[Federal Register: June 20, 2007 (Volume 72, Number 118)]
[Notices]
[Page 34053-34054]
[DOCID:fr20jn07-158]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-55907; File No. SR-BSE-2007-21]

Self-Regulatory Organizations; Boston Stock Exchange, Inc.;
Notice of Filing of Proposed Rule Change To Amend the Existing Fee
Schedule

June 13, 2007.
    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 June 4, 2007, the Boston Stock Exchange (``BSE'' or ``Exchange'')
filed with the Securities and Exchange Commission (``Commission'') the
proposed rule change as described in Items I, II, and III below, which
Items have been prepared substantially by the Exchange. The BSE has
designated this proposal as one changing a due, fee, or other charge
under Section 19(b)(3)(A)(ii) of the Act,\3\ and Rule 19b-4(f)(2)
thereunder,\4\ which renders the proposal effective upon filing with
the Commission. The Commission is publishing this notice to solicit
comments on the proposed rule from interested persons.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 2 17 CFR 240.19b-4.
    \3\ 15 U.S.C. 78s(b)(3)(A)(ii).
    \4\ 17 CFR 240.19b-4(f)(2).
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I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    The BSE proposes amending the certain transaction fees set forth in
the BeX fee schedule as well as the BeX Revenue Sharing formula. The
text of the proposed rule change is available on the Exchange's Web
site (http://www.bostonstock.com), at the BSE, 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 BSE 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 this filing is to amend certain transaction fees set
forth in the Boston Equities Exchange (``BeX'') fee schedule as well as
the BeX Revenue Sharing formula. The BeX fee schedule presently
provides for uniform credits to Liquidity Providers in the amount of
$.0027. In the event the trade involves a share price that is less than
$1.00 Liquidity Providers are presently entitled to a credit in the
amount of $.0027 per share with a maximum of .3% of quotation price per
share. Additionally, the BeX Fee Schedule presently imposes a $.0028
charge on Liquidity Takers. In the event the trade involves a share
price that is less than $1.00, Liquidity Takers are charged $.0028 with
a maximum of .3% of quotation price per share. The purpose of this
proposed amendment to the BeX fee schedule is to eliminate the credit
presently available to Liquidity Providers. Additionally, this proposed
amendment will lower the charge presently imposed on Liquidity Takers
from $.0028 to $.0005. This proposed shift in the traditional economics
of the existing marketplace will attract volume to BeX by encouraging
those firms with a high percentage of taking order flow to make BeX
their chosen routing destination while at the same time encouraging
Liquidity Providers to provide competitive quotes on BeX with the
higher probability of getting an execution.
    In this filing, the Exchange also is proposing to amend the revenue
sharing provision of the BeX fee schedule. Specifically, BSE is
proposing to eliminate the current tape revenue sharing program for
single sided orders. The tape revenue sharing program for cross trades
will remain intact.
2. Statutory Basis
    The Exchange believes that the proposal is consistent with the
requirements of Section 6(b) of the Act,\5\ in general, and furthers
the objectives of Section 6(b)(4) of the Act,\6\ in particular,

in that it is designed to provide for the equitable allocation of
reasonable dues, fees, and other charges among Exchange Members and
issuers and other persons using Exchange facilities.
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    \5\ 15 U.S.C. 78f(b).
    \6\ 15 U.S.C. 78f(b)(4).
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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 that is not necessary or appropriate
in furtherance of the purposes of the Act.

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

    The Exchange has neither solicited nor received comments on the
proposed rule change.

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

    The foregoing proposed rule change has been designated as a fee
change pursuant to Section 19(b)(3)(A) of the Act \7\ and Rule 19b-
4(f)(2) thereunder,\8\ because it establishes or changes a due, fee or
other charge imposed by the Exchange. Accordingly, the proposal will
take effect upon filing with the Commission. At any time within 60 days
of the filing of such rule change the Commission may summarily abrogate
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.
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    \7\ 15 U.S.C. 78s(b)(3)(A).
    \8\ 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 e-mail to<EMAIL_ADDRESS>Please include

File Number SR-BSE-2007-21 on the subject line.

Paper Comments

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

All submissions should refer to File No. SR-BSE-2007-21. This file
number should be included on the subject line if e-mail 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 Web site (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 inspection
and copying at the Commission's Public Reference Room. Copies of such
filing will also be available for inspection and copying at the
principal office of the BSE. All comments received will be posted
without change; the Commission does not edit personal identifying
information from submissions. You should submit only information that
you wish to make available publicly. All submissions should refer to
File Number SR-BSE-2007-21 and should be submitted on or before July
11, 2007.

    For the Commission, by the Division of Market Regulation,
pursuant to delegated authority.\9\
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    \9\ 17 CFR 200.30-3(a)(12).
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Florence E. Harmon,
Deputy Secretary.
[FR Doc. E7-11883 Filed 6-19-07; 8:45 am]

BILLING CODE 8010-01-P


[Federal Register Volume 78, Number 156 (Tuesday, August 13, 2013)]
[Proposed Rules]
[Pages 49237-49240]
[FR Doc No: 2013-19525]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2013-0673; Directorate Identifier 2013-NM-057-AD]
RIN 2120-AA64

Airworthiness Directives; the Boeing Company Airplanes

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice of proposed rulemaking (NPRM).

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SUMMARY: We propose to adopt a new airworthiness directive (AD) for
certain The Boeing Company Model 707 airplanes; and Model 720 and 720B
series airplanes. This proposed AD was prompted by reports indicating
that a standard access door was located where an impact-resistant
access door was required, and stencils were missing from some impact-
resistant access doors. This proposed AD would require an inspection of
the left- and right-hand wing fuel tank access doors to determine that
impact-resistant access doors are installed in the correct locations,
and to replace any door with an impact-resistant access door if
necessary. This proposed AD also would require an inspection for
stencils and index markers on impact-resistant access doors, and
application of new stencils or index markers if necessary. This
proposed AD would also require revising the maintenance program to
incorporate changes to the airworthiness limitations section. We are
proposing this AD to prevent foreign object penetration of the fuel
tank, which could cause a fuel leak near an ignition source (e.g., hot
brakes or engine exhaust nozzle), consequently leading to a fuel-fed
fire.

DATES: We must receive comments on this proposed AD by September 27,
2013.

ADDRESSES: You may send comments, using the procedures found in 14 CFR
11.43 and 11.45, by any of the following methods:
     Federal eRulemaking Portal: Go to http://www.regulations.gov. Follow the instructions for submitting comments.
     Fax:<PHONE_NUMBER>.
     Mail: U.S. Department of Transportation, Docket
Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New
Jersey Avenue SE., Washington, DC 20590.
     Hand Delivery: Deliver to Mail address above between 9
a.m. and 5 p.m., Monday through Friday, except Federal holidays.
    For service information identified in this proposed AD, contact
Boeing Commercial Airplanes, Attention: Data & Services Management, P.
O. Box 3707, MC 2H-65, Seattle, WA 98124-2207; telephone<PHONE_NUMBER>,
extension 1; fax<PHONE_NUMBER>; Internet https://www.myboeingfleet.com.
You may review copies of the referenced service information at the FAA,
Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For
information on the availability of this material at the FAA, call 425-
227-1221.

Examining the AD Docket

    You may examine the AD docket on the Internet at http://www.regulations.gov; or in person at the Docket Management Facility
between 9 a.m. and 5 p.m., Monday through Friday, except Federal
holidays. The AD docket contains this proposed AD, the regulatory
evaluation, any comments received, and other information. The street
address for the Docket Office (phone:<PHONE_NUMBER>) is in the ADDRESSES
section. Comments will be available in the AD docket shortly after
receipt.

FOR FURTHER INFORMATION CONTACT: Suzanne Lucier, Aerospace Engineer,
Propulsion Branch, ANM-140S, FAA, Seattle Aircraft Certification
Office, 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-
6438; fax:

425-917-6590; email<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Comments Invited

    We invite you to send any written relevant data, views, or
arguments about this proposal. Send your comments to an address listed
under the ADDRESSES section. Include ``Docket No. FAA-2013-0673;
Directorate Identifier 2013-NM-057-AD'' at the beginning of your
comments. We specifically invite comments on the overall regulatory,
economic, environmental, and energy aspects of this proposed AD. We
will consider all comments received by the closing date and may amend
this proposed AD because of those comments.
    We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We
will also post a report summarizing each substantive verbal contact we
receive about this proposed AD.

Discussion

    We received reports indicating that a standard access door was
located where an impact-resistant access door was required, and
stencils were missing from some impact-resistant access doors. This
condition, if not corrected, could result in foreign object penetration
of the fuel tank, which could cause a fuel leak near an ignition source
(e.g., hot brakes or engine exhaust nozzle), consequently leading to a
fuel-fed fire.

Relevant Service Information

    We reviewed Boeing Service Bulletin 707-3532, dated January 12,
2012; and critical design configuration control limitations (CDCCL)
Task 57-AWL-01, Impact-Resistant Fuel Tank Access Doors, of Subsection
B, Airworthiness Limitations (AWLs) of Section B, of the Boeing 707/720
Airworthiness Limitations (AWLs) Document D6-7552-AWL, Revision
September 2012. For information on the procedures and compliance times,
see this service information at http://www.regulations.gov by searching
for Docket No. FAA-2013-0673.

FAA's Determination

    We are proposing this AD because we evaluated all the relevant
information and determined the unsafe condition described previously is
likely to exist or develop in other products of these same type
designs.

Proposed AD Requirements

    The FAA issued section 121.316 of the Federal Aviation Regulations
(14 CFR 121.316) requiring that each turbine powered transport category
airplane meet the requirements of section 25.963(e) of the Federal
Aviation Regulations (14 CFR 25.963(e)). Section 25.963(e) outlines the
certification requirements for fuel tank access covers on turbine
powered transport category airplanes.
    This proposed AD would require inspecting fuel tank access doors to
determine that impact-resistant access doors are installed in the
correct locations and replacing any door with an impact-resistant
access door if necessary; inspecting application of stencils and index
markers of impact-resistant access doors and application of new
stencils or index markers if necessary; and revising the maintenance
program.
    This proposed AD requires revisions to certain operator maintenance
documents to include a new CDCCL. Compliance with CDCCLs is required by
section 91.403(c) of the Federal Aviation Regulations (14 CFR
91.403(c)). For airplanes that have been previously modified, altered,
or repaired in the areas addressed by this proposed AD, the operator
might not be able to accomplish the actions described in the revisions.
In this situation, to comply with 14 CFR 91.403(c), the operator must
request approval for an alternative method of compliance according to
the procedures specified in paragraph (j) of this proposed AD. The
request should include a description of changes to the required actions
that will ensure the continued damage tolerance of the affected
structure.
    This proposed AD would require accomplishing the actions specified
in the service information identified previously. After accomplishing
the revision required by paragraph (h) of this AD, no alternative
actions (e.g., inspections), intervals, and/or CDCCLs may be used
unless the actions, intervals, and/or CDCCLs are approved as an
alternative method of compliance (AMOC) in accordance with the
procedures specified in paragraph (j) of this AD.

Costs of Compliance

    We estimate that this proposed AD affects 13 airplanes of U.S.
registry. We estimate the following costs to comply with this proposed
AD:

                                                 Estimated Costs
----------------------------------------------------------------------------------------------------------------
                                                                                Cost per      Cost on U.S.
                Action                         Labor cost           Parts cost        product        operators
----------------------------------------------------------------------------------------------------------------
Inspection............................  Up to 12 work-hours x                 $0          $1,020         $13,260
                                         $85 per hour = $1,020.
Maintenance program revision..........  1 work-hour x $85 per                  0              85           1,105
                                         hour = $85.
----------------------------------------------------------------------------------------------------------------

    We estimate the following costs to do any necessary replacements
that would be required based on the results of the proposed inspection.
We have no way of determining the number of aircraft that might need
these replacements:

                                               On-Condition Costs
----------------------------------------------------------------------------------------------------------------
                                                                                Cost per
                    Action                                 Labor cost               Parts cost        product
----------------------------------------------------------------------------------------------------------------
Replacement per door..........................  $3 work-hours x $85 per hour =            $8,000          $8,255
                                                 $255.
Stencil and index marker (16 to 18 doors per    1 work-hour per door x $85 per                 0           1,530
 airplane).                                      hour = $85 per door.
----------------------------------------------------------------------------------------------------------------

    According to the manufacturer, some of the costs of this proposed
AD may be covered under warranty, thereby reducing the cost impact on
affected individuals. We do not control warranty coverage for affected
individuals. As a result, we have included all costs in our cost
estimate.

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, section 106, describes the
authority of the FAA Administrator. Subtitle VII: Aviation Programs,
describes in more detail the scope of the Agency's authority.
    We are issuing this rulemaking under the authority described in
Subtitle VII, Part A, Subpart III, Section 44701: ``General
requirements.'' Under that section, Congress charges the FAA with
promoting safe flight of civil aircraft in air commerce by prescribing
regulations for practices, methods, and procedures the Administrator
finds necessary for safety in air commerce. This proposed regulation is
within the scope of that authority because it addresses an unsafe
condition that is likely to exist or develop on products identified in
this rulemaking action.

Regulatory Findings

    We determined that this proposed AD would not have federalism
implications under Executive Order 13132. This proposed AD would not
have a substantial direct effect 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.
    For the reasons discussed above, I certify this proposed
regulation:
    (1) Is not a ``significant regulatory action'' under Executive
Order 12866,
    (2) Is not a ``significant rule'' under the DOT Regulatory Policies
and Procedures (44 FR 11034, February 26, 1979),
    (3) Will not affect intrastate aviation in Alaska, and
    (4) Will not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
reference, Safety.

The Proposed Amendment

    Accordingly, under the authority delegated to me by the
Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

    Authority:  49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13  [Amended]

0
2. The FAA amends Sec.  39.13 by adding the following new airworthiness
directive (AD):

The Boeing Company: Docket No. FAA-2013-0673; Directorate Identifier
2013-NM-057-AD.

(a) Comments Due Date

    We must receive comments by September 27, 2013.

(b) Affected ADs

    None.

(c) Applicability

    This AD applies to The Boeing Company Model 707-100 long body, -
200, -100B long body, and -100B short body series airplanes; and
Model 707-300, -300B, -300C, and -400 series airplanes; and Model
720 and 720B series airplanes; certificated in any category; as
identified in Boeing Service Bulletin 707-3532, dated January 12,
2012.

(d) Subject

    Joint Aircraft System Component (JASC)/Air Transport Association
(ATA) of America Code 28, Fuel.

(e) Unsafe Condition

    This AD was prompted by reports indicating that a standard
access door was located where an impact-resistant access door was
required, and stencils were missing from some impact-resistant
access doors. We are issuing this AD to prevent foreign object
penetration of the fuel tank, which could cause a fuel leak near an
ignition source (e.g., hot brakes or engine exhaust nozzle),
consequently leading to a fuel-fed fire.

(f) Compliance

    Comply with this AD within the compliance times specified,
unless already done.

(g) Inspections

    Within 72 months after the effective date of this AD, do the
actions specified in paragraphs (g)(1) and (g)(2) of this AD, in
accordance with the Accomplishment Instructions of Boeing Service
Bulletin 707-3532, dated January 12, 2012.
    (1) Do either a general visual inspection or ultrasonic non-
destructive test of the left- and right-hand wing fuel tank access
doors to determine whether impact-resistant access doors are
installed in the correct locations. If any standard access door is
found, before further flight, replace with an impact-resistant
access door, in accordance with the Accomplishment Instructions of
Boeing Service Bulletin 707-3532, dated January 12, 2012.
    (2) Do a general visual inspection of the left- and right-hand
wing fuel tank impact-resistant access doors to verify stencils and
index markers are applied. If a stencil or index marker is missing,
before further flight, apply stencil or index marker, as applicable,
in accordance with the Accomplishment Instructions of Boeing Service
Bulletin 707-3532, dated January 12, 2012.

(h) Maintenance Program Revision

    Within 60 days after the effective date of this AD, revise the
maintenance program to incorporate Critical Design Configuration
Control Limitations (CDCCL) Task 57-AWL-01, Impact-Resistant Fuel
Tank Access Doors, of Subsection B, Airworthiness Limitations (AWLs)
of the Boeing 707/720 Airworthiness Limitations (AWLs) Document D6-
7552-AWL, Revision September 2012.

(i) No Alternative Actions, Intervals, and/or CDCCLs

    After accomplishing the revision required by paragraph (h) of
this AD, no alternative actions (e.g., inspections), intervals, and/
or CDCCLs may be used unless the actions, intervals, and/or CDCCLs
are approved as an alternative method of compliance (AMOC) in
accordance with the procedures specified in paragraph (j) of this
AD.

(j) Alternative Methods of Compliance (AMOCs)

    (1) The Manager, Seattle Aircraft Certification Office (ACO),
FAA, has the authority to approve AMOCs for this AD, if requested
using the procedures found in 14 CFR 39.19. In accordance with 14
CFR 39.19, send your request to your principal inspector or local
Flight Standards District Office, as appropriate. If sending
information directly to the manager of the ACO, send it to the
attention of the person identified in the Related Information
section of this AD. Information may be emailed to<EMAIL_ADDRESS>    (2) Before using any approved AMOC, notify your appropriate
principal inspector, or lacking a principal inspector, the manager
of the local flight standards district office/certificate holding
district office.
    (3) An AMOC that provides an acceptable level of safety may be
used for any repair required by this AD if it is approved by the
Boeing Commercial Airplanes Organization Designation Authorization
(ODA) that has been authorized by the Manager, Seattle ACO to make
those findings. For a repair method to be approved, the repair must
meet the certification basis of the airplane, and the approval must
specifically refer to this AD.

(k) Related Information

    (1) For more information about this AD, contact Suzanne Lucier,
Aerospace Engineer, Propulsion Branch, ANM-140S, FAA, Seattle
Aircraft Certification Office, 1601 Lind Avenue SW., Renton, WA
98057-3356; phone:<PHONE_NUMBER>; fax:<PHONE_NUMBER>; email:
<EMAIL_ADDRESS>    (2) For service information identified in this AD, contact
Boeing Commercial Airplanes, Attention: Data & Services

Management, P. O. Box 3707, MC 2H-65, Seattle, WA 98124-2207;
telephone<PHONE_NUMBER>, extension 1; fax<PHONE_NUMBER>; Internet
https://www.myboeingfleet.com. You may review copies of the
referenced service information at the FAA, Transport Airplane
Directorate, 1601 Lind Avenue SW., Renton, WA. For information on
the availability of this material at the FAA, call<PHONE_NUMBER>.

    Issued in Renton, Washington, on August 2, 2013.
Ross Landes,
Acting Manager, Transport Airplane Directorate, Aircraft Certification
Service.
[FR Doc. 2013-19525 Filed 8-12-13; 8:45 am]
BILLING CODE 4910-13-P


and reasonable, we propose, pursuant to section 206 of the FPA, to
revise the Commission's regulations to require RTOs/ISOs to establish
and implement the systems and procedures necessary to allow
transmission owners to electronically update transmission line ratings
(for each period for which transmission line ratings are calculated) at
least hourly. We propose to require that such data be submitted by
transmission owners directly into an RTO's/ISO's EMS through
Supervisory Control and Data Acquisition (SCADA) or related
systems.\181\ Absent these capabilities, the voluntary implementation
of DLRs by transmission owners in some RTOs/ISOs would be of limited
value, as their more dynamic ratings would not be incorporated into
RTO/ISO markets.
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    \181\ The NERC Glossary defines ``Supervisory Control and Data
Acquisition'' as: ``A system of remote control and telemetry used to
monitor and control the transmission system.'' NERC, Glossary of
Terms Used in NERC Reliability Standards (June 2, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
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    108. We expect that many of the systems and procedures RTOs/ISOs
would need to develop under this proposal are likely to already be
required as part of compliance with the requirement proposed in the
previous section for transmission providers to adopt AAR. Nonetheless,
we seek comment on the additional costs, if any, needed to comply with
this proposed requirement that RTOs/ISOs also be able to accommodate
frequently updated transmission line ratings from transmission owners.
We also seek comment on whether there is any need to extend this same
requirement to transmission providers that operate outside of an RTO/
ISO.
    109. Finally, we seek comment on whether to require RTOs/ISOs to
conduct a one-time study of the cost effectiveness of DLR
implementation, and if so, what details/format any such study should
include.
c. Emergency Ratings
    110. We seek comment on whether to require transmission providers
to use unique emergency ratings. As discussed above, we expect that
such ratings would not be arbitrarily set equal to the normal ratings,
but rather developed from the appropriate, unique technical
inputs.\182\ We understand that many RTOs/ISOs already have
requirements in place for transmission owners to provide emergency
ratings. However, we also understand that many of the emergency ratings
provided to RTOs/ISOs by transmission owners may be the same as the
normal (pre-contingency) ratings. While Potomac Economics explains that
63% of all post-contingency ratings used by MISO are the same as their
normal ratings,\183\ we do not have comparable information from other
RTO/ISO regions or information regarding whether non-RTO/ISO regions
tend to use unique emergency ratings. For this reason, we seek comment
on the degree to which other transmission providers use or are provided
with unique emergency ratings and the emergency rating durations that
are commonly used.
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    \182\ See supra note 7, at P6 and note 58 at P 46.
    \183\ Potomac Economics Comments at 5.
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    111. We recognize that there may be tradeoffs in requiring
transmission owners to implement unique emergency ratings and therefore
seek comment on the costs and benefits of such a requirement. On one
hand, as Potomac Economics explains, emergency ratings result in
additional capability being made available in shorter timeframes.\184\
Because the transmission system is operated to withstand contingencies,
the use of unique emergency ratings, where appropriate, allows for
greater flows during normal conditions as well.\185\ Such additional
transmission capability can provide significant cost savings and afford
transmission providers additional flexibility in how to respond to
unforeseen events.
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    \184\ Id. at 4.
    \185\ See supra P 31.
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    112. On the other hand, we recognize that there are concerns that
the use of emergency ratings could impact reliability. As Entergy
explained in the September 2019 Technical Conference, the use of
emergency ratings may degrade affected transmission facilities and
ultimately reduce the equipment's useful life.\186\ Therefore, we
request comment on whether and how a requirement to implement unique
emergency rating would impact the useful life of transmission equipment
as well as on the feasibility of calculating emergency ratings on
transmission equipment other than conductors and transformers.
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    \186\ September 2019 Technical Conference, Day 2 Tr. at 293-294.
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B. Transparency

    113. While some transmission owners and/or operators make both
their transmission line ratings and/or ratings methodologies public,
many do not. While NERC Regional Entities are responsible for auditing
line ratings for compliance with Reliability Standards, FAC-008-3 R8
allows other entities, including other Transmission Service Providers,
Planning Coordinators, Reliability Coordinators, or Transmission
Operators, to request facility ratings up to 13 months later for
internal examination.\187\ Such data requests remain non-public.
However, NERC has proposed retiring FAC-008-3 R8, which would end the
option of non-public facility rating requests.\188\
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    \187\ NERC Standard MOD-001-1a--Available Transmission System
Capability, R9.
    \188\ NERC, Petition of the North American Electric Reliability
Corporation for Approval of Revised and Retired Reliability
Standards Under the NERC Standards Efficiency Review, Docket No.
RM19-16-000 (filed June 7, 2019). In the SER NOPR, the Commission
sought further information on NERC's proposed retirement of FAC-008
R7 and R8 inquiring how such requirements are redundant.
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1. Comments
    114. During the September 2019 Technical Conference, some
participants expressed a desire for additional transmission line rating
transparency. Potomac Economics stated that additional transparency
regarding rating methodologies was ``essential'' for administering an
AAR requirement.\189\ WATT noted that transmission owners may have an
incentive to be overly conservative with

their transmission line rating methodologies, and that increasing
transparency around these methodologies could improve efficiency.\190\
Conversely, many transmission owners at the September 2019 Technical
Conference stated that they did not believe additional transparency
requirements should be required.\191\
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    \189\ Michael Chiasson, Potomac Economics, FERC Technical
Conference on Managing Line Ratings: AD19-15 Panel 5--Transparency
of Transmission Line Rating Methodologies (Sept. 11, 2019).
    \190\ September 2019 Technical Conference, Day 1 Tr. at 23 and
25.
    \191\ Id. at 281-82.
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    115. Arguing in favor of further transparency, Potomac Economics
presented data showing a large variation in transmission line ratings
for similar lines. In addition, Potomac Economics pointed to instances
when the same ratings were used for a given transmission line in both
summer and winter, and instances in which the same ratings were used
for both emergency and normal operations. Potomac Economics explained
that, in MISO, 30% of lines use the same ratings for summer as they do
for winter. Potomac Economics further noted that, at least during the
winter, 63% of lines use emergency ratings that are equal to their
normal ratings.\192\
---------------------------------------------------------------------------

    \192\ September 2019 Technical Conference, Day 2 Tr. at 311-12.
---------------------------------------------------------------------------

    116. However, some panelists argued that current transparency
levels were adequate. For example, AEP stated that it has shared
details of its facility rating methodology and assumptions in past
technical industry publications and noted that review of facility
rating parameters and assumptions is common in competitive transmission
development.\193\ MISO Transmission Owners stated that FERC Form No.
715 data in many cases describe the rating methodology.\194\ Similarly,
the Exelon representative stated that their NERC Regional Entity,
ReliabilityFirst, validates some of Exelon's ratings against the
ratings methodology Exelon provides. Exelon stated that PJM publishes
ratings and guidelines for transmission owners on facility ratings, and
that Exelon tries to make their methodology closely conform to PJM's
guidelines.\195\ NYISO noted that it publishes seasonal rating sets as
part of its operating studies, making them available to all interested
parties. NYISO also stated that it makes the transmission line ratings
to which it secures the system available on a limited basis to all
interested parties.\196\
---------------------------------------------------------------------------

    \193\ AEP Comments at 5.
    \194\ September 2019 Technical Conference, Day 2 Tr. at at 322.
    \195\ Id. at 297.
    \196\ Id. at 243.
---------------------------------------------------------------------------

    117. Regarding RTO/ISO audits of transmission line ratings, MISO
indicated that their audit process was more of a ``sanity check''
rather than a comprehensive validation of line ratings.\197\ Similarly,
SPP described its use of ``reasonability limits'' that gets the
transmission owner to ``sign-off'' on upper and lower bounds to cap the
amount by which transmission line ratings can change and thereby ``get
rid of possible erroneous data or anything else that shouldn't be
used.'' \198\
---------------------------------------------------------------------------

    \197\ Id. at 264.
    \198\ Id. at 247.
---------------------------------------------------------------------------

    118. Following the September 2019 Technical Conference, the
Commission requested comments on a variety of issues involving
transparency. Specifically, the Commission asked whether transmission
owners' transmission line rating methodologies and transmission line
ratings should be made more transparent, and, if so, how and to what
extent. The Commission requested comment on who should have access to
this information. The Commission also requested comment on whether
transmission owners or other entities, such as NERC Regional Entities
or RTOs/ISOs, should be required to develop a database to document each
transmission facility's most limiting element, what burdens would be
associated with reporting and maintaining such a database, and who
should have access to such a database and what levels of
confidentiality protections would need to exist for such a limiting
elements database. Finally, the Commission asked whether requests from
transmission system operators to transmission owners to allow an ad hoc
increase in transmission line ratings above seasonal or static ratings
should be publicly posted.
    119. Commenters were divided over the extent to which the
Commission should require further transparency with regard to
transmission line ratings and transmission line rating changes.
Commenters in support of greater transmission line rating methodology
transparency include Potomac Economics and Monitoring Analytics, which
argue that transmission line rating methodologies should be fully
transparent and public.\199\ Potomac Economics contends that, should
AARs be required, additional transparency regarding rating
methodologies and independent oversight is ``essential.'' Potomac
Economics states that very little information is shared with MISO on
transmission owner rating methodologies or calculations, and that the
ability to validate transmission line rating methodologies and
calculations by RTOs/ISOs and other transmission providers would
enhance reliability by increasing operational and situational awareness
and identifying incorrect ratings.\200\
---------------------------------------------------------------------------

    \199\ Potomac Economics Comments at 15; Monitoring Analytics
Comments at 4.
    \200\ Potomac Economics Comments at 14-16.
---------------------------------------------------------------------------

    120. OMS agrees that rating methodologies should be as transparent
as possible and suggests incorporating the transparency model applied
to load forecasting methodologies.\201\ Industrial Customers also
support methodology transparency, suggesting that the Commission enable
market monitors, customers, and other stakeholders (such as state
commissions) to have broad access to transmission line rating
methodologies, assumptions, and values.\202\ PJM supports a requirement
for additional transmission line rating transparency, explaining that
it currently posts ratings on the PJM website every 15 minutes,
including ad hoc changes.\203\ DTE states that transmission owners
currently have a monopoly on all transmission line rating information,
and suggests that enhanced transmission line rating transparency could
help identify more cost-effective congestion management solutions.\204\
TAPS agrees that greater transmission line rating transparency is
essential,\205\ encouraging the Commission to enforce greater
transmission line rating accuracy through FPA section 206 authority
regarding non-discriminatory open access instead of through FPA section
215 authority over reliability.\206\ Finally, WATT also suggests that
additional transmission line rating transparency is appropriate.\207\
WATT contends that transmission owners should face no additional
litigations risk if they post and follow their transmission line rating
methodologies and are subject to audit by an independent entity.
Instead, WATT suggests that more accurate transmission line ratings
should reduce litigation risks.\208\
---------------------------------------------------------------------------

    \201\ OMS Comments at 3-4.
    \202\ Industrial Customers Comments at 13.
    \203\ PJM Comments at 6-7.
    \204\ DTE Comments at 4.
    \205\ TAPS Comments at 8.
    \206\ Id. at 11-12.
    \207\ WATT Comments at 8-9.
    \208\ WATT Reply Comments at 3.
---------------------------------------------------------------------------

    121. Other commenters, while not fully opposed, were less
supportive of increased rating methodology transparency, citing reasons
such as lack of need and concerns that their ratings will be challenged
and subject to increased litigation. Dominion, EEI, Exelon, MISO
Transmission Owners, and AEP all generally contend that the

current transparency provisions are satisfactory and expressed concerns
about challenges or litigation upon publication of transmission line
rating methodologies.\209\ For example, while Exelon does not oppose
posting transmission line ratings, it states that the PJM transparency
method is sufficient, suggesting that no further transmission line
rating transparency requirements is necessary.\210\ MISO Transmission
Owners do not believe that increased transparency will improve
reliability, adding that information on transmission line rating
methodologies is already provided through FERC Form No. 715.\211\ MISO
Transmission Owners contend that transmission line ratings should not
be reviewed or challenged by market participants because such parties
do not bear reliability obligations and that justifying transmission
owner ratings to market participants would be costly.\212\ Similarly,
while AEP states that it would support any rule that required the
publication of transmission line rating methodologies, AEP also
suggests it is unnecessary and requests protection from
litigation.\213\ Finally, NERC states that it does not see a
reliability benefit to increasing the transparency of rating
methodologies, noting that it ended its own requirements for sharing
rating methodologies in 2013,\214\ and that it already audits for
compliance with the NERC Reliability Standards.\215\
---------------------------------------------------------------------------

    \209\ AEP Comments at 5; Dominion Comments at 13; EEI Comments
at 11-12; Exelon Comments at 33; MISO Transmission Owners Comments
at 18-19.
    \210\ Exelon Comments at 14-15.
    \211\ MISO Transmission Owners Reply Comments at 9 (citing FERC
Form No. 715, at part IV(D)).
    \212\ MISO Transmission Owners Comments at 19-20.
    \213\ AEP Comments at 4-5.
    \214\ NERC Comments at 4 (citing Electric Reliability
Organization Proposal to Retire Requirements in Reliability
Standards, Order No. 788, 145 FERC ] 61,147 (2013) (retiring NERC
Reliability Standard FAC-008, R4 and R5)).
    \215\ Id. at 5-6.
---------------------------------------------------------------------------

    122. Regarding the transparency of ad hoc line transmission line
ratings changes specifically, commenters against further transparency
include ITC and MISO. ITC contends they should not be posted because
change requests may not be granted,\216\ and MISO argues that publicly
posting ad hoc ratings would be unduly burdensome with no commensurate
benefit.\217\
---------------------------------------------------------------------------

    \216\ ITC Comments at 6.
    \217\ MISO Comments at 8.
---------------------------------------------------------------------------

    123. Finally, regarding audits, comments were split on whether
additional audits are needed. Those that describe the current auditing
and review procedures as adequate include NRECA, NERC, ITC, EEI,
Exelon, the MISO Transmission Owners, Dominion, and AEP.\218\ These
commenters largely believe the current transmission line rating review
and audit procedures are sufficient,\219\ or that new NERC standards
are the appropriate path for auditing changes.\220\ Conversely,
Industrial Customers, Monitoring Analytics, TAPS, DTE, Potomac
Economics, and WATT contend that additional oversight would be
beneficial.\221\ These commenters argue that lax line ratings oversight
is pervasive,\222\ that transmission providers should review all line
ratings,\223\ that NERC Reliability Standards are not suitable for
auditing,\224\ and that the Commission should occasionally audit.\225\
---------------------------------------------------------------------------

    \218\ NRECA Comments at 7; NERC Comments at 5-6; ITC Comments at
6; EEI Comments at 10-11; Exelon Comments at 17-19; MISO
Transmission Owners Comments at 22-25; Dominion Comments at 16; AEP
Comments at 4-5.
    \219\ ITC Comments at 6; EEI Comments at 10-11; Exelon Comments
at 17-19; MISO Transmission Owners Comments at 22-25; Dominion
Comments at 16; AEP Comments at 4-5.
    \220\ NRECA Comments at 7.
    \221\ Industrial Customer Comments at 10-14; Monitoring
Analytics Comments at 4-5; TAPS Comments at 12-13; DTE at 6-8;
Potomac Economics Comments at 18; WATT Comments at 9.
    \222\ Industrial Customer Comments at 13-14.
    \223\ Monitoring Analytics Comments at 4-5; Potomac Economics
Comments at 18.
    \224\ TAPS Comments at 12-13.
    \225\ WATT Comments at 9.
---------------------------------------------------------------------------

2. Proposal
    124. To remedy any potentially unjust and unreasonable rates caused
by inaccurate transmission line ratings, we propose, pursuant to
section 206 of the FPA, to revise the Commission's regulations to
require transmission owners to share transmission line ratings for each
period for which transmission line ratings are calculated (with updated
ratings shared each time ratings are calculated) and transmission line
rating methodologies with their transmission provider(s) and, in
regions served by an RTO/ISO, also with the market monitor(s) of that
RTO/ISO.
    125. We preliminarily find that this proposal will afford
transmission providers and market monitors more operational and
situational awareness. Because transmission line ratings and
transmission line rating methodologies will be shared only with
transmission providers and, in regions served by an RTO/ISO, also with
the market monitor(s) of that RTO/ISO rather than with the broader
public, we believe that this proposal should address confidentiality
concerns as well as litigation risks and compliance burdens.
    126. We preliminarily find that this proposal to require
transmission owners to share transmission line ratings and transmission
line rating methodologies with their transmission provider(s) and, in
regions served by an RTO/ISO, also with the market monitor(s) of that
RTO/ISO, will enhance operational and situational awareness by ensuring
that transmission providers know the effect that changes in ambient
temperature would have on transmission line ratings within their
system. This information is critical to transmission providers because
it allows them to reasonably anticipate increases and decreases in
transmission capability and coordinate system operations accordingly.
Moreover, we believe that sharing transmission line rating
methodologies with transmission providers and, in regions served by an
RTO/ISO, also with the market monitor(s) of that RTO/ISO will provide
transmission providers and market monitors the information necessary to
verify the resulting transmission line ratings and to identify
potential errors.
    127. We disagree with suggestions that further transparency
measures are not needed. To the contrary, the proposed requirement
would provide transmission providers and market monitors, where
applicable, essential information needed both to validate transmission
line ratings and to ensure operational and situational awareness. While
current NERC Reliability Standards provide some transparency regarding
transmission line ratings and methodologies, current transparency
levels may be insufficient to ensure accurate transmission line ratings
and, thereby just and reasonable rates. Moreover, while some commenters
note that they already provide transmission line rating methodologies
pursuant to FERC Form No. 715, Form No. 715 collects information that
relates only to transmission line rating methodologies used in long-
term transmission planning analyses. By contrast, the proposal would
apply to transmission line ratings and methodologies used in near-term
transmission service. In addition, while Sec.  37.6 of the Commission's
regulations requires all data used to calculate ATC, TTC, TRM, and CBM
for congested paths be made publicly available upon request, such data
may not necessarily include the transmission line rating methodology
and may not be well suited for RTOs/ISOs, which typically make ATC
available only at external seams.
    128. While we propose to limit the sharing of a transmission
owner's transmission line ratings and transmission line rating
methodologies

to only the transmission owner's transmission providers and, in regions
served by an RTO/ISO, also to the market monitor(s) of that RTO/ISO, we
acknowledge that sharing such information with other interested parties
may yield benefits. Sharing transmission line ratings and transmission
line rating methodologies with other interested parties allows for
greater transparency, and in the case of transmission providers, may
aid efforts to manage congestion along mutual seams and may be
beneficial for the study of affected systems during the interconnection
process. For this reason, we seek comment on whether to require
transmission owners to share upon request their transmission line
ratings and rating methodologies with transmission providers other than
the transmission owner's own transmission providers. We also seek
comment on whether to require transmission owners to make their
transmission line ratings and rating methodologies available to other
interested stakeholders, including posting information on their OASIS
pages or other password protected online forum.
    129. In response to arguments that additional auditing of
transmission line ratings to ensure accuracy is needed, while we
propose no new auditing requirements, we reiterate that the Commission
will continue to conduct reviews of line ratings as a component of
broader tariff compliance audits.

VI. Compliance

    130. We propose that each public utility transmission provider be
required to submit a compliance filing within 60 days of the effective
date of any final rule. We note that this compliance deadline would be
for public utility transmission providers to submit proposed AAR tariff
changes, RTOs/ISOs to submit proposed tariff changes designed to
maintain systems and procedures needed to allow for the use of AARs and
DLRs, and for transmission owners to submit tariff changes implementing
the proposed transparency reforms or for each entity to otherwise
comply with any final rule. We understand that implementing the reforms
required by any final rule in this proceeding may be a complex
endeavor. However, we preliminarily find that implementation of these
reforms is important to ensure rates are just and reasonable.
Therefore, for the AAR reforms, we propose a staggered approach that
would prioritize implementation on historically congested lines (within
one year from the date of the compliance filing for implementation to
any final rule), and propose to require a less aggressive
implementation of AARs on all other lines (within two years from the
date to the compliance filing for implementation of any final rule).
For the DLR reforms, we propose that tariff changes filed in response
to a final rule in this proceeding must become effective within one
year from the date of the compliance filing for implementation to any
final rule. Likewise, for the transparency reforms, we propose that
tariff changes filed in response to any final rule in this proceeding
must become effective within one year from the date of the compliance
filing to any final rule in this proceeding.
    131. Some public utility transmission providers may have provisions
in their existing pro forma OATTs or other document(s) subject to the
Commission's jurisdiction that the Commission has deemed to be
consistent with or superior to the pro forma OATT or are permissible
under the independent entity variation standard or regional Reliability
Standard. Where these provisions would be modified by this final rule,
public utility transmission providers must either comply with this
proposed requirements or demonstrate that these previously-approved
variations continue to be consistent with or superior to the pro forma
OATT as modified by the proposed requirements or continue to be
permissible under the independent entity variation standard or regional
Reliability Standard.\226\
---------------------------------------------------------------------------

    \226\ See 18 CFR 35.28(c)(1)(vi).
---------------------------------------------------------------------------

    132. We seek comment on whether 60 days is sufficient time for
public utility transmission providers to develop new tariff language in
response to the final rule.
    133. To the extent that any public utility transmission provider
believes that it already complies with the reforms proposed in this
proceeding, the public utility transmission provider would be required
to demonstrate how it complies in the compliance filing required 60
days after the effective date of any final rule in this proceeding. To
the extent that any public utility transmission provider believes that
its existing market rules are consistent with or superior to the
reforms adopted in any final rule, the Commission will entertain those
at that time.
    134. As discussed above, we propose the following compliance
timelines for the proposals in this NOPR:

------------------------------------------------------------------------
 Proposed due date  (from the
   date of the  compliance
filing to any  eventual final        Proposed compliance obligation
            rule)
------------------------------------------------------------------------
1 year.......................  Requirement for Transmission Providers to
                                implement AARs on historically congested
                                transmission lines.
2 years......................  Requirement for Transmission Providers to
                                implement AARs on all other transmission
                                lines.
1 year.......................  Requirement for RTOs/ISOs to establish
                                and implement the systems and procedures
                                necessary to allow transmission owners
                                to electronically update transmission
                                line ratings at least hourly.
1 year.......................  Requirement for transmission owners to
                                share transmission line ratings and
                                transmission line rating methodologies
                                with their respective transmission
                                provider(s) and, in RTOs/ISOs, their
                                respective market monitor(s).
------------------------------------------------------------------------

VII. Information Collection Statement

    135. The information collection requirements contained in this NOPR
are subject to review by the Office of Management and Budget (OMB)
under section 3507(d) of the Paperwork Reduction Act of 1995.\227\
OMB's regulations require approval of certain information collection
requirements imposed by agency rules.\228\ Upon approval of a
collection of information, OMB will assign an OMB control number and
expiration date. Respondents subject to the filing requirements of this
rule will not be penalized for failing to respond to these collections
of information unless the collections of information display a valid
OMB control number.
---------------------------------------------------------------------------

    \227\ 44 U.S.C. 3507(d).
    \228\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    136. This NOPR would, pursuant to section 206 of the FPA, reform
the pro forma Open Access Transmission Tariff (OATT) and the
Commission's regulations to improve the accuracy and transparency of
transmission line

ratings used by transmission providers. These provisions would affect
the following collections of information:
FERC-516H, Pro Forma Open Access Transmission Tariff (Control No. 1902-
0297); and FERC-725A, Mandatory Reliability Standards for the Bulk-
Power System (Control No. 1902-0244).
    137. Interested persons may obtain information on the reporting
requirements by contacting Ellen Brown, Office of the Executive
Director, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 via email<EMAIL_ADDRESS>or telephone
((202) 502-8663).
    138. The Commission solicits comments on the Commission's need for
this information, whether the information will have practical utility,
the accuracy of the burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected or retained,
and any suggested methods for minimizing respondents' burden, including
the use of automated information techniques.
    139. Please send comments concerning the collections of information
and the associated burden estimates to the Office of Information and
Regulatory Affairs, Office of Management and Budget, through
www.reginfo.gov/public/do/PRAMain. Attention: Federal Energy Regulatory
Commission Desk Officer. Please identify the OMB Control Numbers 1902-
0096 and 1902-0244 in the subject line of your comments. Comments
should be sent within 60 days of publication of this notice in the
Federal Register.
    140. Please submit a copy of your comments on the information
collections to the Commission via the eFiling link on the Commission's
website at http://www.ferc.gov. Comments on the information collection
that are sent to FERC should refer to RM20-16-000.
    141. Title: Pro Forma Open Access Transmission Tariff (FERC-516H)
and Mandatory Reliability Standards for the Bulk-Power System (FERC-
725A).
    142. Action: Proposed revision of collections of information in
accordance with Docket No. RM20-16-000 and request for comments.
    143. OMB Control Nos.: 1902-0297 (FERC-516H) and 1902-0244 (FERC-
725A).
    144. Respondents: Transmission owners, transmission service
providers, generation owners, and RTOs/ISOs.
    145. Frequency of Information Collection: One time and annually.
    146. Necessity of Information: The proposed reform to the pro forma
Open Access Transmission Tariff (OATT) and the Commission's
regulations, if adopted, would improve the accuracy and transparency of
transmission line ratings used by transmission providers. Specifically,
the proposal would require: (1) Transmission providers to implement
ambient-adjusted ratings on the transmission lines over which they
provide transmission service; (2) Regional Transmission Organizations
(RTOs) and Independent System Operators (ISOs) to establish and
implement the systems and procedures necessary to allow transmission
owners to electronically update transmission line ratings at least
hourly; and (3) transmission owners to share transmission line ratings
and transmission line rating methodologies with their respective
transmission provider(s) and, in RTOs/ISOs, with their respective
market monitor(s).
    147. Internal Review: The Commission has reviewed the changes and
has determined that such changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has specific, objective support for the burden estimates
associated with the information collection requirements.
    148. Our estimates are based on the NERC Compliance Registry as of
September 3, 2020, which indicates that 78 transmission service
providers,\229\ 797 generator owners,\230\ and 289 transmission owners
are registered within the United States and are subject to this
proposed rulemaking.\231\ There are also 6 RTOs/ISOs in the United
States subject to this proposed rulemaking.
---------------------------------------------------------------------------

    \229\ The transmission service provider (TSP) function is a NERC
registration function which is similar to the transmission provider
that is referenced in the pro forma OATT. The TSP function is being
used as a proxy to estimate the number of transmission providers
that are impacted by this proposed rulemaking.
    \230\ Of the 797 generator owners listed in the September 3,
2020 NERC Compliance Registry, we estimate that 10% of all NERC
registered generator owners own facilities between the step-up
transformer and the point of interconnection. For this reason, we
estimate that only 80 generator owners are affected.
    \231\ The number of entities listed from the NERC Compliance
Registry reflects the omission of the Texas RE registered entities.
---------------------------------------------------------------------------

    149. Public Reporting Burden: The burden and cost estimates below
are based on the need for applicable entities to revise documentation,
already required by the pro forma OATT and the Commission's regulations
as well as the NERC Reliability Standard FAC-008-3, Facility
Ratings.\232\
---------------------------------------------------------------------------

    \232\ The burden associated with Reliability Standard FAC-008-3,
approved by the Commission under section 215 of the FPA, is included
in the OMB-approved inventory for FERC-725A. Reliability Standard
FAC-008-3 has not been revised in this proceeding however the
requirements proposed in this proposed rulemaking under section 206
of the FPA affects the burden for three requirements in Reliability
Standard FAC-008-3.
---------------------------------------------------------------------------

    150. The Commission estimates that the NOPR would affect the burden
\233\ and cost of FERC-516H and FERC-725A as follows:
---------------------------------------------------------------------------

    \233\ ``Burden'' is the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. For
further explanation of what is included in the information
collection burden, refer to 5 CFR 1320.3.

                                                   Proposed Changes in NOPR in Docket No. RM20-16-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Annual
                                                             Annual         estimated
                                                            estimated       number of      Average burden  hours &      Total estimated  burden hours &
      Area of modification       Number of  respondents     number of       responses      cost \234\  per response    total estimated cost  (column D x
                                                          responses per    (column B x                                             column E)
                                                           respondent       column C)
A.                               B.....................              C.              D.  E..........................  F.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                      FERC-516H, Pro Forma Open Access Transmission Tariff (Control No. 1902-0297)
--------------------------------------------------------------------------------------------------------------------------------------------------------
For point-to-point transmission  129 (TOs \235\ not in                1             129  1,440 hrs; $120,485........  185,760 hrs; $15,542,539.
 service requests within ten      RTOs/ISOs \236\).
 days, use AARs in determining
 ATC and TTC. (One-Time Burden
 in Year 1).

Where network transmission       160 (to account for                  1             160  1,440 hrs; $120,485........  230,400 hrs; $19,277,568.
 service is provided, use         those TOs in RTOs/
 hourly AARs to determine         ISOs that are not
 curtailment or redispatch of     included in the line
 network service. (One-Time       above).
 Burden in Year 1).
Implement software and systems   78 (TSPs \237\).......               1              78  320 hrs; $26,774...........  24,960 hrs; $2,088,403.
 to communicate the required
 line ratings with relevant
 parties. (One-Time Burden in
 Year 1).
RTOs/ISOs implement software     6 (RTOs/ISOs).........               1               6  320 hrs; $26,774...........  1920 hrs; $160,646.
 with the ability to
 accommodate AARs in both the
 day-ahead and real-time
 markets on an hourly basis.
 (One-Time Burden in Year 1).
Compliance Filings (One-Time     295 (TOs and (RTOs/                  1             295  160 hrs; $13,387...........  47,200 hrs; $3,949,224.
 Burden in Year 1).               ISOs).
Compliance Filings (One-Time     289 (TOs).............               1             289  160 hrs; $13,387...........  46,240 hrs; $3,868,901.
 Burden in Year 2).
RTOs/ISOs establish the systems  6 (RTOs/ISOs).........               1               6  960 hrs; $80,323...........  5,760 hrs; $481,939.
 and procedures necessary to
 allow transmission owners to
 update line ratings on an
 hourly basis directly into an
 EMS. (One-Time Burden in Year
 1).
Transmission owners update       289 (TOs).............               1             289  160 hrs; $13,387...........  46,240 hrs; $3,868,901.
 forecasts and ratings, and
 share transmission line
 ratings and facility ratings
 methodologies w/transmission
 providers and, if applicable,
 RTOs/ISOs & market monitors
 (Year 1 and Ongoing).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-516H   ......................  ..............             373  4,800 hrs; $401,616........  542,240 hrs; $45,369,221.
     (Year 1).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-516H   ......................  ..............             289  320 hrs; $26,774...........  92,480 hrs; $7,737,802.
     (Year 2).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-516H   ......................  ..............             289  160 hrs; $13,387...........  46,240 hrs; $3,868,901.
     (Ongoing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                          FERC-725A, Mandatory Reliability Standards for the Bulk-Power System--Reliability Standard FAC-008-3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Review and update facility       369 (TO & GO) \238\...               1             369  40 hrs; $3,347.............  14,760 hrs; $1,234,969.
 ratings methodology,
 Requirements R2 and R3. (One-
 Time Burden in Year 1).
Determine facility ratings       369 (TO & GO) \238\...               1             369  8 hrs; $669................  2,952 hrs; $246,994.
 consistent with methodology,
 Requirement R6. (Burden in
 Year 1 and Ongoing).
    Net Subtotal for FERC-725A   ......................  ..............             369  48 hrs; $4,016.............  17,712 hrs; $1,481,963.
     (Year 1).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-725A   ......................  ..............             369  8 hrs; $669................  2,952 hrs; $246,994.
     (Ongoing).
--------------------------------------------------------------------------------------------------------------------------------------------------------

    151. For the purposes of estimating burden in this NOPR, we
conservatively

estimate these values based on the maximum number of entities and
burden. As discussed elsewhere in this NOPR, some entities may, for
example, already use AARs in their existing operations, in which case
the actual burden associated with specific proposals associated with
the use of AARs would be lower than the estimate. On the other hand, we
also acknowledge that changing approaches to facility ratings may
require extra testing and training for some entities to ensure reliable
operations and gain familiarity with the approach. We estimate that the
majority of the additional burden associated with this NOPR occurs in
the first year, and that, once established, the ongoing burden will
closely approach the existing burden of operating the transmission
system. We seek comment on the estimates in the table above and the
assumptions described here.
---------------------------------------------------------------------------

    \234\ The hourly cost (for salary plus benefits) uses the
figures from the Bureau of Labor Statistics (BLS) for three
positions involved in the reporting and recordkeeping requirements.
These figures include salary (based on BLS data for May 2019, http://bls.gov/oes/current/naics2_22.htm) and benefits (based on BLS data
for December 2019; issued March 19, 2020, http://www.bls.gov/news.release/ecec.nr0.htm) and are Manager (Code 11-0000 $97.15/
hour), Electrical Engineer (Code 17-2071 $70.19/hour), and File
Clerk (Code 43-4071 $34.79/hour). The hourly cost for the reporting
requirements ($83.67) is an average of the cost of a manager and
engineer. The hourly cost for recordkeeping requirements uses the
cost of a file clerk.
    \235\ Transmission Owners. While the proposed AAR reforms apply
to transmission providers, we compute an implementation burden based
on the number of transmission owners because transmission owners
typically calculate transmission line ratings and are therefore
likely to be the entities that update computations to determine the
effect of changing ambient air temperatures on transmission line
ratings.
    \236\ Regional Transmission Organizations/Independent System
Operators.
    \237\ Transmission Service Providers.
    \238\ This number reflects 289 transmission owners and 10% of
the 797 generator owners estimated to own facilities between the
step-up transformer and the point of interconnection.
---------------------------------------------------------------------------

VIII. Environmental Analysis

    152. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\239\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this NOPR under Sec.  380.4(a)(15) of
the Commission's regulations, which provides a categorical exemption
for approval of actions under sections 205 and 206 of the FPA relating
to the filing of schedules containing all rates and charges for the
transmission or sale of electric energy subject to the Commission's
jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classification, and
services.\240\
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    \239\ Regulations Implementing National Environmental Policy Act
of 1969, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. &
Regs. ] 30,783 (1987).
    \240\ 18 CFR 380.4(a)(15).
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IX. Regulatory Flexibility Act

    153. The Regulatory Flexibility Act of 1980 \241\ generally
requires a description and analysis of proposed and final rules that
will have significant economic impact on a substantial number of small
entities. The Small Business Administration (SBA) sets the threshold
for what constitutes a small business. Under SBA's size standards,\242\
RTOs/ISOs, planning regions, and transmission owners all fall under the
category of Electric Bulk Power Transmission and Control (NAICS code
221121), with a size threshold of 500 employees (including the entity
and its associates).\243\
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    \241\ 5 U.S.C. 601-612.
    \242\ 13 CFR 121.201.
    \243\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C.
632.
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    154. The six RTOs/ISOs (SPP, MISO, PJM, ISO-NE, NYISO, and CAISO)
each employ more than 500 employees and are not considered small.
    155. We estimate that 337 transmission owners and six planning
authorities are also affected by the NOPR. Using the list of
transmission owners from the NERC Registry (dated September 3, 2020),
we estimate that approximately 68% of those entities are small
entities.
    156. We estimate that 80 generation owners own facilities between
the step-up transformer and the point of interconnection. We estimate
again that 68% of these are small entities.
    157. We estimate that 78 transmission service providers are
affected by the NOPR. We estimate again that 68% of these are small
entities.
    158. We estimate additional one-time costs associated with the NOPR
(as shown in the table above) of:

--$93,710 for each RTO/ISO (FERC-516H)
--$134,541 for each transmission owner (FERC-516H)
--$3,347 for each transmission owner (FERC-725A)
--$13,387 for each affected generation owner (FERC-516H)
--$3,347 for each generation owner (FERC-725A)
--$26,774 for each transmission service provider (FERC-516H)

    159. Therefore, the estimated additional one-time cost per entity
ranges from $16,734 to $137,219.
    160. We estimate that the majority of the additional burden
associated with this NOPR occurs in the first year (as shown in the
table above), and that, once established, the ongoing burden will
closely approach the existing burden of operating the transmission
system.
    161. According to SBA guidance, the determination of significance
of impact ``should be seen as relative to the size of the business, the
size of the competitor's business, and the impact the regulation has on
larger competitors.'' \244\ We do not consider the estimated cost to be
a significant economic impact. As a result, we certify that the
proposals in this NOPR will not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------

    \244\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------

X. Comment Procedures

    162. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due January 22, 2021. Comments must
refer to Docket No. RM20-16-000, and must include the commenter's name,
the organization they represent, if applicable, and their address in
their comments.
    163. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    164. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE,
Washington, DC, 20426.
    165. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

XI. Document Availability

    166. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (http://www.ferc.gov). At
this time, the Commission has suspended access to the Commission's
Public Reference

Room due to the President's March 13, 2020 proclamation declaring a
National Emergency concerning the Novel Coronavirus Disease (COVID-19).
    167. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
    168. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.

    By direction of the Commission.

     Issued: November 19, 2020.
Kimberly D. Bose,
Secretary.

    In consideration of the foregoing, the Commission is proposing to
amend Part 35, Chapter I, Title 18, Code of Federal Regulations, as
follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.

0
2. Amend Sec.  35.28 as follows:
0
a. In paragraph (b), revise paragraphs (10) and (11) and add paragraphs
(12) and (13);
0
b. In paragraph (c), add paragraph (5); and
0
c. In paragraph (g), revise the paragraph (g) subject heading,
paragraph (12) subject heading, and paragraph (12)(i).
    The additions and revisions read as follows:

Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (b) * * *
    (10) Ambient-adjusted line rating means a transmission line rating
that applies to a time period of not greater than one hour and reflects
an up-to-date forecast of ambient air temperature across the time
period to which the rating applies.
    (11) Dynamic line rating means a transmission line rating that
applies to a time period of not greater than one hour and reflects up-
to-date forecasts of inputs such as (but not limited to) ambient air
temperature, wind, solar irradiance intensity, transmission line
tension, or transmission line sag.
    (12) Energy Management System (EMS) means a computer control system
used by electric utility dispatchers to monitor the real-time
performance of the various elements of an electric system and to
dispatch, schedule, and/or control generation and transmission
facilities.
    (13) Supervisory Control and Data Acquisition (SCADA) means a
computer system that allows an electric system operator to remotely
monitor and control elements of an electric system.
    (c) * * *
    (5) Every public utility that owns, controls, or operates
facilities must have on file a joint pool-wide or system-wide open
access transmission tariff, which provides for the following to be
shared with its transmission provider(s) (and its Market Monitoring
Unit(s), if applicable):
    (i) Transmission line ratings for each period for which
transmission line ratings are calculated (with updated ratings shared
each time ratings are calculated); and
    (ii) Written transmission line rating methodologies used to
calculate the transmission line ratings provided under paragraph
(c)(5)(i).
* * * * *
    (g) Tariffs and operations of Commission-approved independent
system operators and regional transmission organizations--
* * * * *
    (12) Transmission line ratings. (i) Each Commission-approved
independent system operator or regional transmission organization must
establish and maintain systems and procedures necessary to allow
transmission owners to electronically update transmission line ratings
(for each period for which transmission line ratings are calculated) at
least hourly, with such data submitted by transmission owners directly
into the independent system operator's or regional transmission
organization's Energy Management System through Supervisory Control And
Data Acquisition or related systems.

    Note: The following appendix will not be published in the Code
of Federal Regulations.

Appendix A: List of Short Names/Acronyms of Commenters

----------------------------------------------------------------------------------------------------------------
             Short name/ acronym                                           Commenter
----------------------------------------------------------------------------------------------------------------
AEP.........................................  American Electric Power Company, Inc.
AWEA........................................  American Wind Energy Association.
CAISO.......................................  California Independent System Operator Corporation.
Dominion....................................  Dominion Energy Services, Inc.
DESC........................................  Dominion Energy South Carolina.
DEV.........................................  Dominion Energy Virginia.
DTE.........................................  DTE Electric Company.
EEI.........................................  Edison Electric Institute.
ELCON.......................................  Electricity Consumers Resource Council.
Entergy.....................................  Entergy Services, LLC.
ERCOT.......................................  Electric Reliability Council of Texas.
Exelon......................................  Exelon Corporation.
IEEE........................................  The Institute of Electrical and Electronics Engineers.
Industrial Customers........................  Includes ELCON, the PJM Industrial Customers Coalition, and the
                                               Coalition of MISO Transmission Customers.
ITC.........................................  International Transmission Company d/b/a ITCTransmission, Michigan
                                               Electric Transmission Company, LLC, ITC Midwest LLC, and ITC
                                               Great Plains, LLC.
MISO........................................  Midcontinent Independent System Operator, Inc.

MISO Transmission Owners....................  The MISO Transmission Owners consists of: Ameren Services Company,
                                               as agent for Union Electric Company d/b/a Ameren Missouri, Ameren
                                               Illinois Company d/b/a Ameren Illinois and Ameren Transmission
                                               Company of Illinois; American Transmission Company LLC; Big
                                               Rivers Electric Corporation; Central Minnesota Municipal Power
                                               Agency; City Water, Light & Power (Springfield, IL); Cleco Power
                                               LLC; Cooperative Energy; Dairyland Power Cooperative; Duke Energy
                                               Business Services, LLC for Duke Energy Indiana, LLC; East Texas
                                               Electric Cooperative; Great River Energy; Hoosier Energy Rural
                                               Electric Cooperative, Inc.; Indiana Municipal Power Agency;
                                               Indianapolis Power & Light Company; International Transmission
                                               Company d/b/a ITCTransmission; ITC Midwest LLC; Lafayette
                                               Utilities System; Michigan Electric Transmission Company, LLC;
                                               MidAmerican Energy Company; Minnesota Power (and its subsidiary
                                               Superior Water, L&P); Missouri River Energy Services;
                                               MontanaDakota Utilities Co.; Northern Indiana Public Service
                                               Company LLC; Northern States Power Company, a Minnesota
                                               corporation, and Northern States Power Company, a Wisconsin
                                               corporation, subsidiaries of Xcel Energy Inc.; Northwestern
                                               Wisconsin Electric Company; Otter Tail Power Company; Prairie
                                               Power Inc.; Southern Illinois Power Cooperative; Southern Indiana
                                               Gas & Electric Company (d/b/a Vectren Energy Delivery of
                                               Indiana); Southern Minnesota Municipal Power Agency; Wabash
                                               Valley Power Association, Inc.; and Wolverine Power Supply
                                               Cooperative, Inc.
NERC........................................  North American Electric Reliability Corporation.
NRECA.......................................  National Rural Electric Cooperative Association.
NYISO.......................................  New York Independent System Operator, Inc.
ISO-NE......................................  ISO New England Inc.
ITC.........................................  ITC Transmission.
OMS.........................................  Organization of MISO States.
PJM.........................................  PJM Interconnection, L.L.C.
SPP.........................................  Southwest Power Pool, Inc.
TAPS........................................  Transmission Access Policy Study Group.
WATT........................................  Working for Advanced Transmission Technologies.
----------------------------------------------------------------------------------------------------------------

    Note: The following appendix will not be published in the Code
of Federal Regulations.

Appendix B: Pro Forma Open Access Transmission Tariff

ATTACHMENT M

Transmission Line Ratings

General

    The Transmission Provider will implement Ambient-Adjusted
Ratings and Seasonal Line Ratings on the transmission lines over
which it provides Transmission Service, as provided below.

Definitions

    The following definitions apply for purposes of this Attachment:
    (1) ``Transmission Line Rating'' means the maximum transfer
capability of a transmission line, computed in accordance with a
written line rating methodology and consistent with Good Utility
Practice, considering the technical limitations (such as thermal
flow limits) on conductors and relevant transmission equipment, as
well as technical limitations of the Transmission System (such as
system voltage and stability limits). Relevant transmission
equipment may include, but is not limited to, circuit breakers, line
traps, and transformers.
    (2) ``Ambient-Adjusted Rating'' (AAR) means a Transmission Line
Rating that:
    (a) Applies to a time period of not greater than one hour.
    (b) Reflects an up-to-date forecast of ambient air temperature
across the time period to which the rating applies.
    (c) Is calculated at least each hour, if not more frequently.
    (3) ``Seasonal Line Rating'' means a Transmission Line Rating
that:
    (a) Applies to a specified season, where seasons are defined by
the Transmission Provider to not include more than three months in
each season.
    (b) Reflects an up-to-date forecast of ambient air temperature
across the relevant season over which the rating applies.
    (c) Is calculated monthly, if not more frequently, for each
season in the future for which Transmission Service can be
requested.
    (4) ``Near-Term Point-To-Point Transmission Service'' means
Point-To-Point Transmission Service which ends not more than ten
days after the Transmission Service request date. When the
description of obligations below refers to either a request for
information about the availability of potential Transmission Service
(including, but not limited to, a request for ATC), or to the
posting of ATC or other information related to potential service,
the date that the information is requested or posted will serve as
the Transmission Service request date.
    (5) ``Historically Congested Transmission Line'' means a
transmission line that was congested (i.e., whose Transmission Line
Rating was a binding constraint) at any time on or between [insert
date five years prior to the effective date of this final rule] and
[insert the effective date of this final rule].

System Reliability

    If the Transmission Provider reasonably determines, consistent
with Good Utility Practice, that the temporary use of a Transmission
Line Rating different than would otherwise be required under the
Obligations of the Transmission Provider set forth in this
Attachment is necessary to ensure the safety and reliability of the
Transmission System, then the Transmission Provider will use such an
alternate rating.

Obligations of Transmission Provider

    After the relevant dates specified below in the Implementation
section of this Attachment, the Transmission Provider will have the
following obligations.
    The Transmission Provider must use AARs as the relevant
Transmission Line Ratings when performing any of the following
functions: (1) Evaluating requests for Near-Term Point-To-Point
Transmission Service, (2) responding to requests for information on
the availability of potential Near-Term Point-To-Point Transmission
Service (including requests for ATC or other information related to
potential service), or (3) posting ATC or other information related
to Near-Term Point-To-Point Transmission Service to the Transmission
Provider's OASIS site.
    The Transmission Provider must use AARs as the relevant
Transmission Line Ratings when determining the necessity of
curtailment or interruption of Point-To-Point Transmission Service
(under section 14.7) if such curtailment or interruption is both
necessary because of issues related to flow limits on transmission
lines and anticipated to occur (start and end) within the next 10
days. For determining the necessity of curtailment or interruption
of Point-To-Point Transmission Service in other situations, the
Transmission Provider must use Seasonal Line Ratings as the relevant
Transmission Line Ratings.
    The Transmission Provider must use AARs as the relevant
Transmission Line Ratings when determining the necessity of
curtailment (under section 33) or redispatch (under sections 30.5
and/or 33) of Network Integration Transmission Service or secondary
service if such curtailment or redispatch is both necessary because
of issues related to flow limits on transmission lines and
anticipated to occur (start and end) within the following 10 days.
For determining the necessity of curtailment or redispatch of
Network Integration Transmission Service or secondary service in
other situations, the Transmission Provider must use Seasonal Line
Ratings as the relevant Transmission Line Ratings.
    The Transmission Provider must use Seasonal Line Ratings as the
relevant

Transmission Line Ratings when evaluating requests for any
Transmission Service not otherwise covered above in this section
(including, but not limited to, requests for non-Near-Term Point-To-
Point Transmission Service or requests to designate or change the
designation of Network Resources or Network Load), and when
developing any ATC or other information posted or provided to
potential customers related to such services.
    In developing forecasts of ambient air-temperature for AARs and
Seasonal Line Ratings, the Transmission Provider must develop such
forecasts consistent with Good Utility Practice and on a non-
discriminatory basis.
    Exception: Where the Transmission Provider determines,
consistent with Good Utility Practice, that the Transmission Line
Rating of a transmission line is not affected by ambient air
temperature, the Transmission Provider may use a Transmission Line
Rating for that line that is not an AAR or Seasonal Line Rating.
Examples of such a transmission line include (1) a transmission line
where the technical transfer capability of the limiting conductors
and/or limiting transmission equipment is not dependent on ambient
air temperature, and (2) a transmission line whose transfer
capability is limited by a Transmission System limit (such as a
system voltage or stability limit) which is not dependent on ambient
air temperature.

Implementation

    The Transmission Provider will implement the use of AARs and
Seasonal Line Ratings as required in this Attachment in accordance
with the following schedule.
    Prior to these implementation dates, the requirements above will
not apply.
    (1) Historically Congested Transmission Lines: Transmission
Provider will complete implementation of AARs and Seasonal Line
Ratings for Historically Congested Transmission Lines not later than
[insert date one year after the date of the compliance filing to the
final rule].
    (2) Other Transmission Lines: Transmission Provider will
complete implementation of AARs and Seasonal Line Ratings for any
other transmission lines not later than [insert date two years after
the date of the compliance filing to the final rule].

[FR Doc. 2020-26107 Filed 1-19-21; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register: August 21, 2007 (Volume 72, Number 161)]
[Notices]
[Page 46617-46618]
[DOCID:fr21au07-54]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. EL07-82-000]

Pinnacle West Capital Corporation, Arizona Public Service
Company, Pinnacle West Energy Corporation, APS Energy Services Company,
Inc; Notice of Institution of Proceeding and Refund Effective Date

August 14, 2007.
    On August 13, 2007, the Commission issued an order that instituted
a proceeding in the above-referenced docket, pursuant to section 206 of
the Federal Power Act (FPA) 16 U.S.C. 824e, to determine whether
Pinnacle West Capital Corporation's, Arizona Public Service Company's,
Pinnacle West Energy Corporation's and APS Energy Services Company,
Inc.'s (collectively, Pinnacle) market-based

rate authority for the non-APS portion of the Phoenix Valley remains
just and reasonable during the summer months. Pinnacle West Capital
Corporation, 120 FERC ] 61,153 (2007).
    The refund effective date in the above-docketed proceeding,
established pursuant to section 2069(b) of the FPA, will be the date of
publication in the Federal Register.

Kimberly D. Bose,
Secretary.
 [FR Doc. E7-16384 Filed 8-20-07; 8:45 am]

BILLING CODE 6717-01-P