[Federal Register Volume 86, Number 12 (Thursday, January 21, 2021)]
[Proposed Rules]
[Pages 6420-6444]
[FR Doc No: 2020-26107]

Vol. 86

Thursday,

No. 12

January 21, 2021

Part II

Department of Energy

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

Federal Energy Regulatory Commission

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

18 CFR Part 35

Managing Transmission Line Ratings; Proposed Rule

Federal Register / Vol. 86 , No. 12 / Thursday, January 21, 2021 /
Proposed Rules

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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM20-16-000]

Managing Transmission Line Ratings

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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

SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes
to reform both the pro forma Open Access Transmission Tariff and the
Commission's regulations under the Federal Power Act to improve the
accuracy and transparency of transmission line ratings. Specifically,
the proposal would require: Transmission providers to implement
ambient-adjusted ratings on the transmission lines over which they
provide transmission service; 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 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).

DATES: Comments are due March 22, 2021.

ADDRESSES: Comments, identified by docket number RM20-16, may be filed
electronically at http://www.ferc.gov in acceptable native applications
and print-to-PDF, but not in scanned or picture format. For those
unable to file electronically, comments may be filed by mail or hand-
delivery to: Federal Energy Regulatory Commission, Secretary of the
Commission, 888 First Street NE, Washington, DC 20426. The Comment
Procedures Section of this document contains more detailed filing
procedures.

FOR FURTHER INFORMATION CONTACT:
Dillon Kolkmann (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>Mark Armamentos (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>Ryan Stroschein (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

                            Table of Contents

                                                             Paragraph
                                                              numbers

I. Introduction.........................................               1
II. Background..........................................               9
    A. Order Nos. 888 and 889...........................               9
    B. Order No. 890....................................              12
    C. ATC-Related Reliability Standards, Business                    13
     Practices, and Commission Regulations..............
    D. Reliability Standard FAC-008-3 (Facility Ratings)              15
    E. Commission Staff Paper and September 2019                      16
     Technical Conference...............................
III. Technical Background...............................              19
    A. Transmission Line Rating Fundamentals............              19
    B. Current Transmission Line Rating Practices.......              22
    C. Emergency Ratings................................              30
    D. Rating and Methodology Transparency..............              33
IV. Need for Reform.....................................              38
    A. Transmission Line Ratings........................              38
    B. Transparency.....................................              47
V. Discussion...........................................              48
    A. Transmission Line Ratings........................              48
        1. Comments.....................................              48
        2. Proposal.....................................              81
    B. Transparency.....................................             114
        1. Comments.....................................             115
        2. Proposal.....................................             125
VI. Compliance..........................................             131
VII. Information Collection Statement...................             136
VIII. Environmental Analysis............................             153
IX. Regulatory Flexibility Act..........................             154
X. Comment Procedures...................................             163
XI. Document Availability...............................             167
Appendix A: List of Short Names/Acronyms of Commenters..              --
Appendix B: Pro Forma Open Access Transmission Tariff...              --

I. Introduction

    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission) proposes, pursuant to section 206 of
the Federal Power Act (FPA),\1\ to 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. Transmission line ratings represent the maximum
transfer capability of each transmission line. As explained below,
transmission line ratings and the rules by which they are established
are practices that directly affect the cost of wholesale energy,
capacity and ancillary services, as well as the cost of delivering
wholesale energy to transmission customers. Inaccurate transmission
line ratings may result in Commission-

jurisdictional rates that are unjust and unreasonable.
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    2. Transmission line ratings often are calculated based on
assumptions about ambient conditions that do not accurately reflect the
near-term transfer capability of the system.\2\ For example,
transmission line ratings currently based on seasonal or static
assumptions may indicate less transmission system transfer capability
than the transmission system can actually provide, leading to
restricted flows and increased congestion costs. Alternatively,
transmission line ratings currently based on seasonal or static
assumptions may overstate the near-term transfer capability of the
system, creating potential reliability and safety problems. In either
case, the current use of seasonal and static assumptions results in
transmission line ratings that do not accurately represent the transfer
capability of the transmission system.
---------------------------------------------------------------------------

    \2\ Federal Energy Regulatory Commission, Staff Paper, Managing
Transmission Line Ratings, Docket No. AD19-15-000 (Aug. 2019)
(Commission Staff Paper), https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.
---------------------------------------------------------------------------

    3. To address these issues with respect to shorter-term requests
for transmission service, we propose two requirements for greater use
of ambient-adjusted line ratings (AARs),\3\ which are transmission line
ratings that incorporate near-term forecasted ambient air temperatures.
First, we propose to require that transmission providers use AARs as
the basis for evaluation of transmission service requests that will end
within ten days of the request. Second, we propose to require that
transmission providers use AARs as the basis for determination of the
necessity of certain curtailment, interruption, or redispatch of
transmission service that is anticipated to occur within those ten
days.
---------------------------------------------------------------------------

    \3\ As discussed below, we propose to define an ambient-adjusted
line rating, or AAR, as a transmission line rating that: (1) Applies
to a time period of not greater than one hour; (2) reflects an up-
to-date forecast of ambient air temperature across the time period
to which the rating applies; and (3) is calculated at least each
hour, if not more frequently. Proposed 18 CFR 35.28(b)(10).
---------------------------------------------------------------------------

    4. To address these issues with respect to longer-term requests for
transmission service, we propose to require that transmission providers
use seasonal line ratings as the basis for evaluation of such requests.
We also propose to require that transmission providers use seasonal
line ratings as the basis for the determination of the necessity of
curtailment, interruption, or redispatch that is anticipated to occur
more than ten days in the future.\4\
---------------------------------------------------------------------------

    \4\ The use of seasonal transmission line ratings for long-term
requests for transmission service and as the basis for the
determination of curtailment, interruption, or redispatch is
currently standard practice. However, as detailed later, the
Commission proposes changes to seasonal transmission line rating
implementation.
---------------------------------------------------------------------------

    5. Moreover, in certain situations, use of dynamic line ratings
(DLRs) presents opportunities for transmission line ratings that may be
more accurate than those established with AARs.\5\ DLRs are based not
only on forecasted ambient air temperature, but also on other weather
conditions such as wind, cloud cover, solar irradiance intensity,
precipitation, and/or on transmission line conditions such as tension
or sag. One factor that may contribute to the limited deployment of
DLRs by transmission owners is that the regional transmission
organizations (RTO) and independent system operators (ISO) that operate
the transmission system and oversee organized wholesale electric
markets may not be able to automatically incorporate frequently updated
transmission line ratings such as DLRs into their operating and market
models. To address this issue, we propose to require RTOs/ISOs to
establish and implement the systems and procedures necessary to allow
transmission owners to electronically update transmission line ratings
on at least an hourly basis.
---------------------------------------------------------------------------

    \5\ As discussed below, the Commission proposes to define a
dynamic line rating, or DLR, as a transmission line rating that: (1)
Applies to a time period of not greater than one hour; (2) 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; and (3) is calculated at least
each hour, if not more frequently. Proposed 18 CFR 35.28(b)(11).
---------------------------------------------------------------------------

    6. The proposed reforms noted above are intended to improve the
accuracy of transmission line ratings used during normal (pre-
contingency) operations.\6\ We also seek comment on whether to require
transmission providers to implement unique emergency ratings \7\ that
would be used during post-contingency operations.
---------------------------------------------------------------------------

    \6\ The NERC Glossary defines ``normal rating'' as: ``[t]he
rating as defined by the equipment owner that specifies the level of
electrical loading . . . that a system, facility, or element can
support or withstand through the daily demand cycles without loss of
equipment life.'' 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.
    \7\ The NERC Glossary defines ``emergency rating'' as: ``T[t]he
rating as defined by the equipment owner that specifies the level of
electrical loading or output . . . that a system, facility, or
element can support, produce, or withstand for a finite period. The
rating assumes acceptable loss of equipment life or other physical
or safety limitations for the equipment involved.'' Id. For purposes
of this NOPR, the phrase ``unique emergency ratings'' describes an
emergency rating that is a different value from a facility's normal
rating. Typically, the emergency rating would be a higher value than
the normal rating unless there is specific constraint that prohibits
a higher emergency rating.
---------------------------------------------------------------------------

    7. Finally, we propose to require transmission owners to share
transmission line ratings and methodologies with their transmission
provider(s) and, in regions served by an RTO/ISO, also with the market
monitor(s) of that RTO/ISO. We also seek comment on whether
transmission line ratings and transmission line rating methodologies
should be shared with other transmission providers, upon request.
    8. We seek comment on these proposed reforms by 60 days after
publication of this NOPR in the Federal Register.

II. Background

A. Order Nos. 888 and 889

    9. In Order No. 888, the Commission required public utilities to
unbundle their generation and transmission services and file open
access non-discriminatory transmission tariffs (OATTs) to allow third
parties equal access to their transmission system.\8\ In Order No. 889,
issued at the same time as Order No. 888, the Commission established
part 37 of the Commission's regulations that require each public
utility that owns, controls, or operates facilities used for the
transmission of electric energy in interstate commerce to create or
participate in an Open Access Same-time Information System (OASIS) that
would provide transmission customers the same access to information to
enable them to obtain open access non-discriminatory transmission
service.\9\ Among the new requirements, public utilities were directed
to calculate their available transfer capability (ATC) as a way to give
potential third party transmission customers information on
transmission service availability. In Order No. 888, the Commission
used the term ``Available Transmission Capability'' to describe the
amount of additional

capability available in the transmission network to accommodate
additional requests for transmission services. The Commission in Order
No. 890 adopted the current term ATC in the pro forma OATT to be
consistent with the term generally accepted throughout the
industry.\10\ For the purposes of this proceeding, ATC will also refer
to available flowgate capability.\11\
---------------------------------------------------------------------------

    \8\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & Regs. ]
31,036 (1996) (cross-referenced at 77 FERC ] 61,080), order on
reh'g, Order No. 888-A, 62 FR 12,274 (Mar. 14, 1997), FERC Stats. &
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
    \9\ Open Access Same-Time Information System and Standards of
Conduct, Order No. 889, FERC Stats. & Regs. ] 31,035 (1996) (cross-
referenced at 75 FERC ] 61,078), order on reh'g, Order No. 889-A,
FERC Stats & Regs. ] 31,049 (cross-referenced at 78 FERC ] 61,221),
reh'g denied, Order No. 889-B, 81 FERC ] 61,253 (1997).
    \10\ The NERC Glossary defines ATC as: ``A measure of the
transfer capability remaining in the physical transmission network
for further commercial activity over and above already committed
uses. It is defined as Total Transfer Capability (TTC) less Existing
Transmission Commitments (including retail customer service), less a
Capacity Benefit Margin, less a Transmission Reliability Margin,
plus Postbacks, plus counterflows.'' 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.
    \11\ Available flowgate capability is defined in the NERC
Glossary as: ``A measure of the flow capability remaining on a
Flowgate for further commercial activity over and above already
committed uses. It is defined as [total flowgate capability] TFC
less Existing Transmission Commitments (ETC), less a Capacity
Benefit Margin, less a Transmission Reliability Margin, plus
Postbacks, and plus counterflows.'' 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.
---------------------------------------------------------------------------

    10. In Order No. 889, the Commission required that ATC and Total
Transfer Capability (TTC) be calculated based on a methodology
described in the Transmission Provider's tariff, and that those
calculations be based on current industry practices, standards and
criteria.\12\ The Commission also made further changes to its
regulations as part of Order No. 889 to ensure accuracy of the data
posted on OASIS.\13\ For example, the Commission required that entities
that calculate ATC or TTC on constrained posted paths make publicly
available the underlying data and methodologies.\14\
---------------------------------------------------------------------------

    \12\ Order No. 889, FERC Stats. & Regs. ] 31,035 at ] 31,607.
    \13\ Id. ] 31,608.
    \14\ See 18 CFR 37.6 (b)(2)(ii) (stating that, on request, the
responsible party must make all data used to calculate ATC, TTC,
CBM, and TRM for any constrained posted paths publicly available
(including the limiting element(s) and the cause of the limit (e.g.,
thermal, voltage, stability), as well as load forecast assumptions)
in electronic form within one week of the posting.).
---------------------------------------------------------------------------

    11. At the time, no formal methodologies existed to calculate ATC,
and the Commission encouraged the industry to develop a consistent
transmission line rating methodology.\15\ While Order No. 888 required
transmission providers to include descriptions of ATC methodologies in
their tariffs,\16\ Order No. 889 required public utilities to post ATC
values and certain related information to their OASIS.\17\
---------------------------------------------------------------------------

    \15\ Order No. 889, FERC Stats. & Regs. ] 31,035 at ] 31,607.
    \16\ The Commission requires ``all public utilities that own,
control or operate facilities used for transmitting electric energy
in interstate commerce [t]o file open access non-discriminatory
transmission tariffs that contain minimum terms and conditions of
non-discriminatory service.'' Order No. 888, FERC Stats. & Regs. ]
31,036 at 31,635. Public utilities also are ``required to make
section 206 compliance filings to meet . . . pro forma tariff non-
price minimum terms and conditions of non-discriminatory
transmission. Id. at 31,636. The pro forma OATT's ``Methodology To
Assess Available Transmission Capability'' is proscribed in
Attachment C of the Order. Id. at 31,930.
    \17\ Order No. 889, FERC Stats. & Regs. ] 31,035 at 31,587.
---------------------------------------------------------------------------

B. Order No. 890

    12. In Order No. 890, the Commission addressed and remedied
opportunities for undue discrimination under the regulations and the
pro forma OATT adopted in Order Nos. 888 and 889.\18\ Among other
things, the Commission found that the lack of ATC consistency and
transparency throughout the industry allowed for undue discrimination,
with transmission providers able to favor themselves and their
affiliates over third parties in allocating ATC.\19\ The Commission
also stated that ATC inconsistencies made it difficult for parties to
detect discrimination.\20\ In response to these concerns, the
Commission directed public utilities, working through North American
Electric Reliability Corporation (NERC) Reliability Standards and North
American Energy Standards Board (NAESB) business practices development
processes, to produce workable solutions to complex and contentious
issues surrounding improving the consistency and transparency of ATC
calculations.\21\ This included the development of standard ATC
calculation methodologies, definitions for the components in the ATC
equation, and standards for data inputs, assumptions, and information
exchanges to be applied across the industry.\22\
---------------------------------------------------------------------------

    \18\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 118 FERC ] 61,119, order on
reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on reh'g and
clarification, Order No. 890-B, 123 FERC ] 61,299 (2008), order on
reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009), order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
    \19\ Order No. 890, 118 FERC ] 61,119 at P 83.
    \20\ Id. P 21. In regions with RTOs/ISOs, the RTO/ISO in most
cases calculated the ATC for paths within their territory.
    \21\ Id. P 196.
    \22\ Id. P 207.
---------------------------------------------------------------------------

C. ATC-Related Reliability Standards, Business Practices, and
Commission Regulations

    13. The Commission in Order No. 729,\23\ pursuant to section 215 of
the FPA,\24\ approved six Reliability Standards,\25\ subsequently
referred to as the ``MOD A Reliability Standards'' by NERC, and stated
the Commission believes that these Reliability Standards address the
potential for undue discrimination by requiring industry-wide
transparency and increased consistency regarding all components of the
ATC calculation methodology and certain definitions, data, and modeling
assumptions.\26\
---------------------------------------------------------------------------

    \23\ Mandatory Reliability Standards for the Calculation of
Available Transfer Capability, Capacity Benefit Margins,
Transmission Reliability Margins, Total Transfer Capability, and
Existing Transmission Commitments and Mandatory Reliability
Standards for the Bulk-Power System, Order No. 729, 129 FERC ]
61,155, at P 13 (2009), order on clarification, Order No. 729-A, 131
FERC ] 61,109, order on reh'g, Order No. 729-B, 132 FERC ] 61,027
(2010).
    \24\ 16 U.S.C. 824o.
    \25\ The Reliability Standards were: MOD-001-1--Available
Transmission System Capability; MOD-004-1--Capacity Benefit Margin;
MOD-008-1--TRM Calculation Methodology; MOD-028-1--Area Interchange
Methodology; MOD-029-1--Rated System Path Methodology; and MOD-030-
1--Flowgate Methodology.
    \26\ Order No. 729, 129 FERC ] 61,155 at P 2.
---------------------------------------------------------------------------

    14. On July 16, 2020, the Commission issued a NOPR \27\ proposing
to amend its regulations because of the importance of the ATC
calculation and as a result of the proposed retirement of NERC's MOD A
standards. The Commission proposed to revise its regulations to
establish the general criteria transmission owners must use in
calculating ATC.\28\ The Commission also proposed to adopt the NAESB
wholesale electric quadrant

(WEQ) Business Practice Standards that include commercially relevant
requirements from the existing MOD A Reliability Standards as they
appeared generally consistent with those criteria.\29\ On September 17,
2020, the Commission, in Order No. 873, approved the retirement of 18
Reliability Standard requirements identified by NERC, the Commission-
certified Electric Reliability Organization.\30\ The Commission also
remanded proposed Reliability Standard FAC-008-4 for further
consideration by NERC and took no action on the proposed retirement of
56 MOD A Reliability Standard requirements.\31\
---------------------------------------------------------------------------

    \27\ Standards for Business Practices and Communication
Protocols for Public Utilities, Notice of Proposed Rulemaking, 172
FERC ] 61,047, at P 49 (2020).
    \28\ Id. P 50 (proposing new language, shown in italics, for the
Commission's regulations governing the calculation of ATC and TTC in
18 CFR 37.6(b)(2)(i)), that calculation methods, availability of
information, and requests. Information used to calculate any posting
of ATC and TTC must be dated and time-stamped and all calculations
shall be performed according to consistently applied methodologies
referenced in the Transmission Provider's transmission tariff and
shall be based on Commission-approved Reliability Standards,
business practice and electronic communication standards, and
related implementation documents, as well as current industry
practices, standards and criteria. Transmission Providers shall
calculate ATC and TTC in coordination with and consistent with
capability and usage on neighboring systems, calculate system
capability using factors derived from operations and planning data
for the time frame for which data are being posted (including
anticipated outages), and update ATC and TTC calculations as inputs
change. Such calculations shall be conducted in a manner that is
transparent, consistent, and not unduly discriminatory or
preferential.)
    \29\ Id. P 51, NAESB WEQ-023 Modeling Business Practice
Standards.
    \30\ Electric Reliability Organization Proposal to Retire
Requirements in Reliability Standards Under the NERC Standards
Efficiency Review, Order No. 873, 85 FR 65,207, 172 FERC ] 61,225
(2020).
    \31\ Id. P 4 (noting that the Standard Efficiency Review NOPR
indicated that the Commission intended to ``coordinate the effective
dates for the retirement of the MOD A Reliability Standards with
successor North American Energy Standards Board (NAESB) business
practice standards'' and that, on July 16, 2020, ``the Commission
issued a NOPR in Docket Nos. RM05-5-029 and RM05-5-030 proposing to
amend its regulations to incorporate by reference, with certain
enumerated exceptions, NAESB's Version 003.3 Business Practices'').
---------------------------------------------------------------------------

D. Reliability Standard FAC-008-3 (Facility Ratings)

    15. The requirements of Reliability Standard FAC-008-3 (Facility
Ratings) \32\ are generally as follows:
---------------------------------------------------------------------------

    \32\ NERC, Reliability Standard FAC-008-3 (Facility Ratings),
https://www.nerc.com/pa/Stand/Reliability%20Standards/FAC-008-3.pdf.
---------------------------------------------------------------------------

     Requirement number 1 (``R1'') requires a generator owner
to provide documentation for determining the facility ratings of its
generator facility(ies).
     Requirement R2 requires each generator owner to have a
documented methodology for determining facility ratings of its
equipment connected between the location specified in Requirement R1
and the point of interconnection with the transmission owner.
     Requirement R3 requires each transmission owner to have a
documented methodology for determining facility ratings (facility
ratings methodology) of its facilities.\33\
---------------------------------------------------------------------------

    \33\ Requirements R4 and R5 have been retired effective January
21, 2014.
---------------------------------------------------------------------------

     Requirement R6 requires that the generator owner and
transmission owner also establish facility ratings for their facilities
that are consistent with the associated facility rating methodology or
documentation for determining their facility ratings.
     Requirement R7 provides that facility ratings must be
provided to other entities as specified in the requirements.
     Requirement R8 requires the identification and
documentation of the limiting component for all facilities and the
increase in rating if that component were no longer the limiting
component (i.e., the rating for the second most limiting component) for
facilities associated with an Interconnection reliability operating
limit, a limitation of TTC, an impediment to generator deliverability,
or an impediment to service to a major load center.
     Requirement R8 also requires entities to provide
information to requesting entities regarding their facilities.
Requirement R8, Part 8.1 requires an entity to provide the identity of
the most limiting equipment of a facility as well as the facility
rating to requesting entities. Requirement R8, Part 8.2 requires an
entity to provide the identity of the next most limiting equipment of a
facility as well as the thermal rating of that equipment.

E. Commission Staff Paper and September 2019 Technical Conference

    16. In August 2019, the Commission issued the Commission Staff
Paper, ``Managing Transmission Line Ratings'' drawing on Commission
staff outreach conducted in spring 2019 with RTOs/ISOs, transmission
owners, and trade groups, as well as staff participation in a November
2017 Idaho National Laboratory workshop. The report included background
on common transmission line rating approaches, current practices in
RTOs/ISOs, a review of pilot projects, and a discussion of potential
improvements.\34\
---------------------------------------------------------------------------

    \34\ Commission Staff Paper, https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.
---------------------------------------------------------------------------

    17. On September 10 and 11, 2019, Commission staff convened a
technical conference (September 2019 Technical Conference) to discuss
what transmission line ratings and related practices might constitute
best practices, and what, if any, Commission action in these areas
might be appropriate. In particular, the September 2019 Technical
Conference covered issues such as: (1) Common transmission line rating
methodologies; (2) AAR and DLR implementation benefits and challenges;
(3) the ability of RTOs/ISOs to accept and use DLRs; and (4) the
transparency of transmission line rating methodologies.\35\
Participants at the September 2019 Technical Conference included
utilities (some of which implement both AARs and DLRs), technology
vendors, RTO/ISO market monitors, and organizations representing
customers.
---------------------------------------------------------------------------

    \35\ Supplemental Notice of Technical Conference, Docket No.
AD19-15-000 (Sep. 4, 2019).
---------------------------------------------------------------------------

    18. In October 2019, the Commission requested comments on questions
that arose from the September 2019 Technical Conference.\36\ In
response, commenters addressed issues related to AARs and DLRs,
emergency ratings, and transparency, as discussed below.\37\
---------------------------------------------------------------------------

    \36\ Notice Inviting Post-Technical Conference Comments, Docket
No. AD19-15-000 (Oct. 2, 2019).
    \37\ A list of commenters and the abbreviated names used in this
NOPR appears in appendix A.
---------------------------------------------------------------------------

III. Technical Background

A. Transmission Line Rating Fundamentals

    19. Transmission line ratings represent the maximum transfer
capability of each transmission line. A variety of entities use them in
their reliability models, including transmission providers, reliability
coordinators, transmission system operators, planning authorities,
transmission owners, and transmission planners. Transmission line
ratings in reliability models are used to determine operating limits
and can affect transmission system operator action, such as
curtailment, interruption, or redispatch decisions. As market
operators, RTOs/ISOs use transmission line ratings in their market
models to establish commitment and dispatch. In these market models,
transmission line ratings affect congestion, and, thereby, affect the
prices of energy, operating reserves, and other ancillary services.
Transmission line ratings are based on the most limiting of three types
of transmission line ratings/limits: Thermal ratings, voltage limits,
and stability limits. Thermal ratings can change with ambient
conditions; however, voltage and stability limits are fixed values that
limit the power flow on a transmission line from exceeding the point
above which there is an unacceptable risk of a voltage or stability
problem. Transmission line ratings are dictated by the most limiting
element across the entire transmission facility, which includes the
overhead conductors and the associated equipment necessary for the
transfer or movement of electric energy across a transmission facility
(e.g., switches, breakers, busses, metering equipment, relay equipment,
etc.).\38\
---------------------------------------------------------------------------

    \38\ The NERC Glossary defines a facility as ``a set of
electrical equipment that operates as a single Bulk Electric System
Element (e.g., a line, a generator, a shunt compensator,
transformer, etc.)'', defines a facility rating as: ``the maximum or
minimum voltage, current, frequency, or real or reactive power flow
through a facility that does not violate the applicable equipment
rating of any equipment comprising the facility''. 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.

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

    20. Thermal ratings are determined by taking into consideration the
physical characteristics of the conductor and making assumptions about
ambient weather conditions to determine the maximum amount of power
that can flow through a conductor while keeping the conductor under its
maximum operating temperature. Transmission conductors that exceed
their maximum operating temperature can sag and/or become damaged
through material weakening (or ``annealing''), resulting in reduced
capability and causing potential reliability and/or public safety
concerns.
    21. Conductor temperatures are impacted by a variety of factors,
notably ambient air temperatures. Specifically, increases in ambient
air temperatures tend to increase a transmission line's operating
temperature. Electric power flowing through a transmission line
increases the temperature of the line above ambient temperature due to
the line's electrical resistance. Other conditions and phenomena also
tend to increase transmission line temperature, particularly solar
irradiance intensity. Conversely, some conditions and phenomena tend to
lower transmission line temperature, particularly wind. Thermal
transmission line limits, therefore, generally decrease with warmer
ambient air temperatures and greater solar irradiance intensity, and
generally increase with cooler ambient air temperatures and higher wind
speeds. Engineering standards help translate line characteristics and
ambient weather assumptions into transmission line ratings. The
different approaches to transmission line ratings discussed below
primarily reflect differences in how frequently ambient weather
assumptions are updated (which can range from decades to hours or even
minutes) and what types of ambient weather assumptions are updated (air
temperature, solar irradiance intensity, wind speed, etc.).

B. Current Transmission Line Rating Practices

    22. In practice, thermal rating methodologies have evolved along a
spectrum from fully static, with no change in ambient condition
assumptions for thermal limits on conductors, to nearly ``real-time''
dynamic ratings. Static ratings are intended to reflect conservative
assumptions about the worst-case ambient conditions that equipment
might face (e.g., the hottest summer day) and are typically updated
only when equipment is changed or ambient condition assumptions are
updated. Thus, they often remain unchanged for years or even decades.
Seasonal ratings are similar to static ratings in that they change
infrequently, but they use different ambient condition assumptions for
different seasons.\39\
---------------------------------------------------------------------------

    \39\ Although transmission owners typically define seasonal
ratings as summer and winter seasonal ratings, transmission owners
may create more granular seasonal ratings that could include unique
seasonal ratings for the spring and fall seasons.
---------------------------------------------------------------------------

    23. Generally, AARs are transmission line ratings that apply to a
time period not greater than one hour, reflect an up-to-date forecast
of ambient air temperature (and possibly other forecasted inputs) \40\
across the time period to which the rating applies, and is calculated
at least each hour, if not more frequently. AAR implementation can be a
multi-step process that requires selecting an appropriate line,
receiving information about ambient air temperatures (prevailing and
forecasted, typically from the National Oceanic and Atmospheric
Administration or a private service), rating forecasting, and rating
validation. Implementation of AARs often involves transmission owners
developing electronic rating ``look-up'' tables for their transmission
facilities, which yield transmission line ratings for any air
temperature. Transmission line ratings are then determined by using the
rating that corresponds to the ambient air temperature that is
forecasted over the period of the rating (e.g., hour or 15 or 5
minutes).
---------------------------------------------------------------------------

    \40\ For example, PJM implements day and night ambient air
temperature tables, where the night ambient air temperature table
assumes zero solar irradiance. Exelon Comments at 25.
---------------------------------------------------------------------------

    24. AAR methodologies usually result in higher transmission line
ratings relative to seasonal or static rating methodologies because,
while seasonal or static ratings are based on the conservative, worst-
case temperature values, AARs are usually based on ambient air
temperatures lower than the conservative, worst-case temperature
values. For a small percentage of intervals, however, AARs will
identify that the near-term ambient temperature conditions are actually
more extreme than the long-term assumptions used in seasonal or static
ratings, and will therefore result in a line rating that is lower than
a seasonal or static rating would have allowed.
    25. On the opposite end of the spectrum from static ratings are
DLRs, which use assumptions that are updated in near real-time. In
addition to ambient air temperature, DLRs can incorporate additional
ambient conditions such as wind speed and direction, solar irradiance
intensity (considering cloud cover), and/or precipitation. DLRs may
also incorporate measurements from sensors installed on or near the
line, such as wind speed sensors, line tension sensors, conductor
temperature sensors, and/or photo-spatial sensors (e.g., 3-D laser
scanning) monitoring line sag. Such weather and other data are not
immediately converted to transmission line ratings in real-time.
Instead, DLR implementation combines current sensor data with data from
the recent past to create reliable short-term forecasts of the relevant
weather and other variables for longer periods of time (potentially as
granular as five minute increments, but, more likely, larger time
periods that could be as long as an hour). Such forecasts are used to
develop transmission line ratings that can be depended on by system
operators for a specified period (e.g., an hour or 15 or 5 minutes).
Under DLR approaches, the use of additional data (beyond the ambient
temperature data used in AAR approaches) can allow DLRs to even more
accurately reflect transfer capability.
    26. DLR methodologies usually result in higher transmission line
ratings relative to AAR and other methodologies. However, as discussed
above for AAR, for a small percentage of intervals, DLRs will identify
that the near-term weather and/or other conditions are actually more
extreme than the assumptions under other methodologies, and will
therefore result in a line rating that is lower than a static,
seasonal, or AAR rating would have allowed. Moreover, the additional
weather and conductor data that the sensors can provide, such as wind
speed and direction, solar irradiance intensity, precipitation, and
line conditions such as tension and sag, improve operational and
situational awareness by helping transmission operators to better
understand real-time transmission line conditions and potential
anomalies, such as possible clearance violations or galloping.
    27. While DLRs have unique benefits, they also have unique
implementation challenges. The additional data and communications
required under DLR approaches increase implementation costs and system
complexity. DLR implementation requires the strategic deployment and
maintenance of sensors. By increasing the amounts of transmission line
rating data and by introducing additional communication nodes inside a
transmission owner network, DLRs introduce additional physical and
cyber security risks.

Moreover, DLRs can require additional training or knowledge for some
transmission providers or transmission owner personnel.
    28. DLRs are not widely deployed in the United States. Transmission
owners have tested DLRs on some transmission lines,\41\ but they
generally have not incorporated DLRs into operations. For transmission
owners in RTOs/ISOs, they must also work with the RTO/ISO to determine
whether RTO/ISO Energy Management Systems (EMSs) are able to accept a
frequently changing transmission line rating signal. If the RTO/ISO EMS
cannot accept the information provided by DLRs, such a limitation would
significantly reduce the potential benefits of DLRs.
---------------------------------------------------------------------------

    \41\ For example, some prominent DLR pilot projects have been
undertaken in ERCOT, NYISO, and PJM. In ERCOT, ONCOR tested
conductor tension-monitor technology, conductor sag, and clearance
monitors on eight transmission circuits (138 kilovolt (kV) and 345
kV). In NYISO, the New York Power Authority partnered with the
Electric Power Research Institute to install sensor technology
designed to measure conductor temperature, weather conditions, and
conductor sag on three 230 kV ransmission lines. In PJM, pilot
studies were conducted on the 345 kV Cook-Olive transmission line
and an additional line to quantify the financial impact of DLRs.
---------------------------------------------------------------------------

    29. Several participants at the September 2019 Technical
Conference, have already implemented AARs, including AEP, Dominion,
Entergy, and Exelon. ERCOT explained in its testimony that, of its
nearly 7,000 transmission lines, approximately two thirds are rated
dynamically using a process comparable to what we refer to as AARs.\42\
Likewise, PJM explained in its post-conference comments that use of
AARs is commonplace among the overwhelming majority of transmission
owners in the PJM region.\43\ According to Potomac Economics, Entergy
and one additional transmission line owner implement AARs in MISO.\44\
Outside of ERCOT and PJM, most transmission owners implement seasonal
transmission ratings. Seasonal ratings are the norm among non-RTO/ISO
transmission owners as well as in CAISO, ISO-NE, NYISO, MISO, and SPP,
although at least some transmission owners in RTO/ISO regions use
static ratings.\45\
---------------------------------------------------------------------------

    \42\ September 2019 Technical Conference, AD19-15, Day One Tr.
at 79 (filed Oct. 8, 2019) (September 2019 Technical Conference, Day
1 Tr.).
    \43\ PJM Comments at 2 (citing Testimony of Michael Kormos
(Exelon) at 1. (``Exelon has adopted ambient-adjusted facility
ratings for the transmission facilities of five of our six
utilities, with Commonwealth Edison scheduled to complete the
transition to ambient-adjusted facility ratings next year.'');
Testimony of Francisco Velez (Dominion) at 2-3.
    \44\ Potomac Economics Comments at 6-7.
    \45\ Commission Staff Paper at 2, 12.
---------------------------------------------------------------------------

C. Emergency Ratings

    30. For short periods of time, most transmission equipment can
withstand high currents without sustaining damage. This fact allows
transmission owners to develop two sets of ratings for most facilities:
Normal ratings and emergency ratings. Normal ratings are ratings that
can be safely used continuously (i.e., not time-limited) without
overheating the transmission equipment. Emergency ratings are ratings
that can be safely used for a limited period of time. This period of
time can vary from as short as five minutes to as long as four hours or
more.\46\
---------------------------------------------------------------------------

    \46\ In practice, emergency ratings can vary significantly in
duration. As was observed in the September 2019 Technical
Conference, there does not appear to be clear standardization of the
emergency rating timeframes. September 2019 Technical Conference,
Day 1 Tr. at 175.
---------------------------------------------------------------------------

    31. Whether and how a transmission owner establishes emergency
ratings is important because emergency ratings are a critical input
into determining operating limits in market models, both during normal
operations and during post-contingency operations. In general,
operating limits (i.e., the maximum allowable MW flow) for any facility
or set of facilities are set at a level to ensure that the flows on all
facilities will be within applicable facility ratings both during
normal operations and during post-contingency operations. Therefore,
these operating limits create binding transmission constraints and
result in congestion during normal operations and post-contingency,
which increases the cost of production for electric energy. Following a
contingency, if a transmission provider is able to use emergency
ratings, system operators are afforded the flexibility to allow higher
loading on transmission facilities for a short time while they
reconfigure the transmission system, dispatch generation, or take other
measures (e.g., load shedding) to stabilize the system and return it to
within normal limits. Because emergency ratings are generally higher
than normal ratings, using emergency ratings allows for higher
operating limits, and, thus, more efficient system commitment and
dispatch solutions. More efficient commitment and dispatch solutions,
in turn, reduce the prices paid by consumers for electric energy.
    32. However, not all transmission owners use emergency ratings that
are different from their normal ratings. For example, Potomac
Economics, the market monitor for MISO, NYISO, ISO-NE, and ERCOT, notes
that while MISO requires transmission owners to submit both normal and
emergency ratings, 63% of transmission line ratings provided to MISO
reflect emergency ratings that are equal to the normal ratings.\47\
Generally, RTOs/ISOs do not require unique emergency ratings. Instead,
transmission owners can decide whether to submit unique emergency
ratings, or whether to submit emergency ratings that equal their normal
ratings.\48\
---------------------------------------------------------------------------

    \47\ September 2019 Technical Conference, Day 2 Tr. at 311-312.
    \48\ For example, SPP and ISO-NE allow their transmission owners
to use unique emergency ratings, but neither RTO/ISO specifically
requires them, see SPP Planning Criteria, Revision 2.2 (3/16/2020),
Section 7.2. See also ISO-NE, ISO New England Planning Procedure No.
7: Procedures for Determining and Implementing Transmission Facility
Ratings in New England (Revision 4) (Nov. 7, 2014), https://www.iso-ne.com/static-assets/documents/rules_proceds/isone_plan/pp07/pp7_final.pdf.
---------------------------------------------------------------------------

D. Rating and Methodology Transparency

    33. There are two categories of information relevant to
transparency concerns: Transmission line rating methodologies and the
resulting transmission line ratings. Generally, transmission line
ratings and ratings methodologies are not currently available to
transmission providers or the public at large, although certain
transmission owners and/or operators make public their transmission
line ratings and, less commonly, their ratings methodologies. Certain
transmission providers explained that they do not provide such
information because it is governed by confidentiality restrictions.\49\
---------------------------------------------------------------------------

    \49\ MISO Transmission Owners claim that some of the information
related to the limiting element used to establish a transmission
line rating is ``confidential.'' MISO Transmission Owners Comments
at 20; Dominion claims that FAC-008's Requirement 8 requires
confidential sharing of limiting element information only with
``associated Reliability Coordinator(s), Planning Coordinator(s),
Transmission Planner(s), Transmission Owner(s) and Transmission
Operator(s) when requested.'' Dominion Comments at 14.
---------------------------------------------------------------------------

    34. The Commission Staff Paper observed that some entities noted
the lack of transparency regarding transmission line rating
information.\50\ At the subsequent September 2019 Technical Conference,
some participants expressed a desire for additional line rating
transparency regardless of whether the Commission acts on requirements
for AARs or DLRs. Potomac Economics stated that additional transparency
regarding rating methodologies was ``essential'' for administering an
AAR requirement.\51\

WATT noted that transmission owners may have an incentive to be overly
conservative with their line rating methodologies and that increasing
transparency around these methodologies could improve efficiency.\52\
---------------------------------------------------------------------------

    \50\ Commission Staff Paper at 28.
    \51\ September 2019 Technical Conference, Day 2 Tr. at 309.
    \52\ September 2019 Technical Conference, Day 1 Tr. at 23.
---------------------------------------------------------------------------

    35. At the September 2019 Technical Conference, panelists also
discussed auditing of line ratings and rating methodologies. Panelists
disagreed over whether methodologies and ratings were sufficiently
audited by NERC Regional Entities or other parties to ensure just and
reasonable rates.
    36. Separate from the outreach and technical conference
discussions, NERC Reliability Standard FAC-008-3 requires transmission
owners to document their facility ratings methodology. While NERC
Regional Entities are responsible for auditing line ratings for
compliance with Reliability Standards, FAC-008-3 Requirement 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.\53\ Such data requests remain non-public.
---------------------------------------------------------------------------

    \53\ NERC Reliability Standard FAC-008-3--Facility Ratings,
Requirement R8.
---------------------------------------------------------------------------

    37. Lastly, some transmission owners periodically report rating
methodologies in FERC Form 715, Part IV.\54\
---------------------------------------------------------------------------

    \54\ FERC Form 715 is a multi-part annual transmission planning
and evaluation report which each transmitting utility that operates
integrated transmission system facilities rated at or above 100
kilovolts (kV), must annually submit.
---------------------------------------------------------------------------

IV. Need for Reform

A. Transmission Line Ratings

    38. For the reasons discussed below, we preliminarily find that
transmission line ratings and the rules by which they are established
are practices that directly affect the cost of wholesale energy,
capacity and ancillary services, as well as the cost of delivering
wholesale energy to transmission customers. Because of those
relationships, inaccurate transmission line ratings may result in
Commission-jurisdictional rates that are unjust and unreasonable.
    39. First, most transmission owners implement seasonal or static
transmission line rating methodologies. Such seasonal or static line
ratings are based on conservative, worst-case assumptions about the
long-term conditions, such as the expected high temperatures that are
likely to occur over the longer term.\55\ While such long-term
assumptions may be appropriate in various planning contexts, they often
do not reflect the true near-term transfer capability of transmission
facilities as relevant to the availability of, and arrangement for,
point-to-point transmission service. Thus, they fail to reflect the
true cost of delivering wholesale energy to transmission customers.
---------------------------------------------------------------------------

    \55\ For example, transmission providers appropriately utilize
conservative long-term assumptions about long-term conditions to
incorporate requests for long-term firm point-to-point transmission
service, which the pro forma OATT defines as ``firm point-to-point
transmission service under Part II of the Tariff with a term of one
year or more'' (pro forma OATT section 1.19) and requests for
network integration transmission service, whose applications require
10-year projections of all network resources (pro forma OATT section
29.2). Additionally, planning authorities appropriately utilize
conservative long-term assumptions in the long-term transmission
planning horizon and the near-term transmission planning horizon.
---------------------------------------------------------------------------

    40. In the RTO/ISO markets, line ratings directly affect the
dispatch and unit commitment computations by constraining power flows
on individual transmission facilities. The resulting congestion costs
are directly reflected in locational marginal prices (LMPs). Outside of
RTOs/ISOs, LMPs are not generally used; however, transmission line
ratings can still directly affect the cost to deliver wholesale energy
to transmission customers by limiting transmission of electric energy
under both network transmission service and point-to-point transmission
service offered under the pro forma OATT.
    41. In both RTO/ISO and non-RTO/ISO areas, incorporating near-term
forecasts of ambient air temperatures in transmission line ratings
would result in more accurately reflecting the actual cost of
delivering wholesale energy to transmission customers. Because actual
ambient temperatures are usually not as high as the ambient
temperatures conservatively assumed in seasonal and static ratings,
updating transmission line ratings used in near-term transmission
service to reflect ambient temperatures usually results in increased
system transfer capability. By increasing transfer capability,
congestion costs will, on average, decline because transmission
providers will be able to import less expensive power into what were
previously constrained areas. For example, Potomac Economics has found
that AAR implementation by those not already doing so in MISO alone
would have produced approximately $94 million and $78 million in
reduced congestion costs in 2017 and in 2018, respectively.\56\ Such
congestion cost changes and related overall price changes will more
accurately reflect the actual congestion on the system and, similarly,
more accurately reflect the cost of delivering wholesale energy to
transmission customers. Likewise, the ability to increase transmission
flows into load pockets may reduce transmission provider reliance on
local reserves inside load pockets, which may reduce local reserve
requirements and the costs to maintain that required level of reserves.
---------------------------------------------------------------------------

    \56\ Potomac Economics Comments at 6-7.
---------------------------------------------------------------------------

    42. While current line rating practices usually understate
transmission capability, they can also overstate transmission
capability. While actual ambient temperatures are usually not as high
as the assumed seasonal or static temperature input, in some instances
actual ambient temperatures exceed those assumed temperatures. In those
instances, seasonal or static transmission line rating methodologies
result in ratings that reflect more transfer capability than physically
exists, and therefore such line ratings allow access to some electric
power supplies and/or demand that would not be available if ratings
reflected the true transfer capability. Overstating transmission
capability, like understating transmission capability, results in
wholesale energy rates that fail to reflect the actual cost of
delivering wholesale energy to transmission customers, but, by
contrast, results in inaccurately low congestion pricing. Moreover,
overstating transmission capability may risk damage to equipment, and
may prevent occurrences of rates for scarcity pricing or transmission
constraint penalty factors that serve as important signals to the
market that more generation and/or transmission investment may be
needed in the long-term.
    43. Second, regarding potential DLR implementation, some RTOs/ISOs
may rely on software that cannot accommodate line ratings that
frequently change, such as DLRs. Without reflecting such frequent
changes to line ratings, such software may serve as a barrier that
prevents transmission owners in RTOs/ISOs from implementing DLRs that
can better reflect the actual transmission capability of the
transmission system. As noted above, in addition to ambient air
temperature, other weather conditions such as wind, cloud cover, solar
irradiance intensity, and precipitation, and transmission line
conditions such as tension and sag, can affect the

amount of transfer capability of a given transmission facility. DLRs
incorporate these additional inputs and thereby provide transmission
line ratings that are closer to the true thermal transmission line
limit than AARs, which can result in rates that even more accurately
reflect the costs of delivering wholesale energy to transmission
customers. But, even if a transmission owner sought to implement DLRs,
the RTO/ISO's EMS may not be able to accept and use the resulting
transmission line rating. This inability to automatically accept and
use a DLR may prevent the market from benefiting from the more accurate
representation of current system conditions that would otherwise
produce prices that more accurately reflect the costs of delivering
wholesale energy to transmission customers. Therefore, we preliminarily
find that current transmission line rating practices in RTOs/ISOs that
do not permit the acceptance of DLRs from transmission owners may
result in rates that do not reflect the actual costs of delivering
wholesale energy to transmission customers.
    44. Third, regarding emergency ratings, current transmission line
rating practices may fail to use emergency ratings, and in failing to
do so, may result in ratings that do not accurately reflect the near-
term transfer capability of the system and therefore may result in
rates that do not reflect actual costs to delivering wholesale energy
to transmission customers. As discussed above, transmission owners
often develop two sets of ratings for most facilities: Normal ratings
that can be safely used continuously, and emergency ratings that can be
used for a specified shorter period of time, typically during post-
contingency operations.
    45. In RTO/ISO markets, market models, such as security-constrained
economic dispatch (SCED) and security-constrained unit commitment
(SCUC) models, generally calculate resource dispatch and commitments
that ensure that all facilities will be within applicable facility
ratings both during normal operations and following any modeled
contingency (e.g., following the loss of a transmission line). In
ensuring that the system is stable and reliable following a
contingency, SCED and SCUC models often allow post-contingency flows on
lines to exceed normal ratings for short periods of time, as long as
the flows do not exceed the applicable emergency rating for the
corresponding timeframe. Because these emergency ratings are a more
accurate representation of the flow limits over those shorter
timeframes, their use in models of post-contingency flows may produce
prices which more accurately reflect actual costs to delivering
wholesale energy to transmission customers.
    46. While most or all RTO/ISO markets consider both normal and
emergency ratings as part of their SCUC and SCED models, not all
transmission owners have chosen to incorporate unique emergency ratings
into their transmission line rating methodologies. That is, some
transmission owners in RTO/ISO regions provide to the RTOs/ISOs
emergency ratings that are just a copy of the normal ratings,\57\
essentially creating the same situation as if the RTO/ISO did not use
emergency ratings at all when modeling contingencies. As discussed
above, this may result in the use of less accurate flow limits, and
less accurate costs for delivering wholesale energy to transmission
customers. According to Potomac Economics, for example, this failure to
implement unique emergency ratings resulted in approximately $62
million and $68 million in additional costs in 2017 and in 2018,
respectively, in MISO alone.\58\ Therefore, we seek comment on whether
not using unique emergency ratings, as discussed below, similarly may
not be just and reasonable.
---------------------------------------------------------------------------

    \57\ Here we are describing the situation where the emergency
ratings are arbitrarily set equal to the normal ratings. On the
other hand, there may be some instances where, after a proper
technical analysis considering the relevant rating timeframes, the
emergency rating is nonetheless equal to the normal rating. As
relevant to the discussion here, such ratings would be considered
``unique'' because they were developed from the appropriate, unique
technical inputs.
    \58\ Potomac Economics Comments at 6-7.
---------------------------------------------------------------------------

B. Transparency

    47. We preliminarily find that the current level of transparency
into transmission line ratings and transmission line rating
methodologies may result in unjust and unreasonable rates. The current
level of transparency may prevent transmission provider(s) and market
monitors from having the opportunity to validate transmission line
ratings. This may result in transmission owners submitting inaccurate
near-term transmission line ratings, which may result in rates that do
not accurately reflect congestion and reserve costs on the system, as
discussed above. For example, without knowing the basis for a given
line rating that frequently binds and elevates prices, a transmission
provider and/or market monitor cannot determine whether the line rating
is miscalculated or accurately calculated.

V. Discussion

A. Transmission Line Ratings

1. Comments
a. Ambient-Adjusted Line Ratings
    48. At the September 2019 Technical Conference, participants and
staff explored whether the Commission should require the implementation
of AARs.\59\ Several participants supported a requirement to implement
AARs, with several stating their support for AAR implementation as a
best practice. Supporters contend that while AAR implementation
requires an initial investment to upgrade the EMS, these costs are a
manageable way to increase transfer capability.\60\ Potomac Economics
noted that significant economic benefits would have accrued to market
participants if all MISO transmission owners had implemented AARs and
unique emergency ratings.\61\
---------------------------------------------------------------------------

    \59\ Panelists participating in the discussion of a potential
requirement to implement AARs included representatives from AEP,
Ameren (on behalf of the MISO Transmission Owners), CAISO, Entergy,
PacifiCorp, Potomac Economics, and Vistra Energy.
    \60\ September 2019 Technical Conference, Day 1 Tr. at 142.
    \61\ Id. at 171.
---------------------------------------------------------------------------

    49. Several participants did not support an AAR requirement.
Ameren, on behalf of the MISO Transmission Owners, argued that AAR
implementation would be costly and complex. PacifiCorp argued that the
benefits of implementing AARs and DLRs would not materialize on all
lines, and therefore cautioned that the Commission should not require
AAR implementation on all lines.\62\ Finally, Ameren argued that
because forecasting was necessary for day-ahead AAR implementation,
there could be liability associated with an incorrect forecast.\63\
---------------------------------------------------------------------------

    \62\ Id. at 163.
    \63\ Id. at 148.
---------------------------------------------------------------------------

    50. Following the September 2019 Technical Conference, the
Commission requested comments on all conference discussion items,
including the appropriateness of a Commission requirement to implement
AARs, how a requirement might be structured, whether an AAR requirement
should be extended to day-ahead markets, and whether any forecasted
ambient conditions other than temperature should be considered in an
AAR requirement.
    51. Many entities filed comments in support of a requirement to
implement AARs, noting that an AAR requirement represents a cost-
effective industry best practice that would achieve significant savings
to ratepayers. Some transmission owners reiterated points

made in the September 2019 Technical Conference. AEP explains that it
has used AARs in real-time operations for more than a decade and that
it monitors temperature zones in its regions and retrieves real-time
temperature data for every state estimation process run. AEP states
that AARs using real-time and next day forecasted regional temperatures
can benefit customers and bring flexibility to transmission
operations.\64\
---------------------------------------------------------------------------

    \64\ AEP Comments at 2.
---------------------------------------------------------------------------

    52. Dominion explains that requiring the use of AARs, rather than a
default temperature assumption that is ``too conservative,'' will allow
transmission line ratings to better reflect forecasted conditions.
Dominion cautions, however, against AARs that make overly aggressive
assumptions, which would also result in the transmission system being
operated ``less conservatively'' and a degradation of grid
reliability.\65\
---------------------------------------------------------------------------

    \65\ Dominion Comments at 3-4.
---------------------------------------------------------------------------

    53. Similarly, Exelon states that it would not oppose a properly
structured requirement to implement AARs in both real-time and day-
ahead markets. Exelon explains that AARs represent a best practice and
a cost-effective way to enhance transmission use to the benefit of
customers.\66\ As background, Exelon explains that PJM requires its
transmission owners to provide ambient temperature-dependent ratings
for both daytime and nighttime periods (which account for the presence
or lack of solar irradiance heating), and for normal, long-term
emergency, short-term emergency, and load dump conditions.\67\ Exelon
explains that implementing AARs results in more accurate transmission
line ratings, reducing the likelihood of overloading a line and thus
creating reliability benefits. Exelon reiterates its comments from the
conference that, while implementing AARs requires initial investments,
AARs are a cost-effective way to reduce congestion and enhance
reliability.\68\
---------------------------------------------------------------------------

    \66\ Exelon Comments at 1.
    \67\ Id. at 25-26.
    \68\ Id. at 1, 9.
---------------------------------------------------------------------------

    54. While generally supporting a requirement to implement AARs,
AEP, Dominion, and Exelon express caution and request flexibility
regarding AAR implementation. Dominion explains that it would not
support a requirement for AAR implementation to be fully automated.\69\
Dominion and Exelon warn that AAR implementation will not eliminate
congestion.\70\ Exelon further cautions that an AAR requirement should
only apply to transmission facility ratings sensitive to temperature
changes,\71\ that transmission owners should have flexibility to
determine appropriate temperature granularity,\72\ and that it may not
be appropriate to apply AARs to certain degraded or older assets.\73\
AEP cautions that entities that have not implemented AARs before will
incur some up-front costs, including internal process development and
documentation costs, weather data subscriptions, software changes, and
training, but explains that these costs should be manageable.\74\
Exelon and AEP both also caution that AAR implementation should be
applied only to real-time and day-ahead markets and should not be
considered permanent solutions to address thermal constraints
identified in long-term transmission planning reliability
assessments.\75\
---------------------------------------------------------------------------

    \69\ Dominion Comments at 5-6.
    \70\ Exelon Comments at 10; Dominion Comments at 11.
    \71\ Exelon Comments at 22-23.
    \72\ Id. at 24.
    \73\ Id. at 23.
    \74\ AEP Comments at 2-3.
    \75\ Exelon Comments at 5; AEP Comments at 3.
---------------------------------------------------------------------------

    55. Both Potomac Economics and Monitoring Analytics support a
requirement for transmission owners to implement AARs that must be
updated hourly.\76\ Monitoring Analytics states that the ``failure to
use AARs means that line ratings in actual use are wrong much of the
time,'' which they argue is not acceptable.\77\ Potomac Economics
estimates that adoption of AARs in MISO by those not already doing so
would have produced approximately $78 million and $94 million in annual
benefits in 2017 and 2018, respectively. Potomac Economics further
estimates the savings derived from Entergy and another unnamed MISO
transmission owner's current AAR implementation to have been $51.3
million over 2017 and 2018.\78\ Potomac Economics explains that an AAR
requirement would enhance reliability by increasing operational and
situational awareness, by ensuring transmission line ratings are more
accurate, and by ensuring that transmission providers have a better
understanding of the capabilities of transmission facilities.\79\
---------------------------------------------------------------------------

    \76\ Potomac Economics Comments at 2-3; Monitoring Analytics
Comments at 5.
    \77\ Monitoring Analytics Comments at 5.
    \78\ Potomac Economics Comments at 6-7. Potomac Economics
explains that estimates of benefits will necessarily be conservative
given that the shadow price would increase if the market was
controlling to a lower rating.
    \79\ Id. at 8.
---------------------------------------------------------------------------

    56. DTE, TAPS, Industrial Customers, and OMS each make supportive
comments. Citing Entergy's presentation from the September 2019
Technical Conference, DTE explains that using AARs can increase
transmission line ratings by up to 25% for lower-voltage facilities and
by 5% on higher-voltage facilities, and its ongoing implementation
requires only ``one full-time engineer to maintain the associated in-
house database, perform modeling updates, and liaison with real-time
system operations personnel and IT resources to support automation of
the calculations.'' \80\ DTE therefore submits that AARs can be
implemented without causing any undue burden.\81\ DTE states that
transmission owners are obligated to implement the most cost-effective
solution, and given the experience of other transmission owners that
have successfully implemented AARs, DTE contends that transmission
owners should be required to implement AARs because they are the most
cost-effective solution.\82\
---------------------------------------------------------------------------

    \80\ DTE Comments at 2.
    \81\ Id.
    \82\ Id. at 3.
---------------------------------------------------------------------------

    57. TAPS agrees with September 2019 Technical Conference
participants, such as AEP, who contended that the Commission should
issue a rulemaking requiring AAR implementation, assuming appropriate
safeguards.\83\ TAPS encourages a requirement for AAR implementation to
be part of an effort to ensure more accurate transmission line ratings,
as part of good utility practice, and focusing AAR application where
congestion reductions might be most meaningful.\84\ To identify
locations where AAR application would be beneficial, TAPS explains that
RTOs/ISOs should have backstop authority to identify transmission
facility candidates following a transparent process where the RTO/ISO
is directed to independently evaluate the grid for beneficial AAR
candidates.\85\ Noting the importance for transmission line ratings to
be both accurate and applied in a non-discriminatory manner, as well as
the challenges of ensuring accuracy and preventing discrimination in
the absence of an independent entity facilitating AAR implementation,
TAPS explains that the Commission should give serious examination to
AAR application in non-RTO/ISO regions.\86\
---------------------------------------------------------------------------

    \83\ TAPS Comments at 4-5.
    \84\ Id. at 9.
    \85\ Id. at 10.
    \86\ Id. at 11.
---------------------------------------------------------------------------

    58. Industrial Customers similarly argue that the Commission, at a
minimum, should require transmission owners to implement AARs on the
most congested transmission lines and facilities.\87\ Industrial
Customers explain that AARs provide a more

accurate representation of ATC and contend that using AARs is good
utility practice by allowing transmission operators to better optimize
existing circuits and reduce electric prices.\88\ For these reasons,
Industrial Customers contend the Commission should require the
implementation of AARs, but, noting the possibility that a cost-benefit
comparison may change at a very granular level, only on such facilities
where AAR implementation is truly cost-effective.\89\
---------------------------------------------------------------------------

    \87\ Industrial Customers Comments at 15.
    \88\ Id. at 14-15.
    \89\ Id. at 14-16.
---------------------------------------------------------------------------

    59. PJM explains that it has derived significant operational value
in the adoption of AARs, explaining that its use of AARs has allowed it
to take advantage of additional transfer capability that promotes a
more reliable system dispatch.\90\
---------------------------------------------------------------------------

    \90\ PJM Comments at 2-3.
---------------------------------------------------------------------------

    60. Other entities, while not outright supporting a requirement for
AAR implementation, offer a more nuanced view. MISO states that if the
Commission does require AAR implementation, that requirement should not
solely focus on congested facilities. MISO explains that any
transmission facility could become the next most limiting element as
the system changes, and that therefore AARs should be applied to any
facility where temperature is a determining factor.\91\
---------------------------------------------------------------------------

    \91\ MISO Comments at 2-3.
---------------------------------------------------------------------------

    61. IEEE and NERC offer limited support for AAR implementation.
According to IEEE, AARs provide safer transmission line ratings during
periods of unexpected extreme ambient conditions exceeding the
assumptions that are the basis for static ratings, provide better use
of transmission assets, and reduce the need for additional
infrastructure investment to service anticipated demand.\92\ However,
IEEE also highlights disadvantages to AAR implementation. These include
necessary upgrades to EMSs, assurances that a utility's EMS is
protected from sabotage and cyber tampering, and robust analysis
protocols needed to convert changing temperatures into updated
transmission line ratings, as well as additional work needed to
document AAR protocols in a transmission line rating methodology.\93\
NERC cautions that AAR implementation may not increase the reliability
of transmission lines if implementation is not properly coordinated to
avoid real-time operational confusion,\94\ citing an example from
during the 2003 blackout of a transmission line rating discrepancy
between the transmission owner, transmission operator, and reliability
coordinator where each had separate transmission line ratings for the
same facility.\95\
---------------------------------------------------------------------------

    \92\ IEEE Comments at 1.
    \93\ Id. at 2-4.
    \94\ NERC Comments at 3.
    \95\ Technical Conference, Day 1 Tr. at 91.
---------------------------------------------------------------------------

    62. Opposition to a requirement to implement AARs comes primarily
from MISO Transmission Owners, ITC, EEI, NRECA, WATT, and AWEA.
Generally, MISO Transmission Owners and ITC state that the industry is
not ready to support full implementation of AARs or DLRs.\96\ MISO
Transmission Owners and ITC state that the Commission should allow
industry to continue to explore the use primarily of AARs and
secondarily of DLRs through industry groups or pilot programs.\97\ MISO
Transmission Owners further argue that the Commission should recognize
that preserving and protecting transmission system reliability is of
paramount importance, and that tying development and implementation of
AARs and DLRs to financial incentives or other economic criteria
without fully understanding and taking into account the impact on
reliability or safety could be contrary to the reliable and safe
operation of the transmission grid and create unreasonable risk.\98\
One specific cause for concern, according to the MISO Transmission
Owners and ITC, is that implementation of AARs can reduce some of the
``margin'' between what the transmission system can actually handle and
how it is operated.\99\ Moreover, according to MISO Transmission
Owners, if real-time ambient temperatures are higher or wind is lower
than forecasted day-ahead rating assumptions, AARs could lower ratings
near peak load conditions, which could in turn lead to congestion and
generation redispatch.\100\ Citing safety concerns and the importance
of ratings to reliability, ITC also warns that the Commission should
not take any action that conflicts with a transmission owner's NERC's
obligations.\101\
---------------------------------------------------------------------------

    \96\ MISO Transmission Owners Comments at 1-2; ITC Comments at
2-3.
    \97\ MISO Transmission Owners Comments at 1-2; ITC Comments at
2-3.
    \98\ MISO Transmission Owners Comments at 2.
    \99\ Id. at 6; ITC Comments at 3-4.
    \100\ MISO Transmission Owners Comments at 13.
    \101\ ITC Comments at 1.
---------------------------------------------------------------------------

    63. MISO Transmission Owners also contend that the Commission
should recognize that the benefits that would be realized from the
adoption of AARs or DLRs will vary by system, and may even vary within
an RTO/ISO region or within a transmission system.\102\ MISO
Transmission Owners state that AARs and DLRs may only be cost-effective
on a subset of transmission lines, and notes that transmission systems
that are constrained by voltage, stability, or certain substation
limitations may not benefit from AAR or DLR implementation.\103\ MISO
Transmission Owners further state that factors such as topology,
congestion, and localized climate conditions can affect the benefits of
and need for AARs.\104\ MISO Transmission Owners add that implementing
and maintaining the necessary sensors and making the other investments
necessary to implement AARs can be costly, and make the cost of AAR
implementation similar to that of DLRs implementation.\105\
---------------------------------------------------------------------------

    \102\ MISO Transmission Owners Comments at 14.
    \103\ Id. at 8-9 (citing Commission Staff Paper at 8-9).
    \104\ Id. at 7.
    \105\ Id.
---------------------------------------------------------------------------

    64. MISO Transmission Owners argue that there are additional
indirect costs to AAR implementation. According to MISO Transmission
Owners, these indirect costs are primarily liability-related, including
market liability, safety liability, and reliability liability, and
these costs would be complex, if not incalculable, to determine.\106\
MISO Transmission Owners also argue that, should the Commission require
AAR implementation, the Commission should not require AARs be used in
the day-ahead markets.\107\ According to MISO Transmission Owners,
implementation of AARs in the day-ahead markets would increase
potential liability and potentially cause congestion. Specifically,
MISO Transmission Owners imply that liabilities could result from
adjustments to transmission line ratings in real-time should a
transmission line rating be determined based on an inaccurate day-ahead
forecast and cause real-time congestion and generation re-
dispatch.\108\ Therefore, because there are no universal benefits to
AAR or DLR implementation and because of the resulting direct and
indirect costs, MISO Transmission Owners argue that no universal
solution is appropriate.\109\
---------------------------------------------------------------------------

    \106\ Id.
    \107\ Id. at 12-13.
    \108\ Id. at 12-14.
    \109\ Id. at 7.
---------------------------------------------------------------------------

    65. EEI echoes many of MISO Transmission Owners' arguments in its
opposition to an AAR requirement. EEI explains that because of the
initial investment costs, and because the benefits to AAR
implementation would vary considerably, a one-size-fits-all requirement
to implement AARs would

not be appropriate.\110\ EEI further states that, by requiring
transmission owners to consider ambient conditions in transmission line
ratings, NERC Reliability Standard FAC-008-3 creates a meaningful
incentive for transmission owners to implement AARs. Specifically, EEI
argues that transmission owners are required to consider ambient
temperatures under FAC-008-3, and are also required rate their lines
using technically sound principles, and therefore, any further
requirement to implement AARs is unnecessary.\111\ EEI emphasizes that
AARs and DLRs are only appropriate for real-time and near-real-time
operations and are not appropriate to use in system planning.\112\
---------------------------------------------------------------------------

    \110\ EEI Comments at 5-7.
    \111\ Id. at 7-8.
    \112\ Id. at 9-10.
---------------------------------------------------------------------------

    NRECA states that while it would support a reasoned approach to
implementing transmission line rating changes, it does not support a
Commission mandate to implement either AARs or DLRs.\113\ NRECA does
not oppose the use of AARs or DLRs in operations if there are consumer
benefits to be gained, but contends that safety and reliability should
remain the foremost considerations. Further, NRECA agrees with
September 2019 Technical Conference participants who recommended
against ``one-size-fit-all'' requirements for transmission ratings and
ratings methodologies and, citing the September 2019 Technical
Conference, explained that it would not be cost-effective to implement
AARs or DLRs on all transmission lines.\114\ For these reasons, NRECA
emphasizes the need for flexibility to balance the cost and benefits of
implementing these rating methods. Moreover, NRECA explains that a one-
size fits-all approach poses a distinct risk to Western states and
NRECA members in particular, since an AAR or DLR mandate would increase
transmission costs disproportionately for rural consumers.\115\
---------------------------------------------------------------------------

    \113\ NRECA Comments at 2-5.
    \114\ Id. at 4 (citing the opening statements of Dennis D.
Kramer on behalf of the MISO Transmission Owners and Rikin Shah on
behalf of PacifiCorp, located in Technical Conference, Day 1 Tr. at
147 and 163-65, respectively).
    \115\ Id. at 5-6.
---------------------------------------------------------------------------

    66. WATT asserts that transmission owners should not be required to
implement AARs everywhere because, according to WATT, AARs are not
sufficiently conservative.\116\ WATT argues that at times, AAR
implementation may not be conservative enough because AAR
implementation can assume too much wind, causing transmission line
ratings to be too high, and possibly result in safety violations.\117\
Specifically, WATT explains that wind speeds assumed by IEEE and the
International Council on Large Electric Systems studies may be too high
at certain temperatures and result in transmission line ratings that
exceed what a transmission line can safely handle.\118\
---------------------------------------------------------------------------

    \116\ WATT Comments at 2.
    \117\ Id. at 2-5.
    \118\ Id. at 2-4.
---------------------------------------------------------------------------

    67. Finally, rather than recommend Commission action to require
AARs, AWEA recommends a process whereby transmission owners should be
required to disclose transmission line ratings and, for lines whose
limiting element is an overhead conductor, perform a cost-benefit study
of the deployment of DLR or other congestion mitigation
technologies.\119\ AWEA further contends that for lines that are not
conductor-limited, transmission owners should be required to perform a
cost-benefit study of the upgrade of the terminal equipment or other
congestion mitigation technologies.\120\ However, in the absence or
delay of DLR implementation, AWEA adds that AARs also present benefits
and should be considered for implementation.\121\
---------------------------------------------------------------------------

    \119\ AWEA Comments at 2.
    \120\ Id.
    \121\ Id.
---------------------------------------------------------------------------

b. Dynamic Line Ratings
    68. WATT states that DLRs are more accurate than AARs, and that
DLRs reduce uncertainty relative to AARs by providing accurate
information about sag, clearances, and conductor temperatures.\122\
WATT recommends transmission owners be required to, for each line that
is or is forecast to become heavily congested, disclose nominal ratings
and perform a cost-benefit study of the deployment of DLRs, other
congestion mitigation technologies, and/or upgrading the terminal
equipment, as appropriate.\123\ WATT concedes that security can be a
concern, but should not be used as a red herring to avoid improvements
to the grid's reliability and efficiency.\124\
---------------------------------------------------------------------------

    \122\ WATT Comments at 5.
    \123\ Id. at 2-5.
    \124\ WATT Reply Comments at 4.
---------------------------------------------------------------------------

    69. Some commenters recommend pilot programs, a limited or staged
implementation of DLRs, and/or requirements to ensure transmission
operators can accept and use DLRs, noting these would be helpful in
overcoming the challenges related to DLR implementation. Monitoring
Analytics recommends that the Commission direct all transmission owners
in PJM to start DLR pilot programs.\125\ PJM also supports DLR pilot
projects, and notes that DLR pilot projects have already taken place on
its system.\126\ Dominion states that it has partnered with LineVision
and EPRI in pilot projects focused on evaluating DLR sensor
installations and validating the sensors' data, and contends that more
pilot programs could facilitate the adoption of DLRs.\127\ Potomac
Economics and MISO state that they do not oppose DLR implementation,
but contend that AAR implementation should be prioritized.\128\ In
considering where to begin DLR implementation, WATT contends that the
Commission could consider factors such as whether a line is thermally
limited, congested, or the average wind speed or other weather
parameters would have a strong bearing on the line's rating. WATT also
contends that DLRs should be made available at a customer's
request.\129\
---------------------------------------------------------------------------

    \125\ Monitoring Analytics Comments at 5-6.
    \126\ PJM Comments at 1, 4-6.
    \127\ Dominion Comments at 8-9.
    \128\ MISO Comments at 3, 6; Potomac Economics Comments at 13.
    \129\ WATT Reply Comments at 3.
---------------------------------------------------------------------------

    70. Although some commenters highlight the benefits of DLRs, others
stress the challenges associated with DLR implementation. For example,
Dominion cautions that DLRs provide only marginal benefits compared to
AAR implementation in real-time operations, but also include additional
challenges, increased operational burdens, and likely higher
uncertainty.\130\ MISO, PJM, and MISO Transmission Owners caution that
data verification would be necessary when implementing DLRs to protect
against intrusion and corruption.\131\ MISO Transmission Owners further
caution that implementation of DLRs is likely to be complex, resource-
intensive, and costly.\132\ EEI and Exelon note that implementing DLRs
includes additional challenges, such as placing sensors in remote
locations, ensuring the cyber security of sensors, and various
additional costs.\133\ Other commenters urge the Commission to exercise
caution regarding further DLR requirements, including ITC, MISO, and
PJM,\134\ which explain that DLR is a technology still under
development and therefore further pilot projects to evaluate the
appropriateness of DLR requirements

are needed \135\ and also that, since AAR implementation is more cost-
effective, DLR cost-effectiveness should be reevaluated in light of any
AAR requirement.\136\
---------------------------------------------------------------------------

    \130\ Dominion Comments at 8-11.
    \131\ MISO Comments at 8-9; PJM Comments at 8; MISO Transmission
Owners Comments at 25.
    \132\ MISO Transmission Owners Comments at 15-16, 25.
    \133\ EEI Comments at 8-10; Exelon Comments at 11-13.
    \134\ ITC Comments at 3-4; MISO Comments at 5-6; PJM Comments at
4-6.
    \135\ PJM Comments at 5-6; ITC Comments at 3-4.
    \136\ MISO Comments at 6.
---------------------------------------------------------------------------

    71. Comments indicate that the ability to incorporate DLRs is
uneven. Dominion states that its EMS cannot incorporate DLRs, and that,
while PJM's EMS can accept DLRs, that capability is unused. Dominion
states that relative to AAR implementation, EMS upgrades are typically
needed to support DLRs, which would require fundamental data schema
updates. Dominion notes that most ``off-the-shelf'' EMSs can
accommodate AARs because they have alternative line ratings sets that
can be switched on or off according to ambient temperature.\137\
---------------------------------------------------------------------------

    \137\ Dominion Comments at 8.
---------------------------------------------------------------------------

    72. MISO contends that it can accept DLRs, but not the information
necessary to calculate the rating itself.\138\ MISO Transmission Owners
state that some RTOs/ISOs may have the capability now to change
transmission line ratings ``on-the-fly'' through their EMSs, while
other RTOs/ISOs and their transmission owners would have to update and
revise multiple systems to use DLRs in real-time and day-ahead
markets.\139\ WATT concurs, explaining that RTOs/ISOs and transmission
operators currently vary in their ability to incorporate DLRs based on
various factors.\140\
---------------------------------------------------------------------------

    \138\ MISO Comments at 5.
    \139\ MISO Transmission Owners Comments at 16.
    \140\ WATT Comments at 7.
---------------------------------------------------------------------------

    73. The idea of requiring studies on the cost-effectiveness of DLRs
was generally supported, but commenters disagreed on study details and
on whom should conduct the study. WATT and Industrial Customers
recommend that RTOs/ISOs study the benefits and effectiveness of DLR on
the most congested, thermally limited lines.\141\ Dominion states that
it is open to studying its most congested lines to determine DLR's
cost-effectiveness, but argues that PJM is better suited to assess the
costs and congestion relief associated with DLR adoption.\142\
---------------------------------------------------------------------------

    \141\ Id.; Industrial Customers Comments at 16.
    \142\ Dominion Comments at 10-11.
---------------------------------------------------------------------------

    74. MISO Transmission Owners suggest that there may be no single
metric for determining which congested lines to target.\143\ Exelon
states that a DLR cost-effectiveness study could duplicate existing
processes, noting that in PJM, transmission owners are able to propose
advanced technologies as possible transmission solutions.\144\
---------------------------------------------------------------------------

    \143\ MISO Transmission Owners Comments at 16-17.
    \144\ Exelon Comments at 29-30.
---------------------------------------------------------------------------

c. Emergency Ratings
    75. At the September 2019 Technical Conference, Entergy stated that
it uses short-term emergency ratings on less than 10% of its
facilities.\145\ In explaining its reluctance to implement emergency
ratings, Entergy stated that the use of emergency ratings carries a
high degree of risk based on its potential to degrade the applicable
transmission facility, and that the risk and trade-offs must be very
carefully balanced.\146\ Moreover, given the reliability risks, Entergy
further contended that emergency ratings should not be used for
economic purposes.\147\
---------------------------------------------------------------------------

    \145\ Technical Conference, Day 1 Tr. at 159.
    \146\ Id.
    \147\ Id. at 293-94.
---------------------------------------------------------------------------

    76. While most post-September 2019 Technical Conference comments
focused on normal ratings, some commenters also described the current
implementation and availability of emergency ratings, typically used
for specific durations post-contingency. Commenters discussing
emergency ratings include Exelon, PJM, Dominion, Industrial Customers,
Potomac Economics, and Monitoring Analytics.
    77. Exelon and Monitoring Analytics note that, in addition to
normal transmission line ratings, PJM transmission owners are required
to provide short-term emergency transmission line ratings, long-term
emergency transmission line ratings, and load-dump transmission line
ratings.\148\ Exelon states that, like AARs, emergency ratings also may
not be sensitive to changes in ambient air temperatures if the
equipment rating is not sensitive to ambient air temperatures or if the
transmission facility is not thermally limited.\149\ Monitoring
Analytics explains that while PJM typically uses the long-term four-
hour emergency rating in SCED/SCUC modeled contingencies, there is no
requirement that the ratings differ for these operating
conditions.\150\
---------------------------------------------------------------------------

    \148\ Exelon Comments at 25; Monitoring Analytics Comments at 3.
    \149\ Exelon Comments at 10.
    \150\ Monitoring Analytics Comments at 3.
---------------------------------------------------------------------------

    78. PJM points out that any permitted use of emergency ratings is
documented within PJM manuals.\151\ Dominion explains that the
implementation of emergency ratings, if used, typically assumes first
or second contingency conditions, and that the development and usage of
emergency ratings should be documented in each transmission owner's
transmission line rating methodology.\152\ Finally, Industrial
Customers clarify that PJM's tariff allows certain flowgate
calculations to use emergency ratings.\153\
---------------------------------------------------------------------------

    \151\ PJM Comments at 7.
    \152\ Dominion Comments at 15.
    \153\ Industrial Customers Comments at 17.
---------------------------------------------------------------------------

    79. Potomac Economics explains that because most binding real-time
constraints are based on contingencies, operators model the additional
flows that would occur on a monitored facility post-contingency, and
MISO must be prepared to return flows below normal ratings within the
prescribed time period. Thus, Potomac Economics states that unique
emergency ratings may enable operating at higher levels for longer
post-contingency.\154\ Potomac Economics and Industrial Customers \155\
explain that the MISO Transmission Owners Agreement calls for
transmission owners to provide emergency ratings, which can reliably
accommodate flow for two to four hours, for all contingency
constraints.\156\ However, Potomac Economics notes that 63% of all
post-contingency ratings used by MISO are actually the normal
ratings.\157\ Had unique emergency ratings been used in MISO, Potomac
Economics contends, the market cost savings would have been
approximately $62 and $68 million in 2017 and 2018, respectively.\158\
---------------------------------------------------------------------------

    \154\ Potomac Economics Comments at 4.
    \155\ Industrial Customers Comments at 12 (citing MISO, MISO
Rate Schedules, Transmission Owner Agreement, Appendix B, Section V
(30.0.0)).
    \156\ Potomac Economics Comments at 4.
    \157\ Id. at 5.
    \158\ Id. at 6.
---------------------------------------------------------------------------

2. Proposal
    80. To remedy potentially unjust and unreasonable rates, we make
several proposals related to AARs, DLRs and emergency ratings. We
propose to require all transmission providers to implement AARs on the
transmission lines over which they provide transmission service. We
propose a staggered approach to the proposed AAR requirement that would
prioritize implementation on congested lines (within one year from the
date of the compliance filing for implementation of the proposed
reforms to become effective), and propose to require a less aggressive
implementation of AARs on all other lines (within two years from the
date of the compliance filing for implementation of the proposed
reforms to become effective).
    81. In addition, we propose to require all RTOs/ISOs to implement
the systems and procedures necessary to allow transmission owners to
electronically update transmission line ratings at least

hourly. We also seek comment on whether to apply this requirement to
transmission providers located outside of RTO/ISO markets.
    82. Finally, with regard to emergency ratings, we seek comment on
whether to require transmission providers to use unique emergency
ratings.
a. Ambient-Adjusted Line Ratings and Seasonal Line Ratings
i. Proposed Requirements
    83. Having preliminarily found that the use of transmission line
ratings that are based on long-term assumptions is not just and
reasonable, we propose, pursuant to section 206 of the FPA to revise
the pro forma OATT to require all transmission providers to implement
AARs and seasonal line ratings on the transmission lines over which
they provide transmission service, under certain circumstances. This
requirement would ensure that transmission line ratings accurately
reflect the availability of transmission in real-time.
    84. In proposing to require the implementation of AARs and seasonal
transmission line ratings, we propose to define transmission line
ratings as 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.
    85. We propose to implement these requirements through a new
Attachment M to the pro forma OATT titled Transmission Line Ratings.
Within the proposed Attachment M, different line rating requirements
would apply in the context of different types of transmission service,
as discussed below.
(a) Point-to-Point Transmission Service
    86. The first proposed AAR requirement applies to the availability
of and requests for ``near-term point-to-point transmission service,''
(under section 15, section 17, and section 18 of the pro forma OATT)
which we propose to define as point-to-point transmission service
ending within 10 days of the date of the request. We propose to require
transmission providers to use AARs as the relevant transmission line
ratings when (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), and (3) posting ATC or other information related to near-term
point-to-point transmission service to the their OASIS site. Through
the definition of ``near-term point-to-point transmission service,'' we
propose to limit the AAR requirement to requests for transmission
service ending within 10 days of the date of the request. We propose
this 10-day limit both because it appears to be a reasonable cut-off
beyond which forecasts may not be accurate enough for AARs to provide
significant value, and because we believe such a limit would reasonably
accommodate requests for weekly point-to-point transmission service.
However, we seek comment on the appropriateness of this 10-day limit.
    87. For other (longer-term) point-to-point transmission service
requests, we propose to require transmission providers to use seasonal
line ratings as the relevant transmission line ratings when (1)
evaluating requests for such service, (2) responding to requests for
information on the availability of such service (including requests for
ATC or other information related to such potential service), and (3)
posting ATC or other information related to such service to their OASIS
site. In proposing to require seasonal ratings, however, we propose to
limit the duration of a season to three months. We do not propose to
require the use of AARs for evaluations of longer-term service because
we expect that ambient air temperature forecasts for such future
periods have more uncertainty than near-term forecasts, and thus tend
to converge to the longer-term ambient air temperature forecasts used
in seasonal line ratings.
    88. We also propose to require that transmission providers use AARs
as the relevant transmission line ratings when determining whether to
curtail or interrupt point-to-point transmission service (under section
14.7 of the pro forma OATT) if such curtailment or interruption is both
necessary because of a reduction in transmission capability 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 (beyond 10 days) situations, we propose to require
transmission providers to use seasonal line ratings as the relevant
transmission line ratings.
(b) Network Transmission Service
    89. For network transmission service, we propose to require
transmission providers to evaluate requests to designate network
resources (under section 30 of the pro forma OATT) or network load
(under section 31 of the pro forma OATT) based on seasonal line
ratings, because such designations are generally long-term requests and
seasonal line ratings better reflect conditions over a longer-term than
AARs. In proposing to require seasonal ratings for evaluation of
network service requests, however, we propose to limit the duration of
a season to three months. Additionally, we propose to require that
transmission providers use AARs as the relevant transmission line
ratings when determining whether to curtail network service or
secondary network service (under section 33 of the pro forma OATT) or
redispatch network service or secondary network service (under sections
30.5 and/or 33 of the pro forma OATT), 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
10 days of such determination. For determining the necessity of
curtailment or redispatch of network service or secondary network
service in other (beyond 10 days) situations, we propose to require
transmission providers to use seasonal line ratings as the relevant
transmission line ratings.
(c) RTOs/ISOs
    90. With respect to RTOs/ISOs, we recognize that such entities have
Commission-approved variations from the pro forma OATT to manage
congestion and initiate curtailments and/or redispatch of transmission
service within their footprints (although generally not at their
borders) through mechanisms such as SCED and SCUC. To accommodate these
variations, we propose that RTOs/ISOs comply with the proposed
requirements by revising their tariffs to require implementation of
AARs within their SCED and SCUC models (and in any relevant related
models) in both the day-ahead and real-time markets and any intra-day
reliability unit commitment or reliability assessment commitment. For
the real-time market, we propose that RTOs/ISOs update the AARs at
least hourly. For any point-to-point transmission service offered by
RTOs/ISOs (e.g., at their borders), we propose that the AAR
requirements discussed above for point-to-point service would apply.

(d) Implementation Timeline
    91. We propose to apply the proposed requirements for AARs and
seasonal line ratings to all transmission lines, rather than targeting
only congested transmission lines, as suggested by some commenters.
However, we propose to prioritize the implementation of AARs and
seasonal line ratings on historically congested transmission lines.
Specifically, we propose to require that AARs and seasonal line ratings
be implemented on historically congested lines within one year from the
date of the compliance filing for implementation of any final rule, and
on all other lines within two years from the date of the compliance
filing for implementation of any final rule. For purposes of this
proceeding, we propose that the term ``historically congested line''
mean a transmission line that was congested at any time in the five
years prior to the effective date of any final rule.\159\
---------------------------------------------------------------------------

    \159\ Congestion is a characteristic of the transmission system
produced by a binding transmission constraint such that the rates
for wholesale electric energy, exclusive of losses, at different
locations of the transmission system are not equal.
---------------------------------------------------------------------------

    92. We propose to require implementation of AARs on all
transmission lines and not only on congested lines, because any
transmission facility, whether or not historically congested, could
become the most limiting element as the system changes, a point argued
by MISO.\160\ The 2019 FERC NERC Staff Report on the January 2018 South
Central cold weather event illustrates this point.\161\ As shown in
that event, during times of emergency or system stress, flows may
change considerably from normal operations and the increased
transmission capability provided through AARs may prove valuable even
on lines not typically congested.
---------------------------------------------------------------------------

    \160\ MISO Comments at 2-3.
    \161\ 2019 FERC and NERC Staff Report, The South Central United
States Cold Weather Bulk Electric System Event of January 17, 2018,
at 96 (July 2019) (FERC and NERC Staff Report), https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf.
---------------------------------------------------------------------------

    93. Nevertheless, we recognize that a staggered implementation
schedule would allow RTOs/ISOs and transmission owners to focus
implementation on transmission lines where AAR implementation is likely
to provide the most benefits and gain operational experience with the
new AAR requirements prior to full implementation.
(e) Implementation Considerations
    94. As a practical matter, the proposed requirements related to
AARs and seasonal line ratings would entail specific implementation and
on-going obligations on the part of the transmission provider. First,
the proposed AAR requirement would necessitate that transmission
providers implement an automated system that can take as an input a 10-
day forecast of ambient air temperatures at locations across its
service area, and calculate up-to-date AAR values for each of the 240
hours in the next 10 days and for each of their transmission lines.
Under the proposed requirement, for an AAR value to be ``up-to-date,''
a transmission provider must update AAR values at least every hour. We
propose that transmission providers use such AAR values when evaluating
requests for transmission service (or developing ATC or other
information related to potential transmission service) that will occur
within the next 10 days by determining (among other things) whether the
transmission provider can accommodate the requested service request
without violating the AAR in any hour.
    95. Under the proposed AAR requirement, transmission providers
would also need to arrange to have the appropriate forecasts available
to support the AAR determinations discussed above. Based on information
from the 2017 Idaho National Laboratory conference on DLRs, we
understand that existing users of advanced line ratings such as AARs or
DLRs use a variety of approaches to produce those ratings and the
forecasts that underly them. Such approaches range from using vendors
to handle most of the tasks related to developing forecasts and related
line ratings, to performing much or most of those tasks in-house based
on developed expertise and a subscription to a weather data service,
with various approaches in between. We do not propose to stipulate the
approach that transmission providers take to develop AAR values under
our proposed requirements, as long as they execute these
responsibilities consistent with good utility practice.
    96. The proposed seasonal line rating requirement, as defined in
proposed Attachment M, would require similar implementation obligations
as for the proposed AAR requirement discussed above, although for
seasonal line ratings the transmission provider would be (1)
calculating line ratings for future years (instead of calculating
ratings for all hours within the next 10 days for AARs), and (2)
running the seasonal rating system and calculating seasonal ratings
every month (instead of calculating AARs at least every hour).
    97. System safety and reliability are paramount to the proposed
requirements for transmission line ratings. The proposed tariff
language requires the transmission provider to develop transmission
line ratings (including the forecasts that underpin AARs and seasonal
line ratings) consistent with good utility practice, and the definition
of ``Good Utility Practice'' in section 1.15 of the pro forma OATT
requires consistency with safety and reliability, among other things.
While we expect the nature of our proposed requirements to provide
transmission providers with the latitude (and obligation) to develop
accurate, safe, and reliable line ratings in the first instance, we
also propose, in an abundance of caution, to make explicit in the
tariff language proposed herein that if a transmission provider
determines, consistent with good utility practice, that it must
temporarily use a rating different than otherwise required by the
tariff in order to ensure the safety or reliability of the transmission
system, it may do so. While we expect that such alternate line rating
authority would be needed infrequently, if ever, we provide the
clarification related to such temporary ratings to resolve any instance
where a transmission provider reasonably believes that the tariff
requirements for transmission line ratings conflict with system safety
or reliability.
ii. Justification and Response to Comments
    98. While there are differences across transmission systems, simply
accounting for ambient air temperatures in transmission line ratings
can reliably increase power transfer capability and significantly lower
production costs at a manageable implementation cost.\162\ For example,
as noted above, Potomac Economics estimates that the benefits to AAR
implementation in MISO alone would have produced approximately $94
million and $78 million in reduced congestion costs in 2017 and in
2018, respectively.\163\ While several entities note implementation
costs as a barrier, these costs are mostly initial investments in
upgraded OASIS and/or EMS and ratings databases.\164\ Once

these systems are upgraded, adding AARs to additional lines appears to
have a minimal incremental cost.\165\
---------------------------------------------------------------------------

    \162\ AEP Comments at 3.
    \163\ Potomac Economics Comments at 6-7.
    \164\ While most commenters only mention the need for software
changes (AEP Comments at 3) or mention the need for EMS upgrades and
ratings databases to ensure AARs are implemented in near-term
transmission service (Exelon Comments at 5-6), we also note that
OASIS and/or related systems might also need to be upgraded in order
to ensure ATC postings for near-term point-to-point transmission
service transmission service requests also reflect AARs. For this
reason, we describe initial costs to include OASIS and/or EMS
upgrade costs.
    \165\ AEP Comments at 2-3.
---------------------------------------------------------------------------

    99. Between the two possible approaches to increasing transmission
line rating accuracy, AARs and DLRs, our proposal to require
transmission providers to implement AARs in near-term transmission
service is based on our preliminary finding that an AAR requirement
strikes a more appropriate balance between benefits and challenges.
While DLRs can represent more accurate transmission line ratings than
AARs, DLRs also present additional costs and challenges that AARs do
not present. Relative to AARs, these additional costs and challenges
include placing sensors in remote locations, ensuring the cyber
security of sensors, and various additional costs.\166\ However, we
seek comment on whether to require transmission providers to implement
DLRs across their systems or on certain transmission lines that have
the most to benefit from a dynamic rating.
---------------------------------------------------------------------------

    \166\ EEI Comments at 8-10; Exelon Comments at 11-13.
---------------------------------------------------------------------------

    100. In response to comments from OMS and Potomac Economics that
suggest the Commission focus on the most heavily congested lines,\167\
we note that our proposal, as discussed above, is to prioritize the
implementation of AARs on historically congested transmission lines
first.
---------------------------------------------------------------------------

    \167\ OMS Comments at 2; Potomac Economics Comments at 9-10.
---------------------------------------------------------------------------

    101. In response to concerns articulated by MISO Transmission
Owners that day-ahead forecasts could be inaccurate, causing
differences between day-ahead and real-time transmission line ratings
and therefore uplift,\168\ we observe that day-ahead markets already
rely upon forecasts for weather to inform next-day load and
intermittent generation availability. Instead, we agree with PJM that
temperatures can be forecast within a reasonable degree of
certainty,\169\ and we note that within our proposal transmission
providers can (consistent with good utility practice) determine the
needed degree of certainty when constructing their forecasts of ambient
air temperature. We also preliminarily agree with MISO that, because
one of the goals of the day-ahead market is to align prices with those
eventually determined in the real-time market, maintaining policy
consistency between the day-ahead and real-time markets, where
practical, is desirable.\170\
---------------------------------------------------------------------------

    \168\ MISO Transmission Owners Comments at 7.
    \169\ PJM Comments at 3.
    \170\ MISO Comments at 3.
---------------------------------------------------------------------------

    102. We agree with some commenters that not all transmission line
ratings are affected by ambient air temperature, either because the
technical transfer capability of the limiting conductors and/or
limiting transmission equipment is not dependent on ambient air
temperature, or because the transmission line's 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.\171\ Our proposed pro forma OATT language accommodates
such transmission lines without requiring unwarranted calculations or
updates. Specifically, our proposed pro forma OATT language provides
that where the transmission provider determines that the 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.
---------------------------------------------------------------------------

    \171\ Dominion Comments at 3; Exelon Comments at 10, 22-23;
September 2019 Technical Conference, Day 1 Tr. at 141 (AEP opening
statement to Panel Three).
---------------------------------------------------------------------------

    103. Finally, in response to Exelon's comments that AARs should not
be implemented in transmission planning, we agree and reiterate that we
are only proposing to require AAR implementation for certain aspects of
near-term transmission service.\172\
---------------------------------------------------------------------------

    \172\ Exelon Comments at 4-5.
---------------------------------------------------------------------------

    104. Some entities argue that requiring AAR implementation would
lead to operational and reliability concerns. MISO Transmission Owners
caution that any AAR requirement could make operational or safety
incidents more likely by reducing some of the margin between what a set
of transmission facilities can safely handle at that point in time and
the current operating levels.\173\ ITC and NRECA raise similar
reliability questions.\174\ WATT contends that at times, AAR
implementation may not be conservative enough because AAR
implementation can assume too much wind. We do not find these concerns
persuasive. We note that the ``safety margin'' cited by commenters is
not dependable--it exists only during periods where the ambient air
temperature happens to be lower than the temperature assumed when the
static or seasonal line rating was calculated. We further note that the
margin is lowest precisely during the hottest periods, which represent
periods of high system stress when a dependable reliability margin
would be most valuable. Furthermore, transmission providers that find
they need a reliability margin have existing Commission-approved
mechanisms, such as the transmission reliability margin (TRM) component
of ATC, for establishing such a margin on a consistent and transparent
basis. With respect to assumptions about ambient conditions, under our
proposal, transmission owners have latitude, consistent with good
utility practice, to develop assumptions about ambient conditions that
result in transmission line ratings that reflect what transmission
flows the system can safely and reliably accommodate.
---------------------------------------------------------------------------

    \173\ MISO Transmission Owners Comments at 6.
    \174\ ITC Comments at 3-4; NRECA Comments at 3.
---------------------------------------------------------------------------

    105. Moreover, as Exelon points out, AARs would correct the
existing occasional overestimations of transmission line ratings during
periods where the actual ambient air temperature is greater than the
temperature assumed when the rating was calculated. As a result, we
believe that implementation of AARs will reduce transmission line
ratings when extreme high temperature events occur, reducing the
likelihood of inadvertently overloading a transmission line.\175\
Moreover, consistent with PJM's and Potomac Economics' comments, we
believe that because AARs will typically increase transmission line
ratings when actual temperatures are lower than long-term assumptions,
the resulting increased transmission capability will provide operators
additional flexibility, which promotes reliability.\176\ Specifically,
by increasing the available transmission capability, system operators
would be provided more options to manage congestion, and potentially
ameliorate system conditions during an emergency. This is consistent
with the 2019 FERC NERC Staff Report on the January 2018 South Central
cold weather event, which, for example, identified and recommended
adoption of transmission line ratings that better consider ambient
temperature conditions. In this instance, implementing AARs would have
been one way to potentially introduce additional transmission
capability, which would have provided operators additional flexibility
to transfer additional power to an area experiencing a potential
reliability event, and thereby preventing the need for possible
generator redispatch (reducing available contingency reserves),
transmission reconfiguration,

and/or transmission loading relief,\177\ and helping mitigate future
cold weather reliability events.\178\ Implementing AARs may also
improve the ability to schedule and perform planned equipment outages
for maintenance purposes and project upgrades.\179\
---------------------------------------------------------------------------

    \175\ See Exelon Comments at 9.
    \176\ See PJM Comments at 2; Potomac Economics Comments at 8.
    \177\ FERC and NERC Staff Report at 56-57.
    \178\ Id. at 96.
    \179\ Commission Staff Paper at 12 (describing outreach
discussions that noted that the increased transfer capability, which
typically results from ad hoc transmission line rating uprates (but
would also result from AAR implementation) provides RTOs/ISOs
additional options to manage challenges due to maintenance outages).
---------------------------------------------------------------------------

    106. Additionally, RTOs/ISOs already periodically request ad hoc
transmission line rating changes based on differences between actual
and assumed ambient temperatures.\180\ These requests are typically
needed to either manage congestion or support reliable grid operations,
but further demonstrate the benefits of AAR implementation. Our
proposed AAR requirements would help ensure all market participants are
consistently able to access the benefits of such transmission line
rating changes.
---------------------------------------------------------------------------

    \180\ Id. at 10 and 21.
---------------------------------------------------------------------------

b. RTO/ISO Capability To Allow Electronic Updates to Line Ratings
    107. Having preliminary found above that the use of transmission
line ratings that are based on long-term assumptions may not be just