[Federal Register: May 8, 2007 (Volume 72, Number 88)]
[Rules and Regulations]
[Page 25975-25978]
[DOCID:fr08my07-16]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R07-OAR-2007-0249; FRL-8310-6]

Approval and Promulgation of Implementation Plans; Missouri;
Interstate Transport of Pollution

AGENCY: Environmental Protection Agency (EPA).

ACTION: Direct final rule.

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SUMMARY: EPA is revising the Missouri State Implementation Plan (SIP)
for the purpose of approving the Missouri Department of Natural
Resources' (MDNR) actions to address requirements of section
110(a)(2)(D)(i) of the Clean Air Act. Section 110(a)(2)(D)(i) requires
each state to submit a SIP that prohibits emissions that adversely
affect another state's air quality through interstate transport. MDNR
has adequately addressed the four distinct elements related to the
impact of interstate transport of air pollutants. These include
prohibiting significant contribution to downwind nonattainment of the
National Ambient Air Quality Standards (NAAQS), interference with
maintenance of the NAAQS, interference with plans in

another state to prevent significant deterioration of air quality, and
interference with efforts of other states to protect visibility. The
requirements for public notification were also met by MDNR.

DATES: This direct final rule will be effective July 9, 2007, without
further notice, unless EPA receives adverse comment by June 7, 2007. If
adverse comment is received, EPA will publish a timely withdrawal of
the direct final rule in the Federal Register informing the public that
the rule will not take effect.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R07-
OAR-2007-0249, by one of the following methods:
    1. http://www.regulations.gov. Follow the on-line instructions for

submitting comments.
    2. E-mail<EMAIL_ADDRESS>    3. Mail: Heather Hamilton, Environmental Protection Agency, Air
Planning and Development Branch, 901 North 5th Street, Kansas City,
Kansas 66101.
    4. Hand Delivery or Courier: Deliver your comments to Heather
Hamilton, Environmental Protection Agency, Air Planning and Development
Branch, 901 North 5th Street, Kansas City, Kansas 66101.
    Instructions: Direct your comments to Docket ID No. EPA-R07-OAR-
2007-0249. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information

provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit through http://www.regulations.gov
 or e-mail information that you consider to be CBI

or otherwise protected. The http://www.regulations.gov Web site is an

``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through http://www.regulations.gov, your e-mail address will be

automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
    Docket: All documents in the electronic docket are listed in the
http://www.regulations.gov index. Although listed in the index, some

information is not publicly available, i.e., 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 in http://www.regulations.gov
 or in hard copy at the Environmental Protection

Agency, Air Planning and Development Branch, 901 North 5th Street,
Kansas City, Kansas 66101. The Regional Office's official hours of
business are Monday through Friday, 8 p.m. to 4:30, excluding Federal
holidays. The interested persons wanting to examine these documents
should make an appointment with the office at least 24 hours in
advance.

FOR FURTHER INFORMATION CONTACT: Heather Hamilton at<PHONE_NUMBER>, or
by e-mail at<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Throughout this document whenever ``we,''
``us,'' or ``our'' is used, we mean EPA. This section provides
additional information by addressing the following questions:

    What is being addressed in this document?
    What action is EPA taking?

What is being addressed in this document?

    EPA is revising the SIP for the purpose of approving MDNR's actions
to address the requirements of the Clean Air Act (CAA) section
110(a)(2)(D)(i). In its request to revise the SIP, Missouri has also
outlined the other provisions of section 110(a)(2) (the infrastructure
SIP, to support the implementation, maintenance and enforcement of the
NAAQS) and described how the state implements the infrastructure
requirements. In this rule, EPA is only acting on the portion of the
SIP addressing section 110(a)(2)(D)(i). EPA is taking separate action
on this portion of the submission because EPA is obligated to
promulgate a Federal plan if the state plan is not approved by May 27,
2007. EPA intends to act on the other portion of the submission in the
near future.
    Section 110(a)(2)(D)(i) requires each state to submit a SIP that
prohibits emissions that adversely affect another state's air quality
through interstate transport. The SIP must prevent sources in the state
from emitting pollutants in amounts which will: (1) Contribute
significantly to nonattainment of the NAAQS, (2) interfere with
maintenance of the NAAQS in another state, (3) interfere with
provisions to prevent significant deterioration of air quality, and (4)
interfere with efforts to protect visibility.
    The EPA issued guidance on August 15, 2006, relating to SIP
submissions to meet the requirements of section 110(a)(2)(D)(i). As
discussed below, Missouri's analysis of its SIP with respect to the
statutory requirements is consistent with the guidance.
    The MDNR has addressed the first two of these elements by the
adoption of the Clean Air Interstate Rule (CAIR) model rules that
require Missouri sources to participate in the EPA-administered cap and
trade program for nitrogen oxides (NOX) and sulfur dioxide.
Participation in this program will prohibit emissions from the state
that would contribute significantly to nonattainment or interfere with
the maintenance of the particulate matter and ozone NAAQS in any
downwind state. As previously determined by EPA, submittal of a SIP
revision to satisfy CAIR (submitted to EPA on March 13, 2007) also
fulfills the state's obligations that pertain to ``significant
contribution'' and ``interference with maintenance'' (70 FR 25162). It
should be noted that EPA will act on Missouri's CAIR SIP in a separate
rulemaking, and this action makes no conclusion with respect to
approvability of that submittal.
    The third element MDNR addressed was prevention of significant
deterioration (PSD). For 8-hour ozone, the state has met the
obligation, consistent with EPA's guidance described previously, by
confirming that major sources in the state are currently subject to PSD
programs that implement the 8-hour ozone standard and that the state is
on track to meet the June 15, 2007, deadline for SIP submissions
adopting any relevant requirements of the Phase II ozone implementation
rule. For PM2.5, the state has confirmed that the state's
PSD program is being implemented in accordance with EPA's interim
guidance calling for the use of PM10 as a surrogate for
PM2.5 for the purposes of PSD and nonattainment New Source
Review (NSR). Controlling PM10 emissions and analyzing
impacts on the environment serves as a surrogate approach for reducing
PM2.5 emissions

and minimizing impacts to air quality. Although EPA has finalized major
portions of the PM2.5 implementation rule, we have not yet
finalized the portion relating to New Source Review. Once the NSR
portion of the PM2.5 implementation rule is finalized by
EPA, MDNR commits to transitioning from use of the interim
PM2.5 guidance to the final PM2.5 implementation
requirements after approval of the PM2.5 SIP revision (The
submittal is due April 5, 2008).
    It should be noted that most of Missouri is currently designated
attainment/unclassifiable for both the 8-hour ozone and
PM2.5 NAAQS. However, St. Louis City, St. Louis County, St.
Charles County, Franklin County, and Jefferson County are designated as
nonattainment for the 8-hour ozone and annual fine particulate matter
NAAQS.
    At this time, it is not possible for MDNR to accurately determine
whether there is interference with measures in another state's SIP
designed to protect visibility, which is the fourth element that was
addressed. Technical projects relating to visibility degradation
source-receptor relationships are under development. Missouri will be
in a more advantageous position to address the visibility projection
requirements once the initial regional haze SIP has been developed.
MDNR intends to meet the December 17, 2007, submittal deadline for the
regional haze SIP.
    A public hearing with regard to this action was held by the state,
and only EPA provided comments on this SIP revision.
    With this action, the non-regulatory text in 40 CFR 52.1320(e) is
revised to reflect that MDNR addressed the elements of the CAA section
110(a)(2)(D)(i).

What action is EPA taking?

    The EPA is taking direct final action to approve this revision as
MDNR has adequately addressed the required elements of CAA section
110(a)(2)(D)(i). EPA intends to act on the portion of Missouri's
submittal addressing all other elements of section 110(a)(2), which
addresses the infrastructure necessary to implement the 8-hour ozone
and PM2.5 NAAQS in the state of Missouri, in a future
rulemaking.
    Please note that if EPA receives adverse comment on part of this
rule, and if that part can be severed from the remainder of the rule,
EPA may adopt as final those parts of the rule that are not the subject
of an adverse comment.

Statutory and Executive Order Reviews

    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 action 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 action 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).
    This action also does not have tribal implications because it will
not have a substantial direct effect on one or more Indian tribes, on
the relationship between the Federal Government and Indian tribes, or
on the distribution of power and responsibilities between the Federal
Government and Indian tribes, as specified by Executive Order 13175 (65
FR 67249, November 9, 2000). 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 action 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 state 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 state submission for failure to use VCS. It would thus be
inconsistent with applicable law for EPA, when it reviews a state
submission, to use VCS in place of a state 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 action 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. 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. 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 July 9, 2007. 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, Intergovernmental
relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and
recordkeeping requirements, Sulfur oxides, Volatile organic compounds.

    Dated: April 30, 2007.
John B. Askew,
Regional Administrator, Region 7.

0
Chapter I, title 40 of the Code of Federal Regulations is amended as
follows:

PART 52--[AMENDED]

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

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

Subpart AA--Missouri

0
2. In Sec.  52.1320(e) the table is amended by adding an entry in
numerical order to read as follows:

Sec.  52.1320  Identification of plan.

* * * * *
    (e) * * *

                               EPA-Approved Missouri Nonregulatory SIP Provisions
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                                      Applicable
    Name of nonregulatory SIP        geographic or      State submittal    EPA approval date      Explanation
            provision             nonattainment area         date
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
(51) CAA 110(a)(2)(D)(i)........  Statewide.........  2/27/07...........  5/8/07............  ..................
SIP--Interstate Transport.......  ..................  ..................  [insert FR page     ..................
                                                                           number where the
                                                                           document begins].
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 [FR Doc. E7-8774 Filed 5-7-07; 8:45 am]

BILLING CODE 6560-50-P


[Federal Register Volume 83, Number 8 (Thursday, January 11, 2018)]
[Notices]
[Pages 1446-1448]
[FR Doc No: 2018-00305]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-82446; File No. SR-ISE-2017-112]

Self-Regulatory Organizations; Nasdaq ISE, LLC; Notice of Filing
and Immediate Effectiveness of Proposed Rule Change To Amend Certain
Non-Transaction Fees in the Exchange's Schedule of Fees

January 5, 2018.
    Pursuant to 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 December 22, 2017, Nasdaq ISE, LLC (``ISE'' or ``Exchange'') filed
with the Securities and Exchange Commission (``Commission'') the
proposed rule change as described in Items I and II 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 proposes to amend certain non-transaction fees in the
Exchange's Schedule of Fees.
    The text of the proposed rule change is available on the Exchange's
website at http://ise.cchwallstreet.com/, at the principal office of
the Exchange, 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 purpose of the proposed rule change is to amend certain non-
transaction fees in the Exchange's Schedule of Fees. ISE currently
charges its members various non-transaction fees to trade on the
Exchange and use its facilities, including a monthly access fee and an
annual regulatory fee. Such fees are designed to help defray the
technical, regulatory, and administrative costs associated with a
member's use of the Exchange. Specifically, the Exchange currently
assesses a monthly access fee to all its members that is $500 per month
per Electronic Access Member (``EAM'') membership, $4,000 per month per
Primary Market Maker (``PMM'') membership, and $2,000 per month per
Competitive Market Maker (``CMM'') membership.\3\ Payment of the
monthly access fee entitles members to trade on ISE as a PMM, CMM, or
EAM based on their membership type. In addition, Exchange currently
charges a tiered annual regulatory fee to all its members that is: (i)
For PMMs, a fee of $7,500 for the first PMM membership, $1,500 for each
additional PMM membership, and $1,000 for each CMM membership; (ii) for
CMMs, (who are not also PMMs), a fee of $5,000 per membership for the
first CMM membership \4\ and $1,000 for each additional CMM membership;
and (iii) for EAMs, a fee of $5,000 for each EAM membership.\5\
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    \3\ See ISE Schedule of Fees, Section VI.A Access Fees. In the
event where a single member firm has multiple ISE memberships, the
monthly access fee is charged for each membership. For example, if a
single member firm is both an EAM and a CMM, or owns multiple CMM
memberships, the firm is subject to the monthly access fee for each
of those memberships.
    \4\ This fee will only be charged for the first CMM membership
within each group of affiliated companies. Affiliated CMMs will pay
the incremental regulatory fee charged for additional CMM
memberships.
    \5\ See ISE Schedule of Fees, Section VII.D Regulatory Fee.
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    In order to keep pace with rising overhead, the Exchange now
proposes to increase the monthly access fee for Market Makers (i.e.,
PMMs and CMMs) from $4,000 to $5,000 per PMM membership and from $2,000
to $2,500 per CMM membership. The monthly access fee of $500 per
membership for EAMs will remain unchanged under this proposal. In
connection with the proposed increase in the monthly access fees for
Market Makers, the Exchange also proposes to eliminate the annual
regulatory fee for all its members.
    As noted above, members are required to pay a variety of non-
transaction fees, including the monthly access fee and annual
regulatory fee, to be able to trade on the Exchange and use its
facilities. By increasing the monthly access fee and eliminating the
annual regulatory fee in the manner discussed above, the Exchange is
essentially consolidating these fees rather than having members pay two
separate charges for their use of the Exchange. With the proposed
changes, Market Makers may be assessed at a higher rate overall to use
the Exchange, while EAMs may be assessed at a lower rate because the
Exchange is increasing the monthly access fee for Market Makers only,
but eliminating the annual regulatory fee for all members.\6\ The
Exchange will absorb the cost of the eliminated annual regulatory fee
for EAMs going forward.
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    \6\ For example, a PMM currently pays a total of $55,500 per
year in access and regulatory fees ($48,000 of annual access fees
plus the $7,500 annual regulatory fee) for one PMM membership while
an EAM pays a total of $11,000 per year ($6,000 of annual access
fees plus the $5,000 annual regulatory fee) for one EAM membership.
As proposed, the PMM would pay a total of $60,000 per year in access
fees for one PMM membership while the EAM would pay a total of
$6,000 per year for one EAM membership.
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    The access fee and regulatory fee were adopted in 2000 to help
recover the costs of operating a trading market,\7\ including the
technical, regulatory, and administrative costs associated with a
member's use of the Exchange. The monthly access fee amounts have not
changed since this fee was adopted, while the annual regulatory fee was
last amended in 2006.\8\ Accordingly, the Exchange believes that the
fee changes proposed herein should be a more accurate reflection of the
costs associated with a member's use of the Exchange today.
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    \7\ See Securities Exchange Act Release No. 42370 (April 28,
2000), 65 FR 26256 (May 5, 2000) (SR-ISE-00-02).
    \8\ See Securities Exchange Act Release No. 53634 (April 12,
2006), 71 FR 20147 (April19, 2006) (SR-ISE-2006-16).
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2. Statutory Basis
    The Exchange believes that its proposal is consistent with Section
6(b) of the Act,\9\ in general, and furthers the objectives of Sections
6(b)(4) and 6(b)(5) of the Act,\10\ in particular, in that it provides
for the equitable allocation of reasonable dues, fees, and other
charges among members and issuers and other persons using any facility,
and is not designed to permit unfair discrimination between customers,
issuers, brokers, or dealers.
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    \9\ 15 U.S.C. 78f(b).
    \10\ 15 U.S.C. 78f(b)(4) and (5).
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    The Exchange believes that the proposed increase in the monthly
Market Maker access fees to $5,000 per PMM membership and $2,500 per
CMM membership is reasonable and equitable. The proposed access fees
will help the Exchange keep pace with rising overhead, and are within
the range of similar fees charged by other options exchanges, including
for example, C2 Options Exchange (``C2''), which charges its market
makers a monthly access fee of $5,000 per permit.\11\
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    \11\ See C2 Fee Schedule, Section 3 Access Fees.
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    Furthermore, while the Exchange is increasing the monthly access
fees for Market Makers, the Exchange believes that this is partially
offset by the elimination of the annual regulatory fees for all
members. As noted above, members are required to pay a variety of non-
transaction fees, including the monthly access fee and annual
regulatory fee, to be able to trade on the Exchange and use its
facilities. By consolidating the annual regulatory fee with the access
fee in the manner discussed above rather than having members pay two
separate charges for their use of the Exchange, ISE is simplifying the
Schedule of Fees to the benefit of its members. The Exchange also
believes that the proposed changes are reasonable and equitable because
the

fees should be a more accurate representation of the costs associated
with a member's use of the Exchange today for the reasons discussed
above.
    As noted above, some members will be impacted more than others with
this proposal because the Exchange is increasing the monthly access fee
for Market Makers only, but eliminating the annual regulatory fee for
all members. The Exchange does not believe that this is unfairly
discriminatory because the resources dedicated to the supporting and
regulating a member vary on the type of membership. Generally, PMMs are
subject to greater obligations than CMMs are and CMMs are subject to
greater obligations than EAMs are. Furthermore, the technical,
regulatory, and administrative costs associated with an EAM's use of
the Exchange are not as high as those associated with Market Makers.

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. As discussed above, the
proposed fee changes are designed to more accurately reflect the
technical, regulatory, and administrative costs associated with a
member's use of the Exchange, and the fees remain competitive with
similar fees offered on other options exchanges. The Exchange 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, or rebate opportunities available at other venues to be
more favorable. In such an environment, the Exchange must continually
adjust its fees to remain competitive. Because competitors are free to
modify their own fees in response, and because market participants may
readily adjust their order routing practices, the Exchange believes
that the degree to which fee changes in this market may impose any
burden on competition is extremely limited.

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

    No written comments were either solicited or 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,\12\ and Rule 19b-4(f)(2) \13\ 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: (i) Necessary or
appropriate in the public interest; (ii) for the protection of
investors; or (iii) 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.
---------------------------------------------------------------------------

    \12\ 15 U.S.C. 78s(b)(3)(A)(ii).
    \13\ 17 CFR 240.19b-4(f)(2).
---------------------------------------------------------------------------

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-ISE-2017-112 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-ISE-2017-112. 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-ISE-2017-112 and should be submitted on
or before February 1, 2018.

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\14\
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    \14\ 17 CFR 200.30-3(a)(12).
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Eduardo A. Aleman,
Assistant Secretary.
[FR Doc. 2018-00305 Filed 1-10-18; 8:45 am]
 BILLING CODE 8011-01-P


[Federal Register Volume 82, Number 210 (Wednesday, November 1, 2017)]
[Notices]
[Page 50642]
[FR Doc No: 2017-23778]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Combined Notice of Filings

    Take notice that the Commission has received the following Natural
Gas Pipeline Rate and Refund Report filings:

Filings Instituting Proceedings

    Docket Numbers: RP18-51-000.
    Applicants: Natural Gas Pipeline Company of America.
    Description: Sec.  4(d) Rate Filing: Targa Gas Marketing Negotiated
Rate to be effective 11/1/2017.
    Filed Date: 10/23/17.
    Accession Number: 20171023-5300.
    Comments Due: 5 p.m. ET 11/6/17.

    Docket Numbers: RP18-52-000.
    Applicants: Kern River Gas Transmission Company.
    Description: Sec.  4(d) Rate Filing: 2017 October Negotiated Rates
to be effective 10/23/2017.
    Filed Date: 10/23/17.
    Accession Number: 20171023-5482.
    Comments Due: 5 p.m. ET 11/6/17.

    Docket Numbers: RP18-53-000.
    Applicants: El Paso Natural Gas Company, L.L.C.
    Description: Sec.  4(d) Rate Filing: Update to Fuel Exemption
Routes to be effective 12/1/2017.
    Filed Date: 10/23/17.
    Accession Number: 20171023-5485.
    Comments Due: 5 p.m. ET 11/6/17.

    The filings are accessible in the Commission's eLibrary system by
clicking on the links or querying the docket number.
    Any person desiring to intervene or protest in any of the above
proceedings must file in accordance with Rules 211 and 214 of the
Commission's Regulations (18 CFR 385.211 and Sec.  385.214) on or
before 5:00 p.m. Eastern time on the specified comment date. Protests
may be considered, but intervention is necessary to become a party to
the proceeding.
    eFiling is encouraged. More detailed information relating to filing
requirements, interventions, protests, service, and qualifying
facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call<PHONE_NUMBER>
(toll free). For TTY, call<PHONE_NUMBER>.

    Dated: October 25, 2017.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2017-23778 Filed 10-31-17; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 86, Number 212 (Friday, November 5, 2021)]
[Notices]
[Page 61220]
[FR Doc No: 2021-24288]

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ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-SFUND-2014-0549; FRL-8990-01-OLEM; OMB Control Number 2050-
0077]

Proposed Information Collection Request; Comment Request;
Application for Reimbursement to Local Governments for Emergency
Response to Hazardous Substance Releases Under the Comprehensive
Environmental Response, Compensation, and Liability Act (CERCLA)
Section 123 (Renewal)

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice.

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

SUMMARY: The Environmental Protection Agency (EPA) is planning to
submit an information collection request (ICR), Application for
Reimbursement to Local Governments for Emergency Response to Hazardous
Substance Releases under the Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA) Section 123 (Renewal) (EPA ICR
Number 1425.12, OMB Control Number 2050-0077) to the Office of
Management and Budget (OMB) for review and approval in accordance with
the Paperwork Reduction Act. Before doing so, the EPA is soliciting
public comments on specific aspects of the proposed information
collection as described in Supplementary Information. This is a
proposed extension of the ICR, which is currently approved through May
31, 2022. An Agency may not conduct or sponsor and a person is not
required to respond to a collection of information unless it displays a
currently valid OMB control number.

DATES: Comments must be submitted on or before January 4, 2022.

ADDRESSES: Submit your comments, referencing Docket ID No. EPA-HQ-
SFUND-2014-0549 to: (1) EPA online using www.regulations.gov (our
preferred method), by email to [email protected], or by mail to:
EPA Docket Center, Environmental Protection Agency, Mail Code 28221T,
1200 Pennsylvania Ave. NW, Washington, DC 20460, and (2) OMB via email
to [email protected]. Address comments to OMB Desk Officer
for EPA.
    EPA's policy is that all comments received will be included in the
public docket without change including any personal information
provided, unless the comment includes profanity, threats, information
claimed to be Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute.

FOR FURTHER INFORMATION CONTACT: Brian Schlieger, Office of Emergency
Management, Mail Code 5104A, Environmental Protection Agency, 1200
Pennsylvania Ave. NW, Washington, DC 20460; telephone number: (202)
564-3128; email address: [email protected].

SUPPLEMENTARY INFORMATION: Supporting documents which explain in detail
the information that EPA will be collecting are available in the public
docket for this ICR. The docket can be viewed online at http://www.regulations.gov. Out of an abundance of caution for members of the
public and our staff, the EPA Docket Center and Reading Room is closed
to the public, with limited exceptions, to reduce the risk of
transmitting COVID-19. Our Docket Center staff will continue to provide
remote customer service via email, phone, and webform. For further
information about the EPA's public docket, Docket Center services and
the current status, please visit us online at https://www.epa.gov/dockets. The telephone number for the Docket Center is<PHONE_NUMBER>.
    Pursuant to section 3506(c)(2)(A) of the PRA, the EPA is soliciting
comments and information to enable it to: (i) Evaluate whether the
proposed collection of information is necessary for the proper
performance of the functions of the Agency, including whether the
information will have practical utility; (ii) evaluate the accuracy of
the Agency's estimate of the burden of the proposed collection of
information, including the validity of the methodology and assumptions
used; (iii) enhance the quality, utility, and clarity of the
information to be collected; and (iv) minimize the burden of the
collection of information on those who are to respond, including
through the use of appropriate automated electronic, mechanical, or
other technological collection techniques or other forms of information
technology, e.g., permitting electronic submission of responses. EPA
will consider the comments received and amend the ICR as appropriate.
The final ICR package will then be submitted to OMB for review and
approval. At that time, EPA will issue another Federal Register notice
to announce the submission of the ICR to OMB and the opportunity to
submit additional comments to OMB.
    Abstract: The Agency requires applicants for reimbursement under
this program authorized under Section 123 of CERCLA to submit an
application that demonstrates consistency with program eligibility
requirements. This is necessary to ensure proper use of the Superfund.
EPA reviews the information to ensure compliance with all statutory and
program requirements. The applicants are local governments who have
incurred expenses, above and beyond their budgets, for hazardous
substance response. Submission of this information is voluntary and to
the applicant's benefit.
    The burden estimates, numbers and types of respondents, wage rates
and unit and total costs for this ICR renewal will be revised and
updated, if needed, during the 60-day comment period while the ICR
Supporting statement is undergoing review at OMB.
    Form Numbers: 9310-1.
    Respondents/affected entities: Entities potentially affected by
this action are local governments that apply for reimbursement under
this program.
    Respondents' obligation to respond: voluntary (CERCLA Section 123).
    Estimated total number of respondents: 20.
    Frequency of response: On occasion.
    Estimated total annual burden: 170 hours.
    Estimated total annual costs: $4,392.80. This includes an estimated
burden cost of $25.84/hour and there are no capital investment or
maintenance and operational costs.
    Changes in the estimates: Despite the increase in hourly rate,
because the estimated total number of applications per year and the
estimated burden hours per application have decreased, the overall
burden has decreased by $602.20. The decrease in hours per application
is because the form can be filled and submitted electronically.

    Dated: October 28, 2021.
Donna K. Salyer,
Director, Office of Emergency Management.
[FR Doc. 2021-24288 Filed 11-4-21; 8:45 am]
BILLING CODE 6560-50-P


Date Modified: 6/ 3/ 03 By: Abt Associates Inc. Data Sources: NERC level IPM outputs for 1d, 2d, 5d, and 6d NERC level IPM outputs for capacity prices and energy prices for 1d, 2d, 5d, NERC level IPM outputs for capacity additions for 1d, 2d, 5d, and 6d Status change analysis Description: Generates results for the market impact analysis for the section 316( b) Phase Key to IPM runs: 1d  Base case with EPA electricity demand growth assumptions 2d  Base case with AEO electricity demand growth assumptions 3d  Preferred option with EPA electricity demand growth assumptions 4d  Waterbody/ capacity based option with AEO electricity demand growth assumptions 5d  Waterbody/ capacity based option with EPA electricity demand growth assumptions 6d  Preferred option with AEO electricity demand growth assumptions Note that in this Excel version of the spreadsheet, links to external spreadsheets that contain sensitive are therefore not included in the docket in Excel format have been changed to hard values. Please re PDF formula version to determine the origin of any such values. d, and 6d se II NODA ive information and refer to the accompanying Equivalent to Preamble Exhibit 1 Market Level Impacts of the Preferred Option  AEO Base Case ( 2010)

NERC Region Baseline Capacity ( MW) Incremental Capacity Closures ( MW) Closures as % of Baseline Capacity Change in Production Cost per MWh Change in Energy Price per MWh Change in Pre Tax Income 2010 ECAR 127,332  0.0% 0.1% # VALUE!  1.0% ERCOT 80,472  0.0%  0.1% # VALUE!  1.6% FRCC 53,831  0.0% 0.2% # VALUE!  3.0% MAAC 68,838  0.0%  0.2% # VALUE!  0.7% MAIN 63,946 1,012 1.6% 1.8% # VALUE! 0.2% MAPP 38,477  0.0%  0.1% # VALUE!  0.1% NPCC 76,114  0.0%  0.3% # VALUE!  1.6% SERC 207,945  0.0%  0.1% # VALUE!  0.5% SPP 52,670  0.0% 0.0% # VALUE!  0.4% WSCC 177,780  0.0% 0.0% # VALUE!  0.9% Total 947,406 1,012 0.1% 0.1% n/ a  0.8%

Equivalent to Preamble Exhibit 4 Market Level Impacts of the Waterbody/ Capacity Based Option  EPA Base Case ( 2013)

NERC Region Baseline Capacity ( MW) Incremental Capacity Closures ( MW) Closures as % of Baseline Capacity Change in Production Cost per MWh Change in Energy Price per MWh Change in Pre Tax Income 2013 ECAR 122,082  0.0% 0.1% # VALUE!  0.9% ERCOT 80,228  0.0% 0.0% # VALUE!  3.9% FRCC 52,849  0.0% 0.6% # VALUE!  10.1% MAAC 65,308  0.0% 1.0% # VALUE!  6.0% MAIN 61,357 519 0.8% 1.1% # VALUE!  1.0% MAPP 36,628  0.0%  0.2% # VALUE!  0.7% NPCC 73,476  0.0%  0.2% # VALUE!  5.8% SERC 205,307  0.0% 0.1% # VALUE!  1.4% SPP 51,363  0.0% 0.2% # VALUE!  0.4% WSCC 173,587 3,274 1.9% 3.1% # VALUE!  4.4% Total 922,185 3,793 0.4% 0.7% n/ a  2.8%

February 18, 2003 3 of 401 dwcgi 23891 1056490638 613070000. xls  Preamble Equivalent to EBA Tables B3 4 and B8 2 2010 2013 Preferred Option  AEO Base Case Waterbody/ Capacity Based Option  EPA Base Case 2d 6d Difference % Change 1d 5d Difference % Change Total Total Capacity ( MW) 947,406 947,442 36 0.0% 922,185 921,512 ( 673)  0.1% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions 25,258 26,285 1,027 4.1% 21,334 23,954 2,620 12.3% Closures 10,203 11,215 1,012 9.9% 15,044 18,837 3,793 25.2% Energy Price ($/ MWh) n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a Capacity Price ($/ KW) n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a Total Generation ( GWh) 4,400,321 4,400,759 438 0.0% 4,261,561 4,261,871 311 0.0% Total Revenues ($ mill.) $ 156,989 $ 156,999 $ 10 0.0% $ 148,646 $ 148,387 $ 259  0.2% Costs ($ mill) $ 98,824 $ 99,318 $ 494 0.5% $ 92,200 $ 93,546 $ 1,345 1.5% Total Fuel Cost ($ mill.) $ 53,473 $ 53,506 $ 33 0.1% $ 49,047 $ 49,485 $ 438 0.9% Total VOM Cost ($ mill.) $ 8,320 $ 8,330 $ 10 0.1% $ 8,142 $ 8,102 $ 40  0.5% Total Fixed OM ($ mill.) $ 24,484 $ 24,862 $ 378 1.5% $ 23,729 $ 24,378 $ 649 2.7% Total Capital Cost ($ mill.) $ 12,547 $ 12,620 $ 74 0.6% $ 11,283 $ 11,581 $ 298 2.6% Pre Tax Income ($ mill.) $ 58,165 $ 57,681 $ 484  0.8% $ 56,446 $ 54,842 $ 1,604  2.8% Variable Production Costs ($/ MWh) $ 14.70 $ 14.72 $ 0.02 0.1% $ 13.42 $ 13.51 $ 0.09 0.7%

ECAR Total Capacity ( MW) 127,332 127,083 ( 248)  0.2% 122,082 122,454 372 0.3% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions 70 70  0.0% 70 70  0.0% Closures    0.0%    0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 680,905 680,972 67 0.0% 661,406 662,195 789 0.1% Total Revenues ($ mill.) $ 23,781 $ 23,769 $ 12  0.1% $ 22,319 $ 22,366 $ 47 0.2% Costs ($ mill) $ 13,854 $ 13,941 $ 87 0.6% $ 12,767 $ 12,902 $ 136 1.1% Total Fuel Cost ($ mill.) $ 6,963 $ 6,968 $ 5 0.1% $ 6,295 $ 6,307 $ 12 0.2% Total VOM Cost ($ mill.) $ 1,659 $ 1,663 $ 3 0.2% $ 1,627 $ 1,633 $ 6 0.4% Total Fixed OM ($ mill.) $ 3,658 $ 3,751 $ 92 2.5% $ 3,615 $ 3,711 $ 96 2.7% Total Capital Cost ($ mill.) $ 1,573 $ 1,559 $ 14  0.9% $ 1,231 $ 1,252 $ 21 1.7% Pre Tax Income ($ mill.) $ 9,927 $ 9,828 $ 99  1.0% $ 9,552 $ 9,463 $ 89  0.9% Variable Production Costs ($/ MWh) $ 12.66 $ 12.67 $ 0.01 0.1% $ 11.98 $ 11.99 $ 0.01 0.1%

ERCOT Total Capacity ( MW) 80,472 80,473 1 0.0% 80,228 80,206 ( 21) 0.0% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions 5,425 6,319 895 16.5% 1,336 1,713 377 28.2% Closures    0.0%    0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 362,415 362,415  0.0% 359,622 359,033 ( 589)  0.2% Total Revenues ($ mill.) $ 12,605 $ 12,587 $ 18  0.1% $ 12,144 $ 12,047 $ 97  0.8% Costs ($ mill) $ 9,054 $ 9,091 $ 37 0.4% $ 8,724 $ 8,760 $ 35 0.4% Total Fuel Cost ($ mill.) $ 5,760 $ 5,755 $ 5  0.1% $ 5,520 $ 5,512 $ 8.00  0.1% Total VOM Cost ($ mill.) $ 719 $ 718 $ 1  0.2% $ 735 $ 732 $ 2.00  0.3% Total Fixed OM ($ mill.) $ 1,783 $ 1,807 $ 23 1.3% $ 1,793 $ 1,829 $ 36.00 2.0% Total Capital Cost ($ mill.) $ 791 $ 811 $ 20 2.5% $ 676 $ 686 $ 9.00 1.4% Pre Tax Income ($ mill.) $ 3,551 $ 3,496 $ 55  1.6% $ 3,419 $ 3,287 $ 132  3.9% Variable Production Costs ($/ MWh) $ 17.88 $ 17.86 $ 0.02  0.1% $ 17.39 $ 17.39 $ 0.00 0.0%

FRCC Total Capacity ( MW) 53,831 53,832  0.0% 52,849 52,735 ( 115)  0.2% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions    0.0%    0.0% Closures 812 812  0.0% 812 812  0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 204,710.5 204,696.1 ( 14) 0.0% 198,664 198,669 5 0.0% Total Revenues ($ mill.) $ 8,194 $ 8,175 $ 19  0.2% $ 7,898 $ 7,857 $ 42  0.5% Costs ($ mill) $ 6,104 $ 6,149 $ 45 0.7% $ 5,809 $ 5,978 $ 170 2.9% Total Fuel Cost ($ mill.) $ 3,472 $ 3,475 $ 3 0.1% $ 3,264 $ 3,286 $ 22 0.7% Total VOM Cost ($ mill.) $ 393 $ 397 $ 4 1.0% $ 374 $ 374 $ 0 0.1% Total Fixed OM ($ mill.) $ 1,237 $ 1,275 $ 38 3.1% $ 1,213 $ 1,357 $ 144 11.9% Total Capital Cost ($ mill.) $ 1,001 $ 1,002 $ 1 0.1% $ 958 $ 961 $ 3 0.3% Pre Tax Income ($ mill.) $ 2,090 $ 2,027 $ 64  3.0% $ 2,089 $ 1,878 $ 211  10.1% Variable Production Costs ($/ MWh) $ 18.88 $ 18.92 $ 0.03 0.2% $ 18.31 $ 18.42 $ 0.11 0.6%

MAAC Total Capacity ( MW) 68,838 68,821 ( 17) 0.0% 65,308 65,116 ( 191)  0.3% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions 1,658 1,658  0.0% 1,658 1,652 ( 6)  0.4% Closures 1,725 1,725  0.0% 2,831 2,831  0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 299,588 299,389 ( 199)  0.1% 283,007 282,733 ( 274)  0.1% Total Revenues ($ mill.) $ 11,894 $ 11,886 $ 8  0.1% $ 11,009 $ 11,009 $ 0 0.0% Costs ($ mill) $ 7,085 $ 7,111 $ 26 0.4% $ 6,447 $ 6,720 $ 273 4.2% Total Fuel Cost ($ mill.) $ 3,482 $ 3,471 $ 11  0.3% $ 3,111 $ 3,150 $ 38 1.2% Total VOM Cost ($ mill.) $ 596 $ 595 $ 0 0.0% $ 582 $ 576 $ 7  1.2% Total Fixed OM ($ mill.) $ 2,123 $ 2,159 $ 37 1.7% $ 1,959 $ 2,204 $ 246 12.5% Total Capital Cost ($ mill.) $ 884 $ 885 $ 1 0.1% $ 794 $ 790 $ 4  0.6% Pre Tax Income ($ mill.) $ 4,809 $ 4,775 $ 34  0.7% $ 4,562 $ 4,289 $ 273  6.0% Variable Production Costs ($/ MWh) $ 13.61 $ 13.58 $ 0.03  0.2% $ 13.05 $ 13.18 $ 0.12 1.0%

MAIN Total Capacity ( MW) 63,946 63,875 ( 72)  0.1% 61,357 61,375 17 0.0% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions    0.0%    0.0% Closures 3,083 4,095 1,012 32.8% 6,113 6,632 519 8.5% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE!

February 18, 2003 4 of 401 dwcgi 23891 1056490638 613070000. xls  EBA  Main Total Generation ( GWh) 303,096 302,408 ( 688)  0.2% 285,997 285,952 ( 45) 0.0% Total Revenues ($ mill.) $ 10,721 $ 10,749 $ 27 0.3% $ 10,045 $ 10,048 $ 3 0.0% Costs ($ mill) $ 6,568 $ 6,586 $ 18 0.3% $ 5,875 $ 5,918 $ 43 0.7% Total Fuel Cost ($ mill.) $ 3,196 $ 3,258 $ 63 2.0% $ 2,931 $ 2,970 $ 39 1.3% Total VOM Cost ($ mill.) $ 627 $ 623 $ 3  0.5% $ 589 $ 589 $ 0  0.1% Total Fixed OM ($ mill.) $ 1,994 $ 1,929 $ 66  3.3% $ 1,625 $ 1,606 $ 19  1.2% Total Capital Cost ($ mill.) $ 751 $ 776 $ 24 3.2% $ 730 $ 753 $ 23 3.2% Pre Tax Income ($ mill.) $ 4,153 $ 4,163 $ 10 0.2% $ 4,170 $ 4,130 $ 40  1.0% Variable Production Costs ($/ MWh) $ 12.61 $ 12.84 $ 0.23 1.8% $ 12.31 $ 12.45 $ 0.14 1.1%

MAPP Total Capacity ( MW) 38,477 38,477  0.0% 36,628 36,582 ( 46)  0.1% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions    0.0%    0.0% Closures 476 476  0.0% 476 476  0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 195,033 195,155 122 0.1% 186,892 186,505 ( 386)  0.2% Total Revenues ($ mill.) $ 6,512 $ 6,531 $ 19 0.3% $ 5,995 $ 5,984 $ 11  0.2% Costs ($ mill) $ 3,894 $ 3,915 $ 21 0.5% $ 3,489 $ 3,496 $ 6 0.2% Total Fuel Cost ($ mill.) $ 1,963 $ 1,961 $ 2  0.1% $ 1,721 $ 1,713 $ 8  0.5% Total VOM Cost ($ mill.) $ 398 $ 398 $ 1 0.1% $ 387 $ 387 $ 0 0.0% Total Fixed OM ($ mill.) $ 1,044 $ 1,063 $ 19 1.8% $ 1,024 $ 1,041 $ 17 1.7% Total Capital Cost ($ mill.) $ 490 $ 493 $ 4 0.7% $ 357 $ 354 $ 3  0.8% Pre Tax Income ($ mill.) $ 2,618 $ 2,616 $ 2  0.1% $ 2,505 $ 2,488 $ 18  0.7% Variable Production Costs ($/ MWh) $ 12.10 $ 12.09 $ 0.01  0.1% $ 11.28 $ 11.26 $ 0.02  0.2%

NPCC Total Capacity ( MW) 76,114 76,116 2 0.0% 73,476 73,377 ( 99)  0.1% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions 10,554 10,677 123 1.2% 11,264 11,516 252 2.2% Closures 4,107 4,107  0.0% 4,107 4,107  0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 302,155 302,296 142 0.0% 286,959 286,242 ( 717)  0.2% Total Revenues ($ mill.) $ 12,689 $ 12,684 $ 5 0.0% $ 11,791 $ 11,703 $ 88  0.7% Costs ($ mill) $ 8,761 $ 8,819 $ 57 0.7% $ 8,036 $ 8,167 $ 132 1.6% Total Fuel Cost ($ mill.) $ 5,116 $ 5,105 $ 11  0.2% $ 4,660 $ 4,641 $ 19  0.4% Total VOM Cost ($ mill.) $ 402 $ 400 $ 2  0.5% $ 384 $ 378 $ 5  1.3% Total Fixed OM ($ mill.) $ 1,831 $ 1,897 $ 66 3.6% $ 1,795 $ 1,943 $ 148 8.3% Total Capital Cost ($ mill.) $ 1,412 $ 1,417 $ 5 0.3% $ 1,198 $ 1,205 $ 7 0.6% Pre Tax Income ($ mill.) $ 3,928 $ 3,865 $ 63  1.6% $ 3,755 $ 3,536 $ 219  5.8% Variable Production Costs ($/ MWh) $ 18.26 $ 18.21 $ 0.05  0.3% $ 17.57 $ 17.54 $ 0.04  0.2%

SERC Total Capacity ( MW) 207,945 208,341 395 0.2% 205,307 204,839 ( 468)  0.2% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions    0.0%    0.0% Closures    0.0%    0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 1,012,116 1,013,025 909 0.1% 987,086 988,072 986 0.1% Total Revenues ($ mill.) $ 35,984 $ 36,026 $ 43 0.1% $ 34,607 $ 34,621 $ 13 0.0% Costs ($ mill) $ 22,345 $ 22,463 $ 117 0.5% $ 21,363 $ 21,556 $ 193 0.9% Total Fuel Cost ($ mill.) $ 11,804 $ 11,797 $ 7  0.1% $ 10,832 $ 10,860 $ 28 0.3% Total VOM Cost ($ mill.) $ 1,870 $ 1,876 $ 6 0.3% $ 1,837 $ 1,838 $ 1 0.1% Total Fixed OM ($ mill.) $ 5,411 $ 5,493 $ 82 1.5% $ 5,375 $ 5,545 $ 169 3.1% Total Capital Cost ($ mill.) $ 3,260 $ 3,296 $ 36 1.1% $ 3,319 $ 3,312 $ 6  0.2% Pre Tax Income ($ mill.) $ 13,638 $ 13,564 $ 74  0.5% $ 13,244 $ 13,065 $ 179  1.4% Variable Production Costs ($/ MWh) $ 13.51 $ 13.50 $ 0.01  0.1% $ 12.83 $ 12.85 $ 0.02 0.1%

SPP Total Capacity ( MW) 52,670 52,646 ( 25) 0.0% 51,363 51,422 60 0.1% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions    0.0%  43 43 0.0% Closures    0.0%    0.0% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 233,472 233,584 112 0.0% 227,801 228,366 566 0.2% Total Revenues ($ mill.) $ 8,216 $ 8,213 $ 3 0.0% $ 7,812 $ 7,830 $ 18 0.2% Costs ($ mill) $ 4,742 $ 4,753 $ 10 0.2% $ 4,384 $ 4,416 $ 33 0.7% Total Fuel Cost ($ mill.) $ 2,944 $ 2,943 $ 1 0.0% $ 2,701 $ 2,713 $ 12 0.4% Total VOM Cost ($ mill.) $ 430 $ 431 $ 1 0.3% $ 427 $ 429 $ 2 0.4% Total Fixed OM ($ mill.) $ 1,076 $ 1,089 $ 13 1.2% $ 1,060 $ 1,074 $ 14 1.3% Total Capital Cost ($ mill.) $ 292 $ 290 $ 3  1.0% $ 195 $ 200 $ 5 2.5% Pre Tax Income ($ mill.) $ 3,474 $ 3,460 $ 13  0.4% $ 3,429 $ 3,414 $ 15  0.4% Variable Production Costs ($/ MWh) $ 14.45 $ 14.45 $ 0.01 0.0% $ 13.73 $ 13.76 $ 0.03 0.2%

WSCC Total Capacity ( MW) 177,780 177,780  0.0% 173,587 173,405 ( 182)  0.1% Existing # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! New Addtions # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Repowering Addtions 7,552 7,561 9 0.1% 7,006 8,960 1,954 27.9% Closures    0.0% 705 3,979 3,274 464.4% Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 806,830 806,818 ( 12) 0.0% 784,128 784,104 ( 24) 0.0% Total Revenues ($ mill.) $ 26,393 $ 26,380 $ 13  0.1% $ 25,026 $ 24,924 $ 102  0.4% Costs ($ mill) $ 16,417 $ 16,492 $ 75 0.5% $ 15,307 $ 15,633 $ 325 2.1% Total Fuel Cost ($ mill.) $ 8,772 $ 8,772 $ 0 0.0% $ 8,012 $ 8,333 $ 321 4.0% Total VOM Cost ($ mill.) $ 1,226 $ 1,227 $ 1 0.1% $ 1,201 $ 1,166 $ 35  2.9% Total Fixed OM ($ mill.) $ 4,327 $ 4,401 $ 74 1.7% $ 4,269 $ 4,066 $ 203  4.7% Total Capital Cost ($ mill.) $ 2,091 $ 2,092 $ 0 0.0% $ 1,825 $ 2,067 $ 242 13.3% Pre Tax Income ($ mill.) $ 9,976 $ 9,888 $ 89  0.9% $ 9,719 $ 9,291 $ 427  4.4% Variable Production Costs ($/ MWh) $ 12.39 $ 12.39 $ 0.00 0.0% $ 11.75 $ 12.11 $ 0.37 3.1%

February 18, 2003 5 of 401 dwcgi 23891 1056490638 613070000. xls  EBA  Main Equivalent to EBA Tables B3 7 and B8 5 2008 2008 Preferred Option  AEO Base Case Waterbody/ Capacity Based Option  EPA Base Case 2d 6d Difference % Change % Change 2013 1d 5d Difference % Change % Change 2010 Total Energy Price ($/ MWh) n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a Capacity Price ($/ KW) n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a n/ a Total Generation ( GWh) 4,243,558 4,243,861 303 0.0% 0.0% 4,060,238 4,060,343 104 0.0% 0.0% Total Revenues ($ mill.) $ 172,255 $ 172,514 $ 258 0.1% 0.0% $ 154,018 $ 154,755 $ 737 0.5%  0.2% Costs ($ mill) $ 93,847 $ 94,381 $ 535 0.6% 0.5% $ 86,389 $ 87,598 $ 1,209 1.4% 1.5% Total Fuel Cost ($ mill.) $ 51,909 $ 52,013 $ 104 0.2% 0.1% $ 48,097 $ 48,506 $ 409 0.8% 0.9% Total VOM Cost ($ mill.) $ 8,091 $ 8,095 $ 3 0.0% 0.1% $ 7,828 $ 7,789 $ 39  0.5%  0.5% Total Fixed OM ($ mill.) $ 24,215 $ 24,567 $ 352 1.5% 1.5% $ 23,643 $ 24,183 $ 541 2.3% 2.7% Total Capital Cost ($ mill.) $ 9,631 $ 9,707 $ 76 0.8% 0.6% $ 6,821 $ 7,120 $ 300 4.4% 2.6% Pre Tax Income ($ mill.) $ 78,409 $ 78,132 $ 276  0.4%  0.8% $ 67,629 $ 67,157 $ 472  0.7%  2.8% Variable Production Costs ($/ MWh) $ 14.14 $ 14.16 $ 0.02 0.2% 0.1% $ 13.77 $ 13.86 $ 0.09 0.7% 0.7%

ECAR Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 665,167 663,908 ( 1,260)  0.2% 0.0% 649,365 647,903 ( 1,462)  0.2% 0.1% Total Revenues ($ mill.) $ 26,582 $ 26,727 $ 146 0.5%  0.1% $ 23,972 $ 24,098 $ 126 0.5% 0.2% Costs ($ mill) $ 13,472 $ 13,542 $ 70 0.5% 0.6% $ 12,731 $ 12,793 $ 62 0.5% 1.1% Total Fuel Cost ($ mill.) $ 6,921 $ 6,924 $ 2 0.0% 0.1% $ 6,619 $ 6,593 $ 26  0.4% 0.2% Total VOM Cost ($ mill.) $ 1,613 $ 1,612 $ 0 0.0% 0.2% $ 1,579 $ 1,579 $ 0 0.0% 0.4% Total Fixed OM ($ mill.) $ 3,610 $ 3,694 $ 84 2.3% 2.5% $ 3,569 $ 3,656 $ 86 2.4% 2.7% Total Capital Cost ($ mill.) $ 1,329 $ 1,312 $ 16  1.2%  0.9% $ 964 $ 965 $ 1 0.1% 1.7% Pre Tax Income ($ mill.) $ 13,109 $ 13,185 $ 76 0.6%  1.0% $ 11,241 $ 11,305 $ 64 0.6%  0.9% Variable Production Costs ($/ MWh) $ 12.83 $ 12.86 $ 0.03 0.2% 0.1% $ 12.62 $ 12.61 $ 0.01  0.1% 0.1%

ERCOT Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 341,915 342,450 535 0.2% 0.0% 325,835 325,835  0.0%  0.2% Total Revenues ($ mill.) $ 13,770 $ 13,691 $ 79  0.6%  0.1% $ 9,768 $ 9,810 $ 41 0.4%  0.8% Costs ($ mill) $ 8,400 $ 8,442 $ 42 0.5% 0.4% $ 7,728 $ 7,771 $ 43 0.6% 0.4% Total Fuel Cost ($ mill.) $ 5,540 $ 5,542 $ 3 0.0%  0.1% $ 5,211 $ 5,204 $ 7  0.1%  0.1% Total VOM Cost ($ mill.) $ 677 $ 676 $ 2  0.3%  0.2% $ 673 $ 671 $ 2  0.3%  0.3% Total Fixed OM ($ mill.) $ 1,723 $ 1,737 $ 14 0.8% 1.3% $ 1,696 $ 1,719 $ 23 1.4% 2.0% Total Capital Cost ($ mill.) $ 461 $ 487 $ 26 5.8% 2.5% $ 148 $ 176 $ 28 19.1% 1.4% Pre Tax Income ($ mill.) $ 5,370 $ 5,249 $ 121  2.3%  1.6% $ 2,040 $ 2,039 $ 1  0.1%  3.9% Variable Production Costs ($/ MWh) $ 18.18 $ 18.16 $ 0.03  0.1%  0.1% $ 18.06 $ 18.03 $ 0.03  0.1% 0.0%

FRCC Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 197,481 198,482 1,002 0.5% 0.0% 186,234 185,927 ( 307)  0.2% 0.0% Total Revenues ($ mill.) $ 9,399 $ 9,439 $ 40 0.4%  0.2% $ 8,719 $ 8,660 $ 59  0.7%  0.5% Costs ($ mill) $ 5,868 $ 5,938 $ 71 1.2% 0.7% $ 5,349 $ 5,500 $ 151 2.8% 2.9% Total Fuel Cost ($ mill.) $ 3,411 $ 3,447 $ 36 1.1% 0.1% $ 3,129 $ 3,190 $ 61 1.9% 0.7% Total VOM Cost ($ mill.) $ 379 $ 384 $ 5 1.3% 1.0% $ 354 $ 351 $ 2  0.7% 0.1% Total Fixed OM ($ mill.) $ 1,210 $ 1,235 $ 25 2.0% 3.1% $ 1,172 $ 1,271 $ 98 8.4% 11.9% Total Capital Cost ($ mill.) $ 868 $ 873 $ 5 0.6% 0.1% $ 694 $ 688 $ 6  0.8% 0.3% Pre Tax Income ($ mill.) $ 3,531 $ 3,501 $ 31  0.9%  3.0% $ 3,370 $ 3,160 $ 210  6.2%  10.1% Variable Production Costs ($/ MWh) $ 19.19 $ 19.30 $ 0.11 0.6% 0.2% $ 18.70 $ 19.05 $ 0.35 1.8% 0.6%

MAAC Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 289,502 289,395 ( 107) 0.0%  0.1% 274,753 273,471 ( 1,282)  0.5%  0.1% Total Revenues ($ mill.) $ 13,142 $ 13,137 $ 6 0.0%  0.1% $ 12,024 $ 12,124 $ 100 0.8% 0.0% Costs ($ mill) $ 6,665 $ 6,702 $ 37 0.6% 0.4% $ 5,985 $ 6,122 $ 137 2.3% 4.2% Total Fuel Cost ($ mill.) $ 3,166 $ 3,170 $ 4 0.1%  0.3% $ 2,920 $ 2,920 $ 1 0.0% 1.2% Total VOM Cost ($ mill.) $ 594 $ 594 $ 0 0.1% 0.0% $ 553 $ 549 $ 4  0.7%  1.2% Total Fixed OM ($ mill.) $ 2,306 $ 2,336 $ 31 1.3% 1.7% $ 2,125 $ 2,265 $ 140 6.6% 12.5% Total Capital Cost ($ mill.) $ 599 $ 602 $ 2 0.4% 0.1% $ 386 $ 387 $ 1 0.3%  0.6% Pre Tax Income ($ mill.) $ 6,478 $ 6,435 $ 43  0.7%  0.7% $ 6,039 $ 6,002 $ 37  0.6%  6.0% Variable Production Costs ($/ MWh) $ 12.99 $ 13.01 $ 0.02 0.1%  0.2% $ 12.64 $ 12.69 $ 0.04 0.3% 1.0%

MAIN Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 294,504 294,222 ( 282)  0.1%  0.2% 285,282 284,503 ( 780)  0.3% 0.0% Total Revenues ($ mill.) $ 11,982 $ 12,031 $ 49 0.4% 0.3% $ 11,208 $ 11,193 $ 16  0.1% 0.0% Costs ($ mill) $ 6,288 $ 6,309 $ 21 0.3% 0.3% $ 5,940 $ 5,945 $ 5 0.1% 0.7% Total Fuel Cost ($ mill.) $ 3,130 $ 3,164 $ 34 1.1% 2.0% $ 2,940 $ 2,971 $ 31 1.1% 1.3% Total VOM Cost ($ mill.) $ 604 $ 604 $ 0  0.1%  0.5% $ 589 $ 588 $ 1  0.2%  0.1% Total Fixed OM ($ mill.) $ 1,966 $ 1,942 $ 24  1.2%  3.3% $ 1,949 $ 1,925 $ 24  1.3%  1.2% Total Capital Cost ($ mill.) $ 588 $ 599 $ 11 1.8% 3.2% $ 463 $ 462 $ 1  0.1% 3.2% Pre Tax Income ($ mill.) $ 5,694 $ 5,722 $ 29 0.5% 0.2% $ 5,268 $ 5,248 $ 20  0.4%  1.0% Variable Production Costs ($/ MWh) $ 12.68 $ 12.81 $ 0.13 1.0% 1.8% $ 12.37 $ 12.51 $ 0.14 1.1% 1.1%

MAPP Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 186,975 187,484 509 0.3% 0.1% 179,067 178,978 ( 89) 0.0%  0.2% Total Revenues ($ mill.) $ 7,295 $ 7,304 $ 9 0.1% 0.3% $ 6,756 $ 6,802 $ 46 0.7%  0.2% Costs ($ mill) $ 3,642 $ 3,678 $ 36 1.0% 0.5% $ 3,353 $ 3,369 $ 17 0.5% 0.2% Total Fuel Cost ($ mill.) $ 1,877 $ 1,887 $ 10 0.5%  0.1% $ 1,740 $ 1,740 $ 0 0.0%  0.5% Total VOM Cost ($ mill.) $ 376 $ 377 $ 1 0.2% 0.1% $ 366 $ 366 $ 0 0.0% 0.0%

February 18, 2003 6 of 401 dwcgi 23891 1056490638 613070000. xls  EBA  2008 Total Fixed OM ($ mill.) $ 1,017 $ 1,035 $ 18 1.8% 1.8% $ 998 $ 1,015 $ 17 1.7% 1.7% Total Capital Cost ($ mill.) $ 372 $ 380 $ 7 2.0% 0.7% $ 249 $ 249 $ 0 0.0%  0.8% Pre Tax Income ($ mill.) $ 3,653 $ 3,625 $ 27  0.7%  0.1% $ 3,404 $ 3,433 $ 29 0.9%  0.7% Variable Production Costs ($/ MWh) $ 12.05 $ 12.07 $ 0.02 0.2%  0.1% $ 11.76 $ 11.76 $ 0.01 0.0%  0.2%

NPCC Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 291,319 291,337 18 0.0% 0.0% 277,871 278,347 476 0.2%  0.2% Total Revenues ($ mill.) $ 13,908 $ 13,914 $ 5 0.0% 0.0% $ 12,806 $ 12,589 $ 216  1.7%  0.7% Costs ($ mill) $ 8,240 $ 8,311 $ 72 0.9% 0.7% $ 7,668 $ 7,744 $ 76 1.0% 1.6% Total Fuel Cost ($ mill.) $ 4,875 $ 4,886 $ 11 0.2%  0.2% $ 4,459 $ 4,462 $ 3 0.1%  0.4% Total VOM Cost ($ mill.) $ 393 $ 391 $ 2  0.5%  0.5% $ 376 $ 372 $ 3  0.9%  1.3% Total Fixed OM ($ mill.) $ 1,799 $ 1,854 $ 55 3.1% 3.6% $ 1,779 $ 1,836 $ 57 3.2% 8.3% Total Capital Cost ($ mill.) $ 1,173 $ 1,181 $ 8 0.7% 0.3% $ 1,053 $ 1,073 $ 20 1.9% 0.6% Pre Tax Income ($ mill.) $ 5,669 $ 5,602 $ 67  1.2%  1.6% $ 5,138 $ 4,846 $ 292  5.7%  5.8% Variable Production Costs ($/ MWh) $ 18.08 $ 18.11 $ 0.03 0.2%  0.3% $ 17.40 $ 17.37 $ 0.03  0.2%  0.2%

SERC Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 978,448 978,643 194 0.0% 0.1% 924,991 928,237 3,246 0.4% 0.1% Total Revenues ($ mill.) $ 39,685 $ 39,732 $ 47 0.1% 0.1% $ 36,464 $ 36,676 $ 212 0.6% 0.0% Costs ($ mill) $ 21,171 $ 21,260 $ 89 0.4% 0.5% $ 19,134 $ 19,459 $ 325 1.7% 0.9% Total Fuel Cost ($ mill.) $ 11,457 $ 11,445 $ 12  0.1%  0.1% $ 10,337 $ 10,424 $ 87 0.8% 0.3% Total VOM Cost ($ mill.) $ 1,834 $ 1,834 $ 0 0.0% 0.3% $ 1,760 $ 1,760 $ 0 0.0% 0.1% Total Fixed OM ($ mill.) $ 5,302 $ 5,367 $ 65 1.2% 1.5% $ 5,182 $ 5,350 $ 168 3.2% 3.1% Total Capital Cost ($ mill.) $ 2,578 $ 2,613 $ 36 1.4% 1.1% $ 1,854 $ 1,924 $ 70 3.8%  0.2% Pre Tax Income ($ mill.) $ 18,514 $ 18,473 $ 41  0.2%  0.5% $ 17,330 $ 17,217 $ 113  0.6%  1.4% Variable Production Costs ($/ MWh) $ 13.58 $ 13.57 $ 0.02  0.1%  0.1% $ 13.08 $ 13.13 $ 0.05 0.4% 0.1%

SPP Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 225,563 225,261 ( 302)  0.1% 0.0% 217,634 217,598 ( 36) 0.0% 0.2% Total Revenues ($ mill.) $ 9,236 $ 9,261 $ 25 0.3% 0.0% $ 8,503 $ 8,506 $ 3 0.0% 0.2% Costs ($ mill) $ 4,531 $ 4,538 $ 7 0.1% 0.2% $ 4,214 $ 4,228 $ 13 0.3% 0.7% Total Fuel Cost ($ mill.) $ 2,909 $ 2,907 $ 2  0.1% 0.0% $ 2,743 $ 2,746 $ 3 0.1% 0.4% Total VOM Cost ($ mill.) $ 426 $ 426 $ 1 0.1% 0.3% $ 419 $ 420 $ 1 0.2% 0.4% Total Fixed OM ($ mill.) $ 1,051 $ 1,063 $ 12 1.1% 1.2% $ 1,031 $ 1,042 $ 12 1.1% 1.3% Total Capital Cost ($ mill.) $ 146 $ 142 $ 4  2.4%  1.0% $ 21 $ 19 $ 2  11.1% 2.5% Pre Tax Income ($ mill.) $ 4,705 $ 4,723 $ 18 0.4%  0.4% $ 4,289 $ 4,279 $ 10  0.2%  0.4% Variable Production Costs ($/ MWh) $ 14.78 $ 14.80 $ 0.01 0.1% 0.0% $ 14.53 $ 14.55 $ 0.02 0.1% 0.2%

WSCC Energy Price ($/ MWh) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Capacity Price ($/ KW/ yr) # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! Total Generation ( GWh) 772,683 772,679 ( 4) 0.0% 0.0% 739,205 739,543 338 0.0% 0.0% Total Revenues ($ mill.) $ 27,255 $ 27,278 $ 22 0.1%  0.1% $ 23,797 $ 24,296 $ 499 2.1%  0.4% Costs ($ mill) $ 15,569 $ 15,660 $ 91 0.6% 0.5% $ 14,287 $ 14,669 $ 381 2.7% 2.1% Total Fuel Cost ($ mill.) $ 8,623 $ 8,641 $ 18 0.2% 0.0% $ 7,999 $ 8,256 $ 257 3.2% 4.0% Total VOM Cost ($ mill.) $ 1,196 $ 1,197 $ 1 0.1% 0.1% $ 1,160 $ 1,132 $ 28  2.4%  2.9% Total Fixed OM ($ mill.) $ 4,232 $ 4,304 $ 72 1.7% 1.7% $ 4,140 $ 4,104 $ 36  0.9%  4.7% Total Capital Cost ($ mill.) $ 1,518 $ 1,518 $ 0 0.0% 0.0% $ 989 $ 1,176 $ 188 19.0% 13.3% Pre Tax Income ($ mill.) $ 11,686 $ 11,617 $ 69  0.6%  0.9% $ 9,509 $ 9,627 $ 118 1.2%  4.4% Variable Production Costs ($/ MWh) $ 12.71 $ 12.73 $ 0.02 0.2% 0.0% $ 12.39 $ 12.69 $ 0.30 2.5% 3.1%

February 18, 2003 7 of 401 dwcgi 23891 1056490638 613070000. xls  EBA  2008 For Preamble Tables Preferred Option Waterbody/ Capacity Based Option 2008 2010 2008 2013 2d 6d % Change 2d 6d % Change 1d 5d % Change 1d 5d % Change Variable Production Costs/ MWh of Generation ($ 2002) ECAR 12.8 12.9 0.2% 12.7 12.7 0.1% 12.6 12.6  0.1% 12.0 12.0 0.1% ERCOT 18.2 18.2  0.1% 17.9 17.9  0.1% 18.1 18.0  0.1% 17.4 17.4 0.0% FRCC 19.2 19.3 0.6% 18.9 18.9 0.2% 18.7 19.0 1.8% 18.3 18.4 0.6% MAAC 13.0 13.0 0.1% 13.6 13.6  0.2% 12.6 12.7 0.3% 13.1 13.2 1.0% MAIN 12.7 12.8 1.0% 12.6 12.8 1.8% 12.4 12.5 1.1% 12.3 12.4 1.1% MAPP 12.0 12.1 0.2% 12.1 12.1  0.1% 11.8 11.8 0.0% 11.3 11.3  0.2% NPCC 18.1 18.1 0.2% 18.3 18.2  0.3% 17.4 17.4  0.2% 17.6 17.5  0.2% SERC 13.6 13.6  0.1% 13.5 13.5  0.1% 13.1 13.1 0.4% 12.8 12.9 0.1% SPP 14.8 14.8 0.1% 14.5 14.4 0.0% 14.5 14.6 0.1% 13.7 13.8 0.2% WSCC 12.7 12.7 0.2% 12.4 12.4 0.0% 12.4 12.7 2.5% 11.7 12.1 3.1% Total 14.14 14.16 0.2% 14.70 14.72 0.1% 13.77 13.86 0.7% 13.42 13.51 0.7%

Energy Price ($ 2002 per MWh) ECAR # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! ERCOT # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! FRCC # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! MAAC # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! MAIN # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! MAPP # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! NPCC # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! SERC # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! SPP # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! WSCC # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE! # VALUE!

Total Pre Tax Income ($ 2002; million) ECAR 13,109 13,185 0.6% 9,927 9,828  1.0% 11,241 11,305 0.6% 9,552 9,463  0.9% ERCOT 5,370 5,249  2.3% 3,551 3,496  1.6% 2,040 2,039  0.1% 3,419 3,287  3.9% FRCC 3,531 3,501  0.9% 2,090 2,027  3.0% 3,370 3,160  6.2% 2,089 1,878  10.1% MAAC 6,478 6,435  0.7% 4,809 4,775  0.7% 6,039 6,002  0.6% 4,562 4,289  6.0% MAIN 5,694 5,722 0.5% 4,153 4,163 0.2% 5,268 5,248  0.4% 4,170 4,130  1.0% MAPP 3,653 3,625  0.7% 2,618 2,616  0.1% 3,404 3,433 0.9% 2,505 2,488  0.7% NPCC 5,669 5,602  1.2% 3,928 3,865  1.6% 5,138 4,846  5.7% 3,755 3,536  5.8% SERC 18,514 18,473  0.2% 13,638 13,564  0.5% 17,330 17,217  0.6% 13,244 13,065  1.4% SPP 4,705 4,723 0.4% 3,474 3,460  0.4% 4,289 4,279  0.2% 3,429 3,414  0.4% WSCC 11,686 11,617  0.6% 9,976 9,888  0.9% 9,509 9,627 1.2% 9,719 9,291  4.4% Total 78,409 78,132  0.4% 58,165 57,681  0.8% 67,629 67,157  0.7% 56,446 54,842  2.8%


Reader’s Guide for 2-EEEBC (Debacarb)

CRM: Melanie Biscoe

EPA/OPPTS/OPP/SRRD

Reader’s Guide to 2-EEEBC (Debacarb) Docket # EPA-HQ-OPP-2008-0802

Publication Date: December 17, 2008

	EPA has created this document to provide an organizational structure to
the Registration Review 2-EEEBC (Debacarb) Docket for Public Comments.
The docket index groups related documents.  The first group contains the
Federal Register and Docket Organizational Documents, the second group
contains the Human Health Assessment, the third group contains the
Environmental Risk Assessment documents, and the fourth group contains
use/usage information and other information pertaining to the debacarb
registration review.   The Agency is providing the “Reader’s
Guide” to allow the reader to more easily access and navigate the
various items contained in the debacarb docket.

Federal Register and Docket Organizational Documents:

Docket Item 1.	Reader’s Guide to the 2-EEEBC (Debacarb) Docket # EPA-
HQ-OPP-2008-0802

Docket Item 2.	2-EEEBC (Debacarb) Summary Document

Human Health Documents for Registration Review

Docket Item 3.	2-EEEBC: Human Health Assessment Scoping Document in
Support of Registration Review (October 30, 2008)

This document describes the scope of work necessary to support the
registration review.

Docket Item 4. 	Updated Review of 2-EEEBC Incident Reports (October 30,
2008)

This document describes human health incidents reported to the Agency.

Environmental Fate and Effects Documents for Registration Review

Docket Item 5.	Registration Review: Preliminary Problem Formulation for
				Ecological Risk, Environmental Fate, Endangered Species, 					and
Drinking Water Assessments for Debacarb (2-EEEBC) 				(October 30, 2008)

This document describes the ecological risk problem formulation.

Use and Usage Information for Registration Review

Docket Item 6.	Screening Level Use Analysis (SLUA) for 2-EEEBC: Appendix
A.  			(July 31, 2008)

This table list the food/feed and non-food/non-feed uses eligible for
reregistration.

Additional Documents

Docket Item 7.	Revisions to the Data Call-In Request for Debacarb
(2-EEEBC).  				(December 3, 2008)

This document describes the Agency’s retraction of its request for an
acute oral toxicity test for passerines.


[Federal Register: January 26, 2007 (Volume 72, Number 17)]
[Notices]
[Page 3823]
[DOCID:fr26ja07-82]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RP07-137-000]

Questar Pipeline Company; Notice of Tariff Filing

January 22, 2007.
    Take notice that on January 19, 2007, Questar Pipeline Company
(Questar) tendered for filing to as part of its First Revised Volume
No. 1, Forty-First Revised Sheet No. 5, to be effective February 1,
2007.
    Questar proposes to revise its Fuel Gas Reimbursement Percentage
(FGRP) in compliance with the Commission's July 26, 2005, Order
Approving Uncontested Settlement. This order approved Questar's
Stipulation and Agreement (Settlement) that was filed June 17, 2005,
with the Commission. In its Settlement, Questar agreed to reduce the
amortization component in its FGRP to 0% upon the recovery of 1,252,777
Dth through a 0.15% amortization amount in its FGRP. As a result of
this Settlement provision, Questar is seeking to decrease its FGRP from
2.09% to 1.94%.
    Questar states that copies of this filing were served upon
Questar's customers, the Public Service Commission of Utah and the
Public Service Commission of Wyoming.
    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed in accordance with the provisions of
Section 154.210 of the Commission's regulations (18 CFR 154.210).
Anyone filing an intervention or protest must serve a copy of that
document on the Applicant. Anyone filing an intervention or protest on
or before the intervention or protest date need not serve motions to
intervene or protests on persons other than the Applicant.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov.
 Persons unable to file electronically should submit an

original and 14 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the

``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the Web site that enables subscribers to receive e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For

TTY, call<PHONE_NUMBER>.

Magalie R. Salas,
Secretary.
 [FR Doc. E7-1248 Filed 1-25-07; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 81, Number 195 (Friday, October 7, 2016)]
[Notices]
[Page 69808]
[FR Doc No: 2016-24272]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Project No. 14797-000]

California Department of Water Resources; Notice of Intent To
File License Application, Filing of Pre-Application Document, and
Approving Use of the Traditional Licensing Process

    a. Type of Filing: Notice of Intent To File License Application and
Request to Use the Traditional Licensing Process.
    b. Project No.: 14797-000.
    c. Date Filed: August 1, 2016.
    d. Submitted By: California Department of Water Resources.
    e. Name of Project: Devil Canyon Project.\1\
---------------------------------------------------------------------------

    \1\ The proposed Devil Canyon Project is currently licensed as
part of the South SWP Project (P-2426).
---------------------------------------------------------------------------

    f. Location: The project is located along the East Branch of the
California Aqueduct, in San Bernardino County, California. The project
occupies 220.98 acres of United States lands administered by the U.S.
Department of Agriculture, Forest Service, as part of the San
Bernardino National Forest.
    g. Filed Pursuant to: 18 CFR 5.3 of the Commission's regulations.
    h. Potential Applicant Contact: Ted Craddock, Chief, Hydropower
License Planning and Compliance Office, California Department of Water
Resources, P.O. Box 942836, Sacramento, CA 94236-0001;<PHONE_NUMBER>;
<EMAIL_ADDRESS>    i. FERC Contact: John Mudre at<PHONE_NUMBER>; or email at
<EMAIL_ADDRESS>    j. California Department of Water Resources filed its request to
use the Traditional Licensing Process on August 1, 2016. California
Department of Water Resources provided public notice of its request on
July 29 and August 1, 2016. In a letter dated September 30, 2016, the
Director of the Division of Hydropower Licensing approved California
Department of Water Resources' request to use the Traditional Licensing
Process.
    k. With this notice, we are initiating informal consultation with
the U.S. Fish and Wildlife Service under section 7 of the Endangered
Species Act and the joint agency regulations thereunder at 50 CFR, part
402. We are also initiating consultation with the California State
Historic Preservation Officer, as required by section 106, National
Historic Preservation Act, and the implementing regulations of the
Advisory Council on Historic Preservation at 36 CFR 800.2.
    l. With this notice, we are designating California Department of
Water Resources as the Commission's non-federal representative for
carrying out informal consultation pursuant to section 7 of the
Endangered Species Act and consultation pursuant to section 106 of the
National Historic Preservation Act.
    m. California Department of Water Resources filed a Pre-Application
Document (PAD; including a proposed process plan and schedule) with the
Commission, pursuant to 18 CFR 5.6 of the Commission's regulations.
    n. A copy of the PAD is available for review at the Commission in
the Public Reference Room or may be viewed on the Commission's Web site
(http://www.ferc.gov), using the ``eLibrary'' link. Enter the docket
number, excluding the last three digits in the docket number field to
access the document. For assistance, contact FERC Online Support at
<EMAIL_ADDRESS>(866) 208-3676 (toll free), or (202) 502-
8659 (TTY). A copy is also available for inspection and reproduction at
the address in paragraph h.
    o. The licensee states its unequivocal intent to submit an
application for a new license for Project No. 14797. Pursuant to 18 CFR
16.8, 16.9, and 16.10 each application for a new license and any
competing license applications must be filed with the Commission at
least 24 months prior to the expiration of the existing license. All
applications for license for this project must be filed by January 31,
2020.
    p. Register online at http://www.ferc.gov/docs-filing/esubscription.asp to be notified via email of new filing and issuances
related to this or other pending projects. For assistance, contact FERC
Online Support.

    Dated: September 30, 2016.
Kimberly D. Bose,
 Secretary.
[FR Doc. 2016-24272 Filed 10-6-16; 8:45 am]
 BILLING CODE 6717-01-P


[Federal Register Volume 81, Number 219 (Monday, November 14, 2016)]
[Notices]
[Pages 79546-79548]
[FR Doc No: 2016-27234]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-79249; File No. SR-Phlx-2016-86]

Self-Regulatory Organizations; NASDAQ PHLX LLC; Order Granting
Approval of Proposed Rule Change To Delete or Amend Rule Language
Relating to Specialists and Registered Options Traders

November 7, 2016.

I. Introduction

    On August 12, 2016, NASDAQ PHLX LLC (``Exchange'' or ``Phlx'')
filed with the Securities and Exchange Commission (``SEC'' or
``Commission''), pursuant to Section 19(b)(1) of the Securities
Exchange Act of 1934 (``Act'') \1\ and Rule 19b-4 thereunder,\2\ a
proposed rule change to delete or amend its rules relating to
specialists and Registered Options Traders

(``ROTs''). The proposed rule change was published for comment in the
Federal Register on August 31, 2016.\3\ On October 12, 2016, pursuant
to Section 19(b)(2) of the Act,\4\ the Commission designated a longer
period within which to approve the proposed rule change, disapprove the
proposed rule change, or institute proceedings to determine whether to
disapprove the proposed rule change.\5\ The Commission received no
comment letters on the proposed rule change. This order approves the
proposed rule change.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ See Securities Exchange Act Release No. 78680 (August 25,
2016), 81 FR 60110 (August 31, 2016) (``Notice'').
    \4\ 15 U.S.C. 78s(b)(2).
    \5\ See Securities Exchange Act Release No. 79087, 81 FR 71776
(October 18, 2016). The Commission designated a longer period within
which to take action on the proposed rule change and designated
November 29, 2016, as the date by which it should approve,
disapprove, or institute proceedings to determine whether to
disapprove the proposed rule change.
---------------------------------------------------------------------------

II. Description of the Proposal

    Phlx Rules 1022(b) and (c) currently require each specialist \6\ or
ROT \7\ to provide to the Exchange reports of options and orders in a
manner prescribed by the Exchange. Phlx Rule 1022(b) requires each
specialist or ROT to report opening positions and each purchase and
sale in each option in which the specialist or ROT is registered for
each account reported pursuant to Phlx Rule 1022.\8\ Phlx Rule 1022(c)
requires each specialist or ROT to report every order entered by the
specialist or ROT for the purchase or sale of a security underlying any
stock or Exchange-Traded Fund Share options contract traded on the
Exchange or a security convertible into or exchangeable for such
underlying security, as well as opening and closing positions in all
such securities held in each account reported pursuant to Phlx Rule
1022.\9\ The Exchange proposes to delete Phlx Rules 1022(b) and (c).
The Exchange represents that the submission of these reports by
specialists and ROTs is no longer necessary because most of the
information in the reports is available to the Exchange from other
sources.\10\
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    \6\ A ``specialist'' is an Exchange member who is registered as
an options specialist pursuant to Phlx Rule 1020(a). Specialists are
subject to quoting and registration obligations set forth in Phlx
Rules 1014(b), 1020 and 1080.02.
    \7\ A ``ROT'' is defined in Phlx Rule 1014(b) as a regular
member or a foreign currency options participant of the Exchange
located on the trading floor who has received permission from the
Exchange to trade in options for his own account. For the purposes
of Phlx Rule 1014, the term ``ROT'' includes Streaming Quote Traders
and Remote Streaming Quote Traders.
    \8\ See Notice, supra note 3, at 60110. The report is required
to designate the time and type of tick at which such transaction was
effected.
    \9\ See id. The report pertaining to orders must include the
terms of each order, identification of the brokerage firms through
which the orders were entered, the times of entry or cancellation,
the times reports of executions were received and, if all or part of
the order was executed, the quantity and execution price.
    \10\ See id. The Exchange represents that the information
referred to in Phlx Rule 1022(b) is available from the Options
Clearing Corporation and that much of the information referred to in
Phlx Rule 1022(c) is available in the Intermarket Surveillance Group
Equity Audit Trail.
---------------------------------------------------------------------------

    Phlx Rule 1036(a) currently requires every limited partner,
approved person, and every party who is affiliated with a specialist
member organization to agree, in a stipulation approved by the
Exchange, not to violate any Exchange rule or cause a specialist or a
specialist member organization to violate these or any other rules
relating to specialists. The Exchange proposes to delete Phlx Rule
1036(a). The Exchange represents that the violation of a stipulation
would have provided the Exchange with a separate basis for proceeding
against the provider of the stipulation in the event of an Exchange
rule violation.\11\ The Exchange believes that the stipulations are no
longer necessary for that purpose and that the burden of collecting
stipulations outweighs any benefits from the rule.\12\
---------------------------------------------------------------------------

    \11\ See id.
    \12\ See id.
---------------------------------------------------------------------------

    Phlx Rule 1036(b) provides that no issuer, or parent or subsidiary
thereof, or any officer, director or 10% stockholder thereof, may
become an approved person in a specialist member organization whose
members are registered in a security of that issuer. The Exchange
proposes to amend Phlx Rule 1036(b) to refer to members who are
registered in options overlying a security of that issuer to specify
that Phlx Rule 1036(b) applies only to options trading on the
Exchange.\13\
---------------------------------------------------------------------------

    \13\ The Exchange is also correcting the rule by changing the
word ``who'' to ``whose.''
---------------------------------------------------------------------------

    Phlx Rule 1037 provides that a specialist is liable for any loss
sustained for orders entrusted to him which should have been executed,
and for which he should have sent an execution report, when the
specialist was made aware of the error by 9:30 on the business day
following the submission of the order. The Exchange proposes to delete
Phlx Rule 1037. The Exchange represents that today, specialists on the
Exchange trade only for their own account and no longer handle orders
for other market participants in their capacity as specialists;
therefore, specialists would no longer be in a position to miss orders
as contemplated by Rule 1037.\14\
---------------------------------------------------------------------------

    \14\ See Notice, supra note 3, at 60111.
---------------------------------------------------------------------------

III. Discussion and Commission Findings

    After careful review, the Commission finds that the proposed rule
change is consistent with the requirements of the Act and rules and
regulations thereunder applicable to a national securities
exchange.\15\ In particular, the Commission finds that the proposed
rule change is consistent with Section 6(b)(5) of the Act,\16\ which
requires, among other things, that the rules of a national securities
exchange be 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 are not designed to permit
unfair discrimination between customers, issuers, brokers, or dealers.
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    \15\ In approving the proposed rule changes, the Commission has
considered their impact on efficiency, competition, and capital
formation. See 15 U.S.C. 78c(f).
    \16\ 15 U.S.C. 78f(b)(5).
---------------------------------------------------------------------------

    The Commission notes that the deletion of Phlx Rules 1022(b),
1022(c), and 1036(a) should eliminate burdens on Phlx members that the
Exchange believes are no longer necessary to carry out its oversight of
its members. In addition, the Commission notes that the Exchange's
proposal to delete Phlx Rules 1022(b), 1022(c), 1036(a), and 1037
should benefit investors by helping to ensure that the Phlx rules
correctly describe the current operations of the Exchange and
obligations of its members. Finally, the Commission believes that
amending Phlx Rule 1036(b) to specify that Phlx Rule 1036(b) applies
only to options trading on the Exchange should add clarity to Phlx's
rules.
    Accordingly, for the reasons discussed above, the Commission finds
that the proposed rule change is consistent with Section 6(b)(5) of the
Act.

V. Conclusion

    It is therefore ordered pursuant to Section 19(b)(2) of the Act
\17\ that the proposed rule change (SR-PHLX-2016-86) be and hereby is
approved.
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    \17\ 15 U.S.C. 78s(b)(2).
    \18\ 17 CFR 200.30-3(a)(12).

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    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\18\
Brent J. Fields,
Secretary.
[FR Doc. 2016-27234 Filed 11-10-16; 8:45 am]
 BILLING CODE 8011-01-P