Federal implementation plan.

In this Supplemental Proposal, the EPA has not followed the CAA mandate
requiring that prior to promulgating a FIP, the EPA must find that a
State has failed to make a required submission, or find that the plan or
plan revision submitted by the State does not satisfy minimum criteria,
or must disapprove a SIP submission in whole or part. As set forth
above, the EPA has not taken any action in regards to the May 1, 2007,
Interstate Transport SIP that addressed the requirements of CAA
1l0(a)(2)(D)(i). In addition, the EPA has not taken action to approve or
disapprove the December 2007 State of Oklahoma SIP revision and
certification that was submitted pursuant to an October 2007, EPA
guidance document. In that submission, Oklahoma certified (following the
dictates in the EPA Guidance Document) in December 2007 that Oklahoma's
Interstate Transport SIP met all the requirements of CAA section
11O(a)(I) and (2), which includes CAA section 110(a)(2)(D)(i)(I).
Therefore, the EPA does not have the authority under the CAA to issue
the FIP it is proposing in this Supplemental Rule under the CSAP
Program.  [Oklahoma Attorney General (EPA-HQ-OAR-2009-0491-4592), p.
3-6; Oklahoma Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590),
p. 3-5; AES Shady Point (EPA-HQ-OAR-2009-0491-4595), p. 3-4; Western
Farmers Electric Cooperative (EPA-HQ-OAR-2009-0491-4589), p. 5-6.]

RESPONSE:   For the reasons explained in section IV.C.2 of the preamble
to the final Transport Rule (76 FR 48208, August 8, 2011) and in the TSD
entitled “Status of CAA 110(a)(2)(D)(i)(I) SIPs Supplemental Rule”
TSD (December 2011), EPA has the legal obligation to promulgate all of
the FIPs in this rule.  This conclusion is based on the plain language
of the Clean Air Act as applied to the specific circumstances of each
state.

Section 110(c)(1) of the Act requires EPA to promulgate FIPs within two
years after finding that a state has failed to make a required SIP
submission or disapproving a SIP.  Specifically, section 110(c)(1)
states that the Administrator shall promulgate a Federal Implementation
Plan within two years after the Administrator "(A) finds that a State
has failed to make a required submission or finds that the plan or plan
revision submitted by the State does not satisfy the minimum criteria
established under subsection (k)(1)(A) of this section or (B)
disapproves a State implementation plan submission in whole or in part."
 42 U.S.C. § 7410 (c)(1)(A) & (B).  EPA is relieved of the obligation
to promulgate a FIP only if the state corrects the deficiency and EPA
approves the SIP before promulgating a FIP.  42 U.S.C. § 7410(c)(1).
The Act does not create any exceptions to this rule.  EPA has not
approved a SIP for Oklahoma that addresses this requirement; rather, EPA
has proposed to disapprove Oklahoma’s SIP submittal that addresses
110(a)(2)(D)(i)(I).  EPA is promulgating FIPs only in those
circumstances where the Clean Air Act explicitly provides that it shall
do so.

The commenter does not identify any provision that would give EPA
authority to alter the deadlines established in the statute or delay
implementation of the Transport Rule as requested.  In this case, the
Act explicitly provides that the SIP submission deadline runs from the
date of promulgation or revision of a NAAQS and the FIP clock starts
when EPA finds that a state has failed to make a required SIP submission
or EPA disapproves a SIP submission.

Nothing in the Act requires EPA, where it has already made findings of
failure to submit or disapproved SIP submissions, to promulgate a SIP
Call to give the states another opportunity to promulgate a SIP before
promulgating a FIP.  Section 110(a)(2)(D)(i)(I) SIP submittals are due 3
years after promulgation or revision of a NAAQS.  See 42 U.S.C. §
7410(a)(1).  Thus, 110(a)(2)(D)(i)(I) SIPs for the 1997 ozone NAAQS were
due in 2000.  While the statute gives EPA authority to prescribe a
shorter period of time for states to make SIP submissions, it does not
give EPA authority to extend the 3-year deadline established by statute.
 See 42 U.S.C. § 7410(a)(1).  Moreover, there is no requirement that
EPA promulgate a rule or issue guidance regarding the specific
requirements of section 110(a)(2)(D)(i)(I) in advance of the SIP
submittal deadline.

The plain language of section 110(c)(1) of the Act provides that EPA
shall promulgate a FIP at any time within 2 years after the
Administrator finds that a state has failed to make a required
submission or after disapproving a state implementation plan submission
in whole or part, unless the state corrects the deficiency, and the
Administrator approves the plan or plan revision, before the
promulgation of a FIP. See 42 U.S.C. § 7410(c)(1).  Far more than 2
years has now elapsed since EPA first made these findings with respect
to the 1997 ozone and 1997 PM2.5 NAAQS.  There is nothing in the plain
language reading of the Act that says that EPA’s obligation
“expires” at the end of the 2 years.

Finally, nothing in the Act requires EPA, where it has already made
findings of failure to submit or disapproved SIP submissions, to
promulgate a SIP Call to give the states another opportunity to
promulgate a SIP before promulgating a FIP.  Section 110(a)(2)(D)(i)(I)
SIP submittals are due 3 years after promulgation or revision of a
NAAQS.  See 42 U.S.C. § 7410(a)(1).  While the statute gives EPA
authority to prescribe a shorter period of time for states to make SIP
submissions, it does not give EPA authority to extend the 3-year
deadline established by statute.  See 42 U.S.C. § 7410(a)(1).

Comment:  The EPA's Supplemental Rule Proposal for Oklahoma under the
CSAP Program intrudes upon the role generally left to the States under
the CAA. In Train v. Natural Resources Defense Council, Inc., 421 U.S.
60 (1975), the United States Supreme Court found that although the CAA
plainly charges the EPA with the responsibility for setting the national
ambient air quality standards, the Act, just as plainly, relegates the
EPA to a secondary role in the process of determining and enforcing the
specific, source-by-source emission limitations that are necessary if
the national standards are to be met. According to the Court, the Act
gives the agency no authority to question the wisdom of a State's choice
of emission limitations if they are part of a plan that satisfies the
standards of section 110(a)(2), and the agency may devise and promulgate
a specific plan of its own only if a State fails to submit an
implementation plan that satisfies those standards. To this point, the
Court stated: "So long as the ultimate effect of a State's choice of
emission limitations is compliance with the national standards for
ambient air, the State is at liberty to adopt whatever mix of emission
limitations it deems best suited to its particular situation." Id. at
79.

The CAA then "establishes a partnership between EPA and the states for
the attainment and maintenance of national air quality goals." See
Natural Res. Def  Council, Inc. v. Browner, 57 F.3d 1122, 1123 (D.C.
Cir. 1995). "Air pollution prevention ... at its source is the primary
responsibility of States and local governments...." 42 U.S.C. §
7401(a)(3). Congress "carefully balanced State and national interests by
providing for a fair and open process in which State and local
governments, and the people they represent, will be free to carry out
the reasoned weighing of environmental and economic goals and needs."

In the current Supplemental Proposal, the EPA is proposing a FIP in
Oklahoma regarding summertime NOX reductions under the CSAP ozone-season
control program. The EPA is proposing to promulgate this FIP despite the
fact that Oklahoma has submitted a SIP that meets the requirements of
the CAA and despite the fact that EPA has not taken any action on
Oklahoma's SIP, as required in the CAA. Such action by the EPA is an
impermissible intrusion upon the authority reserved to Oklahoma and
exceeds the authority granted to the EPA under the CAA.

Another commenter makes similar arguments, citing the same case law.
The commenter also notes that The Act expressly allocated to states the
initial responsibility for determining the manner in which air quality
standards are to be achieved. Train v. Natural Resources Defense
Counsel, 421 U.S. 60,64 (1975). EPA "may devise and promulgate a
specific plan of its own only if a State fails to submit an
implementation plan which satisfies those standards." Commonwealth of
Virginia, 108 F.3d at 1482.  The CAA is an experiment in federalism "and
the EPA may not run roughshod over the procedural prerogatives that the
Act has reserved to the states ... " Id at 1408 (internal citation
omitted).  [Oklahoma Attorney General (EPA-HQ-OAR-2009-0491-4592), p.
6-8; Western Farmers Electric Cooperative (EPA-HQ-OAR-2009-0491-4589),
p. 4.]

RESPONSE:  For the reasons explained in section IV.C.2 of the preamble
to the final Transport Rule (76 FR 48208, August 8, 2011) and in the TSD
entitled “Status of CAA 110(a)(2)(D)(i)(I) SIPs Supplemental Rule”
TSD (December 2011), EPA has the legal obligation to promulgate all of
the FIPs in this rule.  This conclusion is based on the plain language
of the Clean Air Act as applied to the specific circumstances of each
state.

Section 110(c)(1) of the Act requires EPA to promulgate FIPs within two
years after finding that a state has failed to make a required SIP
submission or disapproving a SIP.  Specifically, section 110(c)(1)
states that the Administrator shall promulgate a Federal Implementation
Plan within two years after the Administrator "(A) finds that a State
has failed to make a required submission or finds that the plan or plan
revision submitted by the State does not satisfy the minimum criteria
established under subsection (k)(1)(A) of this section or (B)
disapproves a State implementation plan submission in whole or in part."
 42 U.S.C. § 7410 (c)(1)(A) & (B).  EPA is relieved of the obligation
to promulgate a FIP only if the state corrects the deficiency and EPA
approves the SIP before promulgating a FIP.  42 U.S.C. § 7410(c)(1).
The Act does not create any exceptions to this rule.  EPA has not
approved a SIP for Oklahoma that addresses this requirement; rather, EPA
has proposed to disapprove Oklahoma’s SIP submittal that addresses
110(a)(2)(D)(i)(I).  EPA is promulgating FIPs only in those
circumstances where the Clean Air Act explicitly provides that it shall
do so.

EPA has considered the specific circumstances of each state in
determining whether it has an obligation to promulgate a FIP for that
state with respect to a particular NAAQS.  More detailed information
regarding Oklahoma-specific actions taken by EPA and the status of its
110(a)(2)(D)(i)(I) SIP appears in the TSD entitled, Status of CAA
110(a)(2)(D)(i)(I) SIPs Supplemental Rule TSD (December 2011).  The TSD
explains the current status of the Oklahoma 110(a)(2)(D)(i)(I) SIP.

Further, the cases cited by the commenter do not support the commenter's
conclusion that it is improper for EPA to promulgate the FIPs in this
rule.  The cases discussing the system of cooperative federalism
established by the Clean Air Act explain both the primary role given to
states with regard to the protection of air quality and EPA’s
obligation to promulgate federal plans “if a State fails to submit an
implementation plan which satisfies [the standards of 110(a)(2)]”.
Train, 421 U.S. at 79.

Comment:  Commenter incorporates by reference comments filed by Oklahoma
Gas and Electric and Western Farmers Electric Cooperative.  [Oklahoma
Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 3.]

RESPONSE:  See above responses in this section.

Wisconsin

No comments received on this issue.

Ozone Season NOX Emission Budgets

3.1. General

No comments received on this issue.

3.2 Iowa

No comments received on this issue.

3.3 Kansas

 (A) Commenters(s) raise issues with the budgets established for Kansas.

Comment:  The allowances allocated to sources in these rules are
severely short for the SO2 and NOX programs. This presents difficult
compliance challenges for Empire District as well as other sources in
Kansas that have either maintained compliance with previous rules via
banked or purchased allowances and have not previously been subject to
the Clean Air Interstate Rule and subsequently do not have the needed
controls installed.

Empire District compared 2010 SO2 actual emissions with the 2012 SO2
allowance allocations and the initial analysis shows that SO2 Group 1
allocations will be approximately 600,000 tons short and SO2 Group 2, of
which the state of Kansas belongs, allocations will be short
approximately 300,000 tons. Since it is apparent there will be a
shortage of SO2 allowances in 2012 available to purchase for compliance,
it is critical that sources have more time to install the controls
needed to comply with the CSAPR and supplemental rule to the CSAPR.

According to the technical supporting document for Final Transport Rule
analysis in EPA’s application of the Integrated Planning Model,
Appendix 3-3 New Source Review settlements in Base Case v 4.10_F
Transport (05-16-11), the state of Kansas SO2 budgets were developed
without considering the allowance restrictions contained in the consent
agreement for Westar’s Jeffrey Energy Center. Because of the consent
agreement restrictions there will be approximately 13,700 SO2 allowances
unavailable for trading. This egregious error severely restricts Kansas
utilities ability to comply with the CSAPR via the SO2 allowance trading
program and represents approximately 34 percent of the total state SO2
budget.

Empire District questions how many other consent agreements were ignored
or erroneously missed. Furthermore, what is the true number of total
allowances available across Group 1 and Group 2 if EPA considers all
consent agreements in its respective state budgets? This is a serious
issue that must be addressed prior to the commencement of the CSAPR
going into effect in January 2012.  [Empire District Electric Company
(EPA-HQ-OAR-2009-0491-4581), p. 2]

RESPONSE:  These comments are outside the scope of this rulemaking.  EPA
is addressing the role of consent decrees in unit-level allowance
allocation in a separate rulemaking.  See Revisions to Federal
Implementation Plans to Reduce Interstate Transport of Fine Particulate
Matter and Ozone, 76 FR 63860, October 14, 2011.

3.4 Michigan

No comments received on this issue.

3.5 Missouri

No comments received on this issue.

Oklahoma

(A)  EPA's Supplemental Proposal requires an overly drastic reduction in
ozone season NOX emissions for commenter and the State of Oklahoma
generally.

Comment:  EPA's Supplemental Proposal marks a significant change in the
Agency's treatment of Oklahoma compared to the 2010 Proposed interstate
Transport Rule, and also would require a drastic reduction in the
State's actual ozone season NOX emissions.  Commenter include a table
that summarizes the differences between the ozone season NOX emissions
budget for Oklahoma in the Supplemental Proposal, the same budget in the
2010 Proposed Rule, and the State's actual NOX emissions from EGUs
during the 2010 ozone season.

As shown in the table, the Supplemental Proposal assigns to Oklahoma a
statewide ozone season NOX emissions budget of just 21,835 tons per
year, which represents a reduction of more than 15,000 tons (roughly
41%) from the state's budget in the 2010 Proposed Transport Rule.
Compared to 2010 actual emissions, this budget requires a reduction of
more than 13,000 tons (37%) statewide. The budget proposed for Oklahoma
is inadequate because EPA relies on a collection of flawed assumptions
about unit shutdowns and curtailments.  For example, OG&E's Mustang
units are allocated no allowances and are therefore assumed to retire.
OG&E does not expect shutdown of these units to be feasible while still
meeting consumer demand.

For OG&E's units, the total emission reduction required under the
Proposal would be roughly 6,000 tons or 38.6% percent less than actual
2010 emissions and 6,800 tons or 41.5% percent less than the allowances
provided to OG&E's units under the 2010 Proposed Rule. Certain OG&E
units would bear the bulk of this impact. As an example, OG&E's Muskogee
and Sooner units (the base load units of OG&E's generation) are assumed
to achieve a 50% reduction in NO, emissions during the ozone season.
Simply put, this would mean that these base load units could only run
during 50% of the ozone season, which is the hot period in Oklahoma.
Based on the demand for recent operations, OG&E believes that these
reductions are not feasible.

EPA claims that the drastic reductions in ozone season NOX emissions
called for by the Supplemental Proposal can be achieved by installing
emission controls, or by purchasing allowances to cover emissions. It is
not realistic, however, to expect EGUs to install controls prior to the
proposed compliance deadline of May I, 2012. Nor has EPA accounted for
the likelihood of allowance shortfalls in light of the drastic emission
reductions that EGUs would be required to achieve by May 2012.
Furthermore, as discussed in more detail in Section IV, the compliance
schedule may not allow enough time for OG&E to purchase power to replace
what would be lost through curtailments.  [Oklahoma Gas & Electric
Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 6-8; Oklahoma Utility
Group (EPA-HQ-OAR-2009-0491-4591), p. 5.]

RESPONSE:  See the preamble to this final rule, section III.B.iv. and
section III.E.

Comment:  Oklahoma’s ozone-season NOX budget is unreasonably low. In
the proposed rulemaking for the Transport Rule (published in the Federal
Register on August 2, 2010), the ozone-season NOX budget for the state
of Oklahoma was set at 37,087 tons (Table IV.E-2 of the preamble to the
proposed rule, 75 FR 45291).  In the SNPR, the ozone-season NOX budget
for the state of Oklahoma was set at 21,835 tons (Table I.C-1 of the
SNPR, 76 FR 40666).  Between the issuance of the proposed rule in 2010
and the issuance of the SNPR in 2011, EPA reduced the state budget by
41.1%. In the proposed rule, the state budgets were set using a process
that started with a baseline developed using the Integrated Planning
Model (IPM), based on historic emissions data and projections about
future growth in demand for electricity.  After setting the emissions
baseline, EPA used an air quality assessment tool (AQAT) and cost curves
to determine the amount of NOX reduction that would be required to
comply with the “good neighbor” requirements of the Clean Air Act.
Using this method, EPA set the state ozone-season NOX budget at 37,087
tons for Oklahoma.  Despite some concerns about some aspects of the
process, we believed the state budget established in the proposed rule
to be fair and achievable.  In the final rule and in the SNPR, EPA made
a radical and previously unannounced departure from the previous method.
 In the preamble for the final rule, EPA stated that, based on emissions
inventory data for 2009, they were changing the ozone-season emissions
baseline.  In the final rule, EPA acknowledged this change, but did not
provide a clear description of the process.  Was the new baseline based
almost exclusively on the 2009 emissions inventory data?  Did the EPA
take into consideration the reduced demand associated with the recession
as mentioned in section IV?  How much did the IPM analysis performed
previously factor into the new state budgets?  The criteria used to set
the new baseline remain unclear. We believe this change in methodology
fails to meet the standards for prudent rulemaking and that, by failing
to re-propose the rule and accept comments on this aspect of the rule,
EPA has acted in an arbitrary and capricious manner.  [Oklahoma
Department of Environmental Quality (EPA-HQ-OAR-2009-0491-4593), p.
5-6.]

RESPONSE:   First, EPA has finalized in this action an ozone-season NOX
budget for the state of Oklahoma that is significantly larger than the
budget in the proposed Supplemental rulemaking.  This higher budget for
2012 addresses the commenter’s concerns about compliance with the 2012
proposed budget.  In regards to questions about 2009 data informing the
baseline, the 2009 data was one of several variables that influenced the
final rule emissions baseline for 2012.  For instance, lower natural gas
prices are another variable that were updated that would also impact the
baseline between proposal and final.  EPA did consider the recessionary
impact of 2009 on emissions levels.  We did not use emission levels in
our modeling, only emission rates — which are minimally impacted by
any recessionary impacts.

Comment:  The Oklahoma emission budget is not based on accurate data and
operational  assumptions. EPA may not impose requirements on sources or
states without authorization by Congress through the CAA. See, e.g.,
Michigan v. EPA, 268 F.3d 1075, 1081 (D.C. Cir. 2001) ("It is axiomatic
that an administrative agency's power to promulgate legislative
regulations is limited to the authority delegated by Congress.")
(quoting Bowen v. Georgetown Univ. Hosp., 488 U.S. 204, 208 (1988». EPA
has not demonstrated that the severely restrictive budget proposed for
Oklahoma would achieve only those emissions reductions required by
Section 110 of the Act. Emissions reductions beyond what is required to
eliminate significant contribution to downwind nonattainment are an
abuse of EPA discretion and in excess of the Agency's authority under
the Act.

The unit-specific data and operational assumptions relied on by EPA to
establish the

State emissions budget contains numerous inaccuracies.  Comments on the
2010 Proposal submitted by the Oklahoma Department of Environmental
Quality ("ODEQ") identified a significant number of errors in EPA's
Integrated Planning Model ("IPM") files. See Docket No.
EPA-HQ-OAR-2009-049I -2662. ("The IPM model run results are very
erratic, retiring both coal and natural gas facilities that have no
plans to retire, increasing and decreasing electricity production at
various facilities, and adding solar power to Oklahoma when none has
been planned.")  Similarly, WFEC notified EPA that the IPM files
contained no heat input data for units 4, 5, and 6 at its Anadarko
facility.  See Docket No. EPA-HQ-OAR-2009-0491-2642.  The heat input of
EGUs within a state play a crucial role in EPA's methodology for
establishing the state's emissions budget.  EPA's failure to correct
these errors "bespeaks a 'let them eat cake' attitude that ill-becomes
an administrative agency whose obligation to the public it serves is
discharged if only it avoids being arbitrary and capricious." Chemical
Mfrs. Ass'n v. EPA, 28 F.3d at 1266. The emissions budget for the State
of Oklahoma cannot accurately reflect emissions reductions necessary to
eliminate only those emissions that significantly contribute to downwind
pollution because it is not based on the most accurate data available to
the Agency.

EPA cannot impose emissions reductions beyond those required to address
Oklahoma's significant contribution to downwind pollution.  In North
Carolina v. EPA, the D.C. Circuit rejected EPA's attempt to require some
states "to exceed the mark" in reducing upwind emissions because the Act
gave "EPA no authority to force an upwind state to share the burden of
reducing other upwind states' emissions." 531 F.3d 896, 921.  Because
the state budgets at issue in North Carolina "shifted the burden of
emissions reductions," the Court invalidated the budgets as arbitrary
and capricious.  Id In CSAPR, EPA claims that the methodology used to
set state emissions budgets evaluates only cost and state-specific
contributions to downwind pollution. 76 Fed. Reg. 48,211-12.  EPA
completely disregards the fact that any methodology would produce
inaccurate emissions budgets if fed inaccurate data and assumptions.
Because the emissions budget proposed for Oklahoma is based on
inaccurate data, modeling and assumptions, there is every reason to
believe that it too "exceeds the mark."  [Western Farmers Electric
Cooperative (EPA-HQ-OAR-2009-0491-4589), p. 9-10.]

RESPONSE:   Regarding the “solar” issue, EPA is not aware of any
projected new solar in the IPM outputs, and the commenter does not
specify what solar in the IPM outputs they are referring to.  There are
only 7.5 MW of Oklahoma solar generating capacity (or about 0.03% of
more than 20,000 MW of total Oklahoma generating capacity) in the NEEDS
input files, reflecting what is reported to be recently installed
Southern Great Plains Commercial Solar.  However, this appears to
already exist and the source did not comment on its existence when
depicted in the proposed modeling, so this is unlikely what commenter is
addressing.  Moreover, the relative size of these existing solar units
would not have any meaningful impact on emissions modeled at the state
level.  In regards to IPM projections of unit level heat input, they are
just that – projections of what would likely be the least-cost
response to the state budget or cost threshold modeled.  EPA was very
clear about how IPM does not reflect how the unit may ultimately decide
to operate.  CSAPR is not a unit-level control program and the
allocations are not based on its projections.  Therefore, the projection
has no bearing on how the unit chooses to operate.  The commenter’s
suggestion that simply substituting historic data from a period when a
source was not subject to an ozone season emission reductions program
for a period when it is subject to an emission reductions program is not
reasonable and fundamentally inconsistent with the notion of emission
reductions.

In regards to the viability of the state budget in 2012, this final rule
addresses those concerns by increasing the budget to a level where no
combustion controls are assumed.

 (B) There are errors in EPA’s methodology as applied to calculation
of Oklahoma’s budget.

Comment:  DEQ’s analysis of the application of EPA’s methodologies
for determining state budgets and allocations to individual units
demonstrates clear errors were made in determining Oklahoma’s
allowances. By changing the method of calculation for the state
allowance budgets from using the IPM modeling to a reliance on 2009
emissions inventory data, EPA made a number of errors that have resulted
in assigning an ozone-season NOX allowance budget for the State of
Oklahoma which is lower than is warranted. The Excel spreadsheet titled
“Proposed CSAPR Unit Level Allocations under the SNPR and Underlying
Data” provides baseline data used to calculate the state budgets. A
number of units are listed in the spreadsheet, because they will be
subject to the Cross-State Air Pollution Rule even though they are not
currently subject to the Acid Rain Program (ARP). These units do not
report emissions to the Clean Air Markets Division (CAMD), and their
emissions are not included in the CAMD database. EPA obtained some
historical emissions data for these units, and those data are included
in the spreadsheet. However, for the years 2008, 2009, and 2010, many of
these units appear in the table as having zero emissions for the ozone
season. The absence of any emissions data for these units has the effect
of lowering the baseline from which EPA set the state budget. The agency
provides a in the comment letter to provide a comparison of EPA and DEQ
data for the total emissions from all subject units for the 2008 through
2010 ozone seasons.

Two key observations are noteworthy: (1) due to the recession, the 2009
ozone season represented an anomalously low year for ozone-season
emissions and (2) the failure to capture year-to-year trends in
emissions from units not subject to the ARP yielded a state budget
baseline that is nearly 3,000 tons too low. In addition, we calculate
that utilities operating in Oklahoma will need to retrofit 43 individual
combustion units with low-NOX burners to comply with the requirements of
the new rule. This number is substantially larger than the 30 units in a
four-state area predicted in EPA’s TSD, “Installation Timing for Low
NOX Burners (LNB).” To remedy these failings, we recommend that EPA
increase the state ozone-season NOX allowance budget by 1,500 tons and
that the compliance date for units operating in Oklahoma be pushed back
to the 2015 ozone season.

We believe that our request for this increase in the state budget is
justified for four reasons: (1) the 2009 emissions estimate data are
unrepresentative due to the recession, (2) the failure to include
non-ARP sources in the budget baseline lead to a baseline nearly 3,000
tons below actual values, (3) assuming a 50% control efficiency for
low-NOX burners applied to a baseline elevated by 3,000 tons would yield
an additional 1,500 tons of allowances for the state budget, and (4)
this increase in the budget still retains over 90% of the reductions
from the initial proposal. We believe the fourth point to be
particularly salient, and we would ask EPA to use their AQAT to
determine whether, with a state ozone-season NOX budget of 23,335 tons,
Oklahoma would be expected to make a significant contribution to the
ozone levels in Allegan Co., Michigan.  [Oklahoma Department of
Environmental Quality (EPA-HQ-OAR-2009-0491-4593), p. 3-4.]

RESPONSE:  The 2012 state budget has been increased.  See section
III.B.iv and section III.E. in the preamble of the final rule.  EPA has
finalized an ozone-season NOX budget for the state of Oklahoma that is
significantly larger than the budget in the proposed Supplemental.  This
higher budget for 2012 addresses the commenter’s concerns about
compliance with the 2012 proposed budget.  In regards to questions about
2009 data informing the baseline, the 2009 data was one of several
variables that influenced the final rule emissions baseline for 2012.
For instance, lower natural gas prices are another variable that were
updated  that would also impact the baseline between proposal and final.
 EPA did consider the recessionary impact of 2009 on emissions levels.
We did not use emissions levels in our modeling, only emission rates —
which are minimally impacted by any recessionary impacts.

3.7 Wisconsin

No comments received on this issue.

Proposed Unit-Level Ozone Season NOX Allowance Allocations (data inputs
& new unit set-asides)

4.1 General

No comments received on this issue.

4.2 Iowa

No comments received on this issue.

4.3 Kansas

No comments received on this issue.

4.4 Michigan

 (A) Commenter disagrees with set-aside for Indian Country in Michigan.

Comment:  The MDEQ believes that the proposed new unit set-asides of 26
allowances for 2012 and 25 allowances for 2014 are not necessary and
should be returned to the allocation pools for the electric generating
units main allowances. At this time and into the foreseeable future, the
MDEQ is not aware of any proposed power plant installations on Michigan
tribal lands.

In addition, the EPA has indicated that even if a state received federal
approval for a SIP, the EPA will continue to allocate allowances to
Indian Country units.

The MDEQ believes it is more appropriate for states to have the ability
to process any new source requests and allowance determinations for the
entire state, including tribal lands, rather than having a split
allocation system once the state's SIP is approved.  [Michigan
Department of Environmental Quality (EPA-HQ-OAR-2009-0491-4606), p.
1-2.]

RESPONSE:  EPA retains administration of new unit set-asides designated
for Indian country because EPA, rather than the states, has the
authority and responsibility of administering the Transport Rule with
regard to new units that locate in Indian country.  Under the FIP, any
allowances from the Indian country new unit set-aside that are not
allocated in a given control period are redistributed to the state’s
new unit set-aside for allocation to new units not in Indian country.
Any allowances not allocated from the state’s new unit set-aside are
redistributed to existing units, which are not in Indian country.
Under a SIP, the state may determine how unallocated allowances in the
Indian country set-aside are to be allocated within the state.  For
details, see section VII.D.2.e of the preamble of the final Transport
Rule and see section XX.D of the Transport Rule Primary Response to
Comments document [EPA-HQ-OAR-2009-0491-4513].

4.5 Missouri

No comments received on this issue.

4.6 Oklahoma

 (A) Commenter(s) state that facility-specific allowance allocations are
based on flawed and/or incomplete data.

Comment:  The data used in the proposed allowance allocations in the
NODA for the proposed rule and supporting technical information are in
error. The allowance allocations in the Technical Support Documents are
based on flawed and incomplete historical data and emissions level model
inputs. These errors were identified in previous comments regarding this
rulemaking by the AES Corporation, but have thus far not been corrected.

The NOX allocations provided for the AES Shady Point facility do not
reflect historical actual NOX emissions.  As indicated in the Unit
Allocation Table in the Administrative Record, the source of the NOX
data for AES Shady Point is Energy Information Administration (EIA)
data. However, in years 2005 - 2006, for the AES Shady Point facility,
despite non zero data entry entries for heat input, data entries for NOX
emissions were omitted, and apparently treated as zero within the
allocation methodology.

This omission must be a clerical error since it cannot be assumed that
the facility generated heat without generating NOX.  The facility was
unquestionably in existence and operating at the time. More
specifically, the State of Oklahoma authorized NOX emissions for this
facility (Permit Number) and included AES Shady Point facility emissions
in its State Implementation Plan (SIP) emissions inventory. For example,
for calendar year 2009, the facility reported a total of 1315.7 tons NOX
(2009 Point Source Emissions, ODEQ, August 22, 2011,
http://www.deq.state.ok.us/AQDnew/emissions/index.htm).  Based on an
engineering review utilizing actual facility NOX emission data (in place
of the omitted data) and the proposed USEPA methodology, these data
omissions appear to yield erroneously low NOX allocations.  A copy of
these engineering calculations including proposed corrected NOX
allocations are attached.

AES asks that the above clerical error be corrected and the facility's
actual emissions be recognized in the allocation methodology. If the
clerical error is not corrected AES will be significantly and unfairly
impacted. While NOX emissions from other company's facilities would be
recognized-the NOX emissions from AES would not-resulting in a
significant competitive disadvantage to AES. Such an unfair  application
of the law would appear to be both arbitrary and capricious, and a
Federal due process violation.  [AES Shady Point
(EPA-HQ-OAR-2009-0491-4580), p. 1.]

RESPONSE:  The AES Shady Point facility’s historic data has been
updated in this final rulemaking to reflect the data submitted during
the comment period and described above.  The final unit level
allocations reflect these updates and can be seen in the allocation
Technical Support Document, “Final Unit-Level Ozone Season NOX
Allowance Allocations to Existing Units in 5 States:  Supplemental Final
Rule,” in the docket to this rulemaking.

4.7 Wisconsin

No comments received on this issue.

Other In-Scope Issues

5.1 Implementation Issues (e.g., timing for installation of controls)

Commenter supports EPA’s compliance timetable.

Comment:  Sierra Club also supports EPA’s proposal to implement the
NOX emissions reductions on the same schedule for the 20 other states
subject to the transport rule.  Each state has been well aware that it
could be subject to ozone season NOX emission requirements.  Four of the
states were subject to the ozone season NOX requirements in the Clean
Air Interstate Rule, and three were subject to 2010 cross state
proposal.

Another compelling reason why these six states must start making
reductions immediately is that the proposed cross state rule only aims
to achieve compliance with 1997 ozone standard of .08 ppm. The standard
was decreased in 2008 to .075 ppm and EPA has proposed to lower the
standard even further to .06 to .07 ppm.  Indeed, Sierra Club’s
position continues to be that the transport rule, and this supplement,
is deficient because it fails to prevent significant contribution to
nonattainment of 2008 ozone NAAQs.  [Sierra Club
(EPA-HQ-OAR-2009-0491-4587), p. 2-3.]

RESPONSE:  EPA concurs with the comments supporting the application of
the same schedule under the Transport Rule ozone season NOX program to
Iowa, Michigan, Missouri, Oklahoma, and Wisconsin as to other states.
To the extent the comment addresses the 2008 Ozone NAAQS, the comment is
outside the scope of this rulemaking, which addresses the 1997 ozone
NAAQS.

Comment:  We also support EPA’s proposal to implement the ozone season
NOX emission requirements for the six states subject to the SNPR
(including SIP submissions) on the same schedule as those requirements
for the 20 other states subject thereto, that is, beginning May 1, 2012.
Those six states and power plants located therein should be able to meet
this schedule, as each state has been subject to (or on notice that it
could be subject to) ozone season NOX emission requirements.  Of the six
states subject to the SNPR, four (Iowa, Michigan, Missouri and
Wisconsin) were subject to the ozone season NOX requirements in the
Clean Air Interstate Rule (“CAIR,” which CSAPR replaces), while
three (Kansas, Michigan, and Oklahoma) were subject to the 2010 CSAPR
proposal.  [Clean Air Task Force, et al. (EPA-HQ-OAR-2009-0491-4588), p.
3.]

RESPONSE:  EPA concurs with the comments supporting the application of
the same schedule under the Transport Rule ozone season NOX program to
Iowa, Michigan, Missouri, Oklahoma, and Wisconsin as to other states.

Commenter(s) questions the feasibility and/or validity of the compliance
deadline.

Comment:  How does EPA expect the States to comply with this rule by the
2012 compliance date?  In the Fact Sheet for the Cross-State Air
Pollution Rule, EPA notes that “This action builds on more than
fifteen years of progress…”  The six States in the Supplemental Rule
will have approximately 6 months to prepare and implement a method of
compliance.   [Oklahoma Municipal Power Authority (OMPA)
(EPA-HQ-OAR-2009-0491-4573), p. 2.]

RESPONSE:  See the preamble of final Transport Rule, section VII.C and
the "Transport Rule Engineering Feasibility Response to Comments"
document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities. While the NOX ozone season
program begins in May 2012, sources have until September 30, 2012 to
achieve emission reductions and can purchase allowances to cover
emissions until December 1, 2012 when they have to comply by holding
allowances sufficient to cover their ozone season NOX emissions.

Comment:   Empire District believes the short time frame whereby
affected sources must comply with the provisions of both the final CSAPR
as well as the proposed supplemental rule to the CSAPR is not realistic.
 Affected sources are allowed less than five months to comply with the
annual NOX and SO2 emissions requirements in the final CSAPR and allowed
less than nine months ( to comply with the ozone season NOX emission
requirements in the proposed supplemental rule to the CSAPR.

In the proposed Transport Rule Empire District commented that during a
2010 study of our Asbury facility to determine the Air Quality Control
Systems (ACQS) needed for the future, including a scrubber, that the
actual projected timeline from project planning to project completion is
approximately 60 months. Using this as an example, it will take more
time than allowed for by these rules for sources to install the controls
that will be required for compliance.  [Empire District Electric Company
(EPA-HQ-OAR-2009-0491-4581), p. 1.]

RESPONSE:  See the preamble of final Transport Rule, section VII.C.2 and
the "Transport Rule Engineering Feasibility Response to Comments"
document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:  EPA indicates that it expects to finalize this rulemaking on
or before November 1, 2011 which allows for only a six-month lead time
prior to the 2012 ozone season which commences on May 1, 2012. See 76
Fed. Reg. 40667, Section I(E). KCP&L has coal-fired units that are part
of what EPA describes as the “vast majority of covered sources already
have combustion controls installed”, but also has units that are part
of the “small number of sources will need to install combustion
controls to comply”. Id. KCP&L does not concur that for this later
group of sources it is “practical” to install combustion controls to
achieve compliance “within the time period” allowed. Id.

Installation of these combustion controls on KCP&L’s coal-fired units
is a time-consuming, expensive process. Steps in this process include:
initial design, development of project specifications, procurement
(identification of bidders, solicitation, review of bids, and contract
negotiations), permitting including in some cases New Source Review
Presentation of significant Deterioration permits, regulatory approvals,
obtaining financing, final design, mobilization of the needed workforce,
construction, process tie-ins and process startup testing. These
activities cannot commence until a final rule is issued and the
compliance requirements known. KCP&L believes several of these steps
alone can exceed six months much less all the steps in total.  [Kansas
City Power & Light (EPA-HQ-OAR-2009-0491-4584), p. 2.]

RESPONSE:  See the preamble of final supplemental rule, section
III.B.iv.  Also see the preamble to the final Transport Rule, section
VII.C.2 and the "Transport Rule Engineering Feasibility Response to
Comments" document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:   In the Supplemental Proposal, EPA says that it expects to
finalize a rule for Oklahoma and the other five states on or before
November 1, 2011, which would allow approximately six months of lead
time before the start of the 2012 ozone season. EPA claims that only "a
small number" of sources would need to install combustion controls in
order to comply with the CSAPR, and that this small number of required
installations can be achieved in just six months.

EPA's assumptions are incorrect for Oklahoma and the surrounding region.
To comply with the Supplemental Proposal (without considering other EPA
rulemakings on air emissions), one commenter anticipates that it would
need to install Low NOX Burners ("LNBs") on all five of its coal-fired
units, which represent a significant portion of the generating capacity
in Oklahoma. Another utility group commenter states broadly that it will
need to install controls on many of its affected units. EPA itself
estimates that LNBs will need to be installed on 30 coal-fired boilers,
mostly in Oklahoma and surrounding states. In Oklahoma alone, EPA
assumes that LNBs will be responsible for 9,900 tons of ozone season NO,
emission reductions in Oklahoma during 2012. Commenters therefore
disagree with EPA's notion that LNB retrofits will impact a "small
number" of units in the region.

Furthermore, it will not be possible to procure, permit, and install the
necessary controls on these units before May of 2012. Some commenters
estimate that it will need roughly three years from the date of an
appropriate final rule before the required controls could be operational
on the appropriate units. Overall, this process requires project
scoping, budgeting, engineering and design, bidding, permitting, outage
planning, equipment fabrication, delivery, and installation.

One utility group commenter estimates that it will need somewhere
between 2 ½ to 3 years, before the required controls can be installed
and are functionally operational. This is typical for this kind of
installation of air emission controls. It will take 12-18 months to bid
and acquire the necessary equipment. Assuming permits and regulatory
approvals can be obtained simultaneously with this procurement process,
the timing to apply for and receive the required permits and approvals
will require approximately 12-18 months. Another 12-18 months of
construction time may be needed once equipment, permits and approvals
are available for the controls to be operational. In some instances the
controls may require additional tuning over a period of four (4) to six
(6) months to achieve the designed reductions. Overall, this process
requires project scoping, budgeting, engineering and design, bidding,
permitting, outage planning, equipment fabrication, delivery, and
installation. While not included in this estimate, another timing
requirement will be to schedule and determine how the units will be
allowed to be taken off-line for the installation – whether during
scheduled outages or if other timing involved with the SPP approval.
This comprehensive planning and schedule coordination will require
additional time and may prevent the controls being installed as quickly
as they might without these important considerations for electricity
reliability on the grid.

Another commenter states that it is estimated that affected units would
need 12-18 months to acquire the necessary equipment and permits, and
that it is estimated that 21 months of construction time would be
necessary once equipment and permits are available.

EPA's two anecdotal instances of LNB installations in Texas and Georgia
from the two page TSD for this rulemaking do not support a six-month
schedule for installing LNBs on commenters’ units.  Two commenters
note that as an initial matter, the "similar schedule" mentioned in the
TSD for the Southern Company units was actually eight months, not six.
Furthermore, these examples do not account for the entire process
leading up to operation. Specification, selection, procurement, and
permitting are not discussed in one or both examples. Optimization is
also not taken into account. Reliant Energy, for example, installed LNBs
in May but then spent through September tuning the controls to achieve
performance guarantees.

One of the commenters notes that unit-specific characteristics
distinguish EPA's two examples from its units. The document cited for
Reliant Energy mentions additional boiler modifications that would be
required when burning Powder River Basin coal, which commenter uses in
its units. For the Southern Company units, the retrofit system consisted
of burners only and did not require the design or installation of
overfire air systems, as would commenter's units. The examples were
1990-2001 retrofits, whereas commenter would need to install controls
under different circumstances and at a time when contractor and
equipment availability will be at a premium. Commenter also differs from
EPA's two examples in that it will need to proceed on its units in
phases for demand reliability reasons. For all these reasons, EPA has no
basis for setting a compliance schedule based on two isolated examples
that are not comparable to LNB installation schedules for EGUs in
Oklahoma.

Some commenters also noted in conjunction with these examples cited by
EPA that, contrary to those examples, it is infeasible for WFEC to
install controls by May 1, 2012 that will be necessary to achieve the
emissions reductions required by the proposed unit-specific allowance
allocation for its units. Under the Proposal, WFEC must reduce its
overall emissions by 30 percent. Installation of dry low NOX burners on
Anadarko units 4, 5, and 6 is the quickest and most cost effective way
for WFEC to achieve the required reductions through controls. EPA makes
the unfounded assumption in its technical support documents that low NOX
burners can be purchased, installed, and tuned within 6 months. EPA's
assumption is based on vendor papers developed as marketing tools. These
papers are not an unbiased technical assessment representative of
industry practices. EPA cannot rely on promotional materials to
determine the feasibility of installing controls.

WFEC has solicited bids for low NOX burners from several vendors. Simply
obtaining the equipment will take WFEC between 12 and 18 months. After
WFEC obtains the necessary equipment, there are numerous other factors
that will further delay installation of the controls. First, WFEC must
obtain approval from Southwest Power Pool ("SPP") before it takes the
units offline for an extended outage (it will take approximately six to
eight weeks to install the low NOX burners at each unit). SPP has
members in nine states; eight of those states are affected by either
CSAPR or the Proposal. EGUs in each of these states also will need to
install controls. Second, WFEC must undertake extended outages during
shoulder seasons. Due to increased demand, it cannot shut down a unit
for a significant amount of time during the winter and summer months.
Finally, WFEC must obtain the necessary permits before it begins
installation of the low NOX burners. The permitting process can take
between 12 and 24 months, depending on the potential affect of the
proposed project on emissions. Even if WFEC beings the process of
obtaining the necessary equipment and permits now, it would be
impossible for the company to install controls by the compliance
deadline for the first ozone-season NOX trading program.

Another commenter (GRDA) stated that it must reduce its overall NOX
emissions by over 50 percent. Installation of low NOX burners with over
fire air and computerized combustion controls is the most expedient and
technically established method for GRDA. To implement such a customized
solution requires substantially more time than the six (6) months
allowed by the Proposal. GRDA has carefully studied EPA's explanation of
its decision to allow Oklahoma utilities only six (6) months to
implement multiple and complex NOX reduction projects, and it is
apparent EPA's six month allowance is unreasonable, and not consistent
with EPA's own statement of facts. For example, EPA expressly
acknowledges on page 48281 of the published rule that "historical
projects suggest a more typical schedule would be 12 to 16 months for
the contractors' portion of the work.  A plant owner's project planning
and procurement work in advance of a contract award would typically
involve several additional months."  The coal fired units in Oklahoma
are the primary and most reliable base load providers of electricity.
Of these, nine units totaling over 4,000 megawatts will require design
and installation of customized low NOX burner systems.  The installation
and startup time for such systems is a minimum of several months, and
electric system needs would necessitate that all nine Oklahoma units be
scheduled between March 20 - May 1, 2012.  Successfully mobilizing the
necessary experienced engineers and technicians for installation and
successful startup would be in grave doubt. Industry experience has
clearly shown that tuning of new low NOX systems often takes several
months. GRDA has consulted with a highly experienced engineering firm
(Black & Veatch), and also obtained preliminary conceptual proposals
from vendors of low NOX burner systems. Based on these consultations, an
achievable and prompt implementation schedule for customized and
effective low NOX burner systems in Oklahoma (and GRDA) needs to include
a number of elements totaling 36 months as outlined in a full detailed
list in the commenter’s letter.

Another commenter states that it will need roughly three years from the
date of an appropriate final rule before the required controls can be
installed and operation. This amount of time is typical for the kind of
work required, and other EGUs are likely to be in a similar position.
Therefore, in addition to revising the Supplemental Proposal to set
forth a reasonable degree of emission reductions, the Agency should
allow no less than three years from the date of a final rule for sources
to comply.  [Oklahoma Gas & Electric Company (OGE)
(EPA-HQ-OAR-2009-0491-4590), p. 8-9; Oklahoma Utility Group
(EPA-HQ-OAR-2009-0491-4591), p. 6-7; AES Shady Point
(EPA-HQ-OAR-2009-0491-4595), p. 5; Western Farmers Electric Cooperative
(EPA-HQ-OAR-2009-0491-4589), p. 10-11; Grand River Dam Authority
("GRDA") (EPA-HQ-OAR-2009-0491-4586), p. 6-8.]

RESPONSE:  See the preamble of final supplemental rule, section
III.B.iv.  Also see the preamble to the final Transport Rule, section
VII.C.2 and the "Transport Rule Engineering Feasibility Response to
Comments" document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:  EPA's claim of two (2) low NOX burner projects requiring only
six (6) months is incorrectly assessed and should not be utilized for
the following reasons:

In the case cited by EPA (subscript 62) by Riley Power, this project
only included low NOX burners, and was specifically implemented without
the use of overfire air (OFA) or burner sizing changes. The actual NOX
emissions attained after this example project was only a pitiful .36
lb/MMBtu. In the case of GRDA, this .36 level is already surpassed and
GRDA must achieve a reduction to approximately 0.16 lb/MMBtu to meet
Proposal allowances. Clearly, much more sophisticated, and customized,
burner technology systems will be needed than this EPA example. Lastly,
this "paper" cited by EPA was obviously written by the vendor as a sales
promotional tool. This "paper" should not be relied on by EPA as
representing an independent and impartial assessment of the facts, and a
basis for issuing enforceable regulations.

In the case cited by EPA (subscript 63) by Foster Wheeler, this "paper"
is again obviously a sales promotional tool, and should not be relied on
by EPA as representing an independent and impartial assessment of the
facts, and a primary basis for establishing enforceable regulations. The
paper claims 16 weeks to engineer and fabricate low NOX burners, and 7
weeks to install them. However, no facts are presented that demonstrated
the project only took six months total and no mention was made of how
this base load unit was scheduled for its nearly two month outage. In
addition, the paper states "The system was fully operational in May of
2000 and was tuned by September to consistently achieve a NOX
performance guarantee". This statement positively shows an additional
four months were needed to actually get burners to work properly, which
is not unusual for low NOX systems. The "paper" states the design was
simply copied from a similar Foster Wheeler design and it is therefore
clear the engineering time was minimal. The paper states the burners
were for tangential style burners which are known to be easier to
achieve results than those at GRDA. Clearly, this case does not warrant
EPA establishing a six (6) month implementation regulation for the
Oklahoma base load coal units.  [Grand River Dam Authority ("GRDA")
(EPA-HQ-OAR-2009-0491-4586), p. 6-7.]

RESPONSE:  EPA is not basing this final rule’s 2012 state budget for
Oklahoma on the installation of new combustion controls by that control
period.  See the preamble of final supplemental rule, section III.B.iv.
Also see the preamble to the final Transport Rule, section VII.C.2 and
the "Transport Rule Engineering Feasibility Response to Comments"
document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.  In addition, sources in
four of the states covered by this final rule (Iowa, Michigan, Missouri,
and Wisconsin) are already covered by the final Transport Rule’s
annual NOX program, which was finalized almost a year in advance of the
2012 ozone season; these sources should have already begun implementing
any desired NOX combustion controls well before finalization of this
rule.

Comment:  EPA'S referenced Technical Support Document (TSD)
"Installation Timing for Low NOX Burners (LNB)” states that EPA
"analyzed" the installation of NOX burners on 30 boilers in the four
affected states that are not in CAIR, with Oklahoma being one of these
four states.  This TSD is defective in several aspects.  First of all,
the TSD assumes the proposal will be finalized in June 2011 and burner
modifications will be performed during fall of 2011 and spring of 2012.
However, the Proposal final rule is now planned for October 2011.  The
TSD was not updated to consider this four month delay of the rule. No
implementation of low NOX burners can be done in the fall of 2011 which
means all 30 boilers must be modified in the spring of 2012.  These 30
boilers are the primary base load electric generators for the involved
utilities. In particular, taking out the affected boilers in Oklahoma,
Kansas and Nebraska at the same time would be irresponsible and
threatens public safety and health.  EPA could have learned this with a
few simple phone calls, but no evidence is included this was done.  EPA
has apparently instead relied on a single telephone discussion with a
vendor, and two sales promotion "papers" issued by vendors.  No apparent
effort was made to obtain independent and non-biased assessment from a
competent engineering firm. There is no evidence that EPA contacted
utilities, the Southwest Power Pool or NERC. As such, EPA has failed to
meet its required consideration of such impacts on the electric energy
system. Secondly, the referenced paper by Foster Wheeler contains no
statement the entire project was done in a total of six months. In fact,
the paper admits that tuning to meet burner guarantees took four months
(during the critical summer months). Thirdly, both referenced examples
were clearly non-typical situations where minimal boiler modifications
and engineering was performed. EPA should not base their rule making on
such non-typical examples. Fourthly, EPA's overly "aggressive" six month
schedule will prevent GRDA and other Oklahoma utilities from obtaining
competitive and fair pricing, and is therefore not in the public
interest. Vendors will be able to charge exorbitant prices, overtime and
support fees. GRDA's ability to negotiate NOX performance guarantees
will be impaired and this is not in the public interest.

In summary, GRDA strongly objects to the six (6) month implementation
and requests EPA to utilize the 36 month implementation schedule
described earlier.  [Grand River Dam Authority ("GRDA")
(EPA-HQ-OAR-2009-0491-4586), p. 7-8.]

RESPONSE:  EPA is not basing this final rule’s 2012 state ozone season
budget for Oklahoma on the installation of new combustion controls by
that control period.  See the preamble of final supplemental rule,
section III.B.iv.  Also see the preamble to the final Transport Rule,
section VII.C.2 and the "Transport Rule Engineering Feasibility Response
to Comments" document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:  Even if EPA retains the allowance budget that is currently
proposed for Oklahoma, an initial compliance deadline of May 1, 2012 is
not reasonable and must be revised. The Agency should allow no less than
three years for utilities to evaluate generating options, obtain
allowances, arrange for the purchase of replacement power where
possible, and install controls to achieve the actual emission reductions
that will drive the trading program in Oklahoma.

Commenters state that a compliance schedule of three years is especially
appropriate in light of the fact that Oklahoma was not included in CAIR
and has relatively tenuous modeled impacts compared to other states. As
evidenced by the shifts in EPA's modeling and emission budgets for
Oklahoma over the years, affected sources in the State have faced
significant uncertainty regarding whether, and to what extent, they
would be subject to interstate transport requirements. This uncertainty
translated into Oklahoma sources having less notice of the requirements
than sources in other states.

One of the commenters also argues that EPA should consider that capital
expenditures for environmental controls cannot be included in customer
rates until state regulatory agencies authorize cost recovery. The
commenter notes that controls were not going to be necessary for its
units based on the 2010 Proposed Rule. As a final alternative, if EPA
retains the allowance budget and the May 1, 2012 deadline in the
Supplemental Proposal, EPA should at the very least delay application of
the assurance provisions until 2014 so that interstate trading can
provide more allowances to Oklahoma EGUs while the markets for instate
allowances develop. Otherwise, if faced with inadequate lead time for
installing controls and a shortfall of emission allowances, commenter
and other electric utilities would be forced to curtail operations to
avoid noncompliance with CSAPR. As noted, the commenter's coal-fired
units could need to curtail operations by roughly 50% during the ozone
season, compared to their operations in 2010, if sufficient allowances
are not available. EPA has not provided an adequate assessment of the
impacts on electric reliability from this level of curtailment.
[Oklahoma Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p.
10; Oklahoma Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 7.]

RESPONSE:  EPA has proposed to adjust the effective date of the
Transport Rule assurance provisions in a separate rulemaking (see 76 FR
63860, October 14, 2011).  EPA believes that this final rule’s 2012
state budget for Oklahoma represents feasible emission reductions in
that timeframe (see section III.B.iv of the preamble to this final
rule).  The Transport Rule does not apply unit-specific requirements,
thus provides flexibility for compliance across units with various
control capacities.  See comments in other areas of this Response to
Comment document regarding EPA’s assessment of current and future
market liquidity and allowance availability based on current reports
from the market place.

Comment:  The timeline for compliance with the rule’s requirements is
not realistic. The final rule (published in the Federal Register on
August 8, 2011) establishes a compliance schedule for both the PM-2.5
and ozone portions of the rule that makes sense only for those states
that were previously covered by the Clean Air Interstate Rule (CAIR).
The final CAIR was published in March of 2005, allowing utilities owning
or operating units subject to the rule years to come into compliance
with the cap-and-trade system set up by the rule. Key components of any
successful market-based program include (1) sending clear signals to the
market regarding the number of allowances which will be issued and (2)
allowing the companies owning and operating units subject to the rule
sufficient time to plan for future needs. DEQ recognizes that the
vacatur and associated holding by the Court of Appeals for the District
of Columbia Circuit put the EPA in a position which necessitated that
EPA set the compliance date for states already covered by CAIR such that
there would be no gap between compliance with CAIR and compliance with
CSAPR. DEQ appreciates that this was needed to retain the reductions in
emissions associated with the installation of new controls and other
changes required by CAIR. A seamless transition from CAIR to CSAPR makes
sense for facilities located in those states; however there is no
similar justification for the short time period between the issuance of
the final rule and the requirements for compliance for states like
Oklahoma that were not part of CAIR. Based on the state budgets
announced in the Proposed Transport rule, it appeared that EPA was
taking those concerns into account by establishing budgets that could
realistically be achieved by the non-CAIR states in general and Oklahoma
in particular.

However, if the SNPR is finalized by the target date of October 1, 2011,
that will only allow utilities seven months to plan, acquire capital,
design, and install the control systems that will be required to allow
those units to operate in compliance with the rule. Even the EPA’s own
Technical Support Document (TSD), “Installation Timing for Low NOX
Burners,” (issued July 2010), assumes that there are only 30 boilers
located in the four states not already covered by CAIR and that
utilities would be able to install low NOX burners on those boilers if
EPA was able to finalize the rule by June 2011. EPA has missed that
target. The rule covering the six states (including Oklahoma) will not
likely be finalized until October of 2011; therefore, even EPA’s own
documents show the false premises upon which the assumption of a smooth
transition to compliance with CSAPR were constructed.

For Oklahoma utilities who were first excluded from CAIR and then led to
believe based on the allowances in the proposed Transport Rule that
compliance could reasonably be achieved, seven months is not enough time
to accomplish the required measures based on the new timeline and new
allowances in the SNPR. First, before installation can even begin,
utilities will have to have the capital expenditures approved, get
designs in place, and obtain the required permits. If PSD is triggered,
permit issuance could possibly take 9-12 months, 3-6 months if PSD is
not triggered. Secondly, Oklahoma utilities must obtain permission from
the Southwest Power Pool to undertake the substantial downtimes that
will be required to install control equipment (upwards of 40-50 days).
Based on power demand and the short timeline, brown-outs could very
likely occur.

The pace and aggressiveness of these environmental regulations should be
adjusted to reflect and consider the overall risk to the bulk power
system. EPA, FERC, DOE, and state utility regulators, both together and
separately, should employ the array of tools at their disposal to
moderate reliability impacts, including, among other things, granting
required extensions to install emission controls.  [Oklahoma Department
of Environmental Quality (EPA-HQ-OAR-2009-0491-4593), p. 2-3.]

RESPONSE:  See the preamble of final supplemental rule, section
III.B.iv.  Also see the preamble to the final Transport Rule, section
VII.C.2 and the "Transport Rule Engineering Feasibility Response to
Comments" document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:  Agency commenter calculates that utilities operating in
Oklahoma will need to retrofit 43 individual combustion units with
low-NOX burners to comply with the requirements of the new rule. This
number is substantially larger than the 30 units in a four-state area
predicted in EPA’s TSD, “Installation Timing for Low NOX Burners
(LNB).” To remedy these failings, agency recommends that the
compliance date for units operating in Oklahoma be pushed back to the
2015 ozone season. We believe that our request for a minimum of a
three-year extension of the compliance date is justified for four
reasons: (1) that is the minimum time necessary between issuance of the
final rule (which will set the allowance budget) and the time the
utilities will need to be able to plan for compliance with the rule –
this is an essential component of any market-based approach, (2) the
failure of the EPA to abide by the assumptions identified in their own
TSD regarding the time required to install low-NOX burners, (3) the
large number of units (43) that will need to be retrofitted in Oklahoma
and the burden that will place on engineers, equipment suppliers, and
the utilities, and (4) the need to allow for utilities to apply for PSD
permits as well as the time required to evaluate and draft the permits
and that needed for the public and EPA to review them.  [Oklahoma
Department of Environmental Quality (EPA-HQ-OAR-2009-0491-4593), p.
4-5.]

RESPONSE:  See the preamble of final supplemental rulemaking, section
III.B.iv.  Also see the preamble to the final Transport Rule, section
VII.C.2 and the "Transport Rule Engineering Feasibility Response to
Comments" document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  The Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:  Should the EPA proceed with this rule making I would request
that Oklahoma be granted a more reasonable implementation timeline.
Because we are so close to the effective date, it will be impossible for
Oklahoma sources to comply and be fitted in time with the appropriate
emission controls, which require custom design, engineering, and
installation specific to each source. With an unrealistic implementation
timeline such as the one proposed, the reliability of electrical
generation in the state of Oklahoma and the livelihood of many
Oklahomans is at stake.  [Governor, State of Oklahoma
(EPA-HQ-OAR-2009-0491-4594), p. 1.]

RESPONSE:  See the preamble of final supplemental rulemaking, section
III.B.iv.  In addition, note that the Transport Rule does not apply
unit-specific requirements, thus provides flexibility for compliance
across units with various control capacities.

Comment:  Our preliminary review of the proposed rule and the supporting
documentation brings us to the same conclusion for both the final rule
and the proposed supplemental rule, which is there is insufficient time
for Kansas utilities to comply with either rule.  Of the 28 states that
will be subject to the Cross State Air Pollution rule (CSAPR) starting
in 2012, all but three were subject to the Clean Air Interstate Rule
(CAIR) prior to CSAPR. The three non-CAIR states are Kansas, Nebraska,
and Oklahoma. CAIR states have had several years to prepare plans,
obtain construction permits, and commence or complete construction of
projects to reduce emission of nitrogen oxides and sulfur dioxide. Until
very recently, Kansas and the other non-CAIR states have shared
uncertainty with respect to interstate transport and future control
requirements. Kansas finds itself at a disadvantage, when compared to
the CAIR states, when faced with a 2012 compliance deadline. In section
VII C. 2. of the CSAPR preamble (76 FR 48279), EPA states:

"In 2012, the industry will largely meet the rule's NOX requirements by:
Operating an extensive existing set of combustion and post-combustion
controls on fossil fuel-fired generators; dispatching lower emitting
units more often; and installing and operating a limited amount of
relatively simple NOX pollution controls in states not previously
subject to CAIR."

EPA acknowledges that utilities in non-CAIR states likely will need to
install "relatively simple NOX pollution controls," such as low-NOX
burners and overfire air, to meet the state emissions budget for 2012.
EPA further posted a NOX cost threshold of$500 per ton for states under
the Cross-State Air Pollution Rule. Installing combustion NOX pollution
controls is not a simple task and cannot be completed in the six months
time frame the proposed rule would allow. We have current real world
costs for installation of such controls and they are higher than the
$500 cost threshold. The rush for Kansas utilities to comply with a 2012
deadline will result in increased costs and the potential for stranded
investments resulting from interim measures or "temporary fixes." For a
utility to install low NOX burners, a prevention of significant
deterioration (PSD) permit generally will be required due to an increase
in carbon monoxide emissions. The PSD construction permitting process
alone would normally take more than five months. It is highly unlikely
that Kansas utilities will be able to install controls and meet the
state's emissions budget for 2012.

Many Kansas facilities are in the planning stages for installation of
additional controls to be completed between 2012 and 2015, and have
received permits or have applications in process. Emission reductions
from approved projects now underway and in 2012 will reduce over 14,000
tons of NOX and 18,133 tons of SO2. Once these controls are in place,
the State of Kansas should be able to meet the assurance levels
established in the Cross State Rule. Kansas needs the time for these
plans to be put in place to comply with the proposed rule. We believe
that the assumptions made by EPA in terms of cost of compliance and
ability to complete pollution control projects in time for the 2012
ozone season are fundamentally flawed and therefore do not accurately
reflect the actual impacts the proposed rule will have on the Kansas
economy. We formally request that EPA provide the State of Kansas and
its affected utilities two additional years to comply with the
provisions of the proposed supplemental Cross-State Air Pollution Rule.
[Kansas Department of Health & Environment (EPA-HQ-OAR-2009-0491-4582),
p. 2.]

RESPONSE:  See the preamble of final supplemental rule, section III.C
regarding the status of Kansas in the final rule.  Also see the preamble
for the final Transport Rule, section VII.C.2 and the "Transport Rule
Engineering Feasibility Response to Comments" document in the docket to
this rulemaking (Docket ID No. EPA–HQ–OAR–2009–0491) regarding
timing and feasibility of controls installation.  Note that the
Transport Rule does not apply unit-specific requirements, thus provides
flexibility for compliance across units with various control capacities.

Comment:  PSO and AEP believe that if these states are required to
reduce emissions, the level of reductions and the schedule for the
emission reductions can and should be relaxed. There is no immediate
need associated with potential health impacts since the Michigan County
at issue is already in attainment and predicted to remain in attainment.
 This clearly illustrates that there is no need to rush the emission
reductions EPA proposed for 2012. The proposed time schedule for
emission reductions will greatly impact the availability of existing
generating sources in these states by requiring controls be added prior
to the 2012 ozone season. Very few units will be able to install
controls in order to comply with the 2012 ozone season and generation
may not be available during high demand periods. Given the uncertain
availability of NOX allowances and the compliance risk associated with
utilizing allowances above the assurance level, sources will likely
curtail operation to achieve compliance. The result could be either
insufficient generating capacity to meet load demands during peak summer
conditions and/or much higher prices for power purchases during these
periods which will significantly impact customer costs. We are also
uncertain of the availability and price of NOX allowances for the 2012
ozone season.  We expect the State as a whole to require allowances
greater than the 21% assurance level above the state budget which will
add an undue burden on the rate payers of Oklahoma.  By extending the
compliance dates by 2-years or more, the industry would have time to
properly plan and install any needed controls in Oklahoma and other
states.  [Public Service Company of Oklahoma
(EPA-HQ-OAR-2009-0491-4600), p. 3-4.]

RESPONSE:  See section III.B.iv in the preamble to the final
supplemental rule.  Also, see the preamble of final Transport Rule,
section VII.C.2 and the "Transport Rule Engineering Feasibility Response
to Comments" document in the docket to this rulemaking (Docket ID No.
EPA–HQ–OAR–2009–0491).  Note in addition that the Transport Rule
does not apply unit-specific requirements, thus provides flexibility for
compliance across units with various control capacities.

(C)  Commenter(s) disagree with statement that ability to purchase
allowances helps address concerns over compliance timetable.

Comment:  EPA recognizes in the Supplemental Proposal that some sources
will need more than six months to procure, permit and install combustion
controls. In this situation, EPA says that sources may comply through
the purchase of additional allowances. Commenters have not been able to
identify how sufficient allowances could be available in Oklahoma while
still allowing EGUs to meet consumer demand. They believe there will be
a shortfall of allowances, especially during the 2012 ozone season. With
no system of information available with which to discern allowances and
their pricing, commenters assert that more time is needed before the
start of CSAPR in order to appropriately manage the supply (and cost) of
allowances available for purchase.

Table A in the comments shows that a reduction of close to 13,000 tons,
or roughly 40%, from actual 2010 state-wide NO, emissions would be
needed in order to make sufficient in-state allowances available to EGUs
in Oklahoma. The group of commenters represents roughly 80% of the
generating capacity in the State of Oklahoma and, as noted, will be
unable to install controls by May 2012. The group of commenters would
need to purchase roughly 16,000 tons of ozone season NOX allowances
prior to that date.  One of the commenters states that it will have to
purchase up to 6,000 allowances, mostly from EGUs that make up the other
50% of the State's generating capacity. Those other units, however,
would themselves be required to reduce (or obtain allowances for) an
additional 7,000 tons or so of NOX emissions. Because many of these
units will be unable to reduce emissions in less than six months time,
there is not likely to be a sufficient supply of in-state allowances
available for purchase in the early days of CSAPR in Oklahoma.

Moreover, even if some units reduce emissions in 2012, they could choose
to bank rather than sell their allowances in light of EPA's stated
intent to promulgate further interstate transport requirements in the
future. Allowances that are available for purchase are likely to be at a
premium price. While commenters agree that allowance banking is a
cost-effective and important feature of any emissions trading program,
EPA should recognize that banking also can lead to an allowance
shortfall (and high prices) at the beginning of a trading program when
drastic emission reductions are required without sufficient time to
install controls, and further, unspecified reductions are likely to be
required in the future.

Interstate trading will be of limited use to commenters and other
utilities that must obtain thousands of allowances at the start of the
CSAPR program, if EPA applies the assurance provisions starting in 2012.
The assurance provisions would mean that interstate trading could
provide no more than 4,585 tons of ozone season NOX allowances (i.e. the
variability limit) to EGUs in Oklahoma during 2012, or else penalties
would be imposed on the State and its sources. One of the commenters
notes that it alone will require more allowances than interstate trading
could provide.

Given the lack of sufficient allowances, EPA should revise the
Supplemental Proposal to allow a reasonable allowance budget. Once a
reasonable budget is established, utilities will need at least three
years from the date of a final rule to comply, which is the amount of
time needed to install controls for achieving actual emission
reductions. One of the commenters notes here, echoing similar remarks
summarized above, that EPA should at the very least delay application of
the assurance provisions until 2014 so that interstate trading can
provide more allowances to Oklahoma EGUs while the markets for instate
allowances develop. Otherwise, if faced with inadequate lead time for
installing controls and a shortfall of emission allowances, commenter
would be forced to curtail operations to avoid noncompliance with CSAPR.
EPA has not provided an adequate assessment of the impacts on electric
reliability from this level of curtailment.  [Oklahoma Gas & Electric
Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 9-10; Oklahoma Utility
Group (EPA-HQ-OAR-2009-0491-4591), p. 7.]

RESPONSE:  Market liquidity is already developing in the Transport Rule
(TR) emission markets, including in the ozone season NOX market relevant
to this rule. Facilities have been trading allowances since EPA formally
recorded 2012 Transport Rule allowances into designated facility
accounts on October 18, 2011.  In fact, several trades of Transport
Rule allowances took place prior to the formal distribution of
allowances. Initial transactions have been followed by further trades
and options contracts in all of the trading programs.

Further, on Thursday, November 17, 2011, First Energy held a successful
auction of a minimum of a 100,000 SO2 allowances, 50,000 each from 2012
and 2013 markets, along with an undisclosed amount of annual and ozone
season NOX allowances. This auction is a significant injection of
liquidity into the market by a single entity, further indicating that a
sufficient numbers of allowances will be available to meet the needs of
sources.  They are planning to hold another auction on April 30, 2012.

Market liquidity has developed rapidly in all of the previous emission
trading programs that EPA has implemented, including the Acid Rain
Trading Program, the NOX SIP Call, the NOX Budget Program, and most
recently CAIR, the predecessor to the Transport Rule.  In both CAIR and
the Transport Rule, individual units have the flexibility to supplement
their own allowance allocations with the acquisition from the
marketplace of any additional allowances needed to cover emissions under
the Transport Rule programs.  Healthy markets for the CAIR annual NOX,
CAIR ozone-season NOX, and Acid Rain (SO2) program allowances have been
in existence for many years and delivered compliance costs below EPA’s
estimates.  Further, as mentioned, trades have already taken place for
allowances in the seasonal NOX market and other TR markets in
anticipation of program implementation.  Also see “Sam Napolitano
Omnibus Declaration” in the docket to this final rulemaking.

EPA is addressing the timing of the assurance provisions in a separate
rulemaking (76 FR 63860, October 14, 2011).

Comment:  EPA says in the Supplemental Proposal that individual sources
may comply through the purchase of additional allowances in the event
that it takes a particular source more than six (6) months to install
combustion controls. EPA fails to acknowledge the potential for
allowance shortfalls, especially leading up to the proposed 2012
compliance deadline.  EPA allowance allocation shows that a 37.5%
reduction in actual state-wide NOX emissions are needed for sufficient
in-state allowances to be available. EPA has not suggested any means for
achieving this sort of reduction in the few short months before the
beginning of the 2012 ozone season.

Interstate trading is limited by assurance provisions that restrict EGU
emissions within each state to the state's budget plus the variability
limit. The number representing a state's budget + variability limit is
referred to as the "assurance level." For Oklahoma, the assurance level
in 2012 for ozone season NOX from EGUs is 21,835 (budget) + 4,585
(variability limit) = 26,420. The purchase of allowances by individual
sources cannot authorize the state to go above 26,420 tons of ozone
season NOX emissions.  Otherwise, penalties will be imposed on the state
and its sources. Note that EPA originally proposed to apply the
assurance provisions starting in 2014, but the final rule implements the
provisions starting in 2012. Commenters favor a 2014 start date for
assurance provisions.

If faced with inadequate lead time for installing controls and a
shortfall of emission allowances, utilities would be forced to shut down
some units or curtail their operation to avoid noncompliance with CSAP
program requirements. If curtailment becomes necessary for CSAP
compliance, the only other alternative to serve customers is to purchase
power from out-of state generators. It is unknown if sufficient
additional generating capacity will be available from units within the
Southwest Power Pool. Additionally power which is available to be
supplied by the Southwest Power Pool would increase NOX emissions in the
generating state as well. [AES Shady Point (EPA-HQ-OAR-2009-0491-4595),
p. 5-6.]

RESPONSE:  Market liquidity is already developing in the Transport Rule
(TR) emission markets, including in the ozone season NOX market relevant
to this rule. Facilities have been trading allowances since EPA formally
recorded 2012 Transport Rule allowances into designated facility
accounts on October 18, 2011.  In fact, several trades of Transport
Rule allowances took place prior to the formal distribution of
allowances. Initial transactions have been followed by further trades
and options contracts in all of the trading programs.

Further, on Thursday, November 17, 2011, First Energy held a successful
auction of a minimum of a 100,000 SO2 allowances, 50,000 each from 2012
and 2013 markets, along with an undisclosed amount of annual and ozone
season NOX allowances. This auction is a significant injection of
liquidity into the market by a single entity, further indicating that a
sufficient numbers of allowances will be available to meet the needs of
sources.  They are planning to hold another auction on April 30, 2012.

Market liquidity has developed rapidly in all of the previous emission
trading programs that EPA has implemented, including the Acid Rain
Trading Program, the NOX SIP Call, the NOX Budget Program, and most
recently CAIR, the predecessor to the Transport Rule.  In both CAIR and
the Transport Rule, individual units have the flexibility to supplement
their own allowance allocations with the acquisition from the
marketplace of any additional allowances needed to cover emissions under
the Transport Rule programs.  Healthy markets for the CAIR annual NOX,
CAIR ozone-season NOX, and Acid Rain (SO2) program allowances have been
in existence for many years and delivered compliance costs below EPA’s
estimates.  Further, as mentioned, trades have already taken place for
allowances in the seasonal NOX market and other TR markets in
anticipation of program implementation.

EPA is addressing the timing of the assurance provisions in a separate
rulemaking (76 FR 63860, October 14, 2011.

Comment:  It is equally infeasible for WFEC to comply with the required
emissions reduction by purchasing allowances. EPA anticipates that EGUs
that cannot install controls by the compliance deadline will avoid
violating the regulatory program by purchasing allowances. However,
EPA's expectations for the liquidity of the allowance market are greatly
inflated. ODEQ analyzed the state emissions budget information provided
by EPA in its technical support documents for CSAPR and determined that,
of the 26 states included in the ozone season NOX trading program, only
five states are predicted to have excess allowances. See ODEQ Analysis,
Attached. None of these states are in the SPP. The remaining states are
expected to have allowance shortfalls that range between 4.5 and 42
percent. ld.

Accordingly, the Proposal would place WFEC in the untenable position of
having to choose between violating the requirements of the program or
derating or shutting down units. Derating or shutting down units would
jeopardize WFEC's ability to fulfill its contractual obligation to
supply power to the cooperatives it serves and ultimately to their
retail, residential, commercial and industrial consumers. WFEC currently
relies on some bilateral and market purchases to satisfy its
obligations. If WFEC is forced to derate its EGUs to avoid violating
CSAPR, it will need to significantly increase its power purchases. WFEC
is concerned that if the Proposal is finalized, it will be unable to
purchase sufficient power to cover the shortfall in generation. Eight of
the nine states in the SPP are affected by either CSAPR or the Proposal
and, thus, are unlikely to generate excess power for sale. Derating or
shutting down units also would pose a significant risk to the public
health and welfare. The cooperatives served by WFEC do not have access
to other sources of power. If WFEC cannot respond to demand, the rural
areas served by the cooperatives will experience potentially dangerous
brownouts and blackouts. 16 WFEC urges EPA to seek additional
information from SPP regarding the potential affect of the Proposal on
reliability before issuing a final rule.

GRDA has studied the NOX allowances for EGU's under the Proposal and is
deeply concerned that sufficient NOX allowance will not be available in
2012 and that Oklahoma utilities will be gouged exorbitant millions of
dollars to purchase allowances from eastern utilities which have had
ample opportunity to accumulate such NOX allowances. To force Oklahoma
utilities like GRDA to transfer many millions of dollars of wealth is
patently unfair and serves no environmental benefit. GRDA estimates that
its public power customers will express great outrage if such a wealth
transfer was forced on them. Again, GRDA urges EPA to reconsider the
Proposal schedule and allow a minimum of 36 months for implementation by
Oklahoma EGU's.  [Grand River Dam Authority ("GRDA")
(EPA-HQ-OAR-2009-0491-4586), p. 5-6]

RESPONSE: Market liquidity is already developing in the Transport Rule
(TR) emission markets, including in the ozone season NOX market relevant
to this rule. Facilities have been trading allowances since EPA formally
recorded 2012 Transport Rule allowances into designated facility
accounts on October 18, 2011.  In fact, several trades of Transport
Rule allowances took place prior to the formal distribution of
allowances. Initial transactions have been followed by further trades
and options contracts in all of the trading programs.

Further, on Thursday, November 17, 2011, First Energy held a successful
auction of a minimum of a 100,000 SO2 allowances, 50,000 each from 2012
and 2013 markets, along with an undisclosed amount of annual and ozone
season NOX allowances. This auction is a significant injection of
liquidity into the market by a single entity, further indicating that a
sufficient numbers of allowances will be available to meet the needs of
sources.  They are planning to hold another auction on April 30, 2012.

Market liquidity has developed rapidly in all of the previous emission
trading programs that EPA has implemented, including the Acid Rain
Trading Program, the NOX SIP Call, the NOX Budget Program, and most
recently CAIR, the predecessor to the Transport Rule.  In both CAIR and
the Transport Rule, individual units have the flexibility to supplement
their own allowance allocations with the acquisition from the
marketplace of any additional allowances needed to cover emissions under
the Transport Rule programs.  Healthy markets for the CAIR annual NOX,
CAIR ozone-season NOX, and Acid Rain (SO2) program allowances have been
in existence for many years and delivered compliance costs below EPA’s
estimates.  Further, as mentioned, trades have already taken place for
allowances in the seasonal NOX market and other TR markets in
anticipation of program implementation.

EPA is addressing the timing of the assurance provisions in a separate
rulemaking (76 FR 63860, October 14, 2011.

Comment:  EPA indicates that, “Individual sources may comply through
other measures (such as purchasing additional allowances) in the event
that it takes a particular source more than six months for installation
of a given combustion control.” See 76 Fed. Reg. 40668, Section I(E).
KCP&L does not agree with this statement. For example, KCP&L operates
the La Cygne Generating Station in Kansas. This Station is the only
coal-fired units operated by KCP&L in Kansas. The proposed 2012 ozone
season allowance allocation shortfall is substantially greater than the
Station’s share of the Kansas variability limit.  So even if KCP&L was
able to procure allowances to cover its shortfall at the Station, it
would be exceeding its share of the Kansas variability limit.  This puts
KCP&L at risk of a significant penalty if the state exceeds it assurance
level even though KCP&L La Cygne Generating Station had allowances to
cover its emissions. See 76 Fed. Reg. 48296.  This risk of penalty
illustrates that EPA’s statement that the sources may purchase
additional allowances is not a viable option to comply with our
allowance shortfall at the Station.  [Kansas City Power & Light
(EPA-HQ-OAR-2009-0491-4584), p. 2-3.]

RESPONSE:  EPA is not finalizing the FIP for Kansas at this time.  See
the preamble to the final supplemental, section III.C, for a discussion
on Kansas’ current status.

(D) The rule presents reliability concerns.

Comment:  In order to provide electrical service to our customers Empire
District must maintain system reliability. Considering the severe
shortage of allowances that will be available for purchase in 2012,
sources that do not receive sufficient allocations permitting them to
operate normally must install pollution control equipment. And given the
fact that sources will not have enough time to install the proper
pollution control equipment before January 1, 2012, to meet customer
electrical demand will be forced to de-rate the unit(s) in order to
comply with these rules. This will have an effect on system reliability.
[Empire District Electric Company (EPA-HQ-OAR-2009-0491-4581), p. 2.]

RESPONSE:  EPA rejects the commenter’s assertion that there will be no
allowances available to purchase in 2012.  As explained above, ample
evidence already exists that viable allowance markets for Transport Rule
compliance are already developing and trading has already begun.
Furthermore, sources have the benefit of accessing the allowance market
not just ahead of the commencement of the programs, but also over the
entire time horizon ahead of the allowance transfer deadlines by which
sources must demonstrate compliance (December 1, 2012 for the 2012 ozone
season and March 1, 2013 for the annual programs in 2012).  As a result,
the Transport Rule offers substantial unit-level flexibility that will
allow sources to continue to meet whatever obligations they may have
concerning electric reliability.  See also “Sam Napolitano Omnibus
Declaration” in the docket to this rulemaking.

Comment:  The Attorney General is also concerned about the effect of
compliance upon the availability of electricity and the reliability of
the grid in this region. To the knowledge of the Attorney General, there
has been no complete or formal electric reliability assessment in
cooperation with FERC for the CSAP Program, either alone or in
combination with EPA's other proposed rules. FERC's informal analysis
regarding the CSAP Program indicates that over 80 gigawatts of
coal-fired generation may be retired in response to EPA regulations.
Instead of obtaining a complete reliability assessment from FERC, EPA
instead relied upon emission projections and analyses developed using
its Integrated Planning Model ("IPM"). However, a major limitation of
the IPM model is that it assumes adequate transmission capacity exists
to deliver any resource located in, or transferred to, the region in
question and thereby fails to accurately evaluate impacts on reliability
resulting from EPA programs such as CSAP, or combinations of EPA
programs. The Attorney General is concerned that deficiencies in the IPM
modeling could result in a shortage of replacement purchased power
during the times in which either generating units are down or usage is
curtailed due to efforts to comply with CSAP or other EPA rules.
Electricity shortages could also result from the inability of utilities
to timely obtain needed permits and control equipment. Oklahoma electric
utilities doubt that they can take the measures required to attain
compliance with CSAP Rules within the six-month time frame currently
allowed by EPA. Instead, they estimate needing twelve to eighteen months
to acquire all necessary permits and equipment is given, with a total of
twenty-one months estimated for the controls to be operational. Failure
to obtain needed permits and control equipment by May 2012 would result
in the utilities' de-rating its non-compliant generating units to a
point necessary to comply with ozone standards, meaning each of those
units would be operating at far less than its rated capacity. As a
result, uncertainty currently exists regarding the availability and
price of purchased power, even assuming adequate transmission
capabilities, due to the widespread imposition of CSAP requirements
across many states. [Oklahoma Attorney General
(EPA-HQ-OAR-2009-0491-4592), p. 2-3.]

RESPONSE:  The commenter erroneously attributes “FERC’s informal
analysis” of 80 GW of potential retirements to the Transport Rule,
while in reality the commenter is citing a preliminary FERC estimate
that was based on a wide spectrum of several regulations, many of which
had not even been proposed, and about which FERC made highly
conservative assumptions about stringency of required controls that were
not borne out by the rules as they were subsequently proposed.  FERC’s
own chairman has emphasized that FERC staff had to make assumptions
about EPA regulations before they were proposed and that these
regulations have changed , has characterized this document as only “an
adequate back-of-the-envelope first assessment” and has stated that it
“cannot be relied on to determine specific effects on system
reliability.  Therefore, it  is “inadequate to use as a basis for
decision making.”    EPA disagrees with the commenter’s unsupported
allegation that its analysis, included in the final Transport Rule,
“fails to accurately evaluate impacts on reliability.”  EPA’s
modeling includes interregional transmission limitations based on
parameters published by the North American Electric Reliability
Corporation, and those modeling assumptions were subject to public
comment in the Transport Rule proposal as well as that rule’s IPM
NODA.  As explained in section III.B.iv of this rule’s preamble, as
well as in the Determination of State Budgets for the Final Ozone Season
Supplemental of the Transport Rule” TSD in the docket to this final
rule, EPA has carefully examined the feasibility of emission reductions
required for Oklahoma under this final rule, and EPA’s analyses show
that the Transport Rule does not threaten the availability or
reliability of electricity for Oklahoma’s citizens.

(E)  A more complete electric reliability assessment is needed for
Oklahoma and the surrounding region.

Comment:  EPA has yet to provide an appropriate electric reliability
assessment for the CSAPR and EPA's other rulemaking initiatives for the
electric power sector. Requiring compliance with the Supplemental
Proposal by May 2012 without a more complete assessment of reliability
would create an unacceptable risk, especially if 2012 brings weather
patterns similar to those experienced in Oklahoma this year.
Commenters’ generating resources are currently operating at maximum
capacity to meet consumer demands during a record-breaking heat wave. A
more complete reliability assessment is critically important to evaluate
whether Oklahoma EGUs could meet these kinds of demands if curtailments
were required as a result of EPA rules.

According to the Federal Electric Reliability Commission ("FERC"), "the
appropriate vehicles for addressing the impact on electric reliability
of the EPA rules in detail are the planning processes used by utilities
to identify and plan for the infrastructure and resources they will need
to meet future needs." The processes FERC is referring to are
implemented by regional planning authorities, including the Southwest
Power Pool ("SPP") for the States of Arkansas, Kansas, Louisiana,
Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas. EPA
should coordinate with FERC and the SPP to prepare a more complete
electric reliability assessment for the implementation of CSAPR and
other major EPA rulemakings in Oklahoma.

In response to comments submitted on the final CSAPR, EPA claims that it
has "been in contact" with many of the regional planning authorities
concerning the impact of CSAPR on electric reliability. EPA does not
elaborate on its consultations with the SPP or other regional
authorities, but instead relies on the fact that regional authorities
"have not filed comments or expressed concerns over reliability in the
record for this rule. . . .  EPA's response misses the point. Numerous
entities have expressed concern over the lack of a complete assessment
of electric reliability impacts from EPA rules, especially during the
early years of CSAPR. The way to obtain a complete assessment is for EPA
to prepare one in consultation with FERC and the regional authorities.
It is not sufficient for EPA to point to a lack of comments from these
entities in the official record.

Rather than performing a complete reliability assessment, EPA claims
that the flexibility allowed by an interstate trading program structure
will inherently promote electric reliability, and that "basic
reliability requirements are already incorporated into the analysis" of
its IPM. With respect to the structure of CSAPR, allowance trading alone
will not ensure electric reliability in Oklahoma during the initial
phase of the CSAPR for the reasons discussed previously in commenters’
letters. Rather, unit curtailments are possible on a scale that could
impact electric reliability, if sufficient replacement power is not
available for purchase and transmission into and within the State.
Commenters are concerned that the IPM does not sufficiently account for
restrictions on purchase power availability and transmission
capabilities.

In particular, the IPM sets certain limits on the ability to transfer
power between model regions using the bulk power transmission system.
One of the commenters recently performed a Linear First Contingency
Incremental Transfer Capability Single Transfer Analysis to determine
the deliverability of a resource in another region and found that the
capacity from that resource was not deliverable, even though the
capacity studied was less than the Joint Capacity and Energy Limit used
by the IPM. Furthermore, the IPM's inter-regional limits were determined
from the 2004 NERC Reliability Assessments, which were performed at a
time when energy sales in Oklahoma were 7% less than in 2010.

The IPM also assumes that, within each model region, "adequate
transmission capacity exists to deliver any resources located in, or
transferred to, the region. . . This is a major limitation on the
model's ability to accurately evaluate impacts on electric reliability
in Oklahoma from major federal rules like the CSAPR. While the IPM can
determine that a given region could meet reserve requirements with
imported resources, it performs no assessment of the reliable delivery
of the needed capacity. Regarding the legacy systems of its members in
the 2010 State of the Market Report, the SPP stated that "[w]hile these
systems may be functionally sufficient for their respective areas, they
may not be sufficient for macro transfers across the region." Also, of
the 20 most congested flowgates identified by the SPP in the July 2011
Monthly State of the Market Report, 18 were within the SPP region as
designated in the IPM.

EPA should consider that purchasing replacement power of this magnitude
may require OG&E to go through a competitive procurement bid process
pursuant to the Oklahoma Corporation Commission ("OCC") electric utility
rules and also may require OCC approval. Depending on the complexity of
the issues involved and the timelines prescribed by OCC rules, this
process could require one year or more to complete, which could
frustrate commenters' ability to arrange for replacement power if needed
during the 2012 ozone season. Commenters are also concerned that an
increase in demand for purchase power of this magnitude could impact the
electricity prices during 2012.

Finally, the IPM does not substitute for an operational study of the
generation capacity that would be available in the SPP during the ozone
season if the Supplemental Proposal is finalized. The assumptions made
in the IPM tend to overestimate unit availability, and commenters are
concerned that EPA has not adequately evaluated how the Supplemental
Proposal would impact the ability to meet peak loads on a month-to-month
basis during the summer time. In addition, while it is theoretically
possible that generation capacity might be available within the region,
it is also necessary to consider potential limitations in gas supply and
transportation deliverability to ensure that fuel switching from coal to
natural gas can be accomplished, along with the costs.

These are select examples of commenters’ concerns about the IPM as a
means of evaluating electric reliability for the Supplemental Proposal,
especially during the 2012 ozone season. More time is needed to review
the model's assumptions and incorporate additional considerations
related to generation capacity and transmission in the SPP. It will not
be possible to prepare a sufficient assessment in time for compliance by
May 2012. Furthermore, requiring compliance by that date without an
appropriate assessment would create an unacceptable risk to electric
reliability.

Commenter AES Shady Point raises some of the same concerns in its
comments.  [Oklahoma Gas & Electric Company (OGE)
(EPA-HQ-OAR-2009-0491-4590), p. 11-13; Oklahoma Utility Group
(EPA-HQ-OAR-2009-0491-4591), p. 8-10; AES Shady Point
(EPA-HQ-OAR-2009-0491-4595), p. 6-7.]

RESPONSE:  As the commenters note in quoting FERC, utility planning
processes are the appropriate vehicle for addressing the impact on
reliability of EPA rules.   EPA has been working with RTOs, utilities,
state commissions, and other appropriate entities in developing this
rule, and others, and will continue working with these agencies as the
rules are finalized and implemented.   EPA considers all rules that are
in effect when it evaluates each proposal, so that the cumulative impact
of rules are evaluated as they are put into effect.  EPA evaluates all
comments that are filed on each proposed rule in finalizing the rule.

EPA believes the limitations on inter-regional power transfers used in
IPM are appropriate; these limits are evaluated and modified when
information is provided that is sufficient to update these limits.
Broad references, such as those in these comments, do not provide
sufficient information to update these limits.  Although the
commenters’ information that sales in Oklahoma are 7% higher today
than they were in 2010 is relevant to the determination of resource
adequacy, IPM already captures these impacts through its use of reserve
margin requirements.

EPA believes commenters are wrong to dismiss the flexibility of the rule
and then claim reliability problems.  The rule’s inherent flexibility
permits all utilities many alternatives to comply with the requirements
of the rule: to purchase allowances from the market, to choose the best
units to dispatch, to change fuel supply, or to import power from other
regions.  These comments provide no substantive reasons why these
alternatives – either singly or in combination – are not viable ways
of meeting the rule’s requirements.

With respect to comments on the operational limitation of the IPM model,
IPM is not intended to be a model of operating capability within a
region, nor does it need to be for the purposes used in developing the
rule.  IPM is an economic model of the operation of the overall power
system in the lower 48 states; it projects generation and emissions in
each region to meet electricity demand using engineering, environmental,
and economic information on generating units and information on the
inter-regional transmission grid.  The rule does not set operating
requirements on individual units and provides operators of units the
flexibility to choose how units should be operated.  IPM models the
loads in each region using a load curve that represents the amount of
load that must be served at each load level; load levels are designed to
reflect key operational peak, intermediate, and baseload conditions,
thus capturing differing monthly load levels where these are important
for operation of the system.  The model also contains a detailed
representation of the natural gas pipeline system, and incorporated the
cost of increased supply of natural gas and additional pipeline capacity
in deciding whether fuel switching is the best economic choice.  EPA has
developed a balanced set of data on unit availabilities to accurately
represent plant availabilities in the IPM modeling:  coal unit
availabilities are based on historical data used by the Energy
Information Administration, and other availabilities for other types of
units are based on the GADS data (see IPM Documentation in the docket to
this rulemaking).

Statutory and Executive Order Reviews (e.g., ICR)

  Commenter questions how the health benefits of this rule were
determined.

Comment:  How does EPA justify/calculate the numerous health benefits to
this rule?  Limiting emissions from any source will of course provide
health benefits; however, the numbers being issued with this rule seem
to have no basis in fact.  They appear to be based on estimations such
as number of cases, severity of cases, and costs associated with
treatment.  Using those estimations to build a case to justify the
action does not seem fair to the States that will pay the actual costs
for estimated benefits.    [Oklahoma Municipal Power Authority (OMPA)
(EPA-HQ-OAR-2009-0491-4573), p. 2.]

RESPONSE:  The comment is outside the scope of the SNPR because it
addresses issues that were within the scope of the request for comments
in the proposed Transport Rule but not in the SNPR.  While EPA is not
reconsidering or reopening the issue, we note that the issue was
previously addressed in section VIII.C of the preamble for the final
Transport Rule and in chapter 5 of the final Transport Rule Regulatory
Impact Analysis, in the docket for this rulemaking.

Rule does not take into consideration inability of independent power
producers to recover compliance costs.

Comment:  Additionally and most importantly, the FIP does not take into
consideration that the AES Shady Point facility, as a contracted
independent power producer under long term contracts, does not currently
have mechanisms in place to recoup the implementation costs of this
rule. This lack of a cost sharing mechanism unfairly penalizes
independent power producers, and thereby jeopardizing facility
profitability, economic viability, regional grid stability, and
employment of 90 workers, not including trickling economic impacts.
[AES Shady Point (EPA-HQ-OAR-2009-0491-4580), p. 1-2.]

RESPONSE:  The comment is outside the scope of the SNPR because it
addresses issues that were within the scope of the request for comments
in the proposed Transport Rule but not in the SNPR.  While EPA is not
reconsidering or reopening the issue, we note that the issue was
previously addressed in the under the subject of long term contracts in
the final Transport Rule RTC.  See section V.D.2.a.,
Applicability/Opt-in Units in the Transport Rule Primary Response to
Comments for more details.

 (C) Commenter questions finding of no significant or unique impacts on
small governments.

Comment:  BPU questions EPA's finding that "[n]either the final
Transport Rule nor the provisions in this SNPR have regulatory
requirements that might significantly or uniquely affect small
governments." 76 FR at 40669/1.  BPU, an administrative agency of the
Unified Government of Wyandotte County/Kansas City, Kansas, operates an
electric utility on a not-for-profit basis for the benefit of
approximately 65,000 residential, commercial, and industrial customers
in Wyandotte County/Kansas City, Kansas. The final Transport Rule and
the SNPR will significantly affect BPU by requiring it to spend
substantial sums of money to comply with these rules. Raising those
amounts through bonds, as BPU must do, places additional burdens on the
regulatory and political process. Moreover, the final Transport Rule and
the SNPR require instantaneous results in comparison to the amount of
time needed to obtain bond financing thus significantly affecting the
ability of a small government to timely react to such requirements
without facing the possibility of enforcement of the new rules against
BPU. Finally, any increased costs related to new emission controls
required by the rule will strain the finances of all BPU's customers,
which include the county, the city and their citizens. [Kansas City
Board of Public Utilities (EPA-HQ-OAR-2009-0491-4585), p. 4-5.]

RESPONSE:  As already stated, EPA believes that no unfunded mandates
have been created by the Transport Rule program inclusive of this
supplemental rule. This comment does not provide evidence to demonstrate
that this rule uniquely affects small governments or that the magnitude
of the impact should be considered “significant.”  EPA has not
changed its finding based on the fact that most of the costs are to be
incurred by the private sector.  In the economic analysis for this rule,
EPA’s projected impacts on electricity prices are small—around 1% on
average nationwide.   See Chapter 8 of the RIA for more on economic
impacts.

(D) The cost of compliance creates a substantial burden upon consumers
and may affect the availability of electricity and the reliability of
transmission within the region.

Comment:  The Attorney General is concerned about the cost of compliance
for utilities within Oklahoma and the effect those costs will have on
consumers when they are inevitably transferred to ratepayers. The cost
of compliance for just the two largest electric utilities in Oklahoma is
estimated to be approximately $150 million. Those costs, when combined
with the substantial costs of compliance with other EPA mandates and
proposed rules create an unprecedented burden upon the electric energy
consumers of Oklahoma. The EPA should be mindful of the fact that
electricity consumers are not only paying the cost of compliance with
its rules, they are also responsible for additional costs mandated by
other entities for transmission development, demand-side management and
energy efficiency programs, renewable energy programs, etc.  [Oklahoma
Attorney General (EPA-HQ-OAR-2009-0491-4592), p. 2.]

RESPONSE:  EPA’s projected impacts on electricity prices are
small—around 1% on average nationwide.   These are the incremental
rate increases attributable to compliance with the Transport Rule.  The
total retail electricity prices forecasted by EPA do take into account
non-Transport Rule variables such as those cited above.  EPA appreciates
the comment and believes its modeling exemplifies its awareness of the
millions of variables factored into electricity prices.  See Chapter 8
of the RIA in the docket of this rulemaking for more on economic
impacts.

 (E) Commenter believes that EPA has failed to consider costs and
impacts properly n applying the rule to Iowa.

Comment:  The 2012 and 2014 base case modeling runs conducted to
determine, among other things, NOX emissions in Iowa and their purported
interference with the maintenance of the 1997 8-hour ozone standard in
Allegan County, Michigan utilized NOX values from IPM that did not
account for the Utility HAPs MACT or the Boiler MACT, both of which will
serve to lower emissions nationwide through the installation of controls
or shutdown of facilities.  Utilization of old base case data that fails
to consider the real emission reductions achieved by the CAIR (as
discussed above) and the emission reductions that will be achieved by
the MACT standards, MEC does not believe EPA has, in this instance,
achieved the requirements of Executive Order 13563 of January 18, 2011,
to “tailor its regulations to impose the least burden on society,
consistent with obtaining regulatory objectives, taking into account,
among other things, and to the extent practicable, the costs of
cumulative regulations” in requiring ozone season NOX reductions from
Iowa sources.  [MidAmerican Energy Company (EPA-HQ-OAR-2009-0491-4597),
p. 4.]

RESPONSE:  The comment is outside the scope of the SNPR because it
addresses issues that were within the scope of the request for comments
in the proposed Transport Rule but not in the SNPR.  While EPA is not
reconsidering or reopening the issue, we note that the issue regarding
the baseline was previously addressed in the preamble to the final
Transport Rule, section VI.  Also see the Regulatory Impact Assessment
for the final Transport Rule in the docket to this rulemaking.

Comment:  EPA is quick to point out that since Iowa and other states
subject to the supplemental notice provisions are already subject to
other requirements to reduce NOX emissions under the final Transport
Rule, there are, effectively, no additional costs to comply with the
ozone season requirements. EPA’s proposed allocation of seasonal NOX
allowances is insufficient to cover Iowa’s compliance burdens without
additional controls, leaving Iowa sources with a choice to spend money
on controls or in the purchase of allowances. Further, there are
incremental administrative costs associated with maintaining compliance
under the ozone season NOX reduction requirements, both from a reporting
and allowance management perspective. EPA’s analysis fails to account
for these incremental costs (as it does for the so-called “sunk
costs” associated with compliance with the legally enforceable
requirements of CAIR); MEC believes that the EPA should be required to
inform the public in general, and MEC’s customers, of the full costs
associated with reducing emissions in Michigan at an ozone monitoring
station that indicates the county is in attainment of the standard.
[MidAmerican Energy Company (EPA-HQ-OAR-2009-0491-4597), p. 4-5.]

RESPONSE:  While EPA is not reconsidering or reopening the issue, we
note that the issue regarding the treatment of CAIR was previously
addressed in section V.B of the preamble of Federal Implementation
Plans: Interstate Transport of Fine Particulate Matter and Ozone and
Correction of SIP Approvals (EPA–HQ–OAR–2009–0491) and Transport
Rule Primary Response to Comments (EPA-HQ-OAR-2009-0491-4513) Section
IV.A.  In regards to the assertion that Iowa will need to install
additional controls or purchase additional allowances, the commenter has
not provided significant evidence of that.  For instance, the 2010
ozone-season emissions in Iowa were 17,179 tons; the preliminary 2011
emissions for ozone-season NOX in Iowa are 17,179 tons, and their 2012
budget is 16,532 tons.  If Iowa continues to lower emissions at the rate
it has been, its 2012 emissions will be well below its 2012 budget
(meaning the state will likely have a surplus of allowances, not a
shortage).  EPA does not anticipate any additional controls or allowance
purchase for the state.  In fact, EPA modeling projects the state to be
a seller of allowances in 2012.  As for the incremental cost of
operating controls that would not otherwise operate in the base case,
that type of cost is captured in EPA’s analysis.  Additionally, the
$1.6 billion in capital cost already sunk into controls for CAIR is also
cited in EPA’s rollout of the final Transport Rule.  In regards to any
administrative or reporting cost, these are not reflected in the model,
as they are negligible.

 (F) EPA’s cost thresholds do not support retrofit environmental
controls.

Comment:  EPA's analysis suggests that additional combustion controls
can be added to many units within Oklahoma in 2012 at or below the cost
effective threshold of $500/ton of seasonal NOX. However, based on the
data contained within the IPM v4.10 documentation and the NEEDs input
file, the cost of some of the projected controls exceeds the
cost-effective threshold. As an example, Northeastern unit 3 is
projected to change from a NOX rate of 0.382 lb/MMBtu in the base case
to a NOX rate 0.251 lb/MMBtu in the policy case. According to EPA
documentation this project would cost almost $13 million and remove
approximately 860 tons of NOX per year. Using the retrofit capital
charge rate of 11.3%, this project would effectively cost more than
$1,600 per ton, before even consideration of O&M impacts. Therefore, it
is unclear why this project would be selected in the policy case. There
appears to be a fundamental discrepancy with the IPM model logic
surrounding control cost-effectiveness.  [Public Service Company of
Oklahoma (EPA-HQ-OAR-2009-0491-4600), p. 4.]

RESPONSE:  The commenter does not provide its underlying calculations
for the $13 million in capital cost referenced in the comment.  EPA’s
calculations reveal a much smaller number for total capital cost and
$/ton figures.  It appears that the commenter may have erred by
reflecting the total capital cost of “LNC3” controls in its
assessment.  However, the only cost incurred to achieve incremental
tonnage reductions noted above are the incremental cost of upgrading
combustion controls from LNC1 to LNC3 figures.  Table 5-5 of EPA’s
IPMv4.10 documentation provides the capital cost and scaling factor
assumption necessary to calculate the upgrade cost at this particular
unit.  Therefore, EPA believes that the reductions can be made
cost-effectively and that the commenter has misinterpreted EPA data in
forming its capital cost projection.  EPA believes that the capital
costs postulated by the commenter are drastically overstated.  However,
even if one were to assume that all the commenter’s calculations are
correct, their observation should be of no surprise.  The EPA remedy
modeling that the commenter is referencing projects an ozone season
allowance price that exceeds $1600/ton in future years, which would make
the upgrade decision for the Northeastern 3 unit economic even at the
conservative parameters assumed in the comment.  Finally, the commenter
assumes that the emissions avoided are 860 tons annually (as shown in
2012).  However, this does not take into account the ability of the unit
to increase utilization in future years and thus generate even more
emission reductions thereby further lowering the $/ton cost of the
control upgrade.  Finally, in this IPM remedy scenario, the state
emissions are less than the budget.  That is, EPA does not assume that
this control is part of necessary emission reductions to reach the
budget level, but rather part of a strategy that allows the state to
outperform its budget (emit less than its budget).  There are no source
specific requirements that the unit install any controls under Transport
Rule.  Moreover, in this rulemaking, EPA has removed any such assumption
that these controls are installed in 2012 in Oklahoma.

5.3 Miscellaneous Issues

(A)  Several commenters claimed that EPA has not provided a valid
opportunity for public review and comment of the supplemental proposal.
 [Note:  RESPONSE at end of this set of comments]

Comment:  Commenters who submitted follow-up comments had earlier
submitted requests for an extension of time to submit comments based on
the size of the rulemaking record and the late date by which the input
and output files were provided for CAMx modeling used to support the
Supplementary Proposal.  [AES Shady Point (EPA-HQ-OAR-2009-0491-4578),
Oklahoma Gas & Electric Company (EPA-HQ-OAR-2009-0491-4577), Westar
Energy (EPA-HQ-OAR-2009-0491-4575).]

Comment:  For the reasons set forth in earlier extension request
letters, commenters request that EPA extend the applicable comment
period to provide sufficient time for commenter to thoroughly review and
further inform its comments on this important proposal. The need for
additional time is especially compelling for Oklahoma sources. As
mentioned above, Oklahoma was not previously included in CAIR, and
whether or not Oklahoma would be included in any interstate transport
rule, and the basis for such inclusion, has been a moving target. EPA
included Oklahoma in its 2010 Proposed Transport Rule on the basis that
sources within the State contributed to nonattainment with NAAQS in
Tarrant County, Texas, with those allowances and actual emissions not
requiring that any control equipment be installed. EPA now proposes to
include Oklahoma based on modeled impacts in Allegan County, Michigan,
and also proposes to require a nearly 40% reduction in emissions in a
six month period.

Oklahoma's purported connection to Allegan County, Michigan is based on
new modeling data. The CAMx input and output files for this modeling
were not available online like other technical support documents, and it
took more than a week to receive the 8 TB of data once requested.
Additionally, it can take weeks to re-run the same CAMx model runs that
EPA completed in support of the CSAPR and the 42 day comment period is
not enough time to allow a thorough review. Given the nature of this
data and the tenuous link between Oklahoma and Allegan County
purportedly established by it, it is important that commenters be
provided additional time in which to conduct an in-depth analysis of the
methodology used by EPA as the basis for including Oklahoma in the
Supplemental Proposal. The 42 days that EPA allows for public comment is
not enough.

Furthermore, the comment period allowed by EPA is inconsistent with
Executive Order 13563, which was signed by the President on January 18,
2011, as well as with other recent rulemakings by EPA. Executive Order
13563 (Improving Regulation and Regulatory Review), provides that in
order to facilitate public participation in the regulatory process,
"each agency shall afford the public a meaningful opportunity to comment
... with a comment period that should generally be at least 60 days."
Although EPA followed this mandate in other rulemakings that also
required time-intensive review, such as the 2010 Proposed Transport Rule
and the Utility MACT, EPA inexplicably fails to do the same here.
Commenters request that EPA reconsider its August 19, 2011 decision not
to extend the comment period for the Supplemental Proposal.

Commenter AES Shady Point raises some of the same concerns in its
comments.  [Oklahoma Gas & Electric Company (OGE)
(EPA-HQ-OAR-2009-0491-4590), p. 13; Oklahoma Utility Group
(EPA-HQ-OAR-2009-0491-4591), p. 10-11; AES Shady Point
(EPA-HQ-OAR-2009-0491-4595), p. 7.]

Comment:   EPA has failed to provide an adequate notice and opportunity
for public comment on the Proposal. The Administrative Procedures Act