implemented and what controls would be implemented in the near future),
or may develop new RPGs for approval by us along with its progress
report, based on new modeling or other appropriate techniques, in
accordance with the requirements of 40 CFR 51.308(d)(1) in evaluating
the adequacy of their SIP (or this FIP) to meet the established RPGs.
---------------------------------------------------------------------------

    \366\ 80 FR 18944, 18998.
    \367\ 40 CFR 51.308(d)(1)(v).
    \368\ 64 FR at 35733 and 40 CFR 51.308(d)(1)(v).
---------------------------------------------------------------------------

    We disagree that Arkansas would be held to a higher standard or
that the methodology utilized by EPA to adjust the RPGs would not be
approvable if submitted by a state. The approach followed by EPA in
this action, using scaling to adjust the modeled RPGs based on
photochemical source apportionment model results is reasonable and
meets the requirements of the Regional Haze Rule. In our 2012
rulemaking,\369\ we made a finding that Arkansas did not complete a
reasonable progress analysis and therefore did not properly demonstrate
that additional controls were not reasonable under 40 CFR
51.308(d)(1)(i)(A). Thus we disapproved the RPGs Arkansas established
for Caney Creek and Upper Buffalo. In our proposed rulemaking, we
completed the reasonable progress analysis and established revised RPGs
using the methodology described above, since we have not received a
revised SIP to correct the portions of the SIP submittal we
disapproved.
---------------------------------------------------------------------------

    \369\ 77 FR 14604.
---------------------------------------------------------------------------

9. Additional Modeling Comments
    Comment: We received additional specific modeling comments
concerning emission rates modeled to assess baseline visibility impacts
for Independence, White Bluff and Flint Creek. We also received
separate comments concerning our modeling analysis and assessment of
NOX controls on Lake Catherine, White Bluff and
Independence.
    Response: We address these comments in our RTC document.

K. Legal

    We received several comments on EPA's legal authority to promulgate
a FIP under the Regional Haze Rule, and, more specifically, to address
the Rule's reasonable progress requirements. Below is a summary of some
of the more significant comments. For a more detailed explanation,
please refer to the RTC document that is a part of the docket for this
rulemaking.
    We received comments that EPA is prohibited from requiring controls
for this planning period if they cannot be installed during this
planning period. We disagree with these comments. The CAA establishes
our authority and responsibility to promulgate a FIP that addresses the
requirements of the regional haze program where a State's SIP
submission fails to meet the program requirements. Although the first
planning period, ending in 2018, includes RPGs specific to that
planning period, there is no limitation in the CAA or the Regional Haze
Rule that controls contained in a SIP (or a FIP) must be fully
implemented by the end of the planning period. As both the long-term
strategy and BART requirements may extend beyond the first planning
period, it follows that EPA has FIP authority to fill in ``gaps'' or
``inadequacies'' related to those components irrespective of whether
controls can be put into place by 2018. In addition, any emission
limitations that prove to be required by the CAA for the first planning
period need to be achieved at their soonest opportunity, not delayed,
deferred, or avoided for later planning periods when even further
progress may be required in order to achieve the national visibility
goal.
    We also received comments that we had no legal basis for requiring
alternative proposals for SO2 and NOX control
measures that would address the regional haze requirements for White
Bluff Units 1 and 2 and Independence Units 1 and 2 for this planning
period to achieve greater reasonable progress than the BART and
reasonable progress requirements that EPA has proposed for the first
planning period. Our response explains our analysis of Entergy's four-
unit approach and clarifies how our evaluation of that approach was
consistent with the Regional Haze Rule's BART alternative and
reasonable progress requirements.
    In addition, we received several comments that our proposed FIP was
not in keeping with the legal requirements for reasonable progress and
long term strategy as spelled out in the Regional Haze Rule and EPA
Guidance. We disagree and explain in more detail in the RTC document
that we disapproved the reasonable progress determination Arkansas
submitted in 2012 because the State did not conduct the required four-
factor analysis. The CAA requires us to stand in the State's shoes and
promulgate a FIP that addresses the requirements of the Regional Haze
Rule that we disapproved, including reasonable progress and the long
term strategy for Arkansas' Class I areas.
    We also received comments that our proposed FIP did not take into
account the leading role of the state in developing a plan that
addresses the regional haze program and thus is not in keeping with
cooperative federalism. We disagree that EPA ignored the principles of
cooperative federalism. Arkansas did develop a regional haze plan. We
reviewed it and partially approved and disapproved the plan in 2012.
The CAA creates a mandatory duty for EPA to either approve a state SIP
revision submittal that corrects the deficiency or promulgate a FIP
within two years of the effective date of the disapproval of a state
plan.
    We received comments that EPA does not have authority to finalize a
FIP after two years have elapsed from our initial disapproval of the
Arkansas Regional Haze SIP. We describe in more detail in the RTC
document our disagreement with this interpretation of what is required
under the Clean Air Act. The Tenth Circuit has upheld EPA's authority
to finalize a Regional Haze FIP after the two years have passed for EPA
to act on Oklahoma's Regional Haze SIP.
    We also received comments that our proposed FIP was not in keeping
with Executive Orders 12866 and 13211. Our response is that our
proposed action is not subject to Executive Order 13211 because it is
not a ``significant regulatory action'' under Executive Order 12866;
therefore, the proposed FIP is not a rule of general applicability
because its requirements apply and are tailored to only seven
individually identified facilities. Thus, it is not a ``rule'' or
``regulation'' within the meaning of E.O. 12866 and this action is not
a ``regulatory action'' subject to 12866. Since E.O. 13211 applies only
to ``significant regulatory actions'' under E.O. 12866, this action is
not subject to review under E.O. 13211.\28\ Evaluation of the proposal
under E.O. 13211's criteria is therefore not required.
    We respond in greater detail in the RTC document to comments that
EPA did not adequately consider costs to ratepayers as is required
under Arkansas law in developing air regulations. States are under an
obligation to submit a Regional Haze SIP to EPA which complies with
federal requirements. While states enjoy flexibility in developing a
SIP and can meet additional state requirements as long as the federal
requirements are satisfied, in the event that EPA must step in and
create a Federal Implementation Plan, we must meet all federal
requirements. We are not subject to state law requirements related to
how the cost

analyses must be conducted or what specific factors need to be
considered. We did consider costs in great detail to ensure that the
controls required by the FIP are cost-effective, appropriate in light
of the visibility reductions achieved, and consistent with expectations
in other SIPs and FIPs.
    We received several general comments including a claim that
documents that EPA relied for its rulemaking were not in the docket. As
explained more fully in our RTC document, the documents referred to are
briefing sheets and did not serve as the basis for EPA's decision
making. The docket contains all of the documents that serve as our
basis for our rulemaking for Arkansas Regional Haze.

L. Interstate Visibility Transport

    Comment: The good neighbor visibility provision in 42 U.S.C.
7410(a)(2)(D)(i)(II) prohibits interference with ``measures'' required
to be included in another State's implementation plan to protect
visibility. EPA has not demonstrated that any of these sources in its
FIP proposal are interfering with any visibility control measure in any
other state's SIP. In its FIP proposal, EPA states that the Arkansas
SIP did not ensure that emissions from Arkansas sources ``do not
interfere with other states' visibility programs as required by section
110(a)(2)(D)(i)(II) of the CAA.'' \370\ The visibility protection
requirement of section 110(a)(2)(D)(i)(II) does not protect against
interference with either other states ``efforts'' or other states
``programs.'' Unlike the language in section 110(a)(2)(D)(i)(I), which
prohibits emissions that contribute significantly to nonattainment or
maintenance of a NAAQS in another state, the visibility protection
requirement is narrower and only protects against interference with
specific measures, that is, actions included in another state's plan to
achieve a visibility goal. Reasonable progress goals, projected
deciview improvements from regional efforts, and the like are goals or
standards; they are not ``measures'' taken by or enforced by a state.
There is nothing in the record demonstrating that any of the sources in
the FIP proposal interfere with any measure included in any other
state's SIP for the purpose of protecting or improving visibility. To
the extent that EPA's proposed interstate visibility transport FIP is
not based on direct interference with a control measure in another
state's regional haze SIP (in contrast to interference with a regional
haze related visibility goal), EPA's interpretation is contrary to the
clear and express language of Section 110. EPA's interpretation also is
contrary to the CAA's clear direction that each state is to determine
its own emission limits, schedules of compliance and other measures for
sources in that state for purposes of visibility protection under
section 169A. EPA's interpretation would impermissibly give one state
the power to control another state's regional haze SIP decisions,
including its BART and reasonable progress determinations. Finally,
even if the CAA's good neighbor visibility provision required a SIP to
contain emission limits for sources that contribute to visibility
impairment at a Class I area in another state, EPA has not demonstrated
that any of the controls in its FIP proposal are ``necessary'' for that
purpose, considering based on the uncertainty in the modeling that
these controls will result in actual visibility improvements.
---------------------------------------------------------------------------

    \370\ 80 FR at 18998.
---------------------------------------------------------------------------

    Response: Section 110(a)(2)(D)(i)(II) does not explicitly define
what is required in SIPs to prevent the prohibited impact on visibility
in other states nor does it explicitly define how to determine if a
state's emissions are interfering with another state's measures to
protect visibility. We have interpreted this statutory requirement as
providing that a Regional Haze SIP that requires emission reductions
consistent with the assumptions the relevant RPO used to model the RPGs
for Class I areas in other states satisfies a state's obligation to
ensure that its own emissions do not interfere with another state's
visibility measures. States may rely on a fully approved Regional Haze
SIP to demonstrate that a SIP for 8-hour ozone or PM2.5
contains adequate provisions to prohibit emissions that interfere with
visibility measures in other states.\371\
---------------------------------------------------------------------------

    \371\ See ``2006 Guidance for SIP Submissions to Meet Current
Outstanding Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour
Ozone and PM2.5 NAAQS'' at pages 9-10.
---------------------------------------------------------------------------

    Arkansas chose to address the interstate visibility transport
requirement under section 110(a)(2)(D)(i)(II) by relying on its 2008
Regional Haze SIP submittal to achieve the emissions reductions
necessary to meet this requirement. However, due to our previous
partial disapproval of this submittal,\372\ the Arkansas SIP does not
currently include all of the emission reductions Arkansas agreed to
achieve in its RPO process. Arkansas is a member state of CENRAP, the
regional planning committee on regional haze. Each CENRAP state based
its regional haze plan and RPGs on the CENRAP modeling, which was based
in part on the emissions reductions each state intended to achieve by
2018. Within the CENRAP process, Arkansas promised to achieve emission
reductions corresponding to BART, and these emissions reductions were
included in the CENRAP modeling used by the participating states to
develop their RPGs and Regional Haze SIPs. However, EPA previously
disapproved some of Arkansas' BART determinations; therefore, the
State's SIP does not currently provide for all the emissions reductions
that Arkansas itself determined to be necessary to meet the interstate
visibility transport requirement. Because Arkansas has not provided any
other analysis or explanation of how the Arkansas SIP fulfills the
requirement of 110(a)(2)(D)(i)(II), it follows that the Arkansas SIP
does not contain adequate provisions to prohibit emissions that would
interfere with other states' visibility protection measures.
---------------------------------------------------------------------------

    \372\ 77 FR 14604.
---------------------------------------------------------------------------

    We disagree with the commenter's contention that our interpretation
is contrary to the CAA because the Act gives clear direction that each
state is to determine its own emission limits, schedules of compliance
and other measures for sources in that state for purposes of visibility
protection under section 169A. The commenter states that our
interpretation would impermissibly give one state the power to control
another state's regional haze SIP decisions. However, the commenter's
interpretation is inconsistent with section 110(a)(2)(D)(i)(II)'s
``good neighbor'' provision, which requires states to prohibit
emissions that interfere with other states' measures to protect
visibility. This statutory requirement anticipates that a state may be
required to adjust its own emissions based on the impacts of those
emissions on other states. Our Regional Haze Rule, which was
promulgated through notice-and-comment rulemaking in 1999, also
requires that states develop ``coordinated emission management
strategies'' when necessary to prevent interstate visibility
impairment.\373\ Thus, while the CAA and our regulations do not allow
one state to ``control'' another's regional haze planning, they do
contemplate that a state may be required to prohibit emissions that
interfere with visibility in another state's Class I areas.
---------------------------------------------------------------------------

    \373\ 40 CFR 51.308(d)(3)(i).
---------------------------------------------------------------------------

    As stated above, Arkansas elected to address the interstate
visibility transport requirement under section 110(a)(2)(D)(i)(II) by
relying on the BART determinations that are part of its

Regional Haze SIP submittal. Arkansas could have elected to address the
interstate visibility transport requirement under section
110(a)(2)(D)(i)(II) by other means; we have elsewhere determined that
states may also be able to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with something less than an approved Regional Haze
SIP.\374\ In other words, an approved Regional Haze SIP is not the only
possible means to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with respect to visibility; however such a SIP
could be sufficient.\375\ The approved portion of the Arkansas Regional
Haze SIP and our Regional Haze FIP together will ensure emissions
reductions from Arkansas sources consistent with the assumptions used
in the CENRAP modeling and meets Arkansas' obligations to address the
interstate visibility transport requirement under section
110(a)(2)(D)(i)(II).
---------------------------------------------------------------------------

    \374\ See, e.g., Colorado (76 FR 22036 (April 20, 2011)), Idaho
(76 FR 36329 (June 22, 2011)), and New Mexico (76 FR 52388 (August,
22, 2011)).
    \375\ We've allowed states to rely on their approved regional
haze plan to meet the requirements of the visibility component of
110(a)(2)(D)(i)(II) because the regional haze plan achieved at least
as much emissions reductions as projected by the RPO modeling. See
76 FR 34608, June 14, 2011 (California); 79 FR 60985, October 9,
2014 (New Mexico); 76 FR 36329, June 22, 2011 (Idaho); and 76 FR
38997, July 5, 2011 (Oregon).
---------------------------------------------------------------------------

    We address elsewhere in this document comments contending that
there is uncertainty in the CALPUFF modeling and uncertainty that our
proposed controls will result in actual visibility improvements.

VI. Final Action

    We are finalizing a FIP to remedy the deficiencies in the Arkansas
Regional Haze SIP and Interstate Visibility Transport SIP to address
the visibility transport requirement under section 110(a)(2)(D)(i)(II)
for the 1997 8-hour ozone and PM2.5 NAAQS.

A. Regional Haze

    Our final FIP includes SO2, NOX, and PM
emission limits for specific emission units in Arkansas to address the
BART requirements. The affected emission units are the AECC Bailey Unit
1; AECC McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff
Units 1, 2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; and
Domtar Ashdown Mill Power Boilers No. 1 and 2. In addition, we are
requiring SO2 and NOX controls under reasonable
progress for Entergy Independence Units 1 and 2. We are also finalizing
compliance schedules and testing, reporting and recordkeeping
requirements for these emission units. Our final FIP requires the
following emission limits for these emission units:

                                      Table 22--Final BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                          Final SO2 emission       Final NOX emission
                 Unit                           limit                    limit           Final PM emission limit
----------------------------------------------------------------------------------------------------------------
Bailey Unit 1........................  0.5% limit on sulfur     887 lb/hr..............  0.5% limit on sulfur
                                        content of fuel                                   content of fuel
                                        combusted.                                        combusted.
McClellan Unit 1.....................  0.5% limit on sulfur     869.1 lb/hr \a\/705.8    0.5% limit on sulfur
                                        content of fuel          lb/hr \a\.               content of fuel
                                        combusted.                                        combusted.
Flint Creek Unit 1...................  0.06 lb/MMBtu..........  0.23 lb/MMBtu..........  EPA approved the
                                                                                state's BART
                                                                                determination in March
                                                                                12, 2012 final action
                                                                                (77 FR 14604).
White Bluff Unit 1...................  0.06 lb/MMBtu..........  0.15 lb/MMBtu \b\/671    EPA approved the
                                                                 lb/hr \c\.               state's BART
                                                                                determination in March
                                                                                12, 2012 final action
                                                                                (77 FR 14604).
White Bluff Unit 2...................  0.06 lb/MMBtu..........  0.15 lb/MMBtu \b\/671    EPA approved the
                                                                 lb/hr \c\.               state's BART
                                                                                determination in March
                                                                                12, 2012 final action
                                                                                (77 FR 14604).
White Bluff Auxiliary Boiler.........  105.2 lb/hr............  32.2 lb/hr.............  4.5 lb/hr.
Lake Catherine Unit 4 \d\............  EPA approved the         0.22 lb/MMBtu..........  EPA approved the
                                        state's BART                                      state's BART
                                        determination in March                            determination in March
                                        12, 2012 final action                             12, 2012 final action
                                        (77 FR 14604).                                    (77 FR 14604).
Domtar Ashdown Mill Power Boiler No.   504 lb/day.............  207.4 lb/hr............  EPA approved the
 1.                                                                                state's BART
                                                                                determination in March
                                                                                12, 2012 final action
                                                                                (77 FR 14604).
Domtar Ashdown Mill Power Boiler No.   91.5 lb/hr.............  345 lb/hr..............  PM BART shall be
 2.                                                                                satisfied by relying
                                                                                on the applicable PM
                                                                                standard under 40 CFR
                                                                                part 63, subpart DDDDD
                                                                                \e\
----------------------------------------------------------------------------------------------------------------
\a\ Emission limit of 869.1 lb/hr applies to the natural gas-firing scenario; emission limit of 705.8 lb/hr
  applies to the fuel oil-firing scenario.
\b\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit's maximum heat
  input rating.
\c\ Emission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit's maximum heat
  input rating.
\d\ Emission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until
  BART determinations for SO2, NOX, and PM are promulgated for the unit for the fuel oil-firing scenario through
  EPA approval of a SIP revision or a FIP.
\e\ The facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD--National Emission
  Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers
  and Process Heaters, as revised, to satisfy the PM BART requirement.

   Table 23--Final Reasonable Progress Emission Limits for Sources not
                             Subject to BART
------------------------------------------------------------------------
                                  Final SO2 emission  Final NOX emission
              Unit                       limit               limit
------------------------------------------------------------------------
Independence Unit 1.............  0.06 lb/MMBtu.....  0.15 lb/MMBtu a/
                                                       671 lb/hr b

Independence Unit 2.............  0.06 lb/MMBtu.....  0.15 lb/MMBtu a/
                                                       671 lb/hr b
------------------------------------------------------------------------
a Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50%
  or greater of the unit's maximum heat input rating.
b Emission limit of 671 lb/hr applies when the unit is operated at less
  than 50% of the unit's maximum heat input rating.

    Based on our technical analysis, we have calculated the following
RPGs for the 20% worst days for Arkansas' Class I areas:

 Table 24--Reasonable Progress Goals for 2018 for Caney Creek and Upper
                                 Buffalo
------------------------------------------------------------------------
                                                           2018 RPG 20%
                      Class I area                          Worst days
                                                               (dv)
------------------------------------------------------------------------
Caney Creek.............................................           22.47
Upper Buffalo...........................................           22.51
------------------------------------------------------------------------

B. Interstate Visibility Transport

    We are finalizing our determination that the control measures in
the approved portion of the Arkansas Regional Haze SIP and our final
FIP are sufficient to prevent Arkansas' emissions from interfering with
other states' required measures to protect visibility. Thus, the
combined measures from both plans satisfy the interstate transport
visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997
8-hour ozone and the 1997 PM2.5 NAAQS.

VII. Statutory and Executive Order Reviews

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

    This action is exempt from review by the Office of Management and
Budget (OMB) because it imposes requirements that apply and are
tailored to only six individual power plants (AECC Bailey; AECC
McClellan; AEP Flint Creek; Entergy White Bluff; Entergy Lake
Catherine; and Entergy Independence) and one paper mill in Arkansas
(Domtar Ashdown Paper Mill). This FIP is not a rule of general
applicability. Thus, it is not a ``rule'' or ``regulation'' within the
meaning of E.O. 12866, and this action is not a ``regulatory action''
subject to 12866.

B. Paperwork Reduction Act (PRA)

    This action does not impose an information collection burden under
the provisions of the PRA, 44 U.S.C. 3501 et seq. Under the PRA, a
``collection of information'' is defined as a requirement for ``answers
to * * * identical reporting or recordkeeping requirements imposed on
ten or more persons * * *'' 44 U.S.C. 3502(3)(A). Because the FIP
applies to only seven facilities, the Paperwork Reduction Act does not
apply. See 5 CFR 1320.3(c).

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. This
action will not impose any requirements on small entities. This FIP
will apply to seven facilities, none of which fall under the definition
of small entities.

D. Unfunded Mandates Reform Act (UMRA)

    EPA has determined that Title II of the UMRA does not apply to this
rule. In 2 U.S.C. 1502(1) all terms in Title II of UMRA have the
meanings set forth in 2 U.S.C. 658, which further provides that the
terms ``regulation'' and ``rule'' have the meanings set forth in 5
U.S.C. 601(2). Under 5 U.S.C. 601(2), ``the term `rule' does not
include a rule of particular applicability relating to . . .
facilities.'' Because this rule is a rule of particular applicability
relating to seven named facilities, EPA has determined that it is not a
``rule'' for the purposes of Title II of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have Federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government. The final
rule does not impose significant economic costs on state or local
governments. Thus, Executive Order 13132 does not apply to the final
rule.

F. Executive Order 13175: Coordination With Indian Tribal Governments

    This action does not have tribal implications as specified in
Executive Order 13175. This action applies to seven facilities in
Arkansas and to Federal Class I areas in Arkansas. This action does not
apply on any Indian reservation land, any other area where EPA or an
Indian tribe has demonstrated that a tribe has jurisdiction, or non-
reservation areas of Indian country. Thus, Executive Order 13175 does
not apply to this action.

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

    The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it implements specific standards
established by Congress in statutes.

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

    This action is not subject to Executive Order 13211 because it is
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    This action involves technical standards. Section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (``NTTAA''),
Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use
voluntary consensus standards in its regulatory activities unless to do
so would be inconsistent with applicable law or otherwise impractical.
Voluntary consensus standards are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by voluntary consensus
standards bodies. NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and
applicable voluntary consensus standards. This rule would require the
seven affected facilities to meet the applicable monitoring
requirements of 40 CFR part 75. Part 75 already incorporates a number
of voluntary consensus standards. Consistent with the Agency's
Performance Based Measurement System (PBMS), part 75 sets forth
performance criteria that allow the use of alternative methods to the
ones set

forth in part 75. The PBMS approach is intended to be more flexible and
cost-effective for the regulated community; it is also intended to
encourage innovation in analytical technology and improved data
quality. At this time, EPA is not recommending any revisions to part
75; however, EPA periodically revises the test procedures set forth in
part 75. When EPA revises the test procedures set forth in part 75 in
the future, EPA will address the use of any new voluntary consensus
standards that are equivalent. Currently, even if a test procedure is
not set forth in part 75, EPA is not precluding the use of any method,
whether it constitutes a voluntary consensus standard or not, as long
as it meets the performance criteria specified; however, any
alternative methods must be approved through the petition process under
40 CFR 75.66 before they are used.

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

    The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income,
or indigenous populations because it increases the level of
environmental protection for all affected populations without having
any disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. This FIP limits emissions of SO2,
NOX, and PM from seven facilities in Arkansas.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on October 27, 2016.

L. Judicial Review

    Under section 307(b)(1) of the Clean Air Act, petitions for
judicial review of this action must be filed in the United States Court
of Appeals for the appropriate circuit by November 28, 2016. Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. (See CAA section 307(b)(2).)

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by
reference, Nitrogen dioxide, Ozone, Particulate matter, Reporting and
recordkeeping requirements, Sulfur dioxides, Visibility, Interstate
transport of pollution, regional haze, Best available retrofit
technology.

    Dated: August 31, 2016.
Gina McCarthy,
Administrator.
    Title 40, chapter I, of the Code of Federal Regulations is amended
as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart E--Arkansas

0
2. Section 52.173 is amended by adding paragraphs (c) and (d) to read
as follows:

Sec.  52.173  Visibility protection.

* * * * *
    (c) Federal implementation plan for regional haze. Requirements for
AECC Carl E. Bailey Unit 1; AECC John L. McClellan Unit 1; AEP Flint
Creek Unit 1; Entergy White Bluff Units 1, 2, and Auxiliary Boiler;
Entergy Lake Catherine Unit 4; Domtar Ashdown Paper Mill Power Boilers
No. 1 and 2; and Entergy Independence Units 1 and 2 affecting
visibility.
    (1) Applicability. The provisions of this section shall apply to
each owner or operator, or successive owners or operators, of the
sources designated as: AECC Carl E. Bailey Unit 1; AECC John L.
McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1,
2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown
Paper Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1
and 2.
    (2) Definitions. All terms used in this part but not defined herein
shall have the meaning given them in the Clean Air Act and in parts 51
and 60 of this title. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12
midnight.
    Air pollution control equipment includes selective catalytic
control units, baghouses, particulate or gaseous scrubbers, and any
other apparatus utilized to control emissions of regulated air
contaminants which would be emitted to the atmosphere.
    Boiler-operating-day for electric generating units listed under
paragraph (c)(1) of this section means any 24-hour period between 12
midnight and the following midnight during which any fuel is combusted
at any time at the steam generating unit, unless otherwise specified.
For power boilers listed under paragraph (c)(1) of this section, we
define boiler-operating-day as a 24-hr period between 6 a.m. and 6 a.m.
the following day during which any fuel is fed into and/or combusted at
any time in the power boiler.
    Daily average means the arithmetic average of the hourly values
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates,
controls, or supervises any of the units or power boilers listed under
paragraph (c)(1) of this section.
    Regional Administrator means the Regional Administrator of EPA
Region 6 or his/her authorized representative.
    Unit means one of the natural gas, fuel oil, or coal fired boilers
covered under paragraph (c) of this section.
    (3) Emissions limitations for AECC Bailey Unit 1 and AECC McClellan
Unit 1. The individual SO2, NOX, and PM emission
limits for each unit are as listed in the following table.

----------------------------------------------------------------------------------------------------------------
                 Unit                     SO2 Emission limit       NOX Emission limit       PM Emission limit
----------------------------------------------------------------------------------------------------------------
AECC Bailey Unit 1...................  Use of fuel with a       887 lb/hr..............  Use of fuel with a
                                        sulfur content limit                              sulfur content limit
                                        of 0.5% by weight..                               of 0.5% by weight.
AECC McClellan Unit 1................  Use of fuel with a       869.1 lb/hr............  Use of fuel with a
                                        sulfur content limit    (Natural Gas firing)...   sulfur content limit
                                        of 0.5% by weight..     705.8 lb/hr............   of 0.5% by weight.
                                                                (Fuel Oil firing)......
----------------------------------------------------------------------------------------------------------------

    (4) Compliance dates for AECC Bailey Unit 1 and AECC McClellan
Unit. The owner or operator of each unit must comply with the
SO2 and PM requirements listed in paragraph (c)(3) of this
section by October 27, 2021. As of October 27, 2016, the owner or
operator of each unit shall not purchase fuel for combustion at the
unit that does not meet the sulfur content limit in paragraph (c)(3) of
this section. The owner or operator of each unit must comply with the
requirement in paragraph (c)(3) of this section to burn only fuel with
a sulfur content limit of 0.5% by weight by October 27, 2021. The owner
or operator of each unit must comply with the NOX emission
limits in paragraph (c)(3) of this section by October 27, 2016.
    (5) Compliance determination and reporting and recordkeeping
requirements for AECC Bailey Unit 1 and AECC McClellan Unit--(i) SO2
and PM. To determine compliance with the SO2 and PM
requirements listed in paragraph (c)(3) of this section, the owner or
operator shall sample and analyze each shipment of fuel to determine
the sulfur content by weight, except for natural gas shipments. A
``shipment'' is considered delivery of the entire amount of each order
of fuel purchased. Fuel sampling and analysis may be performed by the
owner or operator of an affected unit, an outside laboratory, or a fuel
supplier. All records pertaining to the sampling of each shipment of
fuel as described above, including the results of the sulfur content
analysis, must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives.
    (ii) NOX. To determine compliance with the NOX emission
limits of paragraph (c)(3) of this section, the owner or operator shall
determine the average concentration (arithmetic average of three
contiguous one hour periods) of NOX as measured by the CEMS
and converted to pounds per hour using corresponding average
(arithmetic average of three contiguous one hour periods) stack gas
flow rates. Records of the NOX emissions rates must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives.
    (iii) The owner or operator shall continue to maintain and operate
a CEMS for NOX on the units listed in paragraph (c)(3) of
this section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h),
and appendix B of part 60. The owner or operator shall comply with the
quality assurance procedures for CEMS found in 40 CFR part 75.
Compliance with the emission limits for NOX shall be
determined by using data from a CEMS.
    (iv) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(3) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring NOX
and diluent gas shall complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period. Hourly averages shall be computed using at least one data point
in each fifteen minute quadrant of an hour. Notwithstanding this
requirement, an hourly average may be computed from at least two data
points separated by a minimum of 15 minutes (where the unit operates
for more than one quadrant in an hour) if data are unavailable as a
result of performance of calibration, quality assurance, preventive
maintenance activities, or backups of data from data acquisition and
handling system, and recertification events. When valid NOX
pounds per hour emission data are not obtained because of continuous
monitoring system breakdowns, repairs, calibration checks, or zero and
span adjustments, emission data must be obtained by using other
monitoring systems approved by the EPA to provide emission data for a
minimum of 18 hours in each 24-hour period and at least 22 out of 30
successive boiler operating days.
    (6) Emissions limitations for AEP Flint Creek Unit 1 and Entergy
White Bluff Units 1 and 2. The individual SO2 and
NOX emission limits for each unit are as listed in the
following table, as specified in pounds per million British thermal
units (lb/MMBtu) or pounds per hour (lb/hr). The SO2
emission limits of 0.06 lb/MMBtu and the NOX emission limits
of 0.23 lb/MMBtu and 0.15 lb/MMBtu are on a rolling 30 boiler-
operating-day averaging period. The NOX emission limit of
671 lb/hr is on a rolling 3-hour average.

----------------------------------------------------------------------------------------------------------------
                                                                   SO2 Emission    NOX Emission
                              Unit                                  limit (lb/      limit (lb/     NOX Emission
                                                                      MMBtu)          MMBtu)       limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
AEP Flint Creek Unit 1..........................................            0.06            0.23  ..............
Entergy White Bluff Unit 1......................................            0.06            0.15             671
Entergy White Bluff Unit 2......................................            0.06            0.15             671
----------------------------------------------------------------------------------------------------------------

    (7) Compliance dates for AEP Flint Creek Unit 1 and Entergy White
Bluff Units 1 and 2. The owner or operator of AEP Flint Creek Unit 1
must comply with the SO2 and NOX emission limits
listed in paragraph (c)(6) of this section by April 27, 2018. The owner
or operator of White Bluff Units 1 and 2 must comply with the
SO2 emission limit listed in paragraph (c)(6) of this
section by October 27, 2021, and must comply with the NOX
emission limits listed in paragraph (c) (6) of this section by April
27, 2018.
    (8) Compliance determination and reporting and recordkeeping
requirements for AEP Flint Creek Unit 1 and Entergy White Bluff Units 1
and 2. (i) For purposes of determining compliance with the
SO2 and NOX emissions limits listed in paragraph

(c)(6) of this section for AEP Flint Creek Unit 1 and with the
SO2 emissions limit listed in paragraph (c)(6) of this
section for White Bluff Units 1 and 2, the emissions for each boiler-
operating-day for each unit shall be determined by summing the hourly
emissions measured in pounds of SO2 or pounds of
NOX. For each unit, heat input for each boiler-operating-day
shall be determined by adding together all hourly heat inputs, in
millions of BTU. Each boiler-operating-day of the 30-day rolling
average for a unit shall be determined by adding together the pounds of
SO2 or NOX from that day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
or NOX by the sum of the heat input during the same 30
boiler-operating-day period. The result shall be the 30 boiler-
operating-day rolling average in terms of lb/MMBtu emissions of
SO2 or NOX. If a valid SO2 or
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and SO2 or NOX
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for SO2 or NOX. For
each day, records of the total SO2 and NOX
emitted that day by each emission unit and the sum of the hourly heat
inputs for that day must be maintained by the owner or operator and
made available upon request to EPA and ADEQ representatives. Records of
the 30 boiler-operating-day rolling average for SO2 and
NOX for each unit as described above must be maintained by
the owner or operator for each boiler-operating-day and made available
upon request to EPA and ADEQ representatives.
    (ii) For purposes of determining compliance with the 0.15 lb/MMBtu
NOX emissions limit listed in paragraph (c)(6) of this
section for White Bluff Units 1 and 2, the NOX emissions for
each unit shall be determined by the following procedure:
    (A) Summing the total pounds of NOX emitted during the
current boiler-operating-day and the preceding 29 boiler-operating-days
while including only emissions during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
    (B) Summing the total heat input in MMBtu to the unit during the
current boiler-operating-day and the preceding 29 boiler-operating-days
while including only the heat input during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
and
    (C) Dividing the total pounds of NOX emitted as
calculated in step 1 by the total heat input to the unit as calculated
in step 2. The result shall be the 30 boiler-operating-day rolling
average in terms of lb/MMBtu emissions of NOX. If a valid
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and NOX pounds per hour
shall not be used in the calculation of the 30 boiler-operating-day
rolling average for NOX. For each day, records for each unit
of the hours during which the unit was dispatched at 50% or greater of
the unit's maximum heat input rating, as well as NOX
emissions and hourly heat input for each of those hours must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the 30 boiler-operating-day
rolling average for NOX for each unit as described above
must be maintained by the owner or operator for each boiler-operating-
day and made available upon request to EPA and ADEQ representatives.
    (iii) For purposes of determining compliance with the 671 lb/hr
NOX emissions limit listed in paragraph (c)(6) of this
section for White Bluff Units 1 and 2, the NOX emissions for
each unit shall be determined by the following procedure:
    (A) Summing the total pounds of NOX emitted during the
current hour and the preceding 2 hours during which the unit was
dispatched at less than 50% of the unit's maximum heat input rating;
and
    (B) Dividing the total pounds of NOX emitted as
calculated in step 1 by 3. The result shall be the rolling 3-hour
average in terms of lb/hr emissions of NOX. If a valid
NOX pounds per hour is not available for any hour for a
unit, that NOX pounds per hour shall not be used in the
calculation of the rolling 3-hour average for NOX. For each
day, records for each unit of the hours during which the unit was
dispatched at less than 50% of each unit's maximum heat input rating,
as well as NOX emissions and hourly heat input for each of
those hours must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives. Records of the
rolling 3-hour averages for NOX for each unit as described
above must be maintained for each day by the owner or operator and made
available upon request to EPA and ADEQ representatives.
    (iv) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the units listed in
paragraph (c)(6) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and appendix B of part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.
    (v) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(6) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring SO2
and NOX and diluent gas shall complete a minimum of one
cycle of operation (sampling, analyzing, and data recording) for each
successive 15-minute period. Hourly averages shall be computed using at
least one data point in each fifteen minute quadrant of an hour.
Notwithstanding this requirement, an hourly average may be computed
from at least two data points separated by a minimum of 15 minutes
(where the unit operates for more than one quadrant in an hour) if data
are unavailable as a result of performance of calibration, quality
assurance, preventive maintenance activities, or backups of data from
data acquisition and handling system, and recertification events. When
valid SO2 or NOX pounds per hour emission data
are not obtained because of continuous monitoring system breakdowns,
repairs, calibration checks, or zero and span adjustments, emission
data must be obtained by using other monitoring systems approved by the
EPA to provide emission data for a minimum of 18 hours in each 24 hour
period and at least 22 out of 30 successive boiler operating days.
    (9) Emissions limitations for Entergy White Bluff Auxiliary Boiler.
The individual SO2, NOX, and PM emission limits
for the unit are as listed in the following table in pounds per hour
(lb/hr).

----------------------------------------------------------------------------------------------------------------
                                                                   SO2 Emission    NOX Emission     PM Emission
                              Unit                                 limit (lb/hr)   limit (lb/hr)   limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
Entergy White Bluff Auxiliary Boiler............................           105.2            32.2             4.5
----------------------------------------------------------------------------------------------------------------

    (10) Compliance dates for Entergy White Bluff Auxiliary Boiler. The
owner or operator of the unit must comply with the SO2,
NOX, and PM emission limits listed in paragraph (c)(9) of
this section by October 27, 2016.
    (11) Compliance determination and reporting and recordkeeping
requirements for Entergy White Bluff Auxiliary Boiler. For purposes of
demonstrating compliance with the emission limits listed in paragraph
(c)(9) of this section, records of fuel oil analysis must be maintained
by the owner or operator and made available upon request to EPA and
ADEQ representatives.
    (12) Emissions limitations for Entergy Lake Catherine Unit 4. The
individual NOX emission limit for the unit for natural gas
firing is as listed in the following table in pounds per million
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. The unit must not burn fuel oil until BART
determinations are promulgated for the unit for SO2,
NOX, and PM for the fuel oil firing scenario through a FIP
and/or through EPA action upon and approval of revised BART
determinations submitted by the State as a SIP revision.

------------------------------------------------------------------------
                                                           NOX Emission
                                                          limit--natural
                          Unit                            gas firing (lb/
                                                              MMBtu)
------------------------------------------------------------------------
Entergy Lake Catherine Unit 4...........................            0.22
------------------------------------------------------------------------

    (13) Compliance dates for Entergy Lake Catherine Unit 4. The owner
or operator of the unit must comply with the NOX emission
limit listed in paragraph (c)(12) of this section by October 27, 2019.
    (14) Compliance determination and reporting and recordkeeping
requirements for Entergy Lake Catherine Unit 4. (i) NOX
emissions for each day shall be determined by summing the hourly
emissions measured in pounds of NOX. The heat input for each
boiler-operating-day shall be determined by adding together all hourly
heat inputs, in millions of BTU. Each boiler-operating-day of the
thirty-day rolling average for the unit shall be determined by adding
together the pounds of NOX from that day and the preceding
29 boiler-operating-days and dividing the total pounds of
NOX by the sum of the heat input during the same 30 boiler-
operating-day period. The result shall be the 30 boiler-operating-day
rolling average in terms of lb/MMBtu emissions of NOX. If a
valid NOX pounds per hour or heat input is not available for
any hour for the unit, that heat input and NOX pounds per
hour shall not be used in the calculation of the 30 boiler-operating-
day rolling average for NOX. For each day, records of the
total NOX emitted that day by the unit and the sum of the
hourly heat inputs for that day must be maintained by the owner or
operator and made available upon request to EPA and ADEQ
representatives. Records of the 30 boiler-operating-day rolling average
for NOX for the unit as described above must be maintained
by the owner or operator for each boiler-operating-day and made
available upon request to EPA and ADEQ representatives.
    (ii) The owner or operator shall continue to maintain and operate a
CEMS on the unit listed in paragraph (c)(12) of this section in
accordance with 40 CFR part 75, Appendix E as long as the unit meets
the definition of a peaking unit under 40 CFR part 75. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75.
    (iii) Continuous emissions monitoring shall apply during all
periods of operation of the unit listed in paragraph (c)(12) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments.
    (15) Emissions Limitations for Domtar Ashdown Paper Mill Power
Boiler No. 1. The SO2 emission limit for the boiler is as
listed in the following table in pounds per day (lb/day) as averaged
over a rolling 30 boiler-operating-day period. The NOX
emission limit for the boiler is as listed in the following table in
pounds per hour (lb/hr).

------------------------------------------------------------------------
                                           SO2 Emission    NOX Emission
                  Unit                    limit (lb/day)   limit (lb/hr)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler               504           207.4
 No. 1..................................
------------------------------------------------------------------------

    (16) Compliance dates for Domtar Ashdown Mill Power Boiler No. 1.
The owner or operator of the boiler must comply with the SO2
and NOX emission limits listed in paragraph (c)(15) of this
section by November 28, 2016.
    (17) Compliance determination and reporting and recordkeeping
requirements for Domtar Ashdown Paper Mill Power Boiler No. 1. (i)(A)
SO2 emissions resulting from combustion of fuel oil shall be
determined by assuming that the SO2 content of the fuel
delivered to the fuel inlet of the combustion chamber is equal to the
SO2 being emitted at the stack. The owner or operator must
maintain records of the sulfur content by weight of each fuel oil
shipment, where a ``shipment'' is considered delivery of the entire
amount of each order of fuel purchased. Fuel sampling and analysis may
be performed by the owner or operator, an outside laboratory, or a fuel
supplier. All records pertaining to the sampling of each shipment of
fuel oil, including the results of the sulfur content analysis, must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. SO2 emissions resulting from
combustion of bark shall be determined by using the following site-
specific curve equation, which accounts for the SO2
scrubbing capabilities of bark combustion:

Y= 0.4005 * X-0.2645

Where:

Y= pounds of sulfur emitted per ton of dry fuel feed to the boiler
X= pounds of sulfur input per ton of dry bark

    (B) The owner or operator must confirm the site-specific curve
equation through stack testing. By October 27, 2017, the owner or
operator must provide a report to EPA showing confirmation of the site
specific-curve equation accuracy. Records of the quantity of fuel input
to the boiler for each fuel type for each day must be compiled no later
than 15 days after the end of the month and must be maintained by the
owner or operator and made available upon request to EPA and ADEQ
representatives. Each boiler-operating-day of the 30-day rolling
average for the boiler must be determined by adding together the pounds
of SO2 from that boiler-operating-day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
by the sum of the

total number of boiler operating days (i.e., 30). The result shall be
the 30 boiler-operating-day rolling average in terms of lb/day
emissions of SO2. Records of the total SO2
emitted for each day must be compiled no later than 15 days after the
end of the month and must be maintained by the owner or operator and
made available upon request to EPA and ADEQ representatives. Records of
the 30 boiler-operating-day rolling averages for SO2 as
described in this paragraph (c)(17)(i) must be maintained by the owner
or operator for each boiler-operating-day and made available upon
request to EPA and ADEQ representatives.
    (ii) If the air permit is revised such that Power Boiler No. 1 is
permitted to burn only pipeline quality natural gas, this is sufficient
to demonstrate that the boiler is complying with the SO2
emission limit under paragraph (c)(15) of this section. The compliance
determination requirements and the reporting and recordkeeping
requirements under paragraph (c)(17)(i) of this section would not apply
and confirmation of the accuracy of the site-specific curve equation
under paragraph (c)(17)(i)(B) of this section through stack testing
would not be required so long as Power Boiler No. 1 is only permitted
to burn pipeline quality natural gas.
    (iii) To demonstrate compliance with the NOX emission
limit under paragraph (c)(15) of this section, the owner or operator
shall conduct stack testing using EPA Reference Method 7E once every 5
years, beginning 1 year from the effective date of our final rule.
Records and reports pertaining to the stack testing must be maintained
by the owner or operator and made available upon request to EPA and
ADEQ representatives.
    (iv) If the air permit is revised such that Power Boiler No. 1 is
permitted to burn only pipeline quality natural gas, the owner or
operator may demonstrate compliance with the NOX emission
limit under paragraph (c)(15) of this section by calculating
NOX emissions using fuel usage records and the applicable
NOX emission factor under AP-42, Compilation of Air
Pollutant Emission Factors, section 1.4, Table 1.4-1. Records of the
quantity of natural gas input to the boiler for each day must be
compiled no later than 15 days after the end of the month and must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the calculation of
NOX emissions for each day must be compiled no later than 15
days after the end of the month and must be maintained by the owner or
operator and made available upon request to EPA and ADEQ
representatives. Each boiler-operating-day of the 30-day rolling
average for the boiler must be determined by adding together the pounds
of NOX from that day and the preceding 29 boiler-operating-
days and dividing the total pounds of NOX by the sum of the
total number of hours during the same 30 boiler-operating-day period.
The result shall be the 30 boiler-operating-day rolling average in
terms of lb/hr emissions of NOX. Records of the 30 boiler-
operating-day rolling average for NOX must be maintained by
the owner or operator for each boiler-operating-day and made available
upon request to EPA and ADEQ representatives. Under these
circumstances, the compliance determination requirements and the
reporting and recordkeeping requirements under paragraph (c)(17)(iii)
of this section would not apply.
    (18) SO2 and NOX  Emissions Limitations for Domtar Ashdown Paper
Mill Power Boiler No.2. The individual SO2 and
NOX emission limits for the boiler are as listed in the
following table in pounds per hour (lb/hr) as averaged over a rolling
30 boiler-operating-day period.

------------------------------------------------------------------------
                                           SO2 Emission    NOX Emission
                  Unit                     Limit (lb/hr)   Limit (lb/hr)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler              91.5             345
 No. 2..................................
------------------------------------------------------------------------

    (19) SO2 and NOX Compliance dates for Domtar Ashdown Mill Power
Boiler No. 2. The owner or operator of the boiler must comply with the
SO2 and NOX emission limits listed in paragraph
(c)(18) of this section by October 27, 2021.
    (20) SO2 and NOX  Compliance determination and reporting and
recordkeeping requirements for Domtar Ashdown Mill Power Boiler No. 2.
(i) NOX and SO2 emissions for each day shall be
determined by summing the hourly emissions measured in pounds of
NOX or pounds of SO2. Each boiler-operating-day
of the 30-day rolling average for the boiler shall be determined by
adding together the pounds of NOX or SO2 from
that day and the preceding 29 boiler-operating-days and dividing the
total pounds of NOX or SO2 by the sum of the
total number of hours during the same 30 boiler-operating-day period.
The result shall be the 30 boiler-operating-day rolling average in
terms of lb/hr emissions of NOX or SO2. If a
valid NOX pounds per hour or SO2 pounds per hour
is not available for any hour for the boiler, that NOX
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for NOX. For each day, records
of the total SO2 and NOX emitted for that day by
the boiler must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives. Records of the
30 boiler-operating-day rolling average for SO2 and
NOX for the boiler as described above must be maintained by
the owner or operator for each boiler-operating-day and made available
upon request to EPA and ADEQ representatives.
    (ii) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the boiler listed in
paragraph (c)(18) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and appendix B of part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 60. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all
periods of operation of the boiler listed in paragraph (c)(18) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments. Continuous monitoring systems for measuring
SO2 and NOX and diluent gas shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period. Hourly averages shall
be computed using at least one data point in each fifteen minute
quadrant of an hour. Notwithstanding this requirement, an hourly
average may be computed from at least two data points separated by a
minimum of 15 minutes (where the unit operates for more than one
quadrant in an hour) if data are unavailable as a result of performance
of calibration, quality assurance, preventive maintenance activities,
or

backups of data from data acquisition and handling system, and
recertification events. When valid SO2 or NOX
pounds per hour emission data are not obtained because of continuous
monitoring system breakdowns, repairs, calibration checks, or zero and
span adjustments, emission data must be obtained by using other
monitoring systems approved by the EPA to provide emission data for a
minimum of 18 hours in each 24 hour period and at least 22 out of 30
successive boiler operating days.
    (iv) If the air permit is revised such that Power Boiler No. 2 is
permitted to burn only pipeline quality natural gas, this is sufficient
to demonstrate that the boiler is complying with the SO2
emission limit under paragraph (c)(18) of this section. Under these
circumstances, the compliance determination requirements under
paragraphs (c)(20)(i) through (iii) of this section would not apply to
the SO2 emission limit listed in paragraph (c)(18) of this
section.
    (v) If the air permit is revised such that Power Boiler No. 2 is
permitted to burn only pipeline quality natural gas and the operation
of the CEMS is not required under other applicable requirements, the
owner or operator may demonstrate compliance with the NOX
emission limit under paragraph (c)(18) of this section by calculating
NOX emissions using fuel usage records and the applicable
NOX emission factor under AP-42, Compilation of Air
Pollutant Emission Factors, section 1.4, Table 1.4-1. Records of the
quantity of natural gas input to the boiler for each day must be
compiled no later than 15 days after the end of the month and must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the calculation of
NOX emissions for each day must be compiled no later than 15
days after the end of the month and must be maintained and made
available upon request to EPA and ADEQ representatives. Each boiler-
operating-day of the 30-day rolling average for the boiler must be
determined by adding together the pounds of NOX from that
day and the preceding 29 boiler-operating-days and dividing the total
pounds of NOX by the sum of the total number of hours during
the same 30 boiler-operating-day period. The result shall be the 30
boiler-operating-day rolling average in terms of lb/hr emissions of
NOX. Records of the 30 boiler-operating-day rolling average
for NOX must be maintained by the owner or operator for each
boiler-operating-day and made available upon request to EPA and ADEQ
representatives. Under these circumstances, the compliance
determination requirements under paragraphs (c)(20)(i) through (iii) of
this section would not apply to the NOX emission limit.
    (21) PM BART Requirements for Domtar Ashdown Paper Mill Power
Boiler No.2. The owner or operator must rely on the applicable PM
standard required under 40 CFR part 63, subpart DDDDD--National
Emission Standards for Hazardous Air Pollutants for Major Sources:
Industrial, Commercial, and Institutional Boilers and Process Heaters,
as revised, to satisfy the PM BART requirement. Compliance with the
applicable PM standard under 40 CFR part 63 subpart DDDDD, as revised,
shall demonstrate compliance with the PM BART requirement.
    (22) PM compliance dates for Domtar Ashdown Mill Power Boiler No.
2. The owner or operator of the boiler must comply with the PM BART
requirement listed in paragraph (c)(21) of this section by November 28,
2016.
    (23) Alternative PM Compliance Determination for Domtar Ashdown
Paper Mill Power Boiler No.2. If the air permit is revised such that
Power Boiler No. 2 is permitted to burn only pipeline quality natural
gas, this is sufficient to demonstrate that the boiler is complying
with the PM BART requirement under paragraph (c)(21) of this section.
    (24) Emissions limitations for Entergy Independence Units 1 and 2.
The individual emission limits for each unit are as listed in the
following table in pounds per million British thermal units (lb/MMBtu)
or pounds per hour (lb/hr). The SO2 emission limit and the
NOX emission limits listed in the table as lb/MMBtu are on a
rolling 30 boiler-operating-day averaging period. The NOX
emission limit of 671 lb/hr is on a rolling 3-hour average.

----------------------------------------------------------------------------------------------------------------
                                                                   SO2 Emission    NOX Emission
                              Unit                                  limit (lb/      limit (lb/     NOX Emission
                                                                      MMBtu)          MMBtu)       Limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
Entergy Independence Unit 1.....................................            0.06            0.15             671
Entergy Independence Unit 2.....................................            0.06            0.15             671
----------------------------------------------------------------------------------------------------------------

    (25) Compliance dates for Entergy Independence Units 1 and 2. The
owner or operator of each unit must comply with the SO2
emission limit in paragraph (c)(24) of this section by October 27, 2021
and with the NOX emission limits by April 27, 2018.
    (26) Compliance determination and reporting and recordkeeping
requirements for Entergy Independence Units 1 and 2. (i) For purposes
of determining compliance with the SO2 emissions limit
listed in paragraph (c)(24) of this section for each unit, the
SO2 emissions for each boiler-operating-day shall be
determined by summing the hourly emissions measured in pounds of
SO2. For each unit, heat input for each boiler-operating-day
shall be determined by adding together all hourly heat inputs, in
millions of BTU. Each boiler-operating-day of the thirty-day rolling
average for a unit shall be determined by adding together the pounds of
SO2 from that day and the preceding 29 boiler-operating-days
and dividing the total pounds of SO2 by the sum of the heat
input during the same 30 boiler-operating-day period. The result shall
be the 30 boiler-operating-day rolling average in terms of lb/MMBtu
emissions of SO2. If a valid SO2 pounds per hour
or heat input is not available for any hour for a unit, that heat input
and SO2 pounds per hour shall not be used in the calculation
of the applicable 30 boiler-operating-days rolling average. For each
day, records of the total SO2 emitted that day by each
emission unit and the sum of the hourly heat inputs for that day must
be maintained by the owner or operator and made available upon request
to EPA and ADEQ representatives. . Records of the 30 boiler-operating-
day rolling average for each unit as described above must be maintained
by the owner or operator for each boiler-operating-day and made
available upon request to EPA and ADEQ representatives.
    (ii) For purposes of determining compliance with the 0.15 lb/MMBtu
NOX emissions limit listed in paragraph (c)(24), the
NOX emissions for each unit shall be determined by the
following procedure:
    (A) Summing the total pounds of NOX emitted during the
current boiler-operating-day and the preceding 29 boiler-operating-days
while including only emissions during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;

    (B) Summing the total heat input in MMBtu to the unit during the
current boiler-operating-day and the preceding 29 boiler operating days
while including only the heat input during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
and
    (C) Dividing the total pounds of NOX emitted as
calculated in step 1 by the total heat input to the unit as calculated
in step 2. The result shall be the 30 boiler-operating-day rolling
average in terms of lb/MMBtu emissions of NOX. If a valid
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and NOX pounds per hour
shall not be used in the calculation of the 30 boiler-operating-day
rolling average for NOX. For each day, records for each unit
of the hours during which the unit was dispatched at 50% or greater of
the unit's maximum heat input rating, as well as NOX
emissions and hourly heat input for each of those hours must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the 30 boiler-operating-day
rolling average for NOX for each unit as described above
must be maintained by the owner or operator for each boiler-operating-
day and made available upon request to EPA and ADEQ representatives.
    (iii) For purposes of determining compliance with the 671 lb/hr
NOX emissions limit listed in paragraph (c)(24), the
NOX emissions for each unit shall be determined by the
following procedure:
    (A) Summing the total pounds of NOX emitted during the
current hour and the preceding 2 hours during which the unit was
dispatched at less than 50% of the unit's maximum heat input rating;
and
    (B) Dividing the total pounds of NOX emitted as
calculated in step 1 by 3. The result shall be the rolling 3-hour
average in terms of lb/hr emissions of NOX. If a valid
NOX pounds per hour is not available for any hour for a
unit, that NOX pounds per hour shall not be used in the
calculation of the rolling 3-hour average for NOX. For each
day, records for each unit of the hours during which the unit was
dispatched at less than 50% of each unit's maximum heat input rating,
as well as NOX emissions and hourly heat input for each of
those hours must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives. Records of the
rolling 3-hour averages for NOX for each unit as described
above must be maintained for each day by the owner or operator and made
available upon request to EPA and ADEQ representatives.
    (iv) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the units listed in
paragraph (c)(24) in accordance with 40 CFR 60.8 and 60.13(e), (f), and
(h), and appendix B of part 60. The owner or operator shall comply with
the quality assurance procedures for CEMS found in 40 CFR part 75.
Compliance with the emission limits for SO2 and
NOX shall be determined by using data from a CEMS.
    (v) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(24) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring SO2
and NOX and diluent gas shall complete a minimum of one
cycle of operation (sampling, analyzing, and data recording) for each
successive 15-minute period. Hourly averages shall be computed using at
least one data point in each fifteen minute quadrant of an hour.
Notwithstanding this requirement, an hourly average may be computed
from at least two data points separated by a minimum of 15 minutes
(where the unit operates for more than one quadrant in an hour) if data
are unavailable as a result of performance of calibration, quality
assurance, preventive maintenance activities, or backups of data from
data acquisition and handling system, and recertification events. When
valid SO2 or NOX pounds per hour emission data
are not obtained because of continuous monitoring system breakdowns,
repairs, calibration checks, or zero and span adjustments, emission
data must be obtained by using other monitoring systems approved by the
EPA to provide emission data for a minimum of 18 hours in each 24 hour
period and at least 22 out of 30 successive boiler operating days.
    (27) Reporting and recordkeeping requirements. Unless otherwise
stated all requests, reports, submittals, notifications, and other
communications to the Regional Administrator required under paragraph
(c) of this section shall be submitted, unless instructed otherwise, to
the Director, Multimedia Planning and Permitting Division, U.S.
Environmental Protection Agency, Region 6, to the attention of Mail
Code: 6PD, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733.
For each unit subject to the emissions limitation under paragraph (c)
of this section, the owner or operator shall comply with the following
requirements, unless otherwise specified:
    (i) For each emissions limit under paragraph (c) of this section
where compliance shall be determined by using data from a CEMS, comply
with the notification, reporting, and recordkeeping requirements for
CEMS compliance monitoring in 40 CFR 60.7(c) and (d).
    (ii) [Reserved]
    (28) Equipment operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
    (29) Enforcement. (i) Notwithstanding any other provision in this
implementation plan, any credible evidence or information relevant as
to whether the unit would have been in compliance with applicable
requirements if the appropriate performance or compliance test had been
performed, can be used to establish whether or not the owner or
operator has violated or is in violation of any standard or applicable
emission limit in the plan.
    (ii) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to a malfunction shall constitute a
violation of the applicable emission limit.
    (d) Measures Addressing Partial Disapproval of Portion of
Interstate Visibility Transport SIP for the 1997 8-hour ozone and
PM2.5 NAAQS. The deficiencies identified in EPA's partial
disapproval of the portion of the SIP pertaining to adequate provisions
to prohibit emissions in Arkansas from interfering with measures
required in another state to protect visibility, submitted on March 28,
2008, and supplemented on September 27, 2011 are satisfied by Sec.
52.173.
[FR Doc. 2016-22508 Filed 9-26-16; 8:45 am]
 BILLING CODE 6560-50-P


[Federal Register Volume 78, Number 248 (Thursday, December 26, 2013)]
[Proposed Rules]
[Pages 78302-78303]
[FR Doc No: 2013-30698]

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

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 71

[Docket No. FAA-2013-0990; Airspace Docket No. 13-AGL-8]
RIN 2120-AA66

Proposed Modification and Establishment of Air Traffic Service
(ATS) Routes in the Vicinity of Huntingburg, IN

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice of proposed rulemaking (NPRM).

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

SUMMARY: This action proposes to modify a VOR Federal airway (V-243)
and establish an area navigation (RNAV) route (T-325) in the vicinity
of Huntingburg, IN. The FAA is proposing this action due to the
scheduled decommissioning of the Huntingburg, IN (HNB), VHF
Omnidirectional Range (VOR)/Distance Measuring Equipment (DME) facility
that provides navigation guidance for a portion of V-243. This action
would enhance the safety and efficient management of aircraft within
the National Airspace System (NAS).

DATES: Comments must be received on or before February 10, 2014.

ADDRESSES: Send comments on this proposal to the U.S. Department of
Transportation, Docket Operations, M-30, 1200 New Jersey Avenue SE.,
West Building Ground Floor, Room W12-140, Washington, DC 20590-0001;
telephone:<PHONE_NUMBER>. You must identify FAA Docket No. FAA-2013-
0990 and Airspace Docket No. 13-AGL-8 at the beginning of your
comments. You may also submit comments through the Internet at http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: Colby Abbott, Airspace Policy and
Regulations Group, Office of Airspace Services, Federal Aviation
Administration, 800 Independence Avenue SW., Washington, DC 20591;
telephone:<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Comments Invited

    Interested parties are invited to participate in this proposed
rulemaking by submitting such written data, views, or arguments as they
may desire. Comments that provide the factual basis supporting the
views and suggestions presented are particularly helpful in developing
reasoned regulatory decisions on the proposal. Comments are
specifically invited on the overall regulatory, aeronautical, economic,
environmental, and energy-related aspects of the proposal.
    Communications should identify both docket numbers (FAA Docket No.
FAA-2013-0990 and Airspace Docket No. 13-AGL-8) and be submitted in
triplicate to the Docket Management Facility (see ADDRESSES section for
address and phone number). You may also submit comments through the
Internet at http://www.regulations.gov.
    Commenters wishing the FAA to acknowledge receipt of their comments
on this action must submit with those comments a self-addressed,
stamped postcard on which the following statement is made: ``Comments
to FAA Docket No. FAA-2013-0990 and Airspace Docket No. 13-AGL-8.'' The
postcard will be date/time stamped and returned to the commenter.
    All communications received on or before the specified comment
closing date will be considered before taking action on the proposed
rule. The proposal contained in this action may be changed in light of
comments received. All comments submitted will be available for
examination in the public docket both before and after the comment
closing date. A report summarizing each substantive public contact with
FAA personnel concerned with this rulemaking will be filed in the
docket.

Availability of NPRM's

    An electronic copy of this document may be downloaded through the
Internet at http://www.regulations.gov.
    You may review the public docket containing the proposal, any
comments received and any final disposition in person in the Dockets
Office (see ADDRESSES section for address and phone number) between
9:00 a.m. and 5:00 p.m., Monday through Friday, except Federal
holidays. An informal docket may also be examined during normal
business hours at the office of the Central Service Center, Operations
Support Group, Federal Aviation Administration, 2601 Meacham Blvd.,
Fort Worth, TX 76137.
    Persons interested in being placed on a mailing list for future
NPRMs should contact the FAA's Office of Rulemaking,<PHONE_NUMBER>,
for a copy of Advisory Circular No. 11-2A, Notice of Proposed
Rulemaking Distribution System, which describes the application
procedure.

Background

    The Huntingburg, IN, (HNB) VOR/DME facility is currently out of
service. As a result, aircraft that file V-243 are being vectored
between the Bowling Green, KY (BWG), VOR Tactical Air Navigation
(VORTAC) and the Terre Haute, IN (TTH), VORTAC. In response to the
proponent responsible for the HNB VOR/DME requesting the FAA
decommission of the facility, the FAA conducted the required non-
rulemaking study and public notice circularization actions to propose
decommissioning the facility. As a result, a determination was made to
permanently decommission the HNB VOR/DME due to maintenance issues
associated with keeping the facility operational. Additionally, the HNB
VOR/DME is not on the list of VORs planned for retention in the VOR
Minimum Operational Network (MON). Therefore, the ATS routes, fixes,
and procedures that utilize the HNB VOR/DME must be amended. With the
decommissioning of the HNB VOR/DME, the ground-based navigation aid
(NAVAID) coverage is insufficient to ensure the continuity of V-243.
The proposed modification to V-243 would result in the segment between
BWG and TTH being cancelled, but the remaining segments supported by
other NAVAIDs being retained. To cover the cancelled segment of V-243,
an RNAV route, T-325, would be established between BWG and TTH.

The Proposal

    The FAA is proposing an amendment to Title 14, Code of Federal
Regulations (14 CFR) part 71 to amend VOR Federal airway V-243 and
establish RNAV route T-325. The scheduled decommissioning of the HNB
VOR/DME facility has made this action necessary. The proposed route
modification and establishment actions are outlined below.
    V-243: V-243 currently extends between Craig, FL (CRG) and TTH. The
route segment between BWG and TTH would be cancelled. A new RNAV route,
T-325, is proposed, as described below, to replace the cancelled
Federal airway route segment, thereby furthering the

transition to an RNAV route structure in support of the NextGen
initiative.
    T-325: This proposed new route would extend between BWG and TTH to
replace the cancelled Federal airway route segment of V-243 between BWG
and TTH described above. The proposed routing of T-325 between BWG and
the APALO, IN, waypoint (WP), and between the new BUNKA, IN, WP and
TTH, are exact overlays of the route segments of V-243 proposed for
cancellation.
    The navigation aid radials cited in the proposed VOR Federal airway
route description, below, are stated relative to True north.
    Domestic VOR Federal airways are published in paragraph 6010(a) and
low altitude RNAV routes (T) are published in paragraph 6011,
respectively, of FAA Order 7400.9X dated August 7, 2013, and effective
September 15, 2013, which is incorporated by reference in 14 CFR 71.1.
The VOR Federal airway and low altitude RNAV route listed in this
document would be subsequently published in the Order.
    The FAA has determined that this proposed regulation only involves
an established body of technical regulations for which frequent and
routine amendments are necessary to keep them operationally current.
Therefore, this proposed regulation: (1) Is not a ``significant
regulatory action'' under Executive Order 12866; (2) is not a
``significant rule'' under Department of Transportation (DOT)
Regulatory Policies and Procedures (44 FR 11034; February 26, 1979);
and (3) does not warrant preparation of a regulatory evaluation as the
anticipated impact is so minimal. Since this is a routine matter that
would only affect air traffic procedures and air navigation, it is
certified that this proposed rule, when promulgated, would not have a
significant economic impact on a substantial number of small entities
under the criteria of the Regulatory Flexibility Act.
    The FAA's authority to issue rules regarding aviation safety is
found in Title 49 of the United States Code. Subtitle I, Section 106
describes the authority of the FAA Administrator. Subtitle VII,
Aviation Programs, describes in more detail the scope of the agency's
authority.
    This rulemaking is promulgated under the authority described in
Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the
FAA is charged with prescribing regulations to assign the use of the
airspace necessary to ensure the safety of aircraft and the efficient
use of airspace. This regulation is within the scope of that authority
as it would modify the route structure as necessary to preserve the
safe and efficient flow of air traffic within the NAS.

Environmental Review

    This proposal will be subject to an environmental analysis in
accordance with FAA Order 1050.1E, ``Environmental Impacts: Policies
and Procedures'' prior to any FAA final regulatory action.

List of Subjects in 14 CFR Part 71

    Airspace, Incorporation by reference, Navigation (air).

The Proposed Amendment

    In consideration of the foregoing, the Federal Aviation
Administration proposes to amend 14 CFR part 71 as follows:

PART 71--DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR
TRAFFIC SERVICE ROUTES; AND REPORTING POINTS

0
1. The authority citation for part 71 continues to read as follows:

    Authority: 49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854, 24
FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

Sec.  71.1  [Amended]

0
2. The incorporation by reference in 14 CFR 71.1 of FAA Order 7400.9X,
Airspace Designations and Reporting Points, dated August 7, 2013 and
effective September 15, 2013, is amended as follows:

Paragraph 6010 VOR Federal Airways

* * * * *

V-243 [Amended]

From Craig, FL; Waycross, GA; Vienna, GA; LaGrange, GA; INT LaGrange
342[deg] and Choo Choo, GA, 189[deg] radials; Choo Choo; to Bowling
Green, KY.
* * * * *

Paragraph 6011 United States Area Navigation Routes

* * * * *

T-325 Bowling Green, KY to Terre Haute, IN [New]

Bowling Green, KY (BWG)       VORTAC              (Lat. 36[deg]55'43'' N., long. 086[deg]26'36'' W.)
RENRO, KY                     WP                  (Lat. 37[deg]28'51'' N., long. 086[deg]39'19'' W.)
LOONE, KY                     WP                  (Lat. 37[deg]44'14'' N., long. 086[deg]45'18'' W.)
APALO, IN                     WP                  (Lat. 38[deg]00'21'' N., long. 086[deg]51'35'' W.)
BUNKA, IN                     WP                  (Lat. 39[deg]04'57'' N., long. 087[deg]09'07'' W.)
Terre Haute, IN (TTH)         VORTAC              (Lat. 39[deg]29'20'' N., long. 087[deg]14'56'' W.)

* * * * *

    Issued in Washington, DC, on December 18, 2013.
Gary A. Norek,
Manager, Airspace Policy & Regulations Group.
[FR Doc. 2013-30698 Filed 12-24-13; 8:45 am]
BILLING CODE 4910-13-P


 E.O. 12866 Meeting on EPA's Greenhouse Gas New Source

Performance Standard for Electric Generating Units Rule

Tue 02/07/2012 1:00 PM - 1:30 PM

Attendance is  for RobertJ Wayland

Chair:

<EMAIL_ADDRESS>

Location:

10103 NEOB<PHONE_NUMBER>; code 3862485)

This entry has an alarm. The alarm will go off   before the entry starts.

Required:

<EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS>Kevin Culligan/DC/USEPA/US, Peter Tsirigotis/RTP/USEPA/US, Sarah Rees/DC/USEPA/US<EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS><EMAIL_ADDRESS>RobertJ Wayland/RTP/USEPA/US

 This meeting was requested by Michael McKenna, MWR Strategies.Call-in number:<PHONE_NUMBER>; code 3862485.


[Federal Register Volume 84, Number 71 (Friday, April 12, 2019)]
[Notices]
[Page 14932]
[FR Doc No: 2019-07224]

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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Notice of Revocation of Market-Based Rate Authority and
Termination of Electric Market-Based Rate Tariff

------------------------------------------------------------------------
                                                   Docket Nos.
------------------------------------------------------------------------
Electric Quarterly Reports.............  ER02-2001-020
AmericaWide Energy, LLC................  ER11-4386-001
K&R Energy Partners LLC................  ER17-2512-000
Bluesource Energy LLC..................  ER13-1120-001
Greenbelt Energy.......................  ER11-3019-001
PJLB LLC...............................  ER15-2466-000
------------------------------------------------------------------------

    On February 25, 2019, the Commission issued an order announcing its
intent to revoke the market-based rate authority of several public
utilities that had failed to file their required Electric Quarterly
Reports.\1\ The Commission directed those public utilities to file the
required Electric Quarterly Reports within 15 days of the date of
issuance of the order or face revocation of their authority to sell
power at market-based rates and termination of their electric market-
based rate tariffs.\2\
---------------------------------------------------------------------------

    \1\ Electric Quarterly Reports, 166 FERC 61,147 (2019) (February
25 Order).
    \2\ Id. at Ordering Paragraph A.
---------------------------------------------------------------------------

    The time period for compliance with the February 25 Order has
elapsed. The above-captioned companies failed to file their delinquent
Electric Quarterly Reports. The Commission hereby revokes, effective as
of the date of issuance of this notice, the market-based rate authority
and terminates the electric market-based rate tariff of each of the
companies who are named in the caption of this order.

    Dated: April 5, 2019.
Kimberly D. Bose,
Secretary.
[FR Doc. 2019-07224 Filed 4-11-19; 8:45 am]
 BILLING CODE 6717-01-P