65,973            67,525
Minnesota...............................            55,283            38,969            39,114            38,039
Missouri................................            83,019            67,475            61,679            67,648
Nebraska................................            53,029            35,101            34,105            35,457
New Jersey..............................            27,127            23,377            23,358            23,338
New York................................            36,352            36,592            34,538            36,597
North Carolina..........................            62,608            60,516            54,639            60,517
Ohio....................................           164,947            99,358            95,997           100,886
Pennsylvania............................           204,950           123,629           123,095           123,409

South Carolina..........................            47,742            34,735            33,781            34,616
Tennessee...............................            68,914            28,212            26,874            28,873
Virginia................................            37,485            35,805            35,745            37,004
West Virginia...........................           100,095            48,180            48,987            50,555
Wisconsin...............................            54,515            41,875            42,498            42,450
----------------------------------------------------------------------------------------------------------------

      Table V.E-7--Projected State-Level Ozone-Season NOX Emissions From Electric Generating Units in 2014
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                               State budgets/
                                              Base case      State budgets/      intrastate      Direct control
                                                             limited trading       trading
----------------------------------------------------------------------------------------------------------------
Alabama.................................            26,995            26,727            26,552            26,823
Arkansas................................            21,667            12,080            12,095            12,077
Connecticut.............................             3,446             3,453             3,446             3,446
Delaware................................             2,367             2,669             2,671             2,613
District of Columbia....................               391               397               397               398
Florida.................................            94,686            62,221            62,037            48,170
Georgia.................................            21,947            19,686            19,688            19,749
Illinois................................            24,167            24,930            22,833            24,701
Indiana.................................            49,023            47,477            47,813            45,589
Kansas..................................            34,537            17,470            17,590            17,282
Kentucky................................            29,927            29,376            29,671            29,107
Louisiana...............................            21,443            17,388            17,106            17,308
Maryland................................            15,307            15,454            14,275            15,512
Michigan................................            29,934            27,778            28,052            29,415
Mississippi.............................            16,955             8,524             8,526             8,522
New Jersey..............................            10,470            10,324            10,295            10,260
New York................................            17,257            17,493            16,518            17,491
North Carolina..........................            27,018            26,117            23,459            26,004
Ohio....................................            44,753            41,141            40,051            42,789
Oklahoma................................            38,546            24,471            24,471            24,426
Pennsylvania............................            53,263            53,102            52,692            52,586
South Carolina..........................            15,730            14,818            14,666            14,753
Tennessee...............................            12,021            11,868            10,955            12,007
Texas...................................            79,572            68,769            68,874            67,832
Virginia................................            16,264            15,397            15,289            16,093
West Virginia...........................            24,339            20,249            21,466            21,500
----------------------------------------------------------------------------------------------------------------

F. Transition From the CAIR Cap and Trade Programs To Proposed Programs

    This proposed Transport Rule would replace the CAIR rule and its
associated trading programs. This section elaborates on some of the
areas of the CAIR program that would need to be addressed in the
transition to the new program. EPA is taking comment on how the
transition would occur.
1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs
    The CAIR, CAIR SIPs, and CAIR FIPs would be replaced entirely by
the Transport Rule provisions. If this proposed Transport Rule is
finalized in 2011, the CAIR, CAIR SIPs, and CAIR FIPs would sunset at
the completion of all 2011 control period activities.
    In order to implement the sunsetting of the CAIR and CAIR FIPs, the
proposed rule includes several revisions of the CAIR, Sec. Sec.  51.123
and 51.124, and the CAIR FIPs, Sec. Sec.  52.35 and 52.36. First,
sunsetting the CAIR and CAIR FIPs in 2011 would mean that the
requirements of the CAIR and CAIR FIPs would not apply to control
periods after 2011. Specifically, the CAIR would be revised to rescind,
with regard to any control period beginning after December 31, 2011,
the findings that states must revise their SIPs to meet CAIR
requirements. Similarly, the CAIR FIPs would be revised to state that,
with regard to any post-December 31, 2011 control period, CAIR FIP
requirements would not be applicable.
    Second, the sunsetting in 2011 would mean that the CAIR trading
programs would not continue past 2011. Consequently, the proposed
revisions of the CAIR and CAIR FIPs would state that, with regard to
any post-December 31, 2011 control period, the Administrator would not
carry out any of the functions established for the Administrator in the
CAIR model trading rule, the CAIR FIPs, or any state trading programs
approved under the CAIR.
    Third, the sunsetting in 2011 would mean that CAIR allowances
allocated for control periods after 2011--which have already been
recorded by the Administrator in the Allowance Management System
compliance accounts of sources in many states--would not be usable in
the CAIR trading programs for control periods ending before 2012.
Specifically, under the existing CAIR trading programs, a source that
fails to hold sufficient allowances to cover emissions for the 2011
control period (whether annual or ozone season) must provide for
surrender to the Administrator three allowances (one as an offset and
two as an automatic penalty) allocated for the 2012 control period for
every one

allowance that was not held as required. However, consistent with the
proposed termination of the CAIR trading programs for control periods
after 2011, EPA believes that allowances allocated for such control
periods (e.g., 2012 allowances) should not be usable for any purpose.
In any event, because such allowances would have little or no market
value, their deduction would impose little or no cost on the party
holding them. Consequently, the proposed revisions of the CAIR and CAIR
FIPs would state that the Administrator would not deduct, for excess
emissions, any CAIR allowances allocated for control periods in 2012 or
any year thereafter. These revisions would ensure that no CAIR
allowances allocated for post-2011 control periods would be used as an
offset of, or an automatic penalty for, excess emissions.
    As a result of these proposed revisions of the CAIR and CAIR FIP
rules, there would be no offset or automatic penalty deducted for a
source that failed to hold sufficient allowances to cover its 2011
control period emissions unless the state SIPs are revised. In order to
preserve the deductions for offsets and automatic penalties for 2011
control periods, the CAIR SIPs for most states (i.e., 20 out of the 28
states subject to at least one CAIR trading program) would need to be
modified and the modified CAIR SIPs would need to be approved by the
EPA ---before EPA conducts the process of determining source compliance
after the allowance transfer deadline for the 2011 control periods --in
order to change the allocation year of the allowances required to be
deducted (e.g., from allowances allocated for 2012 to allowances
allocated for 2011). Although EPA's past experience with trading
programs strongly suggests that few sources would be out of compliance
with the requirement to hold allowances covering 2011 emissions, all of
these CAIR SIPs would have to be revised because there is no way to
predict which few sources in which few states might be out of
compliance in 2011 and the process of revising SIPs is too long to be
started while EPA is still determining compliance. In fact, when states
needed to revise their SIPs to include the existing requirements of
CAIR and submit the revised SIPS to the Administrator, EPA found that
states needed up to 3 years to develop and submit SIP revisions, and
EPA needed about 6 months to act on the SIP revisions. In light of this
experience with SIP revisions under CAIR, EPA believes that it would
highly unlikely that all, or even most, state CAIR SIPs could be
revised, submitted, and approved in time--even if the SIP revision
process were started when a final Transport Rule is promulgated--to
change what allowances were to be used for offsets and automatic
penalties for excess emissions for the 2011 control periods.
    Moreover, any excess emissions for the 2011 control periods would
be violations of the state SIPs (or of CAIR FIPs in those states with
CAIR FIPs) and of the Clean Air Act and, therefore would be subject to
discretionary civil penalties under CAA Section 113. Each ton of excess
emissions, and each day in the control period involved (i.e., 365 days
for annual control periods and 153 days for the ozone season control
period), would be a violation, with a maximum penalty of $25,000
(inflation adjusted to $37,500) per violation. In determining what
level of discretionary civil penalties to impose on a source that has
excess emissions violations, EPA routinely considers, among other
things, whether, and if so what level of, other penalties (e.g.,
automatic excess emissions penalties) have already been imposed for the
same violations, as well as any economic benefit of noncompliance
(e.g., the avoidance of the cost of surrendering allowances to cover
emissions). See, e.g., 42 U.S.C. 7413(e)(1) (including, as penalty
assessment criteria, ``payment by the violator of penalties previously
assessed for the same violation'' and ``the economic benefit of
noncompliance''). Consequently, EPA believes that, regarding the CAIR
2011 control periods (both annual and ozone season) for which it is not
feasible to change the offset and automatic penalty provisions to make
them workable, the potential for assessment of significant,
discretionary civil penalties would provide a strong incentive for
compliance with the allowance-holding requirement and avoidance of
excess emissions.
    In addition to the previously-described, proposed revisions to
Sec. Sec.  51.123, 51.124, 52.35, and 52.36, certain provisions in part
52 that reflect, state by state, the CAIR SIP revisions and CAIR FIP
requirements applicable to each state would need to be revised to
implement the sunsetting of the CAIR, CAIR SIPs, and CAIR FIPs.
However, the timing for proposal and adoption of revisions to part 52
is necessarily different for the part 52 provisions addressing CAIR SIP
revisions and those addressing revisions of the CAIR and the CAIR FIPs
themselves.
    The part 52 provisions addressing CAIR SIP revisions for the
individual states reflect EPA's approval of CAIR SIP revisions adopted
and submitted to EPA by the respective states. The first step toward
sunsetting those part 52 provisions would be that, if and after the
proposed Transport Rule was finalized, the respective states would
change their SIPs in order to, among other things, make the CAIR
provisions in the SIPs inapplicable to any control period that starts
after December 31, 2011. After the submittal by the respective states
of these SIP revisions, EPA would review and approve such changes.
Consequently, the rule text approving such CAIR SIP revisions would not
be included in either the proposed Transport Rule or any final rule
based on the proposed Transport Rule, but rather would be proposed and
adopted only after the respective states revised their SIPs. As EPA did
when transitioning from the NOX Budget Trading Program to
the CAIR NOX ozone season trading program, EPA will work
with states to transition from state CAIR programs to their replacement
FIPs or state SIPs. This assistance will be provided through meetings
or workshops, web-based references, one-on-one assistance through the
EPA regions, etc.
    In contrast, the part 52 provisions adopting CAIR FIPs for
individual states could be revised, as part of the proposed Transport
Rule, to sunset these CAIR FIPs because no state action would be
required to accomplish this sunsetting. EPA proposes to revise each
state-specific part 52 provision adopting a CAIR FIP--whether for
NOX annual or ozone season emissions or SO2
emissions--to add a paragraph stating that: with regard to any control
period starting after December 31, 2011, the respective CAIR FIP would
not apply and the Administrator would not carry out any of the
functions set forth for the Administrator in the trading program rules
under the CAIR FIP; and the Administrator would not deduct for excess
emissions any CAIR allowances allocated for 2012 or any year
thereafter. The new, added rule text would be very similar to the
proposed rule text revisions to Sec. Sec.  52.35 and 52.36 and would be
essentially the same for each of these state-specific Part 52
provisions. EPA has included in the proposed Transport Rule the
proposed rule text making these state-by-state revisions for Delaware,
District of Columbia, Indiana, Louisiana, Michigan, New Jersey,
Tennessee, Texas, and Wisconsin. These provisions revise all of the
state-specific Part 52 provisions adopting CAIR FIPs provisions to make
the CAIR FIPs inapplicable to any control period that

starts after December 31, 2011 and state that the Administrator would
not carry out any functions under the CAIR trading programs during any
such control period and would not use any CAIR allowances allocated for
any such control period.
2. Change in States Covered
    The states covered by the proposed Transport Rule differ slightly
from states covered by the CAIR. Namely, as compared with the states
covered by the CAIR NOX ozone season trading program, the
states covered by the proposed Transport Rule NOX ozone
season trading program would include Georgia, Kansas, Oklahoma, and
Texas and would not include Iowa, Massachusetts, Missouri, and
Wisconsin. Further, as compared with the states covered by the CAIR
NOX annual and SO2 trading programs, the states
covered by the proposed Transport Rule NOX Annual and
SO2 trading programs would include Connecticut, Kansas,
Massachusetts, Minnesota, and Nebraska and would not include
Mississippi and Texas. (See also the discussion in section IV.D.
regarding the possibility that the states to which this rule would
apply could expand.)
    Consequently, sources in some states that would be covered by the
proposed Transport Rule would have new allowance holding requirements
beginning in 2012, but would not have been subject to the CAIR trading
programs. Conversely, sources in some states covered by the CAIR or
CAIR FIPs would not be subject to the proposed Transport Rule. To the
extent that the CAIR reductions were needed or relied upon to satisfy
other SIP requirements, states might need to find alternative ways to
satisfy requirements for their SIPs. EPA will work with individual
states to identify state-specific options to ensure that necessary
reductions needed for other SIP requirements can continue.
3. Applicability, CAIR Opt-ins and NOX SIP Call Units
    Except for the changes in the states covered, the general
applicability provisions of the proposed Transport Rule would be
essentially the same as the CAIR general applicability provisions, with
a few exceptions. First, the proposed Transport Rule does not allow any
units to opt into the trading programs. In contrast, under CAIR, states
could elect to allow boilers, combustion turbines, and other combustion
devices to opt into the CAIR trading programs under opt-in provisions
specified by EPA, and a number of states adopted these opt-in
provisions. However, currently no units have opted into the CAIR
trading programs, and, even in the Acid Rain Program, where opt-in
provisions have been in place since 1995, very few units have actually
opted in.
    Second, under the CAIR trading programs, a state subject to the
NOX SIP Call was allowed to expand the applicability of the
CAIR NOX ozone season trading program in the state in order
to include all units subject to the NOX Budget Trading
Program (NBP) under the NOX SIP Call and thereby to continue
to meet the state's NOX SIP Call requirements. Fourteen
states chose to expand the CAIR NOX ozone season
applicability in this way, while six states chose not to expand the
applicability and instead to meet their NOX SIP Call
obligations in other ways. In expanding the applicability of the CAIR
NOX ozone season trading program, the fourteen states
brought into the program large industrial boilers and turbines (with
maximum design heat input greater than 250 mmBtu/ hr) and, in some
cases, smaller electric generating units (serving generators with
nameplate capacity of 15 through 25 MWe), and generally the CAIR
NOX ozone season budgets in these states were increased to
account for these additional sources. In contrast, the proposed
Transport Rule NOX ozone season trading program would not
allow for expansion of applicability to include these units currently
covered only by the NBP.
    There are several factors underlying this difference between the
proposed Transport Rule and the CAIR. First, in determining which
states are contributing significantly or interfering with maintenance
of the ozone NAAQS, the Transport Rule does not cover some states
subject to the NOX SIP Call (i.e., Massachusetts, Missouri,
and Rhode Island). Further, the six states that chose under the CAIR to
require the necessary NOX SIP Call reductions through
provisions other than the CAIR NOX ozone season program
would not likely be interested in expanding applicability under the
Transport Rule NOX ozone season trading program to cover
these units. In addition, EPA has determined that these units as a
group did not actually reduce emissions as a result of the NBP or
through their inclusion in the CAIR NOX ozone season trading
program. In fact, their current emissions rates are nearly identical to
what they were before the NBP started. Moreover, these units as a group
had allowances that they did not need for compliance and that were
available for trading to other affected units. The Transport Rule, as
proposed, does not include these units and does not include provisions
for allowing states expand applicability to include them. EPA is taking
comment on this approach.
4. Early Reduction Provisions
    Substantial emissions reductions have occurred as a result of the
CAIR programs. These reductions are greater than were expected when the
rule was promulgated. This is evidenced in the banks of allowances that
exist in each of the CAIR programs.
a. SO2 Allowance Bank
    The bank of Title IV allowances was more than 12 million tons at
the end of 2009. This bank is the result of emissions reductions for
Title IV where allowances are used for compliance with the requirement
to hold allowances covering emissions and early reductions for the CAIR
SO2 trading program. EPA believes that it is advantageous to
minimize sources'' use of the Title IV allowance bank if possible and
recognizes that, if the bank has minimal future market value, there may
be incentive to use as many banked allowances as possible. EPA tracks
the SO2 emissions on a quarterly basis and makes the
information available to the public at http://epa.gov/airmarkets/
quarterlytracking.html.
    EPA evaluated whether the Title IV allowance bank could be used in
the proposed Transport Rule SO2 program in any way. One idea
presented to EPA was to distribute Transport Rule SO2
allowances based on the number of Title IV allowances a source has in
its bank at the completion of compliance in the last year of the CAIR
SO2 program, thereby incentivizing minimal use, by sources,
of Title IV allowance banks and encouraging continued emission control.
EPA is concerned that the approach would have significant legal risk
for two reasons. First, the Court is likely to view the approach as
imposing a significant burden on the use of Title IV allowances and
therefore as modifying the authorization provided by such allowances.
Second, the Court is likely to view the approach as not related to,
much less necessary for, implementation of the section
110(a)(2)(D)(i)(I) mandate to eliminate significant contribution and
interference with maintenance. EPA chose instead, under the proposed
Transport Rule, to distribute Transport Rule SO2 allowances
in a manner directly linked to its calculation of each state's
significant contribution and interference with maintenance and not to
use Title IV allowances as a basis for distributing the new Transport
Rule allowances. EPA is confident that the approach

selected is consistent with the Court's opinion in North Carolina v.
EPA, 531 F.3d 896, 922 (D.C. Cir. 2008). (Additional information on
this approach can be found in the docket.) EPA requests comment on
whether or not an allowance distribution approach based on the number
of Title IV allowances in a given source's account would be consistent
with the Court opinion.
    EPA proposes that the Transport Rule provisions not allow the use
of Title IV allowances either as the basis for allocating Transport
Rule SO2 allowances or directly for compliance with
allowance-holding requirements. Thus, there would be no SO2
allowances carried over into the new SO2 program. Title IV
allowances continue, of course, to be used for compliance with the Acid
Rain Program.
b. NOX Allowance Banks
    Assuming that NOX emissions in 2010 and 2011 are equal
to what they were in 2009, the CAIR NOX ozone season bank
would contain over 600,000 allowances (which would equal more than 100
percent of the total of the state budgets under the proposed Transport
Rule NOX ozone season program for 2012), and the CAIR
NOX annual bank would contain about 720,000 allowances
(which would equal nearly 50 percent of the total of the state budgets
under the proposed Transport Rule NOX annual program for
2012), after completion of true-up of allowance holdings and emissions
for 2011. Estimates of the size of the banks have only recently been
made based on reported 2009 emissions data, and the impacts of
different approaches to handling the banks have not yet been modeled.
However, EPA is concerned about the potential impacts of these
approaches. On one hand, allowing pre-2012 CAIR NOX
allowances and CAIR NOX ozone season allowances to be used
in the proposed Transport Rule NOX programs, and thereby
ensuring that the allowances would continue to have some market value
in the future, would promote the continuation--in 2010 and 2011--of the
reductions that occurred in 2009 under the CAIR NOX
programs. On the other hand, the amounts of the banks are so large that
they might significantly reduce the amount of emissions reductions that
would otherwise be achieved in the proposed Transport Rule
NOX programs, particularly in the earlier years (e.g., 2012
and 2013).
    EPA has identified several possible approaches for handling banked
pre-2012 CAIR NOX allowances in the Transport Rule
NOX programs. The first approach might be to allow all such
banked CAIR allowances to be brought into the Transport Rule
NOX programs, make the assurance provisions effective
starting in 2012, and rely on the assurance provisions to ensure that
each state continues to eliminate all of the significant contribution
and interference with maintenance that EPA has identified in today's
proposal. The banked CAIR allowances would be usable, and the assurance
provisions would apply, in all states in the Transport Rule
NOX programs. However, EPA is concerned that some parties
may view this approach as having the effect of allowing sources that
were advantaged by the development of state budgets using fuel
adjustment factors--the use of which was reversed by the Court in North
Carolina, 531 F.3d at 918-21--and that still hold part of their
allocated allowances to continue have an advantage in the Transport
Rule NOX trading programs. These concerns may be mitigated
somewhat by the fact that even though the methodology used to divide
the regional budget into state budgets used fuel factors, states had
the flexibility to allocate allowances however they wished. EPA takes
comment on the extent to which states have allocated differently and
the extent to which this may mitigate concerns about allowing the use
of banked CAIR NOX allowances in the Transport Rule annual
NOX and ozone season NOX trading programs.
    The second approach might be to allow only a limited amount of
banked pre-2012 CAIR allowances to be brought into the Transport Rule
programs. This could be accomplished by allowing all such banked
allowances to be used, but at a tonnage authorization level
significantly lower than one ton per allowance, in the Transport Rule
NOX programs. However, while severely limiting the tonnage
authorization of banked allowances that is allowed into the new
programs would limit any advantage realized by sources that received
fuel-adjustment-factor-based CAIR allowance allocations, this would
also limit any beneficial impact that bringing CAIR allowances into the
new programs might have on preserving emissions reductions in 2010 and
2011.
    The third option might be to try to factor the bank into the
calculation of state budgets by reducing the state budgets to take
account of the banked pre-2012 CAIR allowances. This might allow these
allowances to be used in the Transport Rule NOX programs
without adversely affecting the states' elimination of the part of
significant contribution and interference with maintenance that EPA has
identified. However, this approach would not be feasible because EPA
cannot determine in advance in which states banked pre-2012 CAIR
allowances might be used and so would not know which state budgets
should be adjusted and what amount of adjustment would be necessary.
    A final approach would simply be to not allow the use of any banked
pre-2012 CAIR allowances in the Transport Rule NOX programs.
This approach would avoid the potential legal and practical problems
raised by the other approaches and is the approach proposed by EPA. EPA
requests comment on the proposed approach, the previously-discussed
alternative approaches, and any other possible approaches for handling
banked pre-2012 CAIR allowances in the Transport Rule NOX
programs.
5. Source Monitoring and Reporting
    Monitoring and reporting using 40 CFR part 75 provisions is
required for all units subject to the CAIR programs and would also be
required for all units subject to the proposed Transport Rule programs.
In states covered by both the CAIR and the proposed Transport Rule,
units would generally have no changes to their monitoring and reporting
requirements and would continue to monitor and submit reports as they
have under the CAIR. The exceptions are units in: CAIR states subject
to CAIR NOX ozone season requirements but NOX and
SO2 annual requirements under the proposed Transport Rule;
or CAIR states subject to CAIR NOX annual and ozone season
and SO2 requirements but only to NOX ozone season
requirements under the proposed Transport Rule. These exceptions could
arise, in part, because under Part 75 some units (i.e., non-Acid Rain
units) that are in NOX ozone season, and not NOX
annual, programs have the option of monitoring and reporting
NOX emissions for just the ozone season.
    Units in the following states monitor and report both
SO2 and NOX year-round under the CAIR and would
continue to do so under the Transport Rule: Alabama, Delaware, the
District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa,
Kentucky, Louisiana, Maryland, Michigan, Missouri, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Virginia, West Virginia, and Wisconsin. Non-Acid Rain units in Arkansas
are currently required to monitor and report NOX in the
ozone season under the CAIR and would continue to be required to do so
under the proposed Transport Rule.

    Non-Acid Rain units in Connecticut and Massachusetts (about 15
units total) that currently monitor and report NOX in the
ozone season would need to monitor and report NOX and
SO2 on an annual basis under the proposed Transport Rule.
    Non-Acid Rain units in Mississippi (about 4 units) and Texas (about
52 units) are currently monitoring and reporting NOX and
SO2 year-round and under the proposed Transport Rule would
be required to monitor and report NOX in the ozone season.
(All of these units burn natural gas and emitted approximately 12 tons
of SO2 in 2009.)
    In states not covered by the CAIR but covered by the proposed
Transport Rule, some units would have to meet new monitoring and
reporting requirements under part 75. Kansas, Minnesota, and Nebraska
are not covered by the CAIR and are covered by the Transport Rule, and
units there would need to monitor and report NOX and
SO2 emissions year-round. Oklahoma is not covered by the
CAIR and is covered by the Transport Rule, and units there would need
to monitor and report NOX in the ozone season. There are
about 34 non-Acid Rain units total in Kansas, Nebraska and Oklahoma not
monitoring and reporting under Part 75 that would need to begin to do
so. Most of these units are simple-cycle combustion turbines used in
the ozone season as peaking units and would likely be able to utilize
the Low Mass Emissions or Appendix D and E methodologies in 40 CFR part
75, which do not require a continuous emissions monitoring system
(CEMS). The circulating fluidized bed (CFB) units in Oklahoma (about 4
units) that burn coal are already monitoring and reporting under 40 CFR
part 60, subpart Da, which requires an SO2, NOX
and CO2/O2 (diluent) CEMS. These boilers would only have to add a flow
monitor and upgrade the automated data acquisition and handling system.
Non-Acid Rain units in Minnesota (about 20 units) would also need to
monitor and report, but were already doing so under the CAIR before the
CAIR was stayed in Minnesota (74 FR 56721, November 3, 2009);
therefore, they would simply have to reactivate those monitoring
systems.
    Units that have not been covered by part 75 monitoring and
reporting in the past would likely have less than one year to install,
certify, and operate the required monitoring systems. EPA believes that
these units would reasonably be able to comply with this requirement
because the monitoring equipment needed is not extensive or is largely
in place already for the purpose of meeting other requirements. Quality
assurance and reporting provisions and data system upgrades may be
necessary, but there would be sufficient time to accomplish this.

G. Interactions With Existing Title IV Program and NOX SIP Call

1. Title IV Interactions
    Promulgation of a Transport Rule would not affect any Acid Rain
Program requirements. Any Title IV sources that are subject to final
Transport Rule provisions would still need to continue to comply with
all Acid Rain provisions. Acid Rain requirements are established
independently in Title IV of the Clean Air Act and would not be
replaced by the Transport Rule. In contrast with the CAIR, the proposed
Transport Rule would not allow Title IV SO2 allowances to be
used in the Transport Rule program. Similarly, Transport Rule
SO2 allowances would not be useable in the Acid Rain
Program. Title IV SO2 and NOX requirements will
continue to apply independently of the Transport Rule provisions. The
Transport Rule program as proposed has no opt-in provisions, so no
sources, including any that have opted into the Acid Rain Program would
be able to opt-in to the Transport Rule program.
    Compliance with the Transport Rule would reduce SO2
emissions in the Transport Rule states below the 2010 Title IV cap. So,
as sources complied with the Transport Rule, emissions would go down
and with them so would the demand for Title IV allowances. Therefore,
the Title IV allowance prices are expected to be very low once the
Transport Rule is finalized; some analysts suggest a price of nearly
zero. Acid Rain sources will still be required to comply with Title IV
requirements, including the requirement to hold Title IV allowances to
cover emissions at the end of a compliance year.
    There would likely be changes to emissions at some Acid Rain
sources outside of the Transport Rule area as a result of the
transition from CAIR to the Transport Rule. Namely, emissions at some
non-Transport Rule Acid Rain sources may increase because of the change
in the Title IV allowance price. This would be expected to occur mainly
in the states that border the Transport Rule states. Overall,
SO2 emissions from these non-Transport Rule Acid Rain
sources would be expected to increase approximately 237,000 tons each
year if the Transport Rule is implemented compared to what they would
have been in the absence of the Transport Rule. There is more
discussion of this effect in section IV.D.
2. NOX SIP Call Interactions
    States affected by both the NOX SIP Call and any final
Transport Rule will be required to comply with the requirements of both
rules. The Transport Rule does not preempt or replace the requirements
of the NOX SIP Call. However, the proposed Transport Rule
ozone season program would achieve the emissions reductions required by
the NOX SIP Call from EGUs greater than 25 MW in nearly all
NOX SIP Call states. The NOX SIP Call states used
the NOX Budget Trading Program (NBP) to comply with the
NOX SIP Call requirements for EGUs serving a generator with
a nameplate capacity greater than 25 MW and large non-EGUs with a
maximum rated heat input capacity greater than 250 MMBTU/hr. (In some
states, EGUs smaller than 25 MW were also part of the NBP as a
carryover from the Ozone Transport Commission NOX Budget
Trading Program.) EPA stopped administering the NBP after the 2008
ozone season control period activities, and states used another
mechanism to comply with the NOX SIP Call requirements.
    Many of the states using the NBP used the CAIR NOX ozone
season trading program to replace the NBP. To address NOX
SIP Call requirements, fourteen NOX SIP Call states chose to
expand the CAIR NOX ozone season applicability to include
all NBP-affected units. EPA has analyzed the effect of allowing states
to expand their CAIR NOX ozone season applicability and
consequently their CAIR NOX ozone season budgets to include
the additional non-CAIR affected NBP units. In 2009, the additional
units emitted about half of the amount of allowances added to the CAIR
NOX ozone season budgets for them. The remaining allowances
are available for the sources to trade to other affected units. As a
group, these units did not reduce their NOX emissions or
their NOX emissions rates as a result of their inclusion in
the CAIR NOX ozone season program. If EPA were to allow them
to be part of the Transport Rule NOX Ozone Season Program,
and if states were allowed to increase the Transport Rule
NOX Ozone Season Budgets by the amounts allowed under the
NBP and CAIR for these units, a state's ability to eliminate the part
of significant contribution and interference with maintenance that EPA
has identified in today's proposal could be jeopardized. One option
considered that could possibly address concerns about still being able
to address significant contribution and interference with

maintenance would be to require the budget increase to be much less
than allowed under the NBP and CAIR. For example, the units' 2009
emissions (or 2012 projected emissions if they are required to install
controls for another program) could be used to determine the budget
increase and the elimination of emissions causing significant
contribution and interference with maintenance might be able to be
preserved. It is likely the budget changes would not be consistent
across states as each state's impact would have to be considered
individually. EPA is proposing to not allow the expansion of the
applicability of the Transport Rule.
    Therefore, the NBP states would need to achieve their
NOX SIP Call emissions reductions another way in order to
continue to comply with the NOX SIP Call. If EPA promulgates
a final rule that does not allow the expansion of the Transport Rule to
NBP units, any state that allowed these units to participate in the
CAIR NOX Ozone Season Program would need to submit a SIP
revision to address their NOX SIP Call requirement for the
reductions.
    States that were part of the CAIR NOX ozone season
program or the NBP that are not part of a final Transport Rule ozone
season program would need to submit SIP revisions that address the
NOX SIP Call requirements for any emissions reductions that
were part of either the CAIR NOX ozone season program or the
NBP and would not continue to be addressed some other way. EPA will
work with states to ensure that NOX SIP Call obligations
continue to be met.

VI. Stakeholder Outreach

    In early 2009, EPA began its efforts to coordinate activities with
state regulatory partners and other stakeholders on the new transport
rule to replace CAIR. To establish open lines of communication and
ensure transparency in the regulatory process, EPA participated in a
series of ``listening sessions'' in March and April, 2009 with states,
nongovernmental organizations, and industry. EPA also participated in
tribal teleconferences. The same agenda was set for each of the ten
meetings. Meeting notes were developed and distributed for concurrence
and to ensure accuracy. Subsequent to these sessions, EPA received
post-meeting comments and additional detailed suggestions and analyses
on ways to address some of the issues that the court cited, most
notably from state regional organizations in the eastern U.S. All the
stakeholder-related materials may be found in the EPA docket for the
transport rule (EPA-HQ-OAR-2009-0491).
    Following the remand of CAIR to EPA in December 2008, 17 states in
the East and Midwest, under the umbrellas of the OTC and Lake Michigan
Air Directors Consortium (LADCO) with support from southeastern states,
worked to develop recommendations for EPA to consider in crafting a new
transport rule to replace CAIR. The comprehensive framework presented
the consensus approach the states reached but noted that certain
regional differences would be addressed in separate letters with
additional recommendations and supporting materials.
    EPA has considered and appreciates all the ideas and
recommendations provided by the states. We are employing the technical
work that they submitted as part of the data set we are using in this
and later transport rules.
    Topics addressed in the listening sessions, where EPA asked
stakeholders and regulatory partners for their thoughts on particular
issues, included:
     Analysis and baselines.
     Linkages between a state's significant contribution and
downwind nonattainment/interference with maintenance.
     Remedies.
     Attainment planning.
     Other areas.
    EPA continued to provide updates to regulatory partners and
stakeholders through monthly conference calls with states, hosted by,
e.g., NACAA, as well as industry and NGO conferences where EPA
directors often made presentations.
    Several of the options presented in this proposal were influenced
by feedback received from stakeholders and regulatory partners,
including:
     2012 baseline used in the calculation of each state's
significant contribution and interference with maintenance.
     The ``tiered'' approach to SO2 emissions
reductions requirements.
     Threshold (1 percent of the NAAQS) used for linking upwind
areas to downwind nonattainment and maintenance receptors.
     Approach used to give independent meaning to the interfere
with maintenance prong of section 110(a)(2)(D)(i)(I).
     Level of reductions required.
     Use of limited interstate trading.
     Correlated and coordinated requirements and timing for the
power industry.
    EPA looks forward to the public comment period of this rulemaking
and is committed to establishing and maintaining close working
relationships with a broad range of public and private sector
organizations.

VII. State Implementation Plan Submissions

A. Section 110(a)(2)(D)(i) SIPs for the 1997 Ozone and PM2.5 NAAQS