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

    90. We do not adopt the NOPR proposal to establish a definition of
historically congested transmission lines. Accordingly, since we are
not adopting the NOPR's proposed definition of historically congested
transmission line, and instead apply the AAR requirements adopted
herein to all transmission lines, we do not address comments related to
the NOPR's proposed definition of historically congested transmission
line. To the

extent that commenters were arguing for a narrower application than
what we adopt in this final rule, below we explain the basis for
application of the AAR requirements to all transmission lines.
    91. Finally, we alter the proposed compliance schedule.
Specifically, we require each transmission provider to submit a
compliance filing within 120 days of the effective date of this final
rule to incorporate into its OATT the changes adopted herein consistent
with pro forma OATT Attachment M and the changes to the Commission's
regulations set forth below. Additionally, we further require that all
requirements adopted herein be fully implemented no later than three
years from the compliance filing due date established by this final
rule.
    92. In response to comments received in response to the NOPR, we
modify the NOPR proposal's defined term ``near-term point-to-point
transmission service'' to instead be ``near-term transmission
service.'' As a result, the AAR requirements will apply to requests for
near-term network transmission service, near-term secondary service,
and near-term point-to-point transmission service, provided that such
service meets the 10-day threshold defined in the near-term
transmission service definition. We agree with TAPS that it would be
inappropriate to apply the AAR requirements only to requests for near-
term point-to-point transmission service and not to requests for near-
term network and near-term secondary service because secondary service
comes before non-firm point-to-point transmission service in
curtailment priority.\215\ More generally, we find that a requirement
to use AARs on all types of near-term transmission service will better
ensure that transmission line ratings are accurate and that wholesale
rates are just and reasonable.
---------------------------------------------------------------------------

    \215\ TAPS Comments at 18-20.
---------------------------------------------------------------------------

    93. Although commenters broadly raise concerns with adopting
transmission line ratings that may fluctuate widely or contend that
implementing AARs on certain transmission lines may not yield benefits,
we do not find that these concerns and arguments overcome the need to
improve the accuracy of transmission line ratings through applying the
AAR requirements to all transmission lines. Specifically, we decline to
accommodate requests for more targeted AAR requirements in which
transmission providers would either have flexibility to identify
candidate transmission lines or the Commission would require AAR
implementation on only priority transmission lines, such as only on
historically congested lines.
    94. We recognize commenters' concerns, such as those from NRECA/
LPPC, that the promised benefits, costs, and risks of implementing AARs
may not be evenly distributed nationwide.\216\ Nevertheless, we find
that with the broad AAR requirements adopted herein, the overall
benefits via savings to load and lower congestion charges to generators
will on balance outweigh the costs. Moreover, we acknowledge the
difficulty of knowing in advance all the locations and situations in
which the benefits of AAR implementation will outweigh the costs. Given
the difficulty in predicting unexpected congestion before it happens,
narrowing the scope of the AAR requirements would limit the ability of
these reforms to ensure just and reasonable wholesale rates. In
particular, we find that the AAR requirements adopted in this final
rule are beneficial in mitigating the impact of transient congestion,
i.e., temporary or short-term congestion that does not occur on a
regular basis, such as congestion caused by unexpected equipment
outages or other unusual conditions. Furthermore, given the increasing
occurrence of extreme weather events, we expect that assessing the
benefits of broader AAR implementation based on historical congestion
likely understates the potential savings associated with implementation
of the AAR requirements adopted in this final rule. By contrast, the
record demonstrates that AAR implementation costs are predominantly
one-time investment costs in EMS improvements to accommodate AARs,
implementation of a ratings database, and review (and potentially
reset) of protective relays settings.\217\ Once these costs have been
incurred, the incremental cost of applying AARs to additional
transmission facilities is minimal.\218\
---------------------------------------------------------------------------

    \216\ NRECA/LPPC Comments at 15.
    \217\ Exelon Comments at 8-9.
    \218\ Id. at 8; Indicated PJM Transmission Owner Comments at 5-
6; AEP Post-Technical Conference Comments at 2-3; September 2019
Technical Conference, Day 1 Tr. at 180-181.
---------------------------------------------------------------------------

    95. Attempts to anticipate the situations in which AARs will not be
cost beneficial (e.g., attempts to forecast locations and situations in
which there will be future congestion and deploy AARs in only those
anticipated situations) will necessarily be imperfect and complex,
especially during infrequent but consequential events. Additionally,
since many emergencies may come and go before new AARs can be developed
and implemented for newly congested transmission lines, a more targeted
AAR requirement advocated by some commenters may not accurately
represent system transfer capability in such critical situations. As
the Commission recognized in the NOPR, congestion is difficult to
predict, particularly during emergency conditions.\219\ The 2019 FERC
and NERC Staff Report on the January 2018 South Central cold weather
event illustrates this point.\220\ As shown by that event, during times
of emergency or system stress, flows may change considerably from
normal operations and the increased transfer capability provided
through AARs may prove valuable even on transmission lines that are not
typically congested.\221\ In addition, in the February 2021 cold
weather event, MISO experienced unprecedented east-to-west flows
throughout the footprint and accrued $773 million in congestion charges
in just a few days.\222\ We note that with broad AAR implementation,
given Potomac Economics' finding that AAR implementation consistently
results in savings of approximately 5% to 8% of total congestion,\223\
congestion cost savings from this single event might have exceeded the
total costs of AAR implementation in the region. Moreover, many argue
that the changing generation mix makes congestion prediction even more
difficult.\224\ Additionally, AAR implementation itself will have
secondary consequences for congestion patterns, as changes to
transmission line ratings may change generation dispatch patterns and,
by extension, congestion patterns. Such secondary congestion
consequences may only be able to be promptly addressed by a broad AAR
requirement that applies to all transmission lines.
---------------------------------------------------------------------------

    \219\ NOPR, 173 FERC ] 61,165 at P 93.
    \220\ 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.
    \221\ NOPR, 173 FERC ] 61,165 at P 93.
    \222\ OMS Comments at 10; OMS Reply Comments at 7; see FERC,
NERC and Regional Entity Staff Report, The February 2021 Cold
Weather Outages in Texas and the South Central United States (Nov.
16, 2021), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and.
    \223\ Potomac Economics Comments at 8; Potomac Economics Post-
Technical Conference Comments at 5-6.
    \224\ ACPA/SEIA Comments at 8, 11; EPSA Comments at 4; New
England State Agencies Comments at 6.
---------------------------------------------------------------------------

    96. Beyond congestion costs, during times of stressed system
conditions, operators in RTOs/ISOs might have to

spend limited time requesting AARs from transmission owners on an ad
hoc basis.\225\ AAR implementation on all transmission lines will help
ensure transmission providers have sufficient transfer capability and
flexibility to manage emergency conditions. Delayed access to AARs
could force transmission operators to spend precious time reaching out
to transmission owners for AARs, rather than using such time to manage
emergency conditions. Instead, AAR implementation on all transmission
lines will alleviate the need for transmission providers to spend time
requesting AARs when there may be no time to waste.
---------------------------------------------------------------------------

    \225\ OMS Reply Comments at 7; see also FERC and NERC Staff
Report at 56-59; ISO-NE, Cold Weather Operations: December 24,
2017--January 8, 2018, at 41 (Jan. 16, 2019), https://www.iso-ne.com/static-assets/documents/2018/01/20180112_cold_weather_ops_npc.pdf.
---------------------------------------------------------------------------

    97. Further, arguments that the benefits of broad AAR
implementation will not outweigh the costs are inconsistent with the
ERCOT and PJM transmission owners' actual AAR implementation
experience. AEP has been implementing AARs for decades and has realized
both reliability and financial benefits for its customers.\226\ As
Indicated PJM Transmission Owners state, transmission owners in PJM
provide AARs for each of their facility ratings.\227\ PJM further
states that the use of AARs is commonplace among the overwhelming
majority of transmission owners in PJM.\228\ As New England State
Agencies observe, the broad experience implementing AARs does not
support the argument that AARs are too difficult or costly to
implement.\229\
---------------------------------------------------------------------------

    \226\ AEP Comments at 3.
    \227\ Indicated PJM Transmission Owners Comments at 6-7.
    \228\ PJM Comments at 2.
    \229\ New England State Agencies Comments at 11-12.
---------------------------------------------------------------------------

    98. In response to MISO Transmission Owners' argument that the
Commission should not rely on Potomac Economics' estimates of the
benefits of AARs, our rationale for the AAR requirements adopted in
this final rule is not solely based on Potomac Economics' analysis.
Rather, our rationale is based on the finding that AARs on all
transmission lines will ensure that wholesale rates more accurately
reflect the cost of the wholesale service being provided, and, thus
that those wholesale rates are just and reasonable. This finding is
further informed by the widespread benefits experienced by commenters
implementing AARs broadly in PJM and ERCOT, the expectation that the
benefits of AAR implementation will be greatest on transmission lines
that are frequently congested, along with the understanding of the
difficulty of predicting congestion and the low incremental cost to
implement AARs. However, in response to MISO Transmission Owners'
critique that Potomac Economics' analysis erroneously assumes that all
transmission lines in MISO are ambient adjustable, we note that, in
response to MISO Transmission Owners' comments, Potomac Economics
states that its analysis does not assume that all transmission lines
are able to be rated using AARs and instead removes from the analysis
all transmission lines that currently have summer ratings equal to
winter ratings.\230\ With respect to MISO Transmission Owners' argument
that Potomac Economics' analysis erroneously assumes that all
transmission lines in MISO are currently using worst-case ambient air
temperature assumptions, we note that Potomac Economics does not
uniformly assume worst-case 104 degrees Fahrenheit as the basis for
adjusting AARs, but instead infers unique transmission owner base
assumptions using maximum historical temperatures in each transmission
owner service territory.\231\ Finally, we disagree with MISO
Transmission Owners' assertion that the benefits in Potomac Economics'
analysis are inflated because of certain transmission outages or
upgrades assumptions. As Potomac Economics explains, there are many
generalized and localized factors that might increase or decrease
congestion in an individual year and, given the highly complex nature
of the electric system, incorporating all of these factors is not
possible.\232\ Despite certain generalizations, which we believe are
likely to render Potomac Economics' analysis conservative, Potomac
Economics has consistently found that AARs and emergency ratings will
reduce congestion by 10% to 15% annually.\233\
---------------------------------------------------------------------------

    \230\ Potomac Economics Reply Comments at 3-5.
    \231\ Id. at 2-3.
    \232\ Id. at 5-6.
    \233\ Id. at 5.
---------------------------------------------------------------------------

    99. We disagree with arguments from Southern Company, EEI, and
other commenters that reliability issues may arise because AARs may
create difficulties in identifying the most limiting element and
similar difficulties and costs associated with complying with
Reliability Standard PRC-023-4's transmission relay loadability
requirements that depend on maximum published ratings. Reliability
Standard PRC-023-4 requires setting transmission line relays at values
at or above 115 to 170% of various maximum values for current or power
carrying capability, e.g., 115% of the highest seasonal 15-minute
Facility Rating of a circuit or 150% of the highest seasonal four-hour
Facility Rating of a circuit. We do not agree that this final rule will
result in PRC-023-4 related relay setting changes to ``thousands''
\234\ of relays, since the relay settings are currently calculated
based on practical limitations which in the majority of cases should
not exceed AAR values. In addition, PJM has long implemented AARs and,
rather than describing reliability challenges, contends that AAR
implementation creates reliability benefits.\235\ For example, PJM
states that the adoption of AARs increases operational flexibility,
promotes a more efficient use of the transmission system, and results
in more reliable system dispatch and cost-effective market
operations.\236\ Transmission owners in PJM have implemented AARs
despite the initial cost incurred to update relay settings. Likewise,
AEP submits that it has implemented AARs for decades and that AAR
implementation presents reliability benefits.\237\
---------------------------------------------------------------------------

    \234\ EEI Comments at 5-6.
    \235\ PJM Comments at 7.
    \236\ Id. at 2.
    \237\ AEP Comments at 3.
---------------------------------------------------------------------------

    100. In response to concerns about the additional challenges
associated with incorporating AARs into ATC, as raised by Duke Energy,
EEI, and several non-RTO/ISO transmission owners with service
territories in the Western Interconnection, we note that such TTC
calculation practices, and in turn ATC practices, particularly those
which only update TTC values annually,\238\ will need to be updated in
order to comply with this final rule's AAR requirements. In fact, such
practices may already be out of compliance with the Commission's
existing ATC calculation rules. For example, while Order No. 890
provides transmission providers with significant flexibility in what
approach they take to determine ATC in their transmission paths, it
also requires that ATC values (regardless of the approach used to
calculate them) be ``updated and benchmarked to actual events.'' \239\
Furthermore, in May 2021, the Commission issued Order No. 676-J,\240\
in which the Commission (among other things) codified the
``fundamentals of Order No. 890 requirements for calculating ATC'' in
the Commission's regulations.\241\ Specifically, Order No.

676-J revised section 37.6(b)(2)(i) of the Commission's regulations to
codify that ATC calculations must be ``conducted in a manner that is .
. . consistent with anticipated system conditions and outages for the
relevant timeframe.'' \242\ We find that transmission line ratings
represent one such ``system condition'' with which ATC calculations
must be consistent.
---------------------------------------------------------------------------

    \238\ EEI Comments at 11.
    \239\ Order No. 890, 118 FERC ] 61,119 at P 290.
    \240\ Standards for Business Practices and Communication
Protocols for Public Utilities, Order No. 676-J, 86 FR 29491 (June
2, 2021), 175 FERC ] 61,139 (2021).
    \241\ Id. P 38.
    \242\ Id.
---------------------------------------------------------------------------

    101. In response to specific concerns from PacifiCorp and BPA about
nomogram constraints, we note that nomogram constraints are typically
used to represent transfer capability on facilities with stability or
voltage limitations. The AAR requirements adopted in pro forma OATT
Attachment M exempt transmission lines whose ratings are not affected
by ambient air temperature.
    102. In response to comments from NERC requesting further
consideration of AAR implementation on long transmission lines, and
from LADWP, and other, primarily western transmission owners, which
describe AAR implementation challenges due to the diversity in terrain
and microclimates that western transmission lines traverse, we agree
that longer transmission lines can and will experience differing
weather conditions across the length of those transmission lines. To
maintain reliable system operations, we expect transmission providers
to implement the transmission line rating calculated based on the most
limiting element under the prevailing weather conditions (actual or
anticipated) at the relevant point on the transmission line. In the
case of transmission conductors, which might be exposed to different
weather conditions along the length of the transmission line,
transmission providers must rate such elements using the most limiting
weather conditions, in accordance with good utility practice. However,
this requirement does not require the installation of field devices or
sensors, as some transmission owners suggest.\243\ Rather, as proposed
in the NOPR, the AAR requirements can be met through the use of a
weather data service.\244\
---------------------------------------------------------------------------

    \243\ WAPA Comments at 7-9; PG&E Comments at 9-10.
    \244\ NOPR, 173 FERC ] 61,165 at P 95.
---------------------------------------------------------------------------

    103. Similarly, in response to comments from BPA that if BPA uses
AARs as proposed, it would need to make its current liberal wind
assumptions (and therefore, the resultant transmission line ratings)
more conservative to mitigate the risk of operating near the conductor
limit,\245\ we reiterate that the AAR requirements will ensure more
accurate transmission line ratings, not necessarily higher transmission
line ratings. We further clarify that there is no requirement to change
wind speed assumptions. Utilities have operated reliably for decades
with AARs.\246\ However, if any transmission owner finds it necessary
to change its wind speed assumptions consistent with good utility
practice, we clarify that nothing in this rulemaking prevents it from
doing so.
---------------------------------------------------------------------------

    \245\ BPA Comments at 4.
    \246\ AEP Comments at 3.
---------------------------------------------------------------------------

2. Specific AAR Implementation Requirements
a. Use of AARs 10-Days Forward in Transmission Service and Operations
i. NOPR Proposal
    104. In the NOPR, within the context of the AAR requirements
described and adopted above in Section IV.B.1, the Commission proposed
to apply the AAR requirements to transmission service that starts/ends
within 10 days, to the curtailment or interruption of point-to-point
transmission service anticipated to occur (start and end) within the
next 10 days, and to the curtailment of network transmission service or
secondary service or redispatch network transmission service or
secondary transmission service anticipated to occur (start and end)
within 10 days (hereinafter referred to as the ``10-day threshold'').
    105. The Commission justified the proposed 10-day threshold as a
reasonable cut-off beyond which forecasts may not be accurate enough
for AARs to provide significant value, and by stating that the
Commission believed that such a limit would reasonably accommodate
requests for weekly point-to-point transmission service. The Commission
further noted that ambient air temperature forecasts for intervals
beyond the proposed 10-day threshold tend to converge to the longer-
term ambient air temperature forecasts used in seasonal line
ratings.\247\ Finally, the Commission noted that its proposal allowed
transmission providers to determine (consistent with good utility
practice) the needed degree of certainty when constructing their
forecasts of ambient air temperature.\248\
---------------------------------------------------------------------------

    \247\ NOPR, 173 FERC ] 61,165 at PP 87-88.
    \248\ Id. P 102.
---------------------------------------------------------------------------

    106. With respect to RTOs/ISOs, the Commission proposed to require
AARs as the relevant transmission line rating for any point-to-point
transmission service offered (e.g., at their borders). However, the
Commission also recognized that RTOs/ISOs have Commission-approved
variations from the pro forma OATT to manage internal congestion and
initiate curtailments and/or redispatch of transmission service within
their footprints through mechanisms such as SCED and SCUC. To
accommodate these variations, the Commission proposed that RTOs/ISOs
comply with the proposed requirements by revising their OATTs 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 RUC processes. For real-time markets, the
Commission proposed that RTOs/ISOs update their AARs at least hourly.
For any point-to-point transmission service offered by RTOs/ISOs (e.g.,
at their borders), the Commission proposed that the AAR requirements
discussed above for point-to-point transmission service would apply. As
justification, the Commission explained that day-ahead markets already
rely upon forecasts of weather to inform next-day load and intermittent
generation availability. The Commission preliminarily agreed with PJM
that temperatures can be forecast with a reasonable degree of certainty
in day-ahead markets.\249\ The Commission further stated that, within
its NOPR proposal, transmission providers could (consistent with good
utility practice) determine the needed degree of certainty when
constructing their forecasts of ambient air temperature, and 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.\250\
---------------------------------------------------------------------------

    \249\ PJM Post-Technical Conference Comments at 3.
    \250\ NOPR, 173 FERC ] 61,165 at P 102.
---------------------------------------------------------------------------

ii. Comments
    107. Many commenters generally support the Commission's proposed
AAR requirements without specifically discussing the 10-day
threshold.\251\ Industrial Customer Organizations specifically agree
with the Commission that implementing AARs in near-term transmission
service will more accurately reflect the cost of delivering

energy to load.\252\ CEA states that using AARs to calculate
transmission line ratings for service requests up to 10 days has proven
to be reliable and to provide benefits to effective and reliable
transmission operations.\253\ EDFR contends that the distinction
between AARs and seasonal line ratings depending on the applicable time
frame appears sensible.\254\ ACPA/SEIA state that they support the
Commission's proposed requirements for near-term point-to-point
transmission service and curtailments expected to occur within the next
10 days.\255\ The Ohio FEA does not take a firm position, but states
that implementing AARs for the next 10 days is reasonable.\256\ OMS
states that the weather data required to implement AARs is already
widely available through public sources and used for load and resource
forecasting.\257\
---------------------------------------------------------------------------

    \251\ EPSA Comments at 2; Clean Energy Parties Comments at 2-3;
R Street Institute Comments at 2-3; TAPS Comments at 1-3; ACORE
Comments at 3; OMS Comments at 2; New England State Agencies
Comments at 10; Vistra Comments at 2-3.
    \252\ Industrial Customer Organizations Comments at 4-6.
    \253\ CEA Comments at 2.
    \254\ EDFR Comments at 7.
    \255\ ACPA/SEIA Comments at 16-17.
    \256\ Ohio FEA Comments at 5.
    \257\ OMS Comments at 11.
---------------------------------------------------------------------------

    108. While not supporting or opposing the proposed 10-day
threshold, EPRI recommends an independent assessment that documents the
accuracy and risk associated with weather forecast data, explaining
that not all weather forecast data will be appropriate for transmission
line ratings and that some limiting spans run through microclimates.
EPRI further explains that inaccurate forecast risks can be mitigated
by identifying and implementing corrective factors to allow forecasts
to be used consistent with good utility practice. EPRI suggests
utility-specific rating studies would be required to assess and
mitigate forecast risk,\258\ to update and revise weather condition
assumptions, and possibly to adjust transmission reliability
margins.\259\ EPRI contends that further studies are needed to
determine a technical basis for updated wind speed assumptions and that
such studies may take between one and two years.\260\ Similarly, NERC
asserts that the Commission should consider how variations in the
temperature and load forecast should be addressed, what temperature
sets should be used when considering requests to grant firm
transmission service, and whether additional AAR calculation
information should be incorporated into transmission line rating
methodologies.\261\
---------------------------------------------------------------------------

    \258\ EPRI Comments at 10-11.
    \259\ Id. at 12. Transmission reliability margin, or TRM, means
the amount of TTC necessary to provide reasonable assurance that the
interconnected transmission network will be secure, or such
definition as contained in Commission-approved Reliability
Standards. 18 CFR 37.6(b)(1)(viii) (2021)..
    \260\ EPRI Comments at 12.
    \261\ NERC Comments at 7.
---------------------------------------------------------------------------

    109. Other commenters also discuss risk management for forecasted
ambient air temperatures. For example, Entergy states that forecasted
ambient air temperatures should include appropriate safety margins to
account for historical forecast uncertainty.\262\ Similarly, the SPP
MMU states that, ideally, congestion costs should, to some extent,
represent the risk assumed to serve the load.\263\ Finally, the CAISO
DMM argues that AAR requirements should allow leeway for RTOs/ISOs to
adjust modeled transmission limits for reliability reasons, as CAISO
does in the case of flowgates and nomograms whose modeled flows
frequently differ from actual flows.\264\ The CAISO DMM asserts that
lower or more conservative transmission limits might be needed for
temporally distant intervals to ensure commitments made in an advisory
interval horizon are feasible in the binding market interval and at the
time of power flow. The CAISO DMM further asserts that lower day-ahead
transmission limits could promote the feasibility of day-ahead
commitments in real time.\265\
---------------------------------------------------------------------------

    \262\ Entergy Comments at 11.
    \263\ SPP MMU Comments at 1.
    \264\ CAISO DMM Comments at 3, 4-5, 7.
    \265\ Id. at 3.
---------------------------------------------------------------------------

    110. Many RTOs/ISOs, however, oppose or urge caution on the
proposed 10-day threshold, with many advocating instead for a 48-hour
threshold.\266\ PJM does not support use of AARs in ATC calculations
beyond 48 hours, arguing that it would require significant system
changes and increase the compliance burden.\267\ PJM proposes AARs for
48 hours, and a more conservative approach for hours 48-240 to avoid
potential volatility and over-selling.\268\ Both NYISO and ISO-NE argue
that the transmission service offered in their respective regions
differs from that contemplated by the pro forma OATT, and request
flexibility in implementing any transmission line rating
requirements.\269\
---------------------------------------------------------------------------

    \266\ PJM Comments at 7-8; ISO-NE Comments at 10; MISO Comments
at 10, 16-17; NYISO Comments at 13-14.
    \267\ PJM Comments at 7-8.
    \268\ Id.
    \269\ ISO-NE Comments at 10; NYISO Comments at 9.
---------------------------------------------------------------------------

    111. NYISO does not support extending the AAR requirements or DLRs
into the day-ahead market, or for use up to 10 days into the future,
contending that such a requirement could result in costly and
unnecessary uplift payments, which could lead to significant cost
increases to customers, and could present reliability concerns if
transmission line ratings decline in real time from the day-ahead
schedule, forcing NYISO to rapidly reduce the schedules of certain
generators while quickly ramping up other generators.\270\ NYISO also
states that it would consider designating a portion of transfer
capability to be able to respond to the operational and cost volatility
that would come with DLR use, although such a process would limit
overall efficiency and increase production costs.\271\
---------------------------------------------------------------------------

    \270\ NYISO Comments at 13-14.
    \271\ Id.
---------------------------------------------------------------------------

    112. Without taking a position on the proposed 10-day threshold,
CAISO explains that the NOPR proposal would significantly increase the
complexity of its day-ahead market and introduce possible variances
between real-time and day-ahead schedules.\272\ Also without taking a
position on the proposed 10-day threshold, SPP states that, to use AARs
to evaluate transmission service requests that end within 10 days or as
the basis for curtailment, SPP would have to make several technical and
process upgrades and align its operating horizon and planning
horizon.\273\
---------------------------------------------------------------------------

    \272\ CAISO Comments at 9-11.
    \273\ SPP Comments at 5-7, 9.
---------------------------------------------------------------------------

    113. MISO argues that the vast majority of the benefit from AARs is
in addressing real-time congestion, and that implementing AARs in
MISO's day-ahead market would be difficult to do in less than three
years, while offering comparatively little benefit. MISO further claims
that requiring hourly AARs 10 days in advance will provide little to no
benefit because the accuracy of temperature forecasts diminishes
considerably beyond 48 hours, and precipitously by the five to seven
day mark.\274\ MISO urges the Commission to limit AAR implementation to
48 hours from the start of the operating day.\275\ Similarly, Potomac
Economics recommends that the Commission require that AARs be used in
the day-ahead and real-time markets, stating that this will allow the
RTOs/ISOs to focus their resources on improving the transmission line
ratings that will generate almost all of the savings.
---------------------------------------------------------------------------

    \274\ MISO Comments at 18.
    \275\ Id. at 19.
---------------------------------------------------------------------------

    114. Similar to RTOs/ISOs, transmission owners also urge caution
on, or oppose, the proposed 10-day threshold.\276\ Those transmission

owners generally argue that there is too much risk forecasting 10 days
forward and generally support more limited forecasting of either 24
\277\ or 48 hours.\278\ For example, Indicated PJM Transmission Owners
contend that forecasting AARs beyond two or three days in advance
provides little benefit because weather conditions beyond that are too
difficult to predict.\279\ Dominion similarly argues there is no
benefit to extending the AAR requirements beyond three to five days
because forecasts beyond five days tend to reflect seasonal
averages.\280\ Entergy contends that forecasts should be limited to
three days and include appropriate safety margins for historical
forecast uncertainty and geographic variability.\281\
---------------------------------------------------------------------------

    \276\ BPA Comments at 7; Indicated PJM Transmission Owners
Comments at 2; Dominion Comments at 8-9; Duke Energy Comments at 8-
9; SDG&E Comments at 2-3; Southern Company Comments at 5-6; MISO
Transmission Owners Comments at 15-16; EEI Comments at 10-11; APS
Comments at 8; NYTOs Comments at 5-6; AEP Comments at 6-7; NRECA/
LPPC Comments at 19-20; SDG&E Comments at 2-3; LADWP Comments at 7;
ITC Comments at 7-9.
    \277\ BPA Comments at 7; Duke Energy Comments at 8-9; Southern
Company Comments at 5-6; MISO Transmission Owners Comments at 15-16;
EEI Comments at 10-11; APS Comments at 8; NYTOs Comments at 5-6.
    \278\ AEP Comments at 6-7; NRECA/LPPC Comments at 19-20; SDG&E
Comments at 2-3; LADWP Comments at 7.
    \279\ Indicated PJM Transmission Owners Comments at 2.
    \280\ Dominion Comments at 9.
    \281\ Entergy Comments at 11.
---------------------------------------------------------------------------

    115. Several commenters argue that requiring AARs 10 days in
advance presents the potential problem of selling transmission service
based on a given ambient air temperature forecast only for the
temperature to be higher in real time, causing curtailments or safety
and reliability risks.\282\ BPA argues that it could result in an
inefficient use of the transmission system because transmission could
be sold, curtailed, and then available again, all prior to the
transmission service window.\283\ NYTOs note that, because there is
generally less flexibility in real time, if operators do not have
sufficient resources to restore flow to a lower limit within the
required time, they may need to shed load or damage equipment.\284\
---------------------------------------------------------------------------

    \282\ MISO Transmission Owners Comments at 15-16; Duke Energy
Comments at 8-9; Southern Company Comments at 5-6; NYTOs Comments at
5.
    \283\ BPA Comments at 7.
    \284\ NYTOs Comments at 5-6.
---------------------------------------------------------------------------

    116. Arguing that the Commission should not extend the AAR
requirements beyond the operating day, MISO Transmission Owners state
that using AARs any further forward than in real time introduces
uncertainty and error. MISO Transmission Owners acknowledge that these
risks exist today, but argue that AARs introduce further complexity and
explain that lowering transmission line ratings in real time would
compound the problems.\285\ Similarly, Duke Energy presents an example
of transmission sold based on a 60 degree Fahrenheit temperature
forecast four days forward and, on the operating day having the
transmission system oversubscribed, with greater pressure on operators
to curtail transmission schedules to avoid safety and reliability
risks, because the actual temperature was 75 degrees Fahrenheit.\286\
Southern Company states that AARs have the potential to create
reliability concerns if transmission service is oversold due to
inaccurate weather forecasts, especially for transmission service that
is scheduled 10 days ahead.\287\ Southern Company also states that
reliability issues may arise because AARs may create difficulties in
identifying the most limiting element, which may change as the
temperature changes, for the purpose of complying with Reliability
Standard FAC-008-5, and similar difficulties in complying with
Reliability Standard PRC-023 relay loadability requirements that depend
on maximum published ratings.\288\
---------------------------------------------------------------------------

    \285\ MISO Transmission Owners Comments at 15-16.
    \286\ Duke Energy Comments at 8-9.
    \287\ Southern Company Comments at 5-6.
    \288\ Id. at 6.
---------------------------------------------------------------------------

    117. NRECA/LPPC contend that such a requirement is unduly
burdensome because most of the benefits of using AARs are for real-time
and day-ahead transactions. NRECA/LPPC add that hourly weather
forecasts and the resulting hourly transmission line ratings are
unlikely to be accurate for more than a very few days.\289\ IID
explains that the Commission should provide flexibility in the forward
AAR application period, noting that weather patterns may not be stable
everywhere. IID contends that the Commission should consider
implementation challenges associated with looking 10 days ahead,
calculating what could be several hundred transmission line ratings per
year.\290\
---------------------------------------------------------------------------

    \289\ NRECA/LPPC Comments at 19-20.
    \290\ IID Comments at 4-6.
---------------------------------------------------------------------------

    118. EEI and APS contend that AARs should only be implemented in
real-time operations.\291\ EEI contends that such AAR values should not
extend to the day-ahead or intra-day unit commitment values and that
hourly ATC for up to 10 days would introduce uncertainty and ATC
fluctuations that result in curtailment of sold service and resale of
previously curtailed service. EEI further explains that the Commission
has previously recognized the reliability harm associated with
overestimated ATC and explains that the harm may result from using
hourly AARs for transmission service available for up to 10 days. EEI
also states that the NOPR proposal for hourly ATC for every hour in the
next 10 days is complex, with a burden that may outweigh the benefits
since the NOPR proposal fundamentally requires a TTC determination.
However, EEI states that TTC is path dependent and is based on many
transmission line ratings, contingencies, and power flow assumptions.
Because of this complexity, some transmission owners only determine TTC
annually or less frequently and, for these transmission owners, the
NOPR proposal for transmission providers to recalculate TTC every hour,
and perform 240 calculations every hour, is infeasible.\292\ NERC
contends that the Commission should consider how entities should
reconcile AARs used for planning and operations functions. NERC also
argues that there is potential confusion regarding transmission line
ratings used in transmission operator operations and planning system
operating limits and interconnection reliability operating limits, but
believes the confusion can be avoided through the timing of Commission
action to retire the NERC Modeling, Data, and Analysis (MOD) A
Reliability Standards.\293\
---------------------------------------------------------------------------

    \291\ APS Comments at 8; EEI Comments at 10-12.
    \292\ EEI Comments at 10-12.
    \293\ NERC Comments at 7-8.
---------------------------------------------------------------------------

    119. NYTOs explain that requiring AARs for up to 10 days forward,
even for a subset of the transmission system, would be a significant
change requiring major software buildout and corresponding market
design changes, which would create a significant burden on NYISO and
its associated utilities. NYTOs assert that this burden would be
further complicated by the fact that vendor availability for such a
buildout is unknown.\294\ NYTOs also explain that implementing AARs 10
days forward has the potential to create reliability concerns through
disconnects between forecasted and real-time conditions \295\ and that
extending the AAR requirements to the day-ahead market would make
security analysis more difficult.\296\ LADWP contends that the
Commission should align any final rule requirements with NERC
Reliability Standards and asserts that the proposed 10-day threshold
would conflict with

the requirements specified in Reliability Standard MOD-001-1a that ATC
be calculated hourly for the next 48 hours.\297\ Moreover, recognizing
the variability in weather, LADWP asks that system operators be
afforded the flexibility to recall transfer capability awarded during
moderate conditions at least 24 hours in advance.\298\
---------------------------------------------------------------------------

    \294\ NYTOs Comments at 5-6.
    \295\ Id.
    \296\ Id. at 7.
    \297\ LADWP Comments at 7.
    \298\ Id. at 6.
---------------------------------------------------------------------------

iii. Commission Determination
    120. We adopt the NOPR proposal to require transmission providers
to use AARs when evaluating the availability of and requests for near-
term transmission service (under sections 15, 17, 18, and 29 of the pro
forma OATT) \299\ as set forth under ``Obligations of Transmission
Provider'' in the pro forma OATT Attachment M adopted in this final
rule. We further adopt the Commission's proposal in the NOPR to require
transmission providers to use AARs as the relevant transmission line
rating when determining whether to curtail or interrupt point-to-point
transmission service (under sections 13.6 and/or 14.7 of the pro forma
OATT) if such curtailment or interruption is both necessary because of
issues related to flow limits on transmission lines and anticipated to
occur (start and end) within the next 10 days. Additionally, we adopt
the Commission's proposal in the NOPR to require transmission providers
to use AARs as the relevant transmission line rating when determining
whether to curtail network or secondary service (under section 33 of
the pro forma OATT) or redispatch network or secondary 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 (i.e., the 10-day threshold). Finally,
consistent with the NOPR, we clarify that AARs must be calculated using
the temperature at which there is sufficient confidence that the actual
temperature will not be greater than that temperature (i.e., expected
temperature plus an appropriate forecast margin).\300\
---------------------------------------------------------------------------

    \299\ See supra P 85.
    \300\ See NOPR, 173 FERC ] 61,165 at PP 97, 102.
---------------------------------------------------------------------------

    121. We believe that the 10-day threshold is justified by: (1) The
additional benefits gained by adopting a threshold that permits weekly
point-to-point transmission service requests to be evaluated using
AARs; (2) the additional benefits gained by the use of daytime/
nighttime ratings (discussed below in Section IV.B.2.c) within the 10-
day threshold; (3) the adequate accuracy of ambient air temperature
forecasts combined with the ability to implement appropriate forecast
margins to alleviate operational concerns associated with persistently
decreasing real-time transmission line ratings; and (4) the low
relative cost difference between a shorter forward threshold and the
proposed 10-day threshold. As the Commission stated in the NOPR, AAR
requirements up to 10 days forward will permit weekly point-to-point
transmission service to be evaluated using AARs. Because weekly point-
to-point transmission service is one of several types of transmission
products provided under the Commission's pro forma OATT, by adopting
the 10-day threshold for AAR implementation rather than a shorter
forward duration, weekly point-to-point transmission customers will
receive the benefits of AAR implementation rather than only
transmission customers taking shorter duration transmission service,
thereby not just increasing the expected benefits from the
implementation of AARs by improving the accuracy of transmission line
ratings for a wider range of transmission services but also for a
potentially wider range of transmission customers.
    122. We also require AARs to include separate daytime and nighttime
ratings. This daytime/nighttime ratings requirement, combined with the
addition of weekly point-to-point transmission service, will produce
further benefits in forward nighttime hours that would not see such
benefits if the AAR requirements were imposed over a timeframe shorter
than 10 days forward. These benefits of increased accuracy that result
from applying daytime/nighttime ratings to weekly point-to-point
transmission service and to shorter duration transmission service up to
10 days forward are significant on their own, even in the unlikely
event that the use of ambient air temperature forecasts 10 days forward
results in no hours where daytime AARs are greater than seasonal line
ratings. In other words, if we were to adopt a shorter threshold for
the AAR requirements than 10 days forward, the significant benefits
derived from the more accurate transmission line ratings during the
additional nighttime hours included in the 10-day threshold would be
lost. We further note that weather forecast quality is not static, but
rather is steadily improving such that the benefits of the 10-day
threshold requirement are likely to increase over time.\301\
---------------------------------------------------------------------------

    \301\ See, e.g., NOAA, Annual WPC Mean Absolute Errors, https://www.wpc.ncep.noaa.gov/images/hpcvrf/maemaxyr.gif (last visited Oct.
28, 2021) (showing NOAA data on the evolving accuracy of their
Weather Prediction Center forecasts of daily high temperature).
---------------------------------------------------------------------------

    123. Although we acknowledge that the accuracy of forecasts
decreases the further in advance the forecast is made, we disagree that
ambient air temperature forecasts made 10 days in advance are so
inaccurate that they cannot provide any benefits when used as part of
AARs, even when adjusted with appropriate forecast margins, as
discussed herein. Neither commenters supporting nor opposing the 10-day
threshold provide quantitative evidence related to the accuracy of 10-
day forecasts; however, a published analysis of the NOAA National Blend
of Models (NBM) forecast--one of the publicly available NOAA forecasts
that looks out at least 10 days--indicates that the mean absolute error
for 240 hour (10 day) forward continental United States surface
temperature forecasts was approximately four to six degrees Fahrenheit
in July to November 2016.\302\ We find that such levels of error would
likely allow for a meaningful number of hours in any season where a 10-
day forward AAR would provide benefits relative to the seasonal line
rating. We also note that this finding is consistent with the support
for the 10-day threshold by various commenters.\303\
---------------------------------------------------------------------------

    \302\ Tabitha Huntemann, Daniel Plumb, and David Ruth,
Verification of the National Blend of Models (2017), https://www.weather.gov/media/mdl/AMS2017-NBMVerification.pdf. We note that
this analysis was applicable to the 2016 National Blend of Models
(NBM) Version 2.0 forecast, and that several improved versions of
the NBM forecast have been implemented since that time. The current
NBM Version 4.0 was implemented in September 2020. See NBM: National
Blend of Models, https://vlab.noaa.gov/web/mdl/nbm. While we take
notice of this NBM forecast accuracy data as a point of reference,
we emphasize that the NBM forecasts are just one example of the
types of forecasts that transmission providers might rely on in
complying with this final rule.
    \303\ CEA Comments at 2; EDFR Comments at 7; Ohio FEA Comments
at 5; New England State Agencies Comments at 9-10; ACPA/SEIA
Comments at 13.
---------------------------------------------------------------------------

    124. We do not find persuasive arguments that the AAR requirements
adopted in this final rule will be unduly burdensome. Contrary to such
assertions, because we expect the increased costs of implementing AARs
under a 10-day threshold (as opposed to a shorter threshold) to be
primarily related to increased forecasting and data storage/hardware
needs, we do not expect such costs to be excessive. Moreover, in
certain situations, especially outside the RTO/ISO context, adopting
the 10-day threshold will

allow more transfer capability to be made available to customers than
simply adopting seasonal worst-case assumptions. In addition, as CEA
states, using AARs to calculate transmission line ratings for service
requests up to 10 days has proven to be reliable and to provide
benefits to effective and reliable transmission operations.\304\ In
that context, commenters have not provided evidence that the cost to
procure or develop 10-day forward forecasts is materially different
from the cost to procure or develop two- or three-day forward forecasts
and, in any case, that such cost outweighs the added benefits of
extending the forward period from two or three days to 10 days. For
these reasons, we expect the material benefits resulting from adopting
the 10-day threshold to, on balance, outweigh the costs.
---------------------------------------------------------------------------

    \304\ CEA Comments at 2.
---------------------------------------------------------------------------

    125. We emphasize that any benefit from the AAR requirements, and
the 10-day threshold in particular, should be compared to the relative
costs of alternatives. And we find that the cost associated with
requiring AARs for additional days forward is essentially the cost of
accessing, storing, and processing the additional forecast data, and
the cost of calculating, storing, and incorporating into transmission
service the additional hours of AARs. As we expect this process will be
largely automated, we do not anticipate that the cost of the 10-day
threshold, as opposed to a shorter threshold, will be significantly
higher. Although the question of where to draw the line in terms of the
time threshold for AAR implementation is not clear cut, we find that 10
days strikes an appropriate balance between the benefits of more
accurate transmission line ratings that result from the AAR
requirements adopted in this final rule, and the likely costs of
implementing those requirements.
    126. We note that some commenters may have misunderstood the
Commission's proposal in the NOPR as requiring the use of expected
ambient air temperatures in forecasts of AARs for future periods. That
is, they may have read the Commission's NOPR proposal as requiring that
if the forecasted ambient air temperature at a given transmission line
10 days in advance (without any forecast margin applied, i.e., the
expected temperature) was X degrees, that the transmission provider was
required to use an AAR for that hour 10 days forward that assumed an
air temperature of X degrees. This is not the case. Rather, AARs must
be calculated using the temperature at which there is sufficient
confidence that the actual temperature will not be greater than that
temperature (i.e., expected temperature plus an appropriate forecast
margin).\305\ This approach to calculations is consistent with EPRI's
recommendation and also comments from Entergy and the CAISO DMM, which
suggest margins to account for forecast error.\306\
---------------------------------------------------------------------------

    \305\ See NOPR, 173 FERC ] 61,165 at PP 97, 102.
    \306\ EPRI Comments at 10-12; Entergy Comments at 11; CAISO DMM
Comments at 3.
---------------------------------------------------------------------------

    127. In response to requests for clarification from BPA, LADWP, and
EEI that transmission providers can curtail transmission sold at least
24 hours in advance, consistent with existing curtailment
prioritization, should temperature forecasts dictate such curtailment,
we confirm that we are not changing the existing curtailment
prioritization. In implementing the 10-day threshold, it may be
necessary in some instances for transmission providers to curtail
transmission sold based on ambient air temperature forecasts (including
forecast margins) that end up being lower than real-time temperatures.
Although transmission providers will continue to curtail transmission
at times due to unrealized ambient air temperature assumptions, the
need for such curtailments should be decreased as a result of the AAR
requirements adopted herein.\307\ We reiterate that under the AAR
requirements that we adopt in this final rule, transmission providers
have the latitude (and obligation) to develop accurate, safe, and
reliable transmission line ratings,\308\ and we do not expect that such
transmission line ratings will necessitate an increase in the need for
curtailments due to inaccurate AARs. If a transmission provider
determines (whether during pre-testing of its AAR methodologies or
during actual operations) that a given level of forecast margins yields
an unreasonable frequency of such curtailment, it should re-evaluate
and adjust its forecast margins.
---------------------------------------------------------------------------

    \307\ We note, for example, that a typical winter seasonal line
rating temperature assumption today is 32 degrees Fahrenheit--a
temperature assumption which in many parts of the United States is
violated frequently over the current typical six-month ``winter
season'' used in seasonal line ratings. Commission Staff Paper at 7;
see also Midwest Reliability Organization Standards Committee,
Standard Application Guide: FAC-008, Version 1.1, p. 14 (March 21,
2017), https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/FAC-008-3%20Standard%20Application%20Guide.pdf. We expect such assumption
violations to be less frequent under our required approach, where
transmission providers will apply reasonable forecast margins when
developing their AARs
    \308\ NOPR, 173 FERC ] 61,165 at P 97.
---------------------------------------------------------------------------

    128. We further acknowledge that, in addition to the concerns of
some commenters related to forecast margins being too low, certain
forecast margins could also prove to be too high. In those instances,
as with the implementation of static transmission line ratings,
transmission line ratings using unreasonably high forecast margins
would also yield inaccurate transmission line ratings and, in turn,
would result in an underutilization of existing transmission
facilities, price signals based on less transfer capability than is
truly available, and wholesale rates that are unjust and unreasonable.
Similar to unreasonably low forecast margins, if a transmission
provider determines (whether during pre-testing of its AAR
methodologies or during actual operations) that a given forecast margin
is unreasonably high, it should re-evaluate and adjust its forecast
margins.
    129. Similarly, contrary to comments from CAISO, NYISO, NYTOs, and
EEI that describe the operational risks associated with overestimating
ATC,\309\ we do not expect that the AAR requirements adopted herein
will result in a frequent number of instances when transmission line
ratings used in the real-time market are lower than transmission line
ratings used in the day-ahead market. Some such instances will occur,
but we believe that there is sufficient latitude within our
requirements, as discussed above, for day-ahead transmission line
ratings to be determined with sufficient forecast margins to avoid this
concern. Furthermore, as the Commission stated in the NOPR, day-ahead
markets already rely heavily upon weather forecasts to inform next-day
load and intermittent generation availability. This final rule does not
change reliance upon weather forecasting; instead, the AAR requirements
we adopt herein will improve the accuracy of transmission line ratings
and, if anything, lead to cost savings to consumers and reliability
benefits. Additionally, as PJM's AAR implementation experience
demonstrates, temperatures can be forecast day ahead with a reasonable
degree of certainty.\310\ We also find that operational risks that
might result from the use of transmission line ratings in the real-time
market that are lower than the transmission line ratings used in the
day-ahead market can further be

managed and mitigated through the use of AARs in the RUC processes,
which will have the benefit of updated temperature forecasts. Finally,
we reiterate that PJM and AEP report reliability benefits from AAR
implementation.
---------------------------------------------------------------------------

    \309\ NYTOs Comments at 5-6; EEI Comments at 10-12; NYISO
Comments at 13-14; CAISO Comments at 9-11.
    \310\ PJM Comments at 3.
---------------------------------------------------------------------------

    130. In response to comments from EEI and other transmission owners
about the complexities of calculating AARs up to the 10-day threshold,
we find that such complexities are predominately reflected in the
upfront set-up and investment costs \311\ and that these costs will be
primarily related to increased forecasting and data storage/hardware
needs.
---------------------------------------------------------------------------

    \311\ Exelon Comments at 8; AEP Post-Technical Conference
Comments at 2-3; see also supra Section IV.B.1.c.
---------------------------------------------------------------------------

    131. In response to NERC's request that the Commission consider how
entities should reconcile AARs used for planning and operations
functions,\312\ we find that AARs used in near-term operations will
deviate from those transmission line ratings used in various planning
functions. As transmission providers progress closer in time to a given
interval, near-term ambient air temperature forecasts will necessarily
be updated. These updates will impact TTC, and, as a result, ATC and
system operating limits. In addition, regarding implementation of this
final rule and currently effective MOD A Reliability Standards,\313\
this final rule does not advocate for operating the transmission system
beyond the system operating limits and established facility ratings.
---------------------------------------------------------------------------

    \312\ NERC Comments at 6-7.
    \313\ Id. at 7.
---------------------------------------------------------------------------

    132. In response to requests for clarification of the NOPR proposal
from NERC and BPA with respect to temperature variations,\314\
transmission providers must consider the relevant ambient air
temperature forecasts along the transmission line, and determine the
transmission line rating based on the most limiting combination of
equipment limitations and forecasted local ambient air temperature
along the transmission line. We note that NERC additionally requested
that the Commission consider how variations in load forecasts would be
addressed when using values for each of the 240 hours in the next 10
days for each transmission line in granting firm point-to-point
transmission service.\315\ In response, we reiterate that the
requirements adopted herein are designed to ensure accurate
transmission line ratings. We also reiterate that AARs must be
calculated using the temperature at which there is sufficient
confidence that the actual temperature will not be greater than that
temperature (i.e., expected temperature plus an appropriate forecast
margin). We further clarify, in response to NERC, that transmission
line rating methodologies must be updated. In particular, pro forma
OATT Attachment M, as adopted by this final rule, requires transmission
line ratings to be computed in accordance with a written transmission
line rating methodology and consistent with good utility practice.
Moreover, we note that Reliability Standard FAC-008-5 Requirement 3.2
requires transmission line rating methodologies to identify how ambient
conditions are considered.\316\ Thus, transmission line rating
methodologies need to document methods used to calculate AARs.
---------------------------------------------------------------------------

    \314\ NERC Comments at 6-7; BPA Comments at 2-4.
    \315\ NERC Comments at 6-7.
    \316\ Reliability Standard FAC-008-5, Requirement R3.2, p.4,
http://www.nerc.com/pa/Stand/Project%20201803%20Standards%20Efficiency%20Review%20Require/2018-03_FAC-008-5_clean_01192021.pdf.
---------------------------------------------------------------------------

    133. In response to LADWP's argument that the Commission should
align AAR requirements with the NERC Reliability Standards--and that
the proposed 10-day threshold would conflict with the requirement
specified in Reliability Standard MOD-001-1a that ATC be calculated
hourly for the next 48 hours--we note that Reliability Standard MOD-
001-1a requires that ATC be calculated for at least the next 48 hours,
not for only the next 48 hours. Furthermore, the Commission's
regulations require ATC to be calculated and/or posted for periods more
than 48 hours in the future (e.g., when transmission service is
requested or inquired about).
    134. Finally, in response to RTO/ISO requests for flexibility, we
clarify the applicability of the 10-day threshold to RTOs/ISOs. The
vast majority of energy transactions in RTOs/ISOs are executed and
financially settled in the day-ahead and real-time energy markets;
thus, we find that requiring AARs for the real-time and day-ahead
energy markets in RTOs/ISOs is necessary to ensure the accuracy of
transmission line ratings and just and reasonable wholesale rates.
Because these transactions take place within a one-day forward
timeframe, the 10-day threshold will provide very little additional
benefits in existing RTO/ISO markets. Accordingly, the 10-day threshold
will not apply to internal transactions or internal flows associated
with through-and-out transactions in RTOs/ISOs. However, given that
RTOs/ISOs generally use the pro forma OATT transmission service model
for movement of electricity into/out of their service territories, the
10-day threshold requirement will apply to RTOs/ISOs' evaluation or
determination of availability of transmission service at the seams of
RTO/ISO service territories, in order to improve the accuracy of
transmission line ratings and ensure just and reasonable wholesale
rates.
b. Role of the Transmission Owner and Transmission Provider in AAR
Implementation
i. NOPR Proposal
    135. In proposing AAR implementation in the pro forma OATT, the
Commission proposed for transmission providers--not transmission
owners--to implement AARs because transmission providers--not
transmission owners--must have an OATT.\317\
---------------------------------------------------------------------------

    \317\ NOPR, 173 FERC ] 61,165 at P 84.
---------------------------------------------------------------------------

ii. Comments
    136. Several commenters clarify that transmission owners, not
transmission providers, calculate transmission line ratings.\318\ For
example, MISO states that its formational documents reflect, and have
codified, the responsibility of transmission owners to calculate
facility ratings, not MISO.\319\ MISO Transmission Owners explain that
Reliability Standard FAC-008-5 requires transmission owners to have ``a
documented methodology for determining facility ratings of its solely
and jointly owned Facilities'' based on the electrical characteristics
of the transmission equipment or other industry standard.\320\ Southern
Company states that the MOD suite of NERC Reliability Standards
governing TTC/ATC calculations requires transmission line ratings as
provided by transmission owners.\321\ Similarly, ISO-NE explains that
its Transmission Operating Agreement requires its participating
transmission owners to establish transmission line ratings for each
transmission facility.\322\ Additionally, NYISO states that in the New
York Control Area, the transmission owners are responsible for
developing transmission line ratings and providing the element ratings
directly to NYISO. In turn, according to NYISO, NYISO determines the
most limiting element, which sets the applicable facility rating.\323\
---------------------------------------------------------------------------

    \318\ MISO Comments at 27; Vistra Comments at 3-4; TAPS Comments
at 13-14; Southern Company Comments at 6; EEI Comments at 2-4; MISO
Transmission Owners at 29; EEI Comments at 2-4.
    \319\ MISO Comments at 27.
    \320\ MISO Transmission Owners at 29.
    \321\ Southern Company Comments at 3, 6.
    \322\ ISO-NE Comments at 6.
    \323\ NYISO Comments at 3.

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

    137. Because of these differing transmission owner and transmission
provider roles and responsibilities, these commenters request that the
Commission recognize and make these differing roles explicit in any
final rule.\324\ Some recommend further Commission action to ensure
transmission owners have an obligation to implement the AAR
requirements in proposed pro forma OATT Attachment M. For example,
Vistra encourages the Commission to modify its regulations to create a
compliance obligation for each transmission owner to provide RTOs/ISOs
all information necessary to implement proposed pro forma OATT
Attachment M.\325\ Similarly, TAPS requests that the Commission clarify
that: (1) RTOs/ISOs have the authority to require transmission owners
to provide the information they will need to implement AARs; or (2)
transmission owners within RTOs/ISOs must provide the information RTOs/
ISOs will need to implement AARs to the relevant RTO/ISO.\326\
Additionally, TAPS argues that in order to achieve efficient and
consistent application of AARs, the Commission should direct RTOs/ISOs
to use, or at minimum accommodate the use of, ``look-up tables.'' \327\
TAPS explains that, using the ``look-up table'' approach will limit the
obligation to continuously monitor weather reports to recalculate AARs
and communicate those transmission line ratings to the RTO/ISO on an
hourly basis.\328\
---------------------------------------------------------------------------

    \324\ MISO Comments at 27; Vistra Comments at 3-4; TAPS Comments
at 13-14; Southern Company Comments at 6; EEI Comments at 2-4.
    \325\ Vistra Comments at 3-4.
    \326\ TAPS Comments at 14.
    \327\ Id. at 8. TAPS states that, for each of their transmission
facilities, transmission owners should be required to provide RTOs/
ISOs with a table showing their temperature-adjusted rating for a
pre-established set of ambient air temperatures.
    \328\ Id. at 8-10.
---------------------------------------------------------------------------

    138. Noting the applicability of the pro forma OATT to transmission
providers and that transmission owners and transmission providers are
different in RTO/ISOs, Exelon comments on the phrasing ``is
calculated'' in the AAR definition, explaining that, while it largely
supports the proposed AAR definition, it does not ``calculate''
transmission line ratings hourly. Exelon states that it calculates 64
different transmission line rating cases (for nine temperatures sets,
across normal, long-term emergency, short-term emergency, emergency
load dump, and for both day and night), and then references the
relevant existing calculations in a ``look-up table'' through its
Inter-Control Center Communications Protocol signal. Exelon proposes to
refine the AAR term to: ``a transmission line rating that reflects the
appropriate temperature-adjusted rating for a facility based on an up-
to-date forecast of ambient air temperatures across the time period to
which the rating applies.'' \329\
---------------------------------------------------------------------------

    \329\ Exelon Comments at 11-12.
---------------------------------------------------------------------------

    139. Finally, CAISO argues that RTOs/ISOs and their stakeholders
will have to answer many questions in developing tariff provisions for
using hourly transmission line ratings. Several of these questions
relate to AAR implementation timelines, including the time hourly
transmission line ratings must be submitted by the transmission owners
to RTOs/ISOs and the time period that transmission owners will have to
update hourly transmission line ratings for use in real-time markets
after day-ahead results are published.\330\ As an example, BPA explains
that its dynamically established TTC calculations are based on
schedules submitted 20 minutes before the operating hour.\331\
---------------------------------------------------------------------------

    \330\ CAISO Comments at 12-13.
    \331\ BPA Comments at 5.
---------------------------------------------------------------------------

iii. Commission Determination
    140. We clarify that transmission owners, not transmission
providers, are responsible for calculating transmission line ratings.
This responsibility is codified in the NERC Reliability Standards, as
well as in RTO/ISO foundational documents.\332\ Nothing in this final
rule changes that responsibility. In the non-RTO/ISO regions, this
detail is generally not a concern because the transmission provider is
usually the transmission owner. However, in the RTO/ISO regions, there
is a distinction between transmission owners and transmission
providers. Thus, in order to comply with this final rule, RTOs/ISOs--
the transmission provider with the OATT on file--will need to rely on
their member transmission owners to calculate transmission line ratings
and provide them to the RTO/ISO.\333\
---------------------------------------------------------------------------

    \332\ See, e.g., Reliability Standards FAC-008-5, Requirement R3
and FAC-008-5, Requirement R6.
    \333\ We note that, as discussed below, in RTO/ISO regions, in
addition to AARs, transmission owners will be required to calculate
and provide other transmission line ratings to the RTO/ISO,
including seasonal line ratings and emergency ratings. Moreover, in
RTO/ISO regions, transmission owners will be required to provide to
the RTO/ISO the list of transmission lines which have been exempted
from the AAR requirement (under the ``Exceptions'' paragraph of pro
forma OATT Attachment M) or temporary alternate ratings (under the
``System Reliability'' section of pro forma OATT Attachment M).
---------------------------------------------------------------------------

    141. In response to concerns about the responsibility for
calculating transmission line ratings in RTOs/ISOs, we clarify that we
expect RTOs/ISOs to require their member transmission owners to make
timely calculations and determinations as required for transmission
line ratings, and to provide them to the RTO/ISO.\334\ Where the
transmission provider is not the transmission owner (e.g., RTOs/ISOs),
we require the transmission provider to explain in its compliance
filing, as part of its implementation of the new pro forma OATT
Attachment M, through what mechanism (tariff, membership agreement,
etc.) the transmission owner(s) will have the obligation for making and
communicating to the transmission provider the timely calculations and
determinations related to transmission line ratings (including the
exercise of any discretion in calculations or application of
exceptions).
---------------------------------------------------------------------------

    \334\ See, e.g., MISO, MISO Rate Schedules, MISO Transmission
Owner Agreement, art. 4, Sec.  II.A Providing Information (30.0.0)
(``Each Owner and User shall provide such information to [MISO] as
is necessary for [MISO] to perform its obligations under this
Agreement and the Tariff.''); SPP, Governing Documents Tariff,
Membership Agreement, Sec.  3.5 Providing Information (0.0.0)
(``Member shall provide such information to SPP as is necessary for
SPP to perform its obligations under this Agreement and the OATT,
and for planning and operational purposes.''); PJM, Rate Schedules,
Sec.  4.11 Transmission Facility Ratings (0.0.0) (``All Parties
shall regularly update and verify Transmission Facility ratings,
subject to review and approval by PJM, in accordance with the
following procedures and the procedures in the PJM Manuals . . .
.''); ISO-NE, ISO New England Inc. Agreements and Contracts,
Transmission Operating Agreement, Sec. Sec.  3.02(a)(ii) (5.0.0)
(stating that ISO-NE shall ``determine Operating Limits based on
forecasted or real-time system conditions and in accordance with the
facility ratings established by the PTOs in collaboration with the
ISO pursuant to Section 3.06''), 3.06(a)(v) (5.0.0) (stating that
the transmission owner shall: ``(v) Collaborate with the ISO with
respect to: (A) The development of Rating Procedures, (B) the
establishment of ratings for each PTO's New Transmission Facilities;
(C) the establishment of ratings for each PTO's Acquired
Transmission Facilities that do not have an existing rating as of
the Operations Date, and (D) the establishment of any changes to
existing ratings for Transmission Facilities in effect as of the
Operations Date''); CAISO, CAISO eTariff, Transmission Control
Agreement, Sec.  4.2 (0.0.0) (stating that facility ratings are
required CAISO's database of all facilities under the CAISO's
control and that transmission owners are responsible for providing
updates to that database when there is a change in ratings, which
CAISO reviews).
---------------------------------------------------------------------------

    142. In response to Exelon's concerns about the proposed AAR
definition,\335\ we clarify that hourly (or more frequent) querying of
``look-up tables'' or similar pre-calculated AAR databases will satisfy
the requirement that AARs be calculated at least each hour. While we
expect transmission owners to calculate transmission line ratings,
given the difference between transmission owners and transmission
providers in RTOs/ISOs, we require RTOs/ISOs on compliance to propose
and justify a

methodology for AAR implementation, delineating the expected roles
between transmission owners and transmission provider. In doing so, we
encourage RTO/ISO transmission owners to coordinate implementation
methodologies and promote implementation consistency to the greatest
extent possible within an RTO/ISO service territory. However, in
response to comments from TAPS that the Commission should require use
of a ``look-up table'' approach, or at least require that approach be
an option,\336\ we decline to require a specific AAR implementation
methodology, noting regional software and procedural differences.
---------------------------------------------------------------------------

    \335\ Exelon Comments at 11-12.
    \336\ TAPS Comments at 7-10.
---------------------------------------------------------------------------

    143. In response to requests for clarification from CAISO, we
decline to require in this final rule a specific timeline by which AARs
will need to be calculated or submitted to the transmission provider
(either in the context of the day-ahead and real-time markets in RTOs/
ISOs, or in terms of how far in advance of an operating hour an AAR
should be calculated in a bilateral market).\337\ However, we note that
the AAR definition we adopt in this final rule requires that AARs
``[r]eflect[] an up-to-date [emphasis added] forecast of ambient air
temperature across the time period to which the rating applies,'' by
which we mean that new forecast data should be incorporated into AAR
calculations as close to real time as reasonably possible given the
timelines needed to obtain forecast data and perform the AAR
calculation, as well as any other steps needed for validation,
communication, or implementation of AARs.\338\ Furthermore,
transmission providers must explain their timelines as part of their
compliance filings. We recognize that transmission providers already
manage similar timing issues with respect to load forecasts, forecasts
for renewable energy production, and generation bid deadlines, and it
may be that deadlines for AAR calculation/submission are not
significantly different from existing deadlines for submission of
updates to generation supply offers and load.
---------------------------------------------------------------------------

    \337\ We note that in some instances RTOs/ISOs may propose (as
we understand PJM does now for its AARs) to have the RTO/ISO select
AARs based on temperature forecasts and pre-calculated AAR tables/
databases. In such cases, it may not be (as CAISO's comments
suggest) that transmission owners will be sending entire sets of
AARs to RTOs/ISOs every time they are calculated.
    \338\ Pro Forma OATT attach. M, AAR Definition.
---------------------------------------------------------------------------

c. Solar Heating in AAR Calculations
i. NOPR Proposal
    144. In the NOPR, the Commission proposed to require AARs that
reflect up-to-date forecasts of ambient air temperature, but noted that
AARs could possibly incorporate other forecasted inputs.\339\ As an
example of other inputs, the Commission pointed to PJM's implementation
of ``day and night ambient air temperature tables, where the night
ambient air temperature table assumes zero solar irradiance.'' \340\
The Commission also sought comment on whether to require transmission
providers to implement DLRs, rather than only AARs, noting that DLRs
can incorporate solar heating intensity, among other ambient
conditions, to calculate the amount of transfer capability of a given
transmission line in near real time.\341\
---------------------------------------------------------------------------

    \339\ NOPR, 173 FERC ] 61,165 at P 23.
    \340\ Id. P 23 n.40; see also id. P 21 (explaining that
different types of ambient weather assumptions can be incorporated
into transmission line ratings, including updated air temperature,
solar irradiance, and wind speed, among others).
    \341\ Id. PP 25-26, 43.
---------------------------------------------------------------------------

ii. Comments
    145. Several commenters discuss the incorporation of solar heating
into transmission line ratings. For example, Vistra suggests that,
instead of requiring full DLRs, the Commission instead adopt a ``middle
ground'' of requiring AARs that incorporate consideration of
predictable solar heating (at least considering daytime/nighttime
hours, similar to PJM's existing implementation of AARs).\342\ Potomac
Economics and Vistra contend that such a requirement would not
necessitate sophisticated monitoring or forecasting, and instead would
produce significant benefits with minimal cost.\343\ R Street
Institute, PG&E, Indicated PJM Transmission Owners, Dominion, and
Potomac Economics also support incorporating predictable daytime/
nighttime solar heating into AARs, with Dominion and Indicated PJM
Transmission Owners noting that this is already the practice in
PJM.\344\ Entergy, without taking a position on whether it would be
appropriate for the Commission to require separately calculated daytime
and nighttime ratings, states that the shade of night provides an
additional 5% to the transmission line's transmission line
ratings.\345\ PG&E states that it supports separately calculated
daytime and nighttime ratings and indicates that its research from
PJM's posted transmission line ratings shows that at least 14% of PJM's
transmission line ratings would increase by 10% by considering solar
heating.\346\ Potomac Economics estimates that considering daytime/
nighttime could increase thermal transmission line ratings on average
by 11% during nighttime hours and the potential benefits would be
approximately $30 million per year in MISO alone.\347\
---------------------------------------------------------------------------

    \342\ Vistra Comments at 4-5.
    \343\ Id. at 4-5; Potomac Economics Comments at 14-15.
    \344\ R Street Institute Comments at 3; PG&E Comments at 11-12;
Indicated PJM Transmission Owner Comments at 8-9; Dominion Comments
at 8; Potomac Economics Comments at 14-15.
    \345\ Entergy Comments at 8.
    \346\ PG&E Comments at 11.
    \347\ Potomac Economics Comments at 14-15.
---------------------------------------------------------------------------

    146. Vistra points out that solar heating varies in several ways:
Between daytime and nighttime (with sunrise/sunset times and day length
varying significantly across the year), across the hours during the day
(varying--under worst-case, clear-sky assumptions--from close to zero
just after and before sunrise and sunset, respectively, to a daily mid-
day peak), and across the days of the year (with higher mid-day peaks
in the summer and lower peaks in the winter).\348\ Vistra and PG&E both
suggest that the Commission consider requiring regular updates to
sunrise/sunset times, with Vistra discussing possible daily or seasonal
updates, and PG&E discussing possible monthly updates.\349\
Furthermore, while Vistra recommends that the Commission at the very
least require separate daytime and nighttime AARs, Vistra also provides
data for how solar heating varies significantly across the day, and
discusses how more granular solar forecasting might reflect these solar
variations.\350\
---------------------------------------------------------------------------

    \348\ Vistra Comments at 4-6; see also PG&E Comments at 11-12.
    \349\ Vistra Comments at 5; PG&E Comments at 12.
    \350\ Vistra Comments at 4-5.
---------------------------------------------------------------------------

iii. Commission Determination
    147. Upon consideration of the comments received in response to the
NOPR, we require transmission providers to incorporate solar heating
into AARs by implementing separate AARs for daytime and nighttime
periods. Specifically, we require transmission providers to reflect the
lack of solar heating in the technical assumptions for nighttime AARs.
As noted by Dominion and Indicated PJM Transmission Owners,
incorporating solar heating into AARs is consistent with PJM's existing
AAR implementation.\351\ Absent this requirement for daytime/nighttime

AARs, AARs would assume the worst-case solar heating assumptions in
every hour, even at night when there is no solar heating of
transmission lines at all.
---------------------------------------------------------------------------

    \351\ Dominion Comments at 7-8; Indicated PJM Transmission
Owners Comments at 7.
---------------------------------------------------------------------------

    148. The consideration of daytime/nighttime solar heating in the
AARs used by transmission providers will further the Commission's goal
of ensuring more accurate transmission line ratings, which result in
just and reasonable wholesale rates. Furthermore, as commenters note,
the improvements to the accuracy of transmission line ratings that will
result from adopting a daytime/nighttime AAR requirement can yield
significant economic benefits at minimal cost.\352\
---------------------------------------------------------------------------

    \352\ Vistra Comments at 4-5; Potomac Economics Comments at 14-
15.
---------------------------------------------------------------------------

    149. We agree with commenters that sunrise/sunset times should be
updated periodically to ensure the accuracy of both daytime and
nighttime ratings. Specifically, we clarify that in order to comply
with the requirement in pro forma OATT Attachment M for AARs to reflect
the absence of solar heating during nighttime periods, transmission
providers must update the sunrise and sunset times used to calculate
their AARs at least monthly, if not more frequently. We find that among
the daily, monthly, and seasonal timeframes suggested by commenters,
the requirement to update sunrise/sunset times on a monthly basis
strikes an appropriate balance between achieving the greatest benefits
of AAR implementation and not imposing an unreasonable burden on
transmission providers. Given the speed at which sunrise and sunset
times change in many areas of the country during certain times of the
year, monthly updates will result in significantly more accuracy in
transmission line ratings and capture significantly greater value than
seasonal updates. Because sunrise/sunset times can be easily calculated
with precision based on location and day of the year,\353\ and because
we expect AAR implementation to be largely automated, we do not expect
monthly updates to sunrise/sunset times to impose a significant
additional implementation burden relative to seasonal updates. Nothing
in this final rule would prevent a transmission provider from updating
its sunrise/sunset times more frequently than monthly and we encourage
transmission providers to do so.\354\
---------------------------------------------------------------------------

    \353\ See, e.g., National Oceanic and Atmospheric
Administration, Global Monitoring Division, General Solar Position
Calculations, https://gml.noaa.gov/grad/solcalc/solareqns.PDF
(providing formulas for calculating sunrise/sunset times based on
latitude, longitude, and day of the year).
    \354\ We note that PJM currently updates its sunrise/sunset
times more frequently than monthly in its day/night AAR
implementation.
---------------------------------------------------------------------------

    150. Vistra correctly points out that, in addition to sunrise/
sunset times, solar heating also varies across the days of the year and
the hours of the day. However, again, to maintain a balance of benefits
and burdens, we decline to require regular updates to mid-day peak
solar heating to account for differences across days of the year. As
such, transmission providers may use maximum annual assumptions for
solar heating when determining daytime AARs. Furthermore, to balance
benefits and burdens, we decline to require more granularity (e.g.,
hourly forecasts) in solar heating assumptions and only require
daytime/nighttime consideration. We note, however, that nothing in this
final rule would prohibit a transmission provider that wants to
voluntarily implement regular updates to peak mid-day solar heating, or
to voluntarily implement hourly forecasts for solar heating, from doing
so. We further note that peak or hourly daytime solar heating (under
worst-case clear-sky assumptions) can be accurately computed based on
location using equations such as those presented in IEEE (Institute of
Electrical and Electronics Engineers) Standard 738.\355\
---------------------------------------------------------------------------

    \355\ Institute of Electrical and Electronics Engineers, IEEE
Standard for Calculating the Current-Temperature Relationship of
Bare Overhead Conductors 18-20, IEEE Std 738-2012 Cor 1-2013 (2013)
(IEEE 738).
---------------------------------------------------------------------------

3. Other AAR Implementation Issues
a. Reliability Unit Commitment Processes
i. NOPR Proposal
    151. In the NOPR, the Commission proposed that RTOs/ISOs comply
with the AAR requirements by revising their OATTs to implement AARs
within their SCED and SCUC models (and in any relevant related models)
in both the day-ahead and real-time markets and in any intra-day RUC
processes.\356\
---------------------------------------------------------------------------

    \356\ NOPR, 173 FERC ] 61,165 at P 91.
---------------------------------------------------------------------------

ii. Comments
    152. CAISO requests clarification on whether hourly transmission
line ratings should be constant in RUC processes.\357\
---------------------------------------------------------------------------

    \357\ CAISO Comments at 12-13.
---------------------------------------------------------------------------

iii. Commission Determination
    153. In response to CAISO, we clarify that transmission providers
should propose on compliance to use updated AARs as part of any market
process associated with the day-ahead and real-time markets (including
RUC, as well as any look-ahead commitment processes or other such
processes). In the event an RTO/ISO believes that AARs should not be
used as part of any market process associated with the day-ahead and
real-time markets (or that updated AARs should not be required for any
market process), it should propose and justify such deviations on
compliance.
b. Time Resolution and Calculation Frequency of AAR Requirements
i. NOPR Proposal
    154. In defining AARs, the Commission proposed to require that AARs
be calculated at least each hour, if not more frequently, and for AARs
to apply to a time period of not greater than one hour.\358\
---------------------------------------------------------------------------

    \358\ NOPR, 173 FERC ] 61,165 at P 95.
---------------------------------------------------------------------------

ii. Comments
    155. Many state agencies, supply and load representatives,
renewable energy advocates, and independent experts support the
proposed AAR requirements overall, which includes the proposed time
resolution or calculation frequency.\359\ RTOs/ISOs are mixed in
whether they take a position and generally discuss their ability to
accept AARs calculated hourly. For example, while not taking a position
on the appropriateness of this part of the NOPR proposal, MISO explains
that its EMS and SCED are capable of receiving and leveraging AARs
provided by their transmission owners at least hourly.\360\
---------------------------------------------------------------------------

    \359\ EPSA Comments at 2; Clean Energy Parties Comments at 2-3;
R Street Institute Comments at 2-3; TAPS Comments at 1-3; ACORE
Comments at 3; ACPA/SEIA Comments at 7; OMS Comments at 2; New
England State Agencies Comments at 10; Vistra Comments at 2-3.
    \360\ MISO Comments at 12.
---------------------------------------------------------------------------

    156. CAISO explains that its transmission owners can submit AARs,
but that the fundamental challenge with using AARs is timely
communication of forecasted transmission line ratings. According to
CAISO, participating transmission owners currently submit AARs as an
equipment rating change through CAISO's outage management system
(webOMS).\361\ CAISO further states that using hourly adjusted
transmission line ratings for transmission lines across the 24-hour
horizon of a trading day will necessarily and significantly increase
the complexity of CAISO's day-ahead optimization processes.\362\ In
addition, CAISO contends that hourly transmission line ratings in real-
time markets may drive uplift costs by causing variances between total
transfer

capability used in each of CAISO's commitment and dispatch processes.
In addition, CAISO asserts that transmission line rating changes over
the market run's look-ahead period can generate inefficient outcomes
through deviations from day-ahead schedules.\363\
---------------------------------------------------------------------------

    \361\ CAISO Comments at 4.
    \362\ Id. at 9-10.
    \363\ Id. at 10-11.
---------------------------------------------------------------------------

    157. Similarly, NYISO cautions against requiring hourly updates to
transmission line ratings if they are not already used by RTOs/
ISOs.\364\ NYISO explains that introducing hourly transmission line
ratings could result in divergences from the day-ahead schedule,
creating uplift or potential reliability risks, if hourly transmission
line ratings cause a transmission line rating to decline.\365\ On
hourly updates to AARs, NYISO notes that its market software looks
ahead, including a 24-hour day-ahead optimization and multi-period
commitment for the real-time market.\366\ NYTOs note that NYISO and
NYTOs can apply AARs and DLRs to congested transmission lines currently
in real time to increase transmission line ratings.\367\
---------------------------------------------------------------------------

    \364\ NYISO Comments at 4.
    \365\ Id. at 4-5.
    \366\ Id. at 13.
    \367\ NYTOs Comments at 4.
---------------------------------------------------------------------------

    158. ISO-NE states that it allows for short-term changes to
transmission line ratings, though not at an hourly level.\368\ ISO-NE
further states that its coordinated transaction scheduling with NYISO
runs every 15 minutes and therefore a shorter interval would have to be
considered.\369\
---------------------------------------------------------------------------

    \368\ ISO-NE Comments at 6-7.
    \369\ Id. at 9.
---------------------------------------------------------------------------

    159. While PJM supports the adoption of AARs, it opposes the
requirements that a transmission line rating apply to a period not
greater than one hour and that transmission line ratings be updated
hourly. PJM states that the key factor for determining the transmission
line rating is the temperature and, as a result, the primary event that
triggers a change in AARs is the ambient air temperature. PJM states
that, in implementing AARs, it continuously monitors temperatures and
updates transmission line ratings for temperature fluctuations in
accordance with the transmission owners' look-up table, so there is no
benefit to updating the AARs hourly if no temperature change has
occurred.\370\ Relatedly, PJM and Duke Energy state that the proposed
requirements in the NOPR that transmission line ratings be updated
hourly could harm operations.\371\ This is because, according to PJM, a
significant temperature change could occur between required hourly
updates and, if a transmission operator is not continuously monitoring
ambient air temperature, an incorrect transmission line rating would be
effective from the time of the temperature change until the next
mandated hourly update.\372\ PJM states that these temporal
requirements simply add an administrative burden without providing
additional benefits.\373\ PJM requests that the Commission refrain from
requiring transmission providers to apply AARs in hourly intervals but
rather require them to be continuously monitored with changes triggered
by temperature changes and the other relevant factors in the look-up
tables.\374\
---------------------------------------------------------------------------

    \370\ PJM Comments at 4-5.
    \371\ Id. at 5; Duke Energy Comments at 8.
    \372\ PJM Comments at 5.
    \373\ Id. at 2 n.5.
    \374\ Id. at 6.
---------------------------------------------------------------------------

    160. Many transmission owners also request flexibility on the
proposed requirement for AARs to be calculated ``at least each hour.''
\375\ ITC asks that the Commission instead only require daily AAR
updates and notes that this is the prevailing practice for transmission
owners using AARs in MISO.\376\ MISO Transmission Owners also request
flexibility to implement daily rather than hourly AARs.\377\ Indicated
PJM Transmission Owners argue against requiring hourly AAR
calculations.\378\ Indicated PJM Transmission Owners explain that PJM
adjusts transmission line ratings over the day as temperatures change,
but state that there is little benefit to hourly verification of
temperature changes because transmission line ratings in PJM do not
typically change hourly. Similarly, EEI argues for a requirement for
daily AAR updates for real-time operations.\379\
---------------------------------------------------------------------------

    \375\ ITC Comments at 9; MISO Transmission Owners Comments at
24; EEI Comments at 12; Duke Energy Comments at 10.
    \376\ ITC Comments at 9.
    \377\ MISO Transmission Owners Comments at 24.
    \378\ AEP Comments at 6-7; Dominion Comments at 3; Indicated PJM
Transmission Owners Comments at 7-9.
    \379\ EEI Comments at 12; PacifiCorp Comments at 2; BPA Comments
at 3; WAPA Comments at 6-7.
---------------------------------------------------------------------------

    161. In contrast, Entergy explains that it automatically updates
AARs every hour for the approximately 1,000 facilities for which it
calculates AARs, and this information is automatically updated hourly
in Entergy's Real Time Contingency Analysis so the operator does not
have to look at charts.\380\ Exelon also contends that an hourly
transmission line ratings check would not be overly burdensome and
instead could help to prevent overloading a transmission line.\381\
Exelon also urges the Commission to provide sufficient flexibility to
ensure transmission line ratings can change intra-hourly.\382\
Moreover, Exelon comments that it believes that the Commission's
proposed requirements are sufficiently flexible to accommodate PJM's
current approach.\383\
---------------------------------------------------------------------------

    \380\ Entergy Comments at 3.
    \381\ Exelon Comments at 9-10.
    \382\ Id.
    \383\ Id. at 9.
---------------------------------------------------------------------------

iii. Commission Determination
    162. We adopt the Commission's proposal in the NOPR to require the
calculation of AARs ``at least each hour, if not more frequently'' and
the requirement that AARs ``appl[y] to a time period of not greater
than one hour.'' \384\
---------------------------------------------------------------------------

    \384\ NOPR, 173 FERC ] 61,165 at P 3 n.3.
---------------------------------------------------------------------------

    163. With respect to calculation frequency, we believe that
performing AAR calculations at least hourly appropriately balances
requiring updates at a frequency that captures meaningful changes in
ambient air temperature forecasts, and not overburdening transmission
providers. In response to concerns that the requirement for hourly
calculations may be unduly burdensome because temperature forecasts do
not always fluctuate hour by hour, we recognize that in some hours
forecasts for temperatures do not change, primarily because weather
services do not always have updated forecasted values for every
location each hour. However, it is not known exactly when such
forecasted values will be updated, and, therefore, our requirement to
calculate AARs hourly appropriately requires transmission providers to
check for forecast updates and apply any updates that are available. We
believe that the requirement to calculate AARs hourly ensures that any
such publication of forecast updates are incorporated into AARs in a
reasonable timeframe.\385\ If we were to instead require such
calculations on a longer time period (e.g., every eight hours), then
there would be some instances when published available weather forecast
updates would not be incorporated into AARs in time to accurately
reflect the transmission line's true transfer capability. Moreover, we
expect this process for AAR implementation to be largely automated,
with computer systems querying or receiving updated forecasts and
processing any such data

into updated AARs, such that calculating AARs hourly should not be
significantly more burdensome than calculating AARs daily. We agree
with Exelon that AAR calculations at least hourly are likely to be an
important tool used to prevent any transmission overload that might
occur as a result of a sudden, unexpected temperature increase.\386\ We
add that this requirement does not preclude intra-hour updates.
---------------------------------------------------------------------------

    \385\ For example, we understand that the NBM forecast (which is
a blend of distinct constituent forecasts) has updates published at
least every hour, but the constituent forecasts are typically
updated only three times per day. Exactly when the constituent
forecasts will be updated is not precise, such that an update to any
forecasted value might change in any hour.
    \386\ Exelon Comments at 9-10.
---------------------------------------------------------------------------

    164. We acknowledge, in response to comments by CAISO and NYISO,
that within RTOs/ISOs there will be times when AARs produce real-time
transmission line ratings that diverge from what was previously
calculated in the day-ahead market (based on earlier forecasts), and
that this may result in operating considerations and uplift costs.
However, we are not persuaded that such considerations or costs
outweigh the benefits of updating real-time transmission line ratings
discussed above. Further, updating transmission line ratings closer to
real time will help ensure that the most accurate transmission line
ratings are used in the real-time energy market and, in turn, tend to
reduce costs and promote reliable operations. Commenters seem to argue
that if the weather conditions unexpectedly change, such that
temperatures are significantly lower and significantly more transfer
capability is able to be used in real time compared to day ahead, the
markets should keep such transfer capability in reserve in order to
minimize uplift. We disagree that a concern about potential uplift
should result in transfer capability being withheld from the real-time
energy market with associated limits on the economic benefits of using
AARs. Further, we do not believe that any operating considerations
associated with updating transmission line ratings in real time will
compromise reliable operations. As PJM states, AARs are already
employed in PJM in both the day-ahead and real-time markets and, in its
experience, AARs increase operational flexibility, promote a more
efficient use of the transmission system, and result in more reliable
system dispatch and cost-effective market operations.\387\
---------------------------------------------------------------------------

    \387\ PJM Comments at 2.
---------------------------------------------------------------------------

    165. One of the reasons that substantial uplift is sometimes
considered problematic is that it may be evidence that the market is
not accurately considering operating constraints, which gives rise to
out-of-market actions and distorts short-term and long-term price
signals.\388\ While we acknowledge the potential for uplift in certain
situations, the reason for incurring uplift here is very different.
Updating transmission line ratings in real time will result in more
accurate prices that reflect actual real-time operating constraints.
Accordingly, the potential for the generation of uplift through our AAR
requirements would not be evidence of market design concerns or
inaccurate price signals.
---------------------------------------------------------------------------

    \388\ Uplift Cost Allocation and Transparency in Mkts. Operated
by Reg'l Transmission Orgs. and Indep. Sys. Operators, Order No.
844, 83 FR 18134 (Apr. 25, 2018), 163 FERC ] 61,041, at P 3 (2018).
---------------------------------------------------------------------------

    166. As discussed above, we believe that, under the AAR
requirements adopted in this final rule, transmission providers will
implement AARs with sufficient forecast margins in forward periods such
that instances of reductions in transfer capability in real time and
the related operational challenges will be infrequent. Accordingly, we
anticipate that transfer capability will typically be freed up as
forecasts become more certain (and require smaller forecast margins)
from forward periods to actual operation, which will typically result
in additional transmission being made available as we approach real
time, and this will create some uplift. But we find this is the result
of the policies that are needed to ensure transmission line ratings are
sufficiently accurate to produce just and reasonable wholesale rates,
and that any resulting uplift is, therefore, appropriate. Additionally,
however, we acknowledge that transmission providers might also
implement unreasonably high ambient air temperature forecast margins.
In such instances, such unreasonably high forecast margins would need
to be adjusted to ensure transmission line ratings are accurate.
    167. We clarify that this final rule does not prohibit transmission
providers from utilizing AARs that are calculated on a more frequent
basis than hourly. Relatedly, in response to comments from PJM, we
clarify that nothing in this final rule prevents a transmission
provider from utilizing a transmission line rating calculated in
between whatever standard AAR calculation period is established.
    168. Turning to the hourly resolution (as opposed to the hourly
frequency of calculation) of AARs, we adopt the NOPR proposal to
require that AARs ``appl[y] to a time period of not greater than one
hour'' because we find such a policy strikes an appropriate balance
between providing sufficient granularity to transmission line ratings
to reflect meaningful predictable changes in ambient air temperature
across each day, and not overburdening transmission providers.\389\
These changes are different from changes in ambient air temperatures
discussed above, which are changes in forecasts due to improved
information as a time period moves closer to real time as time
advances.
---------------------------------------------------------------------------

    \389\ Pro Forma OATT attach. M, AAR Definition.
---------------------------------------------------------------------------

    169. We find that ambient air temperatures typically vary
sufficiently across the day to produce meaningful differences in hourly
transmission line ratings. For example, we expect temperatures during
morning or evening hours to typically be significantly different than
the noon temperature. Recognizing such temperature differences through
transmission line ratings may be particularly important, since
increasingly systems are being challenged during such morning or
evening hours due to ramp or peak net load challenges. We find that
hourly AAR calculations will create important additional operational
flexibility for operators and more accurate transmission line ratings.
And because we expect the AAR process to be largely automated, we do
not believe that the requirement for hourly AARs will be significantly
more burdensome than a less granular requirement (e.g., a requirement
that AARs apply to a time period of not greater than one day). In any
event, we clarify that this final rule does not preclude a transmission
provider from implementing AARs on a more granular basis than hourly,
such as the 15-minute basis suggested by ISO-NE with respect to its
coordinated transaction scheduling.
c. AAR Coordination
i. Comments
    170. Several commenters argue that further consideration is needed
on AAR implementation in certain circumstances.\390\ For example, while
not supporting or opposing an AAR mandate, NERC stresses the importance
of reliability, explaining that reliability of the transmission system
depends upon the proper coordination of transmission line ratings,\391\
and states that special attention must be paid to reliability
considerations in the implementation of any reforms in this
proceeding.\392\ Specifically, NERC notes that the Commission should
consider whether to require transmission

providers to coordinate AAR implementation methods since temperature
readings and methodologies may differ on tie lines, and which
transmission line rating should be used in the event of a disagreement
among entities receiving transmission line ratings or
methodologies.\393\
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    \390\ NERC Comments at 6-7; EEI Comments at 14-15; NYTOs
Comments at 7; CAISO Comments at 12-13.
    \391\ NERC Comments at 4.
    \392\ Id.
    \393\ Id. at 6-7.
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    171. EEI asserts that the NOPR proposal was unclear about how AARs
on transmission lines across seams should be determined, where
transmission line ratings could be subject to assumptions from two
different transmission providers, and how AAR compliance could be
determined for non-jurisdictional transmission facilities. EEI urges
flexibility on seams issues and for the Commission to enforce
reciprocity conditions for non-jurisdictional entities, should the
Commission require targeted AAR implementation.\394\ IID also
encourages the Commission to consider seams issues that may need to be
addressed if AARs are different among neighboring utilities.\395\ MISO
Transmission Owners similarly state that ATC calculations on joint
flowgates and tie lines between RTOs/ISOs will require coordination
among all parties each time a transmission line rating changes,
increasing the level of communication necessary. According to MISO
Transmission Owners, along these joint flowgates and tie lines,
transmission owners and RTOs/ISOs will need to decide which forecast
will govern and whether to use multiple weather forecasts.\396\
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    \394\ EEI Comments at 14-15.
    \395\ IID Comments at 6-7.
    \396\ MISO Transmission Owners Comments at 32-33.
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ii. Commission Determination
    172. We agree with NERC's comments stressing the importance of
reliability and reiterate that system safety and reliability are
paramount to the requirements for transmission line ratings that we
adopt in this final rule. We agree with NERC and other commenters that
implementation of AAR requirements on tie lines may necessitate
increased communication among neighboring transmission providers and
relevant transmission owners. While we expect that parties will work
collaboratively to ensure that appropriate ratings are determined for
each tie line, we decline to adopt specific requirements for
coordinating AAR implementation across transmission provider seams.
Parties along these seams have a long history of working
collaboratively to ensure the reliable implementation of transmission
facility ratings and we are not persuaded that specific requirements
for coordination are required at this time. Moreover, we note that, in
the event of a disagreement over the appropriate facility rating, the
NERC Reliability Standards already establish a framework for how
entities should proceed, i.e., that the system should be operated to
the most limiting parameter.\397\ However, as described further in
Section IV.G.3.b, to ensure that transmission providers have adequate
transparency into the transmission line ratings methodologies of their
neighbors, we require transmission providers to share transmission line
ratings and transmission line rating methodologies with other
transmission providers, upon request.
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    \397\ Reliability Standard TOP-001-5, Requirement R 18, p. 7,
https://www.nerc.com/pa/Stand/Reliability%20Standards/TOP-001-5.pdf.
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    173. In response to EEI and NERC, we further clarify that, to the
extent there is a disagreement among entities about the calculated AAR,
transmission providers should use the most limiting AAR in order to
ensure reliability and that thermal limits are respected. As IID
suggests, however, if the most limiting AAR along a mutual seam is
based on one transmission provider's ambient air temperature
assumptions that are more risk averse than another transmission
provider's ambient air temperature assumptions, the inevitable result
will be increased congestion between control areas. While using the
more risk averse transmission line rating may result in an increase in
congestion relative to the alternative of using a lower forecasted
ambient air temperature, we do not, in this final rule, revise each
transmission provider's authority to set the transmission line ratings
within its control area.
    174. In response to EEI's request for clarification on the
applicability of the AAR requirements to non-jurisdictional entities,
we note that the Commission's pro forma OATT requirements apply only to
Commission-jurisdictional transmission providers. However, to the
extent non-jurisdictional entities have reciprocity tariffs on file
with the Commission, such reciprocity tariffs will need to implement
pro forma OATT Attachment M adopted herein in order to satisfy the
Commission's comparability (non-discrimination) standards established
in Order No. 888.
d. Applicability of AARs to Transmission Loading Relief (TLR) Events
i. NOPR Proposal
    175. In the NOPR, the Commission proposed to require transmission
providers to use AARs as the relevant transmission line rating 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 necessary because of a reduction in transfer
capability anticipated to occur (start and end) within the next 10
days. The Commission also proposed to require transmission providers to
use AARs as the relevant transmission line rating when determining
whether to curtail network transmission service or secondary service
(under section 33 of the pro forma OATT) or redispatch network
transmission service or secondary 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.\398\
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    \398\ NOPR, 173 FERC ] 61,165 at PP 87, 89, 90.
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ii. Comments
    176. MISO states that the Commission should clarify that use of
AARs in congestion management should not discriminate based on the type
of flows being curtailed, be it transmission service or market flow, as
some processes, such as the interregional TLR process, differentiate
between the types of flow.\399\
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    \399\ MISO Comments at 8.
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iii. Commission Determination
    177. We clarify that AARs should not discriminate based on the type
of flows being curtailed, interrupted, or redispatched. Accordingly, we
modify certain aspects of pro forma OATT Attachment M, as proposed in
the NOPR, to clarify that AARs must be used as the relevant
transmission line rating when determining whether to initiate TLR
procedures anticipated to occur (start and end) within the next 10
days. We note that TLR procedures occur pursuant to the curtailment,
interruption, and/or redispatch procedures outlined in pro forma OATT
sections 13.6, 14.7, 30.5, and/or 33, which are also referenced in pro
forma OATT Attachment M, as proposed in the NOPR, as requiring the use
of AARs as the relevant transmission line rating.

In these instances, we find that proposed pro forma OATT Attachment M
is already sufficiently clear: AARs must be used as the relevant
transmission line rating when determining whether to initiate TLR
procedures anticipated to occur (start and end) within the next 10
days. However, because pro forma OATT Attachment M, as proposed in the
NOPR, only referenced curtailment and interruption procedures that
occur pursuant to pro forma OATT section 14.7, for clarity, we modify
the proposed pro forma OATT Attachment M to also reference curtailment
and interruption procedures that occur pursuant to pro forma OATT
section 13.6.
e. Communication and Verification of AARs
i. Comments
    178. With regard to the Commission's NOPR proposal that AAR data be
submitted by the transmission owner to the RTO/ISO through Supervisory
Control and Data Acquisition (SCADA) or related systems, MISO states
that it strongly urges the Commission not to require any specific data
communication medium due to rapid and frequent changes in technology.
MISO emphasizes that the scale and scope of AARs as proposed in the
NOPR would require electronic and programmatic updates to the RTO/ISO,
and using manual communication methods, such as phone calls or written
messaging, would not be practical. MISO adds that the requirements to
coordinate data interchange for reliability are currently regulated by
the NERC Reliability Standards.\400\ CAISO states that a fundamental
challenge will be to ensure entities can transmit forecasted AARs in a
timely manner.\401\ As a result of this challenge, CAISO requests
clarification on what to do in cases of communication failure between
the transmission owner and the RTO's/ISO's EMS and what an RTO/ISO
should do if a transmission owner submits an incorrect transmission
line rating.\402\ NYISO clarifies that it receives updates of
transmission line ratings from asset owners via the Inter-Control
Center Communication Protocol.\403\ NYTOs explain that, since AARs and
DLRs are constantly changing, independent software validation solutions
will be needed to avoid violating NERC Reliability Standard FAC-008,
which would occur when there is any accidental discrepancy between a
calculated transmission line rating and the transmission line rating
methodology.\404\
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    \400\ MISO Comments at 15-16.
    \401\ CAISO Comments at 4-5.
    \402\ Id. at 12-13.
    \403\ NYISO Comments at 4.
    \404\ NYTOs Comments at 7.
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ii. Commission Determination
    179. In response to comments requesting that the Commission not
dictate communication mediums for transmission owners submitting AARs
to RTOs/ISOs, we clarify that this final rule requires that electronic
transmission line rating data be submitted by transmission owners
directly into an RTO's/ISO's EMS through SCADA or similar communication
systems. We clarify that other electronic systems, such as Inter-
Control Center Communication Protocol, can be used to comply with this
requirement, and RTOs/ISOs may propose to use such systems on
compliance.
    180. In response to concerns about potential scarcity of
temperature data and/or AAR communication failures, we modify the NOPR
proposal to require that, if an AAR otherwise required to be used under
pro forma OATT Attachment M is unavailable, the transmission provider
must use the relevant seasonal line rating as the appropriate
transmission line rating. This requirement does not relieve any
transmission provider of the obligation in the first instance to
provide an AAR but provides an alternate only if an AAR otherwise
required under pro forma OATT Attachment M is not available. Further,
while this provision establishes the seasonal line rating as the
default recourse rating, the transmission provider retains the ability
under the ``System Reliability'' section of pro forma OATT Attachment M
to use a different recourse rating where the transmission provider
reasonably determines such a rating is necessary to ensure the safety
and reliability of the transmission system.
    181. In response to NYTOs' comments that changing transmission line
ratings will necessitate additional transmission line rating validation
tools, we reiterate that the definitions of Transmission Line Rating,
AARs, and Seasonal Line Rating we adopt in this final rule--as set
forth in pro forma OATT Attachment M--require computation of
transmission line ratings in accordance with good utility practice,
including up-to-date forecasts, to ensure the accuracy of the relevant
transmission line rating.\405\ And as NYTOs note, inaccurate
transmission line ratings or a discrepancy between transmission line
ratings and the transmission line rating methodology could trigger a
violation of NERC Reliability Standard FAC-008 by the relevant
transmission owner. In other words, pro forma OATT Attachment M imposes
an affirmative obligation on transmission providers to implement
accurate transmission line ratings and the NERC Reliability Standards
similarly require accuracy in transmission line ratings by the
transmission owners that calculate such ratings. In RTOs/ISOs, where
the transmission provider (i.e., the RTO/ISO) must rely on its
transmission owners to calculate and provide the required transmission
line ratings, we acknowledge that there might be some increased
complexity in ensuring the accuracy of the transmission line ratings.
However, we do not prescribe the method for a transmission provider--
including an RTO/ISO--to screen for issues with transmission line
ratings,\406\ instead leaving it up to the transmission provider to
develop a general validation system that ensures its compliance with
the requirements of this final rule and relevant NERC Reliability
Standards. We agree with MISO that it is unable--and indeed is not
required--to audit transmission line ratings; \407\ rather, the type of
validation that we reference here would be akin to the automated
validation referenced by CAISO, SPP, and PJM,\408\ where the RTO/ISO
runs checks for obvious signs of data errors or corruption.
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    \405\ Pro Forma OATT attach. M, AAR Definition.
    \406\ For example, a transmission provider might consider
screening for such issues as: Missing data; significant changes in
transmission line ratings; illogical data (such as ratings that
increase with increasing temperature, or daytime ratings that are
higher than nighttime ratings); and transmission line ratings
outside feasible ranges for particular transmission lines.
    \407\ MISO Comments at 27.
    \408\ PJM Comments at 8; CAISO Comments at 13; SPP Comments at
5-6. We note that, according to the MISO Transmission Owners'
Agreement (TOA), MISO also has a responsibility to verify
transmission line ratings. MISO, Open Access Transmission, Energy
and Operating Reserve Markets Tariff, Rate Schedule 1, Appendix B,
Section V (30.0.0) (``Each Owner shall file with MISO information
regarding the physical ratings of all of its equipment in the
Transmission System. This information is intended to reflect the
normal and emergency ratings routinely used in regional load flow
and stability analyses. In carrying out its responsibilities, MISO
shall apply ratings that have been provided by the respective Owners
and have been verified and accepted as appropriate by MISO where
such ratings affect MISO reliability.'').
---------------------------------------------------------------------------

    182. In response to CAISO's request for clarification on what an
RTO/ISO should do if a transmission owner submits an incorrect
transmission line rating, we do not require RTOs/ISOs to audit or
recalculate transmission line ratings submitted to them (except in
instances where their procedures provide for them to calculate

transmission line ratings, such as for RTOs/ISOs that calculate AARs
from tables or databases). To the extent any transmission provider
becomes aware of an apparent inaccurate transmission line rating, the
transmission provider is expected to inform the transmission owner
immediately and both the transmission provider and transmission owner
should take appropriate action to correct any inaccuracy. If the
transmission provider and transmission owner are unable to resolve the
inaccuracy of a submitted AAR, then, as discussed above, the
transmission provider must use an appropriate recourse rating until the
AAR inaccuracy is resolved. To the extent the transmission provider
and/or transmission owner is out of compliance with any applicable
requirements, they should report such noncompliance as dictated by the
applicable requirement.
f. Minimum AAR Temperature Range and AAR Granularity
i. Comments
    183. Vistra contends that the Commission should provide guidance on
the range and granularity of temperatures to be used in AARs.\409\
Vistra argues that the Commission's AAR policy will be undermined if
implementation decisions reintroduce unnecessary conservativism (such
as only altering AARs for every 20 degrees Fahrenheit of ambient air
temperature, or developing AARs for only a limited range of ambient air
temperatures).\410\ Vistra suggests that it would not be unreasonable
for AARs to change for every one or two degrees Fahrenheit change in
ambient air temperature, and that AARs be calculated for a range of
temperatures that cover the historical low and historical high