[Federal Register Volume 84, Number 69 (Wednesday, April 10, 2019)]
[Notices]
[Pages 14438-14441]
[FR Doc No: 2019-07049]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-85512; File No. SR-MIAX-2019-17]

Self-Regulatory Organizations; Miami International Securities
Exchange LLC; Notice of Filing and Immediate Effectiveness of a
Proposed Rule Change To Amend Its Fee Schedule

April 4, 2019.
    Pursuant to the provisions of Section 19(b)(1) of the Securities
Exchange Act of 1934 (``Act'') \1\ and Rule 19b-4 thereunder,\2\ notice
is hereby given that on March 27, 2019, Miami International Securities
Exchange LLC (``MIAX Options'' or ``Exchange'') filed with the
Securities and Exchange Commission (``Commission'') a proposed rule
change as described in Items I, II, and III below, which Items have
been prepared by the Exchange. The Commission is publishing this notice
to solicit comments on the proposed rule change from interested
persons.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
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I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    The Exchange is filing a proposal to amend the MIAX Options Fee
Schedule (the ``Fee Schedule'') to amend its fees and rebates for
Qualified Contingent Cross (``QCC'') orders and Complex Qualified
Contingent Cross (``cQCC'') orders.
    The text of the proposed rule change is available on the Exchange's
website at http://www.miaxoptions.com/rule-filings, at MIAX's principal
office, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, the Exchange included statements
concerning the purpose of and basis for the proposed rule change and
discussed any comments it received on the proposed rule change. The
text of these statements may be examined at the places specified in
Item IV below. The Exchange has prepared summaries, set forth in
sections A, B, and C below, of the most significant aspects of such
statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

1. Purpose
    The Exchange proposes to amend Sections 1(a)(vii) and (viii) of the
Fee Schedule to amend its fees and rebates for QCC and cQCC Orders. A
QCC Order is comprised of an order to buy or sell at least 1,000
contracts that is identified as being part of a qualified contingent
trade, coupled with a contra side order to buy or sell an equal number
of contracts.\3\ Currently, the Exchange assesses a transaction fee for
all types of market participants other than Priority Customer \4\ for
QCC Orders of $0.15 per contract (Priority Customer orders are assessed
a charge of $0.00 per contract) for the Initiator and the Contra-side.
In addition, the Exchange currently pays a $0.10 per contract rebate
for the initiating order, regardless of the type of market participant.
The rebate is paid to the Member \5\ that enters the order into the
System \6\, but is only paid on the initiating side of the QCC
transaction. No rebates are paid for QCC transactions in which both the
initiator and contra-side orders are from Priority Customers. The
Exchange notes that with regard to order entry, the first order
submitted into the System is marked as the initiating side and the
second order is marked as the contra side.
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    \3\ A Qualified Contingent Cross Order is comprised of an
originating order to buy or sell at least 1,000 contracts, or 10,000
mini-option contracts, that is identified as being part of a
qualified contingent trade, as that term is defined in
Interpretation and Policy .01 to Rule 516, coupled with a contra-
side order or orders totaling an equal number of contracts. See
Exchange Rule 516(j).
    \4\ The term ``Priority Customer'' means a person or entity that
(i) is not a broker or dealer in securities, and (ii) does not place
more than 390 orders in listed options per day on average during a
calendar month for its own beneficial accounts(s). See Exchange Rule
100.
    \5\ The term ``Member'' means an individual or organization
approved to exercise the trading rights associated with a Trading
Permit. Members are deemed ``members'' under the Exchange Act. See
Exchange Rule 100.
    \6\ The term ``System'' means the automated trading system used
by the Exchange for the trading of securities. See Exchange Rule
100.
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    The Exchange now proposes to increase the Per Contract Fee for
Contra-side QCC Orders for all types of market participants other than
Priority Customer from $0.15 to $0.17 (Priority Customer orders will
continue to be assessed a Per Contract Fee for Contra-side QCC Orders
of $0.00). The Exchange does not propose to change the Per Contract Fee
for Initiator QCC Orders for any market participants. In addition, the
Exchange proposes to increase the Per Contract Rebate for Initiator QCC
Orders for all types of market participants from $0.10 per contract to
$0.14 per contract. The Exchange is not proposing to change that no
rebates will be paid for QCC transactions for which both the Initiator
and Contra-side orders are Priority Customers.
    A cQCC Order is comprised of an originating complex order to buy or
sell where each component is at least 1,000 contracts that is
identified as being part of a qualified contingent trade, coupled with
a contra-side complex order or orders to sell or buy an equal number of
contracts.\7\ Currently, the Exchange assesses a transaction fee for
all types of market participants other than Priority Customer for cQCC
Orders of $0.15 per contract (Priority Customer orders are assessed a
charge of $0.00 per contract) for the Initiator and the Contra-side. In
addition, the Exchange currently pays a $0.10 per contract rebate for
the initiating order, regardless of the type of market participant. No
rebates are paid for cQCC transactions in which both the initiator and
contra-side orders are from Priority Customers. All fees and rebates
are per contract per leg. The rebate is paid to the Member that enters
the order into the System, but is only paid on the initiating side of
the cQCC transaction.
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    \7\ See Exchange Rule 518(b)(6).
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    The Exchange now proposes to increase the Per Contract Fee for
Contra-side cQCC Orders for all types of market participants other than
Priority Customer from $0.15 to $0.17 (Priority Customer orders will
continue to be assessed a Per Contract Fee for Contra-side cQCC Orders
of $0.00). The Exchange does not propose to change the Per Contract Fee
for Initiator cQCC Orders for any market participants. In addition, the
Exchange proposes to increase the Per Contract Rebate for Initiator
cQCC Orders for all types of market participants from $0.10 per
contract to $0.14 per contract. The Exchange is not proposing to change
that no rebates will be paid for cQCC transactions for which both the
initiator and contra-side orders are Priority Customers.
    The Exchange notes that QCC and cQCC Orders are excluded from: (i)
The volume threshold calculations for the Market Maker Sliding Scale;
(ii) the rebates and volume calculations as part of the Priority
Customer Rebate Program; (iii) participation in the Professional Rebate
Program; and (iv) the Marketing Fee that is assessed to Market Makers
in their assigned classes in simple or complex order executions when
the contra-party to the execution is a Priority Customer.
    The purpose of increasing the specified QCC and cQCC Order fees and
rebates is for business and competitive reasons. The Exchange believes
that it is appropriate to adjust these specified QCC and cQCC Order
fees and rebates in order to attract additional QCC and cQCC order flow
and grow its market share in this segment, through offering a higher
rebate (than the Exchange currently offers) and fees that are
consistent with other exchanges, effectively lowering the overall cost
to Members executing these orders on the Exchange. The Exchange notes
that other competing exchanges similarly provide rebates on QCC and
cQCC initiating orders,\8\ and similarly charge fees on QCC and cQCC on
Contra-side orders.\9\
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    \8\ See BOX Fee Schedule, Section I(D)(1) (a $0.14 per contract
rebate will be applied to the Agency Order where at least one party
to the QCC transaction is a Non-Public Customer); see also Cboe Fee
Schedule, ``QCC Rate Table,'' Page 5 (a $0.10 per contract credit
will be delivered to the TPH Firm that enters the order into Cboe
Command but will only be paid on the initiating side of the QCC
transaction); see also NYSE American Options Fee Schedule, Section
I.F (a $0.07 credit is applied to Floor Brokers executing 300,000 or
fewer contracts in a month and a $0.10 credit is applied to Floor
Brokers executing more than 300,000 contracts in a month); see also
Nasdaq ISE Pricing Schedule, Options 7, Section 6, Other Options
Fees and Rebate, A. QCC and Solicitation Rebate (rebates range from
$0.00 to $0.11 per contract).
    \9\ See BOX Options Market LLC (``BOX'') Fee Schedule, Section
I(D) (BOX does not charge Public Customers but charges Professional
Customers, Broker-Dealers and Market Makers $0.17 per contract on
both Agency and Contra Orders); see also Cboe Exchange, Inc.
(``Cboe'') Fee Schedule, ``QCC Rate Table,'' Page 5 (Cboe charges
non-Public Customers $0.17 per contract and does not charge Public
Customers); see also NYSE American Options Fee Schedule, Section I.F
(NYSE American charges Non-Customers $0.20 per contract, Specialists
and e-Specialists $0.13 per contract, and does not charge Customer
and Professional Customers).
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    The proposed rule change is to become operative April 1, 2019.
2. Statutory Basis
    The Exchange believes that its proposal to amend its Fee Schedule
is consistent with Section 6(b) of the Act \10\ in general, and
furthers the objectives of Section 6(b)(4) of the Act \11\ in
particular, in that it provides for the equitable allocation of
reasonable dues, fees and other charges among Exchange Members and
issuers and other persons using its facilities. The Exchange also
believes the proposal furthers the objectives of Section 6(b)(5) of the
Act \12\ in that it is designed to promote just and equitable
principles of trade, to remove

impediments to and perfect the mechanism of a free and open market and
a national market system, and, in general to protect investors and the
public interest and is not designed to permit unfair discrimination
between customer, issuers, brokers and dealers.
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    \10\ 15 U.S.C. 78f(b).
    \11\ 15 U.S.C. 78f(b)(4).
    \12\ 15 U.S.C. 78f(b)(5).
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    The Exchange believes its proposal to increase the Per Contract Fee
for Contra-side QCC and cQCC Orders is reasonable, equitable and not
unfairly discriminatory because, at the same time, the Exchange is
proposing to increase the Per Contract Rebate for Initiator QCC and
cQCC Orders for all types of market participants, effectively resulting
in a lower, all-in execution cost for Members for these orders. The
Exchange believes that the proposed fee and rebate changes are
reasonable, equitable, and not unfairly discriminatory because the
proposed fees and rebates are intended to attract additional QCC and
cQCC Order flow, grow the Exchange's market share in this segment by
effectively reducing the all-in execution cost for these orders to the
benefit of all market participants.
    Additionally, the Exchange believes that the proposed increase to
the Per Contract Fee for Contra-side QCC and cQCC Orders is not
unfairly discriminatory because the proposed fees would be charged to
all market participants other than Priority Customers. Assessing QCC
and cQCC Order rates to all market participants other than Priority
Customer is equitable and not unfairly discriminatory because Priority
Customer order flow enhances liquidity on the Exchange for the benefit
of all market participants. Specifically, Priority Customer liquidity
benefits all market participants by providing more trading
opportunities, which attracts Market Makers. An increase in the
activity of these market participants in turn facilitates tighter
spreads, which may cause an additional corresponding increase in order
flow from other market participants. By assessing a $0.00 fee for
Priority Customer orders, the Exchange believes the proposed QCC and
cQCC Order fees will not discourage the sending of Priority Customer
orders. The Exchange believes the proposed increase to the Per Contract
Fee for Contra-side QCC and cQCC Orders for all types of market
participants is reasonable because the proposed amount is in line with
the amount assessed at other Exchanges for similar transactions.\13\
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    \13\ See supra note 9.
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    The Exchange believes the proposed increase to the Per Contract
Rebate for Initiator QCC and cQCC Orders for all types of market
participants is reasonable because the rebate will offset the fee
resulting in a lower all-in execution cost for Members for these
orders, even with the proposed increase to the Per Contract Fee for
Contra-side QCC and cQCC Orders. Further, other competing exchanges
also provide rebates on the initiating order side and the proposed
rebate amount is within the range of the rebate amounts at the other
competing exchanges.\14\ The Exchange believes the proposed increase to
the rebate is equitable and not unfairly discriminatory because it
applies to all Members that enter the initiating order (except for when
both the initiator and contra-side orders are Priority Customers) and
because it is intended to incentivize the sending of more QCC and cQCC
Orders to the Exchange. The Exchange believes it is reasonable,
equitable and not unfairly discriminatory to not provide a rebate for
the Initiator for QCC and cQCC Orders for which both the Initiator and
the Contra-side are Priority Customers since Priority Customers are
already incentivized by being assessed a fee of $0.00 for submitting
QCC and cQCC Orders.
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    \14\ See supra note 8.
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B. Self-Regulatory Organization's Statement on Burden on Competition

    The Exchange does not believe that the proposed rule change will
impose any burden on competition not necessary or appropriate in
furtherance of the purposes of the Act, because the proposed rule
change applies to all Members. The Exchange believes this proposal will
not cause an unnecessary burden on intermarket competition because the
proposed changes will actually enhance the competiveness of the
Exchange relative to other exchanges which offer comparable fees and
rebates for QCC and cQCC Orders. To the extent that the proposed
changes make the Exchange a more attractive marketplace for market
participants at other exchanges, such market participants are welcome
to become market participants on the Exchange.
    The Exchange notes that it operates in a highly competitive market
in which market participants can readily favor competing venues if they
deem fee levels at a particular venue to be excessive. In such an
environment, the Exchange must continually adjust its fees to remain
competitive with other exchanges and to attract order flow to the
Exchange. The Exchange believes that the proposed rule change reflects
this competitive environment because it establishes a fee structure in
a manner that encourages market participants to direct their order
flow, to provide liquidity, and to attract additional transaction
volume to the Exchange.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants, or Others

    Written comments were neither solicited nor received.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    The foregoing rule change has become effective pursuant to Section
19(b)(3)(A)(ii) of the Act,\15\ and Rule 19b-4(f)(2) \16\ thereunder.
At any time within 60 days of the filing of the proposed rule change,
the Commission summarily may temporarily suspend such rule change if it
appears to the Commission that such action is necessary or appropriate
in the public interest, for the protection of investors, or otherwise
in furtherance of the purposes of the Act. If the Commission takes such
action, the Commission shall institute proceedings to determine whether
the proposed rule should be approved or disapproved.
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    \15\ 15 U.S.C. 78s(b)(3)(A)(ii).
    \16\ 17 CFR 240.19b-4(f)(2).
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IV. Solicitation of Comments

    Interested persons are invited to submit written data, views, and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's internet comment form (http://www.sec.gov/rules/sro.shtml); or
     Send an email to [email protected]. Please include
File Number SR-MIAX-2019-17 on the subject line.

Paper Comments

     Send paper comments in triplicate to Secretary, Securities
and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.

All submissions should refer to File Number SR-MIAX-2019-17. This file
number should be included on the subject line if email is used. To help
the Commission process and review your comments more efficiently,
please use only one method. The Commission will post all comments on
the Commission's internet website (http://www.sec.gov/rules/sro.shtml).
Copies of the submission, all subsequent

amendments, all written statements with respect to the proposed rule
change that are filed with the Commission, and all written
communications relating to the proposed rule change between the
Commission and any person, other than those that may be withheld from
the public in accordance with the provisions of 5 U.S.C. 552, will be
available for website viewing and printing in the Commission's Public
Reference Room, 100 F Street NE, Washington, DC 20549 on official
business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of
the filing also will be available for inspection and copying at the
principal office of the Exchange. All comments received will be posted
without change. Persons submitting comments are cautioned that we do
not redact or edit personal identifying information from comment
submissions. You should submit only information that you wish to make
available publicly. All submissions should refer to File Number SR-
MIAX-2019-17, and should be submitted on or before May 1, 2019.

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\17\
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    \17\ 17 CFR 200.30-3(a)(12).
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Eduardo A. Aleman,
Deputy Secretary.
[FR Doc. 2019-07049 Filed 4-9-19; 8:45 am]
 BILLING CODE 8011-01-P


[Federal Register Volume 78, Number 31 (Thursday, February 14, 2013)]
[Rules and Regulations]
[Pages 10546-10554]
[FR Doc No: 2013-03329]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R10-OAR-2011-0367; FRL-9756-8]

Approval and Promulgation of Implementation Plans; State of
Alaska; Regional Haze State Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is approving a State Implementation Plan (SIP) submittal
from the State of Alaska as meeting the requirements of Clean Air Act
(CAA) sections169A and 169B and federal regional haze regulations. The
SIP implements a regional haze program in the State of Alaska for the
first regional haze planning period, through July 31, 2018. This
submittal addresses the requirements of the Clean Air Act (CAA) and
EPA's rules that require states to prevent any future and remedy any
existing manmade impairment of visibility in mandatory Class I areas
caused by emissions of air pollutants from numerous sources located
over a wide geographic area (also referred to as the ``regional haze
program''). In this action, EPA is approving all provisions of Alaska's
Regional Haze SIP submission, including the requirements for the
calculation of baseline and natural visibility conditions, statewide
inventory of visibility-impairing pollutants, best available retrofit
technology (BART), Reasonable Progress Goals (RPGs), and Long-Term
Strategy (LTS). Additionally, EPA is approving the Alaska Department of
Environmental Conservation Best Available Retrofit Technology
regulations, and amendments to Alaska's Area Wide Pollution Control
Program for Regional Haze.

DATES: This final rule is effective March 18, 2013.

ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-R10-OAR-2011-0367. All documents in the docket are listed on
the www.regulations.gov Web site. Although listed in the index, some
information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the Internet and will be publicly available only in hard
copy form. Publicly available docket materials are available either
electronically through www.regulations.gov or in hard copy at the State
and Tribal Air Programs Unit, Office of Air Waste and Toxics, EPA
Region 10, 1200 Sixth Avenue, Seattle, WA 98101. EPA requests that if
at all possible, you contact the individual listed in the FOR FURTHER
INFORMATION CONTACT section to view the hard copy of the docket. You
may view the hard copy of the docket Monday through Friday, 8:00 a.m.
to 4:00 p.m., excluding Federal holidays.

FOR FURTHER INFORMATION CONTACT: Keith Rose, EPA Region 10, Suite 900,
Office of Air, Waste and Toxics, 1200 Sixth Avenue, Seattle, WA 98101,
(206) 553-1949.

SUPPLEMENTARY INFORMATION:

Definitions

    For the purpose of this document, we are giving meaning to certain
words or initials as follows:
    (i) The words or initials Act, CAA, or Clean Air Act mean or refer
to the Clean Air Act, unless the context indicates otherwise.
    (ii) The words EPA, we, us or our mean or refer to the United
States Environmental Protection Agency.
    (iii) The initials SIP mean or refer to State Implementation Plan.
    (iv) The words Alaska and State mean the State of Alaska.

Table of Contents

I. Background Information
II. Response to Comments
III. Final Action
IV. Statutory and Executive Orders Review

I. Background Information

    In the CAA Amendments of 1977, Congress established a program to
protect and improve visibility in the national parks and wilderness
areas. See CAA section 169A. Congress amended the visibility provisions
in the CAA in 1990 to focus attention on the problem of regional haze.
See CAA section 169B. EPA promulgated regulations in 1999 to implement
sections 169A and 169B of the Act. These regulations require states to
develop and implement plans to ensure reasonable progress toward
improving visibility in mandatory Class I Federal areas \1\ (Class I
areas). 64 FR 35714 (July 1, 1999); see also 70 FR 39104 (July 6, 2005)
and 71 FR 60612 (October 13, 2006).
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    \1\ Areas designated as mandatory Class I Federal areas consist
of national parks exceeding 6000 acres, wilderness areas and
national memorial parks exceeding 5000 acres, and all international
parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a).
In accordance with section 169A of the Clean Air Act, EPA, in
consultation with the Department of Interior, promulgated a list of
156 areas where visibility is identified as an important value. 44
FR 69122 (November 30, 1979). The extent of a mandatory Class I area
includes subsequent changes in boundaries, such as park expansions.
42 U.S.C. 7472(a). Although states and tribes may designate as Class
I additional areas which they consider to have visibility as an
important value, the requirements of the visibility program set
forth in section 169A of the Clean Air Act apply only to ``mandatory
Class I Federal areas.'' Each mandatory Class I Federal area is the
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i).
When we use the term ``Class I area'' in this action, we mean a
``mandatory Class I Federal area.''
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    On February 24, 2012, EPA published a Notice of Proposed Rulemaking
(NPR) for the State of Alaska. See 77 FR 11022. In the NPR, EPA
proposed approval of the Alaska SIP submittal that addresses regional
haze for the planning period 2008 through 2018. The Regional Haze Plan
was submitted to EPA on April 4, 2011. Specifically, EPA proposed to
approve all provisions of Alaska's April 4, 2011 Regional Haze SIP
submission. In this action, EPA is approving all provisions of Alaska's
Regional Haze SIP submission, including the requirements for the
calculation of baseline and natural visibility conditions, statewide
inventory of visibility-impairing pollutants, best available retrofit
technology (BART), Reasonable Progress Goals (RPGs), Long-Term Strategy
(LTS), ADEC's BART regulations in 18 AAC 50.260, and the amendments to
18 AAC 50.030 which adopts by reference Volume II, Section III. F. Open
Burning; Volume II, Section III. K. Area Wide Pollution Control Program
for Regional Haze; and Volume II, Appendices to Volume II.

    A detailed explanation of the requirements for regional haze SIPs
as well as EPA's analysis of Alaska's SIP submittal was provided in the
NPR and will not be repeated in detail here.
    Most of the comments received on the NPR addressed the Healy coal-
fired power plant (Healy Power Plant) located in Healy, Alaska just
five miles from Denali National Park. The Healy Power Plant consists of
2 power generating units. Unit 1 is subject to BART as a nominal 25
megawatt (MW) coal-fired electric generating unit that was initially
constructed in 1967. Unit 2, also referred to as the Healy Clean Coal
Project (HCCP), is a nominal 50 MW coal-fired electric generating unit,
was constructed in 1997, is not subject to BART, and has not operated
since 1999. Golden Valley Electric Association, Inc. (GVEA) owns and
operates Unit 1. GVEA and the Alaska Industrial Development and Export
Authority (AIDEA) currently own Unit 2. GVEA and AIDEA intend to
reactivate and/or restart Unit 2.\2\
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    \2\ Unit 2 previously went through Prevention of Significant
Deterioration (PSD) review and received an Air Quality Control
Permit issued in 1993 and amended in 1994. On February 3, 2011, ADEC
issued Final Air Quality Control Permit No. AQ0173TVPO2 to GVEA.
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    Subsequent to the publication of the NPR, the United States entered
into negotiations with GVEA and the AIDEA regarding their future work
plans and intent to operate Unit 2 at the Healy Power Plant. These
negotiations resulted in the United States, on behalf of EPA, filing a
civil complaint for injunctive relief concurrently with a consent
decree in the United States District Court for the District of
Alaska.\3\ The consent decree recognizes that GVEA and AIDEA intend to
reactivate and/or restart Unit 2 and that, as alleged in the complaint
accompanying the consent decree, the United States believes that GVEA's
and AIDEA's project at Unit 2 at the Healy Power Plant would result in
the operation of a new source or, in the alternative, a major
modification of an existing source without obtaining the necessary
permits under the Act and without the installation and operation of the
state-of-the-art controls necessary under the Act to reduce air
pollutants, particularly oxides of nitrogen (NOx) emissions from Unit
2. While not admitting liability, GVEA and AIDEA agreed to comply with
specified pollution control requirements and emissions limits for Unit
1 and Unit 2 at the Healy Power Plant.
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    \3\ United States v. Golden Valley Electric Association, Inc.
and Alaska Industrial Development and Export Authority, Civ. No.
4:12-cv-00025-RRB (D. Alaska). The United States filed an Unopposed
Motion to Enter the Consent Decree on November 14, 2012.
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    The consent decree requires GVEA to install Selective Non-Catalytic
Reduction (SNCR) on Unit 1 on or before September 30, 2015 or 18 months
after Unit 2 first fires coal, whichever is later. Additionally, by
December 31, 2022, GVEA must elect to either permanently retire Unit 1
by December 23, 2024 or install Selective Catalytic Reduction (SCR). If
GVEA elects to operate Unit 1 after December 31, 2024 it must
continuously operate the SCR and comply with specified emission limits.
The consent decree also requires GVEA and AIDEA to install SCR on Unit
2 on or before September 30, 2015 or 24 months after it first fires
coal and to comply with specified emission limits.
    The consent decree also acknowledges that EPA is currently
reviewing the Regional Haze SIP submittal from Alaska and that EPA may
consider the enforceable conditions in the consent decree when it takes
final action on that SIP submission. Additionally the consent decree
provides that nothing in the consent decree relieves GVEA or AIDEA of
their obligation to comply with all applicable state or federal, state
and local laws and regulations, specifically including the BART
requirements in the Alaska SIP or emission limits or deadlines for the
installation of pollution controls set forth in the regulations.

II. Response to Comments

    EPA received a number of comments on the proposed action to approve
the Alaska Regional Haze SIP submittal. These comments were received
from the Alaska Department of Environmental Conservation (ADEC), Sierra
Club, the National Park Service, Denali Citizens' Council, National
Parks and Conservation Association (NPCA), and Golden Valley Electric
Association (GVEA) and a number of individual commenters or members of
organizations. The individual comments included many identical or
nearly identical comment letters that were part of a public comment
campaign sponsored by Sierra Club, NPCA and CREDO. Additionally, on
June 29, 2012, Earth Justice submitted a letter to EPA on behalf of the
NPCA commenting on a number of Regional Haze SIPs, including Alaska,
that were pending review before the agency. Even though the letter was
submitted after the close of the comment period for this action, we
have taken these comments into account and are responding to those
comments relevant to this action in this notice.
    The EPA's responses to the comments are grouped into three
categories: (1) Comments on BART for Healy Unit 1; (2) Comments on
Reasonable Progress and Healy Unit 2; and (3) General Comments.

A. Comments Related to BART for Healy Unit I

    As noted above, the majority of the comments received related to
the Healy Power Plant. Numerous comments were received regarding the
selection of Selective Non-Catalytic Reduction (SNCR) rather than
Selective Catalytic Reduction (SCR) as BART for Healy Unit 1. Many of
the comments focused on the cost of controls, cost effectiveness
calculations, and the lack of an enforceable shut down date for the
unit.
    After reviewing the public comments, we performed additional
analyses of the cost effectiveness associated with the various
NOX control technologies considered by ADEC in determining
BART for Unit 1 at the Healy Power Plant. While evaluating the public
comments received on the proposed approval of the Alaska Regional Haze
SIP submission, we considered the enforceable conditions in the consent
decree and the resulting controls, limits and emission reductions. We
also considered our additional technical and cost effectiveness
analyses. The specific comments and responses are described below.
    Comment: A number of commenters asserted that BART should be SCR
for Healy Unit I. More specifically, a comment concluded that BART for
Healy Unit 1 should require the installation and operation of SCR at a
0.035 lb/mmBtu emission limit and stated that SCR technology is the
industry standard for NOX removal. Other commenters asserted
that SCR could achieve a limit between 0.05 and 0.07 lbs/mmBtu. In the
commenters' view, the State's analysis overestimated the SCR costs and
underestimated its benefits. One comment pointed to EPA's finding in
other determinations that BART for NOX is 0.05 lbs/mmBtu.
For the San Juan coal-fired generating station in New Mexico, EPA
imposed a 0.05 lbs/mmBtu BART limit, and the final permit for the
Desert Rock coal-fired generating plant imposed a limit of 0.035 lbs/
mmBtu.
    Response: EPA agrees that a more stringent emission rate is
achievable with SCR than with SNCR. A BART determination is based on
consideration of multiple factors. As explained in the NPR, the State
found that SCR is not cost effective at this facility for an 8 year
equipment lifetime. Although EPA does

not agree with the State's use of an 8 year equipment life, we are
approving the BART limit for NOX of 0.20 lbs/mmBtu based on
the installation of SNCR. After considering the comments received, EPA
calculated the cost of SCR using a 30 year lifetime for the controls in
addition to the 20 year lifetime cost calculation that EPA had
undertaken prior to the proposed action. Based on the vendor's quote
for SCR and having eliminated costs that were not consistent with EPA's
Control Cost Manual, EPA found that the cost effectiveness of SCR at
Healy Unit 1 is about $5,900/ton for a 20 year equipment lifetime, and
about $5,300/ton for a 30 year lifetime. See ``Revisions to Healy Unit
1 Cost Effectiveness Calculations'', memo from Zach Hedgpeth to Keith
Rose, October 15, 2012. Based on modeled results of visibility impacts
at different emission rates, the State also found that the incremental
visibility improvement at Denali National Park associated with an
emission rate of 0.07 lbs/mmBtu (achievable with SCR) versus the
improvement expected with an emission rate of 0.19 lb/mmBtu (achievable
with SNCR) to be relatively small (about 0.17 dv).
    In this case, as explained in more detail in the proposal, ADEC
selected the BART NOX emission limit for Healy Unit 1 based
on their consideration of the BART five-step review process,
information provided in GVEA's BART analyses, the Enviroplan GVEA Healy
BART Report, and a decision by ADEC to grant GVEA's request to allow
for some operational variability in the NOX emission rate
for Healy Unit 1. 77 FR 11034, February 24, 2012. The Regional Haze
rule grants States the authority to make the initial determination of
what constitutes BART. EPA reviews that determination to ensure that
the appropriate factors were considered and that the determination by
the State is a reasonable one.
    BART is a source by source determination based on consideration,
among other things, of the cost of controls at the source and the
visibility improvement expected to result from the installation of
controls at the source. In other words, each BART determination is made
based on a site-specific, fact-specific evaluation of the particular
BART source. Here, to name but one difference between Healy and the San
Juan Generating Station as an example, the BART unit at Healy is only
rated at 25 MW, whereas the four units at the San Juan facility are
rated at a total of 1,800 MW. The size of the unit can affect both the
cost effectiveness of controls as well as the associated air quality or
visibility impacts. As a result, the conclusion that SCR is BART for
one facility is not determinative in another BART determination. The
decision as to appropriate controls for the Desert Rock facility to
meet the requirements of another CAA program, the prevention of
significant deterioration or PSD program, is of even less relevance to
the determination of BART for Healy Unit 2.
    EPA also notes that pursuant to the consent decree described above,
no later than December 31, 2022, GVEA must decide whether it will
continue to operate Unit 1 past December 31, 2024 (the date upon which
ADEC based its cost effectiveness calculations) or whether it will
permanently retire the Unit by December 31, 2024. If GVEA elects to
continue operation after December 31, 2024, it must install SCR control
technology (or alternate control technology approved by EPA).
    Taking all this into consideration, EPA is approving the State's
NOX BART determination for Healy Unit 1 as meeting the
requirements of the CAA.
    Comment: A number of comments state that the SIP fails to
adequately address the shutdown date required as part of the BART
determination for Healy Unit 1. The commenter references the BART
guidelines statements that ``if a shutdown date affects the BART
determination, this date should be assured by a federally or state
enforceable restriction preventing further operation.'' The commenters
assert that this requirement is not addressed in the SIP submittal and
that the SIP should make clear that a shutdown date of 2024 is a
requirement for Unit 1.
    Response: As noted in the proposal, the BART Guidelines explain
that the source's remaining useful life may be considered as an element
of the cost analysis in a BART determination for a particular source
and, as the comment points out, where the retirement date affects the
BART determination, the date should be enforceable. BART Guidelines
IV.D.4.k. 70 FR 39169, July 6, 2005. In our proposed rulemaking, we
recognized that the 2024 shutdown date relied on in the State's cost
effectiveness calculation is not enforceable. Because of this, EPA
conducted additional analyses of the cost effectiveness of the
particular control technologies under consideration for Healy Unit 1
based on the estimated useful lifetime for the controls. 77 FR 11034,
February 24, 2012. For that analysis we used lifetimes of 20 years for
NOX control technologies, and 15 years for SO2
and PM control technologies. Based on additional information received
during the public comment period, we subsequently evaluated the cost
effectiveness of the NOX control technologies for Healy Unit
1 based on a 8, 15, 20 and 30 year lifetime. This analysis calculated
the cost effectiveness of SNCR, SCR, Rotating Over Fire Air (ROFA),
ROFA with Rotamix, and optimization of the low NOX burners
with a modified over-fire air system. Thus, EPA's revised cost analysis
specifically examined the cost effectiveness of SCR over both 20 and 30
year lifetimes. The revised cost analysis calculates SCR costs of about
$5,900/ton of NOX reduced for a 20 year equipment lifetime,
and $5,300/ton of NOX reduced for a 30 year equipment
lifetime. After reviewing new information submitted from the
commenters, and adjusting the assumptions in our cost effectiveness
calculations, EPA continues to find that it was reasonable for the
State to conclude that the additional cost for SCR over SNCR, even when
based on 20 year or 30 year lifetimes, is not justified.
    Our analysis confirmed that the reduced period for the remaining
useful life used by the State in its BART analysis did not change the
level of control that would reasonably be required as BART at this
facility. As explained above, based on consideration of all the BART
factors, including cost effectiveness, the remaining life, and
visibility improvement estimated to result with emission limits
associated with the different controls, the State's decision to reject
SCR is not unreasonable.
    Comment: EPA failed to conduct an adequate review of Alaska's cost
projections for SCR technology on Healy Unit 1. EPA relied on Alaska's
submission of a single vendor's quote (Fuel Tech) for the cost of SCR.
The cost of an SCR can vary significantly depending on the vendor and
its specifications, and EPA did not even review the details in this
vendor's estimate. Both the Fuel Tech report and the GVEA report use
cost assumptions that are contrary to the Cost Control Manual. EPA
cannot reject SCR on cost effectiveness grounds without more sufficient
factual support.
    Response: EPA disagrees with the comment regarding Fuel Tech's cost
quotes. It is appropriate for our cost analysis to rely, at least in
part, on the vendor's quote which is based on site specific information
and specifications. In conducting our analysis described above, we
reduced the vendor's cost estimates for a number of components,
including annual operating and maintenance (O&M) costs, NOX
emission rates for SCR, expected equipment lifetime, and costs for a
new

induced draft fan, consistent with the EPA Control Cost Manual
methodology.
    Comment: One commenter asserted that the NOX control
options evaluated for Healy Unit 1 could be implemented sooner that the
five years assumed by Alaska, in which case a 2024 shut down date may
affect the cost effectiveness of feasible emission control technologies
considered for Healy Unit 1.
    Response: EPA recognizes that the time it takes to implement
controls and the length of time the controls may operate affect the
cost effectiveness calculation and thus the ultimate BART
determination. EPA acknowledges that SNCR installations may typically
require 8 to 12 months, however, the amount of time necessary for
installation at a particular facility may vary significantly depending
on the site specific circumstances, such as weather conditions, and the
frequency and duration of maintenance periods for a particular power
plant. Additionally, as noted above, the shut down date does not affect
the BART determination here and thus the State's estimate of the time
it may take to install SNCR does not significantly affect the cost
effectiveness calculations of that technology.
    Comment: A commenter asserts that EPA's proposal does not require
meaningful emission reductions from this outdated coal plant. Further
the comment states that limits proposed for SO2 and
NOX at Healy do not represent the ``degree of reduction
achievable through the application of the best system of continuous
emission reduction'' and that EPA must impose lower BART emission
limits for SO2 and NOX at Healy Unit 1 that are
consistent with modern pollution control technology.
    Response: The State's BART determination found that 0.20 lbs/mmBtu
is the appropriate NOX limit based on continued use of the
current low NOX burners (LNB) and over fired air (OFA)
systems, and the new installation of SNCR. This limit represents a
reduction of 29% from baseline emissions of NOX from Healy
1. The BART limit for SO2 is 0.30 lb/mmBtu based on the
current Dry Sorbent Injection (DSI) system. As explained above, based
on comments received on the proposed rulemaking, EPA reevaluated the
cost effectiveness of SCR on Healy Unit 1 based on 20 and 30 year
lifetimes, and evaluated the cost effectiveness of SNCR, ROFA, ROFA
with Rotamix, and optimization of the low NOX burners with
overfire air system for 30 year lifetimes. Though some of the more
stringent control technologies for NOX (such as ROFA with
Rotamix) and for SO2 (such as DSI optimization), are
reasonable in terms of cost effectiveness, the incremental visibility
improvement achievable with these technologies, over the BART limits
determined by ADEC for Healy Unit 1, are relatively small. For example,
ROFA with Rotamix is estimated to result in just 0.166 dv more
visibility improvement than that which is expected to result from SNCR,
and DSI optimization may possibly improve visibility by just 0.25 dv.
The incremental visibility improvement at Denali National Park for SCR
over SNCR is only about 0.17 dv. EPA agrees with the State that the
additional cost of SCR over SNCR is not justified at this facility by
the relatively small incremental improvement in visibility.
    Comment: A commenter asserts that even though a NOX
emissions limit of 0.19 lb/mmBtu is far too high to be BART for Healy
Unit 1, EPA did not provide adequate justification for using a 0.20 lb/
mmBtu emissions limit instead of 0.19 lb/mmBtu. The commenter states
that Alaska found that SNCR could achieve a 0.19 lb/mmBtu emission
limit at Healy, but then allowed a 5% higher emission rate for
``operating variability'' and that EPA accepted this determination
without further analysis. There is no data showing that this need for
variability necessarily exists, and furthermore, neither Alaska nor EPA
conducted a visibility analysis based on the 0.20 lb/mmBtu emission
limit.
    Response: In the proposal, EPA explained that the State's basis for
setting the NOX limit at 0.20 lb/mmBtu rather than 0.19 lb/
mmBtu was GVEA's analysis of 5 years of 30 day rolling average
NOX and SO2 emissions from Unit 1. Based on this
data, the State determined that the small increase would appropriately
allow for operational flexibility. 77 FR 11034, February 24, 2012. EPA
found that a 5% increase in NOX emissions over the 0.19 lb/
mmBtu achievable with SNCR, to allow for operational variability of
Healy Unit 1, is reasonable and EPA has decided that the State's
determination to set the NOX limit at 0.20 lb/mmBtu is
approvable.
    Comment: The comment states that ROFA would achieve a 0.66 dv
incremental visibility improvement over the improvement associated with
SNCR at Healy 1. EPA cannot dismiss a cost-effective improvement
greater than the improvement it proposes to accept. Also, EPA
improperly rejected ROFA with Rotamix as BART based on an unclear
relationship between NOX and CO, CO2 and PM
emissions.
    Response: EPA disagrees with the comment regarding the incremental
visibility improvement between SNCR and ROFA. The SIP submittal
indicates that the incremental visibility improvement expected to
result from ROFA compared to SNCR would only be 0.049 dv, and ROFA with
Rotamix compared to SNCR to be just 0.116 dv. See Table 8-1 of Appendix
III.K.6 of the SIP submittal. EPA regards the small incremental
visibility improvements from ROFA or ROFA with Rotamix as insufficient
to justify the increased cost of either technology, regardless of the
risk of additional collateral pollutant (CO, CO2, and PM)
emission increases.
    Comment: GVEA agrees with Alaska and EPA that the BART process
results in an emissions limit for NOX based on the limit
that can be achieved with SNCR, and that SCR would not be cost
effective.
    Response: As explained above, the State's conclusion regarding the
BART limit for Healy Unit 1 is reasonable. In this action EPA is
approving Alaska's determination that the NOX BART emission
limit for Healy Unit 1 is 0.20 lb/mmBtu.
    Comment: EPA proposed that the current sulfur dioxide emissions
limit of 0.30 lb/mmBtu is BART. EPA erroneously rejected optimization
of the DSI system, which could achieve a 0.18 lb/mmBtu emission limit.
This lower emissions limit would result in significant reduction in
sulfur dioxide emissions and greatly improve visibility at Denali. EPA
found that DSI optimization is cost-effective; however, it rejected
this more stringent limit based on its concerns about a ``brown plume''
effect. The commenter further asserts there is no demonstration that
the rapid conversion to NO2 nearer the source will make any
difference to the visibility in Denali. It is improper for EPA to
dismiss this control possibility based on anecdotal evidence, which is
not even linked to plant-specific characteristics present at Healy. The
comment suggests that a short term pilot study be made part of the SIP
to test the relationship between mercury emissions and sorbent
injection rates.
    Response: For the reasons explained in the SIP submittal and
summarized in the proposal, after considering all the BART factors, the
State's BART analysis for SO2 at Healy Unit 1 found that the
current DSI control technology with a limit of 0.30 lb/mmBtu is BART
for SO2. The State's analysis found that increased sorbent
injection, at a cost of $3578/ton of SO2 removed would
result in a potential visibility improvement of 0.25 dv but could also
cause a visibility impairing brown plume which would interfere with
rather than improve visibility in the nearby Denali National Park. EPA
does not consider this

amount of potential improvement in visibility achievable by optimizing
the existing DSI system when coupled with the potential for brown plume
to provide sufficient basis to disapprove the State's SO2
BART determination for Healy Unit 1.
    The State retains the ability to consider requiring a pilot study
in the future. The results of such a study, along with available
information to better evaluate the potential for brown plume, could be
used to further evaluate optimizing DSI as potential control technology
when the State evaluates reasonable progress in the next planning
period for regional haze. The other SO2 control options
analyzed, a spray dryer and wet limestone flue gas desulfurization,
were considered not cost effective. See 77 FR 11034, February 24, 2012.
Given these considerations, EPA has decided that the State's
SO2 BART determination for Healy Unit 1 is reasonable.
    Comment: One commenter suggested that the effectiveness of a Lime
Spray Dryer (LSD) was underestimated and recommended that EPA require
GVEA to evaluate the LSD SO2 treatment technology with plume
reheat to see if the efficiency of the existing DSI system can be
increased.
    Response: EPA does not believe this further analysis is required.
Plume reheat would require additional fuel combustion. This would
increase CO2 emissions and add to the costs of a wet scrubbing control
system.

B. Comments Related to the State's Reasonable Progress Demonstration
and Healy Unit 2

    A number of comments were received regarding the State's analysis
of future sources that may impact visibility in Denali National Park.
The commenters were particularly concerned with the emissions
associated with Healy Unit 2 and contend its emissions should have been
included in the State's reasonable progress and long term strategy
analysis and determinations.
    Comment: Commenters claim that, in general, the SIP does little to
address additional emissions that are reasonably foreseeable. A number
of industrial developments are currently moving forward in the Denali
region, and are not even mentioned in Alaska's SIP. At a minimum, the
SIP should address how it will deal with future emissions and
construction activities occurring prior to the SIP's next review phase
that would affect Denali's Class I Airshed. The commenters state that
it is not prudent to delay this planning to the future.
    Response: Contrary to the comments, the State in its SIP did
account for future growth in emissions from industrial sources through
2018 by considering and evaluating population growth factors. The State
used population projections compiled by the Alaska Department of Labor
and Workforce Development (DOLWD) at five-year intervals through 2030
by individual borough and census areas to grow 2002 baseline activity
to 2018 for most of the source categories. In addition, emission
factors specific to calendar year 2018 were also developed for
stationary point sources affected by regulatory control programs and
technology improvements. The SIP submittal does not consider emissions
from specific industrial projects that are planned for the future, or
permitted point sources that are not currently operating but which may
be in operation in 2018. Emissions from any such point sources will be
considered and evaluated in future updates to the Alaska Regional Haze
plan as they come into operation. A full description of the emission
sources included in the 2018 projected inventory can be found in
section III.K.5 of the SIP submittal.
    Comment: Multiple commenters claim that the failure to account for
emissions from Healy Unit 2 results in an inaccurate conclusion that
the State is on the ``glide path'' to achieving its reasonable progress
goals. Alaska failed to include Healy Unit 2 in its reasonable progress
analysis, a facility which is projected to come on line in the near
term, and that because Unit 2 is in the same footprint as Healy Unit 1
its emissions may prevent reasonable progress at Denali. The commenters
assert that EPA must issue adequate emission limits for Healy Unit 2 to
ensure reasonable progress not be thwarted by anticipated haze causing
emissions.
    Response: EPA recognizes that the Alaska Regional Haze SIP
submittal does not address future emissions from Healy Unit 2 and that
if, or when, it begins operating its emissions could influence Alaska's
ability to achieve their reasonable progress goals. As explained above,
Healy Unit 2, was originally permitted in 1994, operated briefly for
testing in the late 1990's and has not operated at all since December
1999. It is a 50 MW non-BART unit. Unit 2 was not operating during the
baseline period and its emissions were not included in the State's
baseline emissions inventory. Recently, as further explained in the
proposal, ADEC issued a renewed Title 5 permit to GVEA allowing future
operation at Unit 2. However its future emissions have not been modeled
and its potential visibility impact have not been determined at this
time. 77 FR 11036, February 24, 2012. The Unit is still not operating.
In the proposal, EPA indicated that it would consider additional
relevant information it receives during public comment period regarding
the emissions or visibility impact of this source as it relates to
Alaska's reasonable progress goals. We did not receive additional
specific information regarding Healy Unit 2 emissions or its future
visibility impacts. The potential emissions for Healy Unit 2 have not
been modeled therefore we cannot accurately assess the Unit's potential
future visibility impacts.
    In its SIP submittal, should Unit 2 be restarted, Alaska has
committed to reassess the need for further control on the source during
the five-year review to determine whether additional emission
reductions would improve visibility in Class I areas in the next
planning period. Thus, more specifically, in order to determine the
affect of any such emissions from Healy Unit 2 on the glide path, the
State will need to assess its emissions in future reasonable progress
evaluations conducted pursuant to 40 CFR 51.308(g).
    Additionally, EPA notes that the U.S. v. GVEA and AIDEA consent
decree acknowledges that the anticipated operation of Unit 2 could be
viewed as the operation of a new source and imposes additional
enforceable requirements on Unit 2 that go beyond the Regional Haze SIP
requirements. As described more fully above, pursuant to the consent
decree, GVEA is subject to SCR installation requirements, strict
NOX emission limits and associated monitoring recordkeeping
and reporting requirements. Additionally, the consent decree
establishes declining NOX emission limitations for both Unit
1 and Unit 2. Its emissions will be well controlled. It is unlikely
that even if the State were to include the future emissions from Healy
Unit 2 in its reasonable progress analysis that controls beyond those
required under the consent decree would be necessary under the
reasonable progress provisions in the regional haze rule.
    In consideration of a number of factors including the current non-
operational status of Healy Unit 2, the uncertainty of its future
emissions, the State's commitment to assess its emissions during the 5-
year review and the enforceable terms and conditions in the U.S. v.
GVEA and AIDEA consent decree, EPA approves Alaska's treatment of Healy
Unit 2 in its reasonable progress determination as proposed.

    Comment: GVEA agrees with Alaska and EPA that the exact amount of
impact from any operation of Healy Unit 2 cannot be determined at this
time and that it is not reasonable to require additional controls on
Healy Unit 2. However, GVEA does not agree with the State's assumption
that it will necessarily have to ``consider'' Healy Unit 2 in its
reasonable progress evaluation.
    Response: As explained above, Alaska has committed to assess
emissions from Healy Unit 2 in the reasonable progress evaluation in
its 5-year assessment and in its 2018 Regional Haze SIP submittal.
Given the location of Healy Unit 2, EPA believes that Alaska's
commitment is not only appropriate but is necessary to ensure
reasonable progress. EPA is approving Alaska's treatment of Healy Unit
2 in its reasonable progress determination as proposed.
    Comment: Alaska's LTS fails to satisfy obligations under the
Regional Haze Rule toward achieving natural visibility conditions at
Denali. The Clean Air Act requires states to submit implementation
plans that ``contain such emission limits, schedules of compliance and
other measures as may be necessary to make reasonable progress toward
meeting the national goal'' of achieving natural visibility conditions
at all Class I Areas.
    Response: In developing a LTS, the Regional Haze Rule requires that
states address six topics: (1) Ongoing Air Pollution Control Programs,
(2) Measures to Mitigate Impacts of Construction Activities, (3)
Emission Limitations and Schedules for Compliance, (4) Source
Retirement and Replacement Schedules, (5) Smoke Management Techniques
for Agricultural and Forestry Burning, and (6) Enforceability of
Emission Limitations and Control Measures. In its proposed rulemaking,
EPA found that the Alaska Regional Haze SIP submittal adequately
addressed all six topics, and proposed to find that the LTS as a whole
provided sufficient measures to ensure that Alaska will meet its
emission reduction obligations.
    According to ADEC's reasonable progress analysis, there is no
statistically significant difference between the visibility improvement
predicted by the Weighted Emission Potential (WEP) analysis for 2018
and the 2018 visibility target needed to achieve the uniform rate of
progress (URP) to meet natural visibility conditions by 2064 for each
Alaska Class I area. ADEC reached this conclusion by showing that the
WEP results for 2018 fall within the 95 percent confidence limits of
the 2018 visibility goal for each Class I area. See Section 9.E of the
SIP submission. EPA believes that the reasonable progress goals
established by Alaska for its Class I areas are reasonable. EPA finds
that controls identified in the submittal, including the elements
identified in the LTS portion of the Alaska Regional Haze SIP, along
with additional controls on Healy Unit 2 required as a result of the
consent decree, will provide reasonable progress towards attaining the
goal of achieving natural visibility conditions in Alaska's Class I
areas by 2064.

C. General Comments Regarding Visibility and Air Quality in Alaska

    EPA also received a number of general comments on a range of topics
including the purpose of the Clean Air Act, the need to protect the
visibility in Denali National Park, the impact of pollution on public
health, the importance of visibility to tourism in Alaska, motoring
techniques and coal combustion and other generalized concerns or
comments.
    Comment: EPA received numerous comments asking EPA to ensure clean
air in Denali National Park, Fairbanks, Anchorage, and throughout the
region, and asking EPA to strengthen Alaska's regional haze plan.
    Response: EPA's final action in this rulemaking to approve Alaska's
Regional Haze SIP will result in cleaner air in Denali National Park
and throughout the region by placing stricter emission limits on
sources that contribute to regional haze. The objective of the regional
haze program is to improve and protect visibility in national parks and
wilderness areas through successive 10-year regional haze plans
developed by the states. The Alaska Regional Haze plan, as approved in
this action, establishes emission limits, through BART. For instance,
Healy Unit 1 will have new NOx emission limits that are expected to
result in a significant improvement in visibility in Denali National
Park. The combined effect of all of the elements in the State's long
term strategy that were described in the NPR, including the emission
limits established for Healy, will result in improved visibility in
Denali National Park, and cleaner air throughout the region.
    Comment: EPA received numerous comments on the health effects,
primarily asthma, that are associated with air pollution, and urged EPA
to place tighter controls on sources of air pollution in Alaska.
    Response: We appreciate the commenters' concerns regarding the
potential adverse health effects of air pollution. We agree that the
same emissions that cause visibility impairment can also cause
respiratory problems, such as decreased lung function, aggravated
asthma, and bronchitis. Although our action addresses visibility
impairment, we note that there is the potential for improvements in
human health through reductions in regional concentrations of
visibility impairing pollutants.
    Comment: We received a few comments saying that the purpose of the
Clean Air Act is to protect our nation's air quality, especially at
special places like Denali, the only national park in Alaska classified
as a Class 1 area. These comments urged EPA not to allow air quality to
degrade in the Denali National Park Class I area. We also received
comments urging EPA to preserve the views at Denali National Park, and
to ensure that tourism to pristine areas in Alaska is not adversely
impacted by regional haze. Additional comments were submitted stating
that Healy Units 1 and 2 are less than five miles from Denali, and are
not being required to reduce emission enough to significantly decrease
their visibility impacts on the park. These comments stated that modern
and effective controls should be required to stem the haze pollution
from Healy Unit 1 and Unit 2.
    Response: EPA agrees that it is important to reduce the visibility
and health impacts from man-made pollution at the Federal Class I
Areas, such as Denali National Park. EPA's approval of Alaska's
Regional Haze SIP will result in significant reductions in emissions
and improvement in visibility in the State. This represents only the
first step towards meeting the national goal of natural conditions in
federal Class I Areas. The State's actions being approved in this
rulemaking are the first in a series of actions that will be taken over
the next several decades to improve visibility in Alaska Class I areas.
    EPA also recognizes the role that protecting visibility in national
parks and wilderness areas in Alaska has to tourism throughout the
state. Reducing regional haze will help ensure that views in these
parks and wilderness areas are preserved, and will continue to support
tourism. We also appreciate the concern regarding Healy's proximity to
Denali National Park. With approval of the State's BART determination
for Healy, and as a result of the enforceable terms and conditions in
the U.S. v. GVEA and AIDEA consent decree, the facility will be subject
to modern and effective pollution control requirements and its
emissions will be reduced. Additionally, the State will continue to

assess its control strategies and visibility goals in future regional
haze reviews. Additional more detailed responses to comments regarding
controls on the Healy Power Plant are addressed above.
    Comment: We received a comment regarding the Denali IMPROVE
monitoring site. The commenter stated that while it appears that the
Alaska Regional Haze SIP submittal equally considers data from both the
Denali Headquarters and Trapper Creek monitoring sites, it does not
explicitly state that this is the case. The SIP submittal describes the
Denali Headquarters IMPROVE site as now a ``protocol site'' but does
not define the difference between a protocol and primary site, or
whether data from a primary site would be given preference over a
protocol site. Monitoring pollutants affecting visibility in Denali
should not only consider pollutant information south of the Alaska
Range, but pollutants from nearby major sources such as the Healy Power
Plant, and sources in the Fairbanks area and both sites should be given
equal consideration in the future.
    Response: According to the information on the national IMPROVE Web
site (http://vista.cira.colostate.edu/improve/Overview/IMPROVENetworkExp.htm), the Denali Headquarters site was designated as
the ``IMPROVE'' site, and the Trapper Creek site was designated as a
``protocol'' site when the IMPROVE network was expanded in 2002. EPA
agrees with these designations, and also agrees that data from both the
Denali Headquarters site and the Trapper Creek site should be used by
Alaska to determine future progress toward visibility improvement goals
in Denali National Park.
    Comment: One commenter recommended that a more refined, receptor-
by-receptor modeling analysis be conducted throughout Denali National
Park to determine if visibility improvements greater than those
predicted by GVEA for the Healy Unit 1 would be found.
    Response: GVEA used the CALPUFF model to estimate the visibility
impacts of Healy Unit 1 on Denali National Park. Alaska found that the
CALPUFF modeling methods and related model input options used by GVEA
were consistent with the WRAP CALPUFF modeling protocol and related
BART guidance. The receptors used in the CALPUFF modeling were placed
at uniform receptor spacing along the boundary and in the interior of
Denali National Park, and were based on the National Park Service
database for Class I area modeling receptors, found at: (http://www2.nature.nps.gov/air/maps/Receptors/index.cfm).
    EPA believes that the modeling approach taken to determine
visibility impacts from Healy Unit 1 is consistent with the BART
modeling guidance and does not believe that including additional
receptors in the CALPUFF modeling runs would have identified any
greater visibility improvements for any given emission limits than
those identified in the GVEA modeling results.
    Comment: GVEA commented regarding the contributions from wildfires
and out of State sources and supported the finding that natural
wildfires inside Alaska are the primary contributors to regional haze
at Denali National Park. GVEA also submits that the sources outside and
upwind of Alaska are significant contributors to visibility impairment,
and if visibility is not improving as planned, the monitoring data
should be evaluated to quantify not only the impacts from natural
wildfires, but from the out-of-state, upwind air pollution as well.
    Response: The Alaska Regional Haze SIP submittal identifies organic
carbon emissions from natural wildfires as the primary contributor to
visibility impairment on the 20% worst days in Denali National Park.
More specifically, the WEP analysis used by Alaska found that
approximately 97% of the fine particulates causing visibility
impairment on the 20% worst days in Denali National Park were composed
of organic carbon from natural fires. Alaska will also review
monitoring data prior to the five-year SIP update to determine progress
towards the 2018 visibility goals in each Class I area. Alaska may
decide at that time if additional source controls are necessary to
achieve the 2018 goals. In addition, Alaska will undertake a
comprehensive review of control strategies and visibility goals every
10 years. These subsequent reviews will evaluate whether this
assessment of the dominance of fire continues to be the case.
    Comment: EPA received numerous comments that emissions from coal
combustion have impacts on visibility, human health, salmon, and
climate change through emissions of carbon dioxide. The comments urged
EPA to hold Alaska coal combustion sources, particularly utilities, to
the highest emission standards with the most modern pollution control
technology.
    Response: The primary emission control action pertaining to coal-
fired power plants taken in this final action is to establish BART
emission limits on Healy Unit 1. The emission reductions achieved
through BART for Healy Unit 1 will result in a decrease of nitrogen
oxides emissions from 0.28 lb/mmBtu to 0.20 lb/mmBtu. Additionally it
is noteworthy that, additional reductions in NOx, SO2 and PM
emissions will be achieved through the emission limits on Healy Unit 1
and Unit 2 set forth in the US v. GVEA and AIDEA consent decree
discussed above.
    Comment: A comment contends that it is unclear whether this SIP
fully reviews and addresses all options for control of anthropogenic
pollutants that impair visibility in Denali's Class I airshed. For
example, while the SIP references coal combustion as a source of
Organic Matter Carbon (OMC) and Elemental Carbon (EC), it attributes
all OMC and EC in the Denali region to wildfires. Considering that OMC
and EC are present year-round, it's unclear why the state has avoided
mention of OMC and EC's relationship to the Healy Power Plant and
combustion related to power generation and home heating in and near the
Denali Borough. This SIP should acknowledge the presence of OMC and EC
from anthropogenic sources in and near the Denali Borough (and within
the state), and should consider methods to control OMC and EC
pollutants related to anthropogenic sources.
    Response: As explained in the SIP submittal Chapter III.K.4 of the
SIP, the major sources of OMC in Alaska are wildland fires (forest,
wetland, and tundra) and biogenic aerosols produced by natural
vegetation, and that wildfires in Alaska occur mostly during the May-
August fire season. The SIP submittal also states that in Alaska,
severe wildfires create a significant amount of EC, and that there is
significant amount of elemental carbon aerosols reaching the state from
Asia and Europe. Chapter III.K.4 of the SIP submittal also explains
that wildfire-related OMC is the largest contributor of fine
particulates on the 20% worst days at the Denali IMPROVE sites,
particularly during the spring and summer months. Table III.K.7-1 of
the SIP summarizes the Weighted Emission Potential (WEP) analysis
results from the top three boroughs for each pollutant on the 20% worst
days in Denali. This table shows that approximately 97% of the fine
particulates (which includes particulates composed of OMC and EC) on
the 20% worst visibility days at Denali National Park are due to
natural fires in the Yukon Koyukuk, Southeast Fairbanks, and the
Fairbanks North Star boroughs. The WEP analysis used by Alaska was
developed by the WRAP as a screening tool for states to decide which
source regions have the potential

to contribute to haze formation at specific Class I areas. This method
does not account for chemistry and removal processes in the atmosphere.
Instead, the WEP analysis relies on an integration of gridded emissions
data, meteorological back trajectory residence time data, a one-over-
distance factor to approximate deposition and dispersion, and a
normalization of the final results. The gridded emission data used by
Alaska was consolidated into the following sources categories:
Commercial marine vessels, natural fires, non-road mobile, on-road
mobile, point, and stationary area sources. Therefore, the WEP analysis
identified the OMC and EC contribution from the above man-made source
categories, but was not able to determine the contribution of any
single point source, such as the Healy Power Plant, or a subcategory of
an area source, such as home heating sources. So while the SIP
submission does not specifically identify the contribution of coal-
combustion sources to visibility impairment in Denali National Park, it
does demonstrate that wildfires are the major source of
PM2.5 in the State, that wildfires have the greatest
potential to impact visibility in Denali, and that wildfires are the
major source of OMC on the worst visibility days in Denali National
Park. Alaska may choose to use a more sophisticated chemical-speciation
tracer analysis, such as the PM Source Apportionment Technology (PSAT)
analysis developed by the WRAP (see the WRAP TSD, Chapter 6A), in the
future to determine the contributions from specific point sources or
subcategories of sources.
    Comment: There were a few comments on topics not related to the
proposal. These included comments regarding the regulation of mining
activities in Alaska and mercury monitoring in Alaska.
    Response: These comments may be important topics for discussion but
they are not related to the proposed action.
    Comment: We also received a comment urging the use of alternative
forms of energy, such as reducing emissions from motor vehicles by
shifting to alcohol fuels.
    Response: The State has the option of pursuing cleaner forms of
alternative energy to reduce emissions that cause regional haze in its
Class I areas. Alaska decided not to implement the use of renewable
energy in this Regional Haze SIP but may chose to do so in future SIPs.
    Comment: ADEC commented that it appreciates EPA's thorough review
of the Regional Haze SIP submittal and supports EPA's action to approve
the plan and encouraged EPA to finalize its approval of the Alaska
Regional Haze SIP as meeting the requirements of the Clean Air Act,
Sections 169A and 169B, and the federal Regulations at 40 CFR 51.308.
    Response: EPA appreciates this comment supporting our proposed
action.

III. Final Action

    EPA is approving the Alaska Regional Haze plan, submitted on April
4, 2011, as meeting the requirements set forth in sections 169A and
169B of the Act and in 40 CFR 51.308 regarding Regional Haze. In this
action, EPA is approving all provisions of Alaska's Regional Haze SIP
submission, including the requirements for the calculation of baseline
and natural visibility conditions, statewide inventory of visibility-
impairing pollutants, best available retrofit technology (BART),
Reasonable Progress Goals (RPGs), and Long-Term Strategy (LTS).
Additionally, EPA is approving the Alaska Department of Environmental
Conservation Best Available Retrofit Technology regulations at 18 AAC
50.260, and amendments to 18 AAC 50.030 which adopts by reference
Volume II, Section III.F. Open Burning; and Volume II, Section III.K.
Area Wide Pollution Control Program for Regional Haze.

IV. Statutory and Executive Orders Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is not a ``significant regulatory action'' and therefore is not
subject to review by the Office of Management and Budget. For this
reason, this action is also not subject to Executive Order 13211,
``Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use'' (66 FR 28355, May 22, 2001). This action
merely approves state law as meeting Federal requirements and imposes
no additional requirements beyond those imposed by state law.
Accordingly, the Administrator certifies that this rule will not have a
significant economic impact on a substantial number of small entities
under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). Because
this rule approves pre-existing requirements under state law and does
not impose any additional enforceable duty beyond that required by
state law, it does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4).
    In addition, this rule does not have tribal implications as
specified by Executive Order 13175 (65 FR 67249, November 9, 2000),
because the rule neither imposes substantial direct compliance costs on
tribal governments, nor preempts tribal law. Therefore, the
requirements of section 5(b) and 5(c) of the Executive Order do not
apply to this rule. Consistent with EPA policy, EPA nonetheless
provided a consultation opportunity to Tribes in Alaska located near
the affected Class I areas in letters dated December 30, 2011. EPA
received no requests for consultation in response to these letters.
    This action also does not have Federalism implications because it
does 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, as specified in Executive Order 13132 (64 FR 43255, August
10, 1999). This action merely approves a state rule implementing a
Federal standard, and does not alter the relationship or the
distribution of power and responsibilities established in the CAA. This
rule also is not subject to Executive Order 13045 ``Protection of
Children from Environmental Health Risks and Safety Risks'' (62 FR
19885, April 23, 1997), because it approves a state rule implementing a
Federal standard.
    In reviewing SIP submissions, EPA's role is to approve state
choices, provided that they meet the criteria of the CAA. In this
context, in the absence of a prior existing requirement for the State
to use voluntary consensus standards (VCS), EPA has no authority to
disapprove a SIP submission for failure to use VCS. It would thus be
inconsistent with applicable law for EPA, when it reviews a SIP
submission, to use VCS in place of a SIP submission that otherwise
satisfies the provisions of the CAA. Thus, the requirements of section
12(d) of the National Technology Transfer and Advancement Act of 1995
(15 U.S.C. 272 note) do not apply. This rule does not impose an
information collection burden under the provisions of the Paperwork
Reduction Act of 1995 (44 U.S.C. 3501 et seq.).
    The Congressional Review Act, 5 U.S.C. section 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 rule 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. section 804(2).
    Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by April 15, 2013. Filing a petition for
reconsideration by the Administrator of this final rule does not affect
the finality of this rule 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 section 307(b)(2))

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Nitrogen dioxide, Particulate
matter, Reporting and recordkeeping requirements, Sulfur oxides,
Visibility, and Volatile organic compounds.

     Dated: November 15, 2012.
Dennis J. McLerran,
Regional Administrator, Region 10.
    Part 52, chapter I, title 40 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 C--Alaska

0
2. Section 52.70 is amended by adding paragraph (c)(41) to read as
follows:

Sec.  52.70  Identification of plan.

* * * * *
    (c) * * *
    (41) On April 4, 2011, the Alaska Department of Environmental
Conservation submitted a SIP revision to meet the regional haze
requirements of Clean Air Act sections 169A and 169B, and Federal
Regulations 40 CFR 51.308, to implement a regional haze program in the
State of Alaska for the first planning period through July 31, 2018.
    (i) Incorporation by reference.
    (A) The following revised section of the Alaska Administrative
Rules: Alaska Department of Environmental Conservation, 18 AAC 50.260,
``Guidelines for Best Available Retrofit Technology under the Regional
Haze Rule'', state effective date December 30, 2007.
    (ii) Additional material.
    (A) The following section of ADEC's air quality control
regulations: 18 AAC 50.030 State Air Quality Control Plan; state
effective date February 11, 2011; Volume II, Section III. F. Open
Burning; and Volume II, Section III. K. Area Wide Pollution Control
Program for Regional Haze.

0
3. Section 52.73 is amended by adding paragraph (g) to read as follows:

Sec.  52.73  Approval of plans.

* * * * *
    (g) Visibility protection. (1) EPA approves the Regional Haze SIP
revision submitted by the Alaska Department of Environmental
Conservation on April 4, 2011, as meeting the requirements of Clean Air
Act sections 169A and 169B, and Federal Regulations 40 CFR 51.308 to
implement a regional haze program in the State of Alaska for the first
planning period through July 31, 2018.
    (2) [Reserved]

[FR Doc. 2013-03329 Filed 2-13-13; 8:45 am]
BILLING CODE 6560-50-P