Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NO_X SIP Call [[pp. 25211-25260]]

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: May 12, 2005 (Volume 70, Number 91)]
[Rules and Regulations]
[Page 25211-25260]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12my05-17]

[[pp. 25211-25260]]
Rule To Reduce Interstate Transport of Fine Particulate Matter
and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program;
Revisions to the NO_X SIP Call

[[Continued from page 25210]]
[[Page 25211]]
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(V) Cost Effectiveness of Ozone Season NO_X Reductions
The CAIR requires ozone season NO_X emissions reduction
for all States determined to contribute significantly to ozone
nonattainment downwind (25 States and the District of Columbia). The
EPA used IPM to model average and marginal costs of the ozone season
reductions assuming EGU controls. In this modeling case, EPA modeled an
ozone season NO_X cap for the region affected by CAIR for
downwind ozone nonattainment, but did not include the CAIR annual
SO₂ or NO_X caps. Based on that modeling, Table
IV-11 provides estimated average and marginal costs of regionwide ozone
season NO_X reductions for 2009 and 2015. Table IV-11 shows
the estimated cost effectiveness of today's ozone season NO_X
control requirements for 8-hour transport SIPs.

Table IV-11.--Estimated Costs per Ton of Ozone Season NOX Controlled
Under CAIR \1\
------------------------------------------------------------------------
Type of cost effectiveness 2009 2015
------------------------------------------------------------------------
Average Cost.......................................... $900 $1,800
Marginal Cost......................................... 2,400 3,000
------------------------------------------------------------------------
\1\ The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

These estimated NO_X control costs are based on ozone
season EGU NO_X caps of 0.6 million tons in 2009 and 0.5
million tons in 2015 within the CAIR ozone season NO_X
control region. Average costs shown for 2015 are based on the amount of
reductions that would achieve the total difference in projected
emissions between the base case conditions and CAIR in the year 2015.
These costs are not based on the increment in reductions between 2009
and 2015. (A more detailed description of the final CAIR SO₂
and NO_X control requirements is provided later in today's
preamble.)
The EPA believes that selecting as highly cost-effective amounts at
the lower end of the average and marginal cost ranges is appropriate
for reasons explained above in section IV in this preamble.
In the NO_X SIP Call, EPA identified average costs of
$2,500 (1999$) (or $2,000 (1990$)) as highly cost-effective.\67\ The
estimated average costs of regionwide ozone season NO_X
control under CAIR are $1,800 per ton in 2015 and $900 per ton in 2009.
Thus, with respect to average costs the controls for the final phase
(2015) cap, which are below the $2,500 identified in the NO_X
SIP Call, are also highly cost-effective, as are those for the 2009
cap. In addition, the estimated average costs of CAIR ozone season
NO_X control are at the lower end of the reference range of
average annual NO_X control costs (the reference list of
average annual NO_X control costs is presented above).
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\67\ For both the NO_X SIP Call and CAIR, the
NO_X control costs on the reference lists are generally
for annual reductions. The EPA compared the costs of ozone season
reductions under the NO_X SIP Call, as well as ozone
season CAIR NO_X reductions, to the annual reduction
programs on the reference lists.
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Similarly, the estimated marginal costs \68\ of ozone season CAIR
NO_X controls are within EPA's reference range of marginal
costs, at the lower end of the range (the reference list of marginal
annual NO_X control costs is presented above). We note that
the marginal costs in the reference range are for annual NO_X
reductions, and would likely be higher for ozone season only programs.
Considering both average and marginal costs, the CAIR ozone season
control level is highly cost-effective.
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\68\ In the NO_X SIP Call EPA used average, not
marginal, costs to evaluate cost effectiveness. For the reasons
discussed above we are evaluating both average and marginal costs for CAIR.
---------------------------------------------------------------------------

For purposes of estimating costs of ozone season control under
CAIR, EPA set up this modeling case with CAIR ozone season
NO_X requirements but without the annual NO_X
requirements. The Agency believes that the cost of the ozone season
CAIR requirements will actually be lower than the costs presented here
because interactions will occur between the CAIR annual and ozone
season NO_X control requirements.\69\ In addition, for States
in both programs, the same controls achieving annual reductions for PM
purposes will achieve ozone season reductions for ozone purposes; this
is not reflected in our cost-per-ton estimates.
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\69\ Estimated costs for regionwide CAIR NO_X controls
during the ozone season are higher than the average and marginal
costs for CAIR annual NO_X controls. This is because, as
noted above, the capital costs of installing NO_X control
equipment would be largely identical whether the SCR will be
operated during the ozone season only or for the entire year.
However, the amount of reductions would be less if the control
equipment were operated only during the ozone season compared to
annual operation.
---------------------------------------------------------------------------

As with SO₂ controls, and annual NO_X
controls, EPA also considered the cost effectiveness of alternative
stringency levels for CAIR NO_X reductions for ozone purposes
by examining changes in the marginal cost curve at varying levels of
emissions reductions. Figure IV-5 shows that the ``knee'' in the 2010
marginal cost effectiveness curve for ozone season NO_X
reductions from EGUs--the point where the cost of controlling an ozone
season ton of NO_X begins to increase at a noticeably higher
rate--appears to occur somewhere between $3,000 and $4,000 per ton of
NO_X. Although EPA conducted this marginal cost curve
analysis based on an initial NO_X control phase in 2010 the
results would be very similar for 2009, which is the initial
NO_X phase in the final CAIR. Figure IV-6 shows that the
``knee'' in the 2015 marginal cost effectiveness curve for ozone season
NO_X reductions from EGUs appears to occur somewhere between
$3,000 and $4,000 per ton of NO_X. The EPA used the
Technology Retrofitting Updating Model (TRUM), a spreadsheet model
based on the IPM, for this analysis. These results make clear that CAIR
NO_X reductions for ozone purposes are very cost-effective
because the control level is below the point at which the cost begins
to increase at a significantly higher rate.
In this manner, these results corroborate EPA's findings above
concerning the cost effectiveness of the emissions reductions.\70\
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\70\ EPA is using the knee in the curve analysis solely to show
that the required emissions reductions are very cost effective. The
marginal cost curve reflects only emissions reduction and cost
information, and not other considerations. We note that it might be
reasonable in a particular regulatory action to require emissions
reductions past the knee of the curve to reduce overall costs of
meeting the NAAQS or to achieve benefits that exceed costs. As in
the case of SO₂ controls, described above, it should be
noted that similar analysis for other source categories may yield
different curves.

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B. What Other Sources Did EPA Consider When Determining Emission
Reduction Requirements?

1. Potential Sources of Highly Cost-Effective Emissions Reductions
In today's rulemaking, EPA determines the amount of regionwide
emissions reductions required by determining the amount of emissions
reductions that could be achieved through the application of highly
cost-effective controls on certain EGUs. The EPA has reviewed other
source categories, but concludes that for purposes of today's
rulemaking, there is insufficient information to conclude that highly
cost-effective controls are available for other source categories.
a. Mobile and Area Sources
In the NPR (69 FR 4610), EPA explained that ``it did not identify
highly cost-effective controls on mobile or area sources.'' No comments
were received suggesting that mobile or area sources should be
controlled. Therefore, in developing emission reduction requirements,
EPA is not assuming any emissions reductions from mobile or area sources.
b. Non-EGU Boilers and Turbines
The largest single category of stationary source non-EGUs are large
non-EGU boilers and turbines. This

[[Page 25214]]

source category emits both SO₂ and NO_X. In the
CAIR NPR, EPA proposed not to include any potential SO₂ or
NO_X emissions reductions from non-EGU boilers and turbines
as constituting ``highly cost-effective'' reductions and thus to be
taken into account in establishing emissions requirements because EPA
believed it had insufficient information on their control costs,
particularly costs associated with the integration of NO_X
and SO₂ controls. In addition, based on information EPA does
have, projected base case (without the CAIR) emissions of
SO₂ and NO_X from these sources are significantly
lower than projected EGU emissions. The EPA projects that in 2010 under
base case conditions, EGUs would contribute 70 percent of
SO₂ in the CAIR region compared to 15 percent from non-EGU
boilers and turbines in the CAIR region. The Agency also predicts that
in 2010 under the base case, EGUs would contribute 25 percent of
NO_X emissions in the CAIR region compared to 16 percent from
non-EGU boilers and turbines in the CAIR region. Thus, simply on an
absolute basis, non-EGU emissions are relatively less significant than
emissions from EGUs. The EPA is finalizing its proposed approach to
these sources and has not based today's requirements on any presumed
availability of highly cost-effective emissions reductions from non-EGU
boilers and turbines.
A number of commenters believe EPA should determine that emissions
reductions from non-EGUs should be taken into account in establishing
emission requirements because, they believe, highly cost-effective
controls are available for these sources. These commenters argued that
highly cost-effective controls are available for these sources and that
EPA should have sufficient emissions and control cost information
because the same sources were included in the NO_X SIP Call.
In addition, while it is true that these sources were included in
the NO_X SIP Call, EPA only addressed NO_X
reductions from these sources. Neither SO₂ reductions nor
monitoring of SO₂ emissions is required by the
NO_X SIP Call. As a result, for these sources, EPA has less
reliable SO₂ emissions data and very little information on
the integration of NO_X and SO₂ controls. Although
EPA has more information on NO_X emissions from these sources
because of the NO_X SIP Call (and other programs in the
northeastern U.S.), the geographic coverage of the CAIR includes some
States that were not included in the NO_X SIP Call, some of
which States contain significant amounts of industry. The EPA has even
less emissions data from non-EGUs in these non-SIP call States affected
by the CAIR. While EPA has incorporated State-submitted emissions
inventory data for 1999 into its analysis for the CAIR, even this data
is generally lacking information on fuel, sulfur content, and existing
controls. Without this data, it is very difficult to assess the
emission reduction opportunities available for non-EGU boilers and
turbines. Furthermore, with regards to NO_X, many non-EGU
boilers and turbines are making reductions using low NO_X
burners (the control technology EPA assumed in making the cost-
effectiveness determinations in the NO_X SIP Call). Since
these controls are operated year-round, annual emissions reductions are
already being obtained from many of these units. Additional reductions
would likely be less cost effective.
Another commenter stated that non-EGU ``major sources'' are subject
to the requirements of title V of the CAA and, therefore, EPA should
have adequate emissions data provided as part of the sources'
permitting obligations. However, title V simply requires that a
source's permit include the substantive requirements (such as emission
monitoring requirements) imposed by other sections of the CAA and does
not itself impose any substantive requirements. Thus, the mere fact
that a source is a major source required to have a title V permit does
not mean that the source is monitoring and submitting emissions, fuel,
and control device data. Many such sources do not, in fact, provide
such data.
One commenter submitted cost information for FGD technology
applications on industrial boilers. However, the information submitted
by the commenter was based on the use of a limited number of
technologies and for a limited number of boiler sizes. The EPA does not
believe that the limited information demonstrates that SO₂
emissions from these sources could be controlled in a highly cost-
effective manner across the entire sector in question, or to what level
the emissions could be controlled.
Some commenters recommended including non-EGU boilers and turbines
because in the future, after reductions from EGUs are made, the
relative contribution of non-EGU boilers and turbines to the total
NO_X and SO₂ emissions will increase. The EPA
agrees that the relative contribution of non-EGUs to total
NO_X and SO₂ emissions will increase in the future
if States choose to meet their CAIR emissions reduction obligations
solely by way of emission reductions made by EGUs. However, EPA does
not believe that this, by itself, provides any basis for determining
that in the context of this rule emissions reductions from non-EGUs
should be determined to be highly cost-effective. As discussed above,
EPA believes it is necessary to have more reliable emissions data and
better control cost information for these sources before assuming
reductions from them in the CAIR. The EPA is working to improve its
inventory of emissions and control cost information for non-EGU boilers
and turbines. Specifically, we are assessing the emission inventory
submittals for 2002 made by States in response to the relatively new
requirements of 40 CFR part 51 (the Consolidated Emission Reporting
Rule), and we will work with States whose submissions appear to have
gaps in required data. We also note that EPA provides financial and
technical support for the efforts of the five Regional Planning
Organizations to coordinate among and assist States in improving
emission inventories.
Another commenter expressed concern that if the decision whether to
control large industrial boilers is left to the States, the result may
be inequitable treatment of EGUs on a State-by-State basis,
particularly with respect to allowances, and therefore it would make
sense to require NO_X and SO₂ reductions from
large industrial boilers. Section 110 of the CAA leaves the ultimate
choice of what sources to control to the States, and EPA cannot require
States to control non-EGUs. Even if EPA had included reductions from
non-EGUs in determining the total amount of reductions required under
the CAIR, EPA could not have required any State to achieve those
reductions through emission limitations on non-EGUs.
The recent economic circumstances faced by the manufacturing sector
accentuates EPA's concerns about the lack of reliable emissions data
and control information regarding non-EGUs. We note that the U.S.
manufacturing sector was adversely affected by the latest business
cycle slowdown. As noted in the 2004 Economic Report of the President,
the manufacturing sector was hit earlier, longer, and harder than other
sectors of the economy. The 2004 Report also points out that, although
manufacturing output has dropped much more than the real gross domestic
product (GDP) during past business cycles, the latest recovery has been
unusual because it has been weaker for the manufacturing sector than
the recovery in the real GDP. The disparity across sectors (and even
within individual sectors) in the economic condition of firms reinforces

[[Page 25215]]

EPA's concerns about moving forward to consider emission controls on
non-EGUs at this time.
As explained elsewhere in this preamble, although the CAIR does not
require that States achieve the required emissions reductions by
controlling particular source categories, we expect that States will
meet their CAIR obligations by requiring emissions reductions from EGUs
because such reductions are highly cost effective. We believe the
States are in the best position to make decisions regarding any
additional control requirements for non-EGU sources. In making such
decisions, States may take into consideration all relevant factors and
information, such as differences across States in the need for control,
differences in relative contribution of various sources, and
differences in the operating and economic conditions across sources.
c. Other Non-EGU Stationary Sources
In the NPR and in the technical support document entitled
``Identification and Discussion of Sources of Regional Point Source
NO_X and SO₂ Emissions Other Than EGUs (January
2004),'' EPA applied a similar rationale for non-EGU stationary sources
other than boilers and turbines. For SO₂, EPA noted that the
emissions from such sources were a relatively small part of the
emissions inventory, and we also noted the lack of information on
costs. For NO_X, we explained that more information was
available than for SO₂. This is because the NO_X
SIP Call included consideration of emissions control measures for
internal combustion (IC) engines and cement kilns, and developed cost
estimates for other NO_X-emitting categories such as process
heaters and glass manufacturing. However, we believed--as for boilers
and turbines, discussed above--that insufficient information on
emission control options and costs, was available to apply these
measures to the entire geographic area covered by the proposed rule.
No adverse comments were received suggesting inclusion of
SO₂ emissions reductions from non-EGU stationary sources
other than boilers and turbines. Accordingly, EPA has determined not to
consider SO₂ reductions from these other non-EGU stationary
sources.
Several commenters suggested that EPA should have been able to
consider NO_X emissions reductions from non-EGU categories
other than boilers and turbines, such as internal combustion (IC)
engines and refinery fluid catalytic cracking units. These commenters
believed such reductions were demonstrated to be cost effective, and
questioned EPA's assertion that insufficient information is available.
Finally, some commenters believe EPA should have, at a minimum,
required that controls for NO_X SIP Call sources--including
large IC engines and cement kilns--should be extended from the ozone
season to the entire year.
We believe it likely that inclusion in today's requirements of
reductions from any highly cost-effective controls--if available--for
these categories would have very small effects. First, most of the
States included in the CAIR rule were also included in the
NO_X SIP Call, so that many of the emissions reductions that
would be available from these sources have already occurred due to
implementation of the NO_X SIP Call. Second, in the States
included in the CAIR rule, but which were not covered by the
NO_X SIP Call, only a small portion of NO_X
emissions come from cement kilns and IC engines compared to EGUs.
Moreover, in some parts of this geographic area, in particular for
Texas, many sources in these source categories are already regulated
under ozone nonattainment plans (including SIPs for the Texas cities of
Houston, Galveston, and Dallas).
Regarding the commenters' recommendation that extending
NO_X SIP Call control requirements to a year-round basis for
large IC engines and cement kilns should be considered to be highly
cost effective, EPA believes that few emissions reductions would be
achieved from doing so. The types of controls that were applied in the
NO_X SIP Call States, while required to be in place only
during the ozone season, will, as a practical matter, be applied on a
year-round basis, whether or not so required by today's rule. Most, if
not all, of the NO_X SIP Call States have developed
regulations to control NO_X emissions from IC engines and
cement kilns during the ozone season. The control of choice to meet
these reductions from large lean burn IC engines is low emission
combustion (LEC), which for retrofit applications is a substantial
equipment modification of the engine's combustion system. The engine
will operate with LEC year round because this modification is a
permanent change to the engine. Most, if not all, new large lean-burn
IC engines have LEC. In addition, year-round emissions controls are
already required for rich-burn engines greater than 500 hp which will
likely install nonselective catalyst reduction to comply with the
recently adopted hazardous air pollutant standards (see final rule for
reciprocating IC engines, 69 FR 33474, June 15, 2004). For cement
kilns, the controls of choice are low NO_X burners and mid-
kiln firing. Low NO_X burners (LNB) are a permanent part of
the kiln, so that the kiln will operate year-round with LNB. Mid-kiln
firing is a kiln modification for which a solid and slow burning fuel
(typically tires) is injected in the mid-kiln area. Due to tipping fees
and fuel credits, mid-kiln firing results in an operating cost savings.
After this system is installed, year-round operation is expected.

C. Schedule for Implementing SO₂ and NO_X
Emissions Reduction Requirements for PM_2.5 and Ozone

1. Overview
In the NPR, EPA proposed a two-phased schedule for implementing the
CAIR annual emission reduction requirements: implementation of the
first phase would be required by January 1, 2010 (covering 2010-2014),
and that for the second phase by January 1, 2015 (covering after 2014).
The EPA based its proposal on its analysis of engineering, financial,
and other factors that affect the timing for installing the emission
controls that would be most cost-effective--and are therefore the most
likely to be adopted--for States to meet the CAIR requirements. Those
air pollution controls are primarily retrofitted FGD systems (i.e.,
scrubbers) for SO₂ and SCR systems for NO_X on
coal-fired power plants.
The EPA's projections showed a significant number of affected
sources installing these controls. The proposed two-phased schedule
allowed the implementation of as much of the controls as feasible by an
early date, with a later time for the remaining controls.
The EPA received detailed, technical comments from commenters who
argued that the controls could not be implemented until later than
proposed, and from other commenters who argued that the controls could
be implemented sooner than proposed. The EPA has reviewed the comments
and has conducted additional research and analyses to verify
availability of adequate industrial resources, including boilermakers,
for constructing the emission control retrofits required by CAIR. These
analyses are based on conservative assumptions, including those
suggested by the commenters, to ensure that the requirements imposed by
CAIR do not result in shortages of the required resources that could
substantially increase construction costs for pollution controls and
reduce the cost effectiveness of this program.
Today, EPA is taking final action to require the annual emissions
reductions

[[Page 25216]]

on the same two-phase schedule as proposed. However, the requirements
for the first phase include two separate compliance deadlines:
Implementation of NO_X reductions are required by January 1,
2009 (covering 2009-2014) and for SO₂ reductions by January
1, 2010 (covering 2010-2014). The compliance deadline requirements for
the second phase are the same as proposed. The EPA believes that its
action is consistent with the Agency's obligations under the CAA to
require emission reductions for obtaining NAAQS to be achieved as soon
as practicable. The EPA applied the same criterion in implementing the
NO_X SIP Call, which was based on a single-phased schedule.\71\
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\71\ The NO_X SIP Call Rule allowed approximately 3\1/
2\ years for implementation of all NO_X Controls.
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2. Engineering Factors Affecting Timing for Control Retrofits
a. NPR
In the NPR, EPA identified the availability of boilermakers as an
important constraint for the installation of significant amounts of SCR
and FGD retrofits. Boilermakers are skilled laborers that perform
various specialized construction activities, including welding and
rigging, for boilers and high pressure vessels. The air pollution
control devices, such as scrubber and SCR vessels, require boilermakers
for their construction. Apprentices with no prior work-related
experience complete a four-year training program, to become full
boilermakers. For apprentices with relevant experience, this training
period could be shorter. For example, union members representing the
shipbuilding trade could be expedited into the boilermaker division
within a year.
The boilermaker constraint was considered more important for the
initiation of the first phase of CAIR, since the NO_X SIP
Call experience had shown that many sources would be adverse to
committing significant funds to install controls until after SIPs were
finalized. With the States required to finalize SIPs in 18 months after
the signing of the final rule, the sources would have three years in
which to complete purchasing, construction, and startup activities
associated with these controls, to meet the proposed CAIR deadline.
The EPA's projections showed power plants installing 51.4 gigawatts
(GW) of FGD and 28.2 GW of SCR retrofits during the first CAIR phase.
These projections include retrofits for CAIR as well as retrofits for
base case policies (i.e., retrofits for existing regulatory
requirements). We estimated the total boilermaker-years required for
installing these controls at 12,700, which was based on the
boilermakers being utilized over a period of 18 months during the
installation process. Also, based on the projected boilermaker
population in the timeframe relevant to the installation of these
controls, we estimated that 14,700 boilermaker-years were available
over the same 18-month period. The availability of approximately 15
percent more boilermaker-years than required, as shown by these
estimates, confirms the adequacy of this critical resource for CAIR and
EPA assumed this to be a reasonable contingency factor.
The EPA also determined that installation of the projected amounts
of FGD and SCR retrofits could be completed within the three-year
period available for CAIR. This determination was based on a previous
report prepared by EPA for the proposed Clear Skies Act, ``Engineering
and Economic Factors Affecting the Installation of Control Technologies
for Multi-Pollutant Strategies,'' (docket no. OAR-2003-0053-0106).
According to this report, an average of 21 months are required to
install SCR on one unit, and 27 months to install a scrubber on one
unit. For multiple units within the same plant, installation of
controls would normally be staggered to avoid operational disruptions.
The EPA projected that the maximum number of multiple-unit controls
required for each affected facility could all be installed within three
years.The NPR proposal included a second phase, with a compliance
deadline of January 1, 2015. The EPA's projections showed power plants
installing 19.1 GW of FGD and 31.7 GW of SCR retrofits by 2015, which
included retrofits for CAIR as well as retrofits for base case policies
(i.e., retrofits for existing regulatory requirements). Availability of
boilermaker labor was not an important constraint for this phase.
b. Comments
The EPA received several comments relating to the requirements for
the two-phased implementation program, the emission caps and compliance
deadline for each phase, and resources required to install necessary
controls. The commenters offered opposing viewpoints, which can be
broadly categorized as follows.
Several commenters indicated that the compliance deadline of 2010
for the first phase was not attainable and argued that EPA should
either extend the deadline, or set higher emission caps for this phase.
The commenters raised the following specific points in support of their
concerns:
? The time allowed for completing various activities from
planning to startup of the required controls was not sufficient. Other
related activities, including project financing and obtaining a
landfill permit for the scrubber waste, could also require more time
than what the rule allowed. In addition, the short implementation
period would require simultaneous outages of too many units to tie the
new equipment into the existing systems, which would affect the
reliability of the electrical grid.
? Implementation of controls to the required large number of
units would cause shortages in the supply of critical industrial
resources, especially boilermakers. An analysis performed by a
commenter showed a shortfall in the supply of boilermaker labor during
the construction period relevant to CAIR retrofits. This commenter
anticipated that certain key variables would be greater in value than
those used by EPA and based their analysis on higher SCR prices, EIA-
projected higher natural gas prices and electricity demand factors, and
more stringent boilermaker duty rates (boilermaker-year/MW) and
availability factors.
Commenters who favored more stringent compliance deadlines argued
that the required controls could be installed in less time and more
controls could be built in early years. These commenters raised the
following specific points in support of their concerns.
? The compliance deadlines for the two phases did not
support the ozone and fine particulate (PM_2.5) attainment
dates mandated by the CAA. The Phase I deadline should be accelerated
to meet these attainment dates. Sufficient industrial resources,
including boilermakers, would be available to support such an
acceleration. While some commenters supported an earlier Phase I
deadline of January 1, 2008, the others supported a deadline of January
1, 2009. Some of these commenters also suggested that the Phase I
deadline be accelerated only for NO_X.
? The EPA's estimates for the boilermaker availability were
too conservative. A boilermaker labor analysis performed by one
commenter showed an adequate supply of this resource to support
installation of all Phase I and II controls by the start of the first
phase (by 2010), thereby eliminating the need for two phases.
? The time allowed for installing controls for Phase II was
excessive. The initiation of this phase could be moved forward.

[[Page 25217]]

Several commenters supported EPA's assumptions used in support of
the adequacy of the implementation period and resources to build the
required CAIR controls. These assumptions included the overall
construction schedule durations for SCR and FGD systems and boilermaker
unit rates.
c. Responses
The EPA reviewed the above comments and performed additional
research and analyses, including new IPM runs that incorporated higher
SCR and natural gas costs and greater electric demand. We also found
that more units had installed SCR under the NO_X SIP Call and
other regulatory actions than what our records previously showed. This
increase in the number of existing SCR installations was also
incorporated into these IPM runs. In addition, the number of existing
FGD installations was also revised slightly downward, for the same reason.
The revised IPM analyses for today's final action show that the
amounts of controls that need to be put on for Phase I are 39.6 GW of
FGD and 23.9 GW of SCR. These amounts represent a reduction from the
estimates for the NPR. For Phase II, the amount of the required
controls are 32.4 GW of FGD and 26.6 GW of SCR. These amounts represent
an increase from the estimates for the NPR. The amounts shown for both
phases reflect all retrofits required for the CAIR and base case (non-
CAIR) policies. The retrofit projections for the base case policies are
included, since some of the available boilermaker labor would be
consumed in building these retrofits during the CAIR time-frame.
The EPA also contacted the International Brotherhood of
Boilermakers (IBB), U.S. Bureau of Labor Statistics (BLS), and National
Association of Construction Boilermaker Employers (NACBE) to verify its
assumptions on boilermakers population, percentage of boilermakers
available to work on the control retrofit projects, and average annual
hours of boilermaker employment. Except for the boilermaker population,
the information received as a result of these investigations validated
EPA's assumptions. IBB also confirmed that the boilermaker population
would at least be maintained at the current level of 26,000 members,
during the period relevant to construction of CAIR retrofits. It did
not want to forecast growth and historically has not done so.
Therefore, instead of the 28,000 boilermaker forecasted population used
in the NPR, we have conservatively used a boilermaker population of
26,000 for the final CAIR. A detailed discussion on these assumptions
and the information received from these sources is available in the
docket to this rulemaking as a technical support document (TSD),
entitled ``Boilermaker Labor and Installation Timing Analysis, (docket
no. OAR-2003-0053-2092).''
The responses to the most significant comments on these issues are
summarized in the following sections.
i. Issues Related to Compliance Deadline Extension
(I) Adequacy of Phase I Implementation Period
Today's action initiates State activities in conjunction with EPA
to set up the administrative details of CAIR. With the first phase
compliance deadline of January 1, 2009, for NO_X and January
1, 2010, for SO₂, the affected sources would have
approximately 3\3/4\ and 4\3/4\ years for the implementation of the
overall requirements for this phase, respectively. The final SIPs would
be submitted at the end of the first 18 months of these implementation
periods. The remaining 2\1/4\ and 3\1/4\ years would be available for
the sources to complete activities required for the procurement and
installation of NO_X and SO₂ controls,
respectively. For the reasons outlined below, EPA believes that these
deadlines provide enough time to install the required Phase I controls.
(A) Engineering/Construction Schedule Issues
The EPA notes that, for CAIR, the States would finalize the SIPs in
18 months after the rule is signed, and that until then, the majority
of sources required to install controls may not initiate activities
that require commitment of major funds. However, some activities, such
as planning, preparation of conceptual designs, selection of
technologies, and contacts with equipment suppliers can be started or
completed prior to the finalization of SIPs, at least for major sources
expected to require longer implementation periods. In addition, other
activities, such as permitting and financing can be started after the
rule is finalized. This is based on the NO_X SIP Call experience.
After the SIPs are finalized, the sources would have approximately
2\1/4\ and 3\1/4\ years in which to complete purchasing, detailed
design, fabrication, construction, and startup of the required
NO_X and SO₂ controls, respectively. This assumes
that activities, such as planning and selection of technologies, have
already been started or completed, prior to the start of these 2\1/4\-
and 3\1/4\-year periods. As discussed in the NPR proposal, EPA projects
an average single-unit installation time of 21 months for SCR and 27
months for a scrubber. Our revised IPM analysis for the final rule
shows that many facilities would install controls on multiple units (a
maximum of six for SCR and five for FGD) at the same plant. We expect
these facilities to stagger these installations to minimize operational
disruptions.
The EPA also projects that SCRs and scrubbers could be installed on
the multiple units in the available time periods of 2\1/4\ and 3\1/4\
years, respectively. The issues related to the availability of
boilermakers and the ability of the plants requiring multiple-unit
controls to stagger their installations during these periods are
discussed later in this preamble.
As compared to projections in the NPR proposal, earlier signing of
the final rule adds approximately three additional months to the
overall implementation periods for SO₂ controls.
Furthermore, EPA's projections for the final rule show fewer Phase I
NO_X and SO₂ controls being added than the
projections in the NPR proposal. Since the compliance deadline for
NO_X has been moved up a year from the proposal, a three-
month earlier rule promulgation provides more time for implementing
SO₂ controls only. However, since it does allow use of
critical resources, such as boilermakers, for SO₂ controls
to be spread over a longer period of time, the net effect would be to
make more of these resources available for both SO₂ and
NO_X controls (as compared to a scenario where promulgation
was not three months earlier). This is especially true since the
implementation periods for both NO_X and SO₂
controls would start at the same time and the plants installing these
controls would be competing for the same resources until January 1,
2009, the compliance deadline for NO_X. The EPA, therefore,
believes that 2\1/4\- and 3\1/4\-year time periods provide reasonable
amounts of time from the approval of State programs by September 2006,
until the commencement of compliance deadlines for meeting the
NO_X and SO₂ emission requirements.
Certain commenters have provided their own estimates of schedule
requirements for installing the required controls. In some cases, these
estimates are longer than those determined by EPA. For scrubbers,
including spray dryer and wet limestone or lime type systems, the
control implementation requirements provided by the commenters range
from 30 to 54 months for the overall project and 18 to 36 months for
the phase following

[[Page 25218]]

equipment awards. In this case, the lowest 18-month schedule
requirement cited applies to spray dryers, whereas the shortest
schedule cited for wet scrubbers for the activities following the
equipment awards is 24 months. For SCR, the control implementation
requirements cited by the commenters range from 24 to 36 months for the
overall project and 17 to 25 months for the phase following the
equipment awards.
One commenter has pointed out that the construction schedule
requirements for the FGD and SCR retrofit projects have shortened,
because of the lessons learned from a significant number of such
projects completed during the last few years. The EPA notes that a
recent announcement for a new 485 MW limestone scrubber facility
indicates a construction schedule duration (from equipment award to
startup) of only 18 months.\72\ This is well below the schedule
requirement cited by the commenters for a wet limestone scrubber.
---------------------------------------------------------------------------

\72\ Reference: Announcement by Wheelabrator Air Pollution
Control Inc. for award of a wet limestone scrubber system for K.C.
Coleman Generating Station, Western Kentucky Energy Corp., August 2,
2004, and other related documents. (docket no. OAR-2003-0053-1953)
---------------------------------------------------------------------------

The EPA also notes that most of the commenters' schedule estimates
are consistent with the time periods available for completing the CAIR-
related NO_X and SO₂ projects. Some of the longer
schedules submitted by commenters would exceed the CAIR Phase I dates.
However, EPA considers these longer schedules to be speculative, as
these commenters did not justify them. The major factors that influence
schedule requirements include size of the installation, degree of
retrofit difficulty, and plant location. The EPA does not expect these
factors to make a difference of more than a few months between the
schedule requirements of various installations. The commenters who have
cited long schedule requirements that fall at the higher end of the
above ranges have not provided any data to support the wide differences
between their schedules and those proposed by others, including EPA. It
should also be noted that EPA's schedules are based on information from
several actual SCR and scrubber installations. Therefore, EPA cannot
accept the excessive schedule requirements proposed by these commenters.
(B) Landfill Permit Issue
The EPA contacted several key States requiring FGD retrofits, to
investigate the amount of time required to obtain a landfill permit for
scrubber waste. We note that not all scrubber installations would
require landfills, as some scrubber designs produce saleable waste
products, such as gypsum.
Specifically, EPA contacted Georgia, Ohio, Indiana, Alabama,
Pennsylvania, West Virginia, Tennessee, and Kentucky.\73\ Except for
Kentucky, all States indicated that their permit approval periods
ranged from 12 to 27 months. Some of these States indicated that permit
approval may require more time than 27 months, but only for the cases
in which major landfill design issues persist or the permit applicant
has not provided complete and proper information with the permit
application.
---------------------------------------------------------------------------

\73\ Summary of telephone calls with States to discuss landfill
permit timing (docket no. OAR-2003-0053-1927).
---------------------------------------------------------------------------

The Kentucky Department of Environmental Protection indicated that,
based on their historical records, the average permit approval period
was 3\1/2\ years. They also stated that the State was sensitive to an
applicant's time restrictions and the permit approval times had varied
depending on the level of urgency surrounding a permit application.
They further confirmed that they would work with the industry to meet
compliance deadlines, such as those required by CAIR, as efficiently as
possible.
Based on the above investigations, EPA notes that the landfill
permitting requirements quoted by all States fall well within the 4\3/
4\-year implementation period for Phase I. Also, landfill permitting
activities as well as its design and construction can be accomplished,
independent of the design and construction of the FGD system. The EPA,
therefore, believes that landfill permitting is not a constraint for
compliance with the rule.
(C) Project Financing Issue
Commenters representing small units or units owned by the co-
operatives raised concerns that arrangement of financing for control
retrofits could take long periods of time. However, EPA's projections
show a larger portion of the smaller units installing controls only
during the second phase. These projections also show that only a few
co-operative units would require installation of controls. Therefore,
EPA believes that the Phase I implementation periods of approximately
3\3/4\ and 4\3/4\ years for NO_X and SO₂ controls,
respectively, provide enough time for completing the financing activity
for all controls. Of course, if individual sources face difficulties in
meeting deadlines to implement controls, they may use the allowance-
trading provisions of CAIR to defer implementation of controls.
(D) Electrical Grid Reliability Issue
Based on available data for the NO_X SIP Call,
approximately 68 GW of SCR retrofits were started up during the years
from 2001 to 2003. This included approximately 42 GW of SCRs in 2003
alone, which exceeds the combined capacity of SCR and FGD retrofits for
CAIR that we expect to be started up in any one year. The EPA projects
that startup of the 23.9 GW of SCR and 39.6 GW of FGD capacity required
for Phase I would be spread over a period of two years (2008 and 2009).
The total capacity of units starting up in each year is therefore
expected to be approximately 32 GW (half of the combined SCR and FGD
capacity of 63.5 GW).
The NO_X SIP Call experience shows that outages required
to complete installation of the large SCR capacity, especially during
2003, did not have an adverse impact on the electrical grid
reliability. The EPA notes that the outage requirement for SCR usually
exceeds that for scrubbers, since SCR is located closer to the boiler
and it may be more intrusive to the existing equipment. As shown above,
the CAIR retrofits are projected to include more scrubbers than SCRs
and the capacity of these retrofits starting up in any one year is
below the capacity of the NO_X SIP Call units that started up
in 2003. Therefore, the overall outage requirement for CAIR would be
less than that experienced for the NO_X SIP Call.
Based on published industry data, the planned outage times for
coal-fired units from 2001-2002 (SCR buildup years) decreased by over
two percent compared to the previous two years from 1998-1999.\74\ The
reduction in the overall outage time in the 2001-2002 period also shows
that the SCR retrofits did not adversely affect the grid reliability.
Therefore, EPA believes that the concern regarding electrical grid
reliability is unwarranted for CAIR retrofits.
---------------------------------------------------------------------------

\74\ Reference: ``NERC, Generating Availability Data System: All
MW Sizes--Coal-Fired Generation Report,'' http://www.nerc.com/filez/
gar.html, October 17, 2003.
---------------------------------------------------------------------------

(II) Availability of Boilermaker Labor in Phase I
The EPA has performed several analyses to verify the adequacy of
the available boilermaker labor for the installation of CAIR's Phase I
controls. These analyses were not just based on using EPA's assumptions
for the key

[[Page 25219]]

factors affecting the boilermaker availability, but also the
assumptions suggested by commenters for these factors to determine how
sure we could be on our key conclusions. If there was insufficient
labor for the amount of air pollution controls that will need to be
installed, the program would be in jeopardy. For instance, shortages in
manpower could lead to high wage rates that could substantially
increase construction costs for pollution controls and reduce the cost
effectiveness of this program. During the peak of the NO_X
SIP Call SCR construction period, the power industry did experience an
increase in the SCR construction costs. One of the reasons cited for
these higher costs was an increased demand for boilermaker labor. The
EPA strongly wanted to avoid this possibility for CAIR. The EPA also
wanted to be very sure that the levels of controls and timing of the
program's start were appropriate. Therefore, EPA tended to make
conservative assumptions and to test the sensitivity of key assumptions
that were uncertain.
Boilermakers population, percentage of boilermakers available to
work on the control retrofit projects, and average annual hours of
boilermaker employment are some of the key factors that affect
boilermaker availability. As discussed previously, EPA's assumptions on
these factors were validated or revised through our discussions with
IBB, BLS, and NACBE.
Two other key factors that also have an impact on boilermaker
availability include the number of required SCR and FGD retrofits and
boilermaker duty rates (boilermaker-year/MW, i.e., the number of
boilermaker years needed to install SCR or FGD on one MW of electric
generation capacity). The EPA's projections for the required SCR and
FGD retrofits are based on the IPM analyses performed for the final
rule. The basis for the boilermaker duty rates used by EPA is a report
prepared by EPA for the proposed Clear Skies Act, ``Engineering and
Economic Factors Affecting the Installation of Control Technologies for
Multi-Pollutant Strategies.''
Some commenters have suggested use of EIA's projections of natural
gas prices and electricity demand rates that are higher than EPA's
projections used in the IPM analyses. Use of higher values for these
parameters would increase the number of required control retrofits.
While not agreeing with these commenters that EIA's projections should
replace the data that EPA uses, we acknowledge that there is reasonable
uncertainty concerning these assumptions and that addressing the
uncertainty explicitly by considering EIA's alternative assumptions is
prudent, given the importance of having sufficient labor resources to
meet the program's requirements in 2010. Therefore, EPA has performed a
sensitivity analysis to determine the required control retrofits
resulting from the use of these EIA projections, and then used the
increased amounts of the required control retrofits to determine their
impacts on the boilermaker availability.
The EPA also received comments suggesting that the SCR costs used
in our IPM analyses were below the levels experienced in recent SCR
installations. We note that the SCR costs were revised in the IPM
analyses performed for the final rule, to reflect recent industry
experience. One commenter reported SCR capital costs that exceeded our
revised costs. The EPA does not agree with these reported costs, as
they are not supported by the overall cost data submitted by the
commenter. However, to address the concern with the SCR costs in
general, we have performed a sensitivity analysis to determine the
impact of increasing the SCR capital and fixed O&M costs by 30 percent.
An increase in the SCR costs would affect the amounts of the
required control retrofits. Table IV-12 shows the projected Phase I SCR
and FGD retrofits for the above two alternate cases, based on using
EIA's projections for natural gas prices and electricity demand rates
and higher SCR costs.

Table IV-12.--IPM Projections for Total Capacities of FGD and SCR Retrofit Projects for Coal-Fired Electric
Generation Units for CAIR Phase I Using EPA and Commenter Assumptions
----------------------------------------------------------------------------------------------------------------
EIA
Retrofit type EPA base case projections EIA projections and higher SCR
assumptions \1\ costs \2\
----------------------------------------------------------------------------------------------------------------
CAIR FGD, GW............................... 37 45.4 47.9
Non-CAIR FGD, GW........................... 2.6 3.7 Included Above
CAIR SCR, GW............................... 18.2 20.6 25.2
Non-CAIR SCR, GW........................... 5.7 4.6 Included Above
----------------------------------------------------------------------------------------------------------------
\1\ The required control retrofits shown are based on using EIA projections for natural gas prices and
electricity demand rates.
\2\ The required control retrofits shown are based on using EIA projections for natural gas prices and
electricity demand rates as well as 30 percent higher SCR capital and fixed O&M costs.

As shown in Table IV-12 above, the alternate case using just the
EIA's projections for natural gas prices and electricity demand rates
requires the largest amounts of control retrofits. Therefore, a
boilermaker availability analysis was performed for just this case.
One commenter has suggested use of higher boilermaker duty rates
for both SCR and FGD retrofits, based on an industry survey they had
conducted. Use of higher duty rates would result in more boilermakers
being needed to install the controls. Table IV-13 shows the boilermaker
duty rates used by EPA as well as those suggested by this commenter.

Table IV-13.--Boilermaker Duty Rates for SCR and FGD Systems for Coal-
Fired Electric Generation Units
------------------------------------------------------------------------
Source FGD SCR
------------------------------------------------------------------------
EPA's estimate, boilermaker-year/MW................... 0.152 0.175
Commenter-suggested, boilermaker-year/MW \1\.......... 0.269 0.343
------------------------------------------------------------------------
\1\ The duty rate values shown are average values calculated by using
the FGD and SCR correlations provided by the commenter along with the
MW size of individual units projected by the IPM to require FGD or SCR
controls for Phase I of CAIR.

[[Page 25220]]

Our review of the limited supporting information submitted by the
commenter about their survey for these duty rates shows that they are
based on data from a small number of installations and represent scope
of work at each power plant that is well above the average installation
conditions used in determining the duty rates used by EPA. Therefore,
EPA considers these commenter-suggested duty rates to represent the
upper end of the range of values that would be expected for the SCR and
FGD controls under consideration. This is also supported by the average
duty rate (0.199) submitted by one other commenter for installing FGDs,
which is well below the average duty rate (0.269) suggested by the
first commenter. However, EPA also notes that the duty rate suggested
by the second commenter is higher than that (0.152) used by EPA.
The EPA conducted the boilermaker analysis for the final rule using
alternative assumptions for boilermaker duty rates. These alternative
assumptions yield a range of estimates of the amount of control that
could feasibly be installed. In keeping with EPA's desire to be very
sure that there is sufficient boilermaker labor available during the
CAIR's Phase I construction period, the Agency has considered the most
stringent duty rates suggested by the first commenter, as well as other
duty rates (see Table IV-13), in analyzing the impact on the
boilermaker availability. The EPA considers this to be a bounding
analysis in which the estimates based on the most stringent duty rates
reflect conditions with the highest retrofit difficulty level that EPA
could realistically expect to occur. We expect that the average
boilermaker duty rates applicable to the overall boiler population
required to retrofit controls under this rule would not fall outside of
the values used by EPA and those suggested by the first commenter.
In the NPR, only the union boilermakers belonging to the IBB were
considered in the EPA's availability analysis. Some commenters have
pointed out that additional sources of boilermakers will be available
for CAIR. Two such sources include non-union and Canadian boilermakers.
IBB has confirmed that 1,325 Canadian boilermakers were brought in to
support the NO_X SIP Call SCR work in 2003. The EPA also
projects that approximately 15 percent of FGDs and 43 percent of SCRs
will be installed for Phase I in the traditionally non-union States and
believes there will be nonunion labor available in these States. One
source has confirmed that a substantial amount of SCR retrofit work
during the 2000-2002 period was executed by non-union labor.\75\ Based
on these data, we have conservatively assumed that 1,000 boilermakers
from Canada will be available and 10 percent of the retrofits would be
installed by non-union boilermakers for Phase I.
---------------------------------------------------------------------------

\75\ Reference: ``Email from Institute of Clean Air Companies,''
September 15, 2004 (See Appendix B, Boilermaker Labor Analysis and
Installation Timing).
---------------------------------------------------------------------------

Based on EPA data, an average 32 GW of new gas-fired, combined
cycle generating capacity was being added annually, during the
NO_X SIP Call SCR construction years of 2002 and 2003. A
substantial number of boilermakers were involved in the construction of
these gas-fired projects. Since projections for the timeframe relevant
to CAIR retrofits show only a small amount of new electric generating
capacity being added, the number of boilermakers involved in the
building of new plants would be smaller and more of the boilermaker
population would be available to work on the Phase I retrofits. As
pointed out by one commenter, the boilermakers available due to this
projected drop in the building of new generation capacity represents a
third additional source of boilermakers for CAIR.
The EPA projects only an insignificant amount of new coal-fired
generating capacity being added during Phase I. The most recent EIA's
projections also do not show any new coal fired capacity being added
between 2007 and 2010, the timeframe relevant to boilermaker-related
construction activities for CAIR.\76\ However, EPA's projections do
show approximately 15 GW of new or repowered gas-fired capacity being
added, during 2007-2010. The EIA's projections for new gas-fired
capacity addition during Phase I are well below those of EPA's. We used
the more conservative EPA projections for new generating capacity
additions and the gas-fired capacity additions during the
NO_X SIP Call period to estimate the additional boilermaker
labor that would become available for the Phase I retrofits. This
estimate shows that approximately 28 percent more boilermakers would be
available to work on the CAIR retrofits, because of a slowdown in the
construction of new power plants.\77\
---------------------------------------------------------------------------

\76\ Reference: ``Annual Energy Outlook 2005 (Early Release),
Tables A9 and 9,'' December 2004, http://www.eia.doe.gov/oiaf/aeo/
index.html.
\77\ TSD, ``Boilermaker Labor and Installation Timing
Analysis,'' (Docket no. OAR-2003-0053-2092).
---------------------------------------------------------------------------

In the boilermaker availability analyses performed by EPA, the
required boilermaker-years were determined for each case, based on the
amounts of SCR and FGD retrofits being installed and the pertinent
boilermaker availability factors and duty rates. The required
boilermaker-years were then compared to the available boilermaker years
to verify adequacy of the boilermaker labor. All sources of
boilermakers were considered in these analyses, including the union
boilermakers and the boilermakers from the three additional sources
discussed previously.
The EPA's boilermaker availability analyses firmly support CAIR's
Phase I requirements. Using EPA's projections of FGD and SCR retrofits
installed for Phase I and EPA's assumptions for boilermaker duty rates,
there are ample boilermakers available with a large contingency factor
to support the predicted levels of CAIR retrofits. For the most
conservative analysis using the boilermaker duty rates suggested by one
commenter and the EIA's projections for natural gas prices and
electricity demand rates, there are sufficient boilermakers available
with a contingency factor of approximately 14 percent.
In the NPR proposal, EPA estimated that a contingency factor of 15
percent was available to offset any increases in boilermaker
requirements due to unforeseen events, such as sick leave, time lost
due to inclement weather, time lost due to travel between job-sites,
inefficiencies created due to project scheduling issues, etc. The EPA
had considered this 15 percent contingency factor to be adequate for
these unforeseen events. We also note that EPA did not receive any
comments suggesting a need for a higher contingency factor.
The EPA also notes that the above boilermaker labor estimates have
not considered the benefits of the experiences gained by the U.S.
construction industry from the recent buildup of large amounts of air
pollution controls, including the NO_X SIP Call SCRs. As
pointed out by one commenter, such experiences include use of modular
construction, which can result in a significant reduction in the
required boilermaker labor for CAIR retrofits. Also, as a result of
this controls buildup, an increased number of experienced designers and
construction personnel have become available to the industry. Some of
these benefits may be offset by factors, such as the increased level of
retrofit difficulty expected for the CAIR retrofits, especially for the
small size units. However, we believe that the net effect of this
experience is a more efficient use of the boilermaker labor in the
construction of the air

[[Page 25221]]

pollution control retrofits projects. Unfortunately, EPA cannot
quantify the value of this experience in determining its overall impact
on boilermaker requirements.
Therefore, EPA considers the 14 percent contingency in the
available boilermaker-years for the above bounding analysis using
commenter-suggested assumptions to be adequate.
ii. Issues Related to Compliance Deadline Acceleration
(I) Acceleration of Phase I Compliance Deadline
As a result of EPA's review of the comments received and further
investigations conducted by the Agency for the final rule, the
compliance deadline for implementing Phase I NO_X controls
has been moved up by one year. We believe that the affected plants
would have sufficient time with this change to meet the CAIR
requirements associated with NO_X emissions, as long as the
compliance deadline for implementing SO₂ controls is not
changed. The EPA does not agree that accelerating the originally
proposed Phase I compliance deadline of January 1, 2010, for
implementing both NO_X and SO₂ controls is
possible. These issues are discussed below.
(A) Two-Year Phase I Acceleration for NO_X and SO₂
Controls
With today's final action and allowing 18 months for the SIPs,
sources installing controls would have approximately 3\1/4\ years for
implementing the rule's requirements. Some commenters suggested moving
Phase I forward by 2 years, with a new compliance deadline of January
1, 2008, which would reduce the implementation period to 1\1/4\ years.
It is recognized that sources generally would not initiate any
implementation activities that require major funding, before the final
SIPs are available.
The EPA's projections show that, for SCR installation on one unit,
an average 21-month schedule is required to complete purchasing,
construction, and startup activities. For the same activities for FGD,
an average 27-month schedule is required. As can be seen, the total
time required for just one SCR or FGD installation exceeds the 1\1/4\-
year implementation period available for Phase I, if the compliance
deadline is moved to January 1, 2008.
(B) One-Year Phase I Acceleration for NO_X and SO₂
Controls
If the Phase I compliance deadline for both NO_X and
SO₂ controls is moved up by 1 year, the affected facilities
would have 2\1/4\ years or 27 months to complete installation of these
controls. As discussed in the preceding section, FGD installation on
one unit requires an average 27-month schedule to complete purchasing,
construction, and startup activities.
The sources installing controls on more than one unit at the same
facility would likely stagger the outage-related activities, such as
final hookup of the new equipment into the existing plant settings and
startup, to minimize operational disruptions and avoid losing too much
generating capacity at one time. The EPA projects that an average 2-
month period is required to complete the outage construction activities
and a 1-month period to complete the startup activities for FGD.
Therefore, if back-to-back outages are assumed for a plant installing
FGD on just two units, the 27 months needed to install FGD on the first
unit and an additional 3 months needed for outage activities on the
second unit would result in an overall schedule requirement of 30
months. This 30-month schedule exceeds the available 27-month
implementation period, if the compliance deadline is moved up by 1
year. For plants installing FGD controls on more than two units and
performing hookup construction and startup activities in back-to-back
outages, an additional 3 months would be added to the 30-month schedule
requirement for each additional unit.
The EPA notes that certain plants installing multiple-unit controls
may be able to meet the compliance deadline requirement by using
alternative approaches, such as simultaneous unit outages and purchase
of allowances to defer installation of controls on some units. However,
our projections for the final rule show that some facilities would be
installing FGD controls on five multiple units at a single site.
Moreover, these projections show 26 plants requiring FGD retrofit on
more than one unit, which represents a major portion of the total
number of plants required to install such controls under CAIR. We
believe it would not be appropriate to expect this number of plants to
resort to alternative means to accommodate such installations, such as
simultaneous unit outages or purchasing of allowances.
For FGD retrofits, some plants would be required to obtain solid
waste landfill permits. As discussed previously, the time required to
obtain these permits could range from one to 3\1/2\ years. With the
compliance deadline moved up by one year, the overall implementation
period would be reduced from 4\3/4\ to 3\3/4\ years. For those plants
subjected to a 3\1/2\-year permit approval period, only 3 months would
be available to prepare the permit applications at the beginning of the
compliance period and to prepare the landfill area for accepting the
waste after permit approval. The EPA does not believe that 3 months is
adequate for such activities. These plants would, therefore, need the
4\3/4\-year implementation period to complete activities related to
landfills associated with the FGD systems.
The EPA also performed an analysis to verify if the available
boilermaker labor is adequate to support the January 1, 2009,
compliance deadline for both NO_X and SO₂. This
analysis was performed, using commenter-suggested boilermaker duty
rates and EIA's assumptions for the natural gas prices and electricity
demand rates. The results show that given these assumptions sufficient
number of boilermakers will not be available and that there will be a
shortfall of approximately 32 percent in the boilermakers available to
support Phase I activities for this case.
Considering the constraints identified in the above analyses for
the FGD installation schedule requirements and boilermaker labor
availability, EPA believes that it is not reasonable to move the Phase
I compliance deadline for both NO_X and SO₂ caps
to January 1, 2009.
(C) One-Year Phase I Acceleration for NO_X Controls Only
A 1 year acceleration would result in a compliance deadline of
January 1, 2009, for installing Phase I NO_X controls. With
this change, the affected sources installing these controls would have
approximately 2\1/4\ years for implementing the rule's requirements,
following the approval of State programs. However the implementation
period for installing FGD controls would still be at 3\1/4\ years.
As shown previously, 21 months would be required to complete
purchasing, construction, and startup of SCR on one unit. For multiple-
unit installations with back-to-back unit outages for the tie-in
construction and startup, the available 2\1/4\-year implementation
period would permit staggering of SCR installations on a maximum of
three units (see the above referenced TSD). For a plant requiring SCR
retrofit on more than three units, simultaneous outages of two units
would become necessary. However, EPA notes that there are only six
plants projected to require SCR installation on more than three units
and, therefore, it is expected that simultaneous outages of two units
at each of these plants would not have an adverse impact on the
reliability of the electrical grid.

[[Page 25222]]

In addition, the plants installing SCR on more than three units at
the same site would have two other options to meet the rule's
requirements, without having to resort to simultaneous two-unit
outages. First, these plants would be able to defer installation of
SCRs on some of the units by receiving allocated allowances or
purchasing allowances from the 200,000-ton Compliance Supplement Pool
being made available as part of CAIR.\78\ Second, the outage activities
for some of the units at these plants could be extended into the first
quarter of 2009, which is beyond the compliance deadline of January 1,
2009, since these units would not generate NO_X emissions
during an outage and therefore not require any allowances to compensate
for them. The EPA's projections show that, of the above six plants
installing SCR on more than three units, four of them require SCR
retrofits on four units each. If it is assumed that these four plants
would perform outage activities on the fourth unit during the first
quarter of 2009, there would only be two plants left that would be
required to either purchase allowances or perform work during
simultaneous outages.
---------------------------------------------------------------------------

\78\ The 200,000-ton Compliance Supplement Pool is apportioned
to each of the 23 States and the District of Columbia that are
required by CAIR to make annual NO_X reductions, as well
as the 2 States (Delaware and New Jersey) for which EPA is proposing
to require annual NO_X reductions.
---------------------------------------------------------------------------

The EPA also notes that the total schedule requirements for
multiple-unit plants can be reduced further by performing some of the
activities, especially those related to planning and engineering, prior
to the 2\1/4\-year period. Also, with the total installation time
requirement for FGD being more than that for SCR, EPA expects the
outages associated with most Phase I FGDs to take place after January
1, 2009. The overall impact of the outages taken for these SCR and FGD
retrofits would, therefore, be minimized.
The EPA also performed an analysis to determine the impact of an 1-
year acceleration in the NO_X compliance deadline on Phase I
boilermaker labor requirements. Since the amounts of the required Phase
I NO_X and FGD retrofits are not affected by this change, the
overall boilermaker requirements for this phase will remain the same as
previously reported for the case with the same compliance deadline for
both NO_X and SO₂. However, with the new
NO_X compliance deadline, installation of all NO_X
retrofits would have to be completed by January 1, 2009, and some of
the FGD construction work requiring boilermakers would also be done
during this period. The EPA assumed that, along with completing
installation of all SCRs, 35 percent of the boilermaker labor required
to install all FGDs would be used in the period prior to January 1,
2009. This is a conservative assumption, since the amount of
boilermaker labor used for this period would be greater than 50 percent
of the total Phase I boilermaker labor requirement. The analysis
performed by EPA shows that sufficient boilermakers would be available
with a contingency factor of approximately 14 percent to install all
SCR controls and 35 percent of the FGD retrofit work by January 1,
2009. This analysis is based on the most conservative assumptions,
using the boilermaker duty rates suggested by one commenter and the
EIA's projections for natural gas prices and electricity demand rates.
Based on the above analyses, EPA believes that moving the compliance
deadline for Phase I for both NO_X and SO₂ is not
practical. However, a 1-year acceleration in the compliance deadline
for NO_X only is feasible. Since EPA is obligated under the
CAA to require emission reductions for obtaining NAAQS to be achieved
as soon as practicable, we have based the final rule on two separate
Phase I compliance deadlines of January 1, 2009, and January 1, 2010,
for NO_X and SO₂, respectively.
(II) Implementing All Controls in Phase I
The EPA proposed a phased program with the consideration that for
engineering and financial reasons, it would take a substantial amount
of time to install the projected controls. This program would require
one of the most extensive capital investment and engineering retrofit
programs ever undertaken in the U.S. for pollution control. The capital
investment for pollution control for CAIR that would be installed by
2015 is estimated to be approximately 15 billion dollars. By 2015,
close to 340 control unit retrofits will occur. This is occurring at a
time when the industry also faces another major infrastructure
challenge--upgrading transmission capacity to make the grid more
reliable and economic to operate. This also will cost tens of billions
of dollars.
The proposed program's objective was to eliminate upwind states'
significant contribution to downwind nonattainment, providing air
quality benefits as soon as practicable. A phased approach was also
considered necessary because more of the difficult-to-retrofit and
finance, smaller size units would be included in the second phase,
which would allow them to complete activities necessary for
implementing the required controls as well as provide them an
opportunity to benefit from the lessons learned during the first phase.
In general, environmental controls resulting from legislative or
regulatory actions are applied to those units first that offer superior
choices from constructability and cost-effectiveness standpoints.
Experience gained by the industry from these installations can then be
used to develop innovative solutions for any constructability issues
and to improve cost effectiveness, as these technologies are applied to
harder-to-control units. The EPA believes that this phenomenon applies
to the application of the SCR and FGD technologies at coal-fired power
plants.
In the last few years, SCR and FGD systems have been added to
several existing coal-fired units, under the NO_X SIP Call
and Acid Rain Program. These were mainly large units that had features,
such as spacious layouts, amenable to the retrofit of the new air
pollution control equipment. The units installing controls during Phase
I of CAIR would, in general, be smaller in size and would offer
relatively more difficult settings to accommodate the new equipment.
These units would certainly benefit from the experience the industry
has gained from the installations completed in recent years.
A large portion of the units (47 percent) projected to implement
controls during the second phase consists of even smaller units, less
than 200 MW in size. Compared to larger units, the retrofits for these
smaller units would be more difficult to plan, design, and build.
Historically, smaller units have been built with less equipment
redundancy, smaller capacity margins, and more congested layouts. It is
likely, therefore, to be more difficult and require additional design
efforts to accommodate the new equipment into the existing settings for
the smaller units. Use of lessons learned by firms constructing these
units from the previous installations, including those to be built
during the first phase, would help streamline this process and maintain
the cost effectiveness of these installations. Moving a large portion
of the retrofits required for these smaller units to the second phase
also provides more time to complete the required retrofit activities.
Because EPA's projections for the second phase include a large
proportion of smaller units, the total number of units requiring
NO_X and SO₂ controls exceeds that in the first
phase (186 vs. 153). Requiring an acceleration of the second phase
controls to be completed in the first phase would, therefore, more than
double the number of retrofits

[[Page 25223]]

required for the first phase from 153 to 339. Based on data available
from EPA and other sources, the industry completed 95 SCR installations
for the NO_X SIP Call in 2002 and 2003. If the 2004
projections for the NO_X SIP Call are added to this number,
the total number of SCR retrofits over the 2002-2004 period would be
140. This is less than half the number that would be required for CAIR
during a similar period, if the Phase II requirements are implemented
along with the Phase I requirements. Also, the combined capacity for
FGD and SCR retrofits required for Phase I would be 122.5 GW, which is
approximately 57 percent greater than the installed SIP-Call SCR
capacity for the 2002-2004 period. Such a change in the rule would
therefore amount to imposing a requirement over the power industry that
is significantly more demanding and burdensome than what the industry
was required to do under the NO_X SIP Call rule.
The EPA notes that critical resources other than the boilermakers
are needed for the installation of SCR and FGD controls, such as
construction equipment, engineering and construction staffs belonging
to different trades, construction materials, and equipment
manufacturers. Some commenters, based on their experience with
NO_X SIP Call, also pointed out that the requirement for some
of these resources, especially construction equipment (e.g., large
cranes used to mount SCR and scrubber vessels above ground),
construction materials, equipment manufacturing shop capacities, and
engineering and construction management teams overseeing these
projects, is affected directly by the number of installations. The
greater the requirement is to install a large number of retrofits by
2010, the greater would be the need for all these resources, which
would be limited in the short term, as demands from equipment vendors,
project teams, and material suppliers ramp up. In the NO_X
SIP Call, this led to shortages and bottlenecks in projects in certain
areas, causing increased project times and costs. The EPA wants to
avoid creating a similar situation by requiring too much at once.
The EPA has also acknowledged the increase in SCR costs during the
NO_X SIP Call implementation period, most likely due to an
increase in construction costs (resulting from increased demand for
boilermaker labor) and steel prices. The EPA has revised its estimates
of SCR capital costs in the IPM runs for the final rule and believes
the conservatism in its FGD capital costs also accounts for this
factor.
The EPA believes that moving the Phase II requirements to the Phase
I period could cause near-term shortages in some of the critical
resources. This would further increase compliance costs and could
remove the highly cost-effective nature of these controls and lead to a
greater demand for natural gas.
In addition to the above, financing a large amount of controls for
Phase I may prove challenging, especially for the coal plants owned by
deregulated generators. As discussed later in this section, such
generators are continuing to face serious financial challenges, and
many have below investment grade credit ratings. This significantly
complicates the financing of costly retrofit controls. Such plants
would also not have the certainty of regulatory recovery of investments
in pollution control, and would have to rely on the market to recover
their costs. Having a second phase cap would allow these companies
additional time to strengthen their finances and improve their cash flow.
In the interest of being prudent in evaluating the need to phase in
the program, EPA also performed an analysis to determine if the
available boilermaker labor would be adequate to support installation
of all Phase I and II controls in 2010. This analysis was
conservatively based on using commenter-suggested boilermaker duty
rates and EIA's projections for gas prices and electricity demand
rates. The results show that a sufficient number of boilermakers will
not be available and that there will be a shortfall of approximately 25
percent in the boilermakers available to support Phase I activities for
this case.
Based on the above analyses, EPA believes that implementation of
controls for both phases in Phase I is impractical. We also believe
that it is prudent and reasonable in requiring the industry to
undertake this massive retrofit program on a two-phase schedule, to be
largely completed in less than a decade.
(III) Acceleration of Phase II Compliance Deadline
The EPA does not believe that acceleration of the compliance
deadline for the second phase is reasonable. As pointed out earlier, a
large portion of the units projected to install controls during the
second phase consists of small units, less than 200 MW in size. Due to
the issues related to financing of the retrofit projects for some of
these units and considering that planning and designing of controls for
these units is likely to take longer, EPA does not consider the
schedule acceleration to be appropriate.
The EPA notes that Phase I of CAIR is the initial step on the slope
of emissions reduction (the glide-path) leading to the final control
levels. Because of the incentive to make early emission reductions that
the cap-and-trade program provides, reductions will begin early and
will continue to increase through Phases I and II. The EPA, therefore,
does not believe that all of the required Phase II emission reductions
would take place on January 1, 2015, the compliance deadline. These
reductions are expected to accrue throughout the implementation period,
as the sources install controls and start to test and operate them.
The EPA also notes that the 5-year implementation period for Phase
II is consistent with other regulations and statutory requirements,
such as title IV for SO₂ and NO_X controls. In
addition, some commenters have cited a need for a 6-year period for
obtaining financing for plants owned by the co-operatives. These
facilities are likely to commit funds for major activities, only after
financing has been obtained. Therefore, for such facilities, a period
of approximately four years would be available for procuring,
installing, and startup activities, assuming that the financing
activities were started right after the rule is finalized. Since the
plants owned by co-operatives are usually small in size, they are
likely to require and be benefitted by the extra time allowed to them
by this four-year implementation period.
The EPA also performed an analysis to verify adequacy of the
available boilermaker labor for pollution control retrofits the power
industry will install to comply with the Phase II CAIR requirements. A
36-month construction period requiring boilermakers was conservatively
selected for this analysis. Based on the IPM analysis for the final
rule, conservatively, the power industry will build 27.5 GW of FGD and
26.6 GW of SCR retrofits for compliance with lower emission caps that
go into effect for NO_X and SO₂ in 2015. The
analysis was based on using EIA's projections for the natural gas
prices and electricity demand rates and the commenter-suggested
boilermaker duty rates. The results show availability of ample
boilermakers with a contingency factor of 46 percent to support Phase
II activities.
The EPA notes that the retrofits that will occur in Phase II will
be smaller, more numerous, and more challenging, since the easiest
controls will likely be installed in Phase I. Therefore, having a
greater contingency factor (as we do) is warranted. This is further
supported when the uncertainty in predicting the

[[Page 25224]]

construction activities in the areas outside of air pollution controls
is considered. Notably after 2010, the excess generation capacity that
we have today is no longer expected to be present and there may be a
shift towards a requirement for increasing generation capacity.
Increased construction of new power plants will have a direct impact on
the availability of boilermakers for the Phase II controls. The EPA
believes that a higher contingency factor for Phase II is desirable to
ensure that the industry will succeed in getting the required
reductions at the required time.
Any acceleration of the Phase II compliance deadline will also
cause an appreciable reduction in the above estimated contingency
factor for boilermaker labor. For example, based on EPA analysis, an
acceleration of one year is projected to reduce this contingency factor
to only about one percent. Therefore, EPA believes that acceleration of
the Phase II compliance deadline cannot be justified.
3. Assure Financial Stability
The EPA recognizes that the power sector will need to devote large
amounts of capital to meet the control requirements of the first phase.
Furthermore, over the next 10 years, the power sector is facing
additional financial challenges unrelated to environmental issues,
including economic restructuring impacts, investments related to
domestic security and investments related to electrical infrastructure.
Among the consideration of other factors, EPA believes it is important
to take into account the ability of the power sector to finance the
controls required under CAIR. A detailed assessment of the status of
the financial health of the U.S. Utility Industry, particularly of the
unregulated sector is offered in the TSD, ``U.S. Utility Industry
Financial Status and Potential Recovery.''
Commenters have noted that they appreciate EPA's growing
realization that many companies may have difficulty securing financing,
and the agency's establishment of a two-phase reduction program on both
technical and financial grounds.
Utilities and non-utility generating companies have felt
significant financial pressure over the past 5 years. The years 2000
and 2001 saw the escalation and fallout from the California energy
crisis, the bankruptcy of Enron, and a massive building program,
largely on the side of the merchant generating sector. Subsequent low
power margins and large debt obligations have led to a significant
number of credit downgrades of utilities and power generators and the
bankruptcy of coal-generating merchant companies. According to Standard
and Poor's, a leading provider of investment ratings, there were almost
ten times more downgrades of utility credit in 2002 and 2003 than there
were upgrades. While more recently the sector has stabilized, a
significant number of owners of coal-fired capacity in the CAIR region,
particularly those with deregulated capacity, are still at below
investment-grade credit ratings.
In general, EPA believes that regulated plants, given appropriate
regulatory requirements, should not face significant financial problems
meeting their obligations under CAIR. While EPA recognizes that issues
such as the expiration of rate caps and the time lags associated with
regulatory approval and recovery may provide cash flow challenges,
regulated electricity rates are generally seen as a positive factor in
credit ratings, as entities are allowed a recovery on prudent
investment through rate cases (and, in some jurisdictions, the recovery
of allowance expenditures through fuel adjustment clauses).
Deregulated coal capacity (operating in an environment of market
prices rather than electricity rates set by regulators) has no such
guarantees, and would need to recover investments in pollution control
from market prices (which in many cases are not set by coal units).
Additionally, deregulated entities, because of their more aggressive
building and borrowing strategies and reliance on market prices (which
now reflect the current capacity overbuild), have faced more
significant financial difficulties (including a number of bankruptcies)
and are currently in a weaker position financially.\79\ A number of
firms that have avoided financial distress in the near term have done
so by renegotiating their pending debt, postponing payment. A good
portion of this debt is of a shorter-term nature, and will be coming
due in the next five years.
---------------------------------------------------------------------------

\79\ In fact, between nine and eleven (depending on the credit
agency) of the twenty largest owners of deregulated coal capacity in
the U.S. currently have below-investment-grade credit ratings.
---------------------------------------------------------------------------

Such financial difficulties increase the cost of capital necessary
for capital expenditures and affect the availability of such capital,
making required controls more expensive. Recent financial troubles have
been cited as the reason for the deferment or cancellation of pollution
control expenditures. Should interest rates rise in the future, it will
become more difficult and costly for utilities seeking financing.
These problems impact a significant segment of coal generators, as
deregulated coal capacity makes up about a third of all U.S. coal
capacity and almost 90 percent of this deregulated capacity would be
affected by CAIR requirements.
Given the lead times needed to plan and construct such equipment,
as well as the financial uncertainty many of the plant owners are
confronting, companies may find it difficult to install controls at
their plants too quickly. The EPA believes that the choice of timing of
the emission caps in CAIR would allow firms time to improve their
current and near-term financial difficulties (through reorganization,
mergers, sales, etc.). Phasing in the more stringent emission caps by
2015 would also spread investment requirements and resulting cash flow
demands, rather than forcing firms to finance a large spike in
investments in a very short time period, while they are still trying to
recover financially.
The timing of controls expected to be installed as a result of CAIR
are similar to that noted in EPA's analysis of the Clear Skies
proposal. The EPA looked in detail at the potential financial impact of
the Clear Skies program (particularly focusing on the deregulated coal
sector). The EPA found that some individual deregulated coal plants
might be adversely affected, but on average such plants would actually
experience a small financial improvement under Clear Skies. Baseload
deregulated coal plants would benefit from even slight increases in the
price of natural gas ( units burning natural gas generally set the
wholesale price of electricity on the margin in the regions where
deregulated coal is located). These units would also be recipients of
allocated allowances. Overall, the phased in nature of CAIR, the fact
that most coal plants continue to be regulated and the fact that
sources would also receive allowances, would all mitigate the financial
impact of this rule.
The EPA believes that the timing requirements finalized today
reflect a prudent and cautious approach designed to assure that the
industry will succeed in implementing this program. The EPA believes
that deferring the second phase to 2015 will provide enough time for
companies to raise additional capital needed to install controls. Also,
we believe that the implementation period should account (at least
broadly) for the possibility that electricity demand or natural gas
prices may increase more than assumed, and therefore that additional
control equipment would be needed. Allowing until 2015 for
implementation of the more stringent control levels in today's rule
will provide more flexibility in the

[[Page 25225]]

event of greater electricity demand and will ensure that power plants
in the CAIR region will have the ability, both technical and financial,
to make the pollution control retrofits required.
Currently, EPA is cooperating with the National Association of
Regulatory Utility Commissioners (NARUC) in developing a menu of policy
options and financial incentives for encouraging improved environmental
performance for generation. A survey of a number of States was
conducted as part of this effort, and policies such as pre-approval
statutes for compliance plans, state income tax credits, accelerated
depreciation, and special treatment of allowance transactions were
cited as examples of such policies \80\. Such policies will ease some
of the financial pressures of CAIR by providing greater regulatory
certainty and lowering the effective costs of controls.
---------------------------------------------------------------------------

\80\ The survey results are in ``A Survey of State Incentives
Encouraging Improved Environmental Performance of Base-Load Electric
Generation Facilities: Policy and Regulatory Initiatives,'' at
http://www.naruc.org/displayindustryarticle.cfm?articlenbr=21826.
---------------------------------------------------------------------------

D. Control Requirements in Today's Final Rule

1. Criteria Used To Determine Final Control Requirements
The EPA's general approach to developing emission reduction
requirements--basing the requirements on the application of highly
cost-effective controls--was adopted in the NO_X SIP Call and
has been sustained in court. In the NPR, the Agency proposed this
approach for developing SO₂ and NO_X emission
reduction requirements. The majority of commenters accepted this basic
approach for determining reduction requirements. Some commenters did
suggest other approaches, however, as discussed above.
Many commenters suggested that the CAIR regionwide SO₂
and NO_X control levels should be more or less stringent than
the levels proposed in the NPR. The EPA has determined that the control
levels that we are finalizing today are highly cost-effective and
feasible, and constitute substantial reductions that address interstate
transport, at the outset of State and EPA efforts to bring about
attainment of the PM_2.5 NAAQS (EPA believes that most if not
all States will obtain CAIR reductions by capping emissions from the
power sector). Today, EPA finalizes the use of both average and
marginal cost effectiveness of controls as the basis for determining
the highly cost-effective amounts.
In the CAIR NPR, EPA proposed criteria for determining the
appropriate levels of SO₂ and NO_X emissions
reductions, and stated that EPA considered a variety of factors in
evaluating the source categories from which highly cost-effective
reductions may be available and the level of reduction assumed from
that sector (69 FR 4611). The EPA has reviewed comments on its NPR,
SNPR and NODA and conducted further analyses with respect to the
proposed criteria, and is finalizing its control requirements in
today's action. Following is a brief summary of EPA's conclusions based
on the criteria.
The availability of information, and the identification of source
categories emitting relatively large amounts of the relevant emissions,
are two criteria used in EPA's evaluation of the CAIR program. In the
NPR, EPA stated that EGUs are the most significant source of
SO₂ emissions and a very substantial source of
NO_X in the affected region, and further stated that highly
cost-effective control technologies are available for achieving
significant SO₂ and NO_X emissions reductions from
EGUs. We requested comment on sources of information for emissions and
costs from other sectors (69 FR 4610). A detailed discussion regarding
non-EGU sources is provided above. The EPA has not received additional
information that would change its proposed control strategy.
Another criterion is the performance and applicability of control
measures. The NPR included a detailed discussion of the performance and
applicability of SO₂ and NO_X control technologies
for EGUs. In particular, EPA discussed FGD for SO₂ removal
and SCR for NO_X removal, both of which are fully
demonstrated and available pollution control technologies on coal-fired
EGU boilers (69 FR 4612). None of the commenters provided information
that differed from EPA's assessment of the performance of these control
measures. In addition, the commenters generally supported EPA's
assumptions on the applicability of these controls.
The cost effectiveness of control measures is another criterion
used in EPA's analysis. As discussed in detail above, EPA determined
that the proposed control levels are highly cost-effective, and is
finalizing the levels in today's action. The EPA used IPM to analyze
the cost effectiveness of the proposed and final CAIR control
requirements. IPM incorporates assumptions about the capital costs and
fixed and variable operations and maintenance costs of control measures
for EGUs. Several commenters suggested that the SCR control cost
assumptions that we used in IPM analysis for the NPR were too low.
Consequently, we increased the SCR control cost assumptions in IPM and
conducted cost effectiveness modeling for the final control
requirements using these updated costs.\81\ Commenters generally
supported our FGD control costs assumptions, which are largely
unchanged from the NPR modeling to the modeling for today's final rule.
---------------------------------------------------------------------------

\81\ Detailed documentation of EPA's IPM update, including
updated control cost assumptions, is in the docket. The SCR control
cost assumptions were presented in a peer-reviewed paper by Sikander
Khan and Ravi Srivastava, ``Updating Performance and Cost of
NO_X Control Technologies in the Integrated Planning
Model,'' at the Combined Power Plant Air Pollution Control Mega
Symposium, August 30-September 2, 2004, Washington, DC.
---------------------------------------------------------------------------

And finally, EPA considered engineering and financial factors that
affect the availability of control measures. The EPA conducted a
detailed analysis of engineering factors that affect timing of control
retrofits, including an evaluation of the comments received. The EPA's
analysis supports its compliance schedule, a two-phase emissions
control program with the final phase commencing in 2015, and with a
first phase commencing in 2010 for SO₂ reductions and in
2009 for NO_X reductions. Further, EPA's analysis
demonstrates that it would not be realistically possible to start the
program sooner, or to impose more stringent emissions caps in the first
phase.
Based on EPA's review of comments and analysis, EPA determined that
the proposed control requirements are reasonable with respect to
engineering factors. As discussed above, EPA also considered how to
avoid creating financial instability for the affected sector, and how
to ensure the capital needed for the required controls would be readily
available. Assuming States choose to control EGUs, the power sector
will need to devote large amounts of capital to meet the CAIR control
requirements.
The EPA explained that implementing CAIR as a two-phase program,
with the more stringent control levels commencing in the second phase,
will allow time for the power sector to address any financial
challenges. The EPA's evaluation of engineering and financial factors
supports the decision to implement CAIR as a two-phase program, with
the final (second) compliance level commencing in 2015 and a first
phased-in level starting in 2010 for SO₂ reductions and in
2009 for NO_X reductions. A description of the final CAIR
control requirements follows.

[[Page 25226]]

2. Final Control Requirements
Today's final rule implements new annual SO₂ and
NO_X emissions control requirements to reduce emissions that
significantly contribute to PM_2.5 nonattainment. The final
rule also requires new ozone season NO_X emissions control
requirements to reduce emissions that significantly contribute to ozone
nonattainment.
The final rule requires annual SO₂ and NO_X
reductions in the District of Columbia and the following 23 States:
Alabama, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky,
Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin. (In the ``Proposed
Rules'' section of today's action, EPA is publishing a proposal to
include Delaware and New Jersey in the CAIR region for annual
SO₂ and NO_X reductions.)
In addition, the final rule requires ozone season NO_X
reductions in the District of Columbia and the following 25 States:
Alabama, Arkansas, Connecticut, Delaware, Florida, Illinois, Indiana,
Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan,
Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and
Wisconsin.
The CAIR requires many of the affected States to reduce annual
SO₂ and NO_X emissions as well as ozone season
NO_X emissions. However, there are three States for which
only annual emission reductions are required (Georgia, Minnesota and
Texas). Likewise, there are five States for which only ozone season
reductions are required (Arkansas, Connecticut, Delaware,
Massachusetts, and New Jersey). The following 20 States and the
District of Columbia are required to make both annual and ozone season
reductions: Alabama, Florida, Illinois, Indiana, Iowa, Kentucky,
Louisiana, Maryland, Michigan, Mississippi, Missouri, New York, North
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West
Virginia and Wisconsin.
Table IV-14 shows the amounts of regionwide annual SO₂
and NO_X emissions reductions under CAIR that EPA projects,
if States choose to meet their CAIR obligations by controlling EGUs.
Table IV-15 shows the amounts of regionwide ozone season NO_X
emissions reductions under CAIR that EPA projects, if States choose to
meet their CAIR obligations by controlling EGUs. If all affected States
choose to implement these reductions through controls on EGUs, the
regionwide annual SO₂ and NO_X emissions caps that
would apply for EGUs are also shown in the Table IV-14, and ozone
season NO_X caps for EGUs are in Table IV-15. Base case
emissions levels for affected EGUs as well as emissions with CAIR are
also shown in Table IV-14 and Table IV-15, based on IPM modeling.
The EPA is finalizing the regionwide EGU SO₂ emissions
caps--if States choose to comply by controlling EGUs--as shown in Table
IV-14 \82\. As indicated above, EPA identified SO₂ budget
amounts, as target levels for further evaluation, by adding together
the title IV Phase-II allowances for all of the States in the CAIR
region, and making a 50 percent reduction for the 2010 cap and a 65
percent reduction for the 2015 cap. The EPA determined, through IPM
analysis, that the resulting regionwide emissions caps (if all States
choose to obtain reductions from EGUs) are highly cost-effective
levels.
---------------------------------------------------------------------------

\82\ For a discussion of the emission reduction requirements if
States choose to control sources other than EGUs, see section VII of
this preamble.
---------------------------------------------------------------------------

Also, EPA is finalizing the regionwide EGU annual and ozone season
NO_X emission caps--if States choose to comply by controlling
EGUs--as shown in Table IV-14 and Table IV-15.\83\ As indicated above,
EPA identified NO_X budget amounts, as target levels for
further evaluation, through the methodology of determining the highest
recent Acid Rain Program heat input from years 1999-2002 for each
affected State, summing the highest State heat inputs into a regionwide
heat input, and multiplying the regionwide heat input by 0.15 lb/mmBtu
and 0.125 lb/mmBtu for 2009 and 2015, respectively. The EPA determined,
through IPM analysis, that the resulting regionwide emissions caps (if
all States choose to obtain reductions from EGUs) are highly cost-
effective levels.
---------------------------------------------------------------------------

\83\ For a discussion of the emission reduction requirements if
States choose to control sources other than EGUs, see section VII of
this preamble.
---------------------------------------------------------------------------

The emission reductions, EGU emissions caps, and emissions shown in
Table IV-14 are for the 23 States and the District of Columbia that are
required to make annual SO₂ and NO_X reductions
for CAIR. (Table IV-14 does not include information for the five States
that are required to make ozone season reductions only.)
The emission reductions, EGU emissions caps, and emissions shown in
Table IV-15 are for the 25 States and the District of Columbia that are
required to make ozone season NO_X reductions for CAIR.
(Table IV-15 does not include information for the three States that are
required to make annual reductions only.)
The EPA is requiring the CAIR SO₂ and NO_X
emissions reductions in two phases. For States affected by annual
SO₂ and NO_X emission reductions requirements, the
final (second) phase commences January 1, 2015, and the first phase
begins January 1, 2010 for SO₂ reductions and January 1,
2009 for NO_X reductions. For States affected by ozone season
NO_X emission reductions requirements, the final (second)
phase commences May 1, 2015 and the first phase starts May 1, 2009.
Notably, the first phase control requirements are effective in years
2010 through 2014 for SO₂ and in years 2009 through 2014 for
NO_X, and the 2015 requirements are for that year and
thereafter.

Table IV-14.--Final Rule SO2 and NOX Annual Base Case Emissions, Emission Caps, Emissions After CAIR and
Emission Reductions in the Region Required To Make Annual SO2 and NOX Reductions (23 State and DC) for the
Interim Phase (2010 for SO2 and 2009 for NOX) and Final Phase (2015 for SO2 and NOX) for EGUs
(Million Tons) \84\
----------------------------------------------------------------------------------------------------------------
CAIR
Base case emissions Emissions Emissions
emissions caps after CAIR reduced
----------------------------------------------------------------------------------------------------------------
First phase (2010 for SO2 and 2009 for NOX)
----------------------------------------------------------------------------------------------------------------
SO2......................................................... 8.7 3.6 5.1 3.5
NOX......................................................... 2.7 1.5 1.5 1.2

[[Page 25227]]

Sum......................................................... 11.4 NA 6.6 4.8
-------------------------------------------------------------
Second Phase (2015 for SO2 and NOX)
----------------------------------------------------------------------------------------------------------------
SO2......................................................... 7.9 2.5 4.0 3.8
NOX......................................................... 2.8 1.3 1.3 1.5
Sum......................................................... 10.6 NA 5.3 5.3
----------------------------------------------------------------------------------------------------------------
Notes: Numbers may not add due to rounding.
1. The emission caps that EPA used to make its determination of highly cost-effective controls and the emission
reductions associated with those caps are shown in Table IV-14. For a discussion of the emission reduction
requirements if States control source categories other than EGUs, see section VII in this preamble. Emissions
shown here are for EGUs with capacity greater than 25 MW.
2. The District of Columbia and the following 23 States are affected by CAIR for annual SO2 and NOX controls:
AL, FL, GA, IA, IL, IN, KY, LA, MD, MI, MN, MO, MS, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI.
3. The 2010 SO2 emissions cap applies to years 2010 through 2014. The 2009 NOX emissions cap applies to years
2009 through 2014. The 2015 caps apply to 2015 and beyond.
4. Due to the use of the existing bank of SO2 allowances, the estimated SO2 emissions in the CAIR region in 2010
and 2015 are higher than the emissions caps.
5. Over time the banked SO2 emissions allowances will be consumed and the 2015 cap level will be reached. SO2
emissions levels can be thought of as on a flexible ``glide path'' to meet the 2015 CAIR cap with increasing
reductions over time. The annual SO2 emissions levels in 2020 with CAIR are forecasted to be 3.3 million tons
within the region encompassing States required to make annual reductions, an annual reduction of 4.4 million
tons from base case levels.

---------------------------------------------------------------------------

\84\ Table IV-14 includes regionwide information for the 23
States and DC that are required by CAIR to make annual emission
reductions. It does not include information for the 5 CAIR States
that are required to make ozone season reductions only. The CAIR
requires NO_X emission reductions in a total of 28 States
and DC. For 20 States and DC, both annual and ozone season
NO_X reductions are required. For 3 States only annual
reductions are required, and for 5 States only ozone season
reductions are required. The total projected NO_X emission
reductions that will result from CAIR--if all States control EGUs--
include the annual reductions shown in Table IV-14 (for 23 States
and DC) plus the ozone season reductions in the 5 States required to
make ozone season reductions only. The EPA projects the total
NO_X reductions, in all 28 CAIR States and DC, to be 1.2
million tons in 2009 and 1.5 million tons in 2015. Note that the
values in this table represent the final CAIR policy and differ
slightly from the values in the RIA (which were based on an earlier
and slightly different IPM) (see more detailed discussion both
earlier in this section and in the RIA).
---------------------------------------------------------------------------

---------------------------------------------------------------------------

\85\ Table IV-15 shows regionwide information for the 25 States
and DC that are required to make ozone season emission reductions
under CAIR. It does not include information for the 3 States that
are required to make annual emission reductions only.

Table IV-15.--Final Rule NOX Ozone Season Base Case Emissions, Emissions Caps, Emissions after CAIR and Emission
Reductions in the Region Required to Make Ozone Season NOX Reductions (25 States and DC) for the Interim Phase
(2009) and Final Phase (2015) for Electric Generation Units
(Million Tons) \85\
----------------------------------------------------------------------------------------------------------------
Ozone Season NOX
-----------------------------------------------------------------------------------------------------------------
CAIR
Phase Base case emissions Emissions Emissions
emissions caps after CAIR reduced
----------------------------------------------------------------------------------------------------------------
2009........................................................ 0.7 0.6 0.6 0.1
2015........................................................ 0.7 0.5 0.5 0.2
----------------------------------------------------------------------------------------------------------------
Notes:
1. The emission caps that EPA used to make its determination of highly cost-effective controls and the emission
reductions associated with those caps are shown in Table IV-15. For a discussion of the emission reduction
requirements if States control source categories other than EGUs, see section VII in this preamble. Emissions
shown here are for EGUs with capacity greater than 25 MW.
2. The District of Columbia and the following 25 States are affected by CAIR for ozone season NOX controls: AL,
AR, CT, DE, FL, IA, IL, IN, KY, LA, MA, MD, MI, MO, MS, NJ, NY, NC, OH, PA, SC, TN, VA, WV, WI.
3. The 2009 NOX emissions cap applies to years 2009 through 2014. The 2015 cap applies to 2015 and beyond.

Table IV-16 shows the estimated amounts of regionwide annual
SO₂ and NO_X emissions reductions that would occur
if EPA finalizes its proposal to find that Delaware and New Jersey
contribute significantly to downwind PM_2.5 nonattainment,
and if all affected States choose to control EGUs (the proposal is
published in the ``Proposed Rules'' section of today's action). In that
case, the estimated regionwide annual SO₂ and NO_X
emissions caps that would apply for EGUs are as shown in Table IV-16.
Annual base case emissions levels for EGUs in the CAIR region
(including Delaware and New Jersey) as well as emissions with CAIR are
also shown in the Table, based on IPM modeling. If EPA finalizes its
proposal to include Delaware and New Jersey for PM_2.5
requirements, then the ozone

[[Page 25228]]

season requirements would not change for States required to make ozone
season reductions for CAIR.
Based on EPA modeling with Delaware and New Jersey included in the
PM_2.5 region (and if all affected States choose to control
EGUs), the EGU emissions caps and the ozone season NO_X
emissions and emission reductions associated with those caps, for the
25 States and the District of Columbia that are required to make ozone
season NO_X reductions, would be as shown in Table IV-15,
above.\86\
---------------------------------------------------------------------------

\86\ For a discussion of the emission reduction requirements if
States choose to control sources other than EGUs, see section VII of
this preamble.

Table IV-16.--SO2 and NOX Annual Base Case Emissions, Emissions Caps, Emissions After CAIR and Emission
Reductions in the Region Required to Make Annual SO2 and NOX Reductions (25 States and DC) for the Initial Phase
(2010 for SO2 and 2009 for NOX) and Final Phase (2015 for SO2 and NOX) for Electric Generation Units if EPA
Finalizes Its Proposal to Include Delaware and New Jersey for PM2.5 Requirements
[Million tons]
\87\
----------------------------------------------------------------------------------------------------------------
First phase (2010 for SO2 and 2009 for NOX)
---------------------------------------------------
CAIR
Base case emissions Emissions Emissions
emissions caps after CAIR reduced
----------------------------------------------------------------------------------------------------------------
SO2......................................................... 8.8 3.7 5.2 3.6
NOX......................................................... 2.8 1.5 1.5 1.2
Sum......................................................... 11.5 NA 6.7 4.8
-------------------------------------------------------------
Second phase
(2015 for SO2 and NOX)
-------------------------------------------------------------
Base case CAIR Emissions Emissions
emissions emissions after CAIR reduced
caps
-------------------------------------------------------------
SO2......................................................... 7.9 2.6 4.1 3.9
NOX......................................................... 2.8 1.3 1.3 1.5
Sum......................................................... 10.7 NA 5.3 5.4
----------------------------------------------------------------------------------------------------------------
Note: Numbers may not add due to rounding.
\1\ The emission caps that EPA used to make its determination of highly cost-effective controls and the emission
reductions associated with those caps are shown in Table IV-16. For a discussion of the emission reduction
requirements if States control source categories other than EGUs, see section VII in this preamble. Emissions
shown here are for EGUs with capacity greater than 25 MW.
\2\ The District of Columbia and the following 25 States would be affected by CAIR for annual SO2 and NOX
controls if EPA finalizes its proposal to include DE and NJ: AL, DE, FL, GA, IA, IL, IN, KY, LA, MD, MI, MN,
MO, MS, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI.
\3\ The 2010 SO2 emissions cap would apply to years 2010 through 2014. The 2009 NOX emissions cap would apply to
years 2009 through 2014. The 2015 caps would apply to 2015 and beyond.
\4\ Due to the use of the existing bank of SO2 allowances, the estimated SO2 emissions in the CAIR region in
2010 and 2015 would be higher than the emissions caps.
\5\ Over time the banked SO2 emissions allowances would be consumed and the 2015 cap level would be reached. SO2
emissions levels can be thought of as on a flexible ``glide path'' to meet the 2015 CAIR cap with increasing
reductions over time. The annual SO2 emissions levels in 2020 with CAIR, within the region of States required
to make annual reductions (including Delaware and New Jersey), are forecasted to be 3.3 million tons, an
annual reduction of 4.4 million tons from base case levels.

The EPA apportioned the EGU caps--and associated required
regionwide emission reductions--on a State-by-State basis. The affected
States may determine the necessary controls on SO₂ and
NO_X emissions to achieve the required reductions. The EPA's
apportionment method and the resulting State EGU emissions budgets are
described in Section V in today's preamble.
---------------------------------------------------------------------------

\87\ Table IV-16 includes regionwide information for the 25
States and DC that will be required to make annual emission
reductions if EPA finalizes its proposal to require annual
reductions in Delaware and New Jersey under CAIR. The table does not
include information for the 3 States (Arkansas, Connecticut, and
Massachusetts) that would be affected by CAIR for ozone season
reductions only.
---------------------------------------------------------------------------

To achieve the required SO₂ and NO_X
reductions in the most cost-effective manner, EPA suggests that States
implement these reductions by controlling EGUs under a cap and trade
program that EPA would implement.
However, the States have flexibility in choosing the sources that
must reduce emissions. If the States choose to require EGUs to reduce
their emissions, then States must impose a cap on EGU emissions, which
would in effect be an annual emissions budget. Provisions for
allocating SO₂ and NO_X allowances to individual
EGUs--which apply if a State chooses to control EGUs and elects to
allow them to participate in the interstate cap and trade program--are
presented elsewhere in today's preamble. If a State wants to control
EGUs, but does not want to allow EGUs to participate in the interstate
cap and trade program, the State has flexibility in allocating
allowances, but it must cap EGUs. Sources that are subject to the
emission reduction requirements under title IV continue to be subject
to those requirements.
If the States choose to control other sources, then they must
employ methods to assure that those other sources implement controls
that will yield the appropriate amount of annual emissions reduction.
See section VII (SIP Criteria and Emissions Reporting Requirements) in
today's preamble.
Implementation of the cap and trade program is discussed in section
VIII in today's preamble.
For convenience, we use specific terminology to refer to certain
concepts. ``State budget'' refers to the statewide

[[Page 25229]]

emissions that may be used as an accounting technique to determine the
amount of annual or ozone season emissions reductions that controls may
yield. It does not imply that there is a legally enforceable statewide
cap on emissions from all SO₂ or NO_X sources.
``Regionwide budget'' refers to the amount of emissions, computed on a
regionwide basis, which may be used to determine State-by-State
requirements. It does not imply that there is a legally enforceable
regionwide cap on emissions from all SO₂ or NO_X
sources. ``State EGU budget'' refers to the legally enforceable annual
or ozone season emissions cap on EGUs a State would apply should it
decide to control EGUs.

V. Determination of State Emissions Budgets

The EPA outlined in the NPR and SNPR its proposals regarding a
methodology for setting both regional and State-level SO₂
and NO_X budgets. Section IV explains how the regionwide
budgets were developed. This section V describes how EPA apportions the
regionwide emissions reductions--and the associated EGU caps--on a
State-by-State basis, so that the affected States may determine the
necessary controls of SO₂ and NO_X emissions.
In the NPR and SNPR, EPA proposed annual SO₂ and
NO_X caps for States contributing to fine particle
nonattainment and separate ozone-season only caps for States
contributing to ozone--but not fine particle--nonattainment. The EPA is
finalizing an annual cap for both SO₂ and NO_X for
States that contribute to fine particle nonattainment. In addition, EPA
is finalizing an ozone-season only cap for NO_X for all
States that contribute to ozone nonattainment.
States have several options for reducing emissions that
significantly contribute to downwind nonattainment. They can adopt
EPA's approach of reducing the emissions in a cost-effective manner
through an interstate cap and trade program. This approach would, by
definition, achieve the required cost-effective reductions.
Alternately, States could achieve all of the necessary emissions
reductions from EGUs, but choose not to use EPA's interstate emissions
trading program. In this case, a State would need to demonstrate that
it is meeting the EGU budgets outlined in this section. Finally, States
could obtain at least some of their required emissions reductions from
sources other than EGUs. Additional detail on these options is provided
in section VII.

A. What Is the Approach for Setting State-by-State Annual Emissions
Reductions Requirements and EGU Budgets?

This section presents the final methodologies used for apportioning
regionwide emission reduction requirements or budgets to the individual
States.
In the CAIR NPR, EPA proposed methods for determining the
SO₂ and NO_X emission reduction requirements or
budgets for each affected State. In the June 2004 SNPR, EPA proposed
corrections and improvements to the proposals in the CAIR NPR. In the
August 2004 NODA, EPA presented the corrected NO_X budgets
resulting from the improvements proposed in the SNPR.
1. SO₂ Emissions Budgets
a. State Annual SO₂ Emission Budget Methodology
As noted elsewhere in today's preamble, the regionwide annual budget
for 2015 and beyond is based on a 65 percent reduction of title IV
allowances allocated to units in the CAIR States for SO₂
control. The regionwide annual SO₂ budget for the years
2010-2014 is based on a 50 percent reduction from title IV allocations
for all units in affected States.
In the NPR and SNPR, EPA also proposed calculating annual State
SO₂ budgets based on each State's allowances under title IV
of the 1990 CAA Amendments. We are finalizing this proposed approach
for determining State annual SO₂ budgets.
State annual budgets for the years 2010-2014 (Phase I) are based on
a 50 percent reduction from title IV allocations for all units in the
affected State. The State annual budget for 2015 and beyond (Phase II)
is based on a 65 percent reduction of title IV allowances allocated to
units in the affected State for SO₂ control.
Some commenters criticized EPA's basing State budgets on title IV
allocations since these were based largely on 1985-1987 historic heat
input data. Commenters argue that the initial allocation was not
equitable and that in any event, the electric power sector has changed
significantly. They conclude that State budgets should reflect those
differences. Commenters have also commented that tying SO₂
allocations to title IV also does not let States account for units that
are exempt from title IV or for new units that have come online since
1990.
While acknowledging these concerns, EPA believes, for a number of
reasons, that setting State budgets according to title IV allowances
represents a reasonable approach.
The EPA believes that basing budgets on title IV allowances is
necessary in order to ensure the preservation of a viable title IV
program, which is important for reasons discussed in section IX of this
preamble. Such reasons include the desire to maintain the trust and
confidence that has developed in the functioning market for title IV
allowances. The EPA believes it is important not to undermine such
confidence (which is an essential underpinning to a viable market-based
system) recognizing that it is a key to the success of a trading
program under the CAIR.
The title IV program represents a logical starting point for
assessing emissions reductions for SO₂, since it is the
current effective cap on SO₂ emissions for Acid Rain units,
which make up the large majority of affected EGU CAIR units. It is from
this starting emissions cap, that further CAIR reductions are required.
Consequently, EPA proposes State-level reductions based on reductions
from the initial allocations of title IV allowances to individual units
at sources (power plants) in States covered by the CAIR.
The setting of SO₂ budgets differs from the setting of
NO_X budgets for the CAIR, in part, because of this
difference in starting points--since there is no existing
NO_X regional annual cap, and no currency for emissions, on
which sources rely. Furthermore, Congress, as part of title IV of the
CAA, decided upon the allocations of title IV allowances specifically
for the control of SO₂, and not for NO_X.
Moreover, Congress decided to allocate title IV allowances in
perpetuity, realizing that the electricity sector would not remain
static over this time period. Congress clearly did not choose a policy
to regularly revisit and revise these allocations, believing that its
allocations methodology for title IV allowances would be appropriate
for future time periods.
The EPA realizes, putting aside concerns of linkage to title IV,
that there are numerous potential methodologies of dividing up the
regional budgets among the States. Also, EPA believes, that while
initial allocations of State budgets are important for distributional
reasons, under a cap and trade system, they would not impact the
attainment of the environmental objectives or the overall cost of this
rule.
Each of the alternate methods also has certain shortcomings, many
of which have been identified by commenters. Basing allowances on
historic emissions, for instance, would penalize

[[Page 25230]]

States that have already gone through significant efforts to clean up
their sources. Basing allowances on heat input has advantages, but
cannot accommodate States that have worked to improve their energy
efficiency. Basing allowances on output would provide gas-fired units
with many more allowances than they need, rather than giving them to
the coal-fired units that will be incurring the greatest costs from the
tighter caps.
The EPA did look at a number of allowance outcomes using alternate
potential methods for allocating SO₂ allowances. These
methods included allocating on the basis of historic emissions, heat
input (with alternatives based on heat input from all fossil
generation, and heat input from coal- and oil-fired generation only)
and output (with alternatives based on all generation and all fossil-
fired generation). Allocating allowances based on title IV yields
results that fall within a reasonable range of results obtained from
using these alternate methodologies. In fact, calculating State budgets
using title IV allowances yields budgets generally at or within the
ranges of budgets calculated using the other methods in more than two-
thirds of the States, which account for over 85 percent of the total
heat input in the region from 1999-2002. This analysis is discussed
further in the response to comments document.
b. Final SO₂ State Emission Budget Methodology
The EPA is finalizing the budgets as noted in the SNPR, adjusting
for the proper inclusion of States covered under the final CAIR. The
final State budgets are included in Table V-1 below. Details of the
data and methodology used to calculate these budgets are included in
the accompanying ``Regional and State SO₂ and NO_X
Emissions Budgets'' Technical Support Document.

Table V-1.--Final Annual Electric Generating Units SO2 Budgets
[Tons]
------------------------------------------------------------------------
State SO2 State SO2
State budget budget
2010\*\ 2015\**\
------------------------------------------------------------------------
Alabama....................................... 157,582 110,307
District of Columbia.......................... 708 495
Florida....................................... 253,450 177,415
Georgia....................................... 213,057 149,140
Illinois...................................... 192,671 134,869
Indiana....................................... 254,599 178,219
Iowa.......................................... 64,095 44,866
Kentucky...................................... 188,773 132,141
Louisiana..................................... 59,948 41,963
Maryland...................................... 70,697 49,488
Michigan...................................... 178,605 125,024
Minnesota..................................... 49,987 34,991
Mississippi................................... 33,763 23,634
Missouri...................................... 137,214 96,050
New York...................................... 135,139 94,597
North Carolina................................ 137,342 96,139
Ohio.......................................... 333,520 233,464
Pennsylvania.................................. 275,990 193,193
South Carolina................................ 57,271 40,089
Tennessee..................................... 137,216 96,051
Texas......................................... 320,946 224,662
Virginia...................................... 63,478 44,435
West Virginia................................. 215,881 151,117
Wisconsin..................................... 87,264 61,085
--------------
Total..................................... 3,619,196 2,533,434
------------------------------------------------------------------------
\*\Annual budget for SO2 tons covered by allowances for 2010-2014.
\**\Annual budget for SO2 tons covered by allowances for 2015 and
thereafter.

c. Use of SO₂ Budgets
These specific levels of the proposed State budgets would actually
provide binding statewide caps on EGU emissions for States that choose
to control only EGUs but do not want to participate in the trading
program. For States choosing to participate in the trading program,
these State budgets would not be binding, instead, the States'
SO₂ reductions would be achieved solely through the
application of required retirement ratios as discussed in section VII
of this preamble. For States controlling both EGUs and non-EGUs (or
controlling only non-EGUs), these State budgets would be used to
calculate the emissions reductions requirements for non-EGUs and the
remaining reduction requirement for EGUs. This is described in more
detail in the section VII discussion on SIP approvability.
2. NO_X Annual Emissions Budgets
a. Overview
In this section, EPA discusses the apportioning of regionwide
NO_X annual emission reduction requirements or budgets to the
individual States. In the January 2004 proposal, we proposed State EGU
annual NO_X budgets based on each State's average share of
recent historic heat input. In the SNPR, we proposed the same input-
based methodology, but revised the budgets based on more complete heat
input data. Also, EPA took comment on an alternative methodology that
determines State budgets by multiplying heat input data by adjustment
factors for different fuels. In the August NODA, EPA presented the
corrected annual NO_X budgets resulting from the improved
methodology proposed in the SNPR.
b. State Annual NO_X Emissions Budget Methodology

Proposed and Discussed NO_X Emission Budget Methodology

As noted elsewhere in today's preamble, EPA determined historical
annual heat input data for Acid Rain Program units in the applicable
States and multiplied by 0.15 lb/mmBtu (for 2009) and 0.125 lb/mmBtu
(for 2015) to determine total annual NO_X regionwide budgets
for the CAIR region. The EPA applied these rates to each individual
State's total highest annual heat input for any year from 1999 through
2002. Thus, EPA used the heat input total for the year in which a
State's total heat input was the highest.
In the January 2004 proposal, we proposed annual NO_X
State budgets for a 28-State (and D.C.) region based on each
jurisdiction's average heat input--using heat input data from Acid Rain
Program units--over the years 1999 through 2002. We summed the average
heat input from each of the applicable jurisdictions to obtain a
regional total average annual heat input. Then, each State received a
pro rata share of the regional NO_X emissions budget based on
the ratio of its average annual heat input to the regional total
average annual heat input.
In the SNPR, EPA proposed to revise its determination of State
NO_X budgets by supplementing Acid Rain Program unit data
with annual heat input data from the U.S. Energy Information
Administration (EIA), for the non-Acid Rain unit data. A number of
commenters had suggested that this would better reflect the heat input
of the units that will be controlled under the CAIR, and EPA agrees.
In the SNPR, EPA asked for, and subsequently received, comments on
determining State budgets by multiplying heat input data by adjustment
factors for different fuels. The factors would reflect the inherently
higher emissions rate of coal-fired units, and consequently the greater
burden on coal units to control emissions.

Today's Rule

As noted earlier in the case of SO₂, EPA recognizes that
the choice of method in setting State budgets, with a given regionwide
total annual budget, makes little difference in terms of the levels of
resulting regionwide annual

[[Page 25231]]

SO₂ and NO_X emissions reductions. If States
choose to control EGUs and participate in the cap and trade program,
allowances could be freely traded, encouraging least-cost compliance
over the entire region. In such a case, the least-cost outcome would
not depend on the relative levels of individual State budgets.
A number of commenters have stated, without supporting analysis or
evidence, that budgets based on heat input, (and particularly those
that would use different fuel factors) do not encourage efficiency.
Economic theory indicates that neither a heat input, nor an output-
based approach, if allocated once and based on a historical baseline,
would provide any incentives for more or less efficient generation
(changes in future behavior would have no impact on allocations). The
cap and trade system itself, regardless of how the allowances are
distributed, provides the primary incentive for more efficient, cleaner
generation of electricity.
The EPA is finalizing an approach of calculating State budgets
through a fuel-adjusted heat-input basis. State budgets would be
determined by multiplying historic heat input data (summed by fuel) by
different adjustment factors for the different fuels. These factors
reflect for each fuel (coal, gas and oil), the 1999-2002 average
emissions by State, summed for the CAIR region, divided by average heat
input by fuel by State, summed for the CAIR region. The resulting
adjustment factors from this calculation are 1.0 for coal, 0.4 for gas
and 0.6 for oil. The factors would reflect the inherently higher
emissions rate of coal-fired plants, and consequently the greater
burden on coal plants to control emissions.
Such an approach provides States with allowances more in proportion
with their historical emissions. It provides for a more equitable
budget distribution by recognizing that different States are facing the
reduction requirements with different starting stocks of generation,
with different starting emission profiles.\88\ The fuel burned is a key
factor in differentiating the generation.
---------------------------------------------------------------------------

\88\ States receiving larger budgets under this approach are
generally expected to be those having to make the most reductions.
---------------------------------------------------------------------------

However, this approach is not equivalent to an approach based
strictly on historical emissions (which would give fewer allowances to
States which have already cleaned up their coal plants). Under the
approach we are finalizing today, heat input from all coal, whether
clean or uncontrolled, would be counted equally in determining State
budgets. Likewise, all heat input from gas, whether clean or
uncontrolled, from a steam-gas unit or from a combined-cycle plant,
would be counted equally in determining State budgets.
It is not expected that this decision would disadvantage States
with significant gas-fired generation. One reason is that the
calculation of the adjusted heat input for natural gas generation
generally includes significant historic heat input and emissions from
older, less efficient and dirtier steam gas units. These units'
capacity factors are declining and are expected to decline further over
time as new, cleaner and more efficient combined-cycle gas units
increase their generation.
It is important to note that the methodology by which the
NO_X State budgets are determined need not be used by
individual States in determining allocations to specific sources. As
discussed in section VIII of this document (Model Trading Rule), EPA is
offering States the flexibility to allocate allowances from their
budgets as they see fit.
Finally, EPA discussed in the January 2004 proposal, a methodology
used in the NO_X SIP Call (67 FR 21868) that applied State-
specific growth rates for heat input in setting State budgets.\89\ The
EPA, in the SNPR, noted that it is not proposing to use this method for
the CAIR because we believe that other methods are reasonable, and that
methods involving State-specific growth rates present certain
challenges due to the inherent difficulties in predicting State-
specific growth in heat input over a lengthy period, especially for
jurisdictions that are only a part of a larger regional electric power
dispatch region. Several commenters stated their support for
incorporating growth, believing that not taking growth into account
would penalize States with higher growth. However, a significant number
of commenters stated their opposition to using growth in setting State
budgets, noting the problems that arose in the NO_X SIP Call.
The EPA believes that setting budgets using a heat input approach,
without a growth adjustment, is fair, would be simpler and would
involve less risk of resulting litigation.
---------------------------------------------------------------------------

\89\ With a methodology similar to that used in the
NO_X SIP Call, annual State NO_X budgets would
be set by using a base heat input data, then adjusting it by a
calculated growth rate for each jurisdiction's annual EGU heat
inputs.
---------------------------------------------------------------------------

c. Final Annual State NO_X Emission Budgets
The final annual State NO_X emission budgets following
this method are included in Table V-2 below. Details of the numbers and
methodology used to calculate these budgets are included in the
``Regional and State SO₂ and NO_X Emissions
Budgets'' Technical Support Document.

Table V-2.--Final Annual Electric Generating Units NOX Budgets
[Tons]
------------------------------------------------------------------------
State NOX State NOX
State budget budget
2009\*\ 2015\**\
------------------------------------------------------------------------
Alabama....................................... 69,020 57,517
District of Columbia.......................... 144 120
Florida....................................... 99,445 82,871
Georgia....................................... 66,321 55,268
Illinois...................................... 76,230 63,525
Indiana....................................... 108,935 90,779
Iowa.......................................... 32,692 27,243
Kentucky...................................... 83,205 69,337
Louisiana..................................... 35,512 29,593
Maryland...................................... 27,724 23,104
Michigan...................................... 65,304 54,420
Minnesota..................................... 31,443 26,203
Mississippi................................... 17,807 14,839
Missouri...................................... 59,871 49,892
New York...................................... 45,617 38,014
North Carolina................................ 62,183 51,819
Ohio.......................................... 108,667 90,556
Pennsylvania.................................. 99,049 82,541
South Carolina................................ 32,662 27,219
Tennessee..................................... 50,973 42,478
Texas......................................... 181,014 150,845
Virginia...................................... 36,074 30,062
West Virginia................................. 74,220 61,850
Wisconsin..................................... 40,759 33,966
--------------
Total..................................... 1,504,871 1,254,061
------------------------------------------------------------------------
\*\Annual budget for NOX tons covered by allowances for 2009-2014.
\**\Annual budget for NOX tons covered by allowances for 2015 and
thereafter.

d. Use of Annual NO_X Budgets
These proposed State budgets would serve as effective binding caps
on State emissions, if States chose to control only EGUs, but did not
want to participate in the trading program. For States controlling both
EGUs and non-EGUs (or controlling only non-EGUs), these budgets would
be compared to a baseline level of emissions to calculate the emissions
reductions requirements for non-EGUs and the required caps for EGUs.
This process is described in more detail in the section VII discussion
on SIP approvability.
e. NO_X Compliance Supplement Pool
As is discussed in section I, EPA is establishing a NO_X
compliance supplement pool of 198,494 tons, which would result in a
total compliance supplement pool of approximately 200,000 tons of
NO_X when combined with EPA's proposed rulemaking to include
Delaware and New Jersey. The

[[Page 25232]]

EPA is apportioning the compliance supplement pool to States based on
the assumption that a State's need for allowances from the pool is
proportional to the magnitude of the State's required emissions
reductions (as calculated using the State's base case emissions and
annual NO_X budget). The EPA is apportioning the 200,000 tons
of NO_X on a pro-rata basis, based on each State's share of
the total emissions reductions requirement for the region in 2009. This
is consistent with the methodology used in the NO_X SIP Call.
Table V-3 presents each State's compliance supplement pool.

Table V-3.--State NOX Compliance Supplement Pools
[Tons]
----------------------------------------------------------------------------------------------------------------
Base case 2009 State Compliance
State 2009 annual NOX Reduction supplement
emissions budget requirement pool \*\
----------------------------------------------------------------------------------------------------------------
Alabama..................................................... 132,019 69,020 62,999 10,166
District of Columbia........................................ 0 144 0 0
Florida..................................................... 151,094 99,445 51,649 8,335
Georgia..................................................... 143,140 66,321 76,819 12,397
Illinois.................................................... 146,248 76,230 70,018 11,299
Indiana..................................................... 233,833 108,935 124,898 20,155
Iowa........................................................ 75,934 32,692 43,242 6,978
Kentucky.................................................... 175,754 83,205 92,549 14,935
Louisiana................................................... 49,460 35,512 13,948 2,251
Maryland.................................................... 56,662 27,724 28,938 4,670
Michigan.................................................... 117,031 65,304 51,727 8,347
Minnesota................................................... 71,896 31,443 40,453 6,528
Mississippi................................................. 36,807 17,807 19,000 3,066
Missouri.................................................... 115,916 59,871 56,045 9,044
New York.................................................... 45,145 45,617 0 0
North Carolina.............................................. 59,751 62,183 0 0
Ohio........................................................ 263,814 108,667 155,147 25,037
Pennsylvania................................................ 198,255 99,049 99,206 16,009
South Carolina.............................................. 48,776 32,662 16,114 2,600
Tennessee................................................... 106,398 50,973 55,425 8,944
Texas....................................................... 185,798 181,014 4,784 772
Virginia.................................................... 67,890 36,074 31,816 5,134
West Virginia............................................... 179,125 74,220 104,905 16,929
Wisconsin................................................... 71,112 40,759 30,353 4,898
--------------
CAIR region subtotal.................................... ........... ........... ........... 198,494
--------------
Delaware.................................................... 9,389 4,166 5,223 843
New Jersey.................................................. 16,760 12,670 4,090 660
--------------
Total................................................... ........... ........... ........... 199,997
----------------------------------------------------------------------------------------------------------------
\*\ Rounding to the nearest whole allowance results in a total compliance supplement pool of 199,997 tons.

B. What Is the Approach for Setting State-by-State Emissions Reductions
Requirements and EGU Budgets for States With NO_X Ozone
Season Reduction Requirements?

1. States Subject to Ozone-Season Requirements
In the NPR, EPA proposed that Connecticut contributes significantly
to ozone nonattainment in another State, but not to fine particle
nonattainment. As a result of subsequent air quality modeling, EPA has
also found that Massachusetts, New Jersey, Delaware and Arkansas
contribute significantly to ozone nonattainment in another State, but
not to fine particle nonattainment. In this final rule, EPA is
establishing a regionwide ozone-season budget for all States that
contribute significantly to ozone nonattainment in another State,
regardless of their contribution to fine particle nonattainment. The
following 25 States, plus the District of Columbia, are found to
contribute significantly to ozone nonattainment: Alabama, Arkansas,
Connecticut, Delaware, Florida, Illinois, Indiana, Iowa, Kentucky,
Louisiana, Maryland, Massachusetts, Michigan, Mississippi, Missouri,
New Jersey, New York, North Carolina, Ohio, Pennsylvania, South
Carolina, Tennessee, Virginia, West Virginia, and Wisconsin.
These States are subject to an ozone season NO_X cap,
which covers the 5 months of May through September. The EPA is
calculating the ozone season cap level for the 25 States plus the
District of Columbia region by multiplying the region's ozone season
heat input by 0.15 lb/mmBtu for 2009 and 0.125 lb/mmBtu for 2015. Heat
input for the region was estimated by looking at reported ozone season
Acid Rain heat inputs for each State for the years 1999 through 2002,
and selecting the single year highest heat input for each State as a
whole.
As is the case for the annual NO_X State Budgets, EPA is
finalizing an approach of calculating ozone season NO_X State
budgets through a fuel-adjusted heat input basis. State budgets would
be determined by multiplying State-level average historic ozone-season
heat input data (summed by fuel) by different adjustment factors for
the different fuels (1.0 for coal, 0.4 for gas, and 0.6 for oil). The
total ozone season State budgets are then determined by calculating
each State's share of total fuel-adjusted heat input, and multiplying
this share by the regionwide budget.
The budgets for these States in 2009 and 2015 are included in Table
V-4 below.

[[Page 25233]]

Table V-4.--Final Seasonal Electricity Generating Unit NOX Budgets
[Tons]
------------------------------------------------------------------------
State NOX State NOX
State budget 2009 budget 2015
* **
------------------------------------------------------------------------
Alabama....................................... 32,182 26,818
Arkansas...................................... 11,515 9,596
Connecticut................................... 2,559 2,559
Delaware...................................... 2,226 1,855
District of Columbia.......................... 112 94
Florida....................................... 47,912 39,926
Illinois...................................... 30,701 28,981
Indiana....................................... 45,952 39,273
Iowa.......................................... 14,263 11,886
Kentucky...................................... 36,045 30,587
Louisiana..................................... 17,085 14,238
Maryland...................................... 12,834 10,695
Massachusetts................................. 7,551 6,293
Michigan...................................... 28,971 24,142
Mississippi................................... 8,714 7,262
Missouri...................................... 26,678 22,231
New Jersey.................................... 6,654 5,545
New York...................................... 20,632 17,193
North Carolina................................ 28,392 23,660
Ohio.......................................... 45,664 39,945
Pennsylvania.................................. 42,171 35,143
South Carolina................................ 15,249 12,707
Tennessee..................................... 22,842 19,035
Virginia...................................... 15,994 13,328
West Virginia................................. 26,859 26,525
Wisconsin..................................... 17,987 14,989
--------------
Total..................................... 567,744 484,506
------------------------------------------------------------------------
* Seasonal budget for NOX tons covered by allowances for 2009-2014. For
States that have lower EGU budgets under the NOX SIP Call than their
2009 CAIR budget, table V-4 includes their SIP Call budget. For
Connecticut, the NOX SIP Call budget is also used for 2015 and beyond.
** Seasonal budget for NOX tons covered by allowances for 2015 and
thereafter.

VI. Air Quality Modeling Approach and Results

Overview

In this section we summarize the air quality modeling approach used
for the proposed rule, we address major comments on the fundamental
aspects of EPA's proposed approach, and we describe the updated and
improved approach, based on those comments, that we are finalizing
today. This section also contains the results of EPA's final air
quality modeling, including: (1) Identifying the future baseline
PM_2.5 and 8-hour ozone nonattainment counties in the East;
(2) quantifying the contribution from emissions in upwind States to
nonattainment in these counties; (3) quantifying the air quality
impacts of the CAIR reductions on PM_2.5 and 8-hour ozone;
and (4) describing the impacts on visibility in Class I areas of
implementing CAIR compared to implementing the regional haze
requirement for best available retrofit technology (BART).
We present the air quality models, model configuration, and
evaluation; and then the emissions inventories and meteorological data
used as inputs to the air quality models. Next, we provide the updated
interstate contributions for PM_2.5 and 8-hour ozone and
those States that make a significant contribution to downwind
nonattainment, before considering cost. Finally, we present the
estimated impacts of the CAIR emissions reductions on air quality and
visibility. As described below, our air quality modeling for today's
rule utilizes the Community Multiscale Air Quality (CMAQ) model in
conjunction with 2001 meteorological data for simulating
PM_2.5 concentrations and associated visibility effects and
the Comprehensive Air Quality Model with Extensions (CAMx) with
meteorological data for three episodes in 1995 for simulating 8-hour
ozone concentrations. Our approach to modeling both PM_2.5
and 8-hour ozone involves applying these tools (i.e., CMAQ for
PM_2.5 and CAMx for 8-hour ozone) using updated emissions
inventory data for 2001, 2010, and 2015 to project future baseline
concentrations, interstate transport, and the impacts of CAIR on
projected nonattainment of PM_2.5 and 8-hour ozone. We
provide additional information on the development of our updated CAIR
air quality modeling platform, the modeling analysis techniques, model
evaluation, and results for PM_2.5 and 8-hour ozone modeling
in the CAIR Notice of Final Rulemaking Emissions Inventory Technical
Support Document (NFR EITSD) and the Air Quality Modeling Technical
Support Document (NFR AQMTSD).

A. What Air Quality Modeling Platform Did EPA Use?

1. Air Quality Models
a. The PM_2.5 Air Quality Model and Evaluation

Overview

In the NPR, we used the Regional Model for Simulating Aerosols and
Deposition (REMSAD) as the tool for simulating base year and future
concentrations of PM_2.5. Like most photochemical grid
models, the predictions of REMSAD are based on a set of atmospheric
specie mass continuity equations. This set of equations represents a
mass balance in which all of the relevant emissions, transport,
diffusion, chemical reactions, and removal processes are expressed in
mathematical terms. The modeling domain used for this analysis covers
the entire continental United States and adjacent portions of Canada
and Mexico.
The EPA applied REMSAD for an annual simulation using meteorology
and emissions for 1996. We used the results of this 1996 Base Year
model run to evaluate how well the modeling system (i.e., the air
quality model and input data sets) replicated measured data over the
time period and domain simulated. We performed a model evaluation for
PM_2.5 and speciated components (e.g., sulfate, nitrate,
elemental carbon, organic carbon, etc.) as well as nitrate, sulfate and
ammonium wet deposition, and visibility. The evaluation used available
1996 ambient measurements paired with REMSAD predictions corresponding
to the location and time periods of the measured data. We quantified
model performance using various statistical and graphical techniques.
Additional information on the model evaluation procedures and results
are included in the Notice of Proposed Rulemaking Air Quality Modeling
Technical Support Document (NPR AQMTSD).
The EPA received numerous comments on various elements of the
proposed PM_2.5 air quality modeling approach. The major
comments are responded to below. Other comments are addressed the
Response to Comment (RTC) document. Regarding REMSAD, commenters argued
that: (1) The REMSAD model is an inappropriate tool for modeling
PM_2.5; (2) the scientific formulation of the model is
simplistic and outdated and that other models with better science are
available and should be used; and (3) results from REMSAD are
directionally correct but better tools should be used as the basis for
the final determinations on transport and projected nonattainment.
We agree that models with more refined science are available for
PM_2.5 modeling and we have selected one of these models, the
CMAQ as the tool for PM_2.5 modeling for the final CAIR. The
CMAQ model is a publicly available, peer-reviewed, state-of-the-science
model with a number of science attributes that are critical for
accurately simulating the oxidant precursors and non-linear organic and
inorganic chemical relationships associated with the formation of
sulfate, nitrate, and organic aerosols. Several of the important
science aspects of CMAQ that are superior to REMSAD include: (1)
Updated gaseous/heterogeneous chemistry that provides the basis for the
formation of nitrates and includes a

[[Page 25234]]

current inorganic nitrate partitioning module; (2) in-cloud sulfate
chemistry, which accounts for the non-linear sensitivity of sulfate
formation to varying pH; (3) a state-of-the-science secondary organic
aerosol module that includes a more comprehensive gas-particle
partitioning algorithm from both anthropogenic and biogenic secondary
organic aerosol; and (4) the full CB-IV chemistry mechanism, which
provides a complete simulation of aerosol precursor oxidants.
However, even though REMSAD does not have all the scientific
refinements of CMAQ, we believe that REMSAD treats the key physical and
chemical processes associated with secondary aerosol formation and
transport. Thus, we believe that the conclusions based on the proposal
modeling using REMSAD are valid and therefore support today's findings
based only on CMAQ that: (1) There will be widespread PM_2.5
nonattainment in the eastern U.S. in 2010 and 2015 absent the
reductions from CAIR; (2) upwind States in the eastern part of the
United States contribute to the PM_2.5 nonattainment problems
in other downwind States; (3) States with high emissions tend to
contribute more than States with low emissions; (4) States close to
nonattainment areas tend to contribute more than other States farther
upwind; and (5) the CAIR controls will produce major benefits in terms
of bringing areas into or closer to attainment.
Comments and Responses
(i) REMSAD Science and Evaluation
Comment: Some commenters stated that REMSAD is an inappropriate
model for use in simulating PM_2.5. Other commenters said,
more specifically, that the chemical mechanism in REMSAD (i.e., micro
CB-IV) is simplified and not validated, and that the model has not been
scientifically peer-reviewed.
Response: The EPA disagrees with comments claiming that REMSAD is
an inappropriate tool for modeling PM_2.5. The EPA believes
that REMSAD is appropriate for regional and national modeling
applications because the model does include the key physical and
chemical processes associated with secondary aerosol formation and
transport.\90\
---------------------------------------------------------------------------

\90\ Even so, EPA acknowledges that REMSAD has certain
limitations not found in CMAQ.
---------------------------------------------------------------------------

Specifically, REMSAD simulates both gas phase and aerosol
chemistry. The gas phase chemistry uses a reduced-form version of
Carbon Bond chemical mechanism (micro-CB-IV). Formation of inorganic
secondary particulate species, such as sulfate and nitrate, are
simulated through chemical reactions within the model. Aerosol sulfate
is formed in both the gas phase and the aqueous phase. The REMSAD model
also accounts for the production of secondary organic aerosols through
chemistry processes involving volatile organic compounds (VOC) and
directly emitted organic particles. Emissions of non-reactive particles
(e.g., elemental carbon) are treated as inert species which are
advected and deposited during the simulation.
With regard to comments on the micro CB-IV chemical mechanism,
although this mechanism treats fewer organic carbon species compared to
the full CB-IV, the inorganic portion of the reduced mechanism is
identical to the full chemical mechanism. The intent of the CB-IV
mechanism is to: (a) Provide a faithful representation of the linkages
between emissions of ozone precursor species and secondary aerosol
precursor species; (b) treat the oxidizing capacity of the troposphere,
represented primarily by the concentrations of radicals and hydrogen
peroxide; and (c) simulate the rate of oxidation of the nitrogen oxide
(NO_X) and sulfur dioxide (SO₂), which are
precursors to secondary aerosols. The EPA agrees that micro CB-IV is
simplified compared to the full CB-IV mechanism. However, performance
testing of micro CB-IV indicates that this simplified mechanism is
similar to the full CB-IV chemical mechanism in simulating ozone
formation and approximates other species reasonably well (e.g.,
hydroxyl radical, hydroperoxy radical, the operator radical, hydrogen
peroxide, nitric acid, and peroxyacetyl nitrate).\91\
---------------------------------------------------------------------------

\91\ Whitten, G. memorandum: Comparison of REMSAD Reduced
Chemistry to Full CB-4. February 19, 2001.
---------------------------------------------------------------------------

The REMSAD model was subjected to a scientific peer-review
(Seigneur et al., 1999) and EPA has incorporated the major science
improvements that were recommended by the peer-review panel. These
improvements were included in the version of REMSAD used for the NPR
modeling. Specifically, the following updates have been implemented
into REMSAD Version 7.06, which was used for the proposed CAIR control
strategy simulations: (1) The nighttime chemistry treatment was updated
to improve the treatment of the gas phase species NO₃ and
N₂O₅; (2) the effects of temperature and pressure
dependence on chemical rates were added; (3) the MARS-A aerosol
partitioning module was added for calculating particle and gas phase
fractions of nitrate; (4) aqueous phase formation of sulfate was
updated by including reactions for oxidation of SO₂ by ozone
and oxygen, (5) peroxynitric acid (PNA) chemistry was added; and (6) a
module for calculating biogenic and anthropogenic secondary organic
aerosols was developed and integrated into REMSAD. We believe that
these changes adequately respond to the peer review comments and have
bolstered the scientific credibility of this model.
(ii) Use of CMAQ Instead of REMSAD for PM_2.5 Modeling
Comment: Some commenters claimed that REMSAD is outdated and that
other models with more sophisticated science are available. Commenters
said that EPA should utilize the best available science through use of
the most comprehensive photochemical model for simulating aerosols.
Commenters specifically stated that EPA should use more recently
developed models such as the CMAQ model or the aerosol version of the
Comprehensive Air Quality Model with Extensions (CAM_X-PM).
Response: The EPA agrees that photochemical models are now
available that are more scientifically sophisticated than REMSAD. In
this regard, and in response to commenters' recommendations on specific
models, EPA has selected CMAQ as the modeling tool for the final CAIR
modeling analysis. As stated above, the CMAQ model is a publicaly
available, peer-reviewed, state-of-the-science model with a number of
science attributes that are critical for accurately simulating the
oxidant precursors and non-linear organic and inorganic chemical
relationships associated with the formation of sulfate, nitrate, and
organic aerosols. As listed above, the important science aspects of
CMAQ that are superior to REMSAD include: (1) Updated gaseous/
heterogeneous chemistry that provides the basis for the formation of
nitrates and includes a current inorganic nitrate partitioning module;
(2) in-cloud sulfate chemistry, which accounts for the non-linear
sensitivity of sulfate formation to varying pH; (3) a state-of-the-
science secondary organic aerosol module that includes a more
comprehensive gas-particle partitioning algorithm from both
anthropogenic and biogenic secondary organic aerosol; and (4) the full
CB-IV chemistry mechanism, which provides a complete simulation of
aerosol precursor oxidants.
(iii) Model Evaluation
Comment: A number of commenters claimed that EPA's air quality
model evaluation for 1996 was deficient because it lacked sufficient
ambient measurements, especially in urban

[[Page 25235]]

areas, to judge model performance. Commenters said that EPA should: (1)
Update the evaluation to a more recent time period in order to take
advantage of greatly expanded ambient PM_2.5 species
measurements, especially in urban areas; and (2) calculate model
performance statistics over monthly and/or seasonal time periods using
daily/weekly observed/model-predicted data pairs.
Some commenters said that the 1996 data were so limited that it is
not possible to determine whether REMSAD could be used with confidence
to assess the effects of emissions changes. Still, other commenters
said that the performance of REMSAD for the 1996 modeling platform was
poor.
Commenters acknowledged that there are no universally accepted or
EPA-recommended quantitative criteria for judging the acceptability of
PM_2.5 model performance. In the absence of such model
performance acceptance criteria, some commenters said that performance
should be judged by comparing EPA's model performance results to the
range of results obtained by other groups in the air quality modeling
community who conducted other recent regional PM_2.5 model
applications. A few commenters also identified specific model
performance ranges and criteria that they said should be achievable for
sulfate and PM_2.5, given the current state-of-science for
aerosol modeling and measurement uncertainty. The specific values cited
by these commenters are ±30 percent to ±50
percent for fractional bias, 50 percent to 75 percent for fractional
error, and 50 percent for normalized error.
Response: The EPA agrees that the limited amount of ambient
PM_2.5 species data available in 1996 affected our ability to
evaluate model performance, especially in urban areas, and there were
deficiencies in the performance of REMSAD using the 1996 model inputs.
Also, EPA agrees that a model evaluation should be performed for a more
recent time period in order to address these concerns. Thus, we
conclude that the 1996 modeling platform which includes 1996 emissions,
1996 meteorology, and 1996 ambient data should be updated and improved,
as recommended by commenters.
The EPA has developed a new modeling platform which includes
emissions, meteorological data, and other model inputs for 2001. This
platform was used to confirm the ability of our modeling system to
replicate ambient PM_2.5 and component species in both urban
and rural areas and, thus, establish the credibility of this platform
for PM_2.5 modeling as part of CAIR.\92\ In 2001, there was
an extensive set of ambient PM_2.5 measurements including 133
urban Speciation Trends Network (STN) monitoring sites across the
nation, with 105 of these in the East. This network did not exist in
1996. Also, the number of mainly suburban and rural monitoring sites in
the Clean Air Status and Trends Network (CASTNET) and Interagency
Monitoring of Protected Visual Environments (IMPROVE) network has
increased to over 200 in 2001, compared to approximately 120 operating
in 1996.
---------------------------------------------------------------------------

\92\ The 2001 modeling platform is described in full in the NFR
EITSD and NFR AQMTSD.
---------------------------------------------------------------------------

The EPA evaluated CMAQ for the 2001 modeling platform using the
extensive set of 2001 monitoring data for PM_2.5 species. The
evaluation included a statistical analysis in which the model
predictions and measurements were paired in space and in time (i.e.,
daily or weekly to be consistent with the sampling protocol of the
monitoring network). Model performance statistics were calculated for
each network with separate statistics for sites in the West and the
East.\93\ In response to comments that performance statistics should be
calculated over monthly and/or seasonal time periods, we elected to use
seasonal time periods in order to be consistent with our use of
quarterly average PM_2.5 species as part of the procedure for
projecting future concentrations, as described below in section VI.B.1.
In addition, the sampling frequency at the CASTNET, IMPROVE, and STN
sites may not provide sufficient samples in a 1-month period to provide
a robust calculation of model performance statistics. Details of EPA's
model evaluation for CMAQ using the 2001 modeling platform are in the
report ``Updated CMAQ Model Performance Evaluation for 2001'' which can
be found in the docket for today's rule.
---------------------------------------------------------------------------

\93\ For the purposes of this analysis, we have defined ``East''
as the area to the east of 100 degrees longitude, which runs from
approximately the eastern half of Texas through the eastern half of
North Dakota.
---------------------------------------------------------------------------

The EPA agrees that there are no universally accepted performance
criteria for PM_2.5 modeling and that performance should be
judged by comparison to the performance found by other groups in the
air quality modeling community. In this respect, we have compared our
CMAQ 2001 model performance results to the range of performance found
in other recent regional PM_2.5 model applications by other
groups.\94\ Details of this comparison can be found in the CMAQ
evaluation report. Below is a summary of performance results from
other, non-EPA modeling studies, for summer sulfate and winter nitrate.
It CAIR. Overall, the general range of fractional bias (FB) and
fractional error (FE) statistics for the better performing model
applications are as follows:
---------------------------------------------------------------------------

\94\ These other modeling studies represent a wide range of
modeling analyses which cover various models, model configurations,
domains, years and/or episodes, chemical mechanisms, and aerosol
modules.

--Summer sulfate is in the range of -10 percent to +30 percent for FB
and 35 percent to 50 percent for FE; and
--Winter nitrate is in the range of +50 percent to +70 percent for FB
and 85 percent to 105 percent for FE.

The corresponding performance statistics for EPA's 2001 CMAQ
application as well as the 1996 REMSAD application used for the
proposal modeling are provided in Table VI-1.

Table VI-1.--Selected Performance Evaluation Statistics From the CMAQ 2001 Simulation and the REMSAD 1996
Simulation
----------------------------------------------------------------------------------------------------------------
CMAQ 2001 REMSAD 1996
Eastern U.S. ---------------------------------------------------
FB(%) FE(%) FB(%) FE(%)
----------------------------------------------------------------------------------------------------------------
Sulfate (Summer):
STN..................................................... 14 44 ........... ...........
Improve................................................. 10 42 -20 51
CASTNet................................................. 3 22 -21 59
Nitrate (Winter)
STN..................................................... 15 73 ........... ...........

[[Page 25236]]

Improve................................................. 21 92 67 103
----------------------------------------------------------------------------------------------------------------

The results indicate that the performance for CMAQ in 2001 is
within the range or better than that found by other groups in recent
applications. The performance also meets the benchmark goals suggested
by several commenters. In addition, the CMAQ performance is
considerably improved over that of the REMSAD 1996 performance for
summer sulfate and winter nitrate, which were near the bounds or
outside the range of other recent applications.
The CMAQ model performance results give us confidence that our
applications of CMAQ using the new modeling platform provide a
scientifically credible approach for assessing PM_2.5
concentrations for the purposes of CAIR.
b. Ozone Air Quality Modeling Platform and Model Evaluation
Overview
The EPA used the CAM_X, version 3.10 in the NPR to assess
8-hour ozone concentrations and the impacts of ozone and ozone
precursor transport on elevated levels of ozone across the eastern U.S.
The CAM_X is a publicly available Eulerian model that
accounts for the processes that are involved in the production,
transport, and destruction of ozone over a specified three-dimensional
domain and time period. The CAM_X model was run with 1995/96
base year emissions to evaluate the performance of the modeling
platform to replicate observed concentrations during the three 1995
episodes. This evaluation was comprised principally of statistical
assessments of hourly, 1-hour daily maximum, and 8-hour daily maximum
ozone predictions. As described in the NPR AQMTSD, model performance of
CAM_X for ozone was judged against the results from previous
regional ozone model applications. This analysis indicates that model
performance was comparable to or better than that found in previous
applications and is, therefore, acceptable for the purposes of CAIR
ozone modeling.
The EPA did not receive comments on the CAM_X model or
the model performance for ozone. The EPA did receive comments on the
choice of episodes for ozone modeling, the meteorological data for
these episodes, the spatial resolution of our modeling, and consistency
between ozone and PM_2.5 modeling in terms of methods for
projecting future air quality concentrations. As described below and in
the RTC document and NFR AQMTSD, we continue to believe that: (1) The
three 1995 episodes are representative episodes for regional modeling
of 8-hour ozone; and (2) the meteorological data for these episodes and
spatial resolution are adequate for use in our modeling for CAIR. Thus,
the ozone air quality assessments in today's rule rely on
CAM_X modeling of meteorological data for the three 1995
episodes for the domain and spatial resolution used for the NPR. As
discussed below, we ran CAM_X for the updated 2001 emissions
inventory and the updated 2010 and 2015 base case inventories as part
of the process to project 8-hour ozone for these future year scenarios.
We revised our method of projecting future ozone concentrations to be
consistent with the method we are using for PM_2.5.
c. Model Grid Cell Configuration
As described in the NPR AQMTSD, the PM_2.5 modeling for
the proposal was performed for a domain (i.e., area) covering the 48
States and adjacent portions of Canada and Mexico. Within this domain,
the model predictions were calculated for a grid network with a spatial
resolution of approximately 36 km. Our 8-hour ozone modeling for
proposal was performed using a nested grid network. The outer portion
of this grid has a spatial resolution of approximately 36 km. The inner
``nested'' area, which covers a large portion of the eastern U.S., has
a resolution of approximately 12 km.
Comment: Some commenters said that the 36 km grid cell size used by
EPA in modeling PM_2.5 and the 36 km/12 km grid resolution
used for ozone modeling are too coarse and are inconsistent with EPA's
draft modeling guidance.
Response: We disagree with these comments and continue to believe
that the grid dimensions for our PM_2.5 modeling and our 8-
hour ozone modeling are not too coarse nor are they inconsistent with
our draft guidance documents for PM_2.5 modeling \95\ and
ozone modeling.\96\ The draft guidance for PM_2.5 modeling
states that 36 km resolution is acceptable for regional scale
applications in portions of the domain outside of nonattainment areas.
For portions of the domain which cover nonattainment areas, 12 km
resolution or less is recommended by the guidance. However, as stated
in the guidance document, these recommendations were based on guidance
for 8-hour ozone modeling because there was a lack of PM_2.5
modeling at different grid resolutions at the time the guidance was
drafted. In addition, the PM_2.5 guidance states that
exceptions to these recommendations can be made on a case-by-case basis.
---------------------------------------------------------------------------

\95\ U.S. EPA, 2000: Draft Guidance for Demonstrating Attainment
of the Air Quality Goals for PM_2.5 and Regional Haze;
Draft 1.1, Office of Air Quality Planning and Standards, Research
Triangle Park, NC.
\96\ U.S. EPA, 1999: Draft Guidance on the Use of Models and
Other Analyses in Attainment Demonstrations for the 8-Hour Ozone
NAAQS, Office of Air Quality Planning and Standards, Research
Triangle Park, NC.
---------------------------------------------------------------------------

For several reasons, we believe that 36 km resolution is sufficient
for PM_2.5 modeling for the purposes of CAIR. First, recent
analyses that compare 36 km to 12 km modeling of PM_2.5 \97\
indicate that spatial mean concentrations of gas phase and aerosol
species at 36 km and 12 km are quite similar. A comparison of model
predictions versus observations indicates that the model performance is
similar at 12 km and 36 km in both rural and urban areas. Thus, using
12 km resolution does not necessarily provide any additional confidence
in the results. Second, ambient measurements of sulfate and to a
significant extent nitrate, which are the pollutants of most importance
for CAIR, do not exhibit large spatial differences between rural and
urban areas, as described elsewhere in today's rule. This implies that
it is not necessary to use fine resolution modeling in order to
properly capture

[[Page 25237]]

the regional concentration patterns of these pollutants.
---------------------------------------------------------------------------

\97\ VISTAS Emissions and Air Quality Modeling--Phase I Task 4cd
Report: Model Performance Evaluation and Model Sensitivity Tests for
Three Phase I Episodes. ENVIRON International Corporation, Alpine
Geophysics, and University of California at Riverside, September 7, 2004.
---------------------------------------------------------------------------

Our draft 8-hour ozone modeling guidance recommends using 36 km
resolution for regional modeling with nested grid cells not exceeding
12 km over urban portions of the modeling domain. The guidance states
that 4 to 5 km resolution for urban areas is preferred, if feasible. In
addition, if 12 km modeling is used then plume-in-grid treatment for
large point sources of NO_X should be considered.
Our modeling for CAIR is consistent with this guidance in that we
use 36 km resolution for the outer portions of the region; 12 km
resolution covering nearly all urban areas in the domain; and a plume-
in-grid algorithm for major NO_X point sources in the region.
In addition, analyses that compare model 12 km resolution to 4 km
resolution for portions of our 1995 episodes indicate that the spatial
fields predicted at both 12 km and 4 km have many common features in
terms of the areas of high and low ozone.\98\ In a comparison of model
predictions to observation, the 12 km modeling was found to be somewhat
more accurate than the finer 4 km modeling.
---------------------------------------------------------------------------

\98\ Irwin, J. et al. ``Examination of model predictions at
different horizontal grid resolutions.'' Submitted for Publication
to Environmental Fluid Mechanics.
---------------------------------------------------------------------------

2. Emissions Inventory Data
For the proposed rule, emissions inventories were created for the
48 contiguous States and the District of Columbia. These inventories
were estimated for a 2001 base year to reflect current emissions and
for 2010 and 2015 future baseline scenarios. The inventories were
prepared for electric generating units (EGUs), industrial and
commercial sources (non-EGUs), stationary area sources, on-road
vehicles, and non-road engines. The inventories contained both annual
and typical summer season day emissions for the following pollutants:
oxides of nitrogen (NO_X); volatile organic compounds (VOC);
carbon monoxide (CO); sulfur dioxide (SO₂); direct
particulate matter with an aerodynamic diameter less than 10
micrometers (PM₁₀) and less than 2.5 micrometers
(PM_2.5); and ammonia (NH₃). A summary of the
development of these inventories is provided below. Additional
information on the emissions inventory used for proposal can be found
in the NPR AQMTSD.
Because the complete 2001 National Emission Inventory (NEI) and
future-year projections consistent with that NEI were not available in
a form suitable for air quality modeling when needed for the proposal,
we developed a reasonably representative ``proxy'' inventory for 2001.
For the EGU, mobile, and non-road emissions sectors, 1996-to-2001
adjustment ratios were created by dividing State-level total emissions
for each pollutant for 2001 by the corresponding consistent 1996
emissions. These adjustment ratios were then multiplied by the REMSAD-
ready 1996 emissions for these two sectors to produce REMSAD-ready
files for the 2001 proxy. For non-EGUs and stationary area sources,
linear interpolations were performed between the REMSAD-ready 1996
emissions and the REMSAD-ready 2010 base case emissions to produce 2001
proxy emissions for these two sectors. Details on the creation of the
2001 proxy inventory used for proposal are provided in the NPR AQMTSD.
The NPR future 2010 and 2015 base case emissions reflect projected
economic growth and control programs that are to be implemented by 2010
and 2015, respectively. Control programs included in these future base
cases include those State, local, and Federal measures already
promulgated and other significant measures expected to be promulgated
before the final rule is implemented. Future year 2010 and 2015 base
case EGU emissions were obtained from versions 2.1 and 2.1.6 of the
Integrated Planning Model (IPM).
Comment: Several commenters stated that the emission inventory used
for the ``proxy'' 2001 base year was not sufficient for the rulemaking,
primarily because it was developed from a 1996 modeling inventory by
applying various adjustment factors. Commenters suggested that: (1)
More up-to-date inventories were now available and should be used; (2)
the most recent Continuous Emissions Monitoring (CEM) data or
throughput information should be used to derive a 2001 EGU inventory;
and (3) EPA should use the 2001 MOBILE6 and NONROAD2002 models for
estimating on-road mobile and non-road engine emissions, respectively.
Response: The EPA believes that the base year for modeling should
be as recent as possible, given the availability of nationally complete
emissions estimates and ambient monitoring data. For the analyses of
the final rule, EPA has used a base year inventory developed
specifically for 2001. The base year inventory for the electric utility
sector now uses measured CEM emissions data for 2001. The non-EGU point
source and stationary-area source sectors are based on the final 1999
NEI data submittals from State, local, and Tribal air agencies. This
inventory is the latest available quality-assured and reviewed national
emission data set for these sectors. The 1999 data for non-EGU point
and stationary-area sources were projected to represent a 2001
inventory using State/county-specific and sector-specific growth rates.
The on-road mobile inventory uses MOBILE version 6.2 and the non-road
engines inventory uses the NONROAD2004 model, both with updated input
parameters to calculate emissions for 2001. More detailed information
on the development of the emissions inventories can be found in the NFR
EITSD.
Comment: Commenters stated that EPA failed to develop an accurate
and comprehensive ammonia emission inventory from soil, fertilizer, and
animal husbandry sources.
Response: The 2001 inventory used for the analyses for the final
rule includes a new national county-level ammonia inventory developed
by EPA using the latest emission rates selected based on a
comprehensive literature review, and activity levels as provided by the
U.S. Census of Agriculture for animal husbandry. The 2001 inventory
from fertilizer application sources was compiled from State and local
submissions to EPA for 1999, augmented as necessary with EPA estimates,
and grown to 2001 using State/county-specific and category-specific
growth rates. With regard to background soil emissions of
NH₃, EPA believes that the current state of understanding of
background soil ammonia releases and sinks is insufficient to warrant
including these emission sources in modeling inventories at this time.
Comment: Two commenters indicated that EPA should revise 2010 and
2015 base case emissions by improving the methods for estimating
economic growth and not rely on the Bureau of Economic Analysis (BEA)
data used for proposal.
Response: In response to these comments, EPA has refined its
economic growth projections. In addition to updated versions of the
MOBILE6, NONROAD, and IPM models, EPA developed new economic growth
rates for stationary, area, and non-EGU point sources. For these two
sectors, the final approach uses a combination of: (1) Regional or
national fuel-use forecast data from the U.S. Department of Energy for
source types that map to fuel use sectors (e.g., commercial coal,
industrial natural gas); (2) State-specific growth rates from the
Regional Economic Model, Inc. (REMI) Policy Insight[reg]
model, version
5.5; and (3) forecasts by

[[Page 25238]]

specific industry organizations and Federal agencies. For more detail
on the growth methodologies, please refer to the NFR EITSD.
3. Meteorological Data
In order to solve for the change in pollutant concentrations over
time and space, the air quality model requires certain meteorological
inputs that, in part, govern the formation, transport, and destruction
of pollutant material. Two separate sets of meteorological inputs were
used in the air quality modeling completed as part of the NPR. The
meteorological input files for the proposal PM_2.5 modeling
were developed from a Fifth-Generation NCAR/Pennsylvania State
Mesoscale Model (MM5) model simulation for the entire year of 1996. The
gridded meteorological data for the three 1995 ozone episodes were
developed using the Regional Atmospheric Modeling System (RAMS). Both
of these models are publicly-available, widely-used, prognostic
meteorological models that solve the full set of physical and
thermodynamic equations which govern atmospheric motions. Further, each
of these specific meteorological data sets has been utilized in past
EPA rulemaking modeling analyses (e.g., the Nonroad Land-based Diesel
Engines Standards).
Comment: Several commenters claimed that the 1996 meteorological
modeling data used to support the fine particulate modeling were
outdated and non-representative. We also received recommendations from
commenters on benchmarks to be used as goals for judging the adequacy
of meteorological modeling.
Response: The EPA draft PM_2.5 modeling guidance which
provides general recommendations on meteorological periods to model for
PM_2.5 purposes lists three primary general criteria for
consideration: (a) Variety of meteorological conditions; (b) existence
of an extensive air quality/meteorological data bases; and (c)
sufficient number of days. The approach recommended in the guidance for
modeling annual PM_2.5 is to use a single, representative
year. Based on the comments received and the criteria outlined in the
guidance, EPA developed meteorological data for the entire calendar
year of 2001. This year was chosen for the PM_2.5 modeling
platform based on several factors, specifically: (a) It corresponds to
the most recent set of emissions data; (b) there are considerable
ambient PM_2.5 species data for use in model evaluation (as
described in section VI.A.1., above); and (c) Federal Reference Method
(FRM) PM_2.5 data for this year are included in the
calculation of the most recent PM_2.5 design values used for
designating PM_2.5 nonattainment areas. In view of these
factors, EPA believes that 2001 meteorology are representative for
PM_2.5 modeling for the purposes of this rule.
The new 2001 meteorological data used for PM_2.5 modeling
were derived from an updated version of the MM5 model used for the 1996
meteorology used for proposal. The version of MM5 used for the 2001
simulation contains more sophisticated physics options with respect to
features like cloud microphysics and land-surface interactions, and
more refined vertical resolution of the atmosphere compared to the
version used for modeling 1996 meteorology. While there are currently
no universally accepted criteria for judging the adequacy of
meteorological model performance, EPA compared the 2001 MM5 model
performance against the benchmark goals \99\ recommended by some
commenters. The benchmark goals suggest that temperature bias should be
within the range of approximately ± 0.5 degrees C and errors
less than or equal to 2.0 degrees C are typical.
---------------------------------------------------------------------------

\99\ Environ, Enhanced Meteorological Modeling and Performance
Evaluation for Two Texas Ozone Episodes. August 2001.
---------------------------------------------------------------------------

In general, the model performance statistics for our 2001
meteorological modeling are in line with the above benchmark goals.
Specfically, the mean temperature bias of our 2001 meteorological
modeling was approximately 0.6 degrees C and the mean error was
approximately 2.0 degrees C. The evaluation of the 2001 MM5 for
humidity (water vapor mixing ratio) shows biases of less than 0.5 g/kg
and errors of approximately 1 g/kg, which compare favorably to the
goals of ± 1 g/kg for bias and 2 g/kg or less error. Model
performance for winds in our 2001 simulation was also improved compared
to what has historically been found in MM5 modeling studies. The index
of agreement for surface winds in the 2001 case equaled 0.86, which is
far better than the benchmark goal of 0.60. The precipitation
evaluation results show that the model generally replicates the
observed data, but is overestimating precipitation in the summer
months. More information about the model performance evaluation and the
MM5 configuration is provided in the NFR AQMTSD.
Comment: Several groups criticized the lack of quantitative
meteorological model evaluation data for the 1995 RAMS meteorological
modeling used for episodic ozone modeling.
Response: A peer-reviewed, quantitative evaluation of the RAMS
model performance for this meteorological period is provided by
Hogrefe, et al.\100\ This analysis was performed using RAMS predictions
for June through August of 1995. The results show that the RAMS biases
and errors are generally in line with past meteorological model
simulations by other groups outside EPA. The EPA remains satisfied that
the 1995 RAMS meteorological inputs for the three CAM_X ozone
modeling episodes are of sufficient quality and we have continued to
use these inputs for the ozone analyses for the final rule.
---------------------------------------------------------------------------

\100\ Hogrefe, C. et al. ``Evaluating the performance of
regional-scale photochemical modeling systems: Part 1-meteorological
predictions.'' Atmospherics Environment, vol. 35 (2001), pp. 4159-4174.
---------------------------------------------------------------------------

Comment: The EPA received several comments on the episodes selected
for ozone modeling. There was general criticism that the ozone modeling
did not follow EPA's own guidance for the selection of episodes.
Additionally, there was specific criticism that the episodes did not
provide for a reasonable test of the 8-hour ozone NAAQS in some areas.
Response: The draft 8-hour ozone guidance recommends, at a minimum,
that four criteria be used to select episodes which are appropriate to
model. This guidance is generally intended for local attainment
demonstrations, as opposed to regional transport analyses, but it does
recommend that in applying a regional model one should choose episodes
meeting as many of the criteria as possible, though it acknowledges
there may be tradeoffs. Given the large number of nonattainment areas
within the ozone domain, it would be extremely difficult to assess the
criteria on a area-by-area basis. However, from a general perspective,
the 1995 episodes address all of the primary criteria, which include:
(1) A variety of meteorological conditions; (2) measured ozone values
that are close to current air quality; (3) extensive meteorological and
air quality data; and (4) a sufficient number of days. More detail is
provided in the NFR AQMTSD, but here is a brief description of how each
of the four primary criteria are met by the 1995 cases.
With regard to the criteria of meteorological variations, we have
completed inert tracer simulations for each of the three 1995 episodes
that show different transport patterns in all three cases. For example
the June case involves east-to-west transport; the July case involves
west-to-east transport; and

[[Page 25239]]

the August case involves south-to-north transport. In a separate
analysis to determine whether the 1995 modeling days correspond to
commonly occurring and ozone-conducive meteorology, EPA has applied a
multi-variate statistical approach for characterizing daily
meteorological patterns and investigating their relationship to 8-hour
ozone concentrations in the eastern U.S. Across the 16 sites for which
the analysis was completed, there were five to six distinct sets of
meteorological conditions, called regimes, that occurred during the
ozone seasons studied. An analysis of the 8-hour daily maximum ozone
concentrations for each of the meteorological regimes was undertaken to
determine the distribution of ozone concentrations and the frequency of
occurrence of each regimes. The EPA determined that between 60 and 70
percent of the episode days we modeled are associated with the most
frequently occurring, high ozone potential, meteorological regimes.
These results also provide support that the episodes being modeled are
representative of conditions present when high ozone concentrations are
measured throughout the modeling domain. For the second criteria, EPA
has completed an analysis which shows that the 1995 episodes contain
observed 8-hour daily maximum ozone values that approximate recent
ambient concentrations over the eastern U.S. Additional analyses
performed by EPA and others have concluded that each of the three
episodes involves widespread areas of elevated ozone concentrations.
The synoptic meteorological pattern of the July 1995 episode has been
identified by one of the commenters as representing a classic set of
conditions necessary for high ozone over the eastern U.S. While the
ozone was not quite as widespread in the June and August 1995 episodes,
these periods also contained exceedances of the 8-hour ozone NAAQS in
most portions of the region.
We believe that there is ample meteorological and air quality data
available to support an evaluation of the modeling for these episodes.
Specifically, there were over 700 ozone monitors reporting across the
domain for use in model evaluation. As noted above, the model
performance for these episodes compares favorably to the
recommendations in EPA's urban modeling guidance. In addition, the
modeling period is comprised of 30 days, not including model ramp-up
periods which is considerably more than is typically used in an
attainment demonstration modeling submitted to EPA by a State. Finally,
EPA's draft ozone guidance also indicates as one of four secondary
criteria that extra weight can be assigned to modeling episodes for
which there is prior experience in modeling. The 1995 CAIR ozone
episodes have been successfully used to drive the air quality modeling
completed for several recent notice-and-comment rulemakings (Tier-2,
Heavy Duty Engine, and NonRoad). Based on the analyses discussed above
and the adherence to the modeling guidance, EPA is satisfied that the
1995 CAM_X episodes are appropriate for continued use.

B. How Did EPA Project Future Nonattainment for PM_2.5 and 8-
Hour Ozone?

1. Projection of Future PM_2.5 Nonattainment
a. Methodology for Projecting Future PM_2.5 Nonattainment
In the NPR, we assessed the prospects for future attainment and
nonattainment in 2010 and 2015 of the PM_2.5 annual NAAQS.
The approach for identifying areas expected to be nonattainment for
PM_2.5 in the future involved using the model predictions in
a relative way to forecast current PM_2.5 design values to
2010 and 2015. The modeling portion of this approach included annual
simulations for 2001 proxy emissions and for 2010 and 2015 base case
emissions scenarios. As described below, the predictions from these
runs were used to calculate relative reduction factors (RRFs) which
were then applied to current PM_2.5 design values from FRM
sites in the East. This approach is consistent with the procedures in
the draft of EPA's PM_2.5 modeling guidance.
To determine the current PM_2.5 air quality for use in
projecting design values to the future, we selected the higher of the
1999-2001 or 2000-2002 design value (the most recent ambient data at
the time of the proposal) for each monitor that measured nonattainment
in 2000-2002. For those sites that were attaining the PM_2.5
standard based on their 2000-2002 design value, we used the value from
this period as the starting point for projecting 2010 and 2015 air
quality at these sites.
The procedure for calculating future year PM_2.5 design
values is called the Speciated Modeled Attainment Test (SMAT). The test
uses model predictions in a relative sense to estimate changes expected
to occur in each major PM_2.5 species. These species are
sulfate, nitrate, organic carbon, elemental carbon, crustal, and un-
attributed mass. The relative change in model-predicted species
concentrations were applied to ambient species measurements in order to
project each species for the future year scenarios. We applied a
spatial interpolation to the IMPROVE and STN speciation data as a means
for estimating species composition fractions for the FRM monitoring
sites. Future year PM_2.5 was calculated by summing the
projected concentrations of each species. The SMAT technical
procedures, as applied for the NPR, are contained in the NPR and NPR
AQMTSD.
As noted above, the procedures for determining future year
PM_2.5 concentrations were applied for each FRM site. For
counties with only one FRM site, the forecast design value for that
site was used to determine whether or not the county was predicted to
be nonattainment in the future. For counties with multiple monitoring
sites, the site with the highest future concentration was selected for
that county. Those counties with future year concentrations of 15.1
[mu]g/m3 (as rounded up from 15.05 [mu]g/m3) or
more were predicted to be nonattainment. Based on the modeling
performed for the NPR, 61 counties in the East were forecast to be
nonattainment for the 2010 base case. Of these, 41 were forecast to
remain nonattainment for the 2015 base case.
Comment: Some commenters said that EPA has not established the
credibility of using models in a relative sense to estimate future
PM_2.5 concentrations and that poor performance of REMSAD for
1996 calls into question the use of models to adequately determine the
effects of changes in emissions. One commenter said that a mechanistic
model evaluation, in which model predictions of PM_2.5
precursor photochemical oxidants are compared to corresponding
measurements, is an approach for gaining confidence in the ability of a
model to provide a credible response to emission changes.
Response: The EPA believes the future year nonattainment
projections should be based on using model predictions in a relative
sense. By applying the model in a relative way, each measured component
of PM_2.5 is adjusted upward or downward based on the percent
change in that component, as determined by the ratio of future year to
base year model predictions. The EPA feels that by using this approach,
we are able to reduce the risk that overprediction or underprediction
of PM_2.5 component species may unduly affect our projection
of future year nonattainment.
The EPA agrees with commenters that one way to establish confidence
in the credibility of this approach is to

[[Page 25240]]

determine whether model predictions of PM_2.5 precursors are
generally comparable to corresponding measured data. In this regard, we
compared the CMAQ predictions to observations for several precursor
gases for which measurements were available in 2001. These gases
include sulfur dioxide, nitric acid, and ozone.
The results for the East are summarized in Table VI-2. Additional
details on this analysis can be found in the CMAQ evaluation report.
The results indicate that for both summer and winter ozone, the
fractional bias and error is within the recommended range for urban
scale ozone modeling included in EPA's draft guidance for 8-hour ozone
modeling. For the other species examined, there are limited ambient
data and few other studies against which to compare our findings.
Still, our performance results for these species are within the range
suggested as acceptable by commenters for sulfate (i.e., ±30
percent to ±60 percent for fractional bias and 50 percent to
75 percent for fractional error). Thus, CMAQ is considered appropriate
and credible for use in projecting changes in future year
PM_2.5 concentrations and the resultant health/economic
benefits due to the emissions reductions.

Table VI-2.--CMAQ Model Performance Statistics for Ozone, Total Nitrate,
and Nitric Acid in the East
------------------------------------------------------------------------
CMAQ 2001
Eastern U.S. -------------------------
FB (%) FE (%)
------------------------------------------------------------------------
Ozone:
AIRS (Summer)............................. 13 21
AIRS (Winter)............................. -9 31
Sulfur Dioxide:
CASTNet (Summer).......................... 31 48
CASTNet (Winter).......................... 39 43
Nitric Acid:
CASTNet (Summer).......................... 29 39
CASTNet (Winter).......................... -21 55
------------------------------------------------------------------------

Comment: Several commenters said that EPA's SMAT approach is flawed
and suggested alternative methods for attributing individual species
mass to the FRM measured PM_2.5 mass. One commenter detailed
several different methods to apportion the FRM mass to individual
PM_2.5 species. They refer to two different estimation
methods as the ``FRM equivalent'' approach and the ``best estimate''
approach.
Response: The EPA agrees that alternative methodologies can be used
to apportion PM_2.5 species fractions to the FRM data. We
believe that revising SMAT to use a methodology similar to an ``FRM
equivalent'' methodology, as described in the Notice of Data
Availability (69 FR 47828; August 6, 2004), is warranted. Since
nonattainment designation determinations and future year nonattainment
projections are based on measured FRM data, we believe that the
PM_2.5 species data should be adjusted to best conform to
what is measured on the FRM filters. Based on comments, EPA has revised
our technique for projecting current PM_2.5 data to
incorporate some aspects of the commenter's ``FRM equivalent''
methodology. As described in more detail in the NFR AQMTSD, we believe
our revised methodology to be the most technically appropriate way of
estimating what is measured on the FRM filters.
Full documentation of the revised EPA SMAT methodology is contained
in the updated SMAT report \101\. In brief, we revised the SMAT
methodology to take into account several known differences between what
is measured by speciation monitors and what is measured on FRM filters.
Among the revisions were calculations to account for nitrate, ammonium,
and organic carbon volatilization, blank PM_2.5 mass,
particle bound water, the degree of neutralization of sulfate, and the
uncertainty in estimating organic carbon mass.
---------------------------------------------------------------------------

\101\ Procedures for Estimating Future PM_2.5 Values
for the CAIR Final Rule by Application of the (Revised) Speciated
Modeled Attainment Test (SMAT), docket number OAR-2003-0053-1907.
---------------------------------------------------------------------------

Comment: Several commenters noted that the future year design
values were based on projections of the 1999-2001 and/or 2000-2002 FRM
monitoring data and that there are more recent design value data
available for the 2001-2003 design value period. Commenters also noted
that the 2001-2003 data shows lower PM_2.5 concentrations at
the majority of sites and therefore, by projecting the highest design
value, we are overestimating the future year PM_2.5 values.
Response: As stated above, the PM_2.5 projection
methodology in the NPR used the higher of the 1999-2001 or 2000-2002
PM_2.5 design value data. The draft modeling guidance for
PM_2.5 specifies the use of the higher of the three design
value periods which straddle the emissions year. The emissions year is
2001 and therefore the three periods would be 1999-2001, 2000-2002, and
2001-2003. Since the 2001-2003 data is now available, we are using it
as part of the current year PM_2.5 calculations for the final
rule.
The observation by a commenter that the 2001-2003 data are
generally lower than in the previous two design value periods (i.e.,
1999-2001 and 2000-2002) leads to the issue of how to reduce the
influence of year-to-year variability in meteorology and emissions on
our estimate of current air quality. As a consequence of this year-to-
year variability in concentrations, relying on design values from any
single period, as in the approach used for proposal, may not provide a
robust representation of current air quality for use in forecasting the
future. Specifically, the lower PM_2.5 values in 2001-2003
may not be representative of the current modeling period. To address
the issue of year-to-year variability in the ambient data we have
modified our methodology to use an average of the three design value
periods that straddle the base year emissions year (i.e., 2001). In
this case it is the average of the 1999-2001, 2000-2002, and 2001-2003
design values. The average of the three design values is not a straight
5-year average. Rather, it is a weighted average of the 1999-2003
period. That is, by averaging 1999-2001, 2000-2002, and 2001-2003, the
value from 2001 is weighted three times; 2000 and 2002 are each
weighted twice and 1999 and 2003 are each weighted once. This approach
has the desired benefits of: (1) weighting the PM_2.5 values
towards the middle year of the 5-year period, which is the 2001 base
year for

[[Page 25241]]

our emissions projections; and (2) smoothing out the effects of year-
to-year variability in emissions and meteorology that occurs over the
full 5-year period. We have adopted this method for use in projecting
future PM_2.5 nonattainment for the final rule analysis. We
plan to incorporate this new methodology into the next draft version of
our PM_2.5 modeling guidance.
b. Projected 2010 and 2015 Base Case PM_2.5 Nonattainment
Counties
For the final rule, we have revised the projected PM_2.5
nonattainment counties for 2010 and 2015 by applying CMAQ for the
entire year (i.e., January through December) of 2001 using 2001 Base
Year and 2010 and 2015 future base case emissions from the new modeling
platform, as described in section VI.A.2. The 2010 and 2015 base case
PM_2.5 nonattainment counties were determined applying the
updated SMAT method using current 1999-2003 PM_2.5 air
quality coupled with the PM_2.5 species from the 2001 Base
Year and 2010 and 2015 base case CMAQ model runs. For counties with
multiple monitoring sites, the site with the highest future
concentration was selected for that county. Those counties with future
year design values of 15.05 [mu]g/m\3\ or higher were predicted to be
nonattainment. The result is that, without controls beyond those
included in the base case, 79 counties in the East are projected to be
nonattainment for the 2010 base case. For the 2015 base case, 74
counties in the East are projected to be nonattainment for
PM_2.5.
In light of the uncertainties inherent in regionwide modeling many
years into the future, of the 79 nonattainment counties projected for
the 2010 base case, we have the most confidence in our projection of
nonattainment for those counties that are not only forecast to be
nonattainment in 2010, based on the SMAT method, but that also measure
nonattainment for the most recent period of available ambient data
(i.e., 2001-2003). In our analysis for the 2010 base case, there are 62
such counties in the East that are both ``modeled'' nonattainment and
currently have ``monitored'' nonattainment. We refer to these counties
as having ``modeled plus monitored'' nonattainment. Out of an abundance
of caution, we are using only these 62 ``modeled plus monitored''
counties as the downwind receptors in determining which upwind States
make a significant contribution to PM_2.5 in downwind States.
The 79 counties in the East that we project will be nonattainment
for PM_2.5 in 2010 and the subset of 62 counties that are
also ``monitored'' nonattainment in 2001-2003, are identified in Table
VI-3. The 2015 base case PM_2.5 nonattainment counties are
provided in Table VI-4.

Table VI-3.--Projected PM2.5 Concentrations ([mu]g/m\3\) for Nonattainment Counties in the 2010 Base Case
----------------------------------------------------------------------------------------------------------------
State County 2010 Base ``Modeled + Monitored''
----------------------------------------------------------------------------------------------------------------
Alabama......................... DeKalb Co............... 15.23 No.
Alabama......................... Jefferson Co............ 18.57 Yes.
Alabama......................... Montgomery Co........... 15.12 No.
Alabama......................... Morgan Co............... 15.29 No.
Alabama......................... Russell Co.............. 16.17 Yes.
Alabama......................... Talladega Co............ 15.34 No.
Delaware........................ New Castle Co........... 16.56 Yes.
District of Columbia............ ........................ 15.84 Yes.
Georgia......................... Bibb Co................. 16.27 Yes.
Georgia......................... Clarke Co............... 16.39 Yes.
Georgia......................... Clayton Co.............. 17.39 Yes.
Georgia......................... Cobb Co................. 16.57 Yes.
Georgia......................... DeKalb Co............... 16.75 Yes.
Georgia......................... Floyd Co................ 16.87 Yes.
Georgia......................... Fulton Co............... 18.02 Yes.
Georgia......................... Hall Co................. 15.60 No.
Georgia......................... Muscogee Co............. 15.65 No.
Georgia......................... Richmond Co............. 15.68 No.
Georgia......................... Walker Co............... 15.43 Yes.
Georgia......................... Washington Co........... 15.31 No.
Georgia......................... Wilkinson Co............ 16.27 No.
Illinois........................ Cook Co................. 17.52 Yes.
Illinois........................ Madison Co.............. 16.66 Yes.
Illinois........................ St. Clair Co............ 16.24 Yes.
Indiana......................... Clark Co................ 16.51 Yes.
Indiana......................... Dubois Co............... 15.73 Yes.
Indiana......................... Lake Co................. 17.26 Yes.
Indiana......................... Marion Co............... 16.83 Yes.
Indiana......................... Vanderburgh Co.......... 15.54 Yes.
Kentucky........................ Boyd Co................. 15.23 No.
Kentucky........................ Bullitt Co.............. 15.10 No.
Kentucky........................ Fayette Co.............. 15.95 Yes.
Kentucky........................ Jefferson Co............ 16.71 Yes.
Kentucky........................ Kenton Co............... 15.30 No.
Maryland........................ Anne Arundel Co......... 15.26 Yes.
Maryland........................ Baltimore City.......... 16.96 Yes.
Michigan........................ Wayne Co................ 19.41 Yes.
Missouri........................ St. Louis City.......... 15.10 No.
New Jersey...................... Union Co................ 15.05 Yes.
New York........................ New York Co............. 16.19 Yes.
North Carolina.................. Catawba Co.............. 15.48 Yes.
North Carolina.................. Davidson Co............. 15.76 Yes.
North Carolina.................. Mecklenburg Co.......... 15.22 No.
Ohio............................ Butler Co............... 16.45 Yes.

[[Page 25242]]

Ohio............................ Cuyahoga Co............. 18.84 Yes.
Ohio............................ Franklin Co............. 16.98 Yes.
Ohio............................ Hamilton Co............. 18.23 Yes.
Ohio............................ Jefferson Co............ 17.94 Yes.
Ohio............................ Lawrence Co............. 16.10 Yes.
Ohio............................ Mahoning Co............. 15.39 Yes.
Ohio............................ Montgomery Co........... 15.41 Yes.
Ohio............................ Scioto Co............... 18.13 Yes.
Ohio............................ Stark Co................ 17.14 Yes.
Ohio............................ Summit Co............... 16.47 Yes.
Ohio............................ Trumbull Co............. 15.28 No.
Pennsylvania.................... Allegheny Co............ 20.55 Yes.
Pennsylvania.................... Beaver Co............... 15.78 Yes.
Pennsylvania.................... Berks Co................ 15.89 Yes.
Pennsylvania.................... Cambria Co.............. 15.14 Yes.
Pennsylvania.................... Dauphin Co.............. 15.17 Yes.
Pennsylvania.................... Delaware Co............. 15.61 Yes.
Pennsylvania.................... Lancaster Co............ 16.55 Yes.
Pennsylvania.................... Philadelphia Co......... 16.65 Yes.
Pennsylvania.................... Washington Co........... 15.23 Yes.
Pennsylvania.................... Westmoreland Co......... 15.16 Yes.
Pennsylvania.................... York Co................. 16.49 Yes.
Tennessee....................... Davidson Co............. 15.36 No.
Tennessee....................... Hamilton Co............. 16.89 Yes.
Tennessee....................... Knox Co................. 17.44 Yes.
Tennessee....................... Sullivan Co............. 15.32 No.
West Virginia................... Berkeley Co............. 15.69 Yes.
West Virginia................... Brooke Co............... 16.63 Yes.
West Virginia................... Cabell Co............... 17.03 Yes.
West Virginia................... Hancock Co.............. 17.06 Yes.
West Virginia................... Kanawha Co.............. 17.56 Yes.
West Virginia................... Marion Co............... 15.32 Yes.
West Virginia................... Marshall Co............. 15.81 Yes.
West Virginia................... Ohio Co................. 15.14 Yes.
West Virginia................... Wood Co................. 16.66 Yes.
----------------------------------------------------------------------------------------------------------------

Table VI-4.--Projected PM2.5 Concentrations ([mu]g/m<>\3\) for
Nonattainment Counties in the 2015 Base Case
------------------------------------------------------------------------
State County 2015 Base
------------------------------------------------------------------------
Alabama........................ DeKalb Co.............. 15.24
Alabama........................ Jefferson Co........... 18.85
Alabama........................ Montgomery Co.......... 15.24
Alabama........................ Morgan Co.............. 15.26
Alabama........................ Russell Co............. 16.10
Alabama........................ Talladega Co........... 15.22
Delaware....................... New Castle Co.......... 16.47
District of Columbia........... ....................... 15.57
Georgia........................ Bibb Co................ 16.41
Georgia........................ Chatham Co............. 15.06
Georgia........................ Clarke Co.............. 16.15
Georgia........................ Clayton Co............. 17.46
Georgia........................ Cobb Co................ 16.51
Georgia........................ DeKalb Co.............. 16.82
Georgia........................ Floyd Co............... 17.33
Georgia........................ Fulton Co.............. 18.00
Georgia........................ Hall Co................ 15.36
Georgia........................ Muscogee Co............ 15.58
Georgia........................ Richmond Co............ 15.76
Georgia........................ Walker Co.............. 15.37
Georgia........................ Washington Co.......... 15.34
Georgia........................ Wilkinson Co........... 16.54
Illinois....................... Cook Co................ 17.71
Illinois....................... Madison Co............. 16.90
Illinois....................... St. Clair Co........... 16.49
Illinois....................... Will Co................ 15.12
Indiana........................ Clark Co............... 16.37
Indiana........................ Dubois Co.............. 15.66
Indiana........................ Lake Co................ 17.27
Indiana........................ Marion Co.............. 16.77

[[Page 25243]]

Indiana........................ Vanderburgh Co......... 15.56
Kentucky....................... Boyd Co................ 15.06
Kentucky....................... Fayette Co............. 15.62
Kentucky....................... Jefferson Co........... 16.61
Kentucky....................... Kenton Co.............. 15.09
Maryland....................... Baltimore City......... 17.04
Maryland....................... Baltimore Co........... 15.08
Michigan....................... Wayne Co............... 19.28
Mississippi.................... Jones Co............... 15.18
Missouri....................... St. Louis City......... 15.34
New York....................... New York Co............ 15.76
North Carolina................. Catawba Co............. 15.19
North Carolina................. Davidson Co............ 15.34
Ohio........................... Butler Co.............. 16.32
Ohio........................... Cuyahoga Co............ 18.60
Ohio........................... Franklin Co............ 16.64
Ohio........................... Hamilton Co............ 18.03
Ohio........................... Jefferson Co........... 17.83
Ohio........................... Lawrence Co............ 15.92
Ohio........................... Mahoning Co............ 15.13
Ohio........................... Montgomery Co.......... 15.16
Ohio........................... Scioto Co.............. 17.92
Ohio........................... Stark Co............... 16.86
Ohio........................... Summit Co.............. 16.14
Ohio........................... Trumbull Co............ 15.05
Pennsylvania................... Allegheny Co........... 20.33
Pennsylvania................... Beaver Co.............. 15.54
Pennsylvania................... Berks Co............... 15.66
Pennsylvania................... Delaware Co............ 15.52
Pennsylvania................... Lancaster Co........... 16.28
Pennsylvania................... Philadelphia Co........ 16.53
Pennsylvania................... York Co................ 16.22
Tennessee...................... Davidson Co............ 15.36
Tennessee...................... Hamilton Co............ 16.82
Tennessee...................... Knox Co................ 17.34
Tennessee...................... Shelby Co.............. 15.17
Tennessee...................... Sullivan Co............ 15.37
West Virginia.................. Berkeley Co............ 15.32
West Virginia.................. Brooke Co.............. 16.51
West Virginia.................. Cabell Co.............. 16.86
West Virginia.................. Hancock Co............. 16.97
West Virginia.................. Kanawha Co............. 17.17
West Virginia.................. Marshall Co............ 15.52
West Virginia.................. Wood Co................ 16.69
------------------------------------------------------------------------

2. Projection of Future 8-Hour Ozone Nonattainment
a. Methodology for Projecting Future 8-Hour Ozone Nonattainment
The approach for projecting future 8-hour ozone concentrations used
by EPA in the NPR was based on applying the model in a relative sense
to estimate the change in ozone between the base year (2001) and each
future scenario. Projected 8-hour ozone design values in 2010 and 2015
were estimated by combining the relative change in model predicted
ozone from 2001 to the future scenario with an estimate of the base
year ambient 8-hour ozone design value. These procedures for
calculating future case ozone design values are consistent with EPA's
draft modeling guidance for 8-hour ozone attainment demonstrations. The
draft guidance specifies the use of the higher of the design values
from (a) the period that straddles the emissions inventory base year or
(b) the design value period which was used to designate the area under
the ozone NAAQS. At the time of the proposal, 2000-2002 was the design
value period which both straddled the 2001 base year inventory and was
also the latest period available.
Comment: Commenters noted that the procedures used by EPA for
projecting future 8-hour ozone concentrations differ from the
procedures used for projecting PM_2.5. These commenters said
that EPA should harmonize the two approaches.
Response: In response to comments, we have made several changes in
the approach to projecting future 8-hour ozone nonattainment in order
to follow an approach that is consistent with the manner in which
PM_2.5 projections are determined. The approach we are using
to project PM_2.5 for the final rule analysis is described in
section VI.B.1, above. In order to harmonize the ozone approach with
the approach used for PM_2.5, we are using the weighted
average of the design values for the periods that straddle the emission
base year (i.e., 2001). These periods are 1999-2001, 2000-2002, and
2001-2003. In this approach, the fourth-high ozone value from 2001 is
weighted three times, 2000 and 2002 are weighted twice, and 1999 and
2003 are weighted once. This has the desired effect of weighting the
projected ozone values towards the middle year of the 5-year period,
which is the emissions year (2001), while

[[Page 25244]]

accounting for the emissions and meteorological variability that occurs
over the full 5-year period. The average weighted concentration is
expected to be more representative as a starting point for future year
projections than choosing (a) the single design value period that
straddles the base year or (b) the design value used for designations.
We plan to incorporate this new methodology into the next draft version
of our ozone modeling guidance.
Comment: One commenter claimed that the 2010 and 2015 ozone
projections in the proposal base cases were too optimistic, that is,
that the modeling was underestimating the number of areas that may be
in nonattainment in the future. The commenter urged a more conservative
approach to assessing the future attainment status of areas.
Response: The technical basis for the comment stemmed from the
assertion that the regional ozone modeling that EPA performed for the
proposal was not of ``SIP-quality.'' The EPA response to the specific
technical issues with regard to episode selection and grid resolution
can be found in section VI.A as well as in the response to comments
document. The EPA remains confident that the CAIR 8-hour ozone modeling
platform is appropriate for assessing potential levels of future
nonattainment.
b. Projected 2010 and 2015 Base Case 8-Hour Ozone Nonattainment
Counties
For the final rule, we have revised our projections of ozone
nonattainment for the 2010 and 2015 base cases by applying CAMx for the
three 1995 ozone episodes using 2001 Base Year and 2010 and 2015 future
base case emissions from the new modeling platform, as described in
section VI.A.2. The revised 2010 and 2015 base case 8-hour ozone
nonattainment counties were determined by applying the relative change
in 8-hour ozone predicted by these CAMx model runs to the weighted
average 1999-2003 8-hour ozone concentrations as described above and,
in more detail, in the NFR AQMTSD. For counties with multiple
monitoring sites, the site with the highest future concentration was
selected for that county. Those counties with future year design values
of 85 parts per billion (ppb) or higher were predicted to be
nonattainment.
As a result of our updated modeling we project that, without
controls beyond those in the base case, there will be 40 8-hour ozone
nonattainnment counties in 2010 and 22 nonattainment counties in 2015.
All of the 40 counties that we are projecting to be nonattainment for
the 2010 base case are also measuring nonattainment based on the most
recent design value period (i.e., 2001-2003). We refer to these
counties as ``modeled plus monitored'' nonattainment, as described
above in section IV.B.1 for PM_2.5. We are using these 40
counties as the downwind receptors to determine which States make a
significant contribution to 8-hour ozone nonattainment in downwind
States.
The counties we are projecting to be nonattainment for 8-hour ozone
in the 2010 base case and 2015 base case are listed in Table VI-5 and
Table VI-6, respectively.

Table VI-5.--Projected 2010 Base Case 8-hour Ozone Nonattainment
Counties and Concentrations (ppb)
------------------------------------------------------------------------
State County 2010 Base
------------------------------------------------------------------------
Connecticut.................... Fairfield Co........... 92.6
Connecticut.................... Middlesex Co........... 90.9
Connecticut.................... New Haven Co........... 91.6
Delaware....................... New Castle Co.......... 85.0
District of Columbia........... ....................... 85.2
Georgia........................ Fulton Co.............. 86.5
Maryland....................... Anne Arundel Co........ 88.8
Maryland....................... Cecil Co............... 89.7
Maryland....................... Harford Co............. 93.0
Maryland....................... Kent Co................ 86.2
Michigan....................... Macomb Co.............. 85.5
New Jersey..................... Bergen Co.............. 86.9
New Jersey..................... Camden Co.............. 91.9
New Jersey..................... Gloucester Co.......... 91.8
New Jersey..................... Hunterdon Co........... 89.0
New Jersey..................... Mercer Co.............. 95.6
New Jersey..................... Middlesex Co........... 92.4
New Jersey..................... Monmouth Co............ 86.6
New Jersey..................... Morris Co.............. 86.5
New Jersey..................... Ocean Co............... 100.5
New York....................... Erie Co................ 87.3
New York....................... Richmond Co............ 87.3
New York....................... Suffolk Co............. 91.1
New York....................... Westchester Co......... 85.3
Ohio........................... Geauga Co.............. 87.1
Pennsylvania................... Bucks Co............... 94.7
Pennsylvania................... Chester Co............. 85.7
Pennsylvania................... Montgomery Co.......... 88.0
Pennsylvania................... Philadelphia Co........ 90.3
Rhode Island................... Kent Co................ 86.4
Texas.......................... Denton Co.............. 87.4
Texas.......................... Galveston Co........... 85.1
Texas.......................... Harris Co.............. 97.9
Texas.......................... Jefferson Co........... 85.6
Texas.......................... Tarrant Co............. 87.8
Virginia....................... Arlington Co........... 86.2
Virginia....................... Fairfax Co............. 85.7
Wisconsin...................... Kenosha Co............. 91.3
Wisconsin...................... Ozaukee Co............. 86.2

[[Page 25245]]

Wisconsin...................... Sheboygan Co........... 88.3
------------------------------------------------------------------------

Table VI-6.--Projected 2015 Base Case 8-hour Ozone Nonattainment
Counties and Concentrations (ppb)
------------------------------------------------------------------------
State County 2015 Base
------------------------------------------------------------------------
Connecticut.................... Fairfield Co........... 91.4
Connecticut.................... Middlesex Co........... 89.1
Connecticut.................... New Haven Co........... 89.8
Maryland....................... Anne Arundel Co........ 86.0
Maryland....................... Cecil Co............... 86.9
Maryland....................... Harford Co............. 90.6
Michigan....................... Macomb Co.............. 85.1
New Jersey..................... Bergen Co.............. 85.7
New Jersey..................... Camden Co.............. 89.5
New Jersey..................... Gloucester Co.......... 89.6
New Jersey..................... Hunterdon Co........... 86.5
New Jersey..................... Mercer Co.............. 93.5
New Jersey..................... Middlesex Co........... 89.8
New Jersey..................... Ocean Co............... 98.0
New York....................... Erie Co................ 85.2
New York....................... Suffolk Co............. 89.9
Pennsylvania................... Bucks Co............... 93.0
Pennsylvania................... Montgomery Co.......... 86.5
Pennsylvania................... Philadelphia Co........ 88.9
Texas.......................... Harris Co.............. 97.3
Texas.......................... Jefferson Co........... 85.0
Wisconsin...................... Kenosha Co............. 89.4
------------------------------------------------------------------------

C. How Did EPA Assess Interstate Contributions to Nonattainment?

1. PM_2.5 Contribution Modeling Approach
For the proposed rule, EPA performed State-by-State zero-out
modeling to quantify the contribution from emissions in each State to
future PM_2.5 nonattainment in other States and to determine
whether that contribution meets the air quality prong (i.e., before
considering cost) of the ``contribute significantly'' test. The zero-
out modeling technique provides an estimate of downwind impacts by
comparing the model predictions from the 2010 base case to the
predictions from a run in which all anthropogenic SO₂ and
NO_X emissions are removed from specific States. Counties
forecast to be nonattainment for PM_2.5 in the proposal 2010
base case were used as receptors for quantifying interstate
contributions of PM_2.5. For each State-by-State zero-out run
we projected the annual average PM_2.5 concentration at each
receptor using the proposed SMAT technique, as described in the NPR
AQMTSD. The contribution from an upwind State to nonattainment at a
given downwind receptor was determined by calculating the difference in
PM_2.5 concentration between the 2010 base case and the zero-
out run at that receptor. We followed this process for each State-by-
State zero-out run and each receptor. For each upwind State, we
identified the largest contribution from that State to a downwind
nonattainment receptor in order to determine the magnitude of the
maximum downwind contribution from each State. The maximum downwind
contribution was proposed as the metric for determining whether or not
the contribution was significant. As described in section III, EPA
proposed, in the alternative, a criterion of 0.10 [mu]g/m3
and 0.15 [mu]g/m3 for determining whether emissions in a
State make a significant contribution (before considering cost) to
PM_2.5 nonattainment in another State. Details on these
procedures can be found in the NPR AQMTSD.
Comments: Commenters questioned the use of zero-out modeling and
said that EPA should support the development of a source apportionment
model for PM_2.5 contributions. The commenter recommended
that EPA delay the final rule until such a technique can be used.
Another commenter provided results of a sulfate source apportionment
technique currently under development along with modeling results which
showed that the zero-out technique and source apportionment for sulfate
provide similar results in terms of the magnitude and extent of
downwind impacts. The commenter noted that the results suggest that
zero-out modeling may somewhat underestimate the transport of sulfate.
Response: The EPA continues to believe that the zero-out technique
is a credible method for quantifying interstate PM_2.5
contributions. This is supported by a commenter's results showing that
the zero-out technique and source apportionment appear to give similar
results. We accept the commenter's modeling for sulfate source
apportionment results which indicate that the zero-out technique does
not overestimate interstate transport. Moreover, EPA rejects the notion
that we should delay needed reductions while we await alternative
assessment techniques.
2. 8-Hour Ozone Contribution Modeling Approach
In the proposal, EPA quantified the impact of emissions from
specific upwind States on 8-hour ozone concentrations in projected
downwind nonattainment areas. The procedures we followed to assess
interstate ozone contribution for the proposal analysis are summarized
below. We are using these same procedures along with the updated
CAM_X modeling platform, as

[[Page 25246]]

described in section VI.A., to assess ozone contributions for today's
rule. Details on these procedures can be found in the NFR AQMTSD.
We applied two different modeling techniques, zero-out and source
apportionment, to assess the contributions of emissions in upwind
States on 8-hour ozone nonattainment in downwind States. The outputs of
the two modeling techniques were evaluated in terms of three key
contribution factors to determine which States make a significant
contribution to downwind ozone nonattainment as described in section
VI.B.2. The zero-out and source apportionment modeling techniques
provide different, but equally valid, technical approaches to
quantifying the downwind impact of emissions from upwind States. The
zero-out modeling analysis provides an estimate of downwind impacts by
comparing the model predictions from the 2010 base case and the
predictions from a model run in which all anthropogenic NO_X
and VOC emissions are removed from specific States. The source
apportionment modeling quantifies downwind impacts by tracking and
allocating the amounts of ozone formed from man-made NO_X and
VOC emissions in upwind States. Because large portions of the six
States along the western border of the modeling domain \102\ are
outside the area covered by our modeling, EPA did not analyze the
contributions to downwind ozone nonattainment for these States.
---------------------------------------------------------------------------

\102\ The six States are Kansas, Nebraska, North Dakota,
Oklahoma, South Dakota, and Texas.
---------------------------------------------------------------------------

In the analysis done at proposal, EPA considered three fundamental
factors for evaluating whether emissions in an upwind State make large
and/or frequent contributions to downwind nonattainment: (1) The
magnitude of the contribution; (2) the frequency of the contribution;
and (3) the relative amount of the contribution when compared against
contributions from other areas. The factors are the basis for several
metrics that can be used to assess a particular impact. The metrics
used in this analysis were the same as those used in the NO_X
SIP Call.
Within these three factors, eight specific metrics were calculated
to assess the contribution of each of the 31 States to the residual
nonattainment counties. For the zero-out modeling, EPA considered: (1)
The maximum contribution (magnitude); (2) the number and percentage of
exceedances with contributions in certain concentration ranges
(frequency); (3) the total contribution relative to the total
exceedance level ozone in the receptor area (relative amount); and (4)
the population-weighted total contribution relative to the total
population-weighted exceedance level ozone in the receptor area
(relative amount). For the source apportionment modeling EPA
considered: (5) The maximum contribution (magnitude); (6) the highest
daily average contribution (magnitude); (7) the number and percentages
of exceedances with contributions in certain concentration ranges
(frequency); and (8) the total average contribution to exceedance ozone
in the downwind area (relative amount). The values for these metrics
were calculated using only those periods during which the model
predicted 8-hour average ozone concentrations greater than or equal to
85 ppb in at least one of the model grid cells associated with the
receptor county in the 2010 base case. Grid cells were linked to a
specific nonattainment county if any part of the grid cell covered any
portion of the projected 2010 nonattainment county.
The first step in evaluating the contribution factors was to screen
out linkages for which the contributions were clearly small. This
initial screening was based on two criteria: (1) The maximum
contribution had to be greater than or equal to 2 ppb from either of
the two modeling techniques; and (2) the total average contribution to
exceedance of ozone in the downwind area had to be greater than 1
percent. If either screening test was not met, then the linkage was not
considered significant. Those linkages that had contributions which
exceeded the screening criteria were evaluated further in steps 2
through 4.
In step 2, we evaluated the contributions in each linkage based on
the zero-out modeling and in step 3 we evaluated the contributions in
each linkage based on the source apportionment modeling. In step 4, we
considered the results of both step 2 and step 3 to determine which of
the linkages were significant. For both techniques, EPA determined
whether the linkage is significant by evaluating the magnitude,
frequency, and relative amount of the contributions. Each upwind State
that made relatively large and/or frequent contributions to
nonattainment in the downwind area, based on these factors, was
considered to contribute significantly to nonattainment in the downwind
area.
The EPA believes that each of the factors provides an independent
measure of contribution, however, there had to be at least two
different factors that indicated large and/or frequent contributions in
order for the linkage to be found significant. In this regard, the
finding of a significant contribution for an individual linkage was not
based on any single factor. Further, each of the modeling approaches
had to show at least one indicator of a large and/or frequent
contribution in order for the linkage to be found significant. The EPA
received several general comments on the procedures for assessing
interstate contributions of ozone to projected residual nonattainment
areas, as discussed below.
Comment: A commenter opposed the use of population-weighted metrics
to determine whether an upwind State's impact on a location in another
State is significant.
Response: The commenter's concern was that transport contributions
to rural areas with low populations were not being weighted
appropriately. This is not a valid concern because the relative
contribution factor from the zero-out modeling is presumed to be met if
either of the two criteria (population-weighted, or non-population-
weighted) show large contributions.
Comment: Also, EPA received a specific comment on a certain linkage
that was deemed to be significant in the analysis done to support the
NPR. The commenter objected to the conclusion that Mississippi
significantly contributes to residual ozone exceedances near Memphis.
The objection resulted from issues with grid resolution, episode
selection, and the fact that the zero-out and source apportionment
modeling for Mississippi included some emissions from Tennessee and
Arkansas due to the irregular State boundaries.
Response: As noted in section VI.B.2, Crittenden County, AR is no
longer projected to be a nonattainment area in the 2010 base case. As a
result, the issue of Mississippi's contribution to ozone in the Memphis
area is moot.

D. What Are the Estimated Interstate Contributions to PM_2.5
and 8-Hour Ozone Nonattainment?

1. Results of PM_2.5 Contribution Modeling
In this section, we present the interstate contributions from
emissions in upwind States to PM_2.5 nonattainment in
downwind nonattainment counties. States which contribute 0.2 [mu]g/m\3\
or more to PM_2.5 nonattainment in another State are
determined to contribute significantly (before considering cost). We
calculated the interstate PM_2.5 contributions using the
State-by-State zero-out modeling technique, as indicated above in
section VI.C.1. This technique is described in

[[Page 25247]]

the NFR AQMTSD. We performed zero-out modeling using CMAQ for each of
37 States individually (i.e., Alabama, Arkansas, Connecticut, Delaware,
Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana,
Maine, Maryland combined with the District of Columbia, Massachusetts,
Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire,
New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma,
Pennsylvania, Rhode Island, South Carolina, South Dakota, Tennessee,
Texas, Vermont, Virginia, West Virginia, and Wisconsin).
We calculated each State's contribution to PM_2.5 in each
of the 62 counties that are projected to be nonattainment in the 2010
base case (i.e., ``modeled'' nonattainment) and are also ``monitored''
nonattainment in 2001-2003, as described in section VI.B.1.b. The
maximum contribution from each upwind State to downwind
PM_2.5 nonattainment is provided in Table VI-7. The
contributions from each State to nonattainment in each nonattainment
county are provided in the NFR AQMTSD. Based on the State-by-State
modeling, there are 23 States and the District of Columbia \103\ which
contribute 0.2 [mu]g/m\3\ or more to downwind PM_2.5
nonattainment (Alabama, the District of Columbia, Florida, Georgia,
Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan,
Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin). In Table VI-8, we provide a list of the
downwind nonattainment counties to which each upwind State contributes
0.2 [mu]g/m\3\ or more (i.e., the upwind State-to-downwind
nonattainment ``linkages'').
---------------------------------------------------------------------------

\103\ As noted above, we combined Maryland and the District of
Columbia as a single entity in our contribution modeling. This is a
logical approach because of the small size of the District of
Columbia and, hence, its emissions and its close proximity to
Maryland. Under our analysis, Maryland and the District of Columbia
are linked as significant contributors to the same downwind
nonattainment counties. The EPA received no adverse comment on this
approach. We also considered these entities separately, and in view
of the close proximity of these two areas we believe that Maryland
is linked as a significant contributor to nonattainment in the
District of Columbia and that the District of Columbia is linked as
a significant contributor to nonattainment in Maryland.

Table VI-7.--Maximum Downwind PM2.5 Contribution ([mu]g/m\3\) for each
of 37 States
------------------------------------------------------------------------
Maximum
Upwind State downwind
contribution
------------------------------------------------------------------------
Alabama................................................... 0.98
Arkansas.................................................. 0.19
Connecticut............................................... <0.05
Delaware.................................................. 0.14
Florida................................................... 0.45
Georgia................................................... 1.27
Illinois.................................................. 1.02
Indiana................................................... 0.91
Iowa...................................................... 0.28
Kansas.................................................... 0.11
Kentucky.................................................. 0.90
Louisiana................................................. 0.25
Maine..................................................... <0.05
Maryland/DC............................................... 0.69
Massachusetts............................................. 0.07
Michigan.................................................. 0.62
Minnesota................................................. 0.21
Mississippi............................................... 0.23
Missouri.................................................. 1.07
Nebraska.................................................. 0.07
New Hampshire............................................. <0.05
New Jersey................................................ 0.13
New York.................................................. 0.34
North Carolina........................................... 0.31
North Dakota............................................. 0.11
Ohio..................................................... 1.67
Oklahoma................................................. 0.12
Pennsylvania............................................. 0.89
Rhode Island............................................. <0.05
South Carolina........................................... 0.40
South Dakota............................................. <0.05
Tennessee................................................. 0.65
Texas..................................................... 0.29
Vermont.................................................. <0.05
Virginia................................................. 0.44
West Virginia............................................ 0.84
Wisconsin................................................ 0.56
------------------------------------------------------------------------

Table VI-8.--Upwind State-to-Downwind Nonattainment County Significant ``Linkages'' for PM2.5.
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Upwind Total Downwind counties
states......... linkages
----------------
AL............. 21 Bibb GA............. Cabell WV........... Catawba NC......... Clark IN.
Clarke GA........... Clayton GA.......... Cobb GA............ Davidson NC.
DeKalb GA........... Dubois IN........... Fayette KY......... Floyd GA.
Fulton GA........... Hamilton OH......... Hamilton TN........ Jefferson KY.
Knox TN............. Lawrence OH......... Scioto OH.......... Vanderburgh IN.
Walker GA...........
FL............. 7 Bibb GA............. Clarke GA........... Clayton GA......... Cobb GA.
DeKalb GA........... Jefferson AL........ Russell AL.........
GA............. 17 Butler OH........... Cabell WV........... Catawba NC......... Clark IN.
Davidson NC......... Fayette KY.......... Hamilton OH........ Hamilton TN.
Jefferson AL........ Jefferson KY........ Kanawha WV......... Knox TN.
Lawrence OH......... Montgomery OH....... Russell AL......... Scioto OH.
Vanderburgh IN......
IL............. 23 Allegheny PA........ Butler OH........... Cabell WV.......... Clark IN.
Cuyahoga OH......... Dubois IN........... Fayette KY......... Franklin OH.
Hamilton OH......... Hamilton TN......... Jefferson AL....... Jefferson KY.
Kanawha WV.......... Lake IN............. Lawrence OH........ Mahoning OH.
Marion IN........... Montgomery OH....... Scioto OH.......... Stark OH.
Summit OH........... Vanderburgh IN...... Wayne MI........... ...................
IN............. 46 Allegheny PA........ Beaver PA........... Berkeley WV........ Bibb GA.
Brooke WV........... Butler OH........... Cabell WV.......... Cambria PA.
Catawba NC.......... Clarke GA........... Clayton GA......... Cobb GA.
Cook IL............. Cuyahoga OH......... Davidson NC........ DeKalb GA.
Fayette KY.......... Floyd GA............ Franklin OH........ Fulton GA.
Hamilton OH......... Hamilton TN......... Hancock WV......... Jefferson AL.
Jefferson KY........ Jefferson OH........ Kanawha WV......... Knox TN.

[[Page 25248]]

Lancaster PA........ Lawrence OH......... Madison IL......... Mahoning OH.
Marion WV........... Marshall WV......... Montgomery OH...... Ohio WV.
Russell AL.......... St. Clair IL........ Scioto OH.......... Stark OH.
Summit OH........... Walker GA........... Wayne MI........... Washington PA.
Westmoreland PA..... Wood WV.............
IA............. 5 Cook IL............. Lake IN............. Madison IL......... Marion IN.
St. Clair IL........
KY............. 35 Allegheny PA........ Butler OH........... Cabell WV.......... Catawba NC.
Clark IN............ Clarke GA........... Cobb GA............ Cuyahoga OH.
Davidson NC......... Dubois IN........... Floyd GA........... Franklin OH.
Hamilton OH......... Hamilton TN......... Jefferson AL....... Jefferson OH.
Kanawha WV.......... Knox TN............. Lawrence OH........ Madison IL.
Mahoning OH......... Marion IN........... Marion WV.......... Marshall WV.
Montgomery OH....... Ohio WV............. St. Clair IL....... Scioto OH.
Stark OH............ Summit OH........... Vanderburgh IN..... Walker GA.
Washington PA....... Westmoreland PA..... Wood WV............
LA............. 2 Jefferson AL........ Russell AL..........
MD/DC.......... 13 Berkeley WV......... Berks PA............ Cambria PA......... Dauphin PA.
Delaware PA......... District of Columbia Lancaster PA....... New Castle DE.
New York NY......... Philadelphia PA..... Union NJ........... Westmoreland PA.
York PA.............
MI............. 36 Allegheny PA........ Beaver PA........... Berks PA........... Brooke WV.
Butler OH........... Cabell WV........... Cambria PA......... Clark IN.
Cook IL............. Cuyahoga OH......... Dauphin PA......... Delaware PA.
Fayette KY.......... Franklin OH......... Hamilton OH........ Hancock WV.
Jefferson OH........ Lake IN............. Lancaster PA....... Lawrence OH.
Mahoning OH......... Marion IN........... Marion WV.......... Marshall WV.
Montgomery OH....... New Castle DE....... Ohio WV............ Philadelphia PA.
Scioto OH........... Stark OH............ Summit OH.......... Union NJ.
Washington PA....... Westmoreland PA..... Wood WV............ York PA.
MN............. 2 Cook IL............. Lake IN.............
MO............. 9 Clark IN............ Cook IL............. Dubois IN.......... Jefferson KY.
Lake IN............. Madison IL.......... Marion IN.......... St. Clair IL.
Vanderburgh IN......
MS............. 1 Jefferson AL........
NY............. 5 Berks PA............ Lancaster PA........ New Castle DE...... New Haven CT.
Union NJ............
NC............. 7 Anne Arundel MD..... Baltimore City...... Bibb GA............ Clarke GA.
District of Columbia Kanawha WV.......... Knox TN............
OH............. 51 Anne Arundel MD..... Allegheny PA........ Baltimore City MD.. Beaver PA.
Berkeley WV......... Berks PA............ Bibb GA............ Brooke WV.
Cabell WV........... Cambria PA.......... Catawba NC......... Clark IN.
Clarke GA........... Clayton GA.......... Cobb GA............ Cook IL.
Dauphin PA.......... Davidson NC......... DeKalb GA.......... Delaware PA.
District of Columbia Dubois IN........... Fayette KY......... Floyd GA.
Fulton GA........... Hamilton TN......... Hancock WV......... Jefferson AL.
Jefferson KY........ Kanawha WV.......... Knox TN............ Lake IN.
Lancaster PA........ Madison IL.......... Marion IN.......... Marion WV.
Marshall WV......... New Castle DE....... New York NY........ Ohio WV.
Philadelphia PA..... Russell AL.......... St. Clair IL....... Union NJ.
Vanderburgh IN...... Walker GA........... Washington PA...... Wayne MI.
Westmoreland PA..... Wood WV............. York PA............
PA............. 25 Anne Arundel MD..... Baltimore City...... Berkeley WV........ Brooke WV.
Cabell WV........... Catawba NC.......... Clarke GA.......... Cuyahoga OH.
Davidson NC......... District of Columbia Hancock WV......... Jefferson OH.
Kanawha WV.......... Lawrence OH......... Mahoning OH........ Marion WV.
Marshall WV......... New Castle DE....... New York NY........ Ohio WV.
Stark OH............ Summit OH........... Union NJ........... Wayne MI.
Wood WV.............
SC............. 9 Bibb GA............. Catawba NC.......... Clarke GA.......... Clayton GA.
Cobb GA............. Davidson NC......... DeKalb GA.......... Fulton GA.
Russell AL..........
TN............. 23 Bibb GA............. Butler OH........... Cabell WV.......... Catawba NC.
Clark IN............ Clarke GA........... Clayton GA......... Cobb GA.
Davidson NC......... DeKalb GA........... Dubois IN.......... Fayette KY.
Floyd GA............ Fulton GA........... Hamilton OH........ Jefferson AL.
Jefferson KY........ Kanawha WV.......... Lawrence OH........ Russell AL.
Scioto OH........... Vanderburgh TN...... Walker GA. ...................
TX............. 2 Madison IL.......... St Clair IL.........
VA............. 13 Anne Arundel MD..... Baltimore City MD... Berkeley WV........ Berks PA.
Catawba NC.......... Dauphin PA.......... Davidson NC........ Delaware PA.
District of Columbia Lancaster PA........ New Castle DE...... Philadelphia PA.

[[Page 25249]]

York PA.............
WV............. 33 Anne Arundel MD..... Allegheny PA........ Baltimore City MD.. Beaver PA.
Berks PA............ Butler OH........... Cambria PA......... Catawba NC.
Clarke GA........... Cuyahoga OH......... Dauphin PA......... Davidson NC.
Delaware PA......... District of Columbia Fayette KY......... Franklin OH.
Hamilton OH......... Jefferson OH........ Knox TN............ Lancaster PA.
Lawrence OH......... Mahoning OH......... Montgomery OH...... New Castle DE.
New York NY......... Philadelphia PA..... Scioto OH.......... Stark OH.
Summit OH........... Union NJ............ Washington PA...... Westmoreland PA.
York PA.............
WI............. 4 Cook IL............. Lake IN............. Marion IN.......... Wayne MI.
----------------------------------------------------------------------------------------------------------------

2. Results of 8-Hour Ozone Contribution Modeling
In this section, we present the results of air quality modeling to
determine which upwind States contribute significantly (before
considering cost) to 8-hour ozone nonattainment in downwind States. The
analytical procedures to determine which States make a significant
contribution are based on the zero-out and source apportionment
modeling techniques using CAM_X, as described in section
VI.C.2 and in the NFR AQMTSD. We performed ozone contribution modeling
using both of these techniques for 31 States in the East and the
District of Columbia (i.e., Alabama, Arkansas, Connecticut, Delaware,
Georgia, Florida, Iowa, Illinois, Indiana, Kentucky, Louisiana,
Massachusetts, Maine, Maryland combined with the District of Columbia,
Michigan, Minnesota, Mississippi, Missouri, New Hampshire, New Jersey,
New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South
Carolina, Tennessee, Vermont, Virginia, West Virginia, and Wisconsin).
We evaluated the interstate ozone contributions from each of the 31
upwind States and the District of Columbia to each of the 40 counties
that are projected to be nonattainment in the 2010 base case (i.e.,
``modeled'' nonattainment) and are also ``monitored'' nonattainment in
2001-2003, as described in section VI.B.2.b. We analyzed the
contributions from upwind States to these counties in terms of various
metrics, described above and in more detail in the NFR AQMTSD.
Based on the State-by-State modeling, there are 25 States and the
District of Columbia \104\ which make a significant contribution
(before considering cost) to 8-hour ozone nonattainment in downwind
States (i.e., Alabama, Arkansas, Connecticut, Delaware, the District of
Columbia, Florida, Iowa, Illinois, Indiana, Kentucky, Louisiana,
Massachusetts, Maryland, Michigan, Mississippi, Missouri, New Jersey,
New York, North Carolina, Ohio, Pennsylvania, South Carolina,
Tennessee, Virginia, West Virginia, and Wisconsin). In Table VI-9, we
provide a list of the downwind nonattainment counties to which each
upwind State makes a significant contribution (i.e., the upwind State-
to-downwind nonattainment ``linkages'').
---------------------------------------------------------------------------

\104\ As noted above, we combined Maryland and the District of
Columbia as a single entity in our contribution modeling. This is a
logical approach because of the small size of the District of
Columbia and, hence, its emissions and its close proximity to
Maryland. Under our analysis, Maryland and the District of Columbia
are linked as significant contributors to the same downwind
nonattainment counties. The EPA received no adverse comment on this
approach. We also considered these entities separately, and in view
of the close proximity of these two areas we believe that Maryland
is linked as a significant contributor to nonattainment in the
District of Columbia and that the District of Columbia is linked as
a significant contributor to nonattainment in Maryland.

Table VI-9.--Upwind State-to-Downwind Nonattainment County Significant ``Linkages'' for 8-hour Ozone.
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Upwind Total Downwind counties
states......... linkages
----------------
AL............. 3 Fulton GA........... Harris TX........... Jefferson TX. ...................
AR............. 3 Galveston TX........ Harris TX........... Jefferson TX. ...................
CT............. 2 Kent RI............. Suffolk NY.
DE............. 13 Bucks PA............ Camden NJ........... Chester PA......... Gloucester NJ.
Hunterdon NJ........ Mercer NJ........... Middlesex NJ....... Monmouth NJ.
Montgomery PA....... Morris NJ........... Ocean NJ........... Philadelphia PA.
Suffolk NY..........
FL............. 1 Fulton GA
IA............. 3 Kenosha WI.......... Macomb MI........... Sheboygan WI. ...................
IL............. 5 Geauga OH........... Kenosha WI.......... Macomb MI.......... Ozaukee WI.
Sheboygan WI.
IN............. 5 Geauga OH........... Kenosha WI.......... Macomb MI.......... Ozaukee WI.
Sheboygan WI........
KY............. 3 Fulton GA........... Geauga OH........... Macomb MI.......... ...................
LA............. 3 Galveston TX........ Harris TX........... Jefferson TX. ...................
MA............. 2 Kent RI............. Middlesex NJ.
MD/DC.......... 23 Arlington VA........ Bergen NJ........... Bucks PA........... Camden NJ.
Chester PA.......... District of Columbia Erie NY............ Fairfax VA.
Fairfield CT........ Gloucester NJ....... Hunterton NJ....... Mercer NJ.
Middlesex NJ........ Monmouth NJ......... Montgomery PA...... Morris NJ.

[[Page 25250]]

New Castle DE....... New Haven CT........ Ocean NJ........... Philadelphia PA.
Richmond NY......... Suffolk NY.......... Westchester NY..... ...................
MI............. 19 Anne Arundel MD..... Bergen NJ........... Bucks PA........... Camden NJ.
Cecil MD............ Chester PA.......... Erie NY............ Geauga OH.
Gloucester NJ....... Kent MD............. Mercer NJ.......... Middlesex NJ.
Monmouth NJ......... Morris NJ........... New Castle DE...... Ocean NJ.
Philadelphia PA..... Richmond NY......... Suffolk NY......... ...................
MO............. 4 Geauga OH........... Kenosha WI.......... Ozaukee WI......... Sheboygan WI.
MS............. 2 Harris TX........... Jefferson TX.
NC............. 8 Anne Arundel MD..... Fulton GA........... Harford MD......... Kent MD.
Newcastle DE........ Suffolk NY.......... Bucks PA........... Chester PA.
NJ............. 10 Erie NY............. Fairfield CT........ Kent RI............ Middlesex CT.
Montgomery PA....... New Haven CT........ Philadelphia PA.... Richmond NY.
Suffolk NY.......... Westchester NY.
NY............. 9 Fairfield CT........ Kent RI............. Mercer NJ.......... Middlesex CT.
Middlesex NJ........ Monmouth NJ......... Morris NJ.......... New Haven CT.
Ocean NJ.
Anne Arundel MD..... Arlington VA........ Bergen NJ.......... Bucks PA.
OH............. 28 Camden NJ........... Cecil MD............ Chester PA......... District of
Columbia.
Fairfax VA.......... Fairfield CT........ Gloucester NJ...... Harford MD.
Hunterton NJ........ Kent MD............. Kent RI............ Macomb MI.
Mercer NJ........... Middlesex CT........ Middlesex NJ....... Monmouth NJ.
Montgomery PA....... Morris NJ........... New Castle DE...... New Haven CT.
Ocean NJ............ Philadelphia PA..... Suffolk NY......... Westchester NY.
PA............. 25 Anne Arundel MD..... Arlington VA........ Bergen NJ.......... Camden NJ.
Cecil MD............ District of Columbia Erie NY............ Fairfax VA.
Fairfield CT........ Gloucester NJ....... Harford MD......... Hunterton NJ.
Kent MD............. Kent RI............. Mercer NJ.......... Middlesex CT.
Middlesex NJ........ Monmouth NJ......... Morris NJ.......... New Castle DE.
New Haven CT........ Ocean NJ............ Richmond NY........ Suffolk NY.
Westchester NY.
SC............. 1 Fulton GA.
TN............. 1 Fulton GA.
VA............. 26 Anne Arundel MD..... Bergen NJ........... Bucks PA........... Camden NJ.
Cecil MD............ Chester PA.......... District of Erie NY.
Columbia.
Fairfield CT........ Gloucester NJ....... Harford MD......... Hunterton NJ.
Kent MD............. Kent RI............. Mercer NJ.......... Middlesex CT.
Middlesex NJ........ Monmouth NJ......... Morris NJ.......... New Castle DE.
New Haven CT........ Ocean NJ............ Philadelphia PA.... Richmond NY.
Suffolk NY.......... Westchester NY.
WI............. 2 Erie NY............. Macomb MI.
WV............. 25 Anne Arundel MD..... Bergen NJ........... Bucks PA........... Camden NJ.
Cecil MD............ Chester PA.......... Fairfax VA......... Fairfield CT.
Fulton GA........... Gloucester NJ....... Harford MD......... Hunterton NJ.
Kent MD............. Mercer NJ........... Middlesex NJ....... Monmouth NJ.
Montgomery PA....... Morris NJ........... New Castle DE...... New Haven CT.
Ocean NJ............ Philadelphia PA..... Richmond NY........ Suffolk NY.
Westchester NY......
----------------------------------------------------------------------------------------------------------------

E. What are the Estimated Air Quality Impacts of the Final Rule?

In this section, we describe the air quality modeling performed to
determine the projected impacts on PM_2.5 and 8-hour ozone of
the SO₂ and NO_X emissions reductions in the
control region modeled. The modeling used to estimate the air quality
impact of these reductions assumes annual SO₂ and
NO_X controls for Arkansas, Delaware, and New Jersey in
addition to the 23-States plus the District of Columbia. Since
Arkansas, Delaware, and New Jersey are not included in the final CAIR
region for PM_2.5, the modeled estimated impacts on
PM_2.5 are overstated for today's final rule. However, EPA
plans to include Delaware and New Jersey in the CAIR region for
PM_2.5 through a separate regulatory process. Thus, the
estimates are reflective of the total impacts expected for CAIR
assuming Delaware and New Jersey will become part of the annual
SO₂ and NO_X trading programs.
As discussed in section IV, EPA analyzed the impacts of the
regional emissions reductions in both 2010 and 2015. These impacts are
quantified by comparing air quality modeling results for the regional
control scenario to the modeling results for the corresponding 2010 and
2015 base case scenarios. The 2010 and 2015 emissions reductions from
the power generation sector include a two-phase cap and trade program
covering the control region modeled (i.e., the 23 States plus the
District of Columbia included in today's rule and Arkansas, Delaware,
and New Jersey).\105\ Phase 1 of the regional strategy (the 2010
reductions) is forecast to reduce total EGU SO₂ emissions
\106\ in

[[Page 25251]]

the control region modeled by 40 percent in 2010. Phase 2 (the 2015
reductions) is forecast to provide a 48 percent reduction in EGU
SO₂ emissions compared to the base case in 2015. When fully
implemented post-2015, we expect this rule to result in more than a 70
percent reduction in EGU SO₂ emissions compared to current
emissions levels. The reductions at full implementation occur post-2015
due to the existing title IV bank of SO₂ allowances, which
can be used under the CAIR program. The net effect of the strategy on
total SO₂ emissions in the control region modeled
considering all sources of emissions, is a 28 percent reduction in 2010
and a 32 percent reduction in 2015.
---------------------------------------------------------------------------

\105\ In addition to the SO₂ and NO_X
reductions in these States, we also modeled summer-season only EGU
NO_X controls for Connecticut and Massachusetts, which
significantly contribute to ozone, but not to PM_2.5
nonattainment in downwind areas.
\106\ For the purposes of this discussion, we have calculated
the percent reduction in total EGU emissions which includes units
greater than and less than 25 MW.
---------------------------------------------------------------------------

For NO_X, Phase 1 of the strategy is forecast to reduce
total EGU emissions by 44 percent in 2009. Total NO_X
emissions across the control region (i.e., includes all sources) are 11
percent lower in the 2010 CAIR scenario compared to the emissions in
the 2010 base case. In Phase 2, EGU NO_X emissions are
projected to decline by 54 percent in 2015 in this region. Total
NO_X emissions from all anthropogenic sources are projected
to be reduced by 14 percent in 2015. The percent change in emissions by
State for SO₂ and NO_X in 2010 and 2015 for the
regional control strategy modeled are provided in the NFR EITSD.
1. Estimated Impacts on PM_2.5 Concentrations and Attainment
We determined the impacts on PM_2.5 of the CAIR regional
strategy by running the CMAQ model for this strategy and comparing the
results to the PM_2.5 concentrations predicted for the 2010
and 2015 base cases. In brief, we ran the CMAQ model for the regional
strategy in both 2010 and 2015. The model predictions were used to
project future PM_2.5 concentrations for CAIR in 2010 and
2015 using the SMAT technique, as described in section VI.B.1. We
compared the results of the 2010 and 2015 regional strategy modeling to
the corresponding results from the 2010 and 2015 base cases to quantify
the expected impacts of CAIR.
The impacts of the SO₂ and NO_X emissions
reductions expected from CAIR on PM_2.5 in 2010 and 2015 are
provided in Table VI-10 and Table VI-11, respectively. In these tables,
counties shown in bold/italics are projected to come into attainment
with CAIR.

Table VI-10.--Projected PM2.5 Concentrations ([mu]g/m\3\) for the 2010 Base Case and CAIR and the Impact of CAIR
Regional Controls in 2010
----------------------------------------------------------------------------------------------------------------
2010 Base Impact of
State County case 2010 CAIR CAIR
----------------------------------------------------------------------------------------------------------------
Alabama................................... DeKalb Co.................... 15.23 13.97 -1.26
Alabama................................... Jefferson Co................. 18.57 17.46 -1.11
Alabama................................... Montgomery Co................ 15.12 14.10 -1.02
Alabama................................... Morgan Co.................... 15.29 14.11 -1.18
Alabama................................... Russell Co................... 16.17 15.15 -1.02
Alabama................................... Talladega Co................. 15.34 14.00 -1.34
Delaware.................................. New Castle Co................ 16.56 14.84 -1.72
District of Columbia...................... ............................. 15.84 13.68 -2.16
Georgia................................... Bibb Co...................... 16.27 15.17 -1.10
Georgia................................... Clarke Co.................... 16.39 14.96 -1.43
Georgia................................... Clayton Co................... 17.39 16.29 -1.10
Georgia................................... Cobb Co...................... 16.57 15.35 -1.22
Georgia................................... DeKalb Co.................... 16.75 15.70 -1.05
Georgia................................... Floyd Co..................... 16.87 15.87 -1.00
Georgia................................... Fulton Co.................... 18.02 16.98 -1.04
Georgia................................... Hall Co...................... 15.60 14.28 -1.32
Georgia................................... Muscogee Co.................. 15.65 14.57 -1.08
Georgia................................... Richmond Co.................. 15.68 14.64 -1.04
Georgia................................... Walker Co.................... 15.43 14.22 -1.21
Georgia................................... Washington Co................ 15.31 14.22 -1.09
Georgia................................... Wilkinson Co................. 16.27 15.22 -1.05
Illinois.................................. Cook Co...................... 17.52 16.88 -0.64
Illinois.................................. Madison Co................... 16.66 15.96 -0.70
Illinois.................................. St. Clair Co................. 16.24 15.54 -0.70
Indiana................................... Clark Co..................... 16.51 15.15 -1.36
Indiana................................... Dubois Co.................... 15.73 14.37 -1.36
Indiana................................... Lake Co...................... 17.26 16.48 -0.78
Indiana................................... Marion Co.................... 16.83 15.54 -1.29
Indiana................................... Vanderburgh Co............... 15.54 14.26 -1.28
Kentucky.................................. Boyd Co...................... 15.23 13.38 -1.85
Kentucky.................................. Bullitt Co................... 15.10 13.67 -1.43
Kentucky.................................. Fayette Co................... 15.95 14.17 -1.78
Kentucky.................................. Jefferson Co................. 16.71 15.44 -1.27
Kentucky.................................. Kenton Co.................... 15.30 13.72 -1.58
Maryland.................................. Anne Arundel Co.............. 15.26 12.98 -2.28
Maryland.................................. Baltimore city............... 16.96 14.88 -2.08
Michigan.................................. Wayne Co..................... 19.41 18.23 -1.18
Missouri.................................. St. Louis City............... 15.10 14.40 -0.70
New Jersey................................ Union Co..................... 15.05 13.60 -1.45
New York.................................. New York Co.................. 16.19 14.95 -1.24
North Carolina............................ Catawba Co................... 15.48 14.07 -1.41
North Carolina............................ Davidson Co.................. 15.76 14.36 -1.40

[[Page 25252]]

North Carolina............................ Mecklenburg Co............... 15.22 13.92 -1.30
Ohio...................................... Butler Co.................... 16.45 15.03 -1.42
Ohio...................................... Cuyahoga Co.................. 18.84 17.11 -1.73
Ohio...................................... Franklin Co.................. 16.98 15.13 -1.85
Ohio...................................... Hamilton Co.................. 18.23 16.61 -1.62
Ohio...................................... Jefferson Co................. 17.94 15.64 -2.30
Ohio...................................... Lawrence Co.................. 16.10 14.11 -1.99
Ohio...................................... Mahoning Co.................. 15.39 13.40 -1.99
Ohio...................................... Montgomery Co................ 15.41 13.83 -1.58
Ohio...................................... Scioto Co.................... 18.13 15.98 -2.15
Ohio...................................... Stark Co..................... 17.14 15.08 -2.06
Ohio...................................... Summit Co.................... 16.47 14.69 -1.78
Ohio...................................... Trumbull Co.................. 15.28 13.50 -1.78
Pennsylvania.............................. Allegheny Co................. 20.55 18.01 -2.54
Pennsylvania.............................. Beaver Co.................... 15.78 13.61 -2.17
Pennsylvania.............................. Berks Co..................... 15.89 13.56 -2.33
Pennsylvania.............................. Cambria Co................... 15.14 12.72 -2.42
Pennsylvania.............................. Dauphin Co................... 15.17 12.88 -2.29
Pennsylvania.............................. Delaware Co.................. 15.61 13.94 -1.67
Pennsylvania.............................. Lancaster Co................. 16.55 14.09 -2.46
Pennsylvania.............................. Philadelphia Co.............. 16.65 14.98 -1.67
Pennsylvania.............................. Washington Co................ 15.23 12.99 -2.24
Pennsylvania.............................. Westmoreland Co.............. 15.16 12.60 -2.56
Pennsylvania.............................. York Co...................... 16.49 14.20 -2.29
Tennessee................................. Davidson Co.................. 15.36 14.26 -1.10
Tennessee................................. Hamilton Co.................. 16.89 15.57 -1.32
Tennessee................................. Knox Co...................... 17.44 16.16 -1.28
Tennessee................................. Sullivan Co.................. 15.32 14.01 -1.31
West Virginia............................. Berkeley Co.................. 15.69 13.43 -2.26
West Virginia............................. Brooke Co.................... 16.63 14.42 -2.21
West Virginia............................. Cabell Co.................... 17.03 15.08 -1.95
West Virginia............................. Hancock Co................... 17.06 14.89 -2.17
West Virginia............................. Kanawha Co................... 17.56 15.27 -2.29
West Virginia............................. Marion Co.................... 15.32 12.90 -2.42
West Virginia............................. Marshall Co.................. 15.81 13.46 -2.35
West Virginia............................. Ohio Co...................... 15.14 12.81 -2.33
West Virginia............................. Wood Co...................... 16.66 14.14 -2.52
----------------------------------------------------------------------------------------------------------------

Table VI-11.--Projected PM2.5 Concentrations ([mu]g/m3) for the 2015 Base Case and CAIR and the Impact of CAIR
Regional Controls in 2015
----------------------------------------------------------------------------------------------------------------
2015 Base Impact of
State County case 2015 CAIR CAIR
----------------------------------------------------------------------------------------------------------------
Alabama................................... DeKalb Co.................... 15.24 13.46 -1.78
Alabama................................... Jefferson Co................. 18.85 17.36 -1.49
Alabama................................... Montgomery Co................ 15.24 13.87 -1.37
Alabama................................... Morgan Co.................... 15.26 13.85 -1.41
Alabama................................... Russell Co................... 16.10 14.66 -1.44
Alabama................................... Talladega Co................. 15.22 13.35 -1.87
Delaware.................................. New Castle Co................ 16.47 14.41 -2.06
District of Columbia...................... ............................. 15.57 13.11 -2.46
Georgia................................... Bibb Co...................... 16.41 14.83 -1.58
Georgia................................... Chatham Co................... 15.06 13.86 -1.20
Georgia................................... Clarke Co.................... 16.15 14.10 -2.05
Georgia................................... Clayton Co................... 17.46 15.85 -1.61
Georgia................................... Cobb Co...................... 16.51 14.67 -1.84
Georgia................................... DeKalb Co.................... 16.82 15.29 -1.53
Georgia................................... Floyd Co..................... 17.33 15.79 -1.54
Georgia................................... Fulton Co.................... 18.00 16.47 -1.53
Georgia................................... Hall Co...................... 15.36 13.48 -1.88
Georgia................................... Muscogee Co.................. 15.58 14.06 -1.52
Georgia................................... Richmond Co.................. 15.76 14.23 -1.53
Georgia................................... Walker Co.................... 15.37 13.65 -1.72
Georgia................................... Washington Co................ 15.34 13.67 -1.67
Georgia................................... Wilkinson Co................. 16.54 15.01 -1.53
Illinois.................................. Cook Co...................... 17.71 16.95 -0.76
Illinois.................................. Madison Co................... 16.90 16.07 -0.83
Illinois.................................. St. Clair Co................. 16.49 15.64 -0.85

[[Page 25253]]

Illinois.................................. Will Co...................... 15.12 14.27 -0.85
Indiana................................... Clark Co..................... 16.37 14.79 -1.58
Indiana................................... Dubois Co.................... 15.66 14.16 -1.50
Indiana................................... Lake Co...................... 17.27 16.36 -0.91
Indiana................................... Marion Co.................... 16.77 15.38 -1.39
Indiana................................... Vanderburgh Co............... 15.56 14.17 -1.39
Kentucky.................................. Boyd Co...................... 15.06 12.95 -2.11
Kentucky.................................. Fayette Co................... 15.62 13.54 -2.08
Kentucky.................................. Jefferson Co................. 16.61 15.13 -1.48
Kentucky.................................. Kenton Co.................... 15.09 13.26 -1.83
Maryland.................................. Baltimore city............... 17.04 14.50 -2.54
Maryland.................................. Baltimore Co................. 15.08 12.75 -2.33
Michigan.................................. Wayne Co..................... 19.28 17.95 -1.33
Mississippi............................... Jones Co..................... 15.18 14.06 -1.12
Missouri.................................. St. Louis city............... 15.34 14.50 -0.84
New York.................................. New York Co.................. 15.76 14.33 -1.43
North Carolina............................ Catawba Co................... 15.19 13.45 -1.74
North Carolina............................ Davidson Co.................. 15.34 13.61 -1.73
Ohio...................................... Butler Co.................... 16.32 14.67 -1.65
Ohio...................................... Cuyahoga Co.................. 18.60 16.67 -1.93
Ohio...................................... Franklin Co.................. 16.64 14.57 -2.07
Ohio...................................... Hamilton Co.................. 18.03 16.10 -1.93
Ohio...................................... Jefferson Co................. 17.83 15.26 -2.57
Ohio...................................... Lawrence Co.................. 15.92 13.71 -2.21
Ohio...................................... Mahoning Co.................. 15.13 12.94 -2.19
Ohio...................................... Montgomery Co................ 15.16 13.33 -1.83
Ohio...................................... Scioto Co.................... 17.92 15.55 -2.37
Ohio...................................... Stark Co..................... 16.86 14.58 -2.28
Ohio...................................... Summit Co.................... 16.14 14.18 -1.96
Ohio...................................... Trumbull Co.................. 15.05 13.08 -1.97
Pennsylvania.............................. Allegheny Co................. 20.33 17.47 -2.86
Pennsylvania.............................. Beaver Co.................... 15.54 13.09 -2.45
Pennsylvania.............................. Berks Co..................... 15.66 12.99 -2.67
Pennsylvania.............................. Delaware Co.................. 15.52 13.52 -2.00
Pennsylvania.............................. Lancaster Co................. 16.28 13.33 -2.95
Pennsylvania.............................. Philadelphia Co.............. 16.53 14.53 -2.00
Pennsylvania.............................. York Co...................... 16.22 13.46 -2.76
Tennessee................................. Davidson Co.................. 15.36 14.02 -1.34
Tennessee................................. Hamilton Co.................. 16.82 14.94 -1.88
Tennessee................................. Knox Co...................... 17.34 15.61 -1.73
Tennessee................................. Shelby Co.................... 15.17 14.19 -0.98
Tennessee................................. Sullivan Co.................. 15.37 13.77 -1.60
West Virginia............................. Berkeley Co.................. 15.32 12.73 -2.59
West Virginia............................. Brooke Co.................... 16.51 14.05 -2.46
West Virginia............................. Cabell Co.................... 16.86 14.64 -2.22
West Virginia............................. Hancock Co................... 16.97 14.54 -2.43
West Virginia............................. Kanawha Co................... 17.17 14.66 -2.51
West Virginia............................. Marshall Co.................. 15.52 12.87 -2.65
West Virginia............................. Wood Co...................... 16.69 13.88 -2.81
----------------------------------------------------------------------------------------------------------------

As described in section VI.B.1, we project that 79 counties in the
East will be nonattainment for PM_2.5 in the 2010 base case.
We estimate that, on average, the regional strategy will reduce
PM_2.5 in these 79 counties by 1.6 [mu]g/m3. In
over 90 percent of the nonattainment counties (i.e., 74 out of 79
counties), we project that PM_2.5 will be reduced by at least
1.0 [mu]g/m3. In over 25 percent of the 79 nonattainment
counties (i.e., 23 of the 79 counties), we project PM_2.5
concentrations will decline by of more than 2.0 [mu]g/m3. Of
the 79 counties that are nonattainment in the 2010 Base, we project
that 51 counties will come into attainment as a result of the
SO₂ and NO_X emissions reductions expected from
the regional controls. Even those 28 counties that remain nonattainment
in 2010 after implementation of the regional strategy will be closer to
attainment as a result of these emissions reductions. Specifically, the
average reduction of PM_2.5 in the 28 residual nonattainment
counties is projected to be 1.3 [mu]g/m3. After
implementation of the regional controls, we project that 18 of the 28
residual nonattainment counties in 2010 will be within 1.0 [mu]g/
m3 of the NAAQS and 12 counties will be within 0.5 [mu]g/
m3 of attainment.
In 2015 we are projecting that PM_2.5 in the 74 base case
nonattainment counties will be reduced by 1.8 [mu]g/m3, on
average, as a result of the SO₂ and NO_X
reductions in the regional strategy. In over 90 percent of the
nonattainment counties (i.e., 67 of the 74 counties) concentrations of
PM_2.5 are predicted to be reduced by at least 1.0 [mu]g/
m3. In over 35 percent of the counties (i.e., 27 of the 74
counties), we project the regional strategy to reduce PM_2.5
by more than 2.0 [mu]g/m3. As a result of the reductions in
PM_2.5, 56 nonattainment counties are projected to come into
attainment in 2015. The remaining 18 nonattainment

[[Page 25254]]

counties are projected to be closer to attainment with the regional
strategy. Our modeling results indicate that PM_2.5 will be
reduced in the range of 0.7 [mu]g/m3 to 2.9 [mu]g/
m3 in these 18 counties. The average reduction across these
18 residual nonattainment counties is 1.5 [mu]g/m3.
Thus, the SO₂ and NO_X emissions reductions
which will result from the regional strategy will greatly reduce the
extent of PM_2.5 nonattainment by 2010 and beyond. These
emissions reductions are expected to substantially reduce the number of
PM_2.5 nonattainment counties in the East and make attainment
easier for those counties that remain nonattainment by substantially
lowering PM_2.5 concentrations in these residual
nonattainment counties.
2. Estimated Impacts on 8-Hour Ozone Concentrations and Attainment
We determined the impacts on 8-hour ozone of the regional strategy
by running the CAM_X model for this strategy and comparing
the results to the ozone concentrations predicted for the 2010 and 2015
base cases. In brief, we ran the CAM_X model for the regional
strategy in both 2010 and 2015. The model predictions were used to
project future 8-hour ozone concentrations for the regional strategy in
2010 and 2015 using the Relative Reduction Factor technique, as
described in section VI.B.1. We compared the results of the 2010 and
2015 regional strategy modeling to the corresponding results from the
2010 and 2015 base cases to quantify the expected impacts of the
regional controls.
The results of the regional strategy ozone modeling are expressed
in terms of the expected reductions in projected 8-hour concentrations
and the implications for future nonattainment. The impacts of the
regional NO_X emissions reductions on 8-hour ozone in 2010
and 2015 are provided in Table VI-12 and Table VI-13, respectively. In
these tables, counties shown in bold/italics are projected to come into
attainment with the regional controls.

Table VI-12.--Projected 8-Hour Concentrations (ppb) for the 2010 Base Case and CAIR and the Impact of CAIR
Regional Controls in 2010
----------------------------------------------------------------------------------------------------------------
2010 Base Impact of
State County case 2010 CAIR CAIR
----------------------------------------------------------------------------------------------------------------
Connecticut............................... Fairfield Co................. 92.6 92.2 -0.4
Connecticut............................... Middlesex Co................. 90.9 90.6 -0.3
Connecticut............................... New Haven Co................. 91.6 91.3 -0.3
District of Columbia...................... District of Columbia......... 85.2 85.0 -0.2
Delaware.................................. New Castle Co................ 85.0 84.7 -0.3
Georgia................................... Fulton Co.................... 86.5 85.1 -1.4
Maryland.................................. Anne Arundel Co.............. 88.8 88.6 -0.2
Maryland.................................. Cecil Co..................... 89.7 89.5 -0.2
Maryland.................................. Harford Co................... 93.0 92.8 -0.2
Maryland.................................. Kent Co...................... 86.2 85.8 -0.4
Michigan.................................. Macomb Co.................... 85.5 85.4 -0.1
New Jersey................................ Bergen Co.................... 86.9 86.0 -0.9
New Jersey................................ Camden Co.................... 91.9 91.6 -0.3
New Jersey................................ Gloucester Co................ 91.8 91.3 -0.5
New Jersey................................ Hunterdon Co................. 89.0 88.6 -0.4
New Jersey................................ Mercer Co.................... 95.6 95.2 -0.4
New Jersey................................ Middlesex Co................. 92.4 92.1 -0.3
New Jersey................................ Monmouth Co.................. 86.6 86.4 -0.2
New Jersey................................ Morris Co.................... 86.5 85.5 -1.0
New Jersey................................ Ocean Co..................... 100.5 100.3 -0.2
New York.................................. Erie Co...................... 87.3 86.9 -0.4
New York.................................. Richmond Co.................. 87.3 87.1 -0.2
New York.................................. Suffolk Co................... 91.1 90.8 -0.3
New York.................................. Westchester Co............... 85.3 84.7 -0.6
Ohio...................................... Geauga Co.................... 87.1 86.6 -0.5
Pennsylvania.............................. Bucks Co..................... 94.7 94.3 -0.4
Pennsylvania.............................. Chester Co................... 85.7 85.4 -0.3
Pennsylvania.............................. Montgomery Co................ 88.0 87.6 -0.4
Pennsylvania.............................. Philadelphia Co.............. 90.3 89.9 -0.4
Rhode Island.............................. Kent Co...................... 86.4 86.2 -0.2
Texas..................................... Denton Co.................... 87.4 86.8 -0.6
Texas..................................... Galveston Co................. 85.1 84.6 -0.5
Texas..................................... Harris Co.................... 97.9 97.4 -0.5
Texas..................................... Jefferson Co................. 85.6 85.0 -0.6
Texas..................................... Tarrant Co................... 87.8 87.2 -0.6
Virginia.................................. Arlington Co................. 86.2 86.0 -0.2
Virginia.................................. Fairfax Co................... 85.7 85.4 -0.3
Wisconsin................................. Kenosha Co................... 91.3 91.0 -0.3
Wisconsin................................. Ozaukee Co................... 86.2 85.8 -0.4
Wisconsin................................. Sheboygan Co................. 88.3 87.7 -0.6
----------------------------------------------------------------------------------------------------------------

Table VI-13.--Projected 8-Hour Concentrations (ppb) for the 2015 Base Case and CAIR and the Impact of CAIR
Regional Controls in 2015
----------------------------------------------------------------------------------------------------------------
2015 Base Impact of
State County case 2015 CAIR CAIR
----------------------------------------------------------------------------------------------------------------
Connecticut............................... Fairfield Co................. 91.4 90.6 -0.8

[[Page 25255]]

Connecticut............................... Middlesex Co................. 89.1 88.4 -0.7
Connecticut............................... New Haven Co................. 89.8 89.1 -0.7
Maryland.................................. Anne Arundel Co.............. 86.0 84.9 -1.1
Maryland.................................. Cecil Co..................... 86.9 85.4 -1.5
Maryland.................................. Harford Co................... 90.6 89.6 -1.0
Michigan.................................. Macomb Co.................... 85.1 84.2 -0.9
New Jersey................................ Bergen Co.................... 85.7 84.5 -1.2
New Jersey................................ Camden Co.................... 89.5 88.3 -1.2
New Jersey................................ Gloucester Co................ 89.6 88.2 -1.4
New Jersey................................ Hunterdon Co................. 86.5 85.4 -1.1
New Jersey................................ Mercer Co.................... 93.5 92.4 -1.1
New Jersey................................ Middlesex Co................. 89.8 88.8 -1.0
New Jersey................................ Ocean Co..................... 98.0 96.9 -1.1
New York.................................. Erie Co...................... 85.2 84.2 -1.0
New York.................................. Suffolk Co................... 89.9 89.0 -0.9
Pennsylvania.............................. Bucks Co..................... 93.0 91.8 -1.2
Pennsylvania.............................. Montgomery Co................ 86.5 84.9 -1.6
Pennsylvania.............................. Philadelphia Co.............. 88.9 87.5 -1.4
Texas..................................... Harris Co.................... 97.3 96.4 -0.9
Texas..................................... Jefferson Co................. 85.0 84.1 -0.9
Wisconsin................................. Kenosha Co................... 89.4 88.8 -0.6
----------------------------------------------------------------------------------------------------------------

As described in section VI.B.1, we project that 40 counties in the
East would be nonattainment for 8-hour ozone under the assumptions in
the 2010 base case. Our modeling of the regional controls in 2010
indicates that 3 of these counties will come into attainment of the 8-
hour ozone NAAQS and that ozone in 16 of the 40 nonattainment counties
will be reduced by 1 ppb or more. In addition, our modeling predicts
that 8-hour ozone exceedances (i.e., 8-hour ozone of 85 ppb or higher)
within nonattainment areas are expected to decline by 5 percent in 2010
with CAIR. Of the 37 counties that are projected to remain
nonattainment in 2010 after the regional strategy, nearly half (i.e.,
16 of the 37 counties) are within 2 ppb of attainment.
In 2015, we project that 6 of the 22 counties which are
nonattainment for 8-hour ozone in the base case will come into
attainment with the regional strategy. Ozone concentrations in over 70
percent (i.e., 16 of 22 counties) of the 2015 base case nonattainment
counties are projected to be reduced by 1 ppb or more as a result of
the regional strategy. Exceedances of the 8-hour ozone NAAQS are
predicted to decline in nonattainment areas by 14 percent with regional
controls in place in 2015. Thus, the NO_X emissions
reductions which will result from the regional strategy will help to
bring 8-hour ozone nonattainment areas in the East closer to attainment
by 2010 and beyond.

F. What are the Estimated Visibility Impacts of the Final Rule?

1. Methods for Calculating Projected Visibility in Class I Areas
The NPR contained example future year visibility projections for
the 20 percent worst days and 20 percent best days at Class I areas
that had complete IMPROVE monitoring data in 1996. Changes in future
visibility were predicted by using the REMSAD model to generate
relative visibility changes, then applying those changes to measured
current visibility data. Details of the visibility modeling and
calculations can be found in the NPR AQMTSD. An example visibility
calculation was given in Appendix M of the NPR AQMTSD along with the
predicted improvement in visibility (in deciviews) on the 20 percent
best and worst days at 44 Class I areas. The data contained in Appendix
M was for informational purposes only and was not used in the
significant contribution determination or control strategy development
decisions.
The SNPR contained visibility calculations in support of the
``better-than-BART'' analysis. The better-than-BART analysis employed a
two-pronged test to determine if the modeled visibility improvements
from the CAIR cap and trade program for EGU's were ``better'' than the
visibility improvements from a nationwide BART program. The analysis
used the visibility calculation methodology detailed in the NPR TSD.
Detailed results of the SNPR better-than-BART analysis are contained in
the SNPR AQMTSD. The better-than-BART analysis for the final rule is
addressed in section IX.C.2 of the preamble. Additional information on
the visibility calculation methodology is contained in the NFR AQMTSD.
2. Visibility Improvements in Class I Areas
For the NFR we have modeled several new CAIR \107\ and CAIR + BART
cases to re-examine the better-than-BART two-pronged test. We have
modeled an updated nationwide BART scenario as well as a CAIR in the
East/BART in the West scenario. The results were analyzed at 116 Class
I areas that have complete IMPROVE data for 2001 or are represented by
IMPROVE monitors with complete data. Twenty-nine of the Class I areas
are in the East and 87 are in the West. The results of the visibility
analysis are summarized in section IX.C.2. Detailed results for all 116
Class I areas are presented in the NFR AQMTSD.
---------------------------------------------------------------------------

\107\ The CAIR scenario modeled for the visibility analysis
included controls in Arkansas, Delaware, and New Jersey.
---------------------------------------------------------------------------

VII. SIP Criteria and Emissions Reporting Requirements

This section describes: (1) The criteria we will use in determining
approvability of SIPs submitted to meet the requirements of today's
rulemaking; (2) the dates for submittal of the SIPs that are required
under the CAIR; (3) the consequences of either failing to submit such a
SIP or submitting a SIP which is

[[Page 25256]]

disapproved; and (4) the emissions inventory reporting requirements for
States.

A. What Criteria Will EPA Use To Evaluate the Approvability of a
Transport SIP?

1. Introduction
The approvability criteria for CAIR SIP submissions are finalized
today in 40 CFR 51.123 (NO_X emissions reductions) and in 40
CFR 51.124 (SO₂ emissions reductions). Most of the criteria
are substantially similar to those that currently apply to SIP
submissions under CAA section 110 or part D (nonattainment). For
example, each submission must describe the control measures that the
State intends to employ, identify the enforcement methods for
monitoring compliance and managing violations, and demonstrate that the
State has legal authority to carry out its plan.
This part of the preamble explains additional approvability
criteria specific to the CAIR that were proposed and discussed in the
CAIR NPR or in the CAIR SNPR, and are being promulgated today. As
explained in both the CAIR NPR and the CAIR SNPR, EPA proposed that
each affected State must submit SIP revisions containing control
measures that assure that a specified amount of NO_X and
SO₂ emissions reductions are achieved by specified dates.
Although EPA determined the amount of emissions reductions required
by identifying specific, highly cost-effective control levels for EGUs,
EPA explained in the CAIR NPR and the CAIR SNPR that States have
flexibility in choosing which sources to control to achieve the
required emissions reductions. As long as a State's emissions
reductions requirements are met, a State may impose controls on EGUs
only, on non-EGUs only, or on a combination of EGUs and non-EGUs. The
SIP approvability criteria are intended to provide as much certainty as
possible that, whichever sources a State chooses to control, the
controls will result in the required amount of emissions reductions.
In the CAIR NPR, EPA proposed a ``hybrid'' approach for the
mechanisms used to ensure emissions reductions are achieved. This
approach incorporates elements of an emissions ``budget'' approach
(requiring an emissions cap on affected sources) and an ``emissions
reduction'' approach (not requiring an emissions cap). In this hybrid
approach, if States impose control measures on EGUs, they would be
required to impose an emissions cap on all EGUs, which would
effectively be an emissions budget. And, as stated in the CAIR NPR, if
States impose control measures on non-EGUs, they would be encouraged
but not required to impose an emissions cap on non-EGUs. In the CAIR
NPR, we requested comment on the issue of requiring States to impose
caps on any source categories that the State chooses to regulate.
In the CAIR SNPR, we proposed to modify the hybrid approach and
require States that choose to control large industrial boilers or
turbines (greater than 250 MMBTU/hr) to impose an emissions cap on all
such sources within their State. This is similar to EPA's approach in
the NO_X SIP Call which required States to include an
emissions cap on such sources as well as on EGUs if the SIP submittals
included controls on such sources. (See 40 CFR 51.121(f)(2)(ii).)
A few commenters supported the use of emissions caps on any source
category subject to CAIR controls, including non-EGUs, because it would
be the most effective way to demonstrate compliance with the budget. A
few other commenters opposed the use of an emissions cap on non-EGUs,
saying either that States should have the flexibility to determine
whether to impose a cap, or that such a requirement would result in
increased costs for non-EGUs including cogeneration units that are non-
EGUs. No commenter opposing such a requirement provided any information
indicating that such a requirement would be ineffective or
impracticable. Today EPA is adopting the modified approach, as
described in the CAIR SNPR, that States choosing to control EGUs or
large industrial boilers or turbines must do so by imposing an
emissions cap on such sources, similar to what was required in the
NO_X SIP Call.
Extensive comments were received regarding the need for an ozone
season NO_X cap in States identified to be contributing
significantly to the region's ozone nonattainment problems. In
proposal, EPA stated that the annual NO_X cap under CAIR
reduced NO_X emissions sufficiently enough to not warrant a
regional ozone season NO_X cap. Commenters remained very
concerned that the annual NO_X cap would not aid ozone
attainment. While EPA feels that the annual NO_X limit will
most likely be protective in the ozone season, a seasonal cap will
provide certainty, which EPA agrees is very important in the effort to
help areas achieve ozone attainment. Today, EPA is finalizing an ozone
season NO_X cap for States shown to contribute significantly
for ozone. As is further explained in section VIII, EPA is also
finalizing an ozone season trading program that States may use to
achieve the required emissions reductions. This program will subsume
the existing NO_X SIP Call trading program. Therefore, any
State that wishes to continue including its sources in an interstate
trading program run by EPA to achieve the emissions reductions required
by EPA must modify its SIP to conform with this new trading program.
The EPA will automatically find that a State is continuing to meet
its NO_X SIP Call obligation if it achieves all of its
required CAIR emissions reductions by capping EGUs, it modifies its
existing NO_X SIP Call to require its non-EGUs currently
participating in the NO_X SIP Call budget trading program to
conform to the requirements of the CAIR ozone season NO_X
trading program with a trading budget that is the same or tighter than
the budget in the currently approved SIP, and it does not modify any of
its other existing NO_X SIP Call rules. If a State chooses to
achieve the ozone season NO_X emissions reduction
requirements of CAIR in another way, it will also be required to
demonstrate that it continues to meet the requirements of the
NO_X SIP Call.
Specific criteria for approval of CAIR SIP submissions as
promulgated by today's action are described below. The criteria are
dependent on the types of sources a State chooses to control.
2. Requirements for States Choosing To Control EGUs
a. Emissions Caps and Monitoring
As explained in the CAIR NPR (69 FR 4626), and in the CAIR SNPR (69
FR 32691), EPA proposed requiring States to apply the ``budget''
approach if they choose to control EGUs; that is, each State must cap
total EGU emissions at the level that assures the appropriate amount of
reductions for that State. The requirement to cap all EGUs is important
because it prevents shifting of utilization (and resulting emissions)
to uncapped EGUs. The EGUs are part of a highly interconnected
electricity grid that makes utilization shifting likely and even
common. The units are large and offer the same market product (i.e.,
electricity), and therefore the units that are least expensive to
operate are likely to be operated as much as possible. If capped and
uncapped units are interconnected, the uncapped units' costs would tend
to decrease relative to the capped units, which must either reduce
emissions or use or buy allowances, and the uncapped units' utilization
would likely increase. The cap ensures that emissions reductions

[[Page 25257]]

from these interconnected sources are actually achieved rather than
emissions simply shifting among sources. The caps constitute the State
EGU Budgets for SO₂ and NO_X. Additionally, EPA
proposed that, if States choose to control EGUs, they must require EGUs
to follow part 75 monitoring, recordkeeping, and reporting
requirements. Part 75 monitoring and reporting requirements have been
used effectively for determining NO_X and SO₂
emissions from EGUs under the title IV Acid Rain program and the
NO_X SIP Call program and in combination with emissions caps
are an integral part of those programs. (Additional explanation for the
need for Part 75 monitoring is given in the NPR and SNPR and is
incorporated here.) Therefore, today, EPA adopts the requirements for
emission caps and Part 75 monitoring for EGUs in these States.
b. Using the Model Trading Rules
As proposed, if a State chooses to allow its EGUs to participate in
EPA-administered interstate NO_X and SO₂ emissions
trading programs, the State must adopt EPA's model trading rules, as
described elsewhere in today's preamble and in Sec. Sec. 96.101-96.176
(for NO_X) and Sec. Sec. 96.201-96.276 (for SO₂),
set forth below. Additionally, EPA proposed that for the States for
which EPA made a finding of significant contribution for both ozone and
PM_2.5, participation in both the NO_X and
SO₂ trading programs would be required in order to be
included in the EPA-administered program. States for which the finding
was for ozone only could choose to participate in only the EPA-
administered NO_X trading program through adoption of the
NO_X model trading rule. The EPA stated that States adopting
EPA's model trading rules, modified only as specifically allowed by
EPA, will meet the requirement for applying an emissions cap and
requirement to use part 75 monitoring, recordkeeping, and reporting for
EGUs.
Some commenters opposed EPA's proposal to require participation in
both the NO_X and SO₂ trading programs because
some States may want to participate in the EPA-administered trading
programs for only NO_X or only SO₂. A few
commenters claimed that the requirement to participate in both programs
would limit State flexibility or is an ``all or nothing'' approach;
other commenters objected that there was no environmental basis for
such a requirement; and one commenter suggested that States not
affected by CAIR but that volunteer to control emissions should be
permitted to join the program for one or both pollutants. Additionally,
commenters cited a need for an ozone season NO_X program.
The EPA has taken the comments into account and in today's action
agrees to allow a State identified to contribute significantly for
PM_2.5 (and therefore required to make annual SO₂
and NO_X reductions) to participate in the EPA-administered
CAIR trading program for either SO₂ or NO_X, not
necessarily both, so long as the State adopts the model rule for the
applicable trading program.
In response to extensive comments relating to EPA's proposal to
forego a seasonal NO_X cap because EPA demonstrated that the
annual NO_X cap was sufficiently stringent, EPA is finalizing
an ozone season NO_X trading program for States identified as
contributing significantly for ozone. These States will be subject to
an ozone season NO_X cap and an annual NO_X cap if
the State is also identified as contributing significantly for
PM_2.5. Therefore, today's action includes an additional
model rule for an ozone season NO_X trading program (40 CFR
96, subparts AAAA through IIII). The States that may use the ozone
season NO_X trading program but not the annual NO_X
trading program are those States in the CAIR region identified as
contributing significantly for ozone only (Arkansas, Connecticut,
Delaware, Massachusetts, and New Jersey).
As discussed in the proposal, EPA is finalizing the option for New
Hampshire and Rhode Island to participate in the regional trading
program through use of the CAIR ozone season NO_X model rule
because sources in these States have made investments in NO_X
controls in the past based on the existence of a regional ozone season
NO_X trading program. Additionally, the States' combined
projected 2010 and 2015 NO_X emissions are less than one-half
of one percent of the total CAIR regional NO_X cap and
therefore would not create a significant increase in the CAIR cap. All
comments received were supportive of this approach and EPA is
finalizing it today.
None of these States (Arkansas, Connecticut, Delaware,
Massachusetts, New Hampshire, New Jersey, or Rhode Island) has the
option to participate in the EPA-administered CAIR SO₂
trading program nor the annual CAIR NO_X trading program
because there are no PM_2.5-related emissions reductions
required under today's action in those States. (Of course, sources in
these States will still be subject to the Acid Rain SO₂ cap
and trade program.) Likewise, Texas, Minnesota and Georgia may not
participate in the ozone season NO_X program, because they
have not been shown to contribute significantly to the regional ozone
problem. They are, however, required to make annual NO_X and
SO₂ reductions and may choose to participate in the annual
NO_X and annual SO₂ trading program to meet their
CAIR obligations.
Except for the special cases of Rhode Island and New Hampshire,
other States outside of the CAIR region may not participate in the CAIR
trading programs for either pollutant, because they were not shown to
contribute significantly to PM_2.5 or ozone nonattainment in
the CAIR region. Allowing States outside of the CAIR region to
participate would generally create an opportunity--through net sales of
allowances from the non-CAIR States to CAIR States--for emission
increases in States that have been shown to contribute significantly to
nonattainment in the CAIR region.\108\
---------------------------------------------------------------------------

\108\ Title IV allowances can however be traded freely across
the boundary of the CAIR region without any significant, negative
environmental consequence. The potential negative consequences have
been addressed through other requirements discussed below, like the
retirement of excess title IV allowances.
---------------------------------------------------------------------------

A State may not participate in the EPA-administered trading
programs if they choose to get a portion of CAIR reductions from non-
EGUs. (This is also discussed in Section VIII.) The EPA maintains that
requiring certain consistencies among States in the regionwide trading
programs that EPA has offered to run does not unfairly limit States'
flexibility to choose an approach for achieving CAIR mandated
reductions that is best suited for a particular State's unique
circumstances. States are free to achieve the reductions through
whatever alternative mechanisms the States wish to design; for example,
a group of States could cooperatively implement their own multi-State
trading programs that EPA would not administer.
c. Using a Mechanism Other Than the Model Trading Rules
If States choose to control EGUs through a mechanism other than the
EPA-administered NO_X and SO₂ emissions trading
programs, then the States (i) must still impose an emissions cap on
total EGU emissions and require part 75 monitoring, recordkeeping, and
reporting requirements on all EGUs, and (ii) must use the same
definition of EGU as EPA uses in its model trading rules, i.e., the
sources described as ``CAIR units'' in Sec. 96.102, Sec. 96.202, and
Sec. 96.302. A few commenters expressed concern that these
requirements limit States' discretion in designing control measures to
meet the CAIR requirements, but failed to offer any

[[Page 25258]]

reason why the requirements would be impracticable or ineffective. The
EPA believes that the requirements are necessary for a number of
reasons. The requirements to cap all EGUs and to use the same
definition of EGU are important because they prevent shifting of
utilization (and resulting emissions) from capped to uncapped sources.
In this case, not requiring a cap on total EGU emissions in these
States is likely to result in increased utilization and consequently
increased emissions in these States. The requirement to use part 75
monitoring ensures the accuracy of monitored data and consistency of
reporting among sources (and thus the certainty that emissions
reductions actually occurred) across all States. Furthermore, most EGUs
are currently monitoring and reporting using part 75 so it does not
impose an additional requirement. Therefore, EPA is finalizing the
proposed approach.
If a State chooses to design its own intrastate or interstate
NO_X or SO₂ emissions trading programs, the State
must, in addition to meeting the requirements of the rules finalized in
today's action, consider EPA's guidance, ``Improving Air Quality with
Economic Incentive Programs,'' January, 2001 (EPA-452/R-01-001)
(available on EPA's Web site at: http://www.epa.gov/ttn/ecas/
incentiv.html). The State's programs are subject to EPA approval. The
EPA will not administer a State-designed trading program. Additionally,
it should be noted that allowances from any alternate trading program
may not be used in the EPA-administered trading programs.
d. Retirement of Excess Title IV Allowances
The CAIR NPR proposed requirements on SIPs relating to the effects
of title IV SO₂ allowance allocations for 2010 and beyond
that are in excess of the State's CAIR EGU SO₂ emissions
budget. The requirements were intended to ensure that the excess is not
used in a manner that would lead to a significant increase in supply of
title IV allowances, the collapse of the price of title IV allowances,
the disruption of operation of the title IV allowance market and the
title IV SO₂ cap and trade system, and the potential for
increased emissions in all States prior to 2010 and in non-CAIR States
in 2010 and later. These negative impacts on the title IV allowance
market and on air quality, which are discussed in detail in section
IX.B. below, would undermine the efficacy of the title IV program and
could erode confidence in cap and trade programs in general. To avoid
these impacts, EPA proposed to require retirement of the excess title
IV allowances through a retirement ratio mechanism.
The EPA proposed, as a mechanism for removing these additional
allowances and meeting the 50 percent reduction required under phase I
(2010-2014), that each affected EGU had to hold, and EPA would retire,
two vintage 2010-2014 allowances for every ton of SO₂ that
the unit emits. Further, EPA proposed that, for phase II (which begins
in 2015) when a 65 percent reduction is required, each affected EGU had
to hold, and EPA would retire, three vintage 2015 and beyond allowances
for every ton of SO₂ that the unit emits. This 3-to-1 ratio
would result in slightly more reductions than EPA has determined were
necessary to eliminate the significant contribution by an upwind State.
In the CAIR SNPR, EPA proposed two alternatives for addressing the
issue of the additional allowances. Under the first alternative,
affected EGUs had to hold, and EPA would retire, vintage 2015 and
beyond allowances at a rate of 2.86-to-1 rather than 3-to-1, which
would result in exactly the amount of reductions EPA has determined are
necessary to eliminate a State's significant contribution.
Alternatively, also in the CAIR SNPR, EPA proposed requiring the
retirement of 2015 and beyond vintage allowances at a 3-to-1 ratio and
permitting States to convert the additional reductions into allowances
in their rules. The EPA also suggested that some States may want to use
these reserved allowances to create an incentive for additional local
emissions reductions that will be needed to bring all areas into
attainment with the PM_2.5 NAAQS.
As part of today's final CAIR rulemaking, EPA is finalizing a ratio
of 2.86-to-one. The ratio ultimately represents a reduction of 65
percent from the final title IV cap level, which has been found to be
highly cost-effective. For a detailed discussion regarding EPA's
determination of highly cost-effective, please refer to Section IV of
the final CAIR preamble. As discussed earlier, EPA must employ a
uniform ratio across sources to ensure consistency and the same cost-
effectiveness level across sources. Therefore, EPA will use a Phase II
ratio of 2.86-to-1 for all States affected by CAIR who choose to
participate in the trading program.
Today, EPA is finalizing the general requirement that all SIPs must
include a mechanism to ensure that excess SO₂ allowances are
retired. Furthermore, for States that participate in the EPA-
administered cap and trade program, EPA is finalizing a specific
mechanism that States must use.
i. States Participating in the EPA-Administered SO₂ Trading
Program
If a State chooses to participate in the EPA-administered trading
program, the State's excess title IV allowance retirement mechanism
must follow the provisions of the SO₂ model trading rule
that requires that vintage 2010 through 2014 title IV allowances be
retired at a ratio of two allowances for every ton of emissions and
that vintage 2015 and beyond title IV allowances be retired at a ratio
of 2.86 allowances for every ton of emissions. Pre-2010 vintage
allowances would be retired at a ratio of one allowance for every ton
of emissions. (See discussion of the model SO₂ cap and trade
rule in section VIII of today's preamble.) States using the model
SO₂ cap and trade rule satisfy the requirement for
retirement of excess title IV allowances.
ii. States Not Participating in the EPA-Administered SO₂
Trading Program
In the CAIR NPR, EPA stated that if a State does not choose to
participate in the EPA-administered trading programs but controls only
EGUs, the State may choose the specific method to retire allowances in
excess of its budget. The EPA considered alternative ways for retiring
these excess allowances and, as stated in the CAIR SNPR, believed that
the use by different States of different means to address this concern
could undermine the regionwide emissions reduction goals of the CAIR
rulemaking. The EPA further described its concerns in section II of the
preamble to the CAIR SNPR. (See 69 FR 32686-32688.) Because of these
concerns, in the CAIR SNPR, EPA withdrew the CAIR NPR proposal on this
point and re-proposed that all States use a 2-for-1 retirement ratio
for vintage 2010 through 2014 allowances and a 2.86-for-1 or a 3-for-1
retirement ratio for vintage 2015 and beyond allowances to address
concerns about title IV allowances that exceed State budgets. The EGUs
would have a total emissions cap enforced by the State.
The SNPR described that for sources affected by both title IV and
CAIR, allowance deductions and associated compliance determinations
would be sequential. That is, title IV compliance would be determined
and then CAIR compliance would be determined. So, in 2010-2014, after
surrendering one vintage 2010 through 2014 allowance for each ton of
emissions for title IV compliance, the source would then surrender one
additional allowance (for a total of two allowances for each ton

[[Page 25259]]

which meets the CAIR requirement). Similarly, in 2015 and beyond, after
surrendering one vintage 2015 and beyond allowance for each ton of
emissions for title IV compliance, the source would surrender 1.86 or 2
additional allowances and therefore meet the CAIR requirement.
Commenters argued that in States where EGUs are not trading under CAIR
that the excess title IV allowances could be removed in a variety of
ways and that EPA did not need to require each State do this the same
way, only that each State ensure that they are removed.
Today, EPA adopts the following requirement: If a State does not
choose to participate in the EPA-administered trading programs but
controls only EGUs, the State must include in its SIP a mechanism for
retiring the excess title IV allowances (i.e., the difference between
total allowance allocations in the State and the State EGU
SO₂ budget). To meet this requirement, the State may use the
above-described retirement mechanism or may develop a different
mechanism that will achieve the required retirement of excess
allowances.
3. Requirements for States Choosing to Control Sources Other Than EGUs
a. Overview of Requirements
As noted in both the CAIR NPR and the CAIR SNPR, if a State chooses
to require emissions reductions from non-EGUs, the State must adopt and
submit SIP revisions and supporting documentation designed to quantify
the amount of reductions from the non-EGU sources and to assure that
the controls will achieve that amount. Although EPA did not propose in
the CAIR NPR that States be required to impose an emissions cap on
those sources, but instead solicited comment on the issue, EPA proposed
in the CAIR SNPR that States be required to impose an emissions cap in
certain cases on non-EGU sources. (See discussion in VII.A.1 of today's
preamble.)
If a State chooses to obtain some, but not all, of its required
reductions for SO₂ or NO_X emissions from non-
EGUs, it would still be required to set an EGU budget for
SO₂ or NO_X respectively, but it would set such a
budget at some level higher than shown in Tables V-1, V-2, or V-4 in
today's preamble, thus allowing more emissions from EGUs. The
difference between the amount of a State's SO₂ budget in
Table V-1 and a State's selected higher EGU SO₂ budget would
be the amount of SO₂ emissions reductions the State
demonstrates it will achieve from non-EGU sources. By the same token,
the difference between the amount of a State's annual NO_X
budget in Table V-2 and a State's selected higher annual EGU
NO_X budget would be the amount of annual NO_X
emissions reductions the State demonstrates it will achieve from non-
EGU sources.\109\ Further, the difference between the amount of a
State's seasonal NO_X budget in Table V-4 and a State's
selected higher ozone season EGU NO_X budget would be the
amount of ozone season NO_X emissions reductions the State
demonstrates it will achieve from non-EGU sources.
---------------------------------------------------------------------------

\109\ In the CAIR SNPR, EPA mistakenly cited the EGU budget
numbers from Tables VI-9 and VI-10 in the CAIR NPR (69 FR 4619-20)
when it should have cited Tables II-1 and II-2 in the CAIR SNPR. The
EPA used the correct numbers, however, in the proposed regulatory
text in the CAIR SNPR (69 FR 32729-30 and 69 FR 32733-34 (Sec. Sec.
51.123(e)(2) and 51.124(e)(2)).
---------------------------------------------------------------------------

Special Concerns About SO₂ Allowances

In the case where a State requires a portion of its SO₂
emissions reductions from non-EGU sources and a portion from EGUs,
there remains a concern about the impact of excess title IV allowances
above a State's EGU cap, particularly on the operation of the title IV
SO₂ cap and trade program. Consequently, today, we are
adopting the requirement that these States include a mechanism for
retirement of the allowances in excess of the State's SO₂
budget.
Like a State choosing to control only EGUs but not to participate
in the trading program, a State that chooses to control non-EGUs and
EGUs must adopt a mechanism for retiring surplus title IV allowances.
The number of title IV allowances that must be retired is equal to the
difference between the number of title IV allowances allocated to EGUs
in that State and the SO₂ budget the State sets for EGUs
under this rule. If the State uses a retirement mechanism (as discussed
in VII.A.2.d.) in which a source surrendering allowances under the
title IV SO₂ cap and trade program surrenders more
allowances than otherwise required under title IV, the total number of
allowances surrendered per ton of emissions in this case will be less
than 2 to 1 in Phase 1 and less than 2.86 to 1 in Phase 2. This is
because the non-EGUs will control to achieve a portion of the CAIR
SO₂ reduction required, and so there will be a smaller
surplus of title IV allowances than if all the required reductions were
achieved by EGUs. The appropriate retirement factor will equal two
times the State's SO₂ budget in Phase I or 2.86 times the
State's SO₂ budget in Phase II as noted in Table V-1 of the
budget section, divided by the State's selected higher EGU
SO₂ budget (taking into account non-EGU reductions). The
factor could then be used as the EGU retirement ratio for compliance
purposes in a scenario where a State has decided to control
SO₂ emissions from EGUs through a mechanism other than the
EPA-administered trading program.
A simplified example can help illustrate this. Let us assume a
State's sources were allocated a total of 200 allowances under title
IV. Under CAIR, in Phase I, the State's reduction requirement would
thus be 100 tons. Suppose this State decided that 25 tons would be
reduced by non-EGUs and the remaining 75 tons would be reduced by the
EGUs. (The State's budget for EGUS would increase to 125 tons.) The
State would also need to retire 75 excess title IV allowances. This
could be accomplished by requiring each Acid Rain source to surrender a
total of 1.6 vintage 2010 through 2014 allowances (200 allowances
allocated in the State/125 tons in State EGU budget) per ton of
SO₂ emissions. The allowances surrendered would satisfy the
Acid Rain Program requirement of surrendering one allowance per ton of
emissions, as well as achieving the additional retirement requirement
under CAIR since 200 allowances would be used for EGUs to emit the EGU
budget of 125 tons of SO₂. (Pre-2010 allowances continue to
be available for use on a one-allowance-per-ton-of-emissions basis here
as in other situations.)
This is consistent with EPA's overall approach. If this same State
decided to get all reductions (i.e., 100 tons) from EGUs, the State
would require EGUs to retire 100 additional allowances by surrendering
a total of 2 vintage 2010 through 2014 allowances (200 allowances
allocated in the State/100 tons in State EGU budget) per ton of
SO₂ emissions.
The demonstration of emissions reductions from non-EGUs is a
critical requirement of the SIP revision due from a State that chooses
to control non-EGUs. The State must take into account the amount of
emissions attributable to the source category in both (i) the base
case, in the implementation years 2010 and 2015, i.e., without assuming
any SIP-required reductions under the CAIR from non-EGUs; and (ii) in
the control case, in the implementation years 2010 and 2015, i.e.,
assuming SIP-required reductions under the CAIR from non-EGUs. We
proposed an alternative methodology for calculating the base case for
certain large non-EGU sources, as described below, but generally the
difference between emissions in the base case and emissions in the control

[[Page 25260]]

case equals the amount of emissions reductions that can be claimed from
application of the controls on non-EGUs. (See discussion later in this
section for criteria applicable to development of the baseline and
projected control emissions inventories.)
States that meet the lesser of their CAIR ozone season
NO_X budget or NO_X SIP Call EGU trading budget
using the CAIR ozone season NO_X trading program also satisfy
their NO_X SIP Call requirements for EGUs. States may also
choose to include all of their NO_X SIP Call non-EGUs in the
CAIR ozone season NO_X program at their NO_X SIP
Call levels (i.e., the non-EGU trading budget remains the same).
To the extent EPA allows through the Regional Haze Rule and a State
then chooses to use EPA analysis to show that CAIR reductions from EGUs
meet BART requirements, States that achieve a portion of their CAIR
reductions from sources other than EGUs and wanting to show that even
with those reductions the EGUs will meet BART requirements must make a
supplemental demonstration that BART requirements are satisfied.
b. Eligibility of Non-EGU Reductions
In the CAIR SNPR, EPA proposed that, in evaluating whether
emissions reductions from non-EGUs would count towards the emissions
reductions required under the CAIR, States may only include reductions
attributable to measures that are not otherwise required under the CAA.
Specifically, EPA proposed that States must exclude non-EGU reductions
attributable to measures otherwise required by the CAA, including: (1)
Measures required by rules already in place at the date of promulgation
of today's final rule, such as adopted State rules, SIP revisions
approved by EPA, and settlement agreements; (2) measures adopted and
implemented by EPA (or other Federal agencies) such as emissions
reductions required pursuant to the Federal Motor Vehicle Control
Program for mobile sources (vehicles or engines) or mobile source
fuels, or pursuant to the requirements for National Emissions Standards
for Hazardous Air Pollutants; and (3) specific measures which are
mandated under the CAA (which may have been further defined by EPA
rulemaking) based on the classification of an area which has been
designated nonattainment for a NAAQS, such as vehicle inspection and
maintenance programs.
In discussing this proposal, EPA noted that States required to make
CAIR SIP submittals may also be required to make separate SIP
submittals to meet other requirements applicable to non-EGUs, e.g.,
nonattainment SIPs required for areas designated nonattainment under
the PM_2.5 or 8-hour ozone NAAQS or regional haze SIPs. The
EPA noted it is likely that CAIR SIP submittals will be due before or
at the same time as some of these other SIP submittals. We therefore
proposed that States relying on reductions from controls on non-EGUs
must commit in the CAIR SIP revisions to replace the emissions
reductions attributable to any CAIR SIP measure if that measure is
subsequently determined to be required to meet any other SIP requirement.
Some commenters objected to the proposed exclusion of credit for
measures which are mandated under the CAA based on the classification
of an area which has been designated nonattainment for a NAAQS, as well
as to the proposed requirement that such measures must be replaced if
they are later determined to be required in meeting separate SIP
requirements. These commenters reasoned that such a requirement would
not be applied to EGUs and would impose unnecessary and costly burdens
on non-EGUs, thus creating an incentive for States to avoid controlling
non-EGUs and to impose all CAIR reduction requirements on EGUs. One
commenter further objected that, as long as a measure was not included
in the base case EPA used to determine a State's contribution to other
States' nonattainment under CAA section 110(a)(2)(D), there is no
justification for excluding CAIR credit for such measure, and that
EPA's proposed exclusion of credit for any measure ``otherwise required
by the CAA'' is inconsistent with the NO_X SIP Call.
In response to these comments, EPA agrees that it is not
appropriate to apply this proposed restriction inconsistently to EGUs
and non-EGUs. Thus, EPA is adopting a modified form of the proposed
criteria for the eligibility of non-EGU emissions reductions,
eliminating the requirement that States must exclude non-EGU reductions
attributable to measures otherwise required by the CAA based on the
classification of an area which has been designated nonattainment for a
NAAQS. Consequently, the final rule allows credit for measures that a
State later adopts in response to requirements which result from an
area's nonattainment classification, such as reasonably available
control technology (RACT). With this change, all emissions reductions
are eligible for credit in meeting CAIR except: (1) Measures adopted or
implemented by the State as of the date of promulgation of today's
final rule, such as adopted State rules, SIP revisions approved by EPA,
and settlement agreements; and (2) measures adopted or implemented by
the Federal government (e.g., EPA or other Federal agencies) as of the
date of submission of the SIP revision by the State to EPA, such as
emissions reductions required pursuant to the Federal Motor Vehicle
Control Program for mobile sources (vehicles or engines) or mobile
source fuels, or pursuant to the requirements for National Emissions
Standards for Hazardous Air Pollutants.
This exclusion of credit is consistent with EPA's approach in the
NO_X SIP Call, although a direct comparison of the
creditability requirements in the CAIR and in the NO_X SIP
Call is not possible due to the timing and context in which both rules
were developed. The NO_X SIP Call used statewide budgets for
all sources as an accounting tool to determine the adequacy of a
strategy, while the CAIR takes a different approach in which baseline
emission inventories for non-EGU sectors will, if needed, be developed
later. The NO_X SIP Call did, as does the CAIR, restrict
States from taking credit for any Federal measures adopted after
promulgation of the rule (63 FR 57427-28). It also did not allow credit
for already adopted measures, but the timing of the NO_X SIP
Call was such that nonattainment planning measures would have already
likely been adopted as the SIP deadlines for adoption of such measures
had passed. In today's action, nonattainment planning measures adopted
after the promulgation of today's rule will be allowed credit under CAIR.
In order to take credit for CAIR reductions from non-EGUs, the
reductions must be beyond what is required under the NO_X SIP
Call. That is, a reduction must be in the non-ozone season or it must
be beyond what is expected in the ozone season. Non-ozone season
reductions must also be beyond what is in the base case, particularly
for units that have low NO_X burners and certain SCRs (e.g.,
ones required to be run annually). The reductions must be in addition
to those already expected. If ozone season reductions are considered,
the non-EGU NO_X SIP Call trading budget must be adjusted by
the increment of CAIR reductions beyond the levels in the
NO_X SIP Call. This removes the corresponding allowances from
the market and ensures that the emissions do not shift to other sources.
After evaluating the eligibility of non-EGU reductions in
accordance with the requirements discussed here, States must exclude
credit for ineligible

[[Continued on page 25261]]

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