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. 25261-25310]]

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 25261-25310]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12my05-18]

[[pp. 25261-25310]]
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 25260]]
[[Page 25261]]

measures by (i) including such measures in both the baseline and
controlled emissions inventory cases, if they have already been
adopted; or (ii) excluding them from both the base and control
emissions inventory cases if they have not yet been adopted. (See
discussion later in this section regarding development of emissions
inventories and demonstration of non-EGU reductions.)
c. Emissions Controls and Monitoring
As noted in section VII.A.1., we modified the ``hybrid'' approach
described in the CAIR NPR as it applies to certain non-EGUs, and adopt
today the approach described in the CAIR SNPR. Specifically, for States
that choose to impose controls on large industrial boilers and
turbines, i.e., those whose maximum design heat input is greater than
250 mmBtu/hr, to meet part or all of their emissions reductions
requirements under the CAIR, State rules must include an emissions cap
on all such sources in their State. Additionally, in this situation,
States must require those large industrial boilers and turbines to meet
part 75 requirements for monitoring and reporting emissions as well as
recordkeeping. This ensures consistency in measurement and certainty of
reductions and has been proven technologically and economically
feasible in other programs.
If a State chooses to control non-EGUs other than large industrial
boilers and turbines to obtain the required emissions reductions, the
State must either (i) impose the same requirements, i.e., an emissions
cap on total emissions from non-EGUs in the source category in the
State and part 75 monitoring, reporting and recordkeeping requirements;
or (ii) demonstrate why such requirements are not practicable. In the
latter case, the State must adopt appropriate alternative requirements
to ensure that emissions reductions are being achieved using methods
that quantify those emissions reductions, to the extent practicable,
with the same degree of assurance that reductions are being quantified
for EGUs and non-EGU boilers and turbines using part 75 monitoring.
This is to ensure that, regardless of how a State chooses to meet the
CAIR emissions reduction requirements, all reductions made by States to
comply with the CAIR have the same, high level of certainty as that
achieved through the cap and trade approach. Further, if a State adopts
alternative requirements that do not apply to all non-EGUs in a
particular source category (defined to include all sources where any
aspect of production of one or more such sources is reasonably
interchangeable with that of one or more other such sources), the State
must demonstrate that it has analyzed the potential for shifts in
production from the regulated sources to unregulated or less
stringently regulated sources in the same State as well as in other
States and that the State is not including reductions attributable to
sources that may shift emissions to such unregulated or less regulated
sources.
d. Emissions Inventories and Demonstrating Reductions
To quantify emissions reductions attributable to controls on non-
EGUs, the States must submit both baseline and projected control
emissions inventories for the applicable implementation years. We have
issued many guidance documents and tools for preparing such emissions
inventories, some of which apply to specific sectors States may choose
to control.\110\ While much of that guidance is applicable to today's
rulemaking, there are some key differences between quantification of
emissions reduction requirements under a SIP designed to help achieve
attainment with a NAAQS and emissions reduction requirements under a
SIP designed to reduce emissions that contribute significantly to a
downwind State's nonattainment problem or interfere with maintenance in
a downwind State. Because States are taking actions as a result of
their impact on other States, and because the impacted States have no
authority to reduce emissions from other States, the emissions
reduction estimates become even more important. (For a complete
discussion, see 69 FR 32693; June 10, 2004.)
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\110\ The many EPA guidance documents and tools for preparing
emission inventory estimates for SO₂ and NO_X
are available at the following Web sites:
http://www.epa.gov/ttn/chief/net/general.html,
http://www.epa.gov/ttn/chief/eiip/techreport/,
http://www.epa.gov/ttn/chief/publications.html#general,
http://www.epa.gov/ttn/chief/software/index.html,
and http://www.epa.gov/ttn/chief/efinformation.html
Specifically, when we review CAIR SIPs for approvability, we intend
to review closely the emissions inventory projections for non-EGUs to
evaluate whether emissions reduction estimates are correct. We intend
to review the accuracy of baseline historical emissions for the subject
sources, assumptions regarding activity and emissions growth between
the baseline year and 2010 \111\ and 2015, and assumptions about the
effectiveness of control measures.
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\111\ The 2010 modeling date is relevant for both SO₂
and NO_X even though NO_X requirements begin in
2009. See Section IV for discussion.
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Before describing the specific steps involved in this
quantification process, EPA notes that a few commenters objected to the
proposed requirements as arbitrary restrictions intended to discourage
States' discretion in imposing control measures on non-EGUs since these
requirements would use what the commenters describe as extremely
conservative emissions baseline and emissions reduction estimates. No
commenter refuted EPA's explanation, noted above, of the need for
stringent requirements to ensure greater accuracy of emission
inventories and greater certainty of reduction estimates used in SIPs
addressing transported pollutants. The EPA maintains that the need for
more accurate inventories and more certain reduction estimates
justifies the requirements discussed below. Further, no commenter
provided an alternate method of addressing EPA's concerns about the
development of such inventories and reduction estimates. Thus, EPA is
finalizing its proposed approach.
i. Historical Baseline
To quantify non-EGU reductions, as the first step, a historical
baseline must be established for emissions of SO₂ or
NO_X from the non-EGU source(s) in a recent year. The
historical baseline inventory should represent actual emissions from
the sources prior to the application of the controls. We expect that
States will choose a representative year (or average of several years)
during 2002-2005 for this purpose.
The requirements for estimating the historical baseline inventory
that follow reflect EPA's view that, when States assign emissions
reductions to non-EGU sources, achievement of those reductions should
carry a high degree of certainty, just as EGU reductions can be
quantified with a high degree of certainty in accordance with the
applicable part 75 monitoring requirements. Because the non-EGU
emissions reductions are estimated by subtracting controlled emissions
from a projected baseline, if the historical baseline overestimates
actual emissions, the estimated reductions could be higher than the
actual reductions achieved.
For non-EGU sources that are subject to part 75 monitoring
requirements, historical baselines must be derived from actual
emissions obtained from part 75 monitored data. For non-EGU sources
that do not have part 75 monitoring data, historical baselines must be
established that estimate actual

[[Page 25262]]

emissions in a way that matches or approaches as closely as possible
the certainty provided by the part 75 measured data for EGUs. For these
sources, States must estimate historical baseline emissions using
source-specific or category-specific data and assumptions that ensure a
source's or source category's actual emissions are not overestimated.
To determine the baseline for sources that do not have part 75
measured data, States must use emission factors that ensure that
emissions are not overestimated (e.g., emission factors at the low end
of a range when EPA guidance presents a range) or the State must
provide additional information that shows with reasonable confidence
that another value is more appropriate for estimating actual emissions.
Other monitoring or stack testing data can be considered, but care must
be taken not to overestimate baselines. If a production or utilization
factor is part of the historical baseline emissions calculation, a
factor that ensures that emissions are not overestimated must be used,
or additional data must be provided. Similarly, if a control or rule
effectiveness factor enters into the estimate of historical baseline
emissions, such a factor must be realistic and supported by facts or
analysis. For these factors, a high value (closer to 100 percent
control and effectiveness) ensures that emissions are not overestimated.
ii. Projections of 2010 and 2015 Baselines
The second step in quantifying SO₂ or NO_X
emissions reductions for non-EGUs is to use the historical baseline
emissions and project emissions that would be expected in 2010 and 2015
without the CAIR. This step results in the 2010 and 2015 baseline
emissions estimates.
The EPA proposed and requested comment on two procedures for
estimating the future baselines: one relies on projections based on a
number of estimated parameters; the second uses the lower of this
projection and actual historical emissions. Today, EPA finalizes the
second approach for determining 2010 and 2015 emissions baselines.
To estimate future emissions, States must use state-of-the-art
methods for projecting the source or source category's economic output.
Economic and population forecasts must be as specific as possible to
the applicable industry, State, and county of the source and must be
consistent with both national projections and relevant official
planning assumptions, including estimates of population and vehicle
miles traveled developed through consultation between State and local
transportation and air quality agencies. However, if these official
planning assumptions are themselves inconsistent with official U.S.
Census projections of population or with energy consumption projections
contained in the most recent Annual Energy Outlook published by the
U.S. Department of Energy, then adjustments must be made to correct the
inconsistency, or the SIP must demonstrate how the official planning
assumptions are more accurate. If the State expects changes in
production method, materials, fuels, or efficiency to occur between the
baseline year and 2010 or 2015, the State must account for these
changes in the projected 2010 and 2015 baseline emissions. For example,
if a source has publicly announced a change or applied for a permit for
a change, it should be reflected in the projections. The projection
must also reflect any adopted regulations that are ineligible control
measures and that will affect source emissions.
As stated above, EPA is requiring States to use the lower of
historical baseline emissions or projected 2010 or 2015 emissions, as
applicable, for a source category. This is because changes in
production method, materials, fuels, or efficiency often play a key
role in changes in emissions. Because of factors such as these,
emissions can often stay the same or even decrease as productivity
within a sector increases. These factors that contribute to emission
decreases can be very difficult to quantify. Underestimating the impact
of these types of factors can very easily result in a projection for
increased emissions within a sector, when a correct estimate will
result in a projection for decreased emissions within the sector. A few
commenters opposed this methodology as arbitrary but failed to explain
why EPA's concerns, as described above, are not valid. Commenters also
failed to propose other methodologies for addressing these concerns.
Thus, EPA is finalizing the use of this second methodology.
iii. Controlled Emissions Estimates for 2010 and 2015
The third step is to develop the 2010 and 2015 controlled emissions
estimates by assuming the same changes in economic output and other
factors listed above but adding the effects of the new controls adopted
for the purpose of meeting the CAIR. The controls may take the form of
regulatory requirements, e.g., emissions caps, emission rate limits,
technology requirements, or work practice requirements. The State's
estimate of the effect of the control regulations must be realistic in
light of the specific provisions for monitoring, reporting, and
enforcement and experience with similar regulatory approaches.
In addition, the State's analysis must examine the possibility that
the controls may cause production and emissions to shift to unregulated
or less stringently regulated sources in the same State or another
State. If all sources of a source category (defined to include all
sources where any aspect of production is reasonably interchangeable)
within the State are regulated with the same stringency and compliance
assurance provisions, the analysis of production and emissions shifts
need only consider the possibility of shifts to other States. If only a
portion of a source category within a State is regulated, the analysis
must also include any in-State shifting. In estimating controlled
emissions in 2010 and 2015, assumptions regarding control measures that
are not eligible for CAIR reduction credit must be the same as in the
2010 and 2015 baseline estimates. For example, a State may not take
credit for reductions in the sulfur content of nonroad diesel fuel that
are required under the recent Federal nonroad fuel rule (69 FR 38958;
June 29, 2004). By including the effect of this Federal rule in both
the baseline and controlled emissions estimates for 2010 and 2015, the
State will appropriately exclude this ineligible reduction when it
subtracts the controlled emissions estimates from the baseline
emissions estimates.
The method that we are adopting today specifies the 2010 and 2015
emissions reductions which can be counted toward satisfying the CAIR.
The method requires the use of the historical baseline or the baseline
emission estimates, whichever is lower. That is, the reduction is
calculated as follows: (i) For 2010, the difference between the lower
of historical baseline or 2010 baseline emissions estimates and the
2010 controlled emissions estimates, minus any emissions that may shift
to other sources rather than be eliminated; and (ii) for 2015, the
difference between the lower of historical baseline or 2015 baseline
emissions estimates and the 2015 controlled emissions estimates, minus
any emissions that may shift to other sources rather than be eliminated.
4. Controls on Non-EGUs Only
Although we stated that we believe it is unlikely States may choose
to control only non-EGUs, we proposed in the CAIR SNPR provisions for
determining

[[Page 25263]]

the specified emissions reductions that must be obtained if States
pursue this alternative, and we adopt those provisions today. The
reason we think it is unlikely is based on States' emissions profiles.
Most SO₂ emissions are from EGUs and therefore it is
unlikely that a State can achieve the required emissions reductions
without regulating EGUs to some degree. In addition, SO₂
emissions reductions from EGUs are highly cost effective. States that
choose this path must ensure that the amount of non-EGU reductions is
equivalent to all of the emissions reductions that would have been
required from EGUs had the State chosen to assign all the emissions
reductions to EGUs. For SO₂ emissions, this amount in 2010
would be 50 percent of a State's title IV SO₂ allocations
for all units in the State and, for 2015, 65 percent of such
allocations. For NO_X emissions, this amount would be the
difference between a State's EGU budget for NO_X under the
CAIR and its NO_X baseline EGU emissions inventory as
projected in the Integrated Planning Model (IPM) for 2010 and 2015,
respectively.\112\
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\112\ See ``Technical Support Document for the Clean Air
Interstate Rule Notice of Final Rulemaking; Regional and State
SO₂ and NO_X Emissions Budgets'' for tables
containing information to calculate these amounts for both
SO₂ and NO_X.
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In addition, the same requirements described elsewhere in this part
of today's preamble regarding the eligibility of non-EGU reductions,
emissions control and monitoring, emissions inventories and
demonstration of reductions, will apply to the situation where a State
chooses to control only non-EGUs.
5. Use of Banked Allowances and the Compliance Supplement Pool
In the CAIR NPR, EPA stated that States may allow EGUs to
demonstrate compliance with the State EGU SO₂ budget by
using title IV allowances (i) that were banked, or (ii) that were
obtained in the current year from sources in other States (69 FR 4627).
The EPA adopts this provision in today's action. The EPA adopts a
similar provision for the use of banked NO_X SIP Call
allowances (pre-2009) to demonstrate compliance with the State EGU
ozone season NO_X budget. See also the CAIR NPR (69 FR 4633).
Therefore, State rules may allow the use of pre-2010 title IV and pre-
2009 NO_X SIP Call allowances banked in the title IV and
NO_X SIP Call trading programs for compliance in the CAIR.
States participating in the EPA-administered CAIR trading programs must
allow the use of these pre-2010 title IV allowances or pre-2009
NO_X SIP Call allowances in accordance with EPA's model
trading rules.
Additionally, States with annual NO_X reduction
requirements may use compliance supplement pool (CSP) allowances as
described in sections V and VIII. Distribution of the CSP is
essentially the same as the process used in the NO_X SIP
Call, through one or both of two mechanisms. States may distribute CSP
allowances on a pro-rata basis to sources that implement NO_X
control measures resulting in reductions in 2007 or 2008 that are
beyond what is required by any applicable State or Federal emissions
limitation (early reductions). The second CSP distribution mechanism
that a State can use is to issue CSP allowances based on the
demonstration of a need for an extension of the 2009 deadline for
implementing emission controls. The demonstration must show
unacceptable risk either to a source's own operation or its associated
industry--for EGUs, power supply reliability, for non-EGUs risk
comparable to that described for the electricity industry. See also 63
FR 57356 for further discussion of these points.
Pre-2010 title IV SO₂ allowances, pre-2009
NO_X SIP Call allowances and CAIR annual NO_X CSP
allowances can all be counted toward a States efforts to achieve its
CAIR reduction obligations regardless of whether the CAIR trading
programs are used or not.

B. State Implementation Plan Schedules

1. State Implementation Plan Submission Schedule
In the NPR, we proposed to require States to submit SIPs to address
interstate transport in accordance with the provisions of this rule
approximately 18 months from the date of this final rule (69 FR 4624).
After careful consideration of the comments we received concerning this
issue, we have concluded that States should submit SIPs to satisfy this
final rule as expeditiously as possible, but no later than 18 months
from the date of today's action. Under this schedule, upwind States'
transport SIPs to meet CAA section 110(a)(2)(D) will be due before the
downwind States' PM_2.5 and 8-hour ozone nonattainment area
SIPs under CAA section 172(b). We expect that the downwind States' 8-
hour ozone nonattainment area SIPs will be due by June 15, 2007, and
their PM_2.5 nonattainment SIPs will be due by April 5,
2008.\113\
---------------------------------------------------------------------------

\113\ By statute, the date for submission of nonattainment area
SIPs is to be no later than 3 years from the date of nonattainment
designation. Section 172(b).
---------------------------------------------------------------------------

We believe that this sequence for SIP submissions to address upwind
interstate transport and downwind nonattainment areas is consistent
both with the applicable provisions of the CAA and with sound policy
objectives. The CAA provides for this sequence of submissions in
section 110(a)(1) and (a)(2), which provide that the submittal period
for SIPs required by section 110(a)(2)(D) runs from the earlier date of
the NAAQS revision, and in section 172(b), which provides that the
submittal period for the nonattainment area SIPs runs from the later
date of designation. Clean Air Act section 110(a)(1) requires each
State to submit a SIP to EPA ``within 3 years * * * after the
promulgation of a [NAAQS]
(or any revision thereof).'' Section
110(a)(2) makes clear that this SIP must include, among other things,
provisions to address the requirements of section 110(a)(2)(D). We read
these provisions together to require that each upwind State must
submit, within 3 years of a new or revised NAAQS, SIPs that address the
section 110(a)(2)(D) requirement. By contrast, the schedule provided in
section 172(b) is only applicable to the nonattainment area SIP
requirements.
Section 110(a) imposes the obligation upon States to make a
submission, but the contents of that submission may vary depending on
the facts and circumstances. In particular, the data and analytical
tools available at the time the section 110(a)(2)(D) SIP is developed
and submitted to EPA necessarily affect the content of the submission.
Where, as here, the data and analytical tools to identify a significant
contribution from upwind States to nonattainment areas in downwind
States are available, the State's SIP submission must address the
existence of the contribution and the emission reductions necessary to
eliminate the significant contribution. In other circumstances,
however, the tools and information may not be available. In such
circumstances, the section 110(a)(2)(D) SIP submission should indicate
that the necessary information is not available at the time the
submission is made or that, based on the information available, the
State believes that no significant contribution to downwind
nonattainment exists. EPA can always act at a later time after the
initial section 110(a)(2)(D) submissions to issue a SIP call under
section 110(k)(5) to States to revise their SIPs to provide for
additional emission controls to satisfy the section 110(a)(2)(D)
obligations if such action were

[[Page 25264]]

warranted based upon subsequently-available data and analyses. This is
precisely the circumstance that was presented at the time of the
NO_X SIP Call in 1998 when EPA issued a section 110(k)(5) SIP
call to states regarding their section 110(a)(2)(D) obligations on the
basis of new information that was developed years after the States'
SIPs had been previously approved as satisfying section 110(a)(2)(D)
without providing for additional controls since the information
available at the earlier point in time did not indicate the need for
such additional controls.
Not only is this sequencing consistent with the CAA, it is
consistent with sound policy considerations. The upwind reductions
required by today's action will facilitate attainment planning by the
States affected by transport downwind. Rather than being ``premature''
as some commenters suggested, EPA's understanding of the data and
models leads the Agency to believe that requiring the States to address
the upwind transport contribution to downwind nonattainment earlier in
the process as a first step is a reasonable approach and is fully
consistent with the statutory structure. This approach will allow
downwind States to develop SIPs that address their share of emissions
with knowledge of what measures upwind States will have adopted. In
addition, most of the downwind States that will benefit by today's
rulemaking are themselves significant contributors to violations of the
standards further downwind and, thus, are subject to the same
requirements as the States further upwind. The reductions these
downwind States must implement due to their additional role as upwind
States will help reduce their own PM_2.5 and 8-hour ozone
problems on the same schedule as emissions reductions for the upwind
States. We believe that providing 18 months from the date of today's
action for States to submit the transport SIPs required by this rule is
appropriate and reasonable, for the reasons discussed more fully below.
a. The EPA's Authority To Require Section 110(a)(2)(D) Submissions in
Accordance With the Schedule of Section 110(a)(1)
A number of commenters objected to EPA's proposal to require States
to submit the transport SIPs on the schedule set forth in section
110(a)(1). The commenters argued that section 110(a)(1) does not apply
to the requirements of section 110(a)(2)(D), because the former refers
to plans that States must adopt ``to implement, maintain, and enforce''
the NAAQS ``within'' the State, whereas the latter refers to plans that
prevent emissions that affect nonattainment or maintenance of the NAAQS
in places outside the State. According to the commenters, because
section 110(a)(1) SIPs purportedly need not address the interstate
transport issues governed by section 110(a)(2)(D), the States have no
current obligation to prevent such interstate transport and, by
extension, there is no basis for the CAIR at this time.
The EPA disagrees with the commenters. A State's SIP must of course
provide for ``implementation, maintenance, and enforcement'' of the
NAAQS ``within'' the State because States lack authority to impose
requirements on sources in other States; i.e., any plan submitted by a
State will necessarily be applicable to sources ``within'' that State.
The CAA, however, also requires that such SIPs must be submitted to EPA
no later than three years after promulgation of a new or revised NAAQS
and must contain adequate provisions regarding interstate transport
from emission sources within the State in compliance with section
110(a)(2)(D). The explicit terms of the statute provide for the State
submission of initial SIPs after promulgation of a new NAAQS, and
provide that such SIPs should address interstate transport. Section
110(a)(1) provides that:

[e]ach State shall * * * adopt and submit to the Administrator,
within 3 years (or such shorter period as the Administrator may
prescribe) after the promulgation of a national primary ambient air
quality standard (or any revision thereof) * * * a plan which
provides for implementation, maintenance, and enforcement of such
primary standard in each [area]
within such State.

Section 110(a)(2) provides, in relevant part, that:

[e]ach implementation plan submitted by a State under this Act shall
be adopted by the State after reasonable notice and public hearing.
Each such plan shall * * * (D) contain adequate provisions--(i)
prohibiting * * * any source or other type of emissions activity
within the State from emitting any air pollutant in amounts which
will--(I) contribute significantly to nonattainment in, or interfere
with maintenance by, any other State with respect to [the NAAQS].

By referencing each implementation plan in section 110(a)(2), it is
clear that the implementation plans required under section 110(a)(1)
must satisfy the requirements of section 110(a)(2)(D). Thus, the plain
meaning of these provisions, read together, is that SIP submissions are
required within 3 years of promulgation of a new or revised NAAQS, and
that the SIP submissions must meet the requirements of section 110(a)(2)(D).
By contrast, other requirements of section 110(a)(2) are not
triggered by EPA's promulgation of a new or revised NAAQS, but rather
by EPA's final designation of nonattainment areas. For example, section
110(a)(2)(I) by its terms indicates that State SIPs must meet that
requirement not on the schedule of section 110(a)(1), but instead on
the schedule of section 172(b).
The explicit distinction in the statute between requirements that
States must meet on the schedule of section 110(a)(1) versus the
schedule of section 172(b) reinforces the conclusion that States are to
meet the initial requirements of section 110(a)(2)(D) within the
schedule of section 110(a)(1).
In this context, it is important to note that the requirements of
section 110(a)(1) plans are not limited to areas designated attainment,
nonattainment, or unclassifiable.\114\ Section 110(a)(1) requires each
State to develop and submit a plan that provides for the
implementation, maintenance, and enforcement of the NAAQS in ``each''
area of the State. Similarly, the requirement in section 110(a)(2)(D)
that SIPs must prohibit interstate transport of air pollutants that
significantly contribute to downwind nonattainment is not limited to
any particular category of formally designated areas in the State. The
provisions apply to emissions activities that occur anywhere in a
state, regardless of its designation. If, as the commenters suggested,
the requirements of section 110(a)(2)(D) plans are governed not by
section 110(a)(1), but rather by the schedule of section 172, that
would lead to the absurd result that upwind States need only reduce
emissions from designated nonattainment areas to prevent significant
contribution to nonattainment or interference with maintenance in a
downwind State. Given that large portions of many upwind States may be
designated as attainment for the NAAQS for local purposes, yet still
contain large sources of emissions that affect downwind States through
interstate transport, EPA believes that Congress could not have
intended the prohibitions of section 110(a)(2)(D) to apply only to
nonattainment areas in upwind States.\115\ Indeed, the language of

[[Page 25265]]

section 110(a)(2) itself does not support such an interpretation.
Therefore, the alternative schedule provided in section 172(b)
applicable only to nonattainment areas cannot be the schedule that
governs the State submission of transport SIPs. This leaves the
schedule of section 110(a)(1) as the only appropriate schedule in the
case of SIPs following EPA promulgation of new or revised NAAQS.
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\114\ Under section 107(d), EPA is required to identify all
areas of each State as falling into one of these three categories.
\115\ The EPA notes that under the provisions of section 107(d),
certain portions of an upwind State that are monitoring attainment
may be designated nonattainment because they contribute to
violations of the NAAQS in a ``nearby'' area. Nevertheless, there
will be portions of upwind States that include emissions sources
that are not in designated nonattainment areas, whether because of
local monitored nonattainment, or because of contribution to a
nearby nonattainment area, yet these portions of the upwind State
may contain sources that cause emissions that States must address to
meet the requirements of section 110(a)(2)(D).
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The commenters also disputed that the schedule of section 110(a)(1)
applies to the section 110(a)(2)(D) requirement because there are other
elements of section 110(a)(2) that States could not meet on that
schedule. As an example, the commenters pointed to section 110(a)(2)(I)
which requires States to meet certain obligations imposed upon
designated nonattainment areas. As formal designation under the
generally applicable provisions of section 107(d) could take up to 3
years following promulgation of a new or revised NAAQS, and section
172(b) allows up to 3 additional years for State submission of
nonattainment area SIPs, the commenters concluded that States could not
meet section 110(a)(2)(I) on the schedule of section 110(a)(1). From
the fact that States could not meet all of the elements of the section
110(a)(2) requirement within 3 years, the commenters inferred that EPA
cannot require States to meet any of the requirements in section
110(a)(2), including section 110(a)(2)(D).
The EPA disagrees with the commenters' approach to the
interpretation of the statute. The EPA agrees that there are certain
provisions of section 110(a)(2) that are governed not by the schedule
of section 110(a)(1), but instead by the timing requirement of section
172(b), e.g., section 110(a)(2)(I). Other items in section 110(a)(2),
however, do not depend upon prior designations in order for States to
develop a SIP to begin to comply with them, e.g., section 110(a)(2)(B)
(pertaining to monitoring); section 110(a)(2)(E) (stipulating that
States must provide for adequate resources); and section 110(a)(2)(K)
(pertaining to modeling).
Most important, section 110(a)(2)(D) itself does not apply only to
impacts on downwind nonattainment areas, and thus does not presuppose
prior designations in either upwind or downwind States, or suggest that
section 110(a)(2)(D) is somehow inapplicable until the submission of
nonattainment area plans. By its explicit terms, section 110(a)(2)(D)
requires States to prohibit emissions from ``any source or other types
of emissions activity within the State'' that ``contribute to
nonattainment in, or interfere with maintenance by'' any other State. A
plain reading of the statute indicates that the emissions at issue can
emanate from any portion of an upwind State and that the impacts of
concern can occur in any portion of the downwind State.
While EPA agrees that there is overlap between the submission
requirements of sections 110(a)(1) and (a)(2) and section 172(c), EPA
believes that the plain language of these sections requires States to
submit plans that comply with section 110(a)(2)(D) prior to the
deadline for nonattainment area SIPs established by section 172, and
that there is nothing that compels a contrary conclusion in the
language of section 172. Section 172(b) provides that State plans for
nonattainment areas must meet ``the applicable requirements of [section
172(c)]
and section 110(a)(2)'' (emphasis added). Thus, the statute
itself explicitly indicates that the State submissions for
nonattainment plans must meet those requirements of section 110(a)(2)
that are ``applicable,'' not each requirement regardless of
applicability. In the current situation, EPA believes that it is
appropriate to view the CAA as requiring States to make a submission to
meet the requirement of section 110(a)(2)(D) in accordance with the
schedule of section 110(a)(1), rather than under the schedule for
nonattainment SIPs in section 172(b).\116\
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\116\ As noted earlier, what will be needed to meet section
110(a)(2) may vary, depending upon the specific facts and
circumstances surrounding a new or revised NAAQS. See, e.g.,
Proposed Requirements for Implementation Plans and Ambient Air
Quality Surveillance for Sulfur Oxides (Sulfur Dioxide) National
Ambient Air Quality Standard, 60 FR 12492, 12505 (March 7, 1995). In
the context of a proposed 5-minute NAAQS for S0₂, EPA
tentatively concluded that existing SIP provisions for the 24-hour
and annual S0₂ NAAQS were probably sufficient to meet
many elements of section 110(a)(2). The EPA did not explicitly
discuss State obligations under section 110(a)(2)(D) for the 5-
minute NAAQS in the proposal, but the nature of the pollutant, the
sources, and the proposed NAAQS are such that interstate transport
would not have been the critical regionwide concern that it is for
the PM_2.5 and 8-hour ozone NAAQS. The EPA does not expect
States to make SIP submissions establishing emission controls for
the purpose of addressing interstate transport without having
adequate information available to them.
---------------------------------------------------------------------------

b. The EPA's Authority To Require Section 110(a)(2)(D) Submissions
Prior to Formal Designation of Nonattainment Areas Under Section 107
A number of commenters argued that EPA has no authority to require
States to comply with section 110(a)(2)(D) until after EPA formally
designates nonattainment areas for the PM_2.5 and 8-hour
ozone NAAQS.\117\ These commenters claimed that section 107(d) and
provisions of the Transportation Equity Act for the 21st Century (TEA-
21) governing the designation of PM_2.5 and 8-hour ozone
nonattainment areas preclude EPA from interpreting the CAA to require
States to submit SIPs that comply with section 110(a)(2)(D) on the
schedule contemplated by section 110(a)(1). In the view of the
commenters, EPA could not reasonably expect States to determine whether
and to what extent their in-State sources significantly contributed to
nonattainment in other States within the initial 3-year timeframe, in
advance of nonattainment area designations. According to the
commenters, section 107(d) and TEA-21 negate the timing requirements of
section 110(a)(1), so that States have no current obligation to address
interstate transport and thus there is no basis for today's action.
---------------------------------------------------------------------------

\117\ The EPA notes that the 8-hour ozone designations became
effective on June 15, 2004, and that the PM_2.5
designations will become effective on April 5, 2005. The EPA
believes that the issue raised by the commenters is thus moot with
respect to both the 8-hour ozone and PM_2.5 nonattainment
areas because those designations are now complete.
---------------------------------------------------------------------------

The EPA disagrees with the commenters' view of the interaction of
section 110 and section 107(d). The statute does not require EPA to
have completed the designations process before the Agency or a State
could assess the existence of, or extent of, significant contribution
from one State to another. In addition, the technical approach by which
EPA determines significant contribution from upwind to downwind States
does not depend upon the prior completion of the designation process.
The EPA believes that the statute does not compel the conclusion
that States may postpone compliance with section 110(a)(2)(D) until
some future point after completion of the designation process. As
discussed above, a reading of the plain language of sections 110(a)(1)
and 110(a)(2) indicates that States must adopt and submit a plan to EPA
within 3 years after promulgation of a new or revised NAAQS (the same
time at which designations are generally due under section 107), and
that each

[[Page 25266]]

such plan must meet the applicable requirements of section
110(a)(2)(D).\118\
---------------------------------------------------------------------------

\118\ For reasons discussed in more detail above, EPA interprets
the requirement of section 110(a)(2)(D) to be among those that
Congress intended States to meet within the 3-year timeframe of
section 110(a)(1). The EPA agrees that other requirements, such as
those of section 110(a)(2)(I), are subject to the different timing
requirements of section 172(b).
---------------------------------------------------------------------------

Significantly, neither section 110(a)(1) nor section 110(a)(2)(D)
are limited to ``nonattainment'' areas. By their explicit terms, both
provisions apply to all areas within the State, regardless of whether
EPA has formally designated the areas as attainment, nonattainment, or
unclassifiable, pursuant to section 107(d). As to causes, section
110(a)(2)(D) compels States to address any ``emissions activity within
the State,'' not solely emissions from formally designated
nonattainment areas, nor does it in any other terms suggest that
designations of upwind areas must first have occurred. As to impacts,
section 110(a)(2)(D) refers only to prevention of ``nonattainment'' in
other States, not to prevention of nonattainment in designated
nonattainment areas or any similar formulation requiring that
designations for downwind nonattainment areas must first have occurred.
By comparison, other provisions of the CAA do clearly indicate when
they are applicable to designated nonattainment areas, rather than
simply to nonattainment more generally (e.g., sections 107(d)(1)(A)(i),
181(b)(2)(A), and 211(k)(10)(D)). Because section 110(a)(2)(D) refers
only to ``nonattainment,'' not to ``nonattainment areas,'' EPA
concludes that the section does not presuppose the existence of
formally designated nonattainment areas, but rather to ambient air
quality that does not attain the NAAQS.
The EPA believes that this plain reading of the provisions is also
the most logical approach. A reading that section 110(a)(2)(D) means
that States have no obligation to address interstate transport unless
and until there are formally designated nonattainment areas pursuant to
section 107 would be inconsistent with the larger goal of the CAA to
encourage expeditious attainment of the NAAQS. In this immediate
instance, currently available air quality monitoring data and modeling
make it clear that many areas of the eastern portion of the country are
in violation of both the PM_2.5 and 8-hour ozone NAAQS. Air
quality modeling studies generally available to the States demonstrate
that, and quantify the extent to which, SO₂ and
NO_X emissions from sources in upwind States are contributing
to violations of the PM_2.5 and 8-hour ozone NAAQS in
downwind States.
Following the example of the NO_X SIP Call, EPA has an
effective analytical approach to determine whether that interstate
contribution is significant, in accordance with section 110(a)(2)(D).
Thus, EPA currently has the information and tools that it needs to
determine what the initial PM_2.5 and 8-hour ozone SIPs from
upwind States should include as appropriate NO_X and
SO₂ emissions reductions in order to prevent emissions that
significantly contribute to nonattainment in downwind States. The
designation process under section 107 is the means by which States and
EPA decide the precise boundaries of the nonattainment areas in the
downwind States. Both PM_2.5 and ozone are regional
phenomena, however, and information as to the precise boundaries of
nonattainment areas is not necessary to implement the requirements of
section 110(a)(2)(D) for these pollutants. Consequently, it was not
necessary for EPA to wait until after completion of formal designation
of nonattainment area boundaries before undertaking this rulemaking.
Moreover, EPA believes that taking action now will achieve public
health protections more quickly as it will enable States to develop
implementation plans more expeditiously and efficiently.
The EPA disagrees with the commenters' view of the relationship
between section 110(a)(2) and section 107 and their apparent view of
the method by which EPA analyzes whether there is a contribution from
an upwind State to a downwind State, and whether that contribution is
significant.
The EPA has, in this case, used the detailed data from the
extensive network of air quality monitors to identify which States have
monitors that are currently showing violations of the PM_2.5
and 8-hour ozone NAAQS. In the NPR, EPA stated that based upon data for
the 3-year period from 2000-2002, ``120 counties with monitors exceed
the annual PM_2.5 NAAQS and 297 counties with monitor
readings exceed the 8-hour ozone NAAQS'' (69 FR 4566, 4581; January 30,
2004) (emphasis added). The geographic distribution of monitors with
data registering current violations indicated that there is
nonattainment of both the PM_2.5 and 8-hour ozone NAAQS
throughout the eastern United States and in other portions of the
country including California. For analyses of future ambient
conditions, EPA used various modeling tools to predict that, in the
absence of the CAIR, there would be counties with monitors that would
continue to show violations of the PM_2.5 and 8-hour ozone
NAAQS in 2010 and 2015. In subsequent steps, EPA analyzed whether the
emissions from upwind States contributed to the ambient conditions at
the monitors registering NAAQS violations in downwind States, and
thereafter determined whether that contribution would be significant
pursuant to section 110(a)(2)(D).
In none of these steps, however, did EPA need to know the precise
boundaries of the nonattainment areas that may ultimately result from
the section 107 designation process. The determination of attainment
status in a given county is based primarily upon the monitored ambient
measurements of the applicable pollutant in the county. Thus, it is the
readings at the monitors that are the appropriate information for EPA
to evaluate in assessing current and future interstate transport at
that monitor in that county, not the exact dimensions of the area that
may ultimately comprise the formally designated nonattainment area. The
ultimate size of nonattainment areas will have a bearing on other
components of the State's nonattainment area SIP. The size of such
nonattainment areas, however, is not meaningful in assessing whether
interstate transport from another State or States has an impact at a
violating monitor, and whether the transport significantly contributes
to nonattainment, that the other State or States should address to
comply with section 110(a)(2)(D). Thus, EPA believes that basing the
significant contribution analysis upon the counties with monitors that
register nonattainment, without regard to the precise boundaries of the
nonattainment areas that may ultimately result from the formal
designation process under section 107, is the proper approach.
For similar reasons, EPA also disagrees with the commenters'
assertion that the provisions of TEA-21 preclude EPA's interpretation
of the timing requirements of sections 110(a)(1) and 110(a)(2).
However, TEA-21 did address the need to create a new network of
monitors to assess the geographic scope and location of
PM_2.5 nonattainment. Also, TEA-21 did provide that such a
network should be up and running by December 31, 1999. TEA-21 did lay
out a schedule for the collection of data over a period of 3 years in
order to make subsequent regulatory decisions. From these facts, the
commenters concluded that TEA-21 necessarily contradicts EPA's position
that States must now take action to address significant contribution to
downwind nonattainment in their

[[Page 25267]]

initial section 110(a)(1) SIPs, merely because the initial 3-year
period following the promulgation of a new or revised NAAQS specified
in section 110(a)(1) has expired.
The EPA believes that nothing in TEA-21 explicitly or implicitly
altered the timing requirements of section 110(a)(1) for compliance
with section 110(a)(2)(D), although EPA recognizes that the data from
monitoring funded by that Act contributed to the Agency's development
of the SIP requirements in today's rulemaking. The provisions of TEA-21
pertained to the installation of a network of monitors for
PM_2.5, and to the timing of designation decisions for
PM_2.5 and 8-hour ozone. To be specific, TEA-21 had two
primary purposes for the new NAAQS: (1) To gather information ``for use
in the determination of area attainment or nonattainment designations''
for the PM_2.5 NAAQS; and (2) to ensure that States had
adequate time to consider guidance from EPA concerning ``drawing area
boundaries prior to submitting area designations'' for the 8-hour ozone
NAAQS. TEA-21 sections 6101(b)(1) and (2). The EPA interprets the third
stated purpose of TEA-21 to refer to ensuring consistency of timing
between the Regional Haze program requirements and the PM_2.5
NAAQS requirements. With respect to timing, TEA-21 similarly only
referred to the dates by which States and EPA should take their
respective actions concerning designations. For PM_2.5, TEA-
21 provided that States were required ``to submit designations referred
to in section 107(d)(1) * * * within 1 year after receipt of 3 years of
air quality monitoring data.'' TEA-21 section 6102(c)(1). For 8-hour
ozone, TEA-21 required States to submit designation recommendations
within 2 years after the promulgation of the new NAAQS, and required
EPA to make final designations within 1 year after that (TEA-21
sections 6103(a) and (b)). In all of these provisions, TEA-21 only
addresses SIP timing in the context of the designation process of
section 107(d). As explained in more detail above, EPA does not believe
that the timing of section 110(a)(1) and section 110(a)(2)(D)
obligations depend upon the prior designation of areas in accordance
with section 107(d).
The EPA also notes that legislation subsequent to TEA-21 further
supports this conclusion. In the 2004 Consolidated Appropriations Act,
Congress further amended section 107 to provide specific dates by which
States and EPA must make PM_2.5 designations. 42 U.S.C. 7407
note. The Act now requires States to have made their initial
recommendations for PM_2.5 designations by February 15, 2004,
and requires EPA to take action on those recommendations and make its
final designation decisions no later than December 31, 2004. Again,
these requirements pertain only to formal designations, and do not
directly affect the obligations of States to meet other SIP
requirements. Neither TEA-21 nor the 2004 Appropriations Act language
altered the section 110(a)(1) schedule for compliance with section
110(a)(2)(D).
The commenters suggested that because Congress provided more time
for making formal designations pursuant to section 107, it necessarily
follows that States should not have to meet the requirements of section
110(a)(2)(D) on the schedule of section 110(a)(1). The EPA believes
that Congress did not, through TEA-21 or other actions, alter the
existing submission schedule for SIPs to address interstate transport.
By contrast, Congress did explicitly alter the schedule for submission
of plan revisions to address Regional Haze. From this, EPA infers that
Congress did not intend EPA to delay action to address the issue of
interstate transport for the 8-hour or PM_2.5 NAAQS. Thus,
EPA must still ensure that States submit SIPs in accordance with the
substantive requirements of section 110(a)(2)(D). However, because EPA
and the States now have the data and analyses to establish the presence
and magnitude of interstate transport, in part through the monitoring
data gathered pursuant to TEA-21, the Agency believes that that it is
now appropriate to require States to address interstate transport at
this time in the manner set forth in today's rule.
c. The EPA's Authority To Require Section 110(a)(2)(D) Submissions
Prior to State Submission of Nonattainment Area Plans Under Section 172
Some commenters suggested that EPA cannot determine the existence
of a significant contribution from upwind States to downwind States
until EPA actually receives the nonattainment area SIPs from each State
and evaluates how much ``residual'' nonattainment remains. If the
reasoning of these commenters were adopted, downwind States would have
to construct SIPs to attain the NAAQS without first knowing what upwind
States might ultimately do to reduce interstate transport. Presumably,
the theory is that the downwind States may choose to control their own
local emissions sources more aggressively so that sources in upwind
States could avoid installation of highly cost-effective emission
controls, notwithstanding the continued significant impacts of
emissions from upwind sources on downwind States. Alternatively, the
rationale may be that EPA should wait until submission of upwind State
nonattainment area SIPs to discover whether and to what degree the SIPs
address interstate transport to downwind States.
For reasons already discussed more fully above, EPA does not
believe that the statute requires a ``wait and see'' approach to
discover what, if anything, States may ultimately do to address the
problem of regional interstate transport. Section 110(a)(1) requires
``each'' State to submit a SIP within 3 years after a new or revised
NAAQS addressing the requirements of section 110(a)(2)(D). When the
data and the analyses needed to establish the existence of interstate
transport of pollutants and to determine whether there is a significant
contribution to nonattainment or interference with maintenance by one
State in another State are available, as here after the monitoring
funded by TEA-21, EPA believes that it may act upon that information
prior to State SIP submissions to ensure that States address such
contribution expeditiously, as it is doing in this rulemaking. The EPA
believes it is a better policy to assist the States to address the
regional component of the nonattainment problem in a way that is
equitable, timely, cost effective, and certain.
The EPA acknowledges that historically, especially in the case of
1-hour ozone, the Agency has not had the data and the analytical tools
to help upwind States to address interstate transport as early in the
SIP process as it is doing today for PM_2.5 and 8-hour ozone.
The CAA has required States to regulate ozone or its regulatory
predecessors since 1970. For many years, States and EPA focused on the
adoption and implementation of local controls to bring local
nonattainment areas into attainment. Thus, historically, local areas
bore the burden of achieving attainment through imposition of control
measures on local sources. By comparison, upwind States did not have to
adopt local controls in attainment areas and typically did not adopt
such controls solely to lessen the impact of their emissions on
downwind States. Since 1977, the CAA has also imposed a series of local
control obligations on 1-hour ozone nonattainment areas, such as RACT
for stationary sources, inspection and maintenance for mobile sources,
and other requirements that became increasingly more stringent, based
upon the level of local nonattainment. In spite of these local control
efforts, there continued to be a

[[Page 25268]]

widespread problem with nonattainment that resulted, in part, from
unaddressed interstate transport. A lack of information and analytical
tools hindered the ability of EPA and the States to address the
regional interstate transport component of 1-hour ozone nonattainment,
until the NO_X SIP Call in 1998. While it is thus true that
the NO_X SIP Call postdated the submission of nonattainment
area SIPs, this should not be construed as evidence that the statute
precludes the States and EPA from addressing interstate transport
earlier in the process for the 8-hour ozone and PM_2.5 NAAQS.
Given that EPA and the States indisputably have the requisite
information to identify interstate transport at this stage of SIP
development, EPA believes, based upon its experience in implementing
the 1-hour ozone NAAQS, that it is preferable to take action under
section 110(a)(2)(D) to address the regional transport component of the
PM_2.5 and 8-hour ozone nonattainment problem. States, both
upwind and downwind, will still have an obligation to control emissions
from sources within their boundaries for the purposes of local area
attainment and maintenance of the NAAQS. The EPA does not believe,
however, that it is either required by the statute, or in accordance
with sound policy, for the Agency to wait until submission of the
nonattainment area SIPs of downwind States to discover whether or not
those SIPs will control local sources sufficiently to provide for
eventual attainment regardless of continued significant contribution
through interstate transport from upwind States. To the contrary, past
experience with the 1-hour ozone NAAQS has demonstrated that delayed
action to address the interstate component of nonattainment will
potentially lead to delays in attainment as downwind areas struggle to
overcome the impacts of transport. Indeed, a number of scientific and
technical assessments of ozone and PM_2.5 by the NRC and the
Ozone Transport Assessment Group have identified addressing interstate
transport as a critical issue in developing SIPs.
d. The EPA's Authority To Require Section 110(a)(2)(D) Submissions
Prior to Completion of the Next Review of the PM_2.5 and 8-
Hour Ozone NAAQS
Commenters also asserted that EPA should not take any action to
implement the 8-hour ozone and PM_2.5 NAAQS, until completion
of the next NAAQS review cycle. According to the commenters, a series
of statements by EPA and others indicated an intention to take no
action to implement the NAAQS until after the next review cycle, and
that statutes passed by Congress confirm that EPA is to take no such
action.
The EPA disagrees with the assertion that it should take no action
to implement the 1997 PM_2.5 and 8-hour ozone NAAQS until
completion of the next NAAQS review. Section 110(a) explicitly requires
States to begin to submit SIPS within 3 years after promulgation of a
new or revised NAAQS. The CAA also requires EPA to take action upon
State SIP submissions within specific timeframes. States are likewise
explicitly obligated to attain existing NAAQS within certain specified
timeframes. None of these basic statutory submission, review, or
attainment obligations are stayed or delayed due to the fact that there
may be an ongoing NAAQS review cycle. Indeed, under section 109, EPA is
to review all NAAQS on an ongoing basis, every 5 years. If the mere
existence of a NAAQS review cycle were grounds to suspend implementation
of a NAAQS, it would undermine the very goals of the statute.
The commenters argued that certain statements made by EPA and
others in guidance memoranda and elsewhere preclude EPA from taking any
action to implement the PM_2.5 and 8-hour ozone NAAQS. The
EPA believes that the commenters are misconstruing those statements,
and that the statements merely reflect the Agency's assumption that the
NAAQS review cycle would occur on the normal schedule. It would be
nonsensical to suggest that, if for any reason, the NAAQS review cycle
were delayed, that the CAA would permit no implementation of the
existing NAAQS. Such an approach would invite and encourage
inappropriate interference in the NAAQS review cycle as a means of
subverting the CAA.
The commenters further argued that Congress has taken action to
prevent implementation of the 8-hour ozone and PM_2.5 NAAQS
pending the next NAAQS review cycle. The EPA does not see any such
intention on the part of Congress. In TEA-21 and the 2004 Consolidated
Appropriations Act, Congress has amended section 107 to provide
specific dates by which States and EPA must make designations.
Significantly, Congress did not alter the existing statute with respect
to any other deadlines for SIP submissions, or with respect to
implementation of the PM_2.5 and 8-hour ozone NAAQS
generally. By contrast, in the 2004 Consolidated Appropriations Act,
Congress did explicitly alter the date by which States must submit plan
revisions to address Regional Haze. See, Section 7(A), 42 U.S.C.
section 7407 note. From this explicit action, one must infer that
Congress could have taken action to alter the submission date for plans
to address PM_2.5 or 8-hour ozone, had it intended to alter
the existing statutory scheme. Most importantly, however, Congress did
not make any of the changes effected in TEA-21 or the 2004 Consolidated
Appropriations Act dependent upon completion of the next NAAQS review.
To the contrary, Congress directed EPA to take certain actions
notwithstanding the fact that there were and are ongoing reviews of the
NAAQS. From this, EPA infers that Congress did not intend EPA to defer
all action to implement the existing NAAQS, including today's action to
assist States to address the requirements of section 110(a)(2)(D).
e. The EPA's Authority To Require States To Make Section 110(a)(2)(D)
Submissions Within 18 Months of This Final Rule
Some commenters questioned EPA's proposal to require States to make
SIP submissions in response to this action as expeditiously as
practicable but no later than within 18 months. A number of commenters
suggested that this schedule is too short because of the magnitude or
complexity of the task or because of the typical duration of State
rulemaking processes. Other commenters suggested that EPA should follow
the example of the NO_X SIP Call more closely and provide a
shorter period than the Agency proposed.
The EPA has concluded that the proposed 18-month schedule is
reasonable given the circumstances and given the scope of the actions
that we are requiring States to take. We issued the PM_2.5
and 8-hour ozone NAAQS revisions in July 1997. More than 3 years have
already elapsed since promulgation of the NAAQS, and States have not
submitted SIPs to address their section 110(a)(2)(D) obligations under
the new NAAQS. We recognize that litigation over the new
PM_2.5 and 8-hour ozone NAAQS created substantial uncertainty
as to whether the courts would uphold the new NAAQS, and that this
uncertainty, as a practical matter, rendered it more difficult for
States to develop SIPs. Moreover, in the case of PM_2.5,
additional time was needed for creation of an adequate monitoring
network, collection of at least 3 years of data from that network, and
analysis of those data.
In addition, in the NPR, the SNPR, and today's action, we have
provided States with a great deal of data and analysis concerning air
quality and

[[Page 25269]]

control costs, as well as policy judgments from EPA concerning the
appropriate criteria for determining whether upwind sources contribute
significantly to downwind nonattainment under section 110(a)(2)(D). We
recognize that States would face great difficulties in developing
transport SIPs to meet the requirements of today's action without these
data and policies. In light of these factors and the fact that States
can no longer meet the original 3-year submittal date of section
110(a)(1), we believe that States need a reasonable period of time in
which to comply with the requirements of today's action.
In the comparable NO_X SIP Call rulemaking, EPA provided
12 months for the affected States to submit their SIP revisions. One of
the factors that we considered in setting that 12-month period was that
upwind States had already, as part of the Ozone Transport Assessment
Group process begun 3 years before the NO_X SIP Call
rulemaking, been given the opportunity to consider available control
options. Because today's action requires affected States to control
both SO₂ and NO_X emissions, and to do so for the
purpose of addressing both the PM_2.5 and 8-hour ozone NAAQS,
we believe it is reasonable to allow affected States more time than was
allotted in the NO_X SIP Call to develop and submit transport SIPs.
Another factor that we have considered is that under section
110(k)(5), the CAA stipulates that EPA may provide up to 18 months for
SIP submissions to correct substantially inadequate plans. While
today's action is not pursuant to section 110(k)(5), we believe that
the provision provides an analogy for the appropriate schedule on which
EPA should expect States to make the submission required by today's
action. We believe it would not be appropriate to set a longer schedule
for submission of the plan than would have been possible under section
110(k)(5) had the States submitted a plan on the original 3-year
schedule contemplated in section 110(a)(1) that did not provide for the
emissions reductions today's action requires. While the CAA does
require States to make some SIP submissions on shorter schedules, we
conclude that the complexities of the action required by today's
rulemaking militate in favor of a longer schedule.\119\
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\119\ See, e.g., section 182(a)(2)(A) (providing a 6-month
schedule for submission of a revision to provide for RACT
corrections); section 189(d) (providing 12 months for submission of
plan revisions to ensure attainment and required emissions
reductions). The former revision could be relatively limited in
scope, but the latter might entail submission of a completely revised SIP.
---------------------------------------------------------------------------

Finally, we note that by making findings that States have thus far
failed to submit SIPs to meet the requirements of section 110(a)(2)(D)
for the 8-hour ozone and PM_2.5 NAAQS, EPA has an obligation
to implement a Federal implementation plan (FIP) to address interstate
transport no later than 24 months after that finding, if the States
fail to take appropriate action. Given this schedule for the FIP
obligation, EPA believes that it is reasonable to require States to
take action to meet the section 110(a)(2)(D) obligation with respect to
the significant contribution identified in today's rule within no more
than 18 months. Such a schedule will allow States adequate time to
develop submissions to meet this requirement and will afford EPA
adequate time to review such submissions before the imposition of a FIP
in lieu of a SIP, if necessary.
Thus, EPA has concluded that States should submit SIPs to reduce
interstate transport, as required by this final action, as
expeditiously as practicable but no later than 18 months from today's
date. Such a schedule will provide both upwind and downwind States, and
those States that are in both positions relative to other States, to
develop SIPs that will facilitate expeditious attainment of the
PM_2.5 and the 8-hour ozone standards.

C. What Happens If a State Fails To Submit a Transport SIP or EPA
Disapproves the Submitted SIP?

1. Under What Circumstances Is EPA Required To Promulgate a FIP?
Under section 110(c)(1), EPA is required to promulgate a FIP within
2 years of: (1) finding that a State has failed to make a required
submittal; or (2) finding that a submittal received does not satisfy
the minimum completeness criteria established under section
110(k)(1)(A) (40 CFR part 51, appendix V); or (3) disapproving a SIP
submittal in whole or in part. Section 110(c)(1) mandates that EPA
promulgate a FIP unless the States corrects the deficiency and EPA
approves the SIP before the time EPA would promulgate the FIP.
2. What Are the Completeness Criteria?
Any SIP submittal that is made with respect to the final CAIR
requirements first would be determined to be either incomplete or
complete. A finding of completeness is not a determination that the
submittal is approvable. Rather, it means the submittal is
administratively and technically sufficient for EPA to proceed with its
review to determine whether the submittal meets the statutory and
regulatory requirements for approval. Under 40 CFR 51.123 and 40 CFR
51.124 (the proposed new regulations for NO_X and
SO₂ SIP requirements, respectively), a submittal, to be
complete, must meet the criteria described in 40 CFR, part 51, appendix
V, ``Criteria for Determining the Completeness of Plan Submissions.''
These criteria apply generally to SIP submissions.
Under CAA section 110(k)(1) and section 1.2 of appendix V, EPA must
notify States whether a submittal meets the requirements of appendix V
within 60 days of, but no later than 6 months after, EPA's receipt of
the submittal. If a completeness determination is not made within 6
months after submission, the submittal is deemed complete by operation
of law. For rules submitted in response to the CAIR, EPA intends to
make completeness determinations expeditiously.
3. When Would EPA Promulgate the CAIR Transport FIP?
The EPA views seriously its responsibility to address the issue of
regional transport of PM_2.5, ozone, and precursor emissions.
Decreases in NO_X and SO₂ emissions are needed in
the States named in the CAIR to enable the downwind States to develop
and implement plans to achieve the PM_2.5 and 8-hour ozone
NAAQS and provide clean air for their residents. Thus, EPA intends to
promulgate the FIP shortly after the CAIR SIP submission deadline for
States that fail to submit approvable SIPs in order to help assure that
the downwind States realize the air quality benefits of regional
NO_X and SO₂ reductions as soon as practicable.
This is consistent with Congress' intent that attainment occur in these
downwind nonattainment areas ``as expeditiously as practicable''
(sections 181(a), 172(a)). To this end, EPA intends to propose the FIP
prior to the SIP submission deadline.
The FIP proposal would achieve the NO_X and
SO₂ emissions reductions required under the CAIR by
requiring EGUs in affected States to reduce emissions through
participation in Federal NO_X and SO₂ cap and
trade programs. The EPA intends to integrate these Federal trading
programs with the model trading programs that States may choose to
adopt to meet the CAIR. Although EPA would be proposing FIPs for all
States affected by the CAIR, EPA will only issue a final FIP for those
jurisdictions that fail to respond adequately to the CAIR.

[[Page 25270]]

The EPA's goal is to have approvable SIPs that meet the
requirements of the CAIR. We remain ready to work with the States to
develop fully approvable SIPs, which would eliminate the need for EPA
to promulgate a FIP.

D. What Are the Emissions Reporting Requirements for States?

The EPA believes that it is essential that achievement of the
emissions reductions required by the CAIR be verified on a regular
basis. Emission reporting is the principal mechanism to verify these
reductions and to assure the downwind affected States and EPA that the
ozone and PM_2.5 transport problems are being mitigated as
required by the rule. Therefore, the final rule establishes a small set
of new emission reporting requirements applicable to States affected by
the CAIR, covering certain emissions data not already required under
existing emission reporting regulations. The rule language also removes
a current emission reporting requirement related to the NO_X
SIP call, which we believe is not necessary, for reasons explained
below. A number of other proposed changes in emission reporting
requirements which would have affected States not subject to the final
CAIR are not included in the final rule, for reasons explained below.
We will repropose these other changes, with modifications, in a
separate proposal to allow additional opportunity for public comment.
1. Purpose and Authority
Because we are consolidating and harmonizing the new emission
reporting requirements promulgated today with two pre-existing sets of
emission reporting requirements, we review here the purpose and
authority for emission reporting requirements in general.
Emissions inventories are critical for the efforts of State, local,
and Federal agencies to attain and maintain the NAAQS that EPA has
established for criteria pollutants such as ozone, PM, and CO. Pursuant
to its authority under sections 110 and 172 of the CAA, EPA has long
required SIPs to provide for the submission by States to EPA of
emissions inventories containing information regarding the emissions of
criteria pollutants and their precursors (e.g., VOCs). The EPA codified
these requirements in subpart Q of 40 CFR part 51, in 1979 and amended
them in 1987.
The 1990 Amendments to the CAA revised many of the provisions of
the CAA related to the attainment of the NAAQS and the protection of
visibility in Class I areas. These revisions established new periodic
emissions inventory requirements applicable to certain areas that were
designated nonattainment for certain pollutants. For example, section
182(a)(3)(A) required States to submit an emissions inventory every 3
years for ozone nonattainment areas beginning in 1993. Similarly,
section 187(a)(5) required States to submit an inventory every 3 years
for CO nonattainment areas. The EPA, however, did not immediately
codify these statutory requirements in the CFR, but simply relied on
the statutory language to implement them.
In 1998, EPA promulgated the NO_X SIP call which requires
the affected States and the District of Columbia to submit SIP
revisions providing for NO_X reductions to reduce their
adverse impact on downwind ozone nonattainment areas. (63 FR 57356,
October 27, 1998). As part of that rule, codified in 40 CFR 51.122, EPA
established emissions reporting requirements to be included in the SIP
revisions required under that action.
Another set of emissions reporting requirements, termed the
Consolidated Emissions Reporting Rule (CERR), was promulgated by EPA in
2002, and is codified at 40 CFR part 51 subpart A. (67 FR 39602, June
10, 2002). These requirements replaced the requirements previously
contained in subpart Q, expanding their geographic and pollutant
coverages while simplifying them in other ways.
The principal statutory authority for the emissions inventory
reporting requirements outlined in this final rule is found in CAA
section 110(a)(2)(F), which provides that SIPs must require ``as may be
prescribed by the Administrator * * * (ii) periodic reports on the
nature and amounts of emissions and emissions-related data from such
sources.'' Section 301(a) of the CAA provides authority for EPA to
promulgate regulations under this provision.\120\
---------------------------------------------------------------------------

\120\ Other CAA provisions relevant to this final rule include
section 172(c)(3) (provides that SIPs for nonattainment areas must
include comprehensive, current inventory of actual emissions,
including periodic revisions); section 182(a)(3)(A) (emissions
inventories from ozone nonattainment areas); and section 187(a)(5)
(emissions inventories from CO nonattainment areas).
---------------------------------------------------------------------------

2. Pre-existing Emission Reporting Requirements
As noted above, prior to this final rule, two sections of title 40
of the CFR contained emissions reporting requirements that are
applicable to States: Subpart A of part 51 (the CERR) and section
51.122 in subpart G of part 51 (the NO_X SIP Call reporting
requirements).
Under the NO_X SIP Call requirements in section 51.122,
emissions of NO_X for a defined 5-month ozone season (May 1
through September 30) and for work weekday emissions for point, area
and mobile sources that the State has subjected to emissions control to
comply with the requirements of the NO_X SIP Call, are
required to be reported by the affected States to EPA every year.
However, emissions of sources reporting directly to EPA as part of the
NO_X trading program are not required to be reported by the
State to EPA every year. The affected States are also required to
report ozone season emissions and typical summer daily emissions of
NO_X from all sources every third year (2002, 2005, etc.) and
in 2007. This triennial reporting process does not have an exemption
for sources participating in the emissions trading programs. Section
51.122 also requires that a number of data elements be reported for
each source in addition to ozone season NO_X emissions. These
data elements describe certain of the source's physical and operational
parameters.
Emissions reporting under the NO_X SIP Call as first
promulgated was required starting for the emissions reporting year
2002, the year prior to the start of the required emissions reductions.
The reports are due to EPA on December 31 of the calendar year
following the inventory year. For example, emissions from all sources
and types in the 2002 ozone season were required to be reported on
December 31, 2003. However, because the Court which heard challenges to
the NO_X SIP Call delayed the implementation by 1 year to
2004, no State was required to start reporting until the 2003 inventory
year. The EPA promulgated a rule to subject Georgia and Missouri to the
NO_X SIP Call with an implementation date of 2007. (See 69 FR
21604, April 21, 2004.) We have recently proposed to stay the
NO_X SIP Call for Georgia (see 70 FR 9897, March 1, 2005).
Missouri's emissions reporting begins with 2006. These emissions
reporting requirements under the NO_X SIP Call affect the
District of Columbia and 18 of the 28 States affected by the proposed
CAIR.
As noted above, the other set of pre-existing emissions reporting
requirements is codified at subpart A of part 51. Although entitled the
Consolidated Emissions Reporting Rule (CERR), this rule left in place
the separate Sec. 51.122 for the NO_X SIP Call reporting.
The CERR requirements were aimed at obtaining emissions information to
support a broader set of purposes under the CAA than were the reporting
requirements under the NO_X

[[Page 25271]]

SIP Call. The CERR requirements apply to all States.
Like the requirements under the NO_X SIP Call, the CERR
requires reporting of all sources at 3-year intervals (2005, 2008,
etc.). It requires reporting of certain large sources every year.
However, the required reporting date under the CERR is 5 months later
than under the NO_X SIP Call reporting requirements. Also,
emissions must be reported for the whole year, for a typical day in
winter, and a typical day in summer, but not for the 5-month ozone
season as is required by the NO_X SIP Call. Finally, the CERR
and the NO_X SIP Call differ in what non-emissions data
elements must be reported.
3. Summary of the Proposed Emissions Reporting Requirements
On June 10, 2004, EPA published a SNPR (69 FR 32684) to EPA's
January 30, 2004 proposal (69 FR 4566). The EPA's main objective with
respect to emissions reporting was to add limited new requirements for
emissions reports to serve the additional purposes of verifying the
CAIR-required emissions reductions. The SNPR also sought to harmonize
the CERR and NO_X SIP Call reporting requirements with
respect to specific data elements and consolidate them entirely in
subpart A, and to reduce and simplify the reporting requirements in
several ways. These latter changes were proposed to be applicable to
all States, not just those affected by the CAIR emissions reduction
requirements. The major changes included in the SNPR are described below.
Amendments were proposed to subpart A, which contains Sec. 51.1
through 51.45 and an appendix, and to Sec. 51.122. We also proposed to
add a new Sec. 51.125.
? In Sec. 51.122, the NO_X SIP Call provisions,
we proposed to abolish certain requirements entirely, and to replace
certain requirements with a cross reference to subpart A so that
detailed lists of required data elements appeared only in subpart A. As
proposed, Sec. 51.122 would then have specified what pollutants,
sources, and time periods the States subject to the NO_X SIP
Call must report and when, but would no longer have listed the detailed
data elements required for those reports.
? The proposed new Sec. 51.125 would have been functionally
parallel to Sec. 51.122, specifying all the pollutants, sources, and
time periods the States subject to the proposed CAIR must report and
when, referencing subpart A for the detailed data elements required.
? The proposed amended subpart A would have listed the
detailed data elements for all three reporting programs (CERR,
NO_X SIP Call, and CAIR) as well as provided information on
submittal procedures, definitions, and other generally applicable
provisions.
Taken together, the pre-existing emissions reporting requirements
under the NO_X SIP Call and CERR were already rather
comprehensive in terms of the States covered and the information
required. Therefore, the practical impact of the proposed changes would
have imposed only three new requirements.
First, in Arkansas, Florida, Iowa, Louisiana, Mississippi, and
Wisconsin for which we proposed and are finalizing a finding of
significant contribution to ozone nonattainment in another State but
which were not among the 22 States already subject to the
NO_X SIP Call, the required emissions reporting would be
expanded to match those of the 22 States. The proposed change would
require that they report NO_X emissions during the 5-month
ozone season and for a typical summer day, in addition to the existing
requirement for reporting emissions for the full year. We proposed that
this new requirement begin with the triennial inventory year prior to
the CAIR implementation date. This would be the 2008 inventory year,
the report for which would be due to EPA by June 1, 2010.
Second, under the existing CERR, yearly reporting is required only
for sources whose emissions exceed specified amounts. The SNPR proposed
that the 28 States and the District of Columbia subject to the CAIR for
reasons of PM_2.5 must report to EPA each year a set of
specified data elements for all sources subject to new controls adopted
specifically to meet the CAIR requirements related to PM_2.5,
unless the sources participate in an EPA-administered emissions trading
program. We proposed that this new requirement begin with the 2009
inventory year, the report for which will be due to EPA by June 1,
2011. This new requirement would have no effect on States that fully
comply with the CAIR by requiring their EGUs to participate in the CAIR
model cap and trade programs.
Third, in all States, we proposed to expand the definition of what
sources must report in point source format, so that fewer sources would
be included in non-point source emissions.\121\ We proposed to base the
requirement for point source format reporting on whether the source is
a major source under 40 CFR part 70 for the pollutants for which
reporting is required, i.e., for CO, VOC, NO_X,
SO₂, PM_2.5, PM₁₀ and ammonia but
without regard to emissions of hazardous air pollutants.
---------------------------------------------------------------------------

\121\ We used the term ``non-point source'' in the SNPR to refer
to a stationary source that is treated for inventory purposes as
part of an aggregated source category rather than as an individual
facility. In the existing subpart A of part 51, such emissions
sources are referred to as ``area sources.'' However, the term
``area source'' is used in section 112 of the CAA to indicate a non-
major source of hazardous air pollutants, which could be a point
source. As emissions inventory activities increasingly encompass
both NAAQS-related pollutants and hazardous air pollutants, the
differing uses of ``area source'' can cause confusion. Accordingly,
EPA proposed to substitute the term ``non-point source'' for the
term ``area source'' in subpart A, Sec. 51.122, and the new Sec.
51.125 to avoid confusion. We are not finalizing this change in
terminology in today's rule.
---------------------------------------------------------------------------

A number of other proposed changes would have reduced reporting
requirements on States or provided them with additional options. Two of
the proposed changes in this category are of special note in
understanding the final requirements of today's rule. (The remainder of
these changes were explained in the SNPR at 69 FR 32697.)
? The NO_X SIP Call rule requires the affected
States to submit emissions inventory reports for a given ozone season
to EPA by December 31 of the following year. The CERR requires similar
but not identical reports from all States by the following June 1, five
months later. We proposed to move the December 31 reporting requirement
to the following June 1, the more generally applicable submission date
affecting all 50 States. We asked for comment on whether allowing this
5-month delay is consistent with the air quality goals served by the
emissions reporting requirements. However, we also asked for comment on
the alternative of moving forward to December 31 all or part of the
June 1 reporting for all 50 States. In particular, we solicited comment
on requiring that point sources be reported on December 31 and other
sources on June 1.
? We also proposed to eliminate a requirement of the
NO_X SIP Call for a special all-sources report by affected
States for the year 2007, due December 31, 2008.
4. Summary of Comments Received and EPA's Responses
A number of commenters objected to the 45-day comment period as
being too short to allow for full understanding of and comment on the
emissions reporting changes that EPA had proposed. With respect to this
issue, EPA believes that the comment period was sufficient for those
proposed changes that would affect the States subject to the emissions
reductions

[[Page 25272]]

requirements of the CAIR and that are specifically directed at ensuring
the effectiveness of the CAIR, namely: (1) The requirement for six more
States to report ozone season emissions, and (2) the requirement for
all subject States to report annual emissions from controlled sources
every year if those sources are not participating in the emission
trading programs. These proposed changes are easy to understand on
their face, and also have close precedents in the NO_X SIP
Call. Moreover, the States affected by these proposed reporting
requirements were identified as being subject to the proposed emissions
reduction requirements of the CAIR in the original NPR, and thus they
knew to be alert to the contents of the SNPR. We also consider the
comment period sufficient with respect to two other specific elements
of the proposal, namely (3) the proposal to eliminate the 2007
inventory reporting requirement under the NO_X SIP Call and
(4) the proposal to change the reporting date for the NO_X
SIP Call from December 31 (12 months after the end of the reported
year) to June 1 (17 months after the end of the reported year). These
were also readily understood proposals, and the States affected by them
were among those initially identified as subject to the CAIR itself. A
number of substantive comments were received on these four proposed
changes. Therefore, we have concluded that it is appropriate to
consider the substantive comments that were received on these four
elements of the SNPR, and to take final action on them. The disposition
of the remaining elements of the SNPR is discussed further below.
The EPA received one comment from the Mississippi Department of
Environmental Quality on the proposed requirement that Mississippi and
five other States report ozone season emissions. Mississippi disagreed
that they should be included with the other States subject to the CAIR
provisions, including the emissions reporting provisions. The EPA has
concluded that the analysis performed to support CAIR and discussed
earlier in this preamble amply demonstrates that Mississippi should be
included in the CAIR and subject to the CAIR emissions reporting
requirements.
We did not receive comments specifically on the proposal to require
States to report annual emissions every year from sources controlled to
comply with the CAIR, if those sources are not participating in the
emission trading programs operated by EPA. While we expect the number
of such sources to be small if not zero, we continue to believe that
tracking their emissions from year to year is appropriate, and we are
finalizing this requirement. Since the CERR already contains a
requirement for every-year reporting of emissions from point sources
above certain emission thresholds, this requirement will have an
incremental impact only if States choose to control fairly small point
sources or nonpoint or mobile sources as part of their plan for meeting
the CAIR requirements.
The EPA received several comments regarding the elimination of the
NO_X SIP Call special all-sources 2007 emissions inventory.
These comments all favored the elimination of the 2007 emissions
inventory, which EPA is promulgating in today's rule. We would like to
clarify that the NO_X SIP Call contained no requirement that
any State make a retrospective demonstration that actual statewide
emissions of NO_X were within any limit. The requirement for
the 2007 inventory was for the purpose of program evaluation by EPA. As
explained in the SNPR, we believe that in light of the data on 2007
emissions that will be available from the NO_X trading
program and the further reductions in NO_X required by the
CAIR, the 2007 inventory submissions from the States are not needed for
this purpose.
The EPA also proposed to harmonize the report due dates for the
NO_X SIP Call, currently 12 months after the end of the
reported year, and for the CERR, currently 17 months after the end of
the reported year. The EPA proposed to harmonize the dates for both at
17 months, but asked for comments on a 12-month due date. Several
comments were received, all favoring harmonizing the report due date at
17 months. While we continue to believe in the efficiency advantage of
harmonized submission date requirements, we are not finalizing this
change. The EPA has reconsidered this part of the proposed emissions
reporting requirements and believes that it may be in the interest of
the public to move in the direction of shortening the emissions
reporting cycle for all three reporting requirements (CERR,
NO_X SIP Call, and CAIR), rather than accepting the longer
CERR cycle for all three reporting requirements. In today's final rule,
we are retaining the 12-month submission date requirement of the
original NO_X SIP Call for the States already subject to it.
For the six States that are newly subject to reporting ozone season
NO_X emissions and for the new requirement for every-year
reporting by sources controlled to meet the CAIR requirements for
SO₂ and NO_X annual emissions reductions but not
included in the trading programs, the required reporting date for
States will be June 1, 17 months after the end of the reported year, as
was proposed. We will address reporting deadlines comprehensively in a
separate NPR which will propose a unified, but shorter period of time
to report to EPA. This separate notice will allow for more public
comment on the reporting cycle. The dual approach to reporting due
dates retained in today's rule will be combined into unified due dates
and will be influenced by comments received in response to our proposal
when the separate rulemaking is completed.
Regarding elements of the proposed requirements beyond these four,
i.e., the requirements that would have affected States not subjected to
the CAIR emissions reduction requirements as well as CAIR States, many
commenters said that EPA should not have included changes to national
emissions reporting requirements in a proposed rule placing emissions
reduction requirements on only certain States. Commenters also
questioned whether EPA had given adequate time for comment on the more
detailed revisions in required data elements, definitions, etc.
Substantively, many commenters supported some or all of the proposed
changes, but some commenters objected to some of them.
The EPA has considered these comments. Without conceding EPA's
legal authority to include these provisions in the final rule in light
of the history of proposal, public hearing, and comment period, EPA
has--in an abundance of caution--decided to omit these provisions from
today's rule (see section VIII.D.5 Summary of the Emissions Reporting
Requirements below for the changes which are being finalized today). We
will repropose them, with modifications, in a separate NPR to allow
additional opportunity for public comment by all affected States and
other parties.
5. Summary of the Emissions Reporting Requirements
As a result of the comments received, EPA has revised the emissions
reporting requirements of today's rule by limiting new requirements to
the ones where sufficient notice and opportunity for comment was
clearly given in the June 10, 2004, SNPR and that either: (1) Are
necessary for the monitoring of the implementation of the emissions
reduction requirements of the CAIR, or (2) are changes in reporting
under the NO_X SIP Call linked to the CAIR. Three specific
emissions reporting provisions that change the pre-existing
requirements are included in today's rule.

[[Page 25273]]

1. 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,
Wisconsin and the District of Columbia, which are subject to the CAIR
for reasons of ozone, are made subject to emission reporting
requirements for NO_X that are very similar to the existing
requirements of the NO_X SIP Call, which already affects all
but six of these States. For these six States (Arkansas, Florida, Iowa,
Louisiana, Mississippi and Wisconsin) a new requirement is that they
report NO_X emissions during the 5-month ozone season from
all sources every three years, in addition to reporting emissions for
the full year and for a summer day as was already required. This new
requirement begins with the triennial inventory year 2008. For all the
listed States, a new requirement is to report to EPA for 2009 and each
year thereafter the ozone-season and summer day NO_X
emissions, plus a set of specified other data elements, for all sources
subject to new controls adopted specifically to meet the CAIR
requirements related to ozone, unless the sources participate in an
EPA-administered emissions trading program. These reports will be due
June 1 of the second year following the end of the reported year, i.e.,
17 months after the end of the reported year. The existing CERR
includes several other reporting requirements which in conjunction with
this new requirement will meet the needs for monitoring the
implementation of required NO_X emissions reductions.
2. 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, Wisconsin and the District of Columbia,
which are subject to the CAIR for reasons of PM_2.5, must
report to EPA each year annual NO_X and SO₂
emissions, plus a set of specified other data elements, for all sources
subject to new controls adopted specifically to meet the CAIR
requirements related to PM_2.5, unless the sources
participate in an EPA-administered emissions trading program.
Previously, these states may have been required to report these sources
only every third year, depending on their size. The existing CERR
includes several other reporting requirements which in conjunction with
this new requirement will meet the needs for monitoring the
implementation of required NO_X and SO₂ emissions
reductions.
3. The EPA has determined that the requirement in the
NO_X SIP Call for a special all-sources report by affected
States for the year 2007, due December 31, 2008, is no longer needed to
administer provisions in the NO_X SIP Call. Accordingly, EPA
is eliminating this requirement in today's rule.
The final rule accomplishes these changes by making minimal changes
to the existing provisions of 40 CFR part 51. Subpart A, which contains
the CERR requirements, is not amended at all. 40 CFR 51.122, the
section containing emission inventory reporting requirements for the
NO_X SIP Call, is substantively amended only to delete the
requirement for the 2007 inventory report.\122\ A new section 40 CFR
51.125 is added to contain the two new emission inventory reporting
requirements specifically related to the new CAIR requirements for
emissions reductions, regarding ozone-season emissions of
NO_X and every-year reporting of NO_X and
SO₂ emissions from all sources controlled but not
participating in the EPA trading programs. The new 40 CFR 51.125 refers
to 40 CFR subpart A for the other specific data elements that must be
reported.
---------------------------------------------------------------------------

\122\ 40 CFR 51.122 is also amended: (1) to remove a reference
to now-obsolete electronic data reporting processes (a
``housekeeping'' deletion that was specifically included in the
proposed rule text with the SNPR), and (2) to make a minor technical
correction to properly indicate which of the latitude versus
longitude data elements corresponds to the x-coordinate and which to
the y-coordinate (a correction that was implicitly proposed in the
SNPR in that 51.122 was proposed to refer to 51 subpart A for all
its data element descriptions).
---------------------------------------------------------------------------

VIII. Model NO_X and SO₂ Cap and Trade Programs

A. What Is the Overall Structure of the Model NO_X and
SO₂ Cap and Trade Programs?

The EPA is finalizing model rules for the CAIR annual
NO_X, CAIR ozone-season NO_X, and SO₂
trading programs that States can use to meet the emission reduction
requirements in the CAIR. These rules are designed to be referenced by
States in State rulemaking. State use of the model cap and trade rules
helps to ensure consistency between the State programs, which is
necessary for the market aspects of the regional trading program to
function properly. It also allows the CAIR Program to build on the
successful Acid Rain Program. Consistency in the CAIR requirements from
State-to-State benefits the affected sources, as well as EPA, which
administers the program on behalf of States.
This section focuses on the structure which maintains the existing
NO_X SIP Call rules (in part 96, subparts A through J) while
adding parallel rules for the CAIR annual NO_X (in subparts
AA through II), CAIR SO₂ (in subparts AAA through III), and
the CAIR ozone-season NO_X (in subparts AAAA through IIII) of
the model rules. Commenters generally supported the proposed structure
of the model rules, as well as the use of the cap and trade approach,
which are maintained in the final rules. Later sections of today's rule
discuss specific aspects of the model rules that have been modified or
maintained in response to comment.
The EPA designed the model rules to parallel the NO_X SIP
Call model trading rules (part 96) and to coordinate with the Acid Rain
Program. Mirroring the structure of existing part 96 in the final CAIR
NO_X and SO₂ model rules will ease the transition
to the CAIR rules as many States and sources are already familiar with
the layout of the NO_X SIP Call rule. In addition, because
the EPA proposed new CAIR model trading rules--separate from the
existing NO_X SIP Call model rule in part 96--States can
continue to reference part 96 (subparts A through J) through 2008. The
CAIR ozone-season NO_X cap and trade program that the EPA has
included in today's final rule is intended for use by CAIR ozone-
affected sources as well as those subject to the NO_X SIP
Call in 2009 and beyond. Those States that wish to use an EPA-
administered, ozone-season cap and trade program to achieve the
reductions mandated by the CAIR or the NO_X SIP Call, must
use the CAIR ozone-season NO_X model rule (subparts AAAA
through IIII) in 2009 and beyond.
The model rules rely on the detailed unit-level emissions
monitoring and reporting procedures of part 75 and consistent allowance
management practices. (Note that full CAIR-related SIP requirements,
i.e., part 51, are discussed in section VII of today's preamble.)
Additionally, section IX.B of today's preamble discusses the final
revisions to parts 72 through 77 in order to, among other things,
facilitate the interaction of the title IV Acid Rain Program's
SO₂ cap and trade provisions and those of the CAIR
SO₂ trading program.
Road Map of Model Cap and Trade Rules
The following is a brief ``road map'' to the final CAIR
NO_X and SO₂ cap and trade programs. Please refer
to the detailed discussions of the CAIR

[[Page 25274]]

programmatic elements throughout today's rule for further information
on each aspect.
State Participation
? States have flexibility to achieve emissions reductions
however they chose, including developing and implementing their own
trading program.
? States may elect to participate in an EPA-managed cap and
trade program. To participate, a State must adopt the model cap and
trade rules finalized in this section of today's rule with flexibility
to modify sections regarding NO_X allocations and whether to
include individual unit opt-in provisions.
? States may participate in EPA-managed cap and trade
programs for either the annual NO_X, the ozone-season
NO_X, the SO₂, or any combination. The State can
only choose to participate in the EPA-administered, CAIR cap and trade
program(s) that is (are) relevant to their finding(s).
? The annual NO_X model rule is to be used by only
those States that are affected by the CAIR PM_2.5 finding.
? The ozone-season NO_X model rule is designed to
be used by those States that are affected by the CAIR ozone finding as
well as take the place of the NO_X SIP Call
requirements.\123\ The CAIR ozone-season NO_X program will be
the only ozone-season NO_X program that EPA will administer.
Because EPA will no longer run a NO_X SIP Call trading
program, States may include their NO_X SIP Call trading
sources if they adopt the EPA-administered CAIR ozone-season
NO_X program.
---------------------------------------------------------------------------

\123\ Rhode Island (RI) is the only State currently
participating in the NO_X SIP Call cap and trade program
that is not affected by today's ozone finding. As is explained in
section IX, RI may join the CAIR ozone-season trading program as a
means of satisfying its NO_X SIP Call requirements.
---------------------------------------------------------------------------

? The SO₂ model rule is designed to satisfy the
ongoing statutory requirements of the title IV Acid Rain SO₂
cap and trade program--with sequential compliance with title IV and the
CAIR--for sources in the CAIR region that are affected by both the Acid
Rain Program and the CAIR.
Trading Sources
? States must achieve all of the mandated emission
reductions from EGUs to participate in EPA-managed cap and trade
programs. States may include other NO_X SIP Call trading
sources in the ozone-season CAIR NO_X cap and trade program
and still participate in EPA-managed cap and trade programs.
? States may participate in EPA-managed cap and trade
programs whether or not they adopt the optional individual opt-in
provisions of the model rule. However, if the State chooses to allow
individual sources to opt-in, the opt-in requirements must reflect the
requirements of the model rule.
Emission Allowances
? The CAIR annual NO_X cap and trade program will
rely upon CAIR annual NO_X allowances allocated by the
States. The NO_X SIP Call allowances and CAIR ozone-season
NO_X allowances cannot be used for compliance with the annual
CAIR reduction requirement. (Note that allowances from the Compliance
Supplement Pool (CSP) will be CAIR annual NO_X allowances.)
? The CAIR ozone-season NO_X cap and trade program
will rely upon CAIR ozone-season NO_X allowances allocated by
the States. In addition, pre-2009 NO_X SIP Call allowances
can be banked into the program and used by CAIR-affected sources for
compliance with the CAIR ozone-season NO_X program. The
NO_X SIP Call allowances of vintages 2009 and later can not
be used for compliance with any EPA-administered cap and trade programs.
? The CAIR SO₂ cap and trade program will rely
upon title IV SO₂ allowances but may also include additional
CAIR SO₂ allowances, should a State that allows an
individual unit opt-in mechanism provide CAIR SO₂
allowwances to an opt-in source. Pre-2010 title IV SO₂
allowances can be used for compliance with the CAIR.
? Sulfur dioxide reductions are achieved by requiring
sources to retire more than one allowance for each ton of
SO₂ emissions. The emission value of an SO₂
allowance is independent of the year in which it is used, but is based
upon its vintage (i.e., the year in which the allowance is issued).
Sulfur dioxide allowances of vintage 2009 and earlier offset one ton of
SO₂ emissions. Vintages 2010 through 2014 offset 0.5 tons of
emissions. And, vintages 2015 and beyond offset 0.35 tons of emissions.
Allocation of Allowances to Sources
? For SO₂ allowances, sources have already
received allowances through title IV.
? NO_X allowances (for both the annual and ozone-
season programs) will be allocated based upon the State's chosen
allocation methodology. The EPA's model NO_X rules have
provided an example allocation, complete with regulatory text, that may
be used by State's or replaced by text that implements a States
alternative allocation methodology.
Compliance Supplement Pool (CSP)
? Each State will have a share of the CSP that is comprised
of 200,000 \124\ CAIR annual NO_X allowances of vintage year
2009. The State may distribute the CSP allowances based upon the
criteria, found in the SIP Approvability section of today's rule, for
early reductions and need.
---------------------------------------------------------------------------

\124\ The 200,000 total includes the share of the CSP that DE
and NJ would receive if the EPA finalizes a parallel rule finding
that they are significant contributors for PM_2.5.
---------------------------------------------------------------------------

Emission Monitoring and Reporting by Sources
? Sources monitor and report their emissions using part 75.
This includes individual sources that opt-in to the program.
? Source information management, emissions data reporting,
and allowance trading is done through on-line systems similar to those
currently used for the Acid Rain SO₂ and NO_X SIP
Call Programs.
? Emission monitoring and reporting for both the CAIR annual
and ozone-season NO_X cap and trade programs will use part 75.
Compliance and Penalties
? Compliance for the annual and ozone-season NO_X
cap and trade programs, as well as the SO₂ program, will be
determined separately.\125\
---------------------------------------------------------------------------

\125\ Compliance with the title IV Acid Rain Program will be
determined separately from CAIR compliance.
---------------------------------------------------------------------------

? For the NO_X and SO₂ cap and trade
programs, any source found to have excess emissions must: (1) Surrender
allowances sufficient to offset the excess emissions; and, (2)
surrender allowances from the next control period equal to three times
the excess emissions.
Comments Regarding the Use of a Cap and Trade Approach and the Proposed
Structure
Commenters overwhelmingly supported the use of a cap and trade
approach and the overall framework of the model rules to achieve the
mandated emissions reductions. Some supported the use of cap and trade
for achieving regional emissions reductions but noted the need to have
additional measures that ensure that emission reductions take place in
nonattainment areas. This is in line with the EPA's strategy of
reducing transported SO₂ and NO_X through a
regionwide cap and trade approach and encouraging States to take
complementary measures to address their particular, persistent
nonattainment issues. (Note that comments on specific mechanisms

[[Page 25275]]

within the cap and trade program are discussed in the topic-specific
sections that follow.)

B. What Is the Process for States To Adopt the Model Cap and Trade
Programs and How Will It Interact With Existing Programs?

1. Adopting the Model Cap and Trade Programs
States may choose to participate in the EPA-administered cap and
trade programs, which are a fully approvable control strategy for
achieving all of the emissions reductions required under today's
rulemaking in a highly cost-effective manner. States may simply
reference the model rules in their State rules and, thereby, comply
with the requirements for statewide budget demonstrations detailed in
section VII.B of today's preamble. Affected States for both
PM_2.5 and ozone can adopt the annual NO_X and
SO₂ cap and trade programs in part 96, subparts AA through
II, part 96 subparts AAA through III, and AAAA through IIII. States
with ozone-season only CAIR requirements (i.e., Arkansas, Connecticut,
Delaware, Massachusetts, and New Jersey) can adopt the ozone-season
CAIR NO_X program (subparts AAAA through IIII). Part 96
subparts AA through II and AAA through III can be used by States that
are affected for only PM_2.5 (i.e., Georgia, Minnesota, and
Texas). States that elect to achieve the required reductions by
regulating other sources or using other approaches will follow
alternate State requirements, also described in section VII.B of
today's preamble.
As proposed, EPA is requiring States that wish to participate in
the EPA-managed cap and trade program to use the model rule to ensure
that all participating sources, regardless of which State in the CAIR
region they are located, are subject to the same trading and allowance
holding requirements. Further, requiring States to use the complete
model rule provides for accurate, certain, and consistent
quantification of emissions. Because emissions quantification is the
basis for applying the emissions authorization provided by each
allowance and emissions authorizations (in the form of allowances) are
the valuable commodity traded in the market, the emissions
quantification requirements of the model rule are necessary to maintain
the integrity of the cap and trade approach of the program and
therefore, to ensure that the environmental goals of the program are met.

For States Electing To Participate in the EPA-Administered Ozone-Season
CAIR NO_X Cap and Trade Program

States that wish to achieve their CAIR ozone-season requirements
through an EPA-administered ozone-season NO_X cap and trade
program will adopt the CAIR model rule in subparts AAAA through IIII.
(Note that the EPA-administered annual NO_X CAIR cap and
trade program is independent of ozone-season CAIR NO_X model
rule.) Because EPA will no longer administer the trading program for
the NO_X SIP Call, States that wish to continue to meet their
NO_X SIP Call obligations through an EPA-administered cap and
trade program will also adopt the CAIR ozone-season model rule.
NO_X SIP Call States will ``sun set'' their NO_X
SIP Call rules for sources that will move into the CAIR NO_X
ozone-season program. Part 96, sections A-J (i.e., the NO_X
SIP Call trading rule) will continue to be available for the
NO_X SIP Call and will not be removed for the CAIR. The CAIR
model rules specifically address how NO_X SIP Call allowances
carry forward into the CAIR NO_X ozone-season program.
(Section IX.A provides additional discussion of interactions between
the CAIR and the NO_X SIP Call).

For States Electing To Participate in the EPA-Administered Annual
NO_X Cap and Trade Program

States that are PM_2.5 affected and wish to participate
in an EPA-administered annual NO_X cap and trade program will
adopt the CAIR model rule in subparts AA through II. States may
participate by either adopting the model rule provisions by reference
or codifying the model rule in their State regulations.

For States Electing To Participate in the EPA-Administered
SO₂ Cap and Trade Program

States may simply adopt new provisions, whether by incorporating by
reference the CAIR SO₂ cap and Trade rule (part 96, subparts
AAA through III) or codifying the provisions of the CAIR SO₂
cap and trade rules, in order to participate in the EPA-administered
SO₂ cap and trade program. The CAIR SO₂ model
rule works in conjunction with the Acid Rain Program provisions, which
are implemented at the Federal level and will stay in place. Today's
action also finalizes some revisions to the Acid Rain Program (i.e.,
parts 72, 73, 74, 75, and 78). (Section IX.B of today's preamble
provides additional discussion of interactions between the CAIR and the
Acid Rain Program and changes to the Acid Rain Program).

Comments Regarding the Process for Adopting the Model Rules

Commenters supported EPA's proposed process and emphasized the
importance of workable model rules, because States with limited
resources are likely to incorporate them by reference or heavily rely
on them as the basis for State rules.
2. Flexibility in Adopting Model Cap and Trade Rules
It is important to have consistency on a State-to-State basis with
the basic requirements of the cap and trade approach when implementing
a multi-State cap and trade program. Such consistency ensures the:
Preservation of the integrity of the cap and trade approach so that the
required emissions reductions are achieved; smooth and efficient
operation of the trading market and infrastructure across the multi-
State CAIR region so that compliance and administrative costs are
minimized; and equitable treatment of owners and operators of regulated
sources. However, EPA believes that some limited differences are
possible without jeopardizing the environmental and other goals of the
program. Therefore, the final rule allows States to modify the model
rule language to best suit their unique circumstances in a few,
specific areas.
First, States have the flexibility to include, as full trading
partners, all trading sources affected by the NO_X SIP Call
in the ozone-season CAIR NO_X cap and trade program. This is
an outgrowth of the development of the CAIR ozone-season NO_X
program, which will be the only ozone-season NO_X cap and
trade program administered by EPA.
In addition, States may develop their own NO_X
allocations methodologies, provided allocation information is submitted
to EPA in the required timeframe. (Section VIII.D of today's preamble
discusses unit-level allocations and the related comments in greater
detail. This includes a discussion of the provisions establishing the
advance notice States must provide for unit-by-unit allocations).
Lastly, States using the model cap and trade rules may elect to
include provisions that allow individual units to ``opt-in'' to the cap
and trade programs. States that wish to include this mechanism must
adopt provisions discussed in section VIII.G of today's rulemaking.
Adopting the individual unit opt-in provisions, which would allow non-
EGUs that meet the opt-in requirements to enter into the EPA-managed
cap and trade programs, does not preclude a State from participating

[[Page 25276]]

in the EPA-administered cap and trade programs.

C. What Sources Are Affected Under the Model Cap and Trade Rules?

In the January 2004 NPR, EPA proposed a method for developing
budgets that assumed reductions only from EGUs. Electric Generating
Units were defined as: Fossil fuel-fired, non-cogeneration EGUs serving
a generator with a nameplate capacity of greater than 25 MWe; and
fossil fuel-fired cogeneration EGUs meeting certain criteria (referred
to as the ``\1/3\ potential electric output capacity criteria''). In
the SNPR, we proposed model cap and trade rules that applied to the
same categories of sources. We are finalizing the nameplate capacity
cut-off that we proposed in the NPR for developing budgets and that we
proposed in the SNPR for the applicability of the model trading rules.
We are also finalizing the ``fossil fuel-fired'' definition and the \1/
3\ electric output capacity criteria that were proposed. The actual
rule language in the SNPR describing the sources to which the model
rules apply is being slightly revised to be clearer in response to some
comments that the proposed language was not clear.
1. 25 MW Cut-Off
The EPA is retaining the 25 MW cut-off for EGUs for budget and
model rule purposes. The EPA believes it is reasonable to assume no
further control of air emissions from smaller EGUs. Available air
emissions data indicate that the collective emissions from small EGUs
are relatively small and that further regulating their emissions would
be burdensome, to both the regulated community and regulators, given
the relatively large number of such units. For example, NO_X
and SO₂ emissions from EGUs of 25 MW or less in the CAIR
region represent approximately one percent and two percent of total
NO_X and SO₂ emissions from EGUs, respectively.
There are over 4000 EGUs of 25 MW or less in the CAIR region.
Consequently, EPA believes that administrative actions to control this
large group with small emissions would be inordinate and thus does not
believe these small units should be included. This approach of using a
25 MW cut-off for EGUs is consistent with existing SO₂ and
NO_X cap and trade programs such as the NO_X SIP
Call (where existing and new EGUs at or under this cut-off are, for
similar reasons, not required to be included) and the Acid Rain Program
(where this cut-off is applied to existing units and to new units
combusting clean fuel). Also, EPA's New Source Performance Standards
use an applicability threshold of approximately 25 MW under subpart Da.
One commenter suggested a plant-wide cut-off of 250 MW. This
commenter suggested that including units between 25 and 250 MW would
cause these units to shutdown but failed to provide any analysis to
support its claim. Such a cut-off would be inconsistent with other
existing SO₂ and NO_X cap and trade programs as
noted above. The EPA estimates that approximately \1/3\ of the
SO₂ reductions, and 30 percent of the NO_X
reductions, required under today's rule come from plants between 25 MW
and 250 MW. Our modeling shows that some units below 250 MW will put on
controls as part of our highly cost-effective set of control actions.
The units also have the option to coal-switch, alter dispatch, and/or
purchase allowances.
Another commenter suggested that, in lieu of the language proposed
in the SNPR, EPA adopt a definition for EGU that, according to the
commenter, is the Acid Rain Program's definition of affected utility.
The commenter stated that the Acid Rain definition of EGU is ``all
fossil fuel-fired units with a nameplate capacity greater than 25 MW
supplying more than \1/3\ of potential electrical output to the grid.''
However, the commenter misstated the Acid Rain definition and confused
the Acid Rain applicability provisions concerning utility units in
general with those provisions concerning cogeneration units in
particular. The Acid Rain Program covers, with certain exceptions,\126\
all existing fossil fuel-fired units greater than 25 MW that produce
any electricity for sale; and new fossil fuel-fired units that produce
any electricity for sale. The language referenced by the commenter
concerning potential electrical output applies, in the Acid Rain
Program, only to cogeneration units, not all fossil fuel-fired units.
For non-cogeneration units, there is no exemption from Acid Rain
Program requirements based on the unit selling a ``small'' amount of
electricity for sale. The provisions in the NPR and the SNPR concerning
cogeneration units are discussed below.
---------------------------------------------------------------------------

\126\ For example, certain cogeneration units and new units 25
MW or less that burn only clean fuel are exempt from the Acid Rain Program.
---------------------------------------------------------------------------

2. Definition of Fossil Fuel-Fired
The EPA is finalizing the proposed definition of fossil fuel-fired,
i.e., where any amount of fossil fuel is used at any time. This is the
same definition that is used in the Acid Rain Program. One commenter
suggested that the proposed definition is too broad and that EPA should
use in the CAIR Program the same definition that is used in the
NO_X SIP Call, i.e., where a unit uses fossil fuel for at
least 50 percent of its annual heat input during a specified period.
The same commenter also proposed excluding large wood-fired boilers and
black liquor recovery furnaces. The commenter's definition would result
in units already subject to the Acid Rain Program in a given State
being excluded from the CAIR Program and the model cap and trade rules
applicable in that State. Such exclusion would make it more difficult
to coordinate the Acid Rain Program and the CAIR Program. Consequently,
EPA rejects the commenter's more restricted definition of fossil fuel-
fired.
The EPA recognizes that new (i.e., post-1990) units that are 25 MW
or less and burn other than clean fuels are subject to the Acid Rain
Program but not to the CAIR Program. However, there are very few such
units, and EPA has decided to exclude any units that are 25 MW or less
on other grounds discussed above.
3. Exemption for Cogeneration Units
As proposed, EPA is finalizing an exemption from the model cap and
trade programs for cogeneration units, i.e., units having equipment
used to produce electricity and useful thermal energy for industrial,
commercial, heating, or cooling purposes through sequential use of
energy and meeting certain operating and efficiency standards
(discussed below). The EPA is adopting the proposed definition of
cogeneration unit and the proposed criteria for determining which
cogeneration units qualify for the exemption from the model cap and
trade programs.
The CAIR trading program has different applicability provisions for
non-cogeneration units and cogeneration units. If a unit initially
qualifies as a cogeneration unit, and for the exemption from the
trading program for certain cogeneration units, but subsequently loses
its cogeneration-unit status (e.g., due to changes in operation), such
unit loses the cogeneration-unit exemption and becomes subject to the
applicability criteria for non-cogeneration units, regardless of any
future changes in the unit or its operations. If, under the non-
cogeneration unit applicability criteria, the unit becomes subject to
the trading program, the unit will remain subject to the program in the
future. Conversely if a unit initially does not qualify as a
cogeneration unit, such unit becomes subject to the applicability
criteria for non-cogeneration units, regardless of

[[Page 25277]]

any future changes in the unit. If, under such criteria, the unit is
subject to the trading program, the unit will remain subject to the
program in the future. This approach to applicability means that units
(other than, in some cases, opt-in units) cannot go in and out of the
trading program, which, if allowed, would make it difficult for EPA,
States, and owners or operators to determine which units should be
complying with trading program requirements, and during what years, and
would likely result in more non-compliance problems.
a. Efficiency Standard for Cogeneration Units
The EPA proposed operating and efficiency standards (i.e., the
useful thermal energy output of the unit must be no less than a certain
percent of the total energy output and, in some cases, useful power
must be no less than a certain percent of total energy input) in the
SNPR that a unit must meet in order to qualify as a cogeneration unit.
If the unit qualifies as a cogeneration unit, then it may be eligible
for exemption from the CAIR, depending upon whether it meets additional
operating criteria, discussed below. As discussed in the NPR, EPA
proposed the same operating and efficiency standards for all fossil
fuel-fired units (regardless of whether they burn coal, oil, or gas).
In addition, not applying the operating and efficiency standards to
coal-fired units would be counter productive to EPA's efforts to reduce
SO₂ and NO_X emissions under this proposed rule
because of the relatively high SO₂ and NO_X
emissions from coal-fired units. In particular, without application of
the efficiency standards to coal-fired units, highly inefficient coal-
fired units, which have particularly high emissions per MWhr generated,
could be exempt from the CAIR Program. In addition, if coal-fired units
were not subject to the operating standard, the potential would exist
for a coal-fired unit to provide only a token amount of useful thermal
energy and still qualify for a cogeneration unit exemption from the
CAIR Program, despite having relatively high emissions.
One commenter suggested that EPA should not use the efficiency
standards for solid fuel-fired cogeneration units, because it may
require some coal-fired cogeneration units that were exempt from the
Acid Rain Program to purchase CAIR allowances. However, the EPA
analysis indicates that most existing solid fuel-fired cogeneration
units affected by this rule will meet the proposed standard. See TSD
entitled ``Cogeneration Unit Efficiency Calculations'' in the docket.
To the extent any solid fuel-fired cogeneration units cannot meet the
efficiency standard and become affected units under the CAIR, EPA
believes that, considering their relatively high emissions of
SO₂ and NO_X compared to oil and gas-fired units,
it is important to require these sources to meet the efficiency
standards or be subject to the emission limits under the CAIR Program.
Another commenter suggested that the efficiency standards should
not apply to solid fuel-fired cogeneration units because solid fuel-
fired unit efficiency is based on HHV (higher heating value) while gas,
or oil-fired unit efficiency is based on LHV (lower heating value). The
EPA analyzed a range \127\ of solid fuel-fired cogeneration units and
calculated their efficiencies to see if they would meet the minimum
efficiency standard. All of the units selected satisfied the proposed
efficiency standard. See TSD entitled ``Cogeneration Unit Efficiency
Calculations'' in the docket. As a result, EPA believes that most solid
fuel-fired cogeneration units will meet the proposed efficiency
standard. The efficiency standard EPA is adopting is the Public Utility
Regulatory Act (PURPA) of thermal efficiency of 42.5 percent. See TSD
entitled, ``Cogeneration Unit Efficiency Calculations'' for further
discussion, is based on LHV. If the efficiency of a solid-fuel-fired
unit is expressed in terms of HHV, it can easily be converted to LHV
for purposes of determining whether it meets the efficiency standard.
Therefore, the reason given by the commenter (that solid fuel-fired
unit efficiency is expressed in terms of HHV) is not grounds for not
applying an efficiency standard to these units. One commenter supported
applying the same efficiency standard to solid fuel-fired units as EPA
proposed. The EPA is finalizing its proposed cogeneration unit
definition, which applies the same operating and efficiency standards
to all units regardless of the type of fossil fuel burned.
---------------------------------------------------------------------------

\127\ The range included solid fuel-fired cogeneration units
from 25 MW to 250 MW.
---------------------------------------------------------------------------

b. One-third Potential Electric Output Capacity
The EPA is finalizing the \1/3\ potential electric output capacity
criteria in the NPR and SNPR. Under the proposals, the following
cogeneration units are EGUs: Any cogeneration unit serving a generator
with a nameplate capacity of greater than 25 MW and supplying more than
\1/3\ potential electric output capacity and more than 219,000 MW-hrs
annually to any utility power distribution system for sale. These
criteria are similar to those used in the Acid Rain Program to
determine whether a cogeneration unit is a utility unit and the
NO_X SIP Call to determine whether a cogeneration unit is an
EGU or a non-EGU. The primary difference between the proposed criteria
and the \1/3\ potential electric criteria for the Acid Rain and
NO_X SIP Call Programs is that these programs applied the
criteria to the initial operation of the unit and then to 3-year
rolling average periods while the proposed CAIR criteria are applied to
each individual year starting with the commencement of operation. The
EPA believes that using an individual year approach would streamline
the application and administration of this exemption. No adverse
comments were received on using an individual year approach as opposed
to a 3-year rolling average. In addition, the criteria under the Acid
Rain Program and the NO_X SIP Call are applied somewhat
differently to units commencing construction on or before November 15,
1990 and units commencing construction after November 15, 1990. Several
commenters suggested exempting all cogeneration units under the PURPA
instead of using the proposed criteria and cite the high efficiency of
cogeneration as a reason for a complete exemption. The EPA believes it
is important to include in the CAIR Program all units, including
cogeneration units, that are substantially in the business of selling
electricity. The proposed \1/3\ potential electric output criteria
described above are intended to do that.
Inclusion of all units substantially in the electricity sales
business minimizes the potential for shifting utilization, and
emissions, from regulated to unregulated units in that business and
thereby freeing up allowances, with the result that total emissions
from generation of electricity for sale exceed the CAIR emissions caps.
The fact that units in the electricity sales business are generally
interconnected through their access to the grid significantly increases
the potential for utilization shifting.
One commenter suggested that the \1/3\ of potential electric output
capacity criteria be applied on an annual basis. The EPA agrees that
the criteria should be applied annually. The proposed and final model
cap and trade rules adopt that approach.
c. Clarifying ``For Sale''
Several commenters requested EPA confirm that, for purposes of
applying the \1/3\ potential electric output criteria,

[[Page 25278]]

simultaneous purchases and sales of electricity are to be measured on a
``net'' basis, as is done in the Acid Rain Program. At least one
commenter suggested that the net approach also be applied to purchase
and sales that are not simultaneous. For purposes of applying the \1/3\
potential electric output criteria in the CAIR Program and the model
cap and trade rules, EPA confirms that the only electricity that counts
as a sale is electricity produced by a unit that actually flows to a
utility power distribution system from the unit. Electricity that is
produced by the unit and used on-site by the electricity-consuming
component of the facility will not count, including cogenerated
electricity that is simultaneously purchased by the utility and sold
back to such facility under purchase and sale agreements under the
PURPA. However, electric purchases and sales that are not simultaneous
will not be netted; the \1/3\ potential electric output criteria will
be applied on a gross basis, except for simultaneous purchase and
sales. This is consistent with the approach taken in the Acid Rain Program.
d. Multiple Cogeneration Units
Some commenters suggested aggregating multiple cogeneration units
that are connected to a utility distribution system through a single
point when applying the \1/3\ potential electric output capacity
criteria. These commenters suggested that it is not feasible to
determine which unit is producing the electricity exported to the
outside grid. The EPA proposed to determine whether a unit is affected
by the CAIR on an individual-unit basis. This unit-based approach is
consistent with both the Acid Rain Program and the NO_X SIP
Call. The EPA considers this approach to be feasible based on
experience from these existing programs, including for sources with
multiple cogeneration units. The EPA is unaware of any instances of
cogeneration unit owners being unable to determine how to apply the \1/
3\ potential electric output capacity criteria where there are multiple
cogeneration units at a source.
In a case where there are multiple cogeneration units with only one
connection to a utility power distribution system, the electricity
supplied to the utility distribution system can be apportioned among
the units in order to apply the \1/3\ potential electric output
capacity criteria. A reasonable basis for such apportionment must be
developed based on the particular circumstances. The most accurate way
of apportioning the electricity supplied to the utility power
distribution system seems to be apportionment based on the amount of
electricity produced by each unit during the relevant period of time.
Exemption for Independent Power Production (IPP) Facilities: Some
commenters stated that certain IPP facilities are exempt from the Acid
Rain Program and that they should also be exempt from the CAIR Program
and model-cap and trade rules. Under the Acid Rain Program, an IPP
facility that has, as of November 15, 1990, a qualifying power purchase
commitment (including a sales price) to sell at least 15 percent of
planned net output capacity and has installed net output capacity not
exceeding 130 percent of planned net output capacity is exempt.
However, if the power purchase commitment changes after November 15,
1990 in a way that allows the cost of compliance with the Acid Rain
Program to be shifted to the purchaser, then the IPP facility loses the
exemption. For example, expiration or termination of the power purchase
commitment or modification so that the price is increased (e.g.,
changed to a market price) results in loss of the exemption. The
purpose of the exemption is to protect IPP facilities subject to
contract prices that were set before passage of the CAA Amendments of
1990 (including the Acid Rain Program in title IV) and that did not
allow passthrough of the costs of Acid Rain Program compliance.
However, EPA maintains that this exemption was aimed at easing the
transition of such facilities into the Acid Rain Program and that there
is no basis for maintaining this exemption for every subsequent cap and
trade program. In addition, this exemption was not used in the
NO_X SIP Call.

D. How Are Emission Allowances Allocated to Sources?

It is important to have consistency on a State-by-State basis with
the basic requirements of the cap and trade approach when implementing
a multi-State cap and trade program. This will ensure that: The
integrity of the cap and trade approach is preserved so that the
required emissions reductions are achieved; the compliance and
administrative costs are minimized; and source owners and operators are
equitably treated. However, EPA believes that some limited differences,
such as allowance allocation methodologies for NO_X
allowances, are possible without jeopardizing the environmental and
other goals of the program.
1. Allocation of NO_X and SO₂ Allowances
Each State participating in EPA-administered cap and trade programs
must develop a method for allocating (i.e., distributing) an amount of
allowances authorizing the emissions tonnage of the State's CAIR EGU
budget. For NO_X allowances, each State has the flexibility
to allocate its allowances however they choose, so long as certain
timing requirements are met.
For SO₂, as noted in the January 2004 proposal, States
will have no discretion in their allocation approach since the CAIR
SO₂ cap and trade program uses title IV SO₂
allowances, which have been already allocated in perpetuity to
individual units by title IV of the CAA.
a. Required Aspects of a State NO_X Allocation Approach
While it is EPA's intent to provide States with as much flexibility
as possible in developing allocation approaches, there are some aspects
of State allocations that must be consistent for all States. All State
allocation systems are required to include specific provisions that
establish when States notify EPA and sources of the unit-by-unit
allocations. These provisions establish a deadline for each State to
submit to EPA its unit-by-unit allocations for processing into the
electronic allowance tracking system. Since the Administrator will then
expeditiously record the submitted allowance allocations, sources will
thereby be notified of, and have access to, allocations with a minimum
lead time (about 3 years) before the allowances can be used to meet the
NO_X emission limit.
Today's action finalizes the proposal to require States to submit
unit-by-unit allocations of allowances for a given year no less than 3
years prior to January 1 of the allowance vintage year, which approach
was supported by commenters.\128\ Requiring States to submit
allocations and thereby provide a minimum lead time before the
allowances can be used to meet the NO_X emission limit
ensures that an affected source--regardless of the State in the CAIR
region in which the unit is located--will have sufficient time to plan
for compliance and implement their compliance planning. Allocating
allowances less than 3 years in advance of the compliance year may
reduce a CAIR unit's ability to plan for and implement compliance and,

[[Page 25279]]

consequently, increase compliance costs. For example, a shorter lead
time would reduce the period for buying or selling allowances and could
prevent sources from participating in allowance futures markets, a
mechanism for hedging risk and lowering costs.
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\128\ If the deadline for States to submit SIPs is September of
2006, then this would result in notification period of less than 3
years for the first year of CAIR.
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Further, requiring a uniform, minimum lead-time for submission of
allocations allows EPA to perform its allocation-recordation activities
in a coordinated and efficient manner in order to complete
expeditiously the recordation for the entire CAIR region and thereby
promote a fair and competitive allowance market across the region.
These minimum requirements apply to the NO_X allocation
approach and are not relevant for the SO₂ cap and trade
program, which relies on title IV allowances.
b. Flexibility and Options for a State NO_X Allowance
Allocations Approach
Allowance allocation decisions in a cap-and-trade program raise
essentially distributional issues, as economic forces are expected to
result in economically efficient and environmentally similar outcomes
regardless of the manner in which allowances are initially distributed.
Consequently, for CAIR NO_X allowances, States are given
latitude in developing their allocation approach. NO_X
allocation methodology elements for which States will have flexibility
include:
A. The cost of the allowance distribution (e.g., free distribution
or auction);
B. The frequency of allocations (e.g., permanent or periodically
updated);
C. The basis for distributing the allowances (e.g., heat-input or
power output); and,
D. The use of allowance set-asides and their size, if used (e.g.,
new unit set-asides or set-asides for energy efficiency, for
development of Integrated Gasification Combined Cycle (IGCC)
generation, for renewables, or for small units).
Some commenters have argued against giving States flexibility in
determining NO_X allocations, citing concerns about
complexity of operating in different markets and about the robustness
of the trading system. The EPA maintains that offering such
flexibility, as it did in the NO_X SIP Call, does not
compromise the effectiveness of the trading program.
A number of commenters have argued against allowing (or requiring)
the use of allowance auctions, while others did not believe that EPA
should recommend auctions. For today's final action, while there are
some clear potential benefits to using auctions for allocating
allowances (as noted in the SNPR), EPA believes that the decision
regarding utilizing auctions should ultimately be made by the States.
Therefore, EPA is not requiring, restricting, or barring State use of
auctions for allocating allowances.
A number of commenters supported allowing the use of allowance set-
asides for various purposes. In today's final action, EPA is leaving
the decision on using set-asides up to the States, so that States may
craft their allocation approach to meet their State-specific policy goals.
i. Example Allowance Allocation Methodology
In the SNPR, EPA included an example (offered for informational
guidance) of an allocation methodology that includes allowances for new
generation and is administratively straightforward. In today's
preamble, EPA is including in today's preamble, this ``modified
output'' example allocations approach, as was outlined in the SNPR.
The EPA maintains that the choice of allocation methodology does
not impact the achievement of the specific environmental goals of the
CAIR Program. This methodology is offered simply as an example, and
individual States retain full latitude to make their own choices
regarding what type of allocation method to adopt for NO_X
allowances and are not bound in any way to adopt EPA's example.
This example method involves input-based allocations for existing
fossil units, with updating to take into account new generation on a
modified-output basis. It also utilizes a new source set-aside for new
units that have not yet established baseline data to be used for
updating. Providing allowances for new sources addresses a number of
commenter concerns about the negative effect of new units not having
access to allowances.
Under the example method, allocations are made from the State's EGU
NO_X budget for the first five control periods (2009 through
2013) of the model cap and trade program for existing sources on the
basis of historic baseline heat input. Commenters expressed some
concern regarding the proposed January 1, 1998 cut-off on-line date for
considering units as existing units. The cut-off on-line date was
selected so that any unit meeting the cut-off date would have at least
5 years of operating data, i.e., data for 1998 through 2002 (which was
the last year for which annual data was available). The EPA is still
concerned with ensuring that particular units are not disadvantaged in
their allocations by having insufficient operating data on which to
base the allocations. The EPA believes that a 5 year window, starting
from commencement of operation, gives units adequate time to collect
sufficient data to provide a fair assessment of their operations.
Annual operating data is now available for 2003. The EPA is finalizing
January 1, 2001 as the cut-off on-line date for considering units as
existing units since units meeting the cut-off date will have at least
5 years of operating data (i.e., data for 2001 through 2005).
The allowances for 2014 and later will be allocated from the
State's EGU NO_X budget annually, 6 years in advance, taking
into account output data from new units with established baselines
(modified by the heat input conversion factor to yield heat input
numbers). As new units enter into service and establish a baseline,
they are allocated allowances in proportion to their share of the total
calculated heat input (which is existing unit heat input plus new
units' modified output). Allowances allocated to existing units slowly
decline as their share of total calculated heat input decreases with
the entry of new units.
After 5 years of operation, a new unit will have an adequate
operating baseline of output data to be incorporated into the
calculations for allocations to all affected units. The average of the
highest 3 years from these 5 years will be multiplied by the heat-input
conversion factor to calculate the heat input value that will be used
to determine the new unit's allocation from the pool of allowances for
all sources.
Under the EPA example method, existing units as a group will not
update their heat input. This will eliminate the potential for a
generation subsidy (and efficiency loss) as well as any potential
incentive for less efficient existing units to generate more. This
methodology will also be easier to implement since it will not require
the updating of existing units' baseline data. Retired units will
continue to receive allowances indefinitely, thereby creating an
incentive to retire less efficient units instead of continuing to
operate them in order to maintain the allowances allocations.
Moreover, new units as a group will only update their heat input
numbers once--for the initial 5-year baseline period after they start
operating. This will eliminate any potential generation subsidy and be
easier to implement, since it will not require the collection

[[Page 25280]]

and processing of data needed for regular updating.
The EPA believes that allocating to existing units based on a
baseline of historic heat input data (rather than output data) is
desirable, because accurate protocols currently exist for monitoring
this data and reporting it to EPA, and several years of certified data
are available for most of the affected sources. The EPA expects that
any problems with standardizing and collecting output data, to the
extent that they exist, can be resolved in time for their use for new
unit calculations. Given that units keep track of electricity output
for commercial purposes, this is not likely to be a significant problem.
A number of commenters expressed support for EPA's proposal in the
SNPR that the heat input data for existing units be adjusted by
multiplying it by different factors based on fuel-type. Contrary to
some commenters' claims, determining allocations with fuel factors
would not create disincentives for efficiency. With the use of a single
baseline for existing units, neither adjusted input, nor input, nor
output based allocations would provide additional incentives for energy
efficiency. All sources have incentives to reduce emissions (improving
efficiency is a way of doing this) as a result of the cap and trade
program, not because of the choice of an allocation based on a single
historic baseline.
The EPA acknowledges that since allowances have value, different
allocations of allowances clearly do impact the distribution of wealth
among different generators. However, in general, the economics of power
generation dictate that generators selling power will seek to operate
(and burn fuel) to meet energy demand in a least-cost manner. The cost
of the power generated (reflecting the bid price per megawatt hour)
will include the cost of allowances to cover emissions, whether the
generator uses allowances that it already owns, or whether it needs to
purchase additional allowances. With a liquid market for allowances,
allocations for existing sources (whose baseline does not change) are a
sunk benefit or sunk cost, not impacting the existing generator's
behavior on the margin. Thus, the use of fuel factors in our allocating
method would not be expected to result in changes in generators'
choices for fuel efficiency.
In its example allocation approach, EPA is including adjustments of
heat input by fuel type based on average historic NO_X
emissions rates by three fuel types (coal, natural gas, and oil) for
the years 1999-2002. As noted in the SNPR, such calculations would lead
to adjustment factors of 1.0 for coal, 0.4 for gas and 0.6 for oil. The
factors would reflect the inherently different emissions rates of
different fossil-fired units (and consequently also reflect the
different burdens to control emissions.
However, allocating to new (not existing) sources on the basis of
input (and particularly fuel-adjusted heat input) would serve to
subsidize less-efficient new generation. For a given amount of
generation, more efficient units will have the lower fuel input or heat
input. Allocating to new units based on heat input could encourage the
building of less efficient units since they would get more allowances
than an equivalent efficient, lower heat-input unit. The modified
output approach, as described below, will encourage new, clean
generation, and will not reward less efficient new coal units or less
efficient new gas units.
Under the example method, allowances will be allocated to new units
of each fuel-type with an appropriate baseline on a ``modified output''
basis. The new unit's modified output will be calculated by multiplying
its gross output by a heat rate conversion factor of 7,900 btu/kWh for
coal units and 6,675 btu/kWh for oil and gas units. The 7,900 btu/kWh
value for the conversion factor for new coal units is an average of
heat-rates for new pulverized coal plants and new IGCC coal plants
(based upon assumptions in EIA's Annual Energy Outlook (AEO) 2004
\129\). The 6,675 btu/kWh value for the conversion factor for new gas
units is an average of heat-rates for new combined cycle gas units
(also based upon assumptions in EIA's AEO 2004). A single conversion
rate for each fuel-type will create consistent and level incentives for
efficient generation, rather than favoring new units with higher heat-rates.
---------------------------------------------------------------------------

\129\ Energy Information Administration, ``Annual Energy Outlook
2004, With Projections to 2025'', January 2004. Assumptions for the
NEMS model. http://www.eia.doe.gov/oiaf/archive/aeo04/assumption/tbl38.html.

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

For new cogeneration units, their share of the allowances will be
calculated by converting the available thermal output (btu) of useable
steam from a boiler or useable heat from a heat exchanger to an
equivalent heat input by dividing the total thermal output (btu) by a
general boiler/heat exchanger efficiency of 80 percent.
New combustion turbine cogeneration units will calculate their
share of allowances by first converting the available thermal output of
useable steam from a heat recovery steam generator (HRSG) or useable
heat from a heat exchanger to an equivalent heat input by dividing the
total thermal output (btu) by the general boiler/heat exchanger
efficiency of 80 percent. To this they will add the electrical
generation from the combustion turbine, converted to an equivalent heat
input by multiplying by the conversion factor of 3,413 btu/kWh. This
sum will yield the total equivalent heat input for the cogeneration unit.
Steam and heat output, like electrical output, is a useable form of
energy that can be utilized to power other processes. Because it would
be nearly impossible to adequately define the efficiency in converting
steam energy into the final product for all of the various processes,
this approach focuses on the efficiency of a cogeneration unit in
capturing energy in the form of steam or heat from the fuel input.
Commenters expressed concern about a single conversion factor,
arguing for different factors for different fuels and technologies. The
EPA recognizes these concerns and agrees that different new fossil-
generation units have inherently different heat rates, largely dictated
by the technology needed to burn different fuels. A single conversion
rate for all units would provide new gas-fired combined cycle units
with relatively more allowances, relative to their emissions, than it
would for new coal-fired units.
The EPA maintains that providing each new source an equal amount of
allowances per MWh of output, given the fuel it is burning, is an
equitable approach. Since electricity output is the ultimate product
being produced by EGUs, a single conversion factor for each fuel, based
on output, ensures that all new sources burning a particular fuel will
be treated equally.
Some commenters support allocating allowances to all new
generation, not just fossil fuel-fired CAIR units. The EPA notes that
including new non-CAIR and non-fossil units in the allowance
distribution would raise issues, about which EPA lacks sufficient
information for resolution at this time for EPA's example method. It
would be necessary to clearly define what types of generating
facilities that could participate and what would constitute ``new''
non-fossil generation.\130\ Commenters did not provide any analysis of
the impact of possible definitions on generation mix, or electricity
markets. Further, in order to include all generation, there would be a
need to establish application and data

[[Page 25281]]

collections procedures and determine appropriate size cut-offs and
boundaries of this generation--since in many such instances there is no
clear analog to discrete fossil ``units.'' \131\ There also are
associated issues about developing appropriate measurement and data
reporting requirements for such sources. Commenters supporting this
approach did not address any of these matters in any detail. However,
EPA encourages States that are interested in including such units in
their updating allocations to consider potential solutions and include
them in their SIPs. Under the example method, new units that have
entered service, but have not yet started receiving allowances through
the update, will receive allowances each year from a new source set-
aside. The new source allowances from the set-aside will be distributed
based on their actual emissions from the previous year. Such an
allocation approach will generally provide new units sufficient
allowances to cover their emissions during the interim period before
the units are allocated allowances on the same basis as existing units.
Today's example method includes a new source set-aside equal to 5
percent of the State's emission budget for the years 2009-2013 and 3
percent of the State's emission budget for the subsequent years. In the
SNPR, EPA proposed a level 2 percent set-aside for all years.
---------------------------------------------------------------------------

\130\ Some commenters stated that, if allocations were provided
for non-emitting new generation, they also should be provided to all
such generation, including nuclear units.
\131\ For instance, would the addition of a single new wind
turbine at a wind-farm constitute a ``new unit''?
---------------------------------------------------------------------------

Commenters noted their concern that the amount of the set-aside in
the early years of the program should be higher to reflect the fact
that the set-aside will initially need to accommodate all new units
entering into service from 1998 through 2010.\132\ In order to estimate
the need for allocations for new units, EPA looked at the
NO_X emissions from units that went online starting in 1999
as projected by the Integrated Planning Model (IPM) runs modeling CAIR
for the years 2010 and 2015. These IPM emissions projections indicated
over 57,000 tons of NO_X emissions in 2010 and about 74,000
tons of NO_X emission by 2015 from new sources need to be
covered under set-asides throughout the CAIR region. The 2010 number
represents almost 4 percent of the Phase I NO_X regional cap,
while the 2015 number represents about 6 percent of the Phase I
regional cap. Consequently, today's example method includes a 5 percent
set-aside for the initial period (2009-2013). It should be noted that
by 2014, the set-aside would need to cover new sources from the entire
period 2004-2013.
---------------------------------------------------------------------------

\132\ As noted earlier in this section, EPA is now considering
new units to be those that went online after January 1, 2001 rather
than 1998.
---------------------------------------------------------------------------

The choice of a 3 percent new source set-aside, starting in 2014,
reflects concerns that adequate allowances be provided for the 10 years
of new units to be covered by the set-aside in 2014 and subsequent
years. (The set-aside in 2014, for example, would need to accommodate
all units that went on-line between 2004 and 2013).
Individual States using a version of the example method may want to
adjust this initial 5 year set-aside amount to a number higher or lower
than 5 percent to the extent that they expect to have more or less new
generation going on-line during the 2001-2013 period. They may also
want to adjust the subsequent set-aside amount to a number higher or
lower than 3 percent to the extent that they expect more or less new
generation going on-line after 2004. States may also want to set this
percentage a little higher than the expected need, since, in the event
that the amount of the set-aside exceeds the need for new unit
allowances, the State may want to provide that any unused set-aside
allowances will be redistributed to existing units in proportion to
their existing allocations.
For the example method, EPA is finalizing the approach that new
units will begin receiving allowances from the set-aside for the
control period immediately following the control period in which the
new unit commences commercial operation, based on the unit's emissions
for the preceding control period. Thus, a source will be required to
hold allowances during its start-up year, but will not receive an
allocation for that year.
States will allocate allowances from the set-aside to all new units
in any given year as a group. If there are more allowances requested
than in the set-aside, allowances will be distributed on a pro-rata
basis. Allowance allocations for a given new unit in following years
will continue to be based on the prior year's emissions until the new
unit establishes a baseline, is treated as an existing unit, and is
allocated allowances through the State's updating process. This will
enable new units to have a good sense of the amount of allowances they
will likely receive--in proportion to their emissions for the previous
year. This methodology will not provide allowances to a unit in its
first year of operation; however it is a methodology that is
straightforward, reasonable to implement, and predictable.
In the SNPR, the example method from the NO_X SIP Call
model rule was proposed as an alternate approach.\133\ However, the EPA
has found this approach to be complicated for both the States and the
EPA to implement. Additionally, the NO_X SIP Call approach
would introduce a higher level of uncertainty for sources in the
allocation process than necessary.
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\133\ With the alternate approach from the NO_X SIP
Call. States could distribute a new source set-aside for a control
period based on full utilization rates, at the end of the year the
actual allowance allocation would be adjusted to account for actual
unit utilization/output, and excess allowances would be returned and
redistributed, first taking into account new unit requests that were
not able to be addressed.
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While the EPA is offering an example allocation method with
accompanying regulatory language, the EPA reiterates that it is giving
States' flexibility in choosing their NO_X allocations method
so they may tailor it to their unique circumstances and interests.
Several commenters, for instance, have noted their desire for full
output-based allocations (in contrast to the hybrid approach in the
example above). In the past, EPA had sponsored a work group to assist
States wishing to adopt output-based NO_X allocations for the
NO_X SIP Call and believes it is a viable approach worth
considering. Documents from meetings of this group and the resulting
guidance report (found at http://www.epa.gov/airmarkets/fednox/workgrp.html)
together with additional resources such as the EPA-
sponsored report ``Output-Based Regulations: A Handbook for Air
Regulators'' (found at http://www.epa.gov/cleanenergy/pdf/output_rpt.pdf)
can help States, should they choose to adopt any output-based
elements in their allocation plans.
As an another alternative example, States could decide to include
elements of auctions into their allowance allocation programs.\134\ An
example of an approach where CAIR NO_X allowances could be
distributed to sources through a combination of an auction and a free
allocation is provided below.
---------------------------------------------------------------------------

\134\ Auctions could provide States with a non-distortionary
source of revenue.
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During the first year of the trading program, 94 percent of the
NO_X allowances could, for example, be allocated to affected
units with an auction held for the remaining 1 percent of the
NO_X allowances \135\. Each subsequent year, an additional 1
percent of the allowances (for the first 20 years of the program), and
then an additional 2.5 percent thereafter, could be auctioned until
eventually all the allowances are auctioned. With such a system, for
the first 20 years of the

[[Page 25282]]

trading programs, the majority of allowances would be distributed for
free via the allocation. Allowances allocated for these earlier years
are generally more valuable than allowances allocated for later years
because of the time value of money. Thus, most emitting units would
receive relatively more allowances in the early years of the program,
when they are facing the expenses of taking actions to control their
emissions. Even though the proportion of allowances allocated to
existing sources declines in the later years of the program, these
sources receive for free a very significant share of the total value of
allowances (because the discounted present value of allowances
allocated in the early years of the program is greater than the
discounted present value of the allowances auctioned later).
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\135\ 5 percent of the allowances would go to a new source set-aside.
---------------------------------------------------------------------------

Auctions could be designed by the State to promote an efficient
distribution of allowances and a competitive market. Allowances would
be offered for sale before or during the year for which such allowances
may be used to meet the requirement to hold allowances. States would
decide on the frequency and timing of auctions. Each auction would be
open to any person, who would submit bids according to auction
procedures, a bidding schedule, a bidding means, and by fulfilling
requirements for financial guarantees as specified by the State.
Winning bids, and required payments, for allowances would be determined
in accordance with the State program and ownership of allowances would
be recorded in the EPA Allowance Tracking System after the required
payment is received.
The auction could be a multiple-round auction. Interested bidders
would submit before the auction, one or more initial bids to purchase a
specified quantity of NO_X allowances at a reserve price
specified by the State, specifying the appropriate account in the
Allowance Tracking System in which such allowances would be recorded.
Each bid would be guaranteed by a certified check, a funds transfer,
or, in a form acceptable to the State, a letter of credit for such
quantity multiplied by the reserve price. For each round of the
auction, the State would announce current round reserve prices for
NO_X and determine whether the sum of the acceptable bids
exceeds the quantity of such allowances, available for auction. If the
sum of the acceptable bids for NO_X allowances exceeds the
quantity of such allowances the State would increase the reserve price
for the next round. After the auction, the State would publish the
names of winning and losing bidders, their quantities awarded, and the
final prices. The State would return payment to unsuccessful bidders
and add any unsold allowances to the next relevant auction.
In summary, today's action provides, for States participating in
the EPA-administered CAIR NO_X cap and trade program, the
flexibility to determine their own methods for allocating
NO_X allowances to their sources. Specifically, such States
will have flexibility concerning the cost of the allowance
distribution, the frequency of allocations, the basis for distributing
the allowances, and the use and size of allowance set-asides.

E. What Mechanisms Affect the Trading of Emission Allowances?

1. Banking
a. The CAIR NPR and SNPR Proposal for the Model Rules and Input From
Commenters
Banking is the retention of unused allowances from 1 calendar year
for use in a later calendar year. Banking allows sources to make
reductions beyond required levels and ``bank'' the unused allowances
for use later. Generally speaking, banking has several advantages: It
can encourage earlier or greater reductions than are required from
sources, stimulate the market and encourage efficiency, and provide
flexibility in achieving emissions reductions goals. When sources
reduce their SO₂ and NO_X emissions in the early
phases, the cap and trade program creates an emissions ``glide path''
that provides earlier environmental benefits and lower cost of
compliance. This ``glide path'' does allow emissions to exceed the cap
and trade program budget--especially in the initial years after the
adoption of a more stringent cap. The use of banked allowances from the
Acid Rain and NO_X SIP Call Programs in the CAIR
NO_X and SO₂ cap and trade programs is discussed
below in section VIII.F of this preamble.
The January 30, 2004 CAIR NPR and June 10, 2004 CAIR SNPR proposed
that the CAIR NO_X and SO₂ cap and trade programs
allow banking and the use of banked allowances without restrictions.
Allowing unrestricted banking and the use of banked allowances is
consistent with the existing Acid Rain SO₂ cap and trade
program. The NO_X SIP Call cap and trade program, however,
has some restrictions on the use of banked allowances, a procedure
called ``flow control,'' described in detail in the June 10, 2004 CAIR
SNPR.
Comments Regarding Unrestricted Banking After the Start of the CAIR
NO_X and SO₂ Cap and Trade Programs
Many commenters supported the EPA's proposal to allow unrestricted
banking and the use of banked allowances for both SO₂ and
NO_X, agreeing that flow control is a complex and confusing
procedure with undemonstrated environmental benefit. Further, they
agreed that banking with no restrictions on use will encourage early
emissions reductions, stimulate the trading market, encourage efficient
pollution control, and provide flexibility to affected sources in
meeting environmental objectives.
Other commenters objected to the EPA's proposal to allow
unrestricted use of banked allowances. All of these commenters
supported some use of flow control in the CAIR cap and trade programs,
most supporting its use for both SO₂ and NO_X.
Some commenters disagreed with the EPA's assessment that the use of
flow control in the Ozone Transport Commission (OTC) cap and trade
program was complicated to understand and implement and caused market
complexity. One commenter further elaborated that flow control was
accepted by industry. Another commenter claimed that the EPA has not
analyzed the impact of the flow control mechanism.
Some commenters supportive of flow control stated that flow control
was ``successful'' in the OTC and NO_X SIP Call trading
programs and ``worked well'' and ``achieved the desired effect,''
without supporting those statements.
b. The Final CAIR Model Rules and Banking
The EPA acknowledges that the OTC NO_X cap and trade
program has functioned for several years despite the complexity
introduced by the flow control procedures. Industry and other allowance
traders have adapted to these complex procedures, yet there are ongoing
questions from the regulated community about how the procedures
actually work. As an example, one commenter, while disagreeing with the
EPA's assertion that flow control is overly complex, goes on to
describe incorrectly the implementation of flow control. The
NO_X SIP Call cap and trade program includes similar
procedures but flow control was not triggered in the first 2 years of
the program (2003 and 2004), so there is no experience to be drawn from
that program.
The EPA maintains that the benefits of utilizing these complex
procedures is questionable. The EPA has analyzed the

[[Page 25283]]

use of the flow control procedures in a paper released in March 2004,
``Progressive Flow Control in the OTC NO_X Budget Program:
Issues to Consider at the Close of the 1999 to 2002 Period.'' The
lessons learned from this analysis were as follows:
(1) Flow control can create market pricing complexity and
uncertainty. The need for implementation of flow control for a
particular control period is not known more than a few months in
advance, and the value of banked allowances varies from year to year,
depending on whether flow control has been triggered for the particular
year. Therefore, when deciding how much to control, a source has some
increased uncertainty about the value of any excess allowances it generates.
(2) Flow control can have a bigger impact on small entities than on
large entities. Large firms with multiple allowance accounts can shift
banked allowances among those accounts to minimize the number of banked
allowances surrendered at a discounted rate.
(3) Flow control does not directly affect short-term emissions, so
it may not serve the environmental goals for which it was created.
Incorporating these lessons learned, the EPA is finalizing the CAIR
NO_X and SO₂ cap and trade programs with no flow
control mechanism.
2. Interpollutant Trading Mechanisms
a. The CAIR NPR Proposal for the Model Rules and Input From Commenters
Mechanisms for interpollutant trading allow reduced emissions of
one pollutant to be exchanged for increased emissions of another
pollutant where both pollutants cause the same environmental problem
(e.g., are precursors of a third pollutant). Interpollutant trading
mechanisms are typically based upon each precursor's contribution to a
particular environmental problem and are often controversial and
scientifically difficult to design because of the complexities of
environmental chemistry. Determination of conversion factors (i.e.,
transfer ratios that relate the impact of one pollutant to the impact
of another pollutant) can be dependent upon location, the presence of
other pollutants that are necessary for chemical reactions, the time of
emissions, and other considerations.
The January 30, 2004 CAIR NPR did not propose a specific
interpollutant trading mechanism but rather took comment on
interpollutant trading in general as well as the following specific issues:
(1) What would be the exchange rate (i.e., the transfer ratio) for
the two pollutants,
(2) How can the transfer ratio best achieve the goals of
PM_2.5 and ozone reductions in downwind States and,
(3) How would the interpollutant trading accommodate the different
geographic regions of the PM_2.5 and ozone programs?
Comments Regarding the Potential Interpollutant Trading
The EPA received several comments on interpollutant trading with
the most commenters generally opposed to including provisions to allow
for the interchangability of SO₂ and NO_X allowances.
Several commenters pointed out that the CAIR ozone attainment
benefits result from the NO_X emissions reductions, and
contend that the EPA has not shown that SO₂ emissions impact
ozone. Therefore, the commmenters conclude that it would be
inappropriate for SO₂ allowances to be traded and used for
compliance with the NO_X cap. Some commenters supported the
consideration or use of interpollutant trading if it was one-
directional, i.e., NO_X allowances could be used for
compliance with the SO₂ allowance holding requirements, but
not vice versa. This could result in fewer NO_X emissions and
more SO₂ emissions.
Some commenters supported the consideration or use of
interpollutant trading and emphasized the scientific difficulty in
developing accurate transfer ratios. Of these commenters, some added
that interpollutant trading would be appropriate if the EPA conducted a
thorough analysis of the potential impacts that interpollutant trading
would have on: nonattainment areas' ability to come into attainment;
the allowance markets and prices; and the integrity of the
NO_X caps in light of the potentially large SO₂
allowance bank that might be carried forward into the CAIR trading
programs.
A few commenters noted that the EPA is directed by the CAA to study
interpollutant trading and has approved SIPs that allow the trading of
ozone precursors under specific circumstances.
b. Interpollutant Trading and the Final CAIR Model Rules
Interpollutant trading can provide some additional compliance
flexibility, and potentially lower compliance costs, if appropriately
applied to multiple pollutants that have reasonably well known impacts
on the same environmental problem. The EPA acknowledges that it has the
authority to create interpollutant trading programs and has done so, in
other regulatory contexts, in the past. However, for several reasons,
the EPA determined that direct interpollutant trading is not
appropriate in the CAIR.
The final CAIR includes separate annual SO₂ and annual
NO_X model rules to address PM_2.5 precursor
emissions, and an ozone-season NO_X model rule to address
summertime ozone precursor emissions. The EPA believes it is not
appropriate for the CAIR model rules to allow annual SO₂ or
NO_X allowances to be used for compliance with ozone-season
NO_X allowance holding requirements because this has the
potential to adversely impact the ozone-season emissions reductions and
ozone air quality improvements from CAIR. This is significant because
the EPA, as required by the CAA, has promulgated a national air quality
standard for 8-hour ozone based on a determination that the standard is
necessary to protect public health. Section 110(a)2(D) requires States
to prohibit emissions in amounts that will significantly contribute to
nonattainment in, or interfere with maintenance by, any other State
with respect to any air quality standard, including ozone. In this
rule, EPA has designed the annual (SO₂ and NO_X)
and ozone-season (NO_X) emission caps to achieve the
emissions reductions necessary to address each State's significant
contribution to downwind PM_2.5 and ozone nonattainment,
respectively, and to prevent interference with maintenance. If sources
were permitted to use annual SO₂ or annual NO_X
allowances for compliance with ozone-season NO_X allowance
holding requirements (i.e., the ozone-season NO_X cap), then
there would be no assurance that upwind States' ozone-season
NO_X reduction obligations would be met, and CAIR's projected
ozone improvements in downwind nonattainment areas could be
significantly reduced. As a result, should interpollutant trading be
permitted between the annual and ozone-season programs, the EPA could
not demonstrate that the use of a CAIR ozone-season cap and trade
program would result in the emissions reductions necessary to satisfy
upwind States' obligations under section 110(a)2(D)to reduce
NO_X for ozone purposes.
The EPA believes it is also inappropriate to use annual
NO_X allowances for compliance with the annual SO₂
allowance holding requirements, and vice versa. The EPA agrees with
commenters that emphasize

[[Page 25284]]

that the chemical interactions for PM_2.5 precursors are
scientifically complex and must be accurately reflected in any transfer
ratio in order to maintain the integrity of the market. For example,
EPA analysis has shown (see January 30, 2004 NPR) that PM_2.5
precursors, such as NO_X and SO₂, may have non-
linear interactions in the formation of PM_2.5. Any uniform,
interpollutant transfer ratio would have to be an average and would
introduce significant variability concerning the impact of
interpollutant trading on emissions and significant uncertainty
concerning the achievement of the CAIR Program's emission reduction
goals. The EPA did not receive a response to the request in the January
30, 2004 NPR for information on an appropriate value for a potential
transfer ratio. While the EPA did receive one comment that recommended
the use of a trading ratio of two NO_X allowances for one
SO₂ allowance, no comments presented supporting analysis
that could be used to develop transfer ratios.
While many commenters supportive of allowing interpollutant trading
in the CAIR claimed that it would provide additional compliance
flexibility to sources, the EPA contends that use of the newly created
CAIR trading markets is sufficiently flexible. Sources may develop
integrated, multi-pollutant control strategies and use the separate
allowance markets to mitigate differences in control costs (within the
boundaries of emissions caps). In other words, a source can choose the
level to which they can cost effectively control one pollutant and, if
necessary, buy or sell emission allowances of the other pollutant to
compensate for any expensive or inexpensive control cost. When markets
are used to provide for trading of multiple pollutants, sources benefit
from the additional compliance flexibility while the caps assure the
achievement of the overarching environmental goals.
In the June 10, 2004 SNPR, the EPA solicited comment on how an
interpollutant trading mechanism might accommodate the slightly
different geographic regions found to be significant contributors for
PM_2.5 and ozone under the CAIR. No commenters provided
supporting analysis or input on this issue.
In summary, the EPA received comments that generally opposed
including a specific interpollutant trading mechanism. No commenters
provided analysis to demonstrate the benefit of including a specific
interpollutant trading mechanism nor was there analysis provided in
response to the EPA's solicitation in the June 10, 2004 SNPR for input
on: Transfer ratios, addressing two different environmental issues, and
having slightly different annual NO_X and ozone season
NO_X control regions. Furthermore, because the NO_X
and SO₂ markets provide very flexible mechanisms for trading
of the two pollutants, the EPA does not believe there is a compelling
need to go further at this time. Therefore, EPA is not finalizing
provisions in the CAIR model rules that specifically address
interpollutant trades.

F. Are There Incentives for Early Reductions?

When sources reduce their SO₂ and NO_X
emissions prior to the first phase of a multi-phase cap and trade
program, it creates the emissions ``glide slope'' of a cap and trade
approach that provides early environmental benefit and lowers the cost
of compliance. Early reduction credits (ERCs) can provide an incentive
for sources to install and/or operate controls before the
implementation dates. Allowing emission allowances from existing
programs to be used for compliance in the new program is another
mechanism to encourage early reductions prior to the start of a cap and
trade program. This section discusses the potential use of mechanisms
to provide incentives for early reductions in the CAIR.
1. Incentives for Early SO₂ Reductions
a. The CAIR NPR and SNPR Proposal for the Model Rules and Input From
Commenters
The January 30, 2004 CAIR NPR and June 10, 2004 CAIR SNPR
acknowledge the benefit of early reductions and provide for the use of
title IV SO₂ allowances of vintage years 2009 and earlier to
be used for compliance in the CAIR at a one-to-one ratio. In other
words, title IV allowances can be banked into the CAIR Program. This
provides incentive for title IV sources to reduce their emissions in
years 2009 and earlier because these allowances may be used for CAIR
compliance without being discounted by the retirement ratios applied to
the 2010 and later SO₂ allowances. No other mechanism, such
as SO₂ ERCs were proposed by the EPA.
Comments Regarding the Incentives for Early SO₂ Reductions
The EPA received comments on incentives for early SO₂
reductions with the majority supporting the EPA proposal to encourage
early emission reductions by allowing the CAIR sources to use 2009 and
earlier vintage title IV SO₂ allowances for CAIR compliance.
Some supporters noted concerns in meeting the CAIR's stringent Phase I
SO₂ requirements as another reason to allow the banking of
undiscounted, title IV allowances into the CAIR.
Some commenters expressed concern that achieving the SO₂
caps would be delayed if a large number of SO₂ allowances
were being banked into the CAIR. Based upon experience with
implementing the Acid Rain Program, the EPA acknowledged in the SNPR
that crediting early reductions does create a glide slope--where
emissions are reduced below the baseline before the implementation date
and ``glide'' down to the ultimate cap level sometime after the program
begins. This gradual reduction in emissions is a key component to cap
and trade programs having lower cost of compliance than command-and-
control approaches. One commenter proposed that the EPA needs to assess
the likelihood that allowing the banking of undiscounted title IV
allowances would delay the attainment of the Phase I SO₂ cap
until Phase II. Because the EPA included this mechanism (i.e., the use
of 2009 and earlier vintage SO₂ allowances for compliance in
the CAIR) in the policy case modeled as part of this rulemaking, EPA
analysis includes the benefits and costs that would result from the
level of SO₂ reductions that would take place with banking
of undiscounted title IV allowances.
One commenter advocated the use of SO₂ ERCs. It was not
clear whether these would be awarded in addition to banking title IV
allowances into the CAIR or the ERC mechanism would take the place of
banking SO₂ allowances into the CAIR.
b. SO₂ Early Reduction Incentives in the Final CAIR Model Rules
The CAIR SO₂ model rule allows CAIR sources to use title
IV SO₂ allowances of vintage 2009 and earlier for compliance
with the CAIR at a one-to-one ratio. This approach was part of the CAIR
policy case assumptions used in the rulemaking modeling and the EPA has
shown that the SO₂ cap and trade program, with this early
incentive mechanism, will achieve the level of SO₂
reductions needed to meet the CAIR goals. These reductions take place
on a glide slope that includes early emissions reductions as well as
some use of the SO₂ allowance bank as sources gradually
reduce emissions toward the cap levels.
The EPA did not include SO₂ ERCs because the Acid Rain
Program cap and trade program, which affects a large segment of the
CAIR source universe, makes it impossible to determine whether sources
are reducing their SO₂

[[Page 25285]]

emissions below levels required by existing (i.e., the Acid Rain
Program) programs. Furthermore, given that most sources with
substantial emissions receive SO₂ emission allowances under
the Acid Rain Program, a significant number of SO₂
allowances are expected to be banked into the CAIR. These banked
allowances would be available to CAIR sources in the early years of the
program and make ERCs largely unnecessary.
2. Incentives for Early NO_X Reductions
a. The CAIR NPR and SNPR Proposal for the Model Rules and Input From
Commenters
In the June 10, 2004 SNPR, the EPA proposed to provide incentives
for early NO_X reductions by allowing the use of
NO_X SIP Call allowances of vintage 2009 and earlier to be
used for compliance in the CAIR. Further, the EPA did not propose, but
solicited comment on the potential use of NO_X ERCs to
provide an additional incentive for sources to reduce NO_X
emissions prior to CAIR implementation. In addition to the general
solicitation for comment on NO_X ERCs, the EPA solicited
input on the following specific approaches that could be utilized: (1)
The EPA could maintain the NO_X SIP Call requirements and
allow sources to use ERCs only for compliance with the annual
limitation, to ensure that ozone-season NO_X limitations are
met. Under this scenario, the additional States subject to the CAIR
that have been found to significantly contribute to ozone nonattainment
may also have to be included in the ozone season cap; (2) the EPA could
limit the period of time during which ERCs could be created and banked;
(3) the EPA could cap the amount of ERCs that can be created; and (4)
the EPA could apply a discount rate to ERCs.
Comments Regarding the Incentives for Early NO_X Reductions
The EPA did not receive comment on the proposed use of
NO_X SIP Call allowances of vintage years 2009 and earlier
for compliance in the CAIR. In fact, several commenters characterized
the CAIR proposal as not including any incentives for early
NO_X emissions reductions.
The EPA received several comments on the potential use of
NO_X ERCs with the majority in favor of some sort of ERC
mechanism. Several commenters advocated the use of ERCs to mitigate
concerns that they would not be able to meet the stringent Phase I CAIR
reduction requirements. One commenter wanted early reductions to
facilitate the ozone attainment in 2010 but believed 2010 attainment
could only be helped if there were some restrictions on the number of
ERCs that could be created.
Some ERC supporters wanted credit for wintertime emissions
reductions only, while a few believed that credit should be given for
reductions at any time of year. One commenter advocated providing ERCs
for wintertime reductions only as part of a broader proposal to create
a bifurcated NO_X trading system (i.e., separate wintertime
and summertime allowances and trading markets).
Many of the commenters supporting the use of ERCs advocated that
they be distributed from a pool of allowances similar to the CSP used
in the NO_X SIP Call. (The NO_X SIP Call CSP was a
fixed pool of NO_X allowances that were distributed on a
first come-first serve, prorated, or need basis, depending upon the
State). Commenters noted that the CSP approach has already been part of
a litigated rulemaking and provides the added benefit of limiting the
total number of allowances that can be distributed for early
reductions. Other commenters proposed that should the final approach
use a pool of allowances, this pool should not remove allowances from
the existing State NO_X budget. Another commenter suggested
that allowances from a CSP could be distributed based upon a
NO_X emission rate, such as 0.25 lbs/mmBtu. Allowances could
be distributed to any source emitting below the target emission rate.
Several commenters were concerned that too many NO_X ERCs
(as well as NO_X SIP Call allowances) could be introduced
into the CAIR and the ability of the NO_X cap and trade
program to meet the annual and ozone-season reduction goals could be
compromised. Some commenters suggested that crediting early reductions
at a discount (e.g., 2 tons of NO_X reductions earn 1 ERC)
could mitigate this concern. Other commenters noted that a CSP-style
mechanism also provides safeguards against an overabundance of ERCs.
Another commmenter noted that restrictions on the use of ERCs similar
to the progressive flow control (PFC) mechanism used in the
NO_X SIP Call--PFC restricts the use of banked NO_X
allowances for compliance in years where the NO_X bank is
greater than 10 percent of the allocations--could help to ease concerns
of flooding the market with NO_X ERCs.
One commenter believed that the EPA's projection that the potential
pool of NO_X ERCs could be as large as 3.7 million tons
(presented in the June 10, 2004 SNPR) is unrealistically high. The
commenter contended that technical limitations of Selective Catalytic
Reduction (SCR) operation would not permit facilities to simply run all
of their SCRs year-round. More specifically, the commenter believes the
lower operating loads, typically of the wintertime dispatch, would not
meet the minimum conditions necessary for SCR operation (i.e., at lower
capacity the stack gas temperatures will not support the use of the
catalyst). Fewer wintertime opportunities to operate the SCRs is
believed by the commenter to result in a smaller projected ERC
estimate. This was an estimate used for discussion purposes and was not
directly used in the development of the CSP.
A few commenters advocated providing credits to any source that
reduced emission rates below those used to determine the CAIR State
budgets. One commenter suggested that the rates be based on those rates
used to determine the NO_X SIP Call caps.
A few commenters proposed that the EPA should develop a strategy
for crediting NO_X reductions from sources that have
implemented control measures in response to State-level regulations
that are more stringent than the NO_X SIP Call. Another
commenter advocated only providing ERCs in States subject to both the
NO_X SIP Call and the CAIR.
Some commenters did not support the use of NO_X ERCs in
any form. These commenters believe that the use of ERCs would delay
attainment of the CAIR emission caps.
b. NO_X Early Reduction Incentives in the Final CAIR Model Rules
The CAIR ozone-season NO_X cap and trade rule will allow
the proposed use of NO_X SIP Call allowances of vintage years
2008 and earlier for compliance in the CAIR. This mechanism would
provide incentive for sources in NO_X SIP Call States to
reduce their ozone-season NO_X emissions and bank additional
allowances into the CAIR. Because today's final ozone-season cap and
trade rule includes a mandatory ozone-season NO_X cap in 2009
(this modification is discussed in section IV), the provisions to allow
the banking of NO_X SIP Call allowances into the CAIR are
adjusted to reflect this implementation date.
The CAIR annual NO_X cap and trade rule will provide
additional incentives for early annual NO_X reductions by
creating a CSP for CAIR States from which they can distribute
allowances for early, surplus NO_X emissions reductions in
the years 2007 and 2008. The earning of CAIR CSP allowances for

[[Page 25286]]

NO_X emission reductions does not begin until 2007 because
this is the first year after the State SIP submittal deadlines. The
CAIR CSP will provide a total of 200,000 \136\ CAIR annual
NO_X allowances of vintage 2009 in addition to the annual
CAIR NO_X budgets.
---------------------------------------------------------------------------

\136\ The 200,000 ton pool includes the 1,503 tons that would be
DE and NJ's share. Section V of today's action describes in detail
the State-by-State apportionment of the total CSP.
---------------------------------------------------------------------------

The CAIR's CSP is patterned after the NO_X SIP Call's
CSP, which is part of an established and extensively litigated
rulemaking. Similarities include: Limiting the total number of
allowances that can be distributed; limiting the years in which CSP
allowances can be earned; populating the CSP with allowances vintaged
the first compliance year; and using distribution criteria of early
reductions and need.
The EPA will apportion the CSP to the States based upon their share
of the final, regionwide NO_X CAIR reductions. Similar to the
NO_X SIP Call, States may distribute these CAIR
NO_X allowances to sources based upon either: (1) A
demonstration by the source to the State of NO_X emissions
reductions in surplus of any existing NO_X emission control
requirements; or (2) a demonstration to the State that the facility has
a ``need'' that would affect electricity grid reliability. Sources that
wish to receive CAIR CSP allowances based upon a demonstration of
surplus emissions reductions will be awarded one CAIR annual
NO_X allowance for every ton of NO_X emissions
reductions. (Should a State receive more requests for allowances than
their share of the CAIR CSP, the State would pro-rate the allowance
distribution.) Determination of surplus emissions must use emissions
data measured using part 75 monitoring.
The EPA elected to include the CSP in response to several comments
noting the benefit of early NO_X reductions and some
commenters concerns in complying with the stringent Phase I CAIR
NO_X cap. While EPA analysis has shown that sources had
sufficient time to install NO_X emission controls, the EPA
does believe that it would be appropriate to provide some mechanism to
alleviate the concerns of some sources which may have unique issues
with complying with the 2009 implementation deadline. In addition to
mitigating some of the uncertainty regarding the EPA projections of
resources to comply with CAIR, the CAIR CSP also effectively provides
incentives for early, surplus NO_X reductions.
The EPA agrees with the comments that advocate allowing sources to
earn CAIR annual NO_X allowances only for those reductions
that are in surplus of the sources' existing NO_X reduction
requirements. By allowing sources in NO_X SIP Call and non-
NO_X SIP Call States to demonstrate that their year-round
early reductions are truly ``surplus'' and, therefore, deserving of CSP
allowances, the EPA is responding to comments that the EPA should allow
sources in non-NO_X SIP Call States to receive credit for
early reductions. Some commenters advocated crediting sources in the
ozone-season NO_X cap and trade program that emitted below
the emission rate used to determine the ozone-season budget. The EPA
did not accept this recommendation because a source that is allowed to
bank NO_X SIP Call allowances into the CAIR ozone-season
NO_X program and receive early reduction credit from CAIR's
CSP would be essentially ``double-counting'' that emission reduction.
The EPA did not restrict the use of the NO_X allowances
awarded from the CSP because several aspects of the CSP already address
concerns that too many total credits would be distributed and that they
would flood the markets. First, the CSP is a finite pool of
NO_X allowances. Second, by requiring sources to reduce one
ton of NO_X emissions for every NO_X allowance
awarded from the CSP ensures that significant reductions are made prior
to the CAIR implementation date.

G. Are There Individual Unit ``Opt-In'' Provisions?

In the SNPR, EPA described a potential approach for allowing
certain units to voluntarily participate in, or ``opt-in,'' to the
CAIR. Originally, EPA proposed to have no opt-in provision but included
language in the SNPR on what a potential opt-in provision may look
like. This ``potential'' opt-in provision would have allowed non-EGU
boilers and turbines that exhaust to a stack or duct and monitor and
report in accordance with part 75 to opt into the CAIR. The opt-in unit
would have been required to opt-in for both SO₂ and
NO_X. The allocation method for opt-ins assumed a percentage
SO₂ reduction from a baseline and for NO_X,
allocations were equal to a baseline heat input multiplied by a
specified NO_X emissions rate, the same NO_X
emissions rate EGUs were subject to in the assumed EGU budgets.
Allocations were updated annually and after opting in units would have
had to stay in the CAIR for a minimum of 5 years. The EPA received many
comments in favor of and very few comments against including an opt-in
provision in the final rule. As a result, EPA is including an opt-in
provision in this final rule that is based on the approach described in
the SNPR but includes several modifications and additions in response
to comments as described below. In general, EPA believes there is value
to including an opt-in provision but believes that sources that opt-in
should be responsible for a certain level of reduction below its
baseline because of the additional flexibility provided to that source
by opting into a regional trading program and because of the
possibility that participation in the CAIR may reduce or eliminate
future potential required reductions. Therefore, the following opt-in
approach has as its goals to provide more flexibility to the units
opting in as well as to potentially provide more cost-effective
reductions for the affected EGUs but also to ensure a certain level of
reduction from the units opting into the program.
1. Applicability
Some commenters suggested that the opt-in provision not be limited
to boilers and turbines but should be open to any unit. The EPA
strongly believes that any unit participating in an emissions trading
program be subject to accurate and reliable monitoring and reporting
requirements. This is the purpose of part 75. The EPA has developed
criteria for boilers and turbines to satisfy the requirements of part
75 but has not developed criteria for all non-boilers and turbines and,
therefore, cannot be confident their emissions can be monitored with
the high degree of accuracy and reliability required by a cap-and-trade
program. Continuous Emissions Monitoring Systems or ``CEMS'' are
typically what is required by EPA to participate in a cap-and-trade program.
In response to comments received suggesting that non-boilers and
turbines be allowed to opt-in, EPA is expanding applicability of the
opt-in provision to include, in addition to boilers and turbines, other
fossil fuel-fired combustion devices that vent all emissions through a
stack and meet monitoring, recordkeeping, and recording requirements of
part 75.
2. Allowing Single Pollutant
Some commenters suggested that sources should be allowed to opt-in
for only one pollutant instead of requiring the source to opt-in for
both SO₂ and NO_X as EPA proposed. These
commenters argued that some sources may only emit significant amounts
of one of the two regulated pollutants and that it would not make sense
to require reductions in both pollutants from such

[[Page 25287]]

a source. The EPA agrees with this comment and will allow units to opt-
in for one pollutant, i.e., NO_X, SO₂, or both.
Another commenter suggested that EPA allow non-EGUs subject to the
NO_X SIP Call to opt into the CAIR for NO_X only
without requiring any reductions in SO₂. This commenter
argued that these non-EGUs could simply turn on their SCRs during the
non-ozone season and easily achieve significant NO_X
reductions. The EPA agrees that the relatively small number of non-EGUs
subject to the NO_X SIP Call that have SCRs could achieve
significant NO_X reductions by operating their SCRs during
the non-ozone season. As stated above, EPA is allowing sources to opt-
in for one pollutant and thus non-EGUs subject to the NO_X
SIP call may opt-in for NO_X only.
3. Allocation Method for Opt-Ins
In the SNPR, EPA proposed allocating allowances to opt-in units on
a yearly basis. The amount of allowances allocated would be calculated
by multiplying an emission rate by the lesser of a baseline heat input
or the actual heat input monitored at the unit in the prior year.
The baseline heat input would be calculated by using the most
recent 3 years of quality-assured part 75 monitoring data. When less
than 3 years of quality-assured part 75 monitoring data is available,
the heat input would be based on quality-assured part 75 monitoring
data from the year before the unit opted in.
For SO₂, EPA proposed that the emission rate used to
calculate allocations would be the lesser of, the most stringent State
or Federal SO₂ emission rate that applied in the preceding
year or the emission rate representing 50 percent of the unit's
baseline SO₂ emission rate (in lbs/mmBtu) for the years 2010
through 2014 and 35 percent of the unit's baseline SO₂
emission rate (in lbs/mmBtu) for 2015 and beyond. For NO_X,
EPA proposed that the emission rate would be the lower of the unit's
baseline emission rate, the most stringent State or Federal
NO_X emission limitation that applies to the opt-in unit at
any time during the calender year prior to opting into the CAIR
Program, or 0.15 lb/mmBtu for the years 2010 through 2014 and 0.11 lbs/
mmBtu for the years 2015 and beyond.
In today's final rule, EPA is making a number of changes to its
proposed methodology for calculating allocations for opt-in units.
With regards to baseline heat input, EPA is requiring that sources
may only use part 75 monitored data for years in which they have
maintained at least a 90 percent monitor availability. The EPA is
making this change because part 75 contains missing data provisions
that require substitution of data when monitors are unavailable. When
units have low monitor availability, units are required to report more
conservative (e.g., higher) heat input values. This is to provide an
incentive to maintain high monitor availability (since under a cap and
trade program sources would be required to turn in more allowances if
they reported higher emissions). When setting baselines, sources have
the opposite incentive, reporting a higher heat input would result in a
higher baseline and thus a greater allocation.
With regards to the SO₂ emission rate used to calculate
allocations, EPA is requiring that the emission rate used to calculate
allocations would be the lesser of, the most stringent State or Federal
SO₂ emission rate that applies to the unit in the year that
the unit is being allocated for, or the emission rate representing 70
percent of the unit's baseline SO₂ emission rate (in lbs/
mmBtu). The EPA is changing the percentage emission reduction upon
which allocations are based because some commenters suggested that
instead of using percentage emission reduction requirements that are
the same as the requirements for EGUs as a basis for allocating to opt-
ins, EPA should require emissions reductions based on similar marginal
cost of control. The EPA agrees with the basic concept that emissions
reductions for opt-ins should be based on similar marginal costs. One
commenter submitted results from a study of industrial boiler
NO_X and SO₂ control costs that indicated the use
of similar marginal cost of control would result in approximately a 30
percent reduction in NO_X and SO₂ by 2010. While
the commenter provided limited data to allow EPA to evaluate the
commenter's estimates, EPA is using this percentage reduction
requirement for the opt-in provision. The same commenter stated that it
may be possible to achieve more than a 30 percent reduction in
SO₂ and NO_X by 2015 by employing future
unspecified technology advances. Because these future technology
advances are not specified nor demonstrated, EPA is not requiring more
than a 30 percent reduction in SO₂ and NO_X in
2015 and beyond for opt-ins. The EPA is changing the requirement to use
the lowest required emission rate for the year preceding the year in
which allowances are being allocated to the lowest emission rate for
the year in which allowances are being allocated. The EPA is making
this change because EPA believes that such data should be available and
that this more accurately reflects the intent of the rule to ensure
that the source is not being allocated a greater number of allowances
than the emissions a source would be allowed to emit under the
regulations it is subject to in the year the allocations are being
made. The EPA is finalizing parallel provisions with respect to NO_X.
4. Alternative Opt-In Approach
Some commenters suggested that EPA include an alternative approach
to opting into the CAIR. This alternative would allow units to opt-in
as early as 2009 for NO_X and 2010 for SO₂ and
receive allocations at their current emission levels in return for a
commitment to make deeper reductions by 2015 than would be required
under the general opt-in provision described above. Therefore, for the
years 2010 through 2014, the unit would be allocated allowances based
on the same heat input used under the general opt-in provision (e.g.,
the lesser of the baseline heat input or the heat input for the year
preceding the year in which allocations are being made) multiplied by
an emission rate. This emission rate would be the lower of the emission
rate for the year or years before the unit opted in or the most
stringent State or Federal emission rate required in the year that the
unit opts in. For SO₂ for the years 2015 and beyond, the
unit would be allocated allowances based on the same heat input
multiplied by an emission rate. This emission rate would be the lower
of a 90 percent reduction from the baseline emission rate or the most
stringent State or Federal emission rate required in the baseline year.
For NO_X, the same methodology would be used, except that the
emission rate used for the years 2015 and beyond would be the lower of
0.15 lbs/mmBtu or the most stringent State or Federal emission rate
required in the baseline year. The EPA believes the environmental
benefit of achieving deeper emissions reductions in the future (2015)
from sources that may otherwise not make such deep emissions reductions
is worth including in this final rule.
5. Opting Out
In the SNPR, EPA proposed that opt-in units be required to remain
in the program a minimum of 5 years after which time they could
voluntarily withdraw from the CAIR. Some commenters expressed concern
over this proposed approach, arguing that because EGUs affected by the
CAIR are not allowed to voluntarily withdraw from the CAIR that opt-in
sources should not be allowed to voluntarily

[[Page 25288]]

withdraw either. The EPA recognizes that opt-in sources such as
industrial boilers and turbines tend to be more sensitive to changing
market forces than EGUs. As a result, EPA believes it is appropriate to
allow opt-in sources who voluntarily participate in an emissions
reductions program to be able to end their participation or (``opt-
out'') after a specified period of time. As proposed, EPA believes a
period of 5 years is appropriate and is finalizing a rule to allow opt-
in sources to opt-out after participating in the CAIR for 5 years. This
option to opt-out after 5 years does not apply to sources that opt-in
under the alternative approach. Sources that opt-in under the
alternative approach may not opt-out at any time.
6. Regulatory Relief for Opt-In Units
The CAIR does not offer relief from other regulatory requirements,
existing or future, for units that opt-in to the CAIR cap and trade
program. Any revision of requirements for other, non-CAIR programs
would be done under rulemakings specific to those programs.
As discussed above, EPA is including two different approaches for
opt-in units to follow, a general and an alternative approach. The EPA
is including both approaches in this final rule in response to comments
supportive of including an alternative means and to provide greater
flexibility for sources to participate in the CAIR trading program.
Opt-in sources may select which approach is more appropriate for their
particular situation. An opt-in source may not switch from one approach
to the other once in the program. States have the flexibility to choose
to include both of these approaches, one of these approaches, or none
of them in their SIPs. EPA is not requiring States to include an
individual unit opt-in provision because the participation of
individual opt-in units is not required to meet the goals of the CAIR.
However, States cannot choose to have an individual unit opt-in
approach different than what EPA has finalized in this rule and still
participate in the inter-State trading program administered by EPA.

H. What Are the Source-Level Emissions Monitoring and Reporting
Requirements?

In the NPR, the EPA proposed that sources subject to the CAIR
monitor and report NO_X and SO₂ mass emissions in
accordance with 40 CFR part 75.
The model trading rules incorporate part 75 monitoring and are
being finalized as proposed. The majority of CAIR sources are measuring
and reporting SO₂ mass emissions year round under the Acid
Rain Program, which requires part 75 monitoring. Most CAIR sources are
also reporting NO_X mass emissions year round under the
NO_X SIP Call. The CAIR-affected Acid Rain sources that are
located in States that are not affected by the NO_X SIP Call
currently measure and report NO_X emission rates year round,
but do not currently report NO_X mass emissions. These
sources will need to modify only their reporting practices in order to
comply with the proposed CAIR monitoring and reporting requirements.
Because so many sources are already using part 75 monitoring, there
were very few comments on the source-level monitoring requirements in
this rulemaking. The comments the EPA received related to sources not
currently monitoring under part 75. Commenters suggested that
alternative forms of monitoring (e.g., part 60 monitoring) would be
appropriate for these sources. The EPA disagrees. Consistent, complete
and accurate measurement of emissions ensures that each allowance
actually represents one ton of emissions and that one ton of reported
emissions from one source is equivalent to one ton of reported
emissions from another source. Similarly, such measurement of emissions
ensures that each single allowance (or group of SO₂
allowances, depending upon the SO₂ allowance vintage)
represents one ton of emissions, regardless of the source for which it
is measured and reported. This establishes the integrity of each
allowance, which instills confidence in the underlying market
mechanisms that are central to providing sources with flexibility in
achieving compliance. Part 75 has flexibility relating to the type of
fuel and emission levels as well as procedures for petitioning for
alternatives. The EPA believes this provides the requested flexibility.
Should a State(s) elect to use the example allocation approach, the
EPA would modify the part 75 monitoring and reporting requirements to
collect information used in determining the allowance allocations for
Combined Heat and Power (CHP) units. More specifically, provisions for
the monitoring and reporting of the BTU content of the steam output
would be added to the existing requirements. The information on
electricity output currently reported under part 75 would not need to
be revised to allow States to implement the example allowance
allocation approach.
In the SNPR, the EPA proposed continuous measurement of
SO₂ and NO_X emissions by all existing affected
sources by January 1, 2008 using part 75 certified monitoring
methodologies. New sources have separate deadlines based upon the date
of commencement of operation, consistent with the Acid Rain Program.
These deadlines are finalized as proposed.

I. What Is Different Between CAIR's Annual and Seasonal NO_X
Model Cap and Trade Rules?

Today's action finalizes not only the proposed CAIR annual
NO_X program and annual SO₂ program, but also a
CAIR ozone-season NO_X program. Because the CAIR ozone-season
NO_X program is the only ozone-season NO_X cap and
trade program that the EPA will administer, NO_X SIP Call
States wishing to meet their NO_X SIP Call obligations
through an EPA-administered regional NO_X program will also
use the CAIR ozone-season rule. The EPA believes that States and
affected sources will benefit from having a single, consistent regional
NO_X cap and trade program. This section of today's action
highlights any key differences between the CAIR ozone-season
NO_X model rule and the NO_X SIP Call model rule,
as well as the CAIR annual and ozone-season NO_X model rules.
Differences Between the CAIR Ozone-Season NO_X Model Rule and
the NO_X SIP Call Model Rule
While the CAIR ozone-season NO_X model rule closely
mirrors the NO_X SIP Call rule (as does the other CAIR
rules), the EPA has incorporated into the CAIR model rules its
experience with implementing trading programs (including seasonal
NO_X programs). These modifications include the following.
A. Unrestricted banking: The CAIR ozone-season NO_X model
rule will not include any restrictions on the banking of NO_X
SIP Call allowances (vintages 2008 and earlier) or CAIR ozone-season
NO_X allowances. The NO_X SIP Call rules include
``progressive flow control'' provisions that reduce the value of banked
allowances in years where the bank is above a certain percentage of the
cap. (See section VIII.E.1 of today's rule for a detailed discussion).
B. Facility level compliance: The CAIR ozone-season NO_X
model rule will allow sources to comply with the allowance holding
requirements at the facility level. The NO_X SIP Call rules
required unit-by-unit level compliance with certain types of allowance
accounts providing some flexibility for sources with multiple affected
units. (See the June 2004 SNPR, section IV for a detailed discussion).

The EPA believes that these changes improve the programs and that both
CAIR and NO_X SIP Call affected sources

[[Page 25289]]

will benefit from complying with a single, regionwide cap and trade program.
Differences Between the CAIR Ozone-Season and Annual NO_X
Model Rules
The CAIR ozone-season and annual NO_X model rules are
designed to be identical with the exception of (1) provisions that
relate to compliance period and (2) the mechanism for providing
incentives for early NO_X reductions. For compliance related
provisions, the EPA attempted to maintain as much consistency as
possible between the CAIR annual and ozone-season NO_X model
rules. For example, reporting schedules remain synchronized (i.e.,
quarterly reporting) for both of the CAIR NO_X model rules.
For the annual and ozone-season NO_X model rules, the EPA did
define 12 month and 5 month compliance periods, respectively.
Incentives for early NO_X reductions differ between the
CAIR annual and ozone-season programs. For the annual NO_X
program, early reductions may be rewarded by States through a CSP. (See
section VIII.F.2 of today's action for a detailed discussion.) The CAIR
ozone-season NO_X model rule provides incentive for early
emissions reductions by allowing the banking of pre-2009 NO_X
SIP Call allowances into the CAIR ozone-season program.

J. Are There Additional Changes to Proposed Model Cap and Trade Rules
Reflected in the Regulatory Language?

The proposed and final rules are modeled after, and are largely the
same as, the NO_X SIP Call model trading rule. Today's final
rule includes some relatively minor changes to the model rules'
regulatory text that improve the implementability of the rules or
clarify aspects of the rules identified by the EPA or commenters. (Note
that sections VIII.B through VIII.H of today's action highlight the
more significant modifications included in the final model rules).
One example of a relatively minor change is the inclusion of
language in the SO₂ model rule that implements the
retirement ratio (2.00) used for allowances allocated for 2010 to 2014
and the retirement ratio (2.86) used for allowances allocated for 2015
and later, that clarifies the compliance deduction process and that
provides for rounding-up of fractional tons to whole tons of excess
emissions. More specifically, the definition of ``CAIR SO₂
allowance'' states that an allowance allocated for 2010 to 2014
authorizes emissions of 0.50 tons of SO₂ and that an
allowance allocated for 2015 or later authorizes emissions of 0.35 tons
of SO₂--which corresponds with the 2.86 retirement ratio.
Other, less significant modifications were also included in the
regulatory text of the final model rules. These include:
C. Units and sources are identified separately for NO_X
and SO₂ programs (e.g., CAIR NO_X units, CAIR Nox
ozone season units, and CAIR SO₂ units) since States can
participate in one, two, or three trading programs;
D. The definition of ``nameplate capacity'' is clarified;
E. The language on closing of general accounts is clarified; and,
F. Process of recordation of CAIR SO₂ allowance
allocations and transfers on rolling 30-year periods is added to make
it consistent with Acid Rain regulations.
Another example of where today's final model trading rules
incorporate relatively minor changes from the proposed model trading
rules involves the provisions in the standard requirements concerning
liability under the trading programs. The proposed CAIR model
NO_X and SO₂ trading rules include, under the
standard requirements in Sec. 96.106(f)(1) and (2) and Sec.
96.206(f)(1) and (2), provisions stating that any person who knowingly
violates the CAIR NO_X or SO₂ trading programs or
knowingly makes a false material statement under the trading programs
will be subject to enforcement action under applicable State or Federal
law. Similar provisions are included in Sec. 96.6(f)(1) and (2) of the
final NO_X SIP Call model trading rule. The final CAIR model
NO_X and SO₂ trading rules exclude these
provisions for the following reasons. First, the proposed rule
provisions are unnecessary because, even in their absence, applicable
State or Federal law authorizes enforcement actions and penalties in
the case of knowing violations or knowing submission of false
statements. Moreover, these proposed rule provisions are incomplete.
They do not purport to cover, and have no impact on, liability for
violations that are not knowingly committed or false submissions that
are not knowingly made. Applicable State and Federal law already
authorizes enforcement actions and penalties, under appropriate
circumstances, for non-knowing violations or false submissions. Because
the proposed rule provisions are unnecessary and incomplete, the final
CAIR model NO_X and SO₂ trading rules do not
include these provisions. However, the EPA emphasizes that, on their
face, the provisions that were proposed, but eliminated in the final
rules, in no way limit liability, or the ability of the State or the
EPA to take enforcement action, to only knowing violations or knowing
false submissions.

IX. Interactions With Other Clean Air Act Requirements

A. How Does This Rule Interact With the NO_X SIP Call?

A majority of States affected by the CAIR are also affected by the
NO_X SIP Call. This section addresses the interactions
between the two programs.
The EPA proposed that States achieving all of the annual
NO_X reductions required by the CAIR from only EGUs would not
need to continue to impose seasonal NO_X limitations on EGUs
from which they required reductions for purposes of complying with the
NO_X SIP Call. Also, EPA proposed that States would have the
option of retaining such seasonal NO_X limitations. The EPA
also proposed to keep the NO_X SIP Call in place for non-EGUs
currently subject to the NO_X SIP Call and to continue
working with States to run the NO_X SIP Call Budget Trading
Program for all sources that would remain in the program. In response
to commenters, EPA is making several modifications to its proposed approach.
States Affected by the CAIR for Ozone and PM_2.5 Will Be
Subject to a Seasonal and an Annual NO_X Limitation
A number of commenters recommended leaving the current
NO_X SIP Call ozone season NO_X limitation in place
as a way to ensure that ozone season NO_X reductions from
EGUs required by the NO_X SIP Call would continue to be
achieved. Some commenters argued this would also help non-EGUs
currently subject to the NO_X SIP Call by allowing them to
continue trading with EGUs in a seasonal NO_X program. Many
of the same commenters suggested a dual-season or bifurcated CAIR
trading program as a mechanism for maintaining an ozone season
NO_X limitation for EGUs under the CAIR. In response to these
commenters, EPA is requiring that States subject to the CAIR for
PM_2.5 be subject to an annual limitation and that States
subject to the CAIR for ozone be subject to an ozone season limitation.
This means that States subject to the CAIR for both PM_2.5
and ozone are subject to both an annual and an ozone season
NO_X limitation. The annual and ozone season NO_X
limitations are described in section IV. States subject to the CAIR for
ozone only are only subject to an ozone season NO_X
limitation. To implement these NO_X limitations, EPA will
establish and operate two NO_X trading programs, i.e.,

[[Page 25290]]

a CAIR annual NO_X trading program and a CAIR ozone season
NO_X trading program. The CAIR ozone season NO_X
trading program will replace the current NO_X SIP Call as
discussed in more detail later in this section.
What Will Happen to Non-EGUs Currently in the NO_X SIP Call?
A number of commenters were concerned that the cost of compliance
for non-EGUs in the NO_X SIP Call would increase if they were
not allowed to continue to trade with EGUs. In response to these
commenters, EPA is modifying its proposed approach. The EPA is allowing
States affected by the NO_X SIP Call that wish to use EPA's
model trading rule to include non-EGUs currently covered by the
NO_X SIP Call in the CAIR ozone season NO_X trading
program. This will ensure that non-EGUs in the NO_X SIP Call
will continue to be able to trade with EGUs as they currently do under
the NO_X SIP Call. This will not require States to get
additional reductions from non-EGUs. Budgets for these units would
remain the same as they are currently under the NO_X SIP
Call. States will, however, be required to modify their existing
NO_X SIP Call regulations to reflect the replacement of the
NO_X SIP Call with the CAIR ozone season NO_X
trading program. The EPA will continue to operate the NO_X
SIP Call trading program until implementation of the CAIR begins in
2009. The EPA will no longer operate the NO_X SIP Call
trading program after the 2008 ozone season and the CAIR ozone season
NO_X trading program will replace the NO_X SIP Call
trading program. If States affected by the NO_X SIP Call do
not wish to use EPA's CAIR ozone season NO_X trading program
to achieve reductions from non-EGU boilers and turbines required by the
NO_X SIP Call, they would be required to submit a SIP
Revision deleting the requirements related to non-EGU participation in
the NO_X SIP Call Budget Trading Program and replacing them
with new requirements that achieve the same level of reduction.
Compliance With the NO_X SIP Call for States That Are Subject
to Both the CAIR Ozone Season NO_X Reduction Requirements and
the NO_X SIP Call
If the only changes a State makes with respect to its
NO_X SIP Call regulations are: (1) To bring non-EGUs that are
currently participating in the NO_X SIP Call Budget Trading
Program into the CAIR ozone season program using the same non-EGU
budget and applicability requirements that are in their existing
NO_X SIP Call Budget Trading Program; and (2) to achieve all
of the emissions reductions required under the CAIR from EGUs by
participating in the CAIR ozone season NO_X trading program,
EPA will find that the State continues to meet the requirements of the
NO_X SIP Call.
If the only changes a State makes with respect to its
NO_X SIP Call regulations are not those described above, see
section VII for a discussion of how the State would satisfy its
NO_X SIP Call obligations.
States in the NO_X SIP Call But Not Affected by the CAIR
(Rhode Island)
Rhode Island is the only State in the NO_X SIP Call that
is not affected by the CAIR. To continue meeting its NO_X SIP
Call obligations in 2009 and beyond, Rhode Island will have two
choices. It may either modify its NO_X SIP Call trading rule
to conform to the new CAIR ozone season NO_X trading rule if
it wishes to allow its sources to continue to participate in an
interstate NO_X trading program run by EPA or, it will need
to develop an alternative method for obtaining the required
NO_X SIP Call reductions. In either case, Rhode Island must
continue to meet the budget requirements of the existing NO_X
SIP Call.
Use of Banked SIP Call Allowances in the CAIR Program
As explained earlier in today's final rule, banked allowances from
the NO_X SIP Call may be used in the CAIR ozone season
NO_X trading program.
Other Comments and EPA's Responses
One commenter wrote that because attainment demonstrations for
early action compacts were made based on having EGUs and non-EGUs
together in the NO_X SIP Call, EPA could not allow EGUs to
leave the NO_X SIP Call and still have valid early action
compacts (EACs). As discussed above, EPA is allowing States to keep
EGUs and non-EGUs in the NO_X SIP Call together in one ozone
season program (CAIR ozone season trading program). The NO_X
reductions required by the CAIR ozone season trading program are
slightly more stringent than the reductions required by the
NO_X SIP Call. As a result, the attainment demonstrations for
EACs would remain valid under the CAIR. Having said that, the EAC
program will have ended (April 2008) before the CAIR rule is
implemented. Thus, the compacts will no longer be applicable when the
CAIR takes effect.
Another commenter proposed to have non-EGUs under the
NO_X SIP Call subject to an annual NO_X cap similar
to EGUs under the CAIR so that non-EGUs could continue to trade with
EGUs. By adopting a CAIR ozone season trading program that includes
non-EGUs covered by the NO_X SIP Call, non-EGUs will be able
to continue to trade with EGUs.

B. How Does This Rule Interact With the Acid Rain Program?

As EPA developed this regulatory action, much consideration was
given to interactions between the existing title IV Acid Rain Program
and today's action designed to achieve significant reductions in
SO₂ emissions beyond title IV. Requiring sources to reduce
emissions beyond what title IV mandates has both environmental and
economic implications for the existing title IV SO₂ cap and
trade program. In the absence of an approach for taking account of the
title IV program, a new program (i.e., the CAIR) that imposes a
significantly tighter cap on SO₂ emissions for a region
encompassing most of the sources and most of the SO₂
emissions covered by title IV would likely result in a significant
excess in the supply of title IV allowances, a collapse of the price of
title IV allowances, disruption of operation of the title IV allowance
market and the title IV SO₂ cap and trade system, and the
potential for increased SO₂ emissions. The potential for
increased emissions would exist in the entire country for the years
before the CAIR implementation deadline and would continue after
implementation for States not covered by the CAIR. These negative
impacts, particularly those on the operation of the title IV cap and
trade system, would undermine the efficacy of the title IV program and
could erode confidence in cap and trade programs in general.
Title IV has successfully reduced emissions of SO₂ using
the cap and trade approach, eliminating millions of tons of
SO₂ from the environment and encouraging billions of dollars
of investments by companies in pollution controls to enable the sale of
allowances reflecting excess emissions reductions and in allowance
purchases for compliance. In view of these already achieved reductions
and existing investments under title IV, the likelihood of disruption
of the allowance market and the title IV cap and trade system, and the
potential for SO₂ emission increases, it is necessary to
consider ways to preserve the environmental benefits achieved under
title IV and maintain the integrity of the market for title IV
allowances and the title IV cap and trade system. The EPA maintains
that it is appropriate to provide States the opportunity to achieve the
SO₂ emission reductions

[[Page 25291]]

required under today's action by building on, and avoiding undermining,
this existing, successful program.
The EPA has developed, in the model SO₂ cap and trade
rule, an approach to build on and coordinate with the title IV
SO₂ program to ensure that the required reductions under
today's action are achieved while preserving the efficacy of the title
IV program. The EPA's approach provides States the opportunity to
impose more stringent control requirements for EGUs' SO₂
emissions than under title IV through an EPA-administered cap and trade
program that requires the use of title IV allowances for compliance at
a ratio of 2 allowances per ton of emissions for allowances allocated
for 2010 through 2014 and 2.86 allowances per ton of emissions for
allowances allocated for 2015 or thereafter. (The program also allows
the use of banked title IV allowances allocated for years before 2010
to be used at a ratio of 1 allowance per ton of emissions.) Title IV
allowances continue to be freely transferable among sources covered by
the Acid Rain Program and sources covered by the model SO₂
cap and trade program under CAIR. However, each title IV allowance used
to comply with a source's allowance-holding requirement in the CAIR
model SO₂ cap and trade program is removed from the source's
allowance tracking system account and cannot be used again for
compliance, either in the CAIR model SO₂ cap and trade
program or the Acid Rain Program.
In addition, as discussed above, if a State wants to achieve the
SO₂ emissions reductions required by today's action through
more stringent EGU emission limitations only but without using the
model cap and trade program, then EPA is requiring that the State
include in its SIP a mechanism for retiring the excess title IV
allowances that will result from imposition of these more stringent EGU
requirements. In this case, the State must retire an amount of title IV
allowances equal to the total amount of title IV allowances allocated
to the units in the State minus the amount of title IV allowances
equivalent to the tonnage cap set by the State on SO₂
emissions by EGUs, and the State can choose what retirement mechanism
to use.
Further, as discussed above, if a State wants to meet the
SO₂ emissions reductions requirement in today's action
through reductions by both EGUs and non-EGUs, then EPA is also
requiring the State's SIP to include a mechanism for retiring excess
title IV allowances. In that case, the amount of title IV allowances
that must be retired equals the total amount of title IV allowances
allocated to the units in the State minus the amount of title IV
allowances equivalent to the tonnage cap set by the State on EGU
SO₂ emissions, and the State can choose what retirement
mechanism to use.
Finally, as discussed above, if the State wants to achieve the
SO₂ emissions reductions requirement in today's action
through reductions by non-EGUs only, then EPA is not imposing any
requirement to retire title IV allowances.
1. Legal Authority for Using Title IV Allowances in CAIR Model
SO₂ Cap and Trade Program
The EPA maintains that it has the authority to approve and
administer, if requested by a State in the SIP submitted in response to
today's action, the new CAIR model SO₂ cap and trade program
meeting the SO₂ emission reduction requirement in today's
action that requires use of title IV allowances to comply with the more
stringent allowance-holding requirement of the new program and
retirement under the CAIR SO₂ cap and trade program and the
Acid Rain Program of title IV allowances used for such compliance. Some
commenters claim that EPA's establishment of such a cap and trade
program using title IV allowances that sources must hold generally at a
ratio of greater than one allowance per ton of SO₂ emissions
is contrary to title IV. Most of these commenters prefer the approach
of allowing States to use a new EPA-administered cap and trade program
to meet lawful emission reduction requirements under title I and of
allowing (but not requiring) sources to use title IV allowances in the
new program. However, these commenters argue that title IV prohibits
requiring sources to use title IV allowances in such a program, whether
at the same tonnage authorization (i.e., one allowance per ton of
emissions) established in title IV or at a different tonnage
authorization. Other commenters state that title IV does not bar EPA
from establishing a new cap and trade program that requires the use of
title IV allowances.
The EPA maintains that it has the authority under section
110(a)(2)(D) and title IV to establish a new cap and trade program
requiring the use of title IV allowances at a different tonnage
authorization than under the Acid Rain Program and the retirement of
such allowances for purposes of both programs. First, as discussed in
section V above, EPA has the authority under section 110(a)(2)(D) to
establish a new SO₂ cap and trade program, administered by
EPA if requested in a State's SIP, to prohibit emissions that
contribute significantly to nonattainment, or interfere with
maintenance, of the PM_2.5 NAAQS. Further, EPA notes that
under section 402(3), a title IV allowance is:

An authorization, allocated to an affected unit by the
Administrator under this title [IV], to emit, during or after a
specified calendar year, one ton of sulfur dioxide. 42 U.S.C. 7651(a)(3).

However, section 403(f) states that:

An allowance allocated under this title is a limited
authorization to emit sulfur dioxide in accordance with the
provision of this title [IV]. Such allowance does not constitute a
property right. Nothing in this title [IV]
or in any other provision
of law shall be construed to limit the authority of the United
States to terminate or limit such authorization. Nothing in this
section relating to allowances shall be construed as affecting the
application of, or compliance with, any other provision of this Act
to an affected unit or source, including the provisions related to
applicable National Ambient Air Quality Standards and State
implementation plans. 42 U.S.C. 7651b(f).

The EPA interprets the reference in section 403(f) to the authority
of the ``United States'' to terminate or limit the authorization
otherwise provided by a title IV allowance to mean that EPA (acting in
accordance with its authority under other provisions of the CAA), as
well as Congress, has such authority.\137\

[[Page 25292]]

Therefore, EPA maintains that it has the authority to establish a new
cap and trade program in accordance with section 110(a)(2)(D) that
requires: the holding of title IV allowances under a more limited
authorization (i.e., 2 or 2.86 allowances per ton of emissions) by
sources in States participating in the new program; and the termination
of the authorization through retirement under the new program and the
Acid Rain Program of those title IV allowances used to meet the
allowance-holding requirement of the new program.
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\137\ The EPA's interpretation is based on the language of
section 403(f) and the legislative history of the provision. The
language in CAA section 403(f) contrasts with language that was in
section 503(f) of the House bill--but was excluded from the final
version of the CAA Amendments of 1990--referring to the authority of
the ``United States'' to terminate or limit such authorization ``by
Act of Congress'' and stating that ``[a]llowances under this title
may not be extinguished by the Administrator.'' U.S. Senate
Committee on Environment and Public Works, A Legislative History of
The Clean Air Act Amendments of 1990 (Legis. Hist. of CAAA), S. Prt.
38, 103d Cong., 1st Sess., Vol. II at 2224 (Nov. 1993). Further,
unlike CAA section 403(f), the House bill did not state that an
allowance did not constitute a property right. Section 403(f) of the
Senate bill that was considered, along with the House bill, in
conference committee had language different than both CAA section
403(f) and the House bill and stated that ``allowances may be
limited, revoked or otherwise modified in accordance with the
provisions of this title or other authority of the Administrator''
and that an allowance ``does not constitute a property right.''
Legis. Hist. of CAAA, Vol. III at 4598. While the scope of the
reference to the ``United States'' in CAA section 403(f) is not
clear, EPA maintains that the term is clearly broad enough to
include the Administrator. Moreover, even if the term were
considered ambiguous with regard to the Administrator, EPA believes
that interpreting the term to include the Administrator is
reasonable. Specifically, EPA maintains that, by eliminating the
explicit House bill language that required Congressional action and
including the general reference to the ``United States'' and the
``not a property right'' language, CAA section 403(f) essentially
adopted the Senate's approach and allows the United States--either
through Congressional or administrative (i.e., EPA) action--to
terminate or limit the allowance authorization. See Legis. Hist. of
CAAA, Vol. I at 754, 1034, and 1084 (Oct. 27, 2000 floor statements
of Sen. Symms, Sen. Baucus, and Sen. McClure indicating EPA has
authority to take such action); but see Cong. Rec. at E 3672 (Nov.
1, 2000)(extension of remarks of Cong. Oxley indicating that only
Congress has such authority).
---------------------------------------------------------------------------

Commenters' Arguments Based on Title IV
The commenters claiming that EPA is barred by title IV from
requiring use of title IV allowances at a reduced tonnage authorization
in a new cap and trade program rely on the above-noted provision in
section 402(3) stating that an allowance is an authorization to emit
one ton of SO₂. However, this provision does not bar EPA
from requiring either: use of title IV allowances in a new cap and
trade program under a different title of the CAA at a reduced tonnage
authorization; or retirement in this new program and the Acid Rain
Program of allowances used in this manner.
At the outset, it should be noted that the CAIR model
SO₂ cap and trade program does not change the tonnage
authorization of individual title IV allowances for purposes of the
Acid Rain Program until such an allowance is used to meet the
allowance-holding requirement of the CAIR SO₂ program. The
authorization provided by each title IV allowance for a source to emit
one ton of SO₂ emissions, as well as the requirement that
each source hold title IV allowances covering annual SO₂
emissions, continue to be in effect in the Acid Rain Program whether or
not the source is also covered by the CAIR SO₂ program. In
fact, the Acid Rain Program regulations continue to reflect both this
tonnage authorization and this allowance-holding requirement.\138\ See
final revisions to 40 CFR Sec. 73.35 adopted in today's action.
Moreover, the CAIR model SO₂ cap and trade rule coordinates
the determinations--made by EPA for sources subject to both title IV
and the CAIR--of compliance with the title IV and CAIR allowance-
holding requirements so that such determinations are made in a multi-
step, end-of-year process of comparing allowances held and emissions.
First, EPA determines whether the source holds sufficient title IV
allowances to comply with the one-allowance-per-ton-of-emissions
requirement in the Acid Rain Program as provided in Sec. 73.35; and
subsequently EPA determines whether the source holds the additional
title IV allowances that, when added to those held for Acid Rain
Program compliance, are sufficient to meet the CAIR allowance-holding
requirement. Violations of the Acid Rain allowance-holding requirement
will result in imposition of the penalty for excess emissions (i.e.,
the one-allowance offset plus $2,000 (inflation-adjusted) per ton of
excess emissions) under CAA section 411 and Sec. Sec. 73.35(d) and
77.4. See final Sec. 96.254(b)(1) adopted in today's action. Thus, the
Acid Rain allowance-holding requirement continues as a separate
requirement and reflects the one-allowance-per-ton-of-emissions
authorization under section 402(3).\139\
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\138\ As discussed below, today's action revises the Acid Rain
Program regulations to provide for source-based, instead of unit-
based, compliance with the allowance-holding requirement. These
revisions are adopted for reasons independent of the adoption of the
CAIR model SO₂ cap and trade program, as well as to
facilitate the coordination of these two SO₂ trading programs.
\139\ The commenters' assertion that the sources in a State that
does not participate in the CAIR SO₂ cap and trade
program will be cut off from the Acid Rain cap and trade program is
incorrect on its face. Such a source will continue to be subject to
the allowance-holding requirement and the compliance process in
Sec. 73.35 and will not be subject to the allowance-holding
requirement and the compliance process in the CAIR model
SO₂ cap and trade rule.
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In contrast with the one-allowance-per-ton-of-emissions requirement
under the Acid Rain Program, the CAIR SO₂ cap and trade
program requires each source generally to hold 2 or 2.86 Acid Rain
allowances for each ton of SO₂ emissions. Contrary to the
commenters' claim, this CAIR allowance-holding requirement is not
barred by the definition of the term ``allowance'' in section 402(3).
While section 402(3) defines the term ``allowance'' as an authorization
to emit one ton of SO₂, this provision expressly applies the
definition to the term ``[a]s used in this title [IV]'' and therefore
does not apply to the treatment of title IV allowances in a different
program under a different title of the CAA. Moreover, as noted above,
section 403(f) allows EPA to limit (or terminate) the authorization to
emit that an allowance otherwise provides under section 402(3).
Consequently, the allowance definition in section 402(3) does not bar
the treatment of a title IV allowance as authorizing less than one ton
of SO₂ emissions under the CAIR SO₂ cap and trade
program established under title I.\140\
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\140\ The commenters also seem to argue that the allowance
definition itself bars EPA from requiring use of Acid Rain
allowances in the CAIR SO₂ trading program even on a one-
allowance-per-ton-of-emissions basis. However, as noted above, the
definition is silent on whether title IV allowances may or may not
be used outside the Acid Rain Program.
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Once a title IV allowance is used to meet the more stringent
allowance-holding requirement in the CAIR SO₂ program, that
allowance is deducted from the source's allowance tracking system
account and cannot be used again, either in the CAIR SO₂
program or the Acid Rain Program. As noted above, EPA has the authority
under section 403(f) to require this termination of such a title IV
allowance's tonnage authorization for purposes of the Acid Rain
Program.
In addition to referencing section 402(3) to support claims that
EPA is barred from adopting the CAIR model cap and trade program
provisions on the use of title IV allowances, the commenters rely on
other title IV provisions that they characterize as setting a ``title
IV cap'' on SO₂ emissions. Stating that the requirement to
use title IV allowances in the CAIR model SO₂ cap and trade
program has the effect of reducing the ``title IV cap,'' these
commenters indicate, with little explanation, that such requirement is
unlawful. In mentioning the title IV cap, the commenters are apparently
referring to the fact that section 403(a)(1) (requiring allowance
allocations resulting in emissions not exceeding 8.90 million tons of
SO₂) and section 405(a)(3) (requiring additional allocations
of 50,000 allowances) require EPA to allocate annually, starting in
2010, a total amount of allowances authorizing no more than 8.95
million tons of SO₂ emissions. The commenters' argument
about how the CAIR model SO₂ cap and trade program
effectively reduces the ``title IV cap'' appears to be that elimination
of the ability to use, in the Acid Rain Program, title IV allowances
that will be used for compliance in the CAIR model SO₂ cap
and trade program has the effect of reducing the annual 8.95 million
ton cap on SO₂ emissions. This effective reduction of the
``title IV cap'' seems to occur when title IV allowances are used in
the CAIR SO₂ trading program with a reduced tonnage
authorization so that more title IV allowances are deducted per ton of
emissions than would be deducted for compliance with the Acid

[[Page 25293]]

Rain Program.\141\ The commenters claim that such a reduction in the
8.95 million ton cap is contrary to title IV.
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\141\ Similarly, to the extent title IV allowances are used in
the CAIR SO₂ trading program by non-Acid Rain sources,
the ``title IV cap'' seems to be effectively reduced because more
allowances are used in the CAIR SO₂ trading program and
effectively removed from use in the Acid Rain Program.
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In asserting an overarching principle that EPA is barred from
adopting any requirement that would have the effect of reducing the
8.95 million ton cap under title IV, the commenters do not point to any
specific statutory provision in support. The EPA maintains that not
only are there no such supporting provisions, but also certain title IV
provisions contradict this purported principle. Specifically, while
sections 403 and 405 require annual allowance allocations authorizing
no more than 8.95 million tons of emissions, section 403(f) provides,
as noted above, that EPA may terminate or limit the one-allowance-per-
ton-of-emissions authorization for a title IV allowance.\142\ Because
any termination or limitation of the tonnage authorization provided by
a title IV allowance for purposes of the Acid Rain Program would have
the effect of reducing the total tonnage of emissions allowed by the
allowance allocations (i.e., the 8.95 million ton cap) under sections
403 and 405, the commenters' claim that EPA is barred from adopting any
provision that has such an effect is wrong on its face.
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\142\ In light of this provision, the statement in the NPR
(particularly as it is interpreted by the commenters) that EPA lacks
authority to tighten the requirements of title IV (69 FR 4618, col.
1) is overly broad and is not repeated or adopted in today's preamble.
---------------------------------------------------------------------------

Commenters' Argument Based on Clean Air Markets Group Case

The commenters also state that the CAIR model SO₂ cap
and trade program is unlawful under the court's holding in Clean Air
Markets Group v. Pataki, 338 F.3d 82 (2d Cir. 2003). According to the
commenters, the required use of title IV allowances in the CAIR
SO₂ program constitutes an unlawful interference with the
operation of the interstate title IV SO₂ trading program,
presumably similar to the unlawful interference found by the court in
Clean Air Markets Group. However, the commenters provide little
explanation of how such use of title IV allowances (with or without a
reduced tonnage authorization) purportedly interferes with interstate
operation of the Acid Rain Program and how the holding in Clean Air
Markets Group applies to the CAIR SO₂ program.
In Clean Air Markets Group, the Court reviewed a State law that
imposed a monetary assessment on any title IV allowance sold by a New
York utility to a utility in any of 14 specified States or subsequently
transferred to such a utility, with the assessment equaling the
proceeds received in the allowance sale. The law also required that
each allowance sold include a covenant barring subsequent transfer of
the allowance to a utility in any of those States. The Court held that
the State law was pre-empted by title IV because the State law
impermissibly interfered with the method chosen by Congress in title IV
to reduce utilities' SO₂ emissions, i.e., the opportunity
for nationwide trading of title IV allowances. Id. at 87-88. In
particular, the Court found that the assessment of 100 percent of sale
proceeds ``effectively bans'' sales of any allowance by New York
utilities to utilities in the specified States and that the restrictive
covenant ``indisputedly decreases'' the value of the allowances. Id. at 88.
The EPA maintains that today's action is distinguishable from the
facts and holding in Clean Air Markets Group. In particular, EPA
believes that the exercise of its explicit authority under section
403(f) to limit the tonnage authorization of a title IV allowance in
the CAIR SO₂ cap and trade program and to terminate the
tonnage authorization in the Acid Rain Program once the allowance is
used in the CAIR SO₂ program is consistent with--and
necessary to preserve--the operation of the Acid Rain Program.
Therefore, EPA concludes that its approach of limiting and terminating
of the tonnage authorization of title IV allowances does not
impermissibly interfere with the interstate operation of the Acid Rain
Program and is reasonable.
Unlike the circumstances in Clean Air Markets Group, under EPA's
approach in today's action, each title IV allowance is freely
transferable nationwide unless and until a source uses the allowance to
meet the allowance-holding requirements of the CAIR SO₂
program, at which time the allowance is deducted from the source's
allowance tracking system account and retired for purposes of both the
CAIR SO₂ program and the Acid Rain Program. Further, EPA
expects that the ability to use title IV allowances to meet the more
stringent emission limitation under the CAIR SO₂ program to
maintain or increase (not decrease) the value of each title IV
allowance, until the allowance is used to meet the CAIR SO₂
program allowance-holding requirement and is retired.
Of course, this retirement of title IV allowances once they are
used to meet the CAIR allowance-holding requirement means that they
cannot thereafter be transferred to any person or be used again, e.g.,
to meet the Acid Rain Program allowance-holding requirement. As noted
by the Court in Clean Air Markets Group, section 403(b) provides that
title IV allowances ``may be transferred among designated
representatives of owners or operators of affected sources under [title
IV]
and any other person who holds such allowances, as provided by the
allowance system regulations'' promulgated by EPA.\143\ 42 U.S.C.
7651b(b). Moreover, section 403(d)(1) requires that the allowance
system regulations ``specify all necessary procedures and requirements
for an orderly and competitive functioning of the allowance system.''
42 U.S.C. 7651b(d). In the context of these statutory requirements, EPA
maintains that, on balance, the retirement of title IV allowances used
for compliance in the CAIR model SO₂ cap and trade program
does not constitute impermissible interference with the interstate
operation of the Acid Rain Program, but rather is consistent with, and
necessary to preserve, the operation of the Acid Rain Program.
---------------------------------------------------------------------------

\143\ While section 403(b) (as well as section 403(d)) refer
specifically to the allowance system regulations required to be
promulgated by the EPA Administrator within 18 months of November
15, 1990 (the enactment date of the CAA), the EPA Administrator has
authority under section 301 to amend such regulations ``as necessary
to carry out his functions under [the CAA].'' 42 U.S.C. 7601.
---------------------------------------------------------------------------

As noted above, the imposition of an SO₂ emission
limitation (such as in today's action) that is significantly more
stringent than the one under title IV and covers most of the sources
and emissions covered by title IV--but without addressing the impact on
the Acid Rain Program--would likely have several adverse consequences.
These adverse consequences would be: A significant excess of title IV
allowances; a collapse of the price of title IV allowances; disruption
of the title IV allowance market and the title IV SO₂ cap
and trade system; and potential SO₂ emission increases,
particularly in States outside the CAIR SO₂ region. The EPA
modeling indicates that, in 2010, EGU SO₂ emissions in
States not affected by the CAIR SO₂ program would increase
by about 260,000 tons (or about 29 percent of the approximately 0.9
million tons of SO₂ emissions projected for the non-CAIR
SO₂ region in 2010) in the absence of an approach for
addressing the impact of the CAIR SO₂ program on title IV. This

[[Page 25294]]

is because, with the imposition of the more stringent CAIR
SO₂ emission limitation in the CAIR SO₂ region,
this more stringent limitation becomes the binding limitation for
sources in that region. These CAIR SO₂ sources must comply
with, and cannot use title IV allowances to exceed, the CAIR
SO₂ emission limitation. Consequently, the portion of the
title IV allowances that equals the difference between the CAIR and the
title IV emission limitations is excess and would be available for use
only by Acid Rain sources that are outside the CAIR SO₂ region.
This excess amount of title IV allowances is potentially very
significant. Today's action requires that the States in the CAIR
SO₂ region achieve an amount of SO₂ emission
reductions in 2010 and 2015 equal to 50 percent and 65 percent,
respectively, of the amount of title IV allowances (about 7.3 million
allowances out of the total nationwide allocation of 8.95 million
allowances) allocated to the units in the CAIR SO₂ region.
If the States achieve all the required CAIR SO₂ reductions
through emission reductions by EGUs (which are largely the same units
that are subject to the Acid Rain Program) and if EGUs held only one
title IV allowance for each ton of SO₂ emissions as required
in the Acid Rain Program, the amount of surplus allowances allocated to
the States in the CAIR SO₂ region would be about 3.65
million allowances and 4.75 million allowances, respectively in 2010
and 2015.\144\ Moreover, the vast majority of EGUs nationwide (about 90
percent) and of EGU SO₂ emissions nationwide (about 90
percent) are covered by the CAIR SO₂ program. The net result
would be a large surplus of title IV allowances that would not be
usable in the CAIR SO₂ region and would be usable only by
the small subset of EGUs (about 10 percent) located in non-CAIR
SO₂ region States. Looking at the nation as a whole (both
CAIR and non-CAIR SO₂ States) in 2010, there would be total
allocations in the Acid Rain Program of 8.95 million title IV
allowances but, according to EPA modeling and analysis of the CAIR
without a requirement to retire surplus title IV allowances, total
projected SO₂ emissions for EGUs of only about 4.8 million
tons.\145\ Based on the principles of supply and demand, EPA concludes
that, with the amount of allowances allocated nation wide exceeding
SO₂ emissions for EGUs nationwide in 2010 by about 86
percent (i.e., 8.95 million allowances minus 4.8 million tons divided
by 4.8 million tons), the value of title IV allowances would fall to
zero, and all but 260,000 of the surplus allowances would have no
market and so, as a practical matter, would not be transferable.
---------------------------------------------------------------------------

\144\ The surpluses for 2010 and 2015 respectively are
calculated as: 7.3 million allowances minus ((100 percent minus the
percentage reduction requirement for the year) times 7.3 million
allowances).
\145\ The 4.8 million ton figure is the sum of: 3.65 million
tons of emissions (equal to the tonnage equivalent of the allowance
allocations in the CAIR SO₂ region); plus about 0.9
million tons of emissions in the non-CAIR SO₂ region with
the retirement of surplus title IV allowances; plus 260,000 tons of
increased non-CAIR SO₂ region emissions if the surplus
title IV allowances are not retired.
---------------------------------------------------------------------------

The EPA notes that this effect on allowances would occur no matter
how the State implements the more stringent SO₂ emission
limitation required under the CAIR, e.g., whether implementation is
through a new cap and trade program (like in the model rule) or through
a fixed (command and control) tonnage emission limit imposed on each
individual source. Consequently, the alternatives faced by EPA are
either: (1) To establish a CAIR model cap and trade program (or allow
States to use another means of achieving CAIR SO₂ emissions
reductions) that does not retire the 3.65 million surplus allowances
and that results in the devaluation of all title IV allowances to zero
and the effective non-transferability of all but 260,000 of the 3.65
million surplus allowances in 2010; or, as provided in today's action,
(2) to adopt a CAIR SO₂ model cap and trade program (or
another means of achieving reductions) that retires the 3.65 million
surplus allowances and that results in the non-transferability of the
entire 3.65 million surplus of title IV allowances and ensures the
remaining, unused title IV allowances have market value. Thus, with
regard to the impact on the transferability of title IV allowances,
EPA's decision to adopt the second alternative of retiring the surplus
allowances adversely affects the transferability of only a relatively
small amount (260,000 out of 8.95 million per year) of allowances, as
compared to the amount of allowances whose transferability would be
adversely affected under the first alternative.
Moreover, with the total collapse of the title IV allowance price
in the Acid Rain Program, the nationwide cap and trade system under
title IV--which would be the binding cap and trade system only for
sources in the States outside the CAIR SO₂ region--would
lose all efficacy. The title IV cap and trade system operates by:
Making owners of sources pay for the authorization to emit
SO₂ by surrendering, to EPA, allowances that have a market
value; and by allowing owners (e.g., those who choose to reduce
emissions) to sell unused allowances. Whether the sources' allowances
were originally allocated to the sources or were purchased, the owners
must decide the extent to which it is more efficient to give up the
market value of such allowances or to reduce emissions. If title IV
allowances were to have no market value, the title IV cap and trade
system would no longer affect the choice of whether to emit or to
reduce emissions.\146\
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\146\ See Sen. Rep. No. 101-228, 101st Cong., 1st Sess. at 324
(Dec. 20, 1989) (stating that ``[a]llowances are intended to
function like a currency that is sufficiently valuable to stimulate
efforts to acquire it through innovative and aggressive efforts to
reduce emissions more than required'' and that, in the event of
``inflation in the currency,'' the incentives to ``reduce pollution
* * * will be seriously weakened.'' In the instant case, without a
requirement to retire excess title IV allowances, the currency would
be inflated to a value of zero. See also Legis. Hist. of CAAA, Vol.
I at 1033 (Oct. 27, 1990 floor statement of Sen. Baucus explaining
that ``[s]ince units can gain cash revenues from the sale of
allowances they do not use, they will have a financial incentive
both to make greater-than-required reductions and/or reductions
earlier than required'' and that ``incentives created by the
allowance market should stimulate innovations in the technologies
and strategies used to reduce emissions'' including energy efficiency).
---------------------------------------------------------------------------

The EPA maintains that such a result is contrary to Congressional
intent. The purposes of title IV include not only reductions of annual
SO₂ emissions from 1980 levels, but also the encouragement
of ``energy conservation, use of renewable and clean alternative
technologies, and pollution prevention as a long-range strategy,
consistent with the provisions of this title, for reducing air
pollution and other adverse impacts of energy production and use.'' 42
U.S.C. 7651(b). Reflecting these purposes, Congress required EPA to
promulgate allowance system regulations for the Acid Rain Program that
would promote ``an orderly and competitive functioning of the allowance
system.'' 42 U.S.C. 7651b(d)(1). See Sen. Rep. No. 101-228, 101st
Cong., 1st Sess. at 320 (explaining that ``the allowance system is
intended to maximize the economic efficiency of the program both to
minimize costs and to create incentives for aggressive and innovative
efforts to control pollution''). As discussed above, if title IV
allowances were to have no market value, the cap and trade system under
title IV would no longer affect owners' decisions on whether to emit or
to control emissions and so would no longer provide encouragement (e.g.,

[[Page 25295]]

incentives for innovation) for avoidance or reduction of SO₂
emissions.\147\
---------------------------------------------------------------------------

\147\ While the title IV cap and trade system could be replaced
by a new CAIR SO₂ cap and trade system that did not
address the problems caused by surplus title IV allowance, that new
cap and trade system would not be nationwide like the title IV cap
and trade system and so would not cover sources outside the CAIR
SO₂ region.
---------------------------------------------------------------------------

In addition, EPA is concerned that such disruption of the title IV
allowance market and the title IV SO₂ cap and trade system
would significantly erode confidence in cap and trade programs in
general and the CAIR model cap and trade programs in particular. As
noted above, under the Acid Rain Program, companies have made billions
of dollars of investments in emission controls in order to be able to
sell excess title IV allowances and in purchasing title IV allowances
for future compliance (e.g., under annual, 1-day allowance auctions
held by EPA, one as recently as March 22, 2004 when title IV allowances
were purchased for about $50 million). While in a market-based program
like the Acid Rain Program, investments are necessarily subject to the
vagaries of the market, EPA believes that it should try, to the extent
possible consistent with statutory requirements, to avoid taking
administrative actions that would cause such extensive disruption of
the Acid Rain Program. Allowing such disruption to occur could
significantly reduce the willingness of owners of sources in new cap
and trade programs to invest in measures that would result in excess
allowances for sale or to purchase allowances for compliance. To the
extent owners would ignore the allowance-trading option and simply
control emissions to the level equal to their source's allocations,
this would obviate the incentives for innovation, and hamper
realization of the potential for cost savings, that would otherwise be
provided by new cap and trade programs (such as the CAIR model cap and
trade programs).
Finally, as noted above, such disruption of the Acid Rain Program
would potentially result in significantly increased SO₂
emissions (about 29 percent in 2010) in States covered by the Acid Rain
Program but outside the CAIR SO₂ region.\148\ This would
have the effect of reversing, at least in part, the beneficial effect
that the Acid Rain Program has had on SO₂ emissions in those
States, even though the overall goal of nationwide SO₂
emissions reductions would still be met. See 42 U.S.C. (a)(1)
(Congressional finding that ``the presence of acidic compounds and
their precursors in the atmosphere and in deposition from the
atmosphere represents a threat to natural resources, ecosystems,
materials, visibility, and public health'').
---------------------------------------------------------------------------

\148\ The EPA notes that the potential for increased emissions
within the CAIR SO₂ region would occur before the
implementation of the CAIR SO₂ program and is addressed
by allowing pre-2010 banked title IV allowances to be used to meet
the CAIR allowance holding requirement beginning in 2010.
---------------------------------------------------------------------------

In light of these considerations,\149\ EPA concludes, on balance,
that structuring the CAIR model SO₂ cap and trade program in
a way that avoids such extensive disruption of the Acid Rain Program
(i.e., by requiring retirement from the Acid Rain Program of title IV
allowances used for compliance in the CAIR SO₂ program) does
not constitute impermissible interference with the interstate operation
of the Acid Rain Program. Rather, this approach in the model
SO₂ cap and trade rule is consistent with, and preserves,
such operation--while providing States a tool for imposing the more
stringent SO₂ emission limitations required under title I--
and is a reasonable exercise of EPA's authority under section 403(f) to
terminate or limit the tonnage authorization of title IV allowances.
---------------------------------------------------------------------------

\149\ While the potential for increased emissions outside the
CAIR SO₂ region supports EPA's conclusion, EPA maintains
that, even in the absence of any such increase, the other
considerations discussed above are sufficient to justify the
conclusion that the retirement of title IV allowances does not
impermissibly interfere with the Acid Rain Program and is
reasonable.
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2. Legal Authority for Requiring Retirement of Excess Title IV
Allowances if State Does Not Use CAIR Model SO₂ Cap and
Trade Program
As discussed above, a State has the additional options of achieving
the SO₂ emissions reductions required by today's actions
through: EGU emission reductions only but without using the model
SO₂ cap and trade rule; some EGU and some non-EGU emissions
reductions; or non-EGU reductions only. The requirement to retire
excess title IV allowances applies only in the first and second of
these three additional options. The State must retire an amount of
title IV allowances equal to the total amount of title IV allowances
allocated to units in the State minus the amount of allowances
equivalent to the tonnage cap set by the State on EGUs' SO₂
emissions and can choose what mechanism to use to achieve such
retirement. The EPA has the authority to require that the State include
in its SIP a mechanism for retiring the excess title IV allowances that
will result under these two options.
As discussed above, EPA has the authority under section 403(f) to
terminate or limit the authorization to emit otherwise provided by a
title IV allowance. Specifically, EPA has the authority to: require
that any EGU SO₂ emission reduction program, chosen by a
State to meet (in full or in part) the requirements of section
110(a)(2)(D), include provisions for retiring excess title IV
allowances resulting from the implementation of the more stringent
emission reduction requirement under the State program; and to require
that such retired title IV allowances cannot be used in the Acid Rain
Program. As discussed above, the commenters' claims that such a
retirement requirement is barred by title IV (relying on, e.g., the
section 402(3) definition of ``allowance'' and on the ``title IV cap'')
lack merit. Also, for the reasons discussed above, the retirement
requirement is not unlawful under Clean Air Markets Group and is a
reasonable exercise of EPA's authority under section 403(f) to
terminate or limit the tonnage authorization of title IV allowances.
Some commenters also claim that the retirement requirement
unlawfully constrains the States' authority to determine in the first
instance the control measures to use in meeting emission reduction
requirements necessary to comply with section 110(a)(2)(D). According
to the commenters, since only EGUs are subject to title IV, the
requirement to retire title IV allowances is in effect a mandate that
the State control EGU emissions.
However, EPA is imposing the requirement for a State mechanism to
retire title IV allowances only if the State decides in the first
instance to require any EGU SO₂ emissions reductions to meet
the emission reduction requirements under today's action. A State that
decides not to require any EGU SO₂ emissions reductions for
this purpose is not required to retire title IV allowances. Further,
the amount of the required allowance retirement is limited to the
amount of EGU SO₂ emissions reductions that the State
decides in the first instance to require from EGUs (i.e., the total
title IV allowance allocations in the State minus the tonnage amount of
the cap set by the State for EGUs' SO₂ emissions). In short,
the allowance retirement requirement echoes the State's decision in the
first instance concerning the amount of SO₂ emissions
reductions to require from EGUs in the State. The EPA simply requires
the State to implement the State's EGU-SO₂-emission-
reduction-requirement decision in a manner that avoids the otherwise
likely, extreme disruption of the title IV SO₂ cap and trade
system that is described above. Further, the

[[Page 25296]]

State may choose what mechanism to include in its SIP revision for
achieving the required allowance retirement, and EPA will review the
effectiveness of the mechanism in achieving such retirement, and
approve and adopt the mechanism if appropriate, in an EPA rulemaking
concerning the SIP revision. Therefore, EPA concludes that the
allowance-retirement requirement is lawful and is a reasonable
condition for EPA approval of those State SIPs that require EGU
SO₂ emission reductions without using the CAIR model
SO₂ trading program.
The EPA notes that the requirement to retire excess title IV
allowances--where a State adopts the CAIR model SO₂ trading
program or where a State SIP obtains EGU emissions reductions through
some other means--is reflected in provisions in both the proposed rules
in the SNPR (i.e., in proposed Sec. Sec. 51.124(p) and 96.254(b)) and
in the final rules adopted by today's action (i.e., in final Sec. Sec.
51.124(p) and 96.254(b)). In reviewing the proposed rules in light of
the comments received, EPA has concluded that, for consistency and
clarity, the Acid Rain Program regulations should also reference this
same retirement requirement. Consequently, today's action adds a new
paragraph (a)(3) to Sec. 73.35 of the Acid Rain Program regulations
that reiterates the requirement--addressed in the preamble and
regulations in both the SNPR and today's action--that title IV
allowances previously used to meet the allowance-holding requirement in
the CAIR model trading program in Sec. 96.254(b) or otherwise retired
in accordance with Sec. 51.124(p) cannot be used to meet the
allowance-holding requirement in the Acid Rain Program. Additional
revisions of the Acid Rain Program regulations are discussed below.
3. Revisions to Acid Rain Regulations
In the SNPR, EPA proposed to revise the Acid Rain Program
regulations, effective July 1, 2005, to implement the allowance-holding
requirement on a source-by-source, rather than on a unit-by-unit,
basis. Instead of requiring each unit to hold an amount of allowances
in its Allowance Tracking System account (as of the allowance transfer
deadline) at least equal to the tonnage of SO₂ emissions for
the unit in the preceding calendar year, the proposal required each
source to hold an amount of allowances in its Allowance Tracking System
account at least equal to the tonnage of SO₂ emissions for
all affected units at the source for such calendar year. Because
language reflecting or referencing the unit-by-unit compliance approach
is included in many provisions of the Acid Rain Program regulations, a
significant number of proposed rule revisions were necessary to
implement source-by-source allowance holding.
In today's final rule, EPA is adopting, with minor modifications,
the proposed rule revisions implementing source-by-source compliance
with the allowance-holding requirement. As explained in detail in the
SNPR (69 FR 32698-32701), EPA finds that: Title IV is ambiguous with
regard to whether unit-by-unit compliance is required and so EPA has
discretion in this matter; it is important to provide additional
compliance flexibility by allowing a unit at a source to use allowances
from any other unit at the same source; and many other, non-allowance-
holding provisions of title IV evidence a unit-by-unit orientation.
Further, as discussed in the SNPR, EPA concludes that the adoption of
source-level compliance reasonably balances these considerations. In
balancing these considerations, EPA also concludes that company-level
compliance is not appropriate because it represents too much of a
deviation from the unit-by-unit orientation in the non-allowance-
holding provisions of title IV and is likely to require much more
dramatic changes in the operation of the Acid Rain Program. See 69 FR
32699-700. It is important to note that the final rule revisions, like
the proposed revisions, change only the allowance-holding requirement
and not the emissions monitoring and reporting requirements, which
continue to be applied unit by unit.
In today's action, EPA is making the source-level-compliance rule
revisions effective July 1, 2006, which is 1 year later than proposed.
The shift from unit-level to source-level compliance will require
software changes and testing to ensure that the Allowance Tracking
System operates properly. Currently, EPA is in the process of
conducting a general review and re-engineering of the Allowance
Tracking System and Emissions Tracking System and anticipates
completing the process in 2006. The process of shifting the Allowance
Tracking System to source-level compliance will be much more efficient
and less likely to have adverse results on the system if the shift is
coordinated with the general review and re-engineering and therefore
implemented starting July 1, 2006. Further, as discussed below, this
delay of implementation for 1 additional year will give owners
additional time to make changes that they determine are necessary in
order to adapt to source-level compliance.
Some commenters support the shift to source-by-source allowance
holding, and some oppose the change. One commenter opposing the change
claims that a source-by-source allowance-holding requirement is
``contrary to market-based principles.'' According to the commenter,
market-based systems give operators the tools for achieving compliance
through allowance transfers, but with source-level compliance the
operators do not have to take any action to maintain sufficient
allowances because EPA will move the allowances around for them.
The commenter's argument is based on an incorrect premise. Whether
compliance is unit-by-unit or source-by-source, the owner or owners of
the affected units at each source must take the same types of actions
in order to comply with the applicable allowance-holding requirement.
In particular, under source-level compliance, such owner or owners must
reduce emissions, retain allowances allocated to such units, obtain
additional allowances, or take a combination of these actions to ensure
that the Allowance Tracking System account for the source holds enough
allowances to cover the total emissions of the affected units at the
source. The owner or owners also have the option of reducing emissions
below allocations so that there are extra allowances available to hold
for future use or sale. If the owner or owners do not have enough
allowances to cover the emissions from the source, EPA will not move,
on its own initiative, allowances into the source's compliance account
from other sources' accounts or from general accounts, even if there
are extra allowances in the other accounts. The only difference between
the types of actions owners must take under the unit-level and source-
level approaches is that, under unit-level compliance, the owners must
transfer allowances from one unit at a source to a second unit at that
source in order to use the first unit's allowances for compliance by
the second unit while, under source-level compliance, any allowance
held for compliance for the first unit can be used--without a
transfer--for compliance by the second unit. This difference is
reflected in the Allowance Tracking System, which, under the unit-level
approach, includes a separate account for each unit and, under the
source-level approach, includes a single account for all the affected
units at a single source.
In summary, the mechanism, and the owners' responsibilities, for
achieving

[[Page 25297]]

compliance with the allowance-holding requirements are analogous under
unit-by-unit and source-by-source compliance, except that, under
source-by-source compliance, allowances need not be transferred among
units at the same source. The EPA does not believe that the source-by-
source approach is any less market-based than the unit-by-unit
approach. Owners will still have the ability to reduce emissions or
purchase or sell allowances and the responsibility to take actions
(including the holding of extra allowances) to ensure they have enough
allowances to cover emissions. Moreover, the market-price of allowances
will still play a crucial role in owners' decisions on what actions to
take. The EPA's adoption of source-by-source compliance preserves
market-based principles, while reasonably balancing of the ambiguity of
title IV, the need for additional compliance flexibility, and the unit-
by-unit orientation of many provisions in title IV. See 69 FR 32699-700.
The commenter also argues that having a source-level allowance-
holding requirement in the Acid Rain Program (and the CAIR model cap
and trade program) is inconsistent with unit-level compliance in the
NO_X SIP Call cap and trade program. However, other than
pointing out this difference, the commenter fails to explain why the
programs must be identical in this regard. Based on experience with the
Acid Rain Program (as well as the NO_X SIP Call trading
program), EPA concludes that a source-level allowance-holding
requirement will result in a somewhat less complicated program and a
reduced likelihood of inadvertent, minor errors, while achieving the
program's environmental goals. See 69 FR 32699-700.
The commenter suggests that, instead of adopting source-level
compliance, EPA revise the Acid Rain Program regulations to allow for
source over-draft accounts, like those allowed in the NO_X
SIP Call cap and trade program. Under the NO_X SIP Call
program, each source may have a source over-draft account, in which may
be held extra allowances that may be used for compliance by any
affected unit at the source. However, EPA believes that source-level
compliance is a better approach than unit-level compliance with over-
draft accounts. Relatively few owners in the NO_X SIP Call
cap and trade program actually put allowances in over-draft accounts,
and achievement of compliance is made more complicated by the ability
of all units at a source to draw on the over-draft account (if any
allowances are put in it) but the inability of any unit to use extra
allowances held instead by another unit at the source. Consequently,
rather than adopting in the Acid Rain Program the unit-level approach
with over-draft accounts, EPA is today adopting the source-level
approach in the Acid Rain Program and may consider in the future, as
appropriate, adopting the source-level approach in other programs using
unit-level compliance.
One commenter states that EPA should revise the Acid Rain Program
regulations to allow owners, each year, the option of choosing whether
to use unit-level or source-level compliance. According to the
commenter, significant investments have been made to monitor and report
emissions and surrender allowances under the existing Acid Rain Program
regulations, and shifting to source-level compliance will require
substantial resources and time. The commenter also states that unit-
based compliance should be retained as an option ``to accommodate joint
ownership and other special arrangements that may not affect an entire
facility.''
The EPA rejects the suggestion of allowing each owner the option,
for each year and for each source, of choosing between unit-level and
source-level compliance. Such an approach would significantly
complicate the achievement by sources, and the determination by EPA, of
compliance. The potential for error (e.g., due to erroneous assumptions
about whether unit-or source-level compliance would be applicable to a
particular source for a particular year) on the part of owners or EPA
would be significantly increased. Moreover, this complicated approach
would result in inconsistent treatment from source to source and year-
to-year. Further, the commenter provided only vague assertions about
the benefits of unit-based compliance in certain circumstances and did
not assert--much less show--that source-level compliance cannot be
accommodated under those circumstances. The EPA maintains that the only
reasonable options for the allowance-holding requirement in the Acid
Rain Program are either generally requiring compliance by all sources
each year on a unit-level basis (as in the existing regulations) or
requiring compliance by all sources each year on a source-level basis
(as in the proposed revisions to the regulations). For the reasons
discussed above, EPA believes that source-level compliance for the
allowance-holding requirement is preferable. By postponing until July
1, 2006 the effective date of the rule revisions shifting to source-
level compliance (with the result that 2006 is the first year of
source-level compliance), EPA is providing owners a reasonable amount
of time to make any necessary adjustments, such as those claimed by the
commenter. Further, as noted above, the rule revisions change only the
allowance-holding requirement and not the emissions monitoring and
reporting requirements. This should limit the scope of adjustments
necessary for owners to implement source-level compliance and will
preserve the availability of reliable, unit-level emissions data.
Because unit-level compliance is reflected throughout the Acid Rain
Program regulations, numerous revisions of the regulations are
necessary to implement source-level compliance. (None of these changes
are to the emissions monitoring and reporting provisions in part 75
since monitoring and reporting continue to be on a unit basis.) One
commenter requested that EPA provide ``more in-depth detail'' on the
proposed revisions. However, in the SNPR, EPA described the types of,
and reasons for, revisions that are necessary for source-level
compliance (69 FR 32700-01) and set forth all of the specific, proposed
changes (69 FR 3273-41). Moreover, no commenters stated that they did
not understand any specific, proposed revision or the reason for any
specific revision. The EPA notes that in reviewing the proposed Acid
Rain rule revisions in light of the comments, EPA found some additional
references in the Acid Rain rule to unit-level compliance that should
be revised to reflect source-level compliance. In today's action, EPA
is adopting revisions of these additional references (e.g., changing
references to a ``unit's account'' or a ``unit account'' to a source's
``compliance account'') that are analogous to the revisions
specifically identified in the SNPR.\150\
---------------------------------------------------------------------------

\150\ This approach is consistent with the SNPR, where EPA
proposed to convert all references, including any initially missed
in the SNPR, from unit- to source-level compliance (69 FR 32700).
---------------------------------------------------------------------------

Another commenter opposed the rule revisions implementing source-
level compliance on several other grounds. The commenter claims,
without citing any statutory support, that the Acid Rain Program is
based on ``control of emissions at the unit level'' so that, in the
event of excess emissions, the ``source as a whole would not be
punished'' and ``corrective action could take place'' at the particular
unit. According to the commenter, source-level compliance will: Make it
harder to determine which unit caused excess emissions; make the
existing Acid Rain

[[Page 25298]]

permits meaningless; make the individual unit allowance allocations
meaningless; and cause confusion over which units at a source are
affected units.
While there are many non-allowance-holding provisions in title IV
that have a unit-by-unit orientation, EPA disagrees with the
commenter's basic assertion that the purpose of the Acid Rain Program
is to control emissions on a unit-by-unit basis and that there is a
need to ``distinguish'' the compliance of each individual unit. The
provisions concerning application of the allowance-holding requirement
are ambiguous as to whether EPA must implement the requirement on a
unit-level or a source-level, and the environmental benefits of the
Acid Rain Program will still be realized with source-level compliance.
See 69 FR 32699-700. Further, while EPA will determine compliance on a
source-by-source basis, nothing in the regulations prevents owners
(e.g., owners of units at sources with multiple units and multiple
owners or owners of units with multiple owners and exhausting through a
common stack) from determining by agreement which owners will bear any
excess emissions penalties that occur at the plant and have to take
correction actions. Indeed, owners are likely to already have these
types of agreements in cases of units or sources with multiple owners.
This is because the Acid Rain Program regulations already allow a unit
at a multi-unit source to use some allowances from other units at the
source (albeit to cover most but not all of the potential excess
emissions) and already allow one unit exhausting from a common stack to
use allowances from another unit at that stack (without any limitation
on such use). See 40 CFR 73.35(b)(3) and (e). In addition, while the
Acid Rain permits will have to be revised in the future to reflect
source-level compliance, today's rule does not make source-level
compliance effective until 2006. Permits will not have to be revised
until around the end of 2006, which should provide States a reasonable
opportunity to amend the permits. Contrary to the claims of the
commenter, source-level compliance does not make the unit-by-unit
allocations meaningless; the unit-by-unit allocations (set forth in
Table 2 of Sec. 72.10) will determine the amount of allocations
reflected in each Allowance Tracking System source account, which
amount will equal the sum of the allocations for all affected units at
the source. Finally, the commenter failed to explain how the source-
level allowance-holding requirement could cause ``confusion'' over
which units are affected units. This source-level requirement does not
change the applicability provisions, which are still applied unit by unit.
As discussed in the SNPR, EPA proposed--in addition to the rule
revisions to implement source-level compliance--other revisions of the
Acid Rain Program regulations in order to facilitate coordination of
the Acid Rain Program and the CAIR SO₂ cap and trade
program. These additional revisions were described and explained in the
SNPR (69 FR 32701). The EPA is adopting these revisions for the reasons
in the SNPR, as amplified below. Most of these revisions are supported,
or not opposed, by commenters, but some commenters objected to certain
revisions.
For example, EPA noted that it had recently changed the
``cogeneration unit'' definition in Sec. 72.2 in June 2002 (67 FR
40394, 40420; June 12, 2002). The original definition in Sec. 72.2 had
been used since the commencement of the Acid Rain Program. The only
significant difference between the original and revised definitions is
that the former refers to a unit ``having the equipment used to
produce'' electricity and useful thermal energy through sequential use
of energy, while the latter simply refers to a unit ``that produces''
electricity and useful thermal energy in that manner. The reason that
EPA gave for revising the definition in June 2002 was to conform with
the definition in the Section 126 rule. However, the Section 126 rule
(and the NO_X SIP Call) did not actually specify a
``cogeneration unit'' definition. Consequently, there is no reason to
use the June 2002 revised definition. Moreover, EPA is concerned that
the change in the definition of ``cogeneration unit'' as of June 2002
may cause confusion or raise question about what units qualify for
exemptions for ``cogeneration units'' from the Acid Rain Program. Under
these circumstances, EPA concludes that the definition should be
changed back to the original definition in Sec. 72.2 and, in any
event, intends to interpret the June 2002 revised definition as having
the same meaning as the original definition. One commenter raised
concerns that EPA did not provide any ``detailed analysis'' of the
implications of changing the ``cogeneration unit'' definition. However,
as discussed above, the change simply reinstates the definition that
had been used in the Acid Rain Program from the initial promulgation of
implementing regulations in 1993 until 2002. No commenter asserted that
reverting to the longstanding, original definition would be disruptive.
Another Acid Rain Program rule revision proposed in the SNPR is the
elimination of the requirement for owners and operators to submit an
annual compliance certification report for each source. One commenter
expressed concern, because the purpose of the annual certification is
to ensure that the designated representative is ``aware and has assured
the quality of the data'' being submitted to EPA. However, as noted in
the SNPR, designated representatives must evidence such awareness and
compliance by submitting, with each quarterly emissions report, a
certification that the monitoring and reporting requirements under part
75 of the Acid Rain Program regulations have been met. See 40 CFR
75.64(c). Quarterly emissions reports are available on-line to the
public and the States. In addition, owners and operators of sources
subject to the Acid Rain Program must submit, under title V of the CAA,
annual compliance certification reports concerning all CAA requirements
(including Acid Rain Program requirements). Under these circumstances,
EPA maintains that the separate Acid Rain Program annual compliance
certification reports are duplicative and unnecessary. The EPA notes
that it appears that few, if any, requests for copies of these Acid
Rain Program reports have been made by States or any other persons
since the commencement of the Acid Rain Program. Apparently, other
certifications and submissions required of owners and operators have
been sufficient for the purposes cited by the commenter.
The SNPR also included proposed revisions eliminating the
requirement under the Acid Rain Program for a 1-day newspaper notice
for designation of designated representatives and authorized account
representatives. One commenter suggests that this notice should be
replaced by a requirement to notify the State permitting authority. The
EPA notes that information on designated representatives and authorized
account representatives is already available to State permitting
authorities through on-line access to the Allowance Tracking System.
Moreover, EPA is in the process of developing, and anticipates
establishing in the near future, the ability to send State permitting
authorities (at their request) on-line notices of changes in designated
representatives (who are also the authorized account representatives
for affected sources' accounts).

[[Page 25299]]

Other proposed Acid Rain Program rule revisions on which EPA
received adverse comment are the removal of Sec. 73.32 (prescribing
the contents of an allowance account) and Sec. 73.51 (prohibiting the
transfer of allowances from a future year subaccount to a subaccount
for an earlier year). Section 73.32 sets forth a rather self-evident
list of information that must be recorded in an allowance account in
the Allowance Tracking System, such as the name of the authorized
account representative, the persons represented by the authorized
account representative, and the transfers of allowances in and out of
the account. This section also references information on compliance or
current year subaccounts and future year subaccounts, as well as
emissions information. As discussed in the SNPR, several items on the
list of informational contents for allowance accounts are out-of-date
in that they do not reflect how the electronic Allowance Tracking
System operates or will operate in the near future. For example, the
electronic Allowance Tracking System does not currently use or refer to
subaccounts, which will continue to be unnecessary in the context of
source-level compliance.\151\ See 69 FR 32700-01. In addition, while
Sec. 73.32 states that emissions data are reflected in the Allowance
Tracking System account, such data are currently available instead
through the electronic Emissions Tracking System. Because the
information list in Sec. 73.32 contains either self-evident items or
items that are out-of-date and because the NO_X Allowance
Tracking System has been operating successfully even though the model
NO_X Budget cap and trade rule and State cap and trade rules
under the NO_X SIP Call lack a provision analogous to Sec.
73.32, EPA is removing Sec. 73.32. EPA notes that the removal of the
section will not mean that the information contained in allowance
accounts ``can be changed at will.'' The format for allowance accounts
is set forth in the electronic Allowance Tracking System and implements
the requirements in the Acid Rain Program regulations concerning the
holding, transferring, recording, and deducting of allowances.
---------------------------------------------------------------------------

\151\ In reviewing the proposed Acid Rain Program rule
revisions, EPA found some additional references to ``subaccounts''
that were not specifically noted in the SNPR. For consistency and
clarity in the Acid Rain Program rules, EPA is adopting in today's
action revisions (e.g., chaning the term ``subaccount'' to
``compliance account'') of these additional references, which
revisions are analogous to those specifically set forth in the SNPR.
This approach is consistent with the SNPR, where EPA proposed to
convert all references, including any initially missed in the SNPR,
from subaccount to compliance account, (69 FR 32700).
---------------------------------------------------------------------------

Section 73.51 prohibits the transfer of allowances from a future
year subaccount to a subaccount for an earlier year. The removal of
this section is consistent with the elimination throughout the rest of
the Acid Rain Program regulations, as discussed in the SNPR (id.), of
any references to such subaccounts. Further, the prohibition on using
allowances allocated for a year to meet the allowance-holding
requirement for a prior year is retained in other provisions of the
Acid Rain Program regulations. Consequently, EPA is removing Sec. 73.51.

C. How Does the Rule Interact With the Regional Haze Program?

This section discusses the relationship of the CAIR cap and trade
program for EGUs with the regional haze program under sections 169A and
169B of the CAA, in particular the requirements for Best Available
Retrofit Technology (BART) for certain source categories including
EGUs. The legislative and regulatory background of the BART provisions
were presented in some detail in the SNPR. (See 69 FR 32684, 32702-704,
June 10, 2004). In brief, BART regulations consist of two components.
The first, promulgated in 1980, addresses visibility impairment that
can be ``reasonably attributed'' to a single source or small group of
sources. (45 FR 80085; December 2, 1980, codified at 40 CFR 51.302).
The second component addresses BART in relation to regional haze
(visibility impairment caused by a multitude of broadly distributed
sources) and was promulgated as part of the Regional Haze Rule. (64 FR
35714; July 1, 1999). Certain parts of the BART provisions in that rule
were vacated by the U.S. Court of Appeals for the DC Circuit in
American Corn Growers et al. v. EPA, 291 F.3d 1 (DC Cir., 2002). To
address that decision, in May 2004, EPA proposed changes to the
Regional Haze Rule and reproposed the Guidelines for BART
Determinations (originally proposed in 2001) (69 FR 25185, May 5, 2004).
On February 18, 2005, the DC Circuit decided another case dealing
with BART and a BART alternative program, Center for Energy and
Economic Development v. EPA, No. 03-1222, (DC Cir. Feb. 18, 2005)
(``CEED''). In this case, the court granted a petition challenging
provisions of the regional haze rule governing the optional emissions
trading program for certain western States and Tribes (the ``WRAP Annex
Rule''). The holdings of the case are relevant to today's action in
several respects.
Most importantly for purposes of the CAIR, CEED affirmed EPA's
interpretation of CAA 169A(b)(2) as allowing for non-BART alternatives
where those alternatives make greater progress than BART. (CEED, slip.
op. at 13) (finding that EPA's interpretation of CAA 169(a)(2) as
requiring BART only as necessary to make reasonable progress passes the
two-pronged Chevron test).
The particular provisions involved in CEED applied, on an optional
basis, only to nine western States \152\ (none of which are in the CAIR
region) and the Tribes therein. The provisions, contained in 40 CFR
51.309 (``section 309'') required among other things that States
choosing to participate in a ``backstop'' \153\ cap and trade program
must demonstrate that the emissions reductions under the program
resulted in greater progress towards the national visibility goals than
would BART. At issue was the particular methodology required for this
demonstration. Specifically, EPA's rule required that visibility
improvements under source-specific BART--the benchmark for comparison
to the cap and trade program--must be calculated based on the
application of BART controls to all sources subject to BART.\154\
Although American Corn Growers had vacated this cumulative visibility
approach in the context of determining BART for individual sources, EPA
believed that it was still permissible to require this methodology in
the context of a BART-alternative program. The DC Circuit in CEED held
otherwise, stating: ``EPA cannot under Sec. 309 require states to
exceed invalid emission reductions (or, to put it more exactly, limit
them to a Sec. 309 alternative defined by an unlawful methodology).''
(Id. at 14).
---------------------------------------------------------------------------

\152\ Arizona, California, Colorado, Oregon, Idaho, Nevada, New
Mexico, Utah, and Wyoming.
\153\ The trading program is referred to as a ``backstop''
because under the WRAP Annex, States have the opportunity to achieve
specified emission milestones using voluntary measures, with the
trading program coming into effect only if those milestones are exceeded.
\154\ The methodology is prescribed in 40 CFR 51.308(e)(2) and
incorporated into Sec. 309 by reference at 40 CFR 51.309(f).
---------------------------------------------------------------------------

Thus, CEED firmly established two principles: (1) The CAA allows
States to substitute other programs for BART where the alternative
achieves greater progress, and (2) EPA may not require States to
evaluate visibility improvement on a cumulative basis as a condition
for approval of a BART-alternative. The first principle validates EPA's
proposal to allow the CAIR to substitute for BART. The second

[[Page 25300]]

principle is not at issue in the CAIR context, because EPA is not
proposing to impose the cumulative visibility methodology upon States,
nor to require States to treat the CAIR as having satisfied their BART
obligations.
Nonetheless, EPA has determined that it is premature to make a
final determination regarding the sufficiency of the CAIR as a BART
alternative, primarily because (1) the guidelines for source-specific
BART determinations, in response to American Corn Growers have not been
finalized, and (2) there is now a need to revise the Regional Haze Rule
and the guidelines for BART-alternative programs in response to CEED.
The source-specific BART guidelines will be finalized on or before
April 15, 2005, under a consent decree. The rule changes and revisions
to the BART-alternative guidelines will be proposed soon thereafter.
Therefore, we are making no final determination in today's action
with respect to BART. The EPA continues to believe, however, that the
CAIR will result in greater progress in visibility improvement than
BART, as explained below.
1. How Does This Rule Relate to Requirements for BART Under the
Visibility Provisions of the CAA?
a. Supplemental Notice of Proposed Rulemaking
In the SNPR, we proposed that States which adopt the CAIR cap and
trade program for SO₂ and NO_X would be allowed to
treat the participation of EGUs in this program as a substitute for the
application of BART controls for these pollutants to affected
EGUs.\155\ To give this option effect, we proposed an amendment to the
Regional Haze Rule which would add a section at 40 CFR 51.308(e)(3), as
follows:
---------------------------------------------------------------------------

\155\ The SNPR preamble used the term ``exemption'' in
describing this policy. As clarified below, and as consistent with
the proposed regulatory language, the better-than-BART policy is not
actually an exemption but rather an alternative means of compliance.

(3) A State that opts to participate in the Clean Air Interstate
Rule cap and trade program under part 96 AAA-EEE need not require
affected BART-eligible EGUs to install, operate, and maintain BART.
A State that chooses this option may also include provisions for a
geographic enhancement to the program to address the requirement
under Sec. 51.302(c) related to BART for reasonably attributable
impairment from the pollutants covered by the CAIR cap and trade
---------------------------------------------------------------------------
program.

This proposal is consistent with currently existing provisions
which allow States to develop cap and trade programs or other
alternative measures in lieu of the application of BART on a source
specific basis. (See 40 CFR 51.308(e)(2) and 64 FR 35714, 35741-35743,
July 1, 1999). The proposal was based on the application of the
proposed two-pronged test for whether an alternative to BART is
``better than BART'' which was proposed in the 2001 BART guidelines and
reproposed without changes in our May, 2004 proposed guidelines for
BART determinations (69 FR 25184, May 5, 2004).
Specifically, the re-proposed BART Guidelines provide that if the
geographic distribution of emissions reductions is anticipated to be
similar under both programs, the trading program (or other alternative
measure) must be shown to achieve greater overall emissions reductions
than the application of source-specific BART. If the trading program is
anticipated to result in a different geographic distribution of
emissions reductions than would source-specific BART, the trading
program must be shown to result in no decline in visibility at any
Class I area, and in an overall improvement in visibility on an average
basis over all affected Class I areas (69 FR 25184, 25231). Because we
had not yet determined whether there is a difference in the geographic
distribution of emissions reductions between the CAIR and the
application of source-specific BART in the CAIR region, we assessed the
difference between the two programs by evaluating the visibility
impacts of each program, using this proposed two-pronged test.
The emissions projections and air quality modeling used to
demonstrate that the CAIR satisfies this proposed two-pronged test were
presented in a document entitled Supplemental Air Quality Modeling
Technical Support Document (TSD) for the Clean Air Interstate Rule (May
4, 2004). In brief, we found that the CAIR would not result in a
degradation of visibility from current conditions at any Class I Area
nationwide. Within the CAIR-affected States and New England, EPA found
that the CAIR would produce greater visibility benefits--specifically,
an average improvement of 2.0 deciviews, as compared to 1.0 for BART.
The EPA also found that average visibility improvement for Class I
areas nationwide would be 0.7 deciviews under the CAIR, compared to 0.4
deciviews under BART. The EPA noted in the SNPR and the TSD that
because the emissions scenarios used in these analyses were developed
for different purposes, the scenarios varied slightly from the
scenarios which would be ideal for this test. The EPA committed to
conduct additional analyses, and those analyses have now been done. The
new modeling and results are discussed in more detail in section IX.C.2
below.
b. Comments and EPA's Responses
Several commenters argued that a categorical exclusion of sources
from BART would violate the CAA, as interpreted by the U.S. Court of
Appeals for the DC Circuit in American Corn Growers v. EPA, 291 F.3d 1,
2002, by illegally constraining the discretion Congress conferred to
States in making BART determinations and by depriving States of an
adequate opportunity to evaluate the emissions reductions in light of
the BART requirement. Some States also expressed a desire to retain
their discretion to require BART. Additionally, some commenters
asserted that EPA could not offer an exemption to BART unless the
conditions for exemptions provided by CAA 169A(c) are met, including a
showing that the source in question will not, alone or in combination
with other sources, emit any pollutant which may reasonably be
anticipated to cause or contribute to impairment at any Class I area,
and the concurrence of the appropriate Federal Land Manager with the
exemption determination.
The EPA agrees that under the CAA and the American Corn Growers
case, EPA may not preclude a State from conducting its own BART
analysis, nor from requiring BART controls at individual sources as
determined appropriate through such analysis. Accordingly, as noted
above, the proposed regulatory change to the Regional Haze Rule would
provide that a CAIR affected State ``need not require affected BART-
eligible EGUs to install, operate, and maintain BART'' if such State
opts to participate in the CAIR cap and trade program. The optional
nature of this language (``need not'' rather than ``may not'') is
consistent with the American Corn Growers decision, because it does not
attempt to mandate that States must consider the CAIR as having met the
requirements of BART.
The SNPR preamble summarized the proposal by stating that ``EPA
proposes that BART-eligible EGUs in any State affected by CAIR may be
exempted from BART controls for SO₂ and NO_X if
that State complies with the CAIR requirements through adoption of the
CAIR cap and trade programs for SO₂ and NO_X
emissions.'' (69 FR 3270). That statement accurately reflected the
optional nature of the better-than-BART substitution policy, by
providing that sources ``may'' be granted such regulatory flexibility.
However, the use of the term ``exempted'' in this context

[[Page 25301]]

was somewhat imprecise. EPA agrees that sources may not be ``exempt''
from BART requirements unless the requirements of 169A(c) are
fulfilled. The better-than-BART policy is not an ``exemption'' from
BART; it is an alternative regulatory program that would allow
Congressionally required emissions reductions from BART-eligible
sources to be made in a more cost-effective manner. Moreover, as
explained elsewhere in the SNPR and again below, BART-eligible EGUs
would not be ``exempt'' from BART because, until the emissions
reductions required by the CAIR are fully realized, such sources would
remain subject to the possibility of being required to install BART
controls if deemed necessary to meet requirements regarding reasonably
attributable visibility impairment, as provided by 40 CFR 51.302.
Several commenters asserted that because Congress singled out 26
source categories for the application of BART, there is no basis in law
for EPA to ``exempt'' some of these categories. These comments amount
to facial challenges of EPA's authority to approve SIPs which contain
alternative strategies, rather than source-specific BART requirements,
for BART-eligible sources.
The EPA's authority to approve alternative measures to BART, where
those measures achieve greater reasonable progress than would BART, was
recently upheld by the DC Circuit. (CEED, slip. op. at 13). See also
Central Arizona Water Conservation District v. EPA, 990 F.2d 1531,
1543, (1993) (Upholding EPA's interpretation of CAA 169A(b)(2)as
providing discretion to adopt implementation plan provisions other than
those provided by BART analyses in situations where the agency
reasonably concludes that more reasonable progress will thereby be
attained).
Similarly, some commenters stated that the CAIR could not
substitute for BART because the CAIR and BART are authorized by
separate parts of the CAA. They argue that allowing reductions required
by a provision of the CAA not linked to visibility improvement to
substitute for BART would alter Congress' ``mandate'' that certain
source categories make reductions for visibility in excess of what
other CAA provisions require of those sources.\156\ Commenters also
point to Regional Haze Rule section 308(e)(2), as evidence that
reductions from other programs such as title IV and the NO_X
SIP Call must be achieved in addition to, and not as a substitute for,
BART. Commenters also argue that EPA (and States) will need all
available tools, including BART, to meet visibility and NAAQS
requirements.
---------------------------------------------------------------------------

\156\ CAIR is linked to visibility improvements insofar as it
attempts to make progress towards attainment of the PM_2.5
NAAQS, which would, among other things, improve visibility.
---------------------------------------------------------------------------

Again, under our interpretation of CAA section 169A(b)(2) as upheld
in CEED and Central Arizona Water, Congress did not ``mandate'' that
emission reductions from certain source categories be obtained by the
installation of BART controls. Instead, the CAA allows for alternative
measures to BART--whether for EGUs or non-EGUs--where those measures
result in greater reasonable progress, and as explained below, we have
determined that greater reasonable progress can be obtained from the
EGU sector through the use of the CAIR cap and trade program. However,
if a State believes more progress can be made at affected Class I areas
by utilizing BART, the State need not make the determination that the
CAIR substitutes for BART in that State. Therefore, EPA is not
eliminating any tools available to the States.
With respect to Regional Haze Rule section 308(e)(2), EPA does not
believe that this section provides any support for the notion that
emissions reductions from other programs must necessarily be in
addition to, not substitute, for BART. We first note that the decision
in CEED necessitates revisions to 308(e)(2), at least in the provisions
requiring visibility to be evaluated on a cumulative basis in defining
the BART benchmark for comparison to BART alternative programs. It
remains to be seen whether 308(e)(2)(iv), which requires that emissions
reductions from the BART alternative be ``surplus to reductions
resulting from measures adopted to meet requirements as of the baseline
date of the SIP,'' will be changed. Even if that section remains
unchanged, the CAIR complies with it. The baseline date of Regional
Haze SIPs is 2002.\157\ Since any emissions reduction requirements to
meet the CAIR would necessarily be adopted after 2002, CAIR-required
reductions would clearly be surplus to measures adopted as of the
baseline year.\158\
---------------------------------------------------------------------------

\157\ See ``2002 Base Year Emission Inventory SIP Planning: 8-hr
Ozone, PM_2.5 and Regional Haze Programs,'' November 8,
2002, Guidance Memorandum, http://www.epa.gov/ttn/oarpg/t1/memoranda/2002bye_gm.pdf.
\158\ The purpose of providing a cut-off year for SIP measures
to which the alternative must be surplus is to prevent an untenable
situation where programs being developed simultaneously must be
surplus to each other. Establishing a baseline year allows States to
continue to make reductions between that baseline date and the
submittal of regional haze SIPs without being ``penalized'' for
those reductions by not being allowed to count them as contributing
to reasonable progress towards the national visibility goal.
---------------------------------------------------------------------------

Several commenters argued that the question of whether BART is
better than the CAIR is properly addressed in the BART rulemaking, not
in today's action, and that the better-than-BART determination is
otherwise premature. While EPA believes that our current analysis
demonstrates that the CAIR is better than BART (based on the criteria
in our May 2004 BART proposal), and that the range of uncertainty
regarding the presumptive BART controls for EGUs to be finalized in the
BART guidelines is not likely to alter that demonstration, we agree
that we cannot make a final determination that CAIR is better than BART
until the changes to the regional haze regulations required by both
American Corn Growers and CEED are finalized.
Several commenters felt the CAIR should be considered better than
BART for a State whether or not that State participates in the CAIR cap
and trade program, as long as the State achieves its emission reduction
requirement under the CAIR. Conversely, one commenter felt that CAIR
reductions should be considered better than BART only when a State does
not participate in the cap and trade program, thereby ensuring that the
reductions will occur in-State.
Our preliminary demonstration that the CAIR results in more
reasonable progress than BART for EGUs is based on a comparison of
emissions reductions from EGUs, and attendant air quality effects,
under the CAIR as compared to under BART as proposed in May, 2004. If
emissions reductions are achieved from other source sectors, a similar
analysis would have to be conducted for those sector(s) before it could
be determined that the reductions were better than BART for affected
source categories. For example, if a State either wants to use EGU
emissions reductions under the CAIR to substitute for BART for non-
EGUs, or use non-EGU emissions reductions to substitute for BART for
EGUs, that could be allowed as an alternative measure to BART provided
a similar ``better-than-BART'' determination is made for the sectors
involved.
A few commenters believed EPA should not limit the substitution of
the CAIR for BART to States that are required to meet CAIR for both
SO₂ and NO_X on an annual basis, but rather should
also allow it for States which are only required to reduce
NO_X during the ozone season. Because the modeling scenarios
were based on the pollutants

[[Page 25302]]

covered by the CAIR in each affected State, our better-than-BART
demonstration is limited to those scenarios. A State subject to the
CAIR for NO_X purposes only would have to make a
supplementary demonstration that BART has been satisfied for
SO₂, as well as for NO_X on an annual basis.
A few commenters believed that the CAIR should satisfy BART for
purposes of reasonably attributable visibility impairment as well as
BART for purposes of regional haze. Several others commented that it
was appropriate or legally necessary to preserve the authority of
Federal Land Managers (FLMs) and States to certify impairment and make
reasonable attribution determinations, which could subject a source to
BART requirements even if the source is a participant in the CAIR cap
and trade program. These commenters supported the use of a strategy
similar to that employed by the Western Regional Air Partnership, which
relies upon a Memorandum Of Understanding (MOU) between the FLMs and
the States regarding the criteria by which certifications of impairment
may be made, along with the possibility of ``geographic enhancements''
to the cap and trade program to accommodate the imposition of source-
specific BART control requirements on a source within the cap and trade
program.
As proposed in the SNPR, EPA continues to believe that reasonably
attributable visibility impairment determinations under 40 CFR 51.302
must continue to be a viable option in order to insure against any
possibility of hot-spots. We believe that a certification of reasonably
attributable visibility impairment is fairly unlikely, given that there
have been few such certifications since 1980, and given that the
reductions from the CAIR and other recent initiatives will make such
certifications decreasingly likely. We believe sources can be given
sufficient regulatory certainty to enable effective participation in a
cap and trade program through the use of MOUs and geographic
enhancement provisions.
Some commenters believe that because section 169A(b)(2)(A) requires
BART for an eligible source which may reasonably be anticipated to
cause or contribute to any impairment of visibility in any Class I
area, EPA is without basis in law or regulation to base a better-than-
BART determination on an analysis that does not evaluate visibility
improvement at each and every Class I area, or one that uses averaging
of visibility improvement across different Class I areas.
The criteria we applied in our present analysis--that greater
reasonable progress is defined as no degradation at any Class I area,
and greater overall average improvement--have not been finalized.
However, we disagree with comments that 169A(b)(2)'s requirement of
BART for sources reasonably anticipated to contribute to impairment at
any Class I area \159\ means that an alternative to the BART program
must be shown to create improvement at each and every Class I area.
Even if a BART alternative is deemed to satisfy BART for regional haze
purposes, based on average overall improvement as opposed to
improvement at each and every Class I Area, 169A(b)(2)'s trigger for
BART based on impairment at any Class I area remains in effect, because
a source may become subject to BART based on ``reasonably attributable
visibility impairment'' at any area. (The EPA believes it is unlikely
that a State or FLM will have need to certify reasonably attributable
visibility impairment (RAVI) with respect to any EGU in the CAIR
region, but nevertheless believes it is necessary to preserve this
safeguard).
---------------------------------------------------------------------------

\159\ The question of whether section 169A(b)(2) requires BART
based on contribution to impairment at any Class I area is separate
from the question of whether this section requires source-specific
BART under all circumstances. As noted earlier, we interpret section
169A(b)(2) as requiring BART only as needed to make reasonable
progress, thus allowing for alternative measures which make greater
reasonable progress.
---------------------------------------------------------------------------

We also received a number of comments regarding the broader
relationship between the CAIR and regional haze, including whether the
CAIR meets reasonable progress requirements, as well as BART, for
affected States; whether EPA should allow non-CAIR States to opt in to
the CAIR cap and trade program to meet their BART requirements; and
whether regional haze provisions should be used as a basis for
expanding the CAIR rule to the rest of the States which were not
included on the basis of contribution to PM_2.5 and ozone
nonattainment. The EPA's responses to comments on these broader issues,
which are not germane to the issue of whether the CAIR may substitute
for BART for affected EGUs, are contained in the Response to Comment
Document.
c. Today's Action
As discussed above, EPA has the authority to approve SIPs which
rely upon a cap and trade program as an alternative to BART. However,
at this time, we are deferring a final determination that, in EPA's
view, the CAIR makes greater progress than BART for CAIR-affected
States until such time as the BART guidelines for EGUs and the criteria
for BART-alternative programs are finalized. At that time, contingent
upon supporting analysis and our final rules governing the regional
haze program, EPA will make a final determination as to whether the
CAIR makes greater progress than BART, and can be relied on as an
alternative measure in lieu of BART.
2. What Improvements Did EPA Make to the Bart Versus the CAIR Modeling,
and What Are the New Results?
a. Supplemental Notice of Proposed Rulemaking
For the better-than-BART analysis in the SNPR, we used the
Integrated Planning Model (IPM) to estimate emissions expected after
implementation of a source-specific BART approach and after
implementation of the CAIR cap and trade program for EGUs. We then used
the Regional Modeling System for Aerosols and Deposition (REMSAD) air
quality model to project the visibility impact of these IPM emissions
predictions for both the CAIR and the nationwide source-specific BART
scenarios. Specifically, EPA evaluated the model results for the 20
percent best days (that is, least visibility impaired) and the 20
percent worst days at 44 Class I areas throughout the country. Thirteen
of these Class I areas are within States affected by the CAIR proposal,
and 31 Class I areas are outside the CAIR region--29 in States to the
west of the CAIR region, and 2 in New England States northeast of the
CAIR region.
As explained in the SNPR, the ``CAIR'' scenario modeled was
imperfect for purposes of this analysis in that it assumed
SO₂ reductions on a nationwide basis (rather than in the
CAIR region only) and assumed NO_X reductions requirements in
a slightly different geographic region than covered by the proposed
CAIR. The ideal scenario would have correctly represented the
geographic scope of the CAIR SO₂ and NO_X
reduction requirements, and included source-specific BART controls in
areas outside the CAIR region. (This corrected scenario has been
modeled for the NFR, as explained below).
The SNPR REMSAD modeling showed that under the proposed two-pronged
test, CAIR controls achieved equal or greater visibility improvement
than the application of source-specific BART to EGUs nationwide. The
modeling predicted that the CAIR cap and trade program will not result
in degradation of visibility, compared to

[[Page 25303]]

existing (1998-2002) visibility conditions, at any of the 44 Class I
areas considered. It also indicated that CAIR emissions reductions as
modeled produce significantly greater visibility improvements than
source-specific BART. Specifically, for the 15 Eastern Class I areas
analyzed, the average visibility improvement (on the 20 percent worst
days) expected solely as a result of the CAIR was 2.0 deciviews, and
the average degree of improvement predicted for source-specific BART
was 1.0 deciviews. Similarly, on a national basis, the visibility
modeling showed that for all 44 Class I areas evaluated, the average
visibility improvement, on the 20 percent worst days, in 2015 was 0.7
deciviews under the CAIR cap and trade program, but only 0.4 deciviews
under the source-specific BART approach.
b. Comments and EPA Responses
Several commenters noted that EPA did not model the ``correct''
emissions scenarios to compare the CAIR and BART controls. They
suggested that a model run with the CAIR controls in the East and BART
controls in the West should be compared to a model run with nationwide
BART controls.
The EPA agrees (as we have already noted in the SNPR) that the
suggested comparison of model runs is a more appropriate comparison of
the CAIR and BART. The SNPR better-than-BART analysis was limited by
the availability of the model results at the time. For the NFR, we have
modeled nationwide BART for EGUs as proposed in the May 2004 guidelines
and a separate scenario consisting of CAIR reductions in the CAIR-
affected States plus BART-reductions in the remaining States (excluding
Alaska and Hawaii). Additionally, we have improved the BART control
assumptions (in both scenarios) by increasing the number of BART-
eligible units included. Specifically, in the SNPR analysis, controls
were ``required'' (i.e., assumed by the model) for BART-eligible EGUs
greater than 250 MW capacity, for both NO_X and
SO₂. For today's action, BART controls are assumed for
SO₂ for all BART-eligible EGU units greater than 100 MW, and
NO_X controls for all BART-eligible EGU units greater than 25
MW.\160\ This, along with a review of potentially BART-eligible EGUs,
has expanded the universe of units assumed subject to BART in the
modeling from 302 to 491.\161\
---------------------------------------------------------------------------

\160\ Because the presumptive controls in the BART guidelines
are applicable to coal-fired EGUs, the BART analysis does not assume
controls on oil- and gas-fired units. However, NO_X
emissions from all (not just BART-eligible) oil and gas steam plants
and simple cycle turbines in the CAIR region in the 2010 base case
are projected to be about 40,000 tons, or less than 1.5% of the
projected total 2010 EGU emissions. By comparison, the modeling of
the scenario of the CAIR (with BART in the non-CAIR region) resulted
in 640,000 tons of NO_X per year less than the projected
emissions under a nationwide BART scenario. Therefore, even if the
40,000 tons of NO_X emissions from oil and gas EGUs were
reduced to zero under the BART scenario, the CAIR will still produce
significantly greater emission reductions than BART. Also, not all
of the oil and gas units associated with those 40,000 tons would be
eligible for BART. The IPM does not predict any difference in
SO₂ emissions from oil or gas-fired units between the
CAIR and BART.
\161\ See ``Memo From Perrin Quarles Associates, Inc. Re Follow-
Up on Units Potentially Affected by BART, July 19, 2004,'' as
Appendix A to the ``Better than BART'' TSD.
---------------------------------------------------------------------------

Several commenters noted that the better-than-BART visibility
analysis only covered 44 Class I areas and did not adequately address
visibility in all areas of the country.
For the NFR, we have significantly expanded the number of Class I
areas covered by the analysis. The NPR and SNPR visibility analysis was
limited by the availability of observed data from Inter-agency
Monitoring of Protected Visual Environments (IMPROVE) monitors during
the meteorological modeling year of 1996. There was complete IMPROVE
data at 44 IMPROVE sites which represented 68 Class I areas.\162\ All
of the regions of the country (as defined by IMPROVE) were represented
by at least one site, except the Northern Great Lakes region. For the
final rule, the modeling has been updated to use a meteorological year
of 2001. Therefore, the IMPROVE data for 2001 was used for the NFR
better-than-BART analysis. For 2001, there were 81 IMPROVE sites with
complete data,\163\ representing 116 Class I areas. The NFR analysis
accounts for visibility changes at 80 percent of the active IMPROVE
sites in the lower 48 States. More importantly for today's rulemaking,
the number of Class I areas in the East has been increased from 15 to
29 and now covers all IMPROVE-defined visibility regions within the
CAIR-affected States, including the Northern Great Lakes.\164\ We,
therefore, believe the expanded geographic scope of Class I areas
covered is sufficient for purposes of this analysis.
---------------------------------------------------------------------------

\162\ Some Class I areas do not have IMPROVE monitors and are
represented by nearby IMPROVE sites.
\163\ This is the number of IMPROVE sites that are located at or
represent Class I areas. There are additional IMPROVE protocol
monitoring sites that are not located at Class I areas.
\164\ There are 5 Class I areas in the East and 33 Class I areas
in the West (outside of the CAIR control region) that do not have
complete IMPROVE data for 2001.
---------------------------------------------------------------------------

c. Today's Action
We have compared the two model runs (BART nationwide and BART in
the West with the CAIR in the East) using the proposed two-pronged
better-than-BART test. The results were analyzed at the 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. Detailed modeling results for
all 116 Class I areas are contained in the Better-than-BART TSD.\165\
Results applicable to the better-than-BART proposed two-pronged test
are summarized below.
---------------------------------------------------------------------------

\165\ ``Demonstration that CAIR Satisfies the `Better-than-BART'
Test As Proposed in the Guidelines for Making BART Determinations,''
March, 2005.
---------------------------------------------------------------------------

The updated visibility analysis reaffirms that under the proposed
two-pronged test, CAIR controls are better than BART for EGUs. The
modeling predicts that the CAIR cap and trade program will not result
in degradation of visibility on the 20 percent best or 20 percent worst
days compared to the 2015 baseline conditions, at any of the 116 Class
I areas considered.\166\
---------------------------------------------------------------------------

\166\ See Better-than-BART TSD for results at each Class I Area.
---------------------------------------------------------------------------

With respect to the greater-average-improvement prong, the modeling
indicates that CAIR emissions reductions in the East produce
significantly greater visibility improvements than source-specific
BART. Specifically, for the 29 Eastern Class I areas analyzed, the
average visibility improvement, on the 20 percent worst days, expected
solely as a result of the CAIR applied in the East and BART applied in
the West is 1.6 dv, as compared to the average degree of improvement
predicted for nationwide source-specific BART of 0.7 dv. Similarly, on
a national basis, the visibility modeling showed that for all 116 Class
I areas evaluated, the average visibility improvement, on the 20
percent worst days, in 2015 was 0.5 dv under the CAIR cap and trade
program in the East and BART in the West, but only 0.2 deciviews under
the nationwide source-specific BART approach.
The modeling showed similar results for the 20 percent best
visibility days, although there is less visibility improvement on the
best days compared to the worst days. For the 29 Eastern Class I areas
analyzed, the average visibility improvement, on the 20 percent best
days, expected solely as result of the CAIR applied in the East and
BART applied in the West is 0.4 dv, as compared to the average degree of

[[Page 25304]]

improvement predicted for nationwide source-specific BART of 0.2 dv. On
a national basis, the visibility modeling showed that for all 116 class
I areas evaluated, the average visibility improvement, on the 20
percent best days, in 2015 was 0.1 dv under both the CAIR cap and trade
program in the East and BART in the West, and under the nationwide
source-specific BART approach. The results are summarized in table IX-
1.

Table IX-1.--Average Visibility Improvement in 2015 vs. 2015
Base Case (deciviews)
----------------------------------------------------------------------------------------------------------------
CAIR + BART in West Nationwide BART
Class I Areas ---------------------------------------------------
East \167\ National East National
----------------------------------------------------------------------------------------------------------------
20% Worst Days.............................................. 1.6 0.5 0.7 0.2
20% Best Days............................................... 0.4 0.1 0.2 0.1
----------------------------------------------------------------------------------------------------------------

The results clearly indicate that the CAIR will achieve greater
reasonable progress than BART as proposed, measured by the proposed
better-than-BART test. At this time, we can foresee no circumstances
under which BART for EGUs could produce greater visibility improvement
than the CAIR. However, for the reasons noted in section IX.C.1. above,
we are deferring a final determination of whether the CAIR makes
greater reasonable progress than BART until the BART guidelines for
EGUs and the criteria for BART-alternative programs are finalized.
---------------------------------------------------------------------------

\167\ Eastern Class I areas are those in the CAIR affected
states, except areas in west Texas which are considered western and
therefore included in the national average, plus those in New England.
---------------------------------------------------------------------------

D. How Will EPA Handle State Petitions Under Section 126 of the CAA?

Section 126 of the CAA authorizes a downwind State to petition EPA
for a finding that any new (or modified) or existing major stationary
source or group of stationary sources upwind of the State emits or
would emit in violation of the prohibition of section 110(a)(2)(D)(i)
because their emissions contribute significantly to nonattainment, or
interfere with maintenance, of a NAAQS in the State. If EPA makes such
a finding, EPA is authorized to directly regulate the affected sources.
Section 126 relies on the same statutory provision that underlies the
CAIR.
In the January 30, 2004 CAIR proposal, EPA set forth its general
view of the approach it expected to take in responding to any section
126 petition that might be submitted which relies on essentially the
same record as the CAIR. That approach is the one EPA used in
addressing section 126 petitions that were submitted to EPA in 1997
while EPA was developing the NO_X SIP Call to control ozone
transport. In the NO_X SIP Call rule, we determined under
section 110(a)(2)(D) that the SIP for each affected State (and the
District of Columbia) must be revised to eliminate the amount of
emissions that contributes significantly to nonattainment in downwind
States. The emissions reductions requirement was based on the quantity
of emissions that could be eliminated by the application of highly
cost-effective controls on specified sources in that State. In May
1999, shortly after promulgation of the NO_X SIP Call, EPA
took final action on the section 126 petitions (64 FR 28250; May 25,
1999). The Section 126 action relied on essentially the same record as
the NO_X SIP Call. In addition, we established a section 126
remedy based on the same set of highly cost-effective controls. In the
May 1999 Section 126 Rule, we determined which petitions had technical
merit, but we stopped short of granting the findings for the petitions.
Instead, we stated that because we had promulgated the NO_X
SIP Call--a transport rule under section 110(a)(2)(D)--as long as an
upwind State remained on track to comply with that rule, EPA would
defer making the section 126 findings. The findings would be triggered
at either of two future dates if specified progress had not been made
by those times. The Section 126 Rule included a provision under which
the rule would be automatically withdrawn for sources in a State once
that State submitted and EPA fully approved a SIP that complied with
the NO_X SIP Call. (See 64 FR 28271-28274; May 25, 1999.) The
reason for this withdrawal would be the fact that the affected State's
SIP revision would fulfill the section 110(a)(2)(D) requirements, so
that there would no longer be any basis for the section 126 finding
with respect to that State. In this manner, the NO_X SIP Call
and the Section 126 Rules would be harmonized.
Under the CAIR proposal, EPA received comments regarding its
intended approach for acting on any future section 126 petitions that
might be filed. Many commenters expressed support for the approach that
EPA had outlined. Other commenters raised issues regarding the timing
of emissions reductions under a new section 126 action. Some pointed
out that the CAIR compliance date would be later than the 3 years
allowed for compliance under section 126. Some were concerned that the
proposed CAIR compliance date is later than many attainment dates and
States may need section 126 petitions in order to get earlier upwind
reductions in order to meet their attainment dates. Some questioned the
legal basis for linking the two rules. Several commenters expressed
concern that EPA would be restricting the use of or weakening the
section 126 provision. A number of commenters urged EPA not to prejudge
any petition, but to evaluate each on its own merit. Some thought that
any petitions submitted prior to designations or before States had had
the opportunity to prepare SIPs would be premature and should be
denied. Others suggested that CAIR might not solve all the transport
problems and that States would need to retain the section 126 tool to
seek further reductions.
After issuing the CAIR proposal, EPA received, on March 19, 2004, a
section 126 petition from North Carolina seeking reductions in upwind
NO_X and SO₂ for purposes of reducing
PM_2.5 and 8-hour ozone levels in North Carolina. The
petition relies in large part on the technical record for the proposed
CAIR.
When we propose action on the North Carolina petition, we will set
forth our view of the interaction between section 110(a)(2)(D) and
section 126. In that proposal, we will take into consideration and
respond to the section 126-related comments we received on the CAIR.
The EPA will provide a comment period and opportunity for a public
hearing on the specifics of that section 126 proposal, including an
opportunity to comment on our view of the interaction of the 2
statutory provisions.

[[Page 25305]]

E. Will Sources Subject to CAIR Also Be Subject to New Source Review?

The EPA did not propose any provisions in the CAIR related to new
source review (NSR). Nonetheless, we received some comments on the
relationship between CAIR and the NSR provisions that may apply to
emissions sources also impacted by the CAIR. Many commenters indicated
that if an EGU is part of an EPA-administered regional cap and trade
program for NO_X and SO₂, then that EGU should be
exempted from NSR for the covered pollutants. The commenters cited
Clear Skies legislation as containing provisions affecting NSR for
covered sources. In this final rule, EPA is not addressing or revising
the provisions of NSR.
It should be noted that pollution control measures implemented by
EGUs in compliance with the CAIR may be eligible for an exemption under
the NSR pollution control project provision.\168\ These provisions
provide an exemption from major NSR for controls such as selective
catalytic reduction (SCR) for NO_X control and wet scrubbers
for SO₂ control, provided that certain conditions identified
in the provisions are met.
---------------------------------------------------------------------------

\168\ See 40 CFR 51.165(a)(1)(xxv) and 51.165(e), 40 CFR
51.166(b)(31) and 51.166(v), and 40 CFR 51.21(b)(32) and 52.21(z).
---------------------------------------------------------------------------

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether a regulatory action is ``significant''
and therefore subject to Office of Management and Budget (OMB) review
and the requirements of the Executive Order. The Order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:
1. Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or Tribal governments or communities;
2. Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
3. Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
4. Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
In view of its important policy implications and potential effect
on the economy of over $100 million, this action has been judged to be
an economically ``significant regulatory action'' within the meaning of
the Executive Order. As a result, today's action was submitted to OMB
for review, and EPA has prepared an economic analysis of the rule
entitled ``Regulatory Impact Analysis of the Final Clean Air Interstate
Rule'' (March 2005).
1. What Economic Analyses Were Conducted for the Rulemaking?
The analyses conducted for this final rule provide several
important analyses of impacts on public welfare. These include an
analysis of the social benefits, social costs, and net benefits of the
regulatory scenario. The economic analyses also address issues
involving small business impacts, unfunded mandates (including impacts
for Tribal governments), environmental justice, children's health,
energy impacts, and requirements of the Paperwork Reduction Act (PRA).
2. What Are the Benefits and Costs of This Rule?
The benefit-cost analysis shows that substantial net economic
benefits to society are likely to be achieved due to reductions in
emissions resulting from this rule. The results detailed below show
that this rule would be highly beneficial to society, with annual net
benefits (benefits less costs) of approximately $71.4 or $60.4 billion
in 2010 and $98.5 or $83.2 billion in 2015. These alternative net
benefits estimates occur due to differing assumptions concerning the
social discount rate used to estimate the annual value of the benefits
and costs of the rule with the lower estimates relating to a discount
rate of 7 percent and the higher estimates a discount rate of 3
percent. All amounts are reflected in 1999 dollars.
The benefits and costs reported for the CAIR represent estimates
for the final CAIR program that includes the CAIR promulgated rule and
the concurrent proposal to include annual SO₂ and
NO_X controls for New Jersey and Delaware. The modeling used
to provide these estimates also assumes annual SO₂ and
NO_X controls for Arkansas that are not a part of the final
CAIR program resulting in a slight overstatement of the reported
benefits and costs.
a. Control Scenario
Today's rule sets forth requirements for States to eliminate their
significant contribution to down-wind nonattainment of the ozone and
PM_2.5 NAAQS. In order to reduce this significant
contribution, EPA requires that certain States reduce their emissions
of SO₂ and NO_X. The EPA derived the quantities by
calculating the amount of SO₂ and NO_X emissions
that EPA believes can be controlled from the electric power industry in
a highly cost-effective manner. The EPA considered all promulgated CAA
requirements and known State actions in the baseline used to develop
the estimates of benefits and costs for this rule. For a more complete
description of the reduction requirements and how they were calculated,
see section IV of today's rulemaking.
Although States may choose to obtain the emissions reductions from
other source categories, for purposes of analyzing the impacts of the
rule, EPA is assuming the application of the controls that it has
identified to be highly cost effective on all EGUs in the transport
region.
b. Cost Analysis and Economic Impacts
For the affected region, the projected annual private incremental
costs of the CAIR to the power industry are $2.4 billion in 2010 and
$3.6 billion in 2015. These costs represent the private compliance cost
to the electric generating industry of reducing NO_X and
SO₂ emissions to meet the caps set forth in the rule.
Estimates are in 1999 dollars.
In estimating the net benefits of regulation, the appropriate cost
measure is ``social costs.'' Social costs represent the welfare costs
of the rule to society. These costs do not consider transfer payments
(such as taxes) that are simply redistributions of wealth. The social
costs of this rule are estimated to be approximately $1.9 billion in
2010 and $2.6 billion in 2015 assuming a 3 percent discount rate. These
costs become $2.1 billion in 2010 and $3.1 billion in 2015 assuming a 7
percent discount rate.
Overall, the impacts of the CAIR are modest, particularly in light
of the large benefits we expect. Ultimately, we believe the industry
will pass along most of the costs of the rule to consumers, so that the
costs of the rule will largely fall upon the consumers of electricity.
Retail electricity prices are projected to increase roughly 2.0-2.7
percent with the CAIR in the 2010 and 2015 timeframe, and then drop
below the 2.0 percent increase level thereafter. The effects of the
CAIR on natural gas prices and the power-sector generation mix are
relatively small, with a 1.6 percent or less increase in natural gas
prices projected from 2010 to 2020.

[[Page 25306]]

There will be continued reliance on coal-fired generation, that is
projected to remain at roughly 50 percent of total electricity
generated. A relatively small amount of coal-fired capacity, about 5.3
GW (1.7 percent of all coal-fired capacity and 0.5 percent of all
generating capacity), is projected to be uneconomic to maintain. For
the most part, these units are small and infrequently used generating
units that are dispersed throughout the CAIR region. Units projected to
be uneconomic to maintain may be ``mothballed,'' retired, or kept in
service to ensure transmission reliability in certain parts of the
grid. The EPA's analysis does not address these choices.
As demand grows in the future, additional coal-fired generation is
projected to be built under the CAIR. As a result, coal production for
electricity generation is projected to increase from 2003 levels by
about 15 percent in 2010 and 25 percent by 2020, and we expect a small
shift towards greater coal production in Appalachia and the interior
coal regions of the country with the CAIR.
For today's rule, EPA analyzed the costs using the Integrated
Planning Model (IPM). The IPM is a dynamic linear programming model
that can be used to examine the economic impacts of air pollution
control policies for SO₂ and NO_X throughout the
contiguous U.S. for the entire power system. Documentation for IPM can
be found in the docket for this rulemaking or at
http://www.epa.gov/airmarkets/epa-ipm.
c. Human Health Benefit Analysis
Our analysis of the health and welfare benefits anticipated from
this rule are presented in this section. Briefly, the analysis projects
major benefits from implementation of the rule in 2010 and 2015. As
described below, thousands of deaths and other serious health effects
would be prevented. We are able to monetize annual benefits of
approximately $73.3 or $62.6 billion in 2010 (based upon a 3 percent or
7 percent discount rate, respectively) and $101 billion or $86.3
billion in 2015 (based upon a discount rate of 3 percent or 7 percent,
respectively, 1999 dollars).
Table X-1 presents the primary estimates of reduced incidence of
PM- and ozone-related health effects for the years 2010 and 2015 for
the regulatory control strategy. In 2015, we estimate that PM-related
annual benefits include approximately 17,000 fewer premature
fatalities, 8,700 fewer cases of chronic bronchitis, 22,000 fewer non-
fatal heart attacks, 10,500 fewer hospitalizations (for respiratory and
cardiovascular disease combined) and result in significant reductions
in days of restricted activity due to respiratory illness (with an
estimate of 9.9 million fewer cases) and approximately 1,700,000 fewer
work-loss days. We also estimate substantial health improvements for
children from reduced upper and lower respiratory illness, acute
bronchitis, and asthma attacks.
Ozone health-related benefits are expected to occur during the
summer ozone season (usually ranging from May to September in the
Eastern U.S.). Based upon modeling for 2015, annual ozone-related
health benefits are expected to include 2,800 fewer hospital admissions
for respiratory illnesses, 280 fewer emergency room admissions for
asthma, 690,000 fewer days with restricted activity levels, and 510,000
fewer days where children are absent from school due to illnesses.
While we did not include in our primary benefits analysis separate
estimates of the number of premature deaths that would be avoided due
to reductions in ozone levels, recent studies suggest a link between
short-term ozone exposures with premature mortality independent of PM
exposures. Based upon a recent report by Thurston and Ito, (2001),\169\
the EPA Science Advisory Board has recommended that EPA reevaluate the
ozone mortality literature for possible inclusion of ozone mortality in
the estimate of total benefits. More recently, a comprehensive analysis
using data from the National Morbidity, Mortality and Air Pollution
Study (NMMAPS) found a significant association between daily ozone
levels and daily mortality rates (Bell et al. 2004).\170\ The analysis
estimated a 0.5 percent increase in daily mortality associated with a
10 ppb increase in ozone, based on data from 95 major urban areas.
Using a similar magnitude effect estimate, sensitivity analysis
estimates suggest that in 2015, the CAIR would result in an additional
500 fewer premature deaths annually due to reductions in daily ambient
ozone concentrations. The EPA has sponsored three independent meta-
analyses of the ozone mortality epidemiology literature to inform a
determination on inclusion of this important health impact in the
primary benefits analysis for future regulations.
---------------------------------------------------------------------------

\169\ Thurston, G.D. and K. Ito. 2001. ``Epidemiological Studies
of Acute Ozone Exposures and Mortality''. J. Expo Anal Environ
Epidemiology 11 (4) :286-294.
\170\ Bell, M.L., A. McDermott, S. Zeger, J. Samet, F.
Dominichi. 2005. ``Ozone and Mortality in 95 U.S. Urban Communities
from 1987 to 2000.'' Journal of the American Medical Association.
Forthcoming.
---------------------------------------------------------------------------

Table X-2 presents the estimated monetary value of reductions in
the incidence of health and welfare effects. Annual PM-related and
ozone-related health benefits are estimated to be approximately $72.1
or $61.4 billion in 2010 (3 percent and 7 percent discount rate,
respectively) and $99.3 or $84.5 billion in 2015 (3 percent or 7
percent discount rate, respectively). Estimated annual visibility
benefits in southeastern Class I areas are approximately $1.14 billion
in 2010 and $1.78 billion in 2015. All monetized estimates are stated
in 1999$. These estimates account for growth in real gross domestic
product (GDP) per capita between the present and the years 2010 and
2015. As the table indicates, total benefits are driven primarily by
the reduction in premature fatalities each year, that accounts for over
90 percent of total benefits.
Table X-3 presents the total monetized net benefits for the years
2010 and 2015. This table also indicates with a ``B'' those additional
health and environmental benefits of the rule that we were unable to
quantify or monetize. These effects are additive to the estimate of
total benefits. A listing of the benefit categories that could not be
quantified or monetized in our benefit estimates are provided in Table
X-4. We are not able to estimate the magnitude of these unquantified
and unmonetized benefits. While EPA believes there is considerable
value to the public for the PM-related benefit categories that could
not be monetized, we believe these benefits may be small relative to
those categories we were able to quantify and monetize. In contrast,
EPA believes the monetary value of the ozone-related premature
mortality benefits could be substantial. As previously discussed, we
estimate that ozone mortality benefits may yield as many as 500 reduced
premature mortalities per year and may increase the benefits of CAIR by
approximately $3 billion annually.
d. Quantified and Monetized Welfare Benefits
Only a subset of the expected visibility benefits--those for Class
I areas in the southeastern U.S. are included in the monetary benefits
estimates we project for this rule. We believe the benefits associated
with these non-health benefit categories are likely significant. For
example, we are able to quantify significant visibility improvements in
Class I areas in the Northeast and Midwest, but are unable at present
to place a monetary value on these improvements. Similarly, we

[[Page 25307]]

anticipate improvement in visibility in residential areas where people
live, work and recreate within the CAIR region for which we are
currently unable to monetize benefits. For the Class I areas in the
southeastern U.S., we estimate annual benefits of $1.78 billion
beginning in 2015 for visibility improvements. The value of visibility
benefits in areas where we were unable to monetize benefits could also
be substantial.
We also quantify nitrogen and sulfur deposition reductions expected
to occur as a result of the CAIR and discuss potential benefits from
these reductions in section X.A.4 of this preamble. While we are unable
to estimate a dollar value associated with these benefits, we are able
to quantify acidification improvements in lakes in the Northeast
including the Adirondacks and potential benefits of reductions in
nitrogen deposition to estuaries such as the Chesapeake Bay.
---------------------------------------------------------------------------

\171\ Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D.
Krewski, K. Ito, and G.D. Thurston. 2002. ``Lung Cancer,
Cardiopulmonary Mortality, and Long-term Exposure to Fine
Particulate Air Pollution.'' Journal of American Medical Association
287:1132-1141.
\172\ Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997.
``The Relationship Between Selected Causes of Postneonatal Infant
Mortality and Particulate Infant Mortality and Particulate Air
Pollution in the United States.'' Environmental Health Perspectives
105(6):608-612.
\173\ U.S. Environmental Protection Agency, 2000. Guidelines for
Preparing Economic Analyses. http://www.yosemite1.epa.gov/ee/epa/eed/hsf/
pages/Guideline.html. Office of Management and Budget, The Executive
Office of the President, 2003. Circular A-4.
http://www.whitehouse.gov/omb/circulars.

Table X-1.--Estimated Annual Reductions in Incidence of Health Effects a
------------------------------------------------------------------------
2010 annual 2015 annual
Health Effect incidence incidence
reduction reduction
------------------------------------------------------------------------
PM-Related endpoints
------------------------------------------------------------------------
Premature Mortality b, c................
Adult, age 30 and over.............. 13,000 17,000
Infant, age < 1 year................. 29 36
Chronic bronchitis (adult, age 26 and 6,900 8,700
over)..................................
Non-fatal myocardial infarction (adult, 17,000 22,000
age 18 and over).......................
Hospital admissions--respiratory (all 4,300 5,500
ages) d................................
Hospital admissions--cardiovascular 3,800 5,000
(adults, age >18) e....................
Emergency room visits for asthma (age 18 10,000 13,000
years and younger).....................
Acute bronchitis, (children, age 8-12).. 16,000 19,000
Lower respiratory symptoms (children, 190,000 230,000
age 7-14)..............................
Upper respiratory symptoms (asthmatic 150,000 180,000
children, age 9-18)....................
Asthma exacerbation (asthmatic children, 240,000 290,000
age 6-18)..............................
Work Loss Days.......................... 1,400,000 1,700,000
Minor restricted activity days (adults 8,100,000 9,900,000
age 18-65).............................
-----------------------------------------
Ozone-Related endpoints
------------------------------------------------------------------------
Hospital admissions--respiratory causes 610 1,700
(adult, 65 and older) f................
Hospital admissions--respiratory causes 380 1,100
(children, under 2)....................
Emergency room visit for asthma (all 100 280
ages)..................................
Minor restricted activity days (adults, 280,000 690,000
age 18-65).............................
School absence days..................... 180,000 510,000
------------------------------------------------------------------------
a Incidences are rounded to two significant digits. These estimates
represent benefits from the CAIR nationwide. The modeling used to
derive these incidence estimates are reflective of those expected for
the final CAIR program including the CAIR promulgated rule and the
proposal to include annual SO2 and NOX controls for New Jersey and
Delaware. Modeling used to develop these estimates assumes annual SO2
and NOX controls for Arkansas resulting in a slight overstatement of
the reported benefits and costs for the complete CAIR program.
b Premature mortality benefits associated with ozone are not analyzed in
the primary analysis.
c Adult mortality based upon studies by Pope, et al. 2002.\171\ Infant
mortality based upon studies by Woodruff, Grillo, and
Schoendorf,1997.\172\
d Respiratory hospital admissions for PM include admissions for chronic
obstructive pulmonary disease (COPD), pneumonia and asthma.
e Cardiovascular hospital admissions for PM include total cardiovascular
and subcategories for ischemic heart disease, dysrhythmias, and heart
failure.
f Respiratory hospital admissions for ozone include admissions for all
respiratory causes and subcategories for COPD and pneumonia.

Table X-2.--Estimated Annual Monetary Value of Reductions in Incidence
of Health and Welfare Effects
[Millions of 1999$]
a, b
------------------------------------------------------------------------
2010 2015
estimated estimated
Health effect Pollutant value of value of
reductions reductions
------------------------------------------------------------------------
Premature mortality c, d
Adult >30 years .............. ........... ...........
3 percent discount PM2.5......... $67,300 $92,800
rate.
7 percent discount .............. 56,600 78,100
rate.
Child < 1 year............. .............. 168 222
Chronic bronchitis (adults, 26 PM2.5......... 2,520 3,340
and over).
Non-fatal acute myocardial
infarctions
3 percent discount rate... PM2.5......... 1,420 1,850
7 percent discount rate... .............. 1,370 1,790

[[Page 25308]]

Hospital admissions for PM2.5, O3..... 45.2 78.9
respiratory causes.
Hospital admissions for PM2.5......... 80.7 105
cardiovascular causes.
Emergency room visits for PM2.5, O3..... 2.84 3.56
asthma.
Acute bronchitis (children, PM2.5......... 5.63 7.06
age 8-12).
Lower respiratory symptoms PM2.5......... 2.98 3.74
(children, age 7-14).
Upper respiratory symptoms PM2.5......... 3.80 4.77
(asthma, age 9-11).
Asthma exacerbations.......... PM2.5......... 10.3 12.7
Work loss days................ PM2.5,........ 180 219
Minor restricted activity days PM2.5, O3..... 422 543
(MRADs).
School absence days........... O3............ 12.9 36.4
Worker productivity (outdoor O3............ 7.66 19.9
workers, age 18-65).
Recreational visibility, 81 PM2.5......... 1,140 1,780
Class I areas.
--------------
Monetized Total e
Base estimate .............. ........... ...........
3 percent discount PM2.5, O3..... 73,300 + B 101,000 + B
rate.
7 percent discount .............. 62,600 + B 86,300 + B
rate.
------------------------------------------------------------------------
a Monetary benefits are rounded to three significant digits. These
estimates represent benefits from the CAIR nationwide for NOX and SO2
emissions reductions from electricity-generating units sources (with
the exception of ozone and visibility benefits). Ozone benefits relate
to the eastern United States. Visibility benefits relate to Class I
areas in the southeastern United States. The benefit estimates
reflected relate to the final CAIR program that includes the CAIR
promulgated rule and the proposal to include annual SO2 and NOX
controls for New Jersey and Delaware. Modeling used to develop these
estimates assumes annual SO2 and NOX controls for Arkansas resulting
in a slight overstatement of the reported benefits and costs for the
complete CAIR program.
b Monetary benefits adjusted to account for growth in real GDP per
capita between 1990 and the analysis year (2010 or 2015).
c Valuation assumes discounting over the SAB recommended 20 year
segmented lag structure described in the Regulatory Impact Analysis
for the Final Clean Air Interstate Rule (March 2005). Results show 3
percent and 7 percent discount rates consistent with EPA and OMB
guidelines for preparing economic analyses (US EPA, 2000 and OMB,
2003).\173\
d Adult mortality based upon studies by Pope et al. 2002. Infant
mortality based upon studies by Woodruff, Grillo, and Schoendorf,
1997.
e B represents the monetary value of health and welfare benefits not
monetized. A detailed listing is provided in Table X-4.

3. How Do the Benefits Compare to the Costs of This Final Rule?
The estimated annual private costs to implement the emission
reduction requirements of the final rule for the CAIR region are $2.36
in 2010 and $3.57 billion in 2015 (1999$). These costs are the annual
incremental electric generation production costs that are expected to
occur with the CAIR. The EPA uses these costs as compliance cost
estimates in developing cost-effectiveness estimates.
In estimating the net benefits of regulation, the appropriate cost
measure is ``social costs.'' Social costs represent the welfare costs
of the rule to society. These costs do not consider transfer payments
(such as taxes) that are simply redistributions of wealth. The social
costs of this rule are estimated to be approximately $1.9 billion in
2010 and $2.6 billion in 2015 assuming a 3 percent discount rate. These
costs become $2.1 billion in 2010 and $3.1 billion in 2015, if one
assumes a 7 percent discount rate. Thus, the net benefit (social
benefits minus social costs) of the program is approximately $71.4 + B
billion or $60.4 + B billion (3 percent and 7 percent discount rate,
respectively) annually in 2010 and $98.5 + B billion or $83.2 + B
billion annually (3 percent and 7 percent discount rate, respectively)
in 2015. Implementation of the rule is expected to provide society with
a substantial net gain in social welfare based on economic efficiency
criteria.
The annualized regional cost of the CAIR, as quantified here, is
EPA's best assessment of the cost of implementing the CAIR, assuming
that States adopt the model cap and trade program. These costs are
generated from rigorous economic modeling of changes in the power
sector due to the CAIR. This type of analysis using IPM has undergone
peer review and been upheld in Federal courts. The direct cost
includes, but is not limited to, capital investments in pollution
controls, operating expenses of the pollution controls, investments in
new generating sources, and additional fuel expenditures. The EPA
believes that these costs reflect, as closely as possible, the
additional costs of the CAIR to industry. The relatively small cost
associated with monitoring emissions, reporting, and recordkeeping for
affected sources is not included in these annualized cost estimates,
but EPA has done a separate analysis and estimated the cost to less
than $42 million (see section X. B., Paperwork Reduction Act). However,
there may exist certain costs that EPA has not quantified in these
estimates. These costs may include costs of transitioning to the CAIR,
such as the costs associated with the retirement of smaller or less
efficient EGUs, employment shifts as workers are retrained at the same
company or re-employed elsewhere in the economy, and certain relatively
small permitting costs associated with title IV that new program
entrants face. Costs may be understated since an optimization model was
employed that assumes cost minimization, and the regulated community
may not react in the same manner to comply with the rules. Although EPA
has not quantified these costs, the Agency believes that they are small
compared to the quantified costs of the program on the power sector.
The annualized cost estimates presented are the best and most accurate
based upon available information. In a separate analysis, EPA estimates
the indirect costs and impacts of higher electricity prices on the
entire economy [see Regulatory Impact Analysis for the Final Clean Air
Interstate Rule, Appendix E (March 2005)].

[[Page 25309]]

The costs presented here are EPA's best estimate of the direct
private costs of the CAIR. For purposes of benefit-cost analysis of
this rule, EPA has also estimated the additional costs of the CAIR
using alternate discount rates for calculating the social costs,
parallel to the range of discount rates used in the estimates of the
benefits of the CAIR (3 percent and 7 percent). Using these alternate
discount rates, the social costs of the CAIR are $1.9 billion in 2010
and $2.6 billion in 2015 using a discount rate of 3 percent, and $2.1
billion in 2010 and $3.1 billion in 2015 using a discount rate of 7
percent. The costs of the CAIR using the adjusted discount rates are
lower than the private costs of the CAIR generated using IPM because
the social costs do not include certain transfer payments, primarily
taxes, that are considered a redistribution of wealth rather than a
social cost.\174\
---------------------------------------------------------------------------

\174\ United States Environmental Protection Agency, 2000.
Guidelines for Preparing Economic Analyses.
http://www.yosemitel.epa.gov/ee/epa/eed/hsf/pages/Guideline.html.
Office of Management and Budget, The Executive Office of the President,
2003. Circular A-4.
http://www.whitehouse.gov/omb/circulars.

Table X-3.--Summary of Annual Benefits, Costs, and Net Benefits of the
Clean Air Interstate Rule a
[Billions of 1999 dollars]
------------------------------------------------------------------------
2010 (Billions of 2015 (Billions of
Description 1999 dollars) 1999 dollars)
------------------------------------------------------------------------
Social Costs: \b\
3 percent discount rate.... $1.91.............. $2.56
7 percent discount rate.... 2.14............... 3.07
Social Benefits: c,d,e
3 percent discount rate.... 73.3 + B........... 101 + B
7 percent discount rate.... 62.6 + B........... 86.3 + B
Health-related benefits:
3 percent discount rate.... 72.1 + B........... 99.3 + B
7 percent discount rate.... 61.4 + B........... 84.5 + B
Visibility benefits............ 1.14 + B........... 1.78 + B
Annual Net Benefits (Benefits-
Costs): \e,f\
3 percent discount rate.... 71.4 + B........... 98.5 + B
7 percent discount rate.... 60.4 + B........... 83.2 + B
------------------------------------------------------------------------
\a\ All estimates are rounded to three significant digits and represent
annualized benefits and costs anticipated for the years 2010 and 2015.
Estimates relate to the complete CAIR program including the CAIR
promulgated rule and the proposal to include annual SO2 and NOX
controls for New Jersey and Delaware. Modeling used to develop these
estimates assumes annual SO2 and NOX controls for Arkansas resulting
in a slight overstatement of the reported benefits and costs for the
complete CAIR program.
\b\ Note that costs are the annual total costs of reducing pollutants
including NOX and SO2 in the CAIR region.
\c\ As this table indicates, total benefits are driven primarily by PM-
related health benefits. The reduction in premature fatalities each
year accounts for over 90 percent of total monetized benefits in 2015.
Benefits in this table are nationwide (with the exception of ozone and
visibility) and are associated with NOX and SO2 reductions for the EGU
source category. Ozone benefits represent benefits in the eastern
United States. Visibility benefits represent benefits in Class I areas
in the southeastern United States.
\d\ Not all possible benefits or disbenefits are quantified and
monetized in this analysis. B is the sum of all unquantified benefits
and disbenefits. Potential benefit categories that have not been
quantified and monetized are listed in Table X-4.
\e\ Valuation assumes discounting over the SAB-recommended 20 year
segmented lag structure described in chapter 4 of the Regulatory
Impact Analysis for the Clean Air Interstate Rule (March 2005).
Results reflect 3 percent and 7 percent discount rates consistent with
EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000
and OMB, 2003).\174\
\f\ Net benefits are rounded to the nearest $100 million. Columnar
totals may not sum due to rounding.

Every benefit-cost analysis examining the potential effects of a
change in environmental protection requirements is limited to some
extent by data gaps, limitations in model capabilities (such as
geographic coverage), and uncertainties in the underlying scientific
and economic studies used to configure the benefit and cost models.
Gaps in the scientific literature often result in the inability to
estimate quantitative changes in health and environmental effects. Gaps
in the economics literature often result in the inability to assign
economic values even to those health and environmental outcomes that
can be quantified. While uncertainties in the underlying scientific and
economics literatures (that may result in overestimation or
underestimation of benefits) are discussed in detail in the economic
analyses and its supporting documents and references, the key
uncertainties which have a bearing on the results of the benefit-cost
analysis of this rule include the following:
? EPA's inability to quantify potentially significant
benefit categories;
? Uncertainties in population growth and baseline incidence
rates;
? Uncertainties in projection of emissions inventories and
air quality into the future;
? Uncertainty in the estimated relationships of health and
welfare effects to changes in pollutant concentrations including the
shape of the C-R function, the size of the effect estimates, and the
relative toxicity of the many components of the PM mixture;
? Uncertainties in exposure estimation; and
? Uncertainties associated with the effect of potential
future actions to limit emissions.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the rulemaking in future years under a set of reasonable assumptions.
In valuing reductions in premature fatalities associated with PM,
we used a value of $5.5 million per statistical life. This represents a
central value consistent with a range of values from $1 to $10 million
suggested by recent meta-analyses of the wage-risk value of statistical
life (VSL) literature.\175\
---------------------------------------------------------------------------

\175\ Mrozek, J.R. and L.O. Taylor, What determines the value of
a life? A Meta Analysis, Journal of Policy Analysis and Management
21(2), pp. 253-270.
---------------------------------------------------------------------------

The benefits estimates generated for this rule are subject to a
number of assumptions and uncertainties, that are discussed throughout
the Regulatory Impact Analysis document [Regulatory

[[Page 25310]]

Impact Analysis for the Final Clean Air Interstate Rule (March 2005)].
As Table X-2 indicates, total benefits are driven primarily by the
reduction in premature fatalities each year. Elaborating on the
previous uncertainty discussion, some key assumptions underlying the
primary estimate for the premature mortality category include the
following:
(1) EPA assumes inhalation of fine particles is causally associated
with premature death at concentrations near those experienced by most
Americans on a daily basis. Plausible biological mechanisms for this
effect have been hypothesized for the endpoints included in the primary
analysis and the weight of the available epidemiological evidence
supports an assumption of causality.
(2) EPA assumes all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality. This is
an important assumption, because the proportion of certain components
in the PM mixture produced via precursors emitted from EGUs may differ
significantly from direct PM released from automotive engines and other
industrial sources, but no clear scientific grounds exist for
supporting differential effects estimates by particle type.
(3) EPA assumes the C-R function for fine particles is
approximately linear within the range of ambient concentrations under
consideration. In the PM Criteria Document, EPA recognizes that for
individuals and specific health responses there are likely threshold
levels, but there remains little evidence of thresholds for PM-related
effects in populations.\176\ Where potential threshold levels have been
suggested, they are at fairly low levels with increasing uncertainty
about effects at lower ends of the PM_2.5 concentration
ranges. Thus, EPA estimates include health benefits from reducing the
fine particles in areas with varied concentrations of PM, including
both regions that are in attainment with fine particle standard and
those that do not meet the standard.
---------------------------------------------------------------------------

\176\ U.S. EPA. (2004). Air Quality Criteria for Particulate
Matter. Research Triangle Park, NC: National Center for
Environmental Assessment--RTP Office; Report No. EPA/600/P-99/002aD.

The EPA recognizes the difficulties, assumptions, and inherent
uncertainties in the overall enterprise. The analyses upon which the
CAIR is based were selected from the peer-reviewed scientific
literature. We used up-to-date assessment tools, and we believe the
results are highly useful in assessing this rule.
There are a number of health and environmental effects that we were
unable to quantify or monetize. A complete benefit-cost analysis of the
CAIR requires consideration of all benefits and costs expected to
result from the rule, not just those benefits and costs which could be
expressed here in dollar terms. A listing of the benefit categories
that were not quantified or monetized in our estimate are provided in
Table X-4. These effects are denoted by ``B'' in Table X-3 above, and
are additive to the estimates of benefits.
4. What Are the Unquantified and Unmonetized Benefits of the CAIR
Emissions Reductions?
Important benefits beyond the human health and welfare benefits
resulting from reductions in ambient levels of PM_2.5 and
ozone are expected to occur from this rule. These other benefits occur
both directly from NO_X and SO₂ emissions
reductions, and indirectly through reductions in co-pollutants such as
mercury. These benefits are listed in Table X-4. Some of the more
important examples include: Reductions in NO_X and
SO₂ emissions required by the CAIR will reduce acidification
and, in the case of NO_X, eutrophication of water bodies.
Reduced nitrate contamination of drinking water is another possible
benefit of the rule. This final rule will also reduce acid and
particulate deposition that cause damages to cultural monuments, as
well as, soiling and other materials damage.
To illustrate the important nature of benefit categories we are
currently unable to monetize, we discuss two categories of public
welfare and environmental impacts related to reductions in emissions
required by the CAIR: Reduced acid deposition and reduced
eutrophication of water bodies.
a. What Are the Benefits of Reduced Deposition of Sulfur and Nitrogen
to Aquatic, Forest, and Coastal Ecosystems?
Atmospheric deposition of sulfur and nitrogen, more commonly known
as acid rain, occurs when emissions of SO₂ and
NO_X react in the atmosphere (with water, oxygen, and
oxidants) to form various acidic compounds. These acidic compounds fall
to earth in either a wet form (rain, snow, and fog) or a dry form
(gases and particles). Prevailing winds can transport acidic compounds
hundreds of miles, across State borders. Acidic compounds (including
small particles such as sulfates and nitrates) cause many negative
environmental effects, including acidification of lakes and streams,
harm to sensitive forests, and harm to sensitive coastal ecosystems.
i. Acid Deposition and Acidification of Lakes and Streams
The extent of adverse effects of acid deposition on freshwater and
forest ecosystems depends largely upon the ecosystem's ability to
neutralize the acid. The neutralizing ability [key indicator is termed
Acid Neutralizing Capacity (ANC)]
depends largely on the watershed's
physical characteristics: Geology, soils, and size. Waters that are
sensitive to acidification tend to be located in small watersheds that
have few alkaline minerals and shallow soils. Conversely, watersheds
that contain alkaline minerals, such as limestone, tend to have waters
with a high ANC. Areas especially sensitive to acidification include
portions of the Northeast (particularly, the Adirondack and Catskill
Mountains, portions of New England, and streams in the mid-Appalachian
highlands) and southeastern streams.
Some of the impacts of today's rulemaking on acidification of water
bodies have been quantified. In particular, this rule will result in
improvements in the acid buffering capacity for lakes in the Northeast
and Adirondack Mountains. Specifically, 12 percent of Adirondack lakes
are projected to be chronically acidic in the base case. However, we
project that the CAIR rule will eliminate chronic acidification in
lakes in the Adirondack Mountains by 2030. In addition, today's rule is
expected to decrease the percentage of chronically acidic lakes
throughout Northeast from 6 to 1 percent. However, some lakes in the
Adirondacks and New England will continue to experience episodic
acidification even after implementation of this rule.
In a recent study,\177\ Resources for the Future (RFF) estimates
total benefits (i.e., the sum of use and nonuse values) of natural
resource improvements for the Adirondacks resulting from a program that
would reduce acidification in 40 percent of the lakes in the
Adirondacks that were of concern for acidification. While this study
requires further evaluation, the RFF study suggests that the benefits
of acid deposition reductions for the CAIR are likely to be substantial
in terms of the total monetized value for ecological endpoints
(although likely small in

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