temperature plus some margin (e.g., 10 degrees).\411\ Vistra argues
that recent extreme temperature events illustrate that temperatures can
exceed historical levels with important reliability implications.\412\
---------------------------------------------------------------------------

    \409\ Vistra Comments at 6-7.
    \410\ Id. at 6.
    \411\ Id. at 6-7.
    \412\ Id. at 7.
---------------------------------------------------------------------------

    184. ITC asserts that the Commission should adopt a transmission
line rating ``floor'' where no AAR would fall below the lowest seasonal
line rating and states that operational risk and planning issues
outweigh any benefit of exceeding such a floor given how rarely ambient
air temperatures exceed those associated with the lowest seasonal line
rating.\413\
---------------------------------------------------------------------------

    \413\ ITC Comments at 15-16.
---------------------------------------------------------------------------

ii. Commission Determination
    185. In response to Vistra's comments, we clarify that any methods
for determining AARs must be valid for at least the range of local
historical temperatures (over the entire period for which records are
available) plus or minus a margin of 10 degrees Fahrenheit, in order to
meet the pro forma OATT Attachment M requirement that an AAR reflect an
up-to-date forecast of ambient air temperature. For example, if the
historical range is -30 degrees Fahrenheit to 107 degrees Fahrenheit,
the valid range must be at least -40 degrees Fahrenheit to 117 degrees
Fahrenheit. Where a transmission provider uses pre-calculated AARs
within a look-up table or similar database, such values must be
calculated for all temperatures within such a valid range. Similarly,
where a transmission provider uses a formula or computer program to
calculate AARs based on forecasted temperatures, such a formula/program
must be accurate across such a valid range. Furthermore, transmission
providers must have procedures in place to handle a situation where
forecast temperatures fall outside of such a range of temperatures, to
ensure that safe and reliable transmission line ratings are used.
Finally, in the event that actual temperatures set new high or low
records, transmission providers are required to revise their look-up
tables/databases or formulas/programs, as necessary and within a timely
manner, to maintain the 10 degree Fahrenheit margin.
    186. We agree with Vistra's assertion that recent extreme
temperature events in California and Texas illustrate that temperatures
can exceed historical levels with significant economic and reliability
implications.\414\ The clarification that any methods for determining
AARs must be valid for at least the range of local historical
temperatures plus or minus a margin of 10 degrees Fahrenheit ensures
that, when such severe and unexpected weather events do occur,
transmission providers will be prepared and able to continue to
implement more accurate transmission line ratings.
---------------------------------------------------------------------------

    \414\ Vistra Comments at 6-7.
---------------------------------------------------------------------------

    187. With respect to the requirement for AARs to reflects an up-to-
date forecast of ambient air temperatures, as Vistra points out, absent
clarification, some implementations of AARs may not result in an AAR
change with every change in forecasted temperature (e.g.,
implementations that use pre-calculated look-up tables or databases,
where AARs do not change within each temperature ``step''). For this
reason, we clarify that a transmission provider must implement AARs
that update at least with every five degree Fahrenheit increment of
temperature change, in order to meet the pro forma OATT Attachment M
requirement that an AAR reflect an up-to-date forecast of ambient air
temperature. For example, an AAR is not consistent with the
requirements of pro forma OATT Attachment M if it results in
transmission line ratings that do not change when temperature forecasts
increase or decrease by five degrees Fahrenheit. This clarification is
consistent with ERCOT's AAR implementation, which utilizes AAR look-up
tables that define AARs in five-degree Fahrenheit steps.\415\ We find
that larger steps may introduce inaccuracies into transmission line
ratings, resulting in wholesale rates that are unjust and unreasonable.
Moreover, as Vistra suggests, a minimum amount of AAR temperature
granularity is necessary to ensure that transmission line ratings
sufficiently reflect changes in ambient air temperatures.\416\
---------------------------------------------------------------------------

    \415\ Commission Staff Paper at 7.
    \416\ Vistra Comments at 6-7.
---------------------------------------------------------------------------

    188. We decline to require a transmission line rating ``floor''
whereby no AAR would fall below the lowest seasonal line rating, as
requested by ITC. Seasonal line ratings are generally already
calculated to reflect worst-case weather conditions. However, to the
extent that a transmission provider experiences extreme temperatures
that exceed seasonal assumptions, the resulting transmission line
ratings will be more accurate than seasonal line ratings and will send
important price signals to market participants. In such circumstances,
transmission providers should be able to plan for such extreme
temperatures given current temperature forecasting capabilities.
g. AAR Liabilities
i. Comments
    189. Transmission owners also discuss and request protection from
liabilities, which might result from AAR implementation. For example,
explaining that using AARs in the day-ahead and/or real-time market may
result in different congestion patterns than were anticipated, MISO
Transmission Owners argue that transmission owners should not be
responsible for any resulting uplift or for any impacts on the value of
financial transmission rights (FTR) or the value of other market
trades, uplift costs, or other losses resulting from the

implementation of AARs. MISO Transmission Owners also contend that the
Commission should absolve transmission owners from tariff violations
resulting from last minute transmission line rating changes to protect
public safety.\417\
---------------------------------------------------------------------------

    \417\ MISO Transmission Owners Comments at 18-21.
---------------------------------------------------------------------------

    190. Some commenters discuss the implications of the proposed pro
forma OATT Attachment M for the FTR markets.\418\ MISO and EEI also
urge liability protections, explaining that absent liability
protections, RTOs/ISOs and their members could be subject to liability
if the weather is predicted incorrectly. MISO and EEI explain that
implementing AARs in the day-ahead market could result in differences
between the transmission line ratings used in FTR markets, and thereby
impact the value of congestion rights. MISO and EEI further explain
that if weather shifts unexpectedly, reliance on AARs could result in
too much or too little being committed in the day-ahead market, causing
financial impacts. MISO and EEI state that potential liability could
also arise from possible reliability events for which it is
subsequently determined that a more conservative transmission line
rating could have prevented.\419\ Explaining that in CAISO's congestion
revenue rights (CRR) market ratepayers can be exposed to substantial
losses after they become the CRR counterparty in the event some CRR
auction capacity is left unpurchased, the CAISO DMM argues that
transmission line ratings used in CRR auction models should still be
the most conservative limits for those transmission lines instead of
any higher limit enabled through hourly transmission line ratings.\420\
The SPP MMU suggests that the implementation of AARs and DLRs should be
coincident with an annual transmission congestion rights (TCR) auction,
or the status of implementation should be clearly communicated to
auction participants.\421\
---------------------------------------------------------------------------

    \418\ MISO Comments at 21; EEI Comments at 12; CAISO DMM
Comments at 3-4, 8-9; SPP MMU Comments at 11.
    \419\ MISO Comments at 21; EEI Comments at 12.
    \420\ CAISO DMM Comments at 3-4, 8-9.
    \421\ SPP MMU Comments at 11.
---------------------------------------------------------------------------

    191. ITC also asks that the Commission clarify that transmission
owners will not be liable for any market inefficiencies that arise from
inaccurate transmission line ratings, provided the transmission line
ratings are communicated to the transmission provider in good
faith.\422\
---------------------------------------------------------------------------

    \422\ ITC Comments at 3.
---------------------------------------------------------------------------

ii. Commission Determination
    192. We decline to provide explicit liability protections related
to AAR implementation, as requested by commenters. We are not persuaded
that this final rule's AAR reforms introduce additional liabilities
that do not already exist. To the extent there are liability concerns
associated with transmission line ratings changing in real time, these
concerns already exist today as RTOs/ISOs forecast load and asset
owners forecast renewable energy availability in real time. Moreover,
FTR auctions, like all forward planning activities, already make a
variety of forward assumptions about transmission availability that do
not necessarily materialize in real-time operations. As the Commission
stated in the NOPR, RTOs/ISOs already periodically request, and
transmission owners periodically provide, ad hoc transmission line
rating changes based on differences between actual and assumed ambient
air temperatures.\423\ In those cases, as long as utilities operate in
a manner consistent with good utility practice, blanket liability
protection is not necessary. Nevertheless, we note that transmission
providers could submit filings pursuant to FPA section 205 to the
Commission to propose revised liability protections in their tariffs to
the extent they believe such protections are warranted.
---------------------------------------------------------------------------

    \423\ NOPR, 173 FERC ] 61,165 at P 107.
---------------------------------------------------------------------------

C. Seasonal Line Ratings

1. Seasonal Line Ratings Requirements
a. NOPR Proposal
    193. In the NOPR, the Commission proposed to require transmission
providers to use seasonal line ratings when evaluating requests for
other (longer-term) point-to-point transmission service, i.e., requests
for point-to-point transmission service ending more than 10 days from
the date of the request. Specifically, the Commission proposed to
require transmission providers to use seasonal line ratings as the
relevant transmission line ratings when: (1) Evaluating requests for
longer-term point-to-point transmission service; (2) responding to
requests for information on the availability of such longer-term point-
to-point transmission service (including requests for ATC or other
information related to such potential service); and (3) posting ATC or
other information related to such longer-term point-to-point
transmission service to their OASIS site.
    194. For network transmission service, the Commission proposed to
require transmission providers to evaluate requests to designate
network resources (under section 30 of the pro forma OATT) or network
load (under section 31 of the pro forma OATT) based on seasonal line
ratings because the Commission found that such designations are
generally long-term requests and seasonal line ratings better reflect
conditions over a longer term than AARs.
    195. The Commission further proposed to require transmission
providers to use seasonal line ratings as the relevant transmission
line ratings when determining whether to curtail or interrupt point-to-
point transmission service (under section 14.7 of the pro forma OATT)
in situations other than those in which 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 similarly proposed to require transmission providers to use
seasonal line ratings as the relevant transmission line rating for
determining the necessity of curtailment or redispatch of network
transmission service or secondary service in situations other than
those in which such curtailment or redispatch is necessary because of a
reduction in transfer capability anticipated to occur within the next
10 days.\424\
---------------------------------------------------------------------------

    \424\ Id. PP 88, 90.
---------------------------------------------------------------------------

b. Comments
    196. Some commenters support \425\ and others generally do not
oppose the Commission's NOPR proposal to require transmission providers
to use seasonal line ratings for transmission service requests and for
curtailments, interruptions, and redispatch beyond the 10-day
threshold. Some commenters argue that the Commission should go further
by requiring that seasonal line ratings be used in transmission
planning \426\ and/or that more granular alternatives be used when
examining transmission service involving wind resources.\427\ CAISO and
ISO-NE note that summer and winter seasonal line ratings are already
used by transmission owners in their respective regions.\428\ On the
other hand, MISO Transmission Owners contend that the Commission should
require seasonal line ratings in long-term transmission operations and
planning only when it is beneficial to do

so.\429\ Similarly, Entergy argues that the Commission should not
mandate the use of seasonal line ratings, explaining that it does not
use seasonal line ratings, and that, instead, it uses AARs on a one-
day, two-day, or hourly basis because AARs are more accurate. Entergy
claims that maximum monthly temperatures in its service territory do
not differ significantly enough for seasonal line ratings to create any
value and therefore requirements to calculate seasonal line ratings
would result in increased costs without commensurate benefits.\430\
---------------------------------------------------------------------------

    \425\ See, e.g., AEP Comments at 1; EDFR Comments at 7.
    \426\ ACPA/SEIA Comments at 15-16.
    \427\ Clean Energy Parties Comments at 12.
    \428\ CAISO Comments at 3, ISO-NE Comments at 6.
    \429\ MISO Transmission Owners Comments at 17-18.
    \430\ Entergy Comments at 15.
---------------------------------------------------------------------------

    197. SPP requests clarification on whether the seasonal line rating
requirements are intended to apply to transmission service requests
longer than one year in duration.\431\
---------------------------------------------------------------------------

    \431\ SPP Comments at 7.
---------------------------------------------------------------------------

c. Commission Determination
    198. We adopt the Commission's proposal in the NOPR to require
transmission providers to use seasonal line ratings as the appropriate
transmission line ratings when: (1) Evaluating requests for
transmission service--including point-to-point, network, and secondary
service--ending more than 10 days from the date of the request; (2)
responding to requests for information on the availability of such
transmission service (including requests for ATC or other information
related to potential transmission service); and (3) posting
transmission availability (including ATC for point-to-point
transmission service requests) or other information related to
transmission service to their OASIS site.
    199. Additionally, we adopt the Commission's proposal in the NOPR
to require transmission providers to use seasonal line ratings as the
relevant transmission line ratings when determining whether to curtail
or interrupt non-firm point-to-point transmission service (under
section 14.7 of the pro forma OATT) in situations other than those in
which such curtailment or interruption is necessary because of issues
related to flow limits on transmission lines anticipated to occur
(start and end) within the next 10 days. We also require transmission
providers to use seasonal line ratings when determining whether to
curtail or interrupt firm point-to-point transmission service under
section 13.6 of the pro forma OATT in such situations.
    200. We also adopt the NOPR proposal to require seasonal line
ratings be used as the relevant transmission line rating for
determining the necessity of curtailment (under section 33 of the pro
forma OATT) or redispatch (under sections 30.5 and/or 33 of the pro
forma OATT) of network or secondary service in situations other than
those in which such curtailment or redispatch is necessary because of
issues related to flow limits on transmission lines anticipated to
occur within the next 10 days. We continue to find that seasonal line
ratings are the appropriate transmission line rating for evaluations of
longer-term transmission service requests because ambient air
temperature forecasts for such future periods have more uncertainty
than near-term forecasts, and thus tend to converge to the longer-term
ambient air temperature forecasts used in seasonal line ratings. The
requirements for seasonal line ratings we adopt in this section are set
forth under ``Obligations of Transmission Provider'' in pro forma OATT
Attachment M.
    201. In response to arguments from MISO Transmission Owners and
Entergy that the Commission should not require seasonal line ratings or
should do so only on a limited basis, we find that seasonal line
ratings are needed to ensure that transmission line ratings used for
evaluating requests for longer-term transmission service are accurate
and result in just and reasonable wholesale rates. In response to
Entergy's comment regarding its use of AARs instead of seasonal line
ratings because AARs are more accurate, the seasonal line ratings
requirements adopted herein do not prevent Entergy from using AARs for
near-term transmission service, and in fact we require AARs to be used
for near-term transmission service. Seasonal line ratings are only
required to be used for longer-term transmission service. Entergy also
claims that its maximum temperatures do not vary sufficiently across
the year for seasonal line ratings to provide value. We find that, in
general, temperatures vary sufficiently across seasons of the year for
seasonal line ratings to provide value. We also find that the burden of
implementing seasonal line ratings is particularly low.
    202. In response to SPP's comments, we clarify that the
requirements for seasonal line rating implementation do apply to
transmission service requests longer than one year in duration. To the
extent SPP's comments reflect any confusion about how to apply seasonal
line ratings to service longer than a season, we clarify that such
requests should be approved or denied (or availability should be
determined) based on whether the requested service can be accommodated
in each season (given the applicable seasonal line ratings).
    203. We decline to adopt ACPA/SEIA's suggestion that seasonal line
ratings should be required for transmission planning. Such a
requirement is beyond the scope of this rulemaking, which is focused on
remedying unjust and unreasonable wholesale rates resulting from
inaccurate transmission line rating assumptions used in requests for
transmission service and in transmission operations. We note that the
Commission recently initiated a proceeding to examine a broad range of
transmission-related issues, including regional transmission planning,
in its July 2021 Advance Notice of Proposed Rulemaking in Docket No.
RM21-17-000.\432\
---------------------------------------------------------------------------

    \432\ Building for the Future Through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, 86 FR 40266 (July 27, 2021), 176 FERC ] 61,024
(2021).
---------------------------------------------------------------------------

2. Seasonal Line Rating Implementation Requirements
a. NOPR Proposal
    204. In the NOPR, the Commission proposed to define a seasonal line
rating in pro forma OATT Attachment M as ``a transmission line rating
that: (a) Applies to a specified season, where seasons are defined by
the transmission provider to not include more than three months in each
season; (b) reflects an up-to-date forecast of ambient air temperature
across the relevant season over which the rating applies; and (c) is
calculated monthly, if not more frequently, for each season in the
future for which transmission service can be requested.'' \433\
---------------------------------------------------------------------------

    \433\ Proposed pro forma OATT attach. M, Seasonal Line Rating
definition.
---------------------------------------------------------------------------

b. Comments
    205. Many entities comment on the Commission's NOPR proposal to
define ``seasonal line rating'' as a season which includes no more than
three months. These entities predominately request flexibility for
transmission providers to define seasonal line ratings in a manner
appropriate to their climate.\434\ For example, NRECA/LPPC contend that
seasons do not fall into neat three-month windows and that shoulder
months on either side of the summer season may resemble summer
conditions more than fall or spring. For this reason, NRECA/LPPC
recommend that the definition of seasonal line

ratings be revised to accommodate regional considerations.\435\ MISO
Transmission Owners argue that the Commission should not require
seasonal line rating durations to be limited to no more than three
months because weather patterns vary widely.\436\
---------------------------------------------------------------------------

    \434\ NRECA/LPPC Comments at 23-24; MISO Transmission Owners
Comments at 18; Entergy Comments at 15; SPP Comments at 8; EEI
Comments at 9; ITC Comments at 9-10; MISO Comments at 20-21; SDG&E
Comments at 3.
    \435\ NRECA/LPPC Comments at 23-24.
    \436\ MISO Transmission Owners Comments at 18.
---------------------------------------------------------------------------

    206. Duke Energy similarly states that temperatures in its Florida
service territory do not differ enough to justify seasonal line
ratings. Duke Energy also argues that, at a minimum, the Commission
should clarify that one seasonal line rating set may have transmission
line ratings equal to another seasonal line rating set, as long as the
transmission line ratings are consistent with historically observed
and/or expected weather patterns.\437\ MISO states that requiring
seasonal line ratings to be unique from season to season may introduce
arbitrary differences in seasonal line ratings.\438\
---------------------------------------------------------------------------

    \437\ Duke Energy Comments at 12.
    \438\ MISO Comments at 20-21.
---------------------------------------------------------------------------

    207. ITC also asserts that the Commission should allow transmission
owners to determine the number and length of seasons in their service
territory so that seasonal line rating definitions may recognize
differences in regional climates.\439\ PacifiCorp states that it
currently only uses summer and winter ratings and that implementation
of the proposed three month seasonal requirements would require
substantial expansion to its Weak Link databases.\440\ PacifiCorp
further states that firm contractual commitments may need to be
reexamined and remedied if previously granted levels of transmission
service cannot be honored under this seasonal line ratings
construct.\441\
---------------------------------------------------------------------------

    \439\ ITC Comments at 9-10.
    \440\ PacifiCorp Comments at 3.
    \441\ Id. at 7.
---------------------------------------------------------------------------

    208. SPP notes that the three-month season duration conflicts with
the four-month season length established by SPP's stakeholders.\442\
---------------------------------------------------------------------------

    \442\ SPP Comments at 8.
---------------------------------------------------------------------------

    209. Other commenters question the proposed requirement for a
``seasonal line rating'' to ``forecast'' ambient air temperatures
across the relevant season. SDG&E, for example, questions the value of
basing seasonal line ratings for future seasons on weather forecast
data, stating that such data is statistically insignificant that far
into the future and instead suggests basing seasonal line ratings on
historical weather data, specifically a 12-month, static data set per
calendar month.\443\ MISO Transmission Owners also state that the NOPR
proposal would require seasonal line ratings to be based on forecasts,
not historical data, as is currently used to develop seasonal line
ratings.\444\ MISO strongly urges the Commission to allow seasonal line
ratings to be established based on historical data rather than
forecasts because historical temperature data is known and thus more
reliable than predictions. MISO contends that using forecast data would
risk greater certainty.\445\
---------------------------------------------------------------------------

    \443\ SDG&E Comments at 3.
    \444\ MISO Transmission Owners Comments at 34.
    \445\ MISO Comments at 21.
---------------------------------------------------------------------------

    210. Finally, some commenters protest the proposed requirement for
seasonal line ratings to be ``calculated monthly, if not more
frequently, for each season in the future for which transmission
service can be requested.'' Multiple commenters argue that this monthly
updating requirement provides little value or can cause additional
problems.\446\ ITC argues that monthly updates to seasonal line ratings
could cause significant uncertainty in planning processes and requests
that the Commission instead only require seasonal line ratings be
calculated for the duration of a single season.\447\ Exelon explains
that it does not update seasonal line ratings monthly, that its
seasonal line ratings use historical temperatures to make assumptions
on future maximum temperatures, and that those assumptions typically do
not change. Exelon contends that there would not be any value in
regularly reassessing seasonal line rating assumptions and instead
suggests the following revision to the proposed definition of seasonal
line rating: ``reflects a forecast of ambient air temperatures across
the relevant season over which the rating applies.'' \448\ MISO, on the
other hand, contends that seasonal line ratings, once established,
should be reviewed when equipment changes are made, climate or weather
data necessitates, or when otherwise prudent.\449\
---------------------------------------------------------------------------

    \446\ Exelon Comments at 12-13; EEI Comments at 8-9; ITC
Comments at 11; SDG&E Comments at 3.
    \447\ ITC Comments at 11.
    \448\ Exelon Comments at 12-13.
    \449\ MISO Comments at 21.
---------------------------------------------------------------------------

c. Commission Determination
    211. In response to comments requesting that the Commission provide
flexibility for seasonal line ratings to cover periods greater than
three months, we modify the Commission's proposed requirement in the
NOPR for how transmission providers define seasons, to provide
additional flexibility. Specifically, rather than prohibiting
transmission providers from including more than three months in each
season, we instead require that transmission providers define seasons
to include not fewer than four seasons in each year, and to reasonably
reflect portions of the year where expected high temperatures are
relatively consistent. Seasonal line ratings typically encompass six
months. Six-month seasonal line ratings, however, necessarily require a
worst-case weather representation specific to a specific month to be
applied to every other month. In that context, ``summer'' seasonal line
ratings could be, and often are, applied to the months of May through
October despite the average historic high temperature in October, in
much of the country, being considerably different than July's average
historic high temperature. Moreover, ``winter'' seasonal line ratings
could be, and often are, applied to the months of November through
April despite the average historic high temperature in April, in much
of the country, being considerably different than January's average
historic high temperature. As with AARs, using unrealistic temperature
assumptions will result in inaccurate seasonal line ratings, and, in
turn, unjust and unreasonable wholesale rates.
    212. However, we clarify that a transmission provider may define
seasons shorter than three months, and/or have more than four seasons
for its seasonal line rating program. For example, if a transmission
provider found through its analysis that its system had a five-month
``summer'' period that was characterized by a consistent high
temperature, that transmission provider could accommodate such a period
by defining a three-month Summer 1 season, and a two-month Summer 2
season, and independently determining the seasonal line ratings (based
on an independent analysis of temperatures) for each season. We further
clarify, in response to comments from MISO, Entergy, and Duke Energy,
that seasonal line ratings are not required to be arbitrarily different
between seasons. As long as such ratings are uniquely determined in
accordance with the relevant requirements, it is not prohibited for
seasonal line ratings to be the same across different seasons if the
independent analyses support those ratings, although we expect such
instances will be infrequent.
    213. In response to comments from PacifiCorp about the cost
associated with implementing seasonal line ratings with three-month
granularity, we appreciate that this three-month granularity
requirement represents some level of burden, but we believe that the
burden in most cases will be relatively low. Moreover, in cases such as

PacifiCorp describes, we believe that seasonal line ratings with a
three-month granularity represent a more accurate representation of
existing transfer capabilities and that using a more accurate
representation of existing transfer capabilities will require
transmission providers to more accurately examine the feasibility of
existing contracts.
    214. In doing so, our expectation is that, in at least certain
circumstances, transmission providers will find that certain existing
approved transmission service, accepted based on six-month winter
seasonal air temperature assumptions of 32 degrees Fahrenheit (or other
similar assumptions), are not able to be effectuated without
curtailment, interruption, and/or redispatch, given likely warmer
temperatures in shoulder periods falling within that six-month winter
season.
    215. In response to comments discussing the burden of calculating
seasonal line ratings monthly, we modify the definition of seasonal
line rating proposed in the NOPR to require that seasonal line ratings
be calculated ``annually, if not more frequently,'' rather than
``monthly, if not more frequently.'' We adopt the remainder of the
definition unchanged from the Commission's proposal in the NOPR. We
agree with MISO that seasonal line ratings, once established, should be
reviewed when equipment changes are made, climate or weather data
necessitates, or when otherwise prudent. However, we also agree with
commenters concerned about the burden of calculating monthly updates to
seasonal line ratings and are persuaded that the underlying weather
assumptions of seasonal line ratings are unlikely to change on a
monthly basis. We believe that a requirement for annual recalculations
of seasonal line ratings strikes an appropriate balance between
ensuring seasonal line ratings continue to be accurate as weather
patterns change,\450\ and the costs associated with updating such
transmission line ratings on a regular basis.
---------------------------------------------------------------------------

    \450\ ACPA/SEIA Comments at 8, 11; EPSA Comments at 4; New
England State Agencies Comments at 6.
---------------------------------------------------------------------------

    216. Finally, in response to comments that seasonal line ratings
should be allowed to be based on historical temperatures, rather than
forecasted temperature values, we clarify that seasonal line ratings
may be derived from historical temperatures. Seasonal line ratings are
an important input to longer-term sales for transmission service, and
in that context are inherently forward-looking, but, given the
challenges of forecasting future temperatures discussed in Section
IV.b.2.a, seasonal line ratings may be based on historical
temperatures, as long as such practices are consistent with good
utility practice and otherwise meet the requirements in pro forma OATT
Attachment M.

D. Exceptions and Alternate Ratings

1. NOPR Proposal
    217. In the NOPR, the Commission proposed to require the use of
AARs in many instances but allowed for the use of an alternative
transmission line rating when a transmission provider determines that a
transmission line is not affected by ambient air temperatures.
Specifically, the Commission stated that not all transmission line
ratings are affected by ambient air temperatures, either because the
technical transfer capability of the limiting conductors and/or
limiting transmission equipment is not dependent on ambient air
temperatures, or because the transmission line's transfer capability is
limited not by ambient air temperatures but by a transmission system
limit such as a system voltage or stability limit. For this reason, the
proposed language under the ``Exceptions'' paragraph of pro forma OATT
Attachment M accommodates such transmission lines without requiring
unwarranted calculations or updates. Attachment M provides that,
consistent with good utility practice, where the transmission provider
determines that a transmission line is not affected by ambient air
temperatures, the transmission provider may use a transmission line
rating for that transmission line that is not an AAR or seasonal line
rating.\451\
---------------------------------------------------------------------------

    \451\ NOPR, 173 FERC ] 61,165 at P 103.
---------------------------------------------------------------------------

    218. Additionally, the Commission proposed in the NOPR to include,
in pro forma OATT Attachment M under the ``System Reliability''
section, a reliability ``safety valve.'' This exception provides that,
if the transmission provider reasonably determines, consistent with
good utility practice, that the temporary use of a transmission line
rating different than would otherwise be required by pro forma OATT
Attachment M is necessary to ensure the safety and reliability of the
transmission system, then the transmission provider will use such an
alternate transmission line rating.\452\
---------------------------------------------------------------------------

    \452\ Proposed pro forma OATT attach. M, ``System Reliability''.
---------------------------------------------------------------------------

2. Comments
    219. Several commenters state that certain transmission elements,
such as underground cables, are not exposed to ambient air
temperatures, and thus should be exempt from the AAR requirements.\453\
For example, NYISO explains that many of its thermally limited
transmission elements are underground cables.\454\ While NYTOs note
that NYPA and Consolidated Edison have piloted the use of DLRs on
underground cables,\455\ NYISO and NYTOs explain that underground cable
ratings are typically the result of line-specific operating conditions
(e.g., thermal issues in the oil-filled pipe) and generally do not vary
with ambient air temperatures.\456\ For this reason, NYISO and NYTOs do
not support AAR implementation on underground cables.\457\ PJM and
Eversource similarly request an exception from the proposed AAR
requirements for underground cables, noting that their ratings are not
affected by ambient air temperatures.\458\
---------------------------------------------------------------------------

    \453\ See, e.g., NYISO Comments at 8-9; NYTOs Comments at 8; PJM
Comments at 6; LADWP Comments at 8.
    \454\ NYISO Comments at 8.
    \455\ NYTOs Comments at 4.
    \456\ NYISO Comments at 4; NYTOs Comments at 8.
    \457\ NYISO Comments at 8-9; NYTOs Comments at 8.
    \458\ PJM Comments at 6; Eversource Comments at 3.
---------------------------------------------------------------------------

    220. NYTOs and NRECA/LPPC contend that AARs may not be appropriate
on older transmission facilities.\459\ For example, NRECA/LPPC assert
that a transmission provider should be allowed to obtain a waiver from
the AAR requirements when implementation would be too difficult or
costly, noting that this may especially be the case for older
transmission facilities.\460\ Relatedly, EEI includes asset health as
one consideration that might be taken into account by transmission
owners in their recommendation for transmission owners to study AAR
implementation and propose candidate AAR transmission lines.\461\
---------------------------------------------------------------------------

    \459\ NYTOs Comments at 7; NRECA/LPPC Comments at 22.
    \460\ NRECA/LPPC Comments at 22.
    \461\ EEI Comments at 7.
---------------------------------------------------------------------------

    221. NRECA/LPPC contend that the AAR requirements should not apply
to transmission lines that are not part of the bulk electric system
operated above 100 kV.\462\ Entergy similarly contends that AARs should
not be required on facilities operated at or below 69 kV stating that
such facilities are more likely to include underbuilds, such as

third-party telecommunications facilities, and that, as a result, the
use of AARs on such facilities could have significant third-party
effects.\463\ EEI includes voltage levels as another consideration that
might be taken into account by transmission owners in their
recommendation for transmission owners to study AAR implementation and
propose candidate AAR transmission lines.\464\
---------------------------------------------------------------------------

    \462\ NRECA/LPPC Comments at 17.
    \463\ Entergy Comments at 10-11.
    \464\ EEI Comments at 7.
---------------------------------------------------------------------------

    222. LADWP requests flexibility in the implementation of AARs,
noting high wind speeds in California increase wildfire risk and that
it may be preferable to allow transmission line loadings to fall in
those circumstances.\465\ PG&E, in proposing criteria for determining
candidate transmission lines for AAR implementation, identifies
wildfire risk and transmission lines within high fire threat districts
as transmission lines that specifically may not be considered for AAR
implementation.\466\ EEI includes wildfire areas as another
consideration that might be taken into account by transmission owners
in its recommendation for transmission owners to study AAR
implementation and propose candidate AAR transmission lines.
---------------------------------------------------------------------------

    \465\ LADWP Comments at 6-7.
    \466\ PG&E Comments at 5.
---------------------------------------------------------------------------

    223. CAISO, SDG&E, and SCE also note challenges or the potential
inapplicability of AARs to certain transmission lines under remedial
action schemes.\467\ Given the challenges of applying AARs to remedial
action schemes designed to prevent thermal overload, CAISO requests
clarification on whether transmission lines whose thermal ratings
trigger remedial action schemes should be rated using AARs.\468\ SCE
explains that applying AARs to remedial action schemes, which are
facility-rating dependent, may adversely impact the protection scheme,
potentially increasing operational complexity, and could potentially
initiate a widespread chain of additional reliability considerations
that would require evaluation and potential mitigation.\469\ SDG&E also
explains that it has flow-based remedial action schemes which use
facility ratings to operate and are set to operate at a static value.
According to SDG&E, all of these characteristics will cause AARs to
yield no benefit to the monitored facilities and that removing this
limitation will increase the complexity of the remedial action
scheme.\470\
---------------------------------------------------------------------------

    \467\ SCE Comments at 4; SDG&E Comments at 4; CAISO Comments at
12-13.
    \468\ CAISO Comments at 12-13.
    \469\ SCE Comments at 4.
    \470\ SDG&E Comments at 4.
---------------------------------------------------------------------------

    224. ISO-NE and NYISO also discuss remedial action schemes.\471\
NYISO discusses corrective action plans, which create plans to respond
to contingencies, and voices concern that frequently updated
transmission line ratings, especially an update that lowers
transmission line ratings, would have a detrimental effect on
reliability should the system operating limits used to develop the
corrective action plan in planning studies not materialize in real
time.\472\ ISO-NE requests that transmission lines where the actions or
triggers of a remedial action scheme are based on a transmission line
rating be exempt from any AAR requirement, noting that use of AARs on
these transmission lines may require installing transmission system
upgrades.\473\
---------------------------------------------------------------------------

    \471\ NYISO Comments at 7-8; ISO-NE Comments at 9.
    \472\ NYISO Comments at 7-8.
    \473\ ISO-NE Comments at 9.
---------------------------------------------------------------------------

    225. Exelon and EEI support the NOPR's proposed exceptions but
request that the applicability of the exceptions be determined by the
transmission owner, not the transmission provider.\474\ Exelon contends
that because the NERC Reliability Standards give the transmission owner
responsibility for establishing transmission facility ratings, the
transmission owner should be the entity that decides when one or more
of the exceptions apply.\475\
---------------------------------------------------------------------------

    \474\ Exelon Comments at 2; EEI Comments at 6.
    \475\ Exelon Comments at 11.
---------------------------------------------------------------------------

    226. Finally, EPSA asks that transmission providers be required to
disclose (potentially via OASIS) which transmission lines they deem as
not benefitting from an AAR or seasonal line rating. EPSA also asks
that transmission providers be required to disclose the reasons for
making those determinations to thereby enable RTOs/ISOs and market
monitors to verify those decisions. Moreover, EPSA asks that these
decisions be evaluated at least every five years to ensure AAR-exempt
transmission lines should continue to qualify for exceptions.\476\
---------------------------------------------------------------------------

    \476\ EPSA Comments at 4.
---------------------------------------------------------------------------

3. Commission Determination
    227. As set forth in pro forma OATT Attachment M, we adopt the NOPR
proposal to allow exceptions to the AAR and seasonal line rating
requirements in instances where the transmission provider determines,
consistent with good utility practice, that the transmission line
rating of a transmission line is not affected by ambient air
temperatures.\477\ In this instance, the transmission provider may use
a transmission line rating for that transmission line that is not an
AAR or seasonal line rating. Examples of such a transmission line may
include (but are not limited to): (1) A transmission line for which the
technical transfer capability of the limiting conductors and/or
limiting transmission equipment is not dependent on ambient air
temperatures; or (2) a transmission line whose transfer capability is
limited by a transmission system limit (such as a system voltage or
stability limit) which is not dependent on ambient air temperatures. As
discussed in the NOPR, we adopt this exception because not all
transmission line ratings are affected by ambient air temperature,
either because the technical transfer capability of the limiting
conductors and/or limiting transmission equipment is not dependent on
ambient air temperature, or because the transmission line's transfer
capability is limited by a transmission system limit (such as a system
voltage or stability limit) which is not dependent on ambient air
temperature.\478\
---------------------------------------------------------------------------

    \477\ As discussed in Section IV.B.2.b, we clarify that
transmission owners, not transmission providers, are responsible for
calculating transmission line ratings. However, in the RTO/ISO
regions where there is a distinction between transmission owners and
transmission providers, we clarify that we expect RTOs/ISOs to
require their member transmission owners to make timely
determinations on transmission line rating exceptions, and to
provide them to the RTO/ISO. In such instances, 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 determinations
related to transmission line ratings exceptions.
    \478\ NOPR, 173 FERC ] 61,165 at P 103.
---------------------------------------------------------------------------

    228. We also adopt the NOPR proposal to establish a ``System
Reliability'' section in pro forma OATT Attachment M that will allow a
transmission provider to temporarily use a transmission line rating
different than would otherwise be required under pro forma OATT
Attachment M in instances when the transmission provider reasonably
determines, consistent with good utility practice, that the use of such
a temporary alternate rating is necessary to ensure the safety and
reliability of the transmission system.\479\ As discussed in

the NOPR, while we expect that such alternate transmission line rating
authority would be needed infrequently, if ever, we adopt the ``System
Reliability'' section of pro forma OATT Attachment M to resolve any
instance where a transmission provider reasonably believes that the
requirements for transmission line ratings conflict with system safety
or reliability.\480\
---------------------------------------------------------------------------

    \479\ Because the ``System Reliability'' section provides an
exception and does not establish a requirement, we change the verb
tense in this section to indicate that in such circumstances, the
transmission provider may use an alternate transmission line rating
rather than stating that the transmission provider ``will use'' an
alternate transmission line rating as was proposed in the NOPR.
    \480\ NOPR, 173 FERC ] 61,165 at P 97.
---------------------------------------------------------------------------

    229. We decline to adopt the further specific exceptions requested
by commenters. First, with respect to underground cables, as multiple
commenters note, the transfer limit of underground cables is generally
not affected by ambient air temperatures. Rather than adopting a
blanket exception for underground transmission lines, we note that
where the technical transfer limits of such cables are not affected by
ambient air temperatures, they would satisfy the exception for
instances in which the transmission line rating of a transmission line
is not affected by ambient air temperatures. Because the transmission
line ratings for underground transmission lines are generally the
result of thermal issues in the oil-filled pipe, we agree with
commenters that underground transmission lines likely satisfy such
exception.
    230. With respect to older transmission facilities, we decline to
adopt an exception from the AAR requirements for such facilities. We do
not find the arguments that these facilities cannot be rated using AARs
persuasive. For one, Reliability Standard FAC-008-5, which sets forth
requirements to ensure that transmission line ratings used in
operations are determined on a technically sound basis, makes no
distinction with respect to age of transmission lines: Ratings for all
transmission lines must be based on technically sound principles
outlined in the Reliability Standard.\481\ Moreover, regardless of
transmission facility age, the principles of transmission line sag and
tension are correlated with the conductor material and construction
style. A conductor's sag, tension, and swing properties are used to
calculate clearances to vegetation, structures, and other distribution/
communication lines. For older transmission lines that do not have
computerized sag/tension values, graphical methods can be used to
generate the values.\482\ These values for older transmission lines,
similar to parameters for new facilities, are used to calculate
transmission line ratings and adjust transmission line ratings based on
various operating/ambient air temperatures.
---------------------------------------------------------------------------

    \481\ In addition to the Reliability Standard, the NERC alert in
2010 recommended that transmission owners conduct an assessment and
perform any necessary remediation of rating issues including review
of the current facility ratings methodology for their solely and
jointly owned transmission lines to verify that the methodology used
to determine facility ratings is based on actual field conditions
with no distinguishment due to age of transmission assets.
    \482\ See, e.g., ``Sag-Tension Calculation Methods for Overhead
Lines,'' CIGRE Task Force B2.12.3 (Apr. 2016); ``Graphic Method for
Sag Tension Calculations for ACSR and Other Conductors,''
Publication No. 8, Aluminum Company of America (1961).
---------------------------------------------------------------------------

    231. Third, we decline to adopt a blanket exception from the AAR
requirements for transmission facilities below a specific voltage
threshold. Commenters have not explained why transmission line ratings
from lower voltage transmission facilities cannot be rated using AARs.
Rather, we find that the same principles and factors determining
transmission line ratings for higher voltage transmission lines apply
to lower voltage transmission line ratings. We further note that within
RTOs/ISOs (and possibly in other areas), lower voltage transmission
lines often represent the binding transmission constraints that cause
congestion, because such lines are at their limits within the modeled
contingencies, and so we expect that excluding such transmission lines
would meaningfully reduce the benefits of AARs. However, in response to
Entergy's comments,\483\ we note that in cases where lower voltage
transmission facilities might host third-party under-build, such under-
build can and should be considered when developing the sag limits that
inform a transmission facility's AARs.
---------------------------------------------------------------------------

    \483\ Entergy Comments at 10-11.
---------------------------------------------------------------------------

    232. Fourth, we decline to adopt a blanket exception for nomogram
facilities, for transmission facilities that are part of certain
remedial action schemes, or for transmission facilities in areas at
risk of wildfires. For nomogram constraints, as noted in Section
IV.B.1, these typically occur to protect system stability or voltage
and the AAR requirements adopted herein exempt such transmission lines
as well as those whose transmission line ratings that are not affected
by ambient air temperatures. We also note that remedial action schemes
are not inherently inconsistent with AAR implementation. For example,
PJM implements both AARs and remedial action schemes.\484\ In any
event, if the transmission owner determines that the transmission line
ratings of transmission lines associated with the remedial action
schemes are not affected by ambient air temperature because the
operational limitations of the remedial action scheme represent the
relevant limiting element, then the ``Exceptions'' paragraph of pro
forma OATT Attachment M would apply. Moreover, the transmission
provider may also utilize the ``System Reliability'' exception of pro
forma OATT Attachment M if the reasonably transmission provider
determines, consistent with good utility practice, that the temporary
use of a transmission line rating different than would otherwise be
required under pro forma OATT Attachment M is necessary to ensure
safety and reliability. While we note the various exceptions to AAR
implementation that may be applicable to remedial action schemes, we
expect that, in situations where the remedial action scheme is not
armed, transmission providers will implement the AAR requirements
unless doing so would negatively impact system reliability. Finally, to
mitigate the risk of wildfires, we reiterate our adoption of the
``System Reliability'' exception in pro forma OATT Attachment M to
ensure the safety and reliability of the transmission system. We
believe this exception provides sufficient flexibility for transmission
providers to use seasonal or static line ratings when reliability and
good utility practice call for it.
---------------------------------------------------------------------------

    \484\ For example, PJM Manual 3: Transmission Operations,
Attachment A, provides a listing of the remedial action schemes in
operation in PJM. PJM Manual 3 is available here: https://pjm.com/-/media/documents/manuals/m03.ashx.
---------------------------------------------------------------------------

    233. As suggested by EPSA,\485\ we modify proposed pro forma OATT
Attachment M to require transmission providers to reevaluate any
exceptions taken under the ``Exceptions'' paragraph of pro forma OATT
Attachment M at least every five years to ensure that longstanding
exceptions continue to be valid. However, we clarify that if the
technical basis for such an exception goes away, the transmission line
must be re-rated in a timely manner,\486\ and that the five-year
reevaluation requirement is just to ensure that any exceptions do not
inadvertently grow

stale (i.e., the five-year reevaluation is not a justification for
waiting five years to re-rate a transmission line). We do not
specifically require a periodic re-evaluation of temporary alternate
ratings, as we expect such ratings to be used over relatively short
timeframes. However, we note that temporary alternate ratings may only
be used during periods in which the transmission provider determines
that they are necessary under the ``System Reliability'' section of pro
forma OATT Attachment M.
---------------------------------------------------------------------------

    \485\ EPSA Comments at 4.
    \486\ The definition of transmission line rating we adopt in pro
forma OATT Attachment M requires that transmission line ratings
reflect the relevant technical limitations. Thus, when technical
limitations that would justify an exception go away, that
transmission line rating would need to be properly rated in a timely
manner to continue to comply with the pro forma OATT.
---------------------------------------------------------------------------

    234. Finally, as further discussed below in Section IV.G.3.d, we
modify proposed pro forma OATT Attachment M to require that uses of
exceptions or temporary alternate ratings under pro forma OATT
Attachment M be posted to OASIS or another password-protected website.
We require that such postings document the nature of and basis for each
such exception or alternate rating, as well as the date(s) and time(s)
of initiation and (if applicable) withdrawal for the exception or the
alternate rating. Further, transmission providers must maintain in such
databases records of which transmission line ratings and methodologies
were in effect at which times over at least the previous five years.
This five-year period of record retention is consistent with a majority
of the document retention periods required for OASIS postings.\487\
---------------------------------------------------------------------------

    \487\ 18 CFR 37.6 (Information to be posted on the OASIS).
---------------------------------------------------------------------------

E. Dynamic Line Ratings

1. Dynamic Line Ratings Definition
a. NOPR Proposal
    235. In the NOPR, the Commission proposed to define a dynamic line
rating as a transmission line rating that applies to a time period of
not greater than one hour and reflects up-to-date forecasts of inputs
such as (but not limited to) ambient air temperature, wind, solar
heating, transmission line tension, or transmission line sag.\488\
---------------------------------------------------------------------------

    \488\ NOPR, 173 FERC ] 61,165 at P 25.
---------------------------------------------------------------------------

b. Comments
    236. Comments on the proposed definition were limited; however,
Industrial Customer Organizations ask that the proposed definition be
expanded to include additional inputs, such as conductor temperature,
thermal age of the line, and the cumulative number and frequency of
faults. Industrial Customer Organizations assert that thermal age of a
transmission line is a more accurate measure of a transmission line's
physical capability than calendar age.\489\
---------------------------------------------------------------------------

    \489\ Industrial Customer Organizations Comments at 26.
---------------------------------------------------------------------------

    237. Noting that the Commission proposed to require AARs when
evaluating requests for short-term transmission service and when
considering potential curtailment, interruption, and/or redispatch
expected to occur in the next 10 days, ACPA/SEIA argues that DLR
implementation should also fulfill the AAR requirements in proposed pro
forma OATT Attachment M.\490\
---------------------------------------------------------------------------

    \490\ ACPA/SEIA Comments at 12-13.
---------------------------------------------------------------------------

c. Commission Determination
    238. We adopt the definition of DLR that the Commission proposed in
the NOPR. We believe that this definition clearly sets forth a non-
exhaustive list of factors affecting transmission line ratings to be
input into calculations of DLRs. There are many factors that affect an
individual transmission line rating; for this reason, it would be
inappropriate for the Commission to attempt to create an exhaustive
list of factors affecting transmission line ratings for inclusion in
the definition of DLR.
    239. In response to arguments from ACPA/SEIA, we clarify that
because the proposed addition to the Commission's regulations defines
DLRs as reflecting up-to-date forecasts of ambient air temperature,
along with other variables, and because pro forma OATT Attachment M and
the Commission's regulations adopted in this final rule also define an
AAR as reflecting up-to-date forecasts of ambient air temperature,
implementing DLRs satisfies the requirements in pro forma OATT
Attachment M to implement AARs.
2. DLR Requirements
a. NOPR Proposal
    240. In the NOPR, the Commission preliminarily found that between
the two possible approaches to increasing transmission line rating
accuracy--requiring AARs or requiring DLRs--an AAR requirement strikes
a more appropriate balance between benefits and challenges than a DLR
requirement. The Commission explained that, while DLRs can represent
more accurate transmission line ratings than AARs, DLRs also present
additional costs and challenges that AARs do not present. According to
the Commission, these additional costs and challenges, relative to
AARs, include placing sensors in remote locations, ensuring an
appropriate level of cybersecurity, and various additional costs.
Nevertheless, the Commission sought comment on whether to require
transmission providers to implement DLRs across their transmission
systems or on certain transmission lines that have the most to benefit
from DLRs.\491\
---------------------------------------------------------------------------

    \491\ NOPR, 173 FERC ] 61,165 at P 100.
---------------------------------------------------------------------------

    241. Recognizing that DLRs have benefits in certain circumstances,
the Commission proposed to require RTOs/ISOs to establish and implement
the systems and procedures necessary to allow transmission owners to
electronically update transmission line ratings (for each period for
which transmission line ratings are calculated) at least hourly. Absent
these capabilities, the Commission reasoned, the voluntary
implementation of DLRs by transmission owners in some RTOs/ISOs would
be of limited value, as their more dynamic ratings would not be
incorporated into RTO/ISO markets.\492\ The Commission stated that it
expected that many of the systems and procedures RTOs/ISOs would need
to develop are likely to already be required as part of compliance with
the proposed AAR requirements. Nonetheless, the Commission sought
comment on the additional costs, if any, needed to comply with the
proposed requirement that RTOs/ISOs also be able to accommodate
frequently updated transmission line ratings from transmission
owners.\493\
---------------------------------------------------------------------------

    \492\ NOPR, 173 FERC ] 61,165 at P 108.
    \493\ Id. P 109.
---------------------------------------------------------------------------

b. Comments
    242. Nearly all transmission owners that filed comments about DLRs
either oppose a mandate to implement DLRs on all transmission lines
\494\ or oppose a mandate in any form.\495\ Many of these transmission
owners, as well as some RTOs/ISOs, see the merits of DLRs on some
transmission lines, but only after taking into account transmission
line characteristics that would make DLRs more or less cost
effective.\496\
---------------------------------------------------------------------------

    \494\ APS Comments at 8; NYTOs Comments at 2; Indicated PJM
Transmission Owners Comments at 13; PG&E Comments at 11-12.
    \495\ AEP Comments at 6; Dominion Comments at 9; Entergy
Comments at 14; BPA Comments at 6; Exelon Comments at 3; PacifiCorp
Comments at 5-6; NRECA/LPPC Comments at 3; MISO Transmission Owners
Comments at 45-46; ITC Comments at 14-15.
    \496\ APS Comments at 8; Exelon Comments at 3, 13; PacifiCorp
Comments at 5-6; EEI Comments at 15; ITC Comments at 12; AEP
Comments at 6; NYTOs Comments at 4, 12-13; Dominion Comments at 9-
11; NYISO Comments at 5; PJM Comments at 10-11.
---------------------------------------------------------------------------

    243. In opposing a mandate to implement DLRs on all transmission
lines, many transmission owners focus on the cost and challenges
associated

with DLRs. Some offer rough quantitative estimates of these costs. For
example, BPA explains that DLR implementation would require significant
investment of potentially over $1 million per transmission line in
monitoring equipment, software, and hardware to submit and host the
data.\497\ MISO Transmission Owners explain that one transmission
owner's experience with DLRs in MISO suggests that DLR implementation
could cost between $100,000 and $200,000 per transmission line. MISO
Transmission Owners assert that the cost to implement DLRs on all MISO
transmission lines could be $1.5 billion (estimating $150,000 per line
multiplied by 10,000 lines on the MISO system).\498\
---------------------------------------------------------------------------

    \497\ BPA Comments at 6.
    \498\ MISO Transmission Owners Comments at 47.
---------------------------------------------------------------------------

    244. Other transmission owners offer qualitative assessments of the
potential costs and challenges associated with DLRs. APS asserts that
DLRs are a high cost option with limited benefits.\499\ Exelon explains
that any investment in DLRs could come at the expense of investment in
other equipment.\500\ As EEI, Exelon, and NYTOs explain, there are
additional costs and challenges associated with sensor and
communication technology installation, cybersecurity, and with DLRs
themselves, which tend to fluctuate.\501\ Entergy does not use DLRs and
contends that DLRs present significant technical, logistical, and
financial commitments, that the input data is too unpredictable, and
that, while sensors work, they are not predictive of future
conditions.\502\ Dominion also articulates concerns with DLR data
interruptions.\503\ Others note the challenges associated with
implementing DLRs on transmission lines traversing multiple temperature
and wind climates.\504\ Finally, NYTOs note that, because AARs and DLRs
are constantly changing, their use in real-time operations could lead
to violations of NERC Reliability Standard FAC-008 if there are
discrepancies, potentially caused by a software calculation error.
NYTOs are concerned that there would be no allowance for time to
identify any calculation errors. For this reason, NYTOs aver that
independent software validation solutions would be needed.\505\
---------------------------------------------------------------------------

    \499\ APS Comments at 8.
    \500\ Exelon Comments at 16.
    \501\ EEI Comments at 15; Exelon Comments at 15-16; NYTOs
Comments at 4.
    \502\ Entergy Comments at 14-15.
    \503\ Dominion Comments at 11.
    \504\ NYTOs Comments at 12; Exelon Comments at 14; BPA Comments
at 6.
    \505\ NYTOs Comments at 7.
---------------------------------------------------------------------------

    245. Many transmission owners believe that DLRs have merit in
certain applications, but argue that further study is needed. Some
explain that they have experience with DLR pilot projects and limited
DLR implementation and state that DLRs are likely economic in certain
applications.\506\ For example, Dominion explains that it is currently
analyzing three separate DLR pilot programs, but cautions that it is
too early to judge the effectiveness of the technology.\507\ Potomac
Economics and several transmission owners caution that the current
focus should be on AAR implementation, not DLR implementation, and that
the benefits of DLRs should be reassessed after AAR
implementation.\508\ Sunflower does not rule out support for future DLR
implementation, but states that DLRs must be thoroughly studied and
tested first.\509\ Southern Company and NYTOs oppose implementation of
either AARs or DLRs on all transmission lines. NYTOs instead suggest a
compliance process to select transmission lines for either AAR or DLR
implementation similar to the Order No. 1000 process for regional
transmission planning, while Southern Company suggests that the
Commission adopt a process similar to its ATC requirements and direct
transmission providers to identify transmission facilities that would
most benefit from both AAR and DLR implementation.\510\ While NRECA/
LPPC generally do not oppose using AARs and DLRs, they assert that
consumer benefits in the form of lower costs should remain the primary
focus, so long as safety and reliability are uncompromised.
Furthermore, NRECA/LPPC argue that conservative transmission line
ratings of facilities must continue to account for unanticipated
conditions and human error.\511\
---------------------------------------------------------------------------

    \506\ EEI Comments at 15; ITC Comments at 12; AEP Comments at 6;
Exelon Comments at 13; APS Comments at 8; NYTOs Comments at 4, 12-
13; Dominion Comments at 9-11.
    \507\ Dominion Comments at 4.
    \508\ Potomac Economics Comments at 20; ITC Comments at 14-15;
PG&E Comments at 11-12; NYTOs Comments at 13.
    \509\ Sunflower Comments at 5-6.
    \510\ NYTOs Comments at 10; Southern Company Comments at 2-3.
    \511\ NRECA/LPPC Comments at 7-8.
---------------------------------------------------------------------------

    246. Similarly, RTOs/ISOs caution that a full DLR mandate is
premature \512\ and some argue that the decision to study or pursue
DLRs should be left to transmission owners.\513\ PJM asserts that RTOs/
ISOs could rank the most congested transmission lines, which might
serve to test the degree to which such transmission lines might be
impacted by DLR implementation, and asserts that DLRs should only be
used on the most congested transmission lines.\514\ SPP believes that
the DLR implementation costs to transmission owners may outweigh the
benefits, estimating that DLR implementation that requires an EMS
upgrade would cost transmission owners up to $1 million and, without
upgrading the EMS, DLR implementation would cost an additional
$100,000-$500,000 annually in additional SCADA communications with the
Reliability Coordinator's EMS.\515\ ISO-NE notes that transmission
lines in its territory often do not follow a linear path, which can
result in different transmission line ratings for different segments of
the same transmission line at the same time if wind speed is taken into
account rather than solely ambient air temperature.\516\ NYISO explains
that its currently-effective DLR functionality and seasonal
transmission line ratings ``support effective system planning,
efficient markets, reliable system operation, and the flexibility
needed for NYISO and TO operators to respond to real-time system
conditions''; \517\ however, this has historically been used to
increase transmission line ratings in real time based on ambient
conditions. NYISO voices concern that frequently updated transmission
line ratings, especially those that lower transmission line ratings in
real-time during emergency conditions, would have a detrimental effect
on reliability in the context of corrective action plans designed to
create plans to respond to contingencies, should the system operating
limits used to develop the corrective action plan be lowered in real
time.\518\ NYISO further explains that instances wherein increased
transmission line ratings in the day-ahead market resulting in
increased commitments are then reduced in the real-time markets could
increase uplift costs.\519\
---------------------------------------------------------------------------

    \512\ CAISO Comments at 16; ISO-NE Comments at 12; NYISO
Comments at 7; PJM Comments at 10-11; MISO Comments at 33.
    \513\ CAISO Comments at 16; PJM Comments at 10-11,13; MISO
Comments at 33.
    \514\ PJM Comments at 12.
    \515\ SPP Comments at 12.
    \516\ ISO-NE Comments at 19.
    \517\ NYISO Comments at 6.
    \518\ Id. at 7-8.
    \519\ Id. at 14.
---------------------------------------------------------------------------

    247. The market monitors are divided over the timing and
implementation of a DLR mandate. The SPP MMU recommends DLR
implementation on all transmission lines, not just congested
transmission lines, to account for the interlinkage among transmission
lines

and to avoid preferential treatment or gaming of transmission lines
selected for DLR.\520\ On the other hand, Potomac Economics suggests
further study and discourages mandates for both universal and targeted
DLR implementation at this time.\521\ The CAISO DMM states that it
would support the use of DLRs where practicable in the future and
suggests that conservative assumptions for some applications, such as
in the day-ahead market or future advisory intervals, may be
appropriate. As such, the CAISO DMM requests that RTOs/ISOs retain the
ability to adjust modeled transmission for reliability.\522\
---------------------------------------------------------------------------

    \520\ SPP MMU Comments at 4.
    \521\ Potomac Economics Comments at 20.
    \522\ CAISO DMM Comments at 2-3.
---------------------------------------------------------------------------

    248. State agencies, consumer advocacy groups, and other
miscellaneous organizations generally support DLR implementation, but
vary widely on what approach the Commission should take. Some groups
support the Commission requiring full DLR implementation. R Street
Institute contends that DLRs should be required by default, with
exception given when justified by a cost-benefit analysis.\523\
Industrial Customer Organizations likewise contend that the Commission
should require the implementation of DLRs unless a transmission owner
can establish that costs would exceed benefits to consumers.\524\ ACORE
recommends the Commission take further steps to encourage DLR
deployment.\525\ Clean Energy Parties argue that DLR is superior to
AAR, and that the Commission should establish criteria for when DLR is
required.\526\ ACPA/SEIA contend that DLR can provide significant
benefits,\527\ and that congestion reviews should evaluate both AARs
and DLRs for any congested transmission line.\528\
---------------------------------------------------------------------------

    \523\ R Street Institute Comments at 3.
    \524\ Industrial Customer Organizations Comments at 5.
    \525\ ACORE Comments at 1.
    \526\ Clean Energy Parties Comments at 5, 7.
    \527\ ACPA/SEIA Comments at 5-6.
    \528\ Id. at 9-11.
---------------------------------------------------------------------------

    249. Several groups also argue for more targeted or limited DLR
requirements. WATT proposes a list of criteria for requiring DLR
implementation,\529\ and contends that such criteria can help overcome
concern about costs exceeding benefits.\530\ ACPA/SEIA similarly
support requiring an evaluation of both AARs and DLRs for any congested
transmission line, and a DLR requirement where appropriate.\531\ EDFR
supports requiring DLRs when cost-benefit analysis or public policy
justifies their use.\532\ EPSA contends that the Commission should
first require DLRs only on transmission lines that are deemed to be the
most critical for optimizing system performance.\533\ Vistra states
that it uses DLRs with some of its facilities in ERCOT, and states that
it has seen improved congestion management, greater deliverability of
low-cost energy to load, lower costs for load, higher revenues for low
cost remote generation, and lower hedging costs.\534\ Vistra states
that DLR benefits will become increasingly important as more zero
marginal cost energy resources are added to the resource mix.\535\
---------------------------------------------------------------------------

    \529\ WATT proposes for sensor-based DLR to be required on all
thermally limited transmission lines rated 69 kV or greater when
market congestion totaling over $1 million has occurred within the
past year; the transmission line is identified as being a constraint
projected to have market congestion over $1 million over the coming
three years as a part of the current RTO/ISO transmission planning
cycle process, which can be economic or reliability based; thermally
limited transmission lines show up as limiting in generator
interconnection system impact studies; or generation curtailed by
more than 10% on average for one year due to factors that include
transmission line capacity. WATT Comments at 10.
    \530\ Id. at 2, 10-11.
    \531\ ACPA/SEIA Comments at 8-10.
    \532\ EDFR Comments at 4.
    \533\ EPSA Comments at 6.
    \534\ Vistra Comments at 2-3.
    \535\ Id. at 3.
---------------------------------------------------------------------------

    250. Several other groups support DLR mandates or oversight of
voluntary deployment. TAPS supports voluntary implementation of DLRs,
but also argues that subjective deployment decisions should be subject
to monitoring.\536\ Industrial Customer Organizations contend that the
Commission should, at minimum, require the implementation of staggered
pilot programs requiring the implementation of DLRs on the most
thermally limited, congested transmission lines.\537\ Certain TDUs
argue that DLR utilization can improve contingency planning and defer
or eliminate the need for transmission line upgrades or
reconductoring.\538\
---------------------------------------------------------------------------

    \536\ TAPS Comments at 15-17.
    \537\ Industrial Customer Organizations Comments at 25.
    \538\ Certain TDUs Comments at 6-7.
---------------------------------------------------------------------------

    251. In response to the Commission's proposal to require RTOs/ISOs
to establish and implement the systems and procedures necessary to
allow transmission owners to electronically update transmission line
ratings (for each period for which transmission line ratings are
calculated) at least hourly, however, commenters are broadly
supportive. For example, PacifiCorp agrees with the Commission that
many of the systems and procedures RTOs/ISOs would need to develop to
accept DLRs are likely to already be required as part of compliance
with the requirements to adopt AARs.\539\ PJM notes that, as part of
DLR pilot projects, it has received and reviewed DLRs.\540\ Similarly,
NYISO notes that it has successfully implemented DLR functionality to
allow asset owners to increase real-time transmission line capability,
when appropriate, and notes that this implementation does not
differentiate between AARs and DLRs.\541\
---------------------------------------------------------------------------

    \539\ PacifiCorp Comments at 6.
    \540\ PJM Comments at 11-12.
    \541\ NYISO Comments at 4.
---------------------------------------------------------------------------

c. Commission Determination
    252. Based on the record, we decline to mandate DLR implementation
in this final rule.
    253. We agree with commenters that highlight the benefits to DLR
implementation.\542\ For example, use of DLRs generally allows for
greater power flows than would otherwise be allowed, and its use can
also detect situations where power flows should be reduced to maintain
safe and reliable operation and avoid unnecessary wear on transmission
equipment.\543\ We agree with EPSA, which, citing to a PJM pilot
program with AEP and PPL Electric Utilities Corporation, explains that
there could be significant benefits to strategically expanding DLR
deployment.\544\ Additionally, we agree with Exelon that there may be
targeted applications in which DLRs can provide net benefits to
customers. For example, when the limiting element for a transmission
facility experiencing significant congestion is the conductor and
conditions besides ambient air temperature have a consistent and
significant impact on the power carrying capabilities of the line, DLRs
may provide more accurate transmission line ratings than AARs and
therefore may provide significant benefits.\545\
---------------------------------------------------------------------------

    \542\ Clean Energy Parties Comments at 6; EPSA Comments at 5;
Exelon Comments at 13.
    \543\ Clean Energy Parties Comments at 6.
    \544\ EPSA Comments at 5.
    \545\ Exelon Comments at 13.
---------------------------------------------------------------------------

    254. However, we appreciate that while DLRs can represent more
accurate transmission line ratings than AARs, DLR implementation also
presents additional costs and challenges not found in AAR
implementation. Relative to AARs, these additional costs and challenges
include placing sensors in remote locations, ensuring the cybersecurity
of sensors, and various additional costs. The record in this proceeding
is not sufficient for the Commission to evaluate the relative benefits
and costs and challenges of DLR implementation. For this reason,

we incorporate the record in this proceeding on DLRs into new Docket
No. AD22-5-000, which we open to further explore DLR implementation.
    255. Finally, we adopt the Commission's proposal in the NOPR to
require RTOs/ISOs to establish and maintain systems and procedures
necessary to allow transmission owners to electronically update
transmission line ratings (for each period for which transmission line
ratings are calculated) at least hourly, with such data submitted by
transmission owners directly into the RTO's/ISO's EMS through SCADA or
related systems.\546\ We continue to find that, because DLR
implementation may be economic in certain applications,\547\ absent
RTOs/ISOs having these capabilities, voluntary implementation of DLRs
by transmission owners in some RTOs/ISOs would be of limited value, as
their more dynamic ratings and resulting benefits would not be
incorporated into RTO/ISO markets. Absent these minimum capabilities,
RTO/ISO software would serve as a barrier that prevents transmission
owners in RTOs/ISOs from implementing DLRs that can better reflect the
actual transfer capability of the transmission system and,
consequently, wholesale rates would not remain just and reasonable.
Additionally, as the Commission stated in the NOPR, we continue to
expect that many of the systems and procedures RTOs/ISOs would need to
develop to accept DLRs are likely to already be required as part of
compliance with the AAR requirements adopted in this final rule.
---------------------------------------------------------------------------

    \546\ However, we add the DLR requirement adopted herein to 18
CFR 35.28(g)(13), rather than to 18 CFR 35.28(g)(12) as proposed in
the NOPR, in light of the requirements recently approved in Order
No. 2222. See Participation of Distributed Energy Resource
Aggregations in Markets Operated by Regional Transmission
Organizations and Independent System Operators, Order No. 2222, 85
FR 68450 172 FERC ] 61,247 (2020), order on reh'g, Order No. 2222-A,
174 FERC ] 61,197 (2021).
    \547\ EEI Comments at 15; ITC Comments at 12; AEP Comments at 6;
Exelon Comments at 13; APS Comments at 8; NYTOs Comments at 4, 12-
13; Dominion Comments at 9-11.
---------------------------------------------------------------------------

3. Extending to Non-RTO/ISO Transmission Providers the Requirement To
Allow Transmission Owners To Electronically Update Transmission Line
Ratings at Least Hourly
a. NOPR Proposal
    256. In addition to requiring RTOs/ISOs to establish and implement
the systems and procedures necessary to allow transmission owners to
electronically update transmission line ratings at least hourly, the
Commission also sought comment on whether there is any need to extend
this same requirement to transmission providers that operate outside of
an RTO/ISO.\548\
---------------------------------------------------------------------------

    \548\ NOPR, 173 FERC ] 61,165 at P 109.
---------------------------------------------------------------------------

b. Comments
    257. Comments on this question are limited. EEI and PacifiCorp
state that there is no need to extend this requirement beyond RTOs/
ISOs.\549\ R Street Institute, however, observes that transmission
management inefficiency and transmission line rating opacity outside
RTOs/ISOs is far greater than within RTOs/ISOs, and therefore concludes
that updating transmission line ratings hourly outside RTOs/ISOs would
be a prudent start.\550\ Similarly, WATT argues that the same
requirements should apply consistently across RTOs/ISOs and non-RTOs/
ISOs, noting concerns of utilities considering voluntary RTO/ISO
membership that regulatory requirements are stricter within RTOs/ISOs
than outside RTOs/ISOs which serves as a disincentive to RTO/ISO
participation.\551\
---------------------------------------------------------------------------

    \549\ EEI Comments at 18-19; PacifiCorp Comments at 6.
    \550\ R Street Institute Comments at 5.
    \551\ WATT Comments at 15.
---------------------------------------------------------------------------

c. Commission Determination
    258. We decline to extend the requirement for RTOs/ISOs to be able
to accept DLRs to non-RTO/ISO transmission providers at this time. As
EEI explains, in most cases outside of an RTO/ISO market, transmission
providers operate only their own transmission systems. In those cases,
transmission providers have the ability to fully implement DLRs should
they choose to do so. Because non-RTO/ISO transmission providers are
also typically the transmission owner, we find that any requirement for
non-RTO/ISO transmission providers to be able to accept DLRs would be
unnecessary.
4. DLR Studies
a. NOPR Proposal
    259. In the NOPR, the Commission sought comment on whether to
require RTOs/ISOs to conduct a one-time study of the cost effectiveness
of DLR implementation, and if so, what details/format any such study
should include.\552\
---------------------------------------------------------------------------

    \552\ NOPR, 173 FERC ] 61,165 at P 110.
---------------------------------------------------------------------------

b. Comments
    260. Most transmission owners oppose requirements for RTOs/ISOs to
study the cost effectiveness of DLR implementation.\553\ One exception
is PG&E, which argues that an RTO/ISO study could identify the efficacy
of system-wide DLR implementation relative to more localized use.\554\
Exelon opposes a study requirement, asserting that it would be costly,
time-consuming, and duplicative to existing processes.\555\ Indicated
PJM Transmission Owners contend that there would be little point in PJM
conducting another DLR study and caution that any DLR study would be
costly and highly locational in nature, possibly necessitating DLR
sensor installation.\556\ MISO Transmission Owners question whether the
RTO/ISO is the appropriate entity to study the cost effectiveness of
DLR implementation and further explain that certain study details
remain unaddressed.\557\ Therefore, MISO Transmission Owners assert
that the Commission should provide flexibility for transmission owners
and RTOs/ISOs to collaborate on a voluntary basis to conduct DLR
studies.\558\ EEI also does not support a mandate to study DLR cost
effectiveness, explaining that RTOs/ISOs already study congestion and
solutions to resolve congestion in the transmission planning
processes.\559\ Dominion cautions that, should the Commission require
DLR studies, such studies should involve transmission owners.\560\
Finally, Certain TDUs explain that transparency into the benefits of
DLRs is important, and they therefore support DLR studies, but argue
that studies should involve the RTOs/ISOs and be incorporated into the
transmission planning processes.\561\
---------------------------------------------------------------------------

    \553\ MISO Transmission Owners Comments at 38; ITC Comments at
15; Exelon Comments at 6; Dominion Comments at 12; EEI Comments at
16; Indicated PJM Transmission Owners Comments at 13-14.
    \554\ PG&E Comments at 11.
    \555\ Exelon Comments at 6.
    \556\ Indicated PJM Transmission Owners Comments at 13-14.
    \557\ Specifically, MISO Transmission Owners explain that the
Commission should clarify for what purpose the study results would
be used.
    \558\ MISO Transmission Owners Comments at 38.
    \559\ EEI Comments at 16.
    \560\ Dominion Comments at 12.
    \561\ Certain TDUs Comments at 7.
---------------------------------------------------------------------------

    261. Several RTOs/ISOs also discourage the Commission from
requiring DLR studies.\562\ MISO states that studies should be
transmission line specific and driven by the transmission owners.\563\
ISO-NE does not believe a study is necessary until, and unless, AARs
are fully implemented. ISO-NE recommends that, if a study is required,
it be carried out by a third party.\564\ CAISO opposes DLR cost-
effectiveness study requirements but would not

oppose an informational report on its work with stakeholders evaluating
the costs and benefits of DLRs.\565\ PJM argues that several
outstanding issues should be studied and recommends: (1) Periodic
reporting requirements by region on the status and lessons learned from
DLR deployments; (2) requiring transmission owners to document their
DLR implementation processes; and (3) technical conferences to share
best practices on DLR implementation.\566\ SPP notes that it recently
published a whitepaper that examined the costs and benefits of
DLRs.\567\
---------------------------------------------------------------------------

    \562\ CAISO Comments at 16; ISO-NE Comments at 12; MISO Comments
at 33.
    \563\ MISO Comments at 33.
    \564\ ISO-NE Comments at 12.
    \565\ CAISO Comments at 16.
    \566\ PJM Comments at 13-14.
    \567\ SPP Comments at 15.
---------------------------------------------------------------------------

    262. EPRI argues that, before studies on DLR cost effectiveness can
be conducted, studies on monitoring systems must be conducted.
According to EPRI, such studies must identify a technical basis to
select sensors, establish the accuracy of sensors, develop an
understanding of sensors' reliability and maintenance needs, and
identify methods to integrate monitoring system data into an EMS. EPRI
states that unbiased information on monitoring systems is not yet
available and explains that some commercial DLR monitoring equipment
may not be up to utility standards.\568\
---------------------------------------------------------------------------

    \568\ EPRI Comments at 5.
---------------------------------------------------------------------------

    263. While RTOs/ISOs and transmission owners generally oppose a
study requirement, several commenters are more supportive of DLR study
requirements. New England State Agencies support independent studies on
the cost-effectiveness of DLRs as a first step before ordering
implementation.\569\ Ohio FEA does not support Commission requirements
for RTOs/ISOs to study the cost effectiveness of DLR implementation,
but, noting that DLRs may be cost effective on certain lines, states
that pilot programs should be initiated to identify these segments
through the stakeholder process rather than a requirement.\570\ CEA
supports DLR feasibility studies to address the cost of infrastructure
and EMS-SCADA changes, the challenges of implementing DLRs on
transmission lines with varying climates and little communications
infrastructure, and DLR forecasting challenges, but questions whether
risks and costs will be borne by RTOs/ISOs or by transmission
owners.\571\ Clean Energy Parties support requiring RTOs/ISOs to
conduct a study of the cost effectiveness of DLR implementation.\572\
OMS contends that industry and regulators need more information to
better understand the potential benefits of DLRs.\573\
---------------------------------------------------------------------------

    \569\ New England State Agencies Comments at 14.
    \570\ Ohio FEA Comments at 6-7.
    \571\ CEA Comments at 2-3.
    \572\ Clean Energy Parties Comments at 11.
    \573\ OMS Comments at 12.
---------------------------------------------------------------------------

c. Commission Determination
    264. In consideration of the comments on this issue, we decline to
require one-time DLR studies at this time. We agree with New England
State Agencies and OMS that studies assessing the cost effectiveness of
DLR implementation may be useful to transmission providers in
identifying possible transmission line candidates for DLR deployment
and serve as a good first step prior to consideration of additional
requirements.\574\ Specifically, such studies may support the
development of various criteria transmission providers could use to
identify candidates for DLR deployment.\575\ However, we also agree
that there are various factors to consider in order to determine when
and how such studies should be conducted, including whether such
studies: Should be conducted by independent third parties; should
incorporate the adoption of AARs into the analysis; \576\ and would
overlap with existing congestion studies in RTOs/ISOs.\577\ Although we
decline to require one-time DLR studies at this time, we incorporate
the record in this proceeding on DLRs into new Docket No. AD22-5-000,
which we open to further explore DLR implementation.
---------------------------------------------------------------------------

    \574\ New England State Agencies Comments at 14; OMS Comments at
12.
    \575\ WATT Comments at 10; ACPA/SEIA Comments at 9-10; Clean
Energy Parties Comments at 7-10.
    \576\ ISO-NE Comments at 11-12.
    \577\ EEI Comments at 16; Exelon Comments at 6.
---------------------------------------------------------------------------

5. Advanced Transmission Technology Cost Recovery
a. Comments
    265. ENEL states that advanced transmission technologies can
achieve cost savings and provide value to ratepayers, such that
transmission owners should be eligible to recover their costs through
rate base and to earn a return, and requests clarification on the cost
allocation and recovery associated with AAR and DLR
implementation.\578\
---------------------------------------------------------------------------

    \578\ ENEL Comments at 2-3.
---------------------------------------------------------------------------

b. Commission Determination
    266. We are not considering in this proceeding whether to grant
special rate treatment for technologies used to implement AARs and
DLRs. We are also not considering in this proceeding whether to change
the Commission's policies regarding cost recovery. While the purchase
and installation cost of equipment that may normally be considered as
plant in service may be eligible for inclusion in rate base, without
knowing the specific facts related to a particular investment, it would
be impractical to address their cost recovery at this time. However,
once specific costs are known, parties can file with the Commission to
seek recovery, as appropriate.\579\
---------------------------------------------------------------------------

    \579\ Note that the Commission convened a workshop on September
10, 2021, to discuss certain performance-based ratemaking
approaches, particularly shared savings, that may foster deployment
of transmission technologies. Notice of Workshop, Docket Nos. AD19-
19-000, RM20-10-000 (Apr. 15, 2021).
---------------------------------------------------------------------------

F. Emergency Ratings

1. NOPR Request for Comments
    267. In the NOPR, the Commission sought comment on: (1) Whether to
require transmission providers to use unique emergency ratings; (2) the
degree to which transmission providers use or are provided with unique
emergency ratings and the emergency rating durations that are commonly
used; (3) whether and how requirements to implement unique emergency
ratings would impact the useful life of transmission equipment; and (4)
the feasibility of calculating emergency ratings on transmission
equipment other than conductors and transformers.\580\ The Commission
stated that emergency ratings should not be arbitrarily set equal to
normal ratings, but rather should be developed from appropriate, unique
technical inputs.\581\ The Commission acknowledged that there may be
some instances when, after a proper technical analysis considering the
relevant rating timeframes, the emergency rating is equal to the normal
rating.\582\
---------------------------------------------------------------------------

    \580\ NOPR, 173 FERC ] 61,165 at PP 111-113.
    \581\ Id. P 110.
    \582\ Id. P 46 n.57.
---------------------------------------------------------------------------

    268. The Commission observed that, for short periods of time, most
transmission equipment can withstand high currents without sustaining
damage, which allows transmission owners to develop two sets of ratings
for most facilities: Normal ratings that can be safely used
continuously (i.e., not time-limited) and emergency ratings that can be
safely used for a limited period of time. Whether and how a
transmission owner establishes emergency ratings is important because
emergency ratings are a critical input into determining operating
limits in market models, both during normal operations and during post-
contingency operations. Market models often allow

post-contingency flows on transmission lines to exceed normal ratings
for short periods of time, as long as the flows do not exceed the
applicable emergency rating for the corresponding timeframe. Because
these emergency ratings are a more accurate representation of the flow
limits over shorter timeframes, their use in models of post-contingency
flows may produce prices which more accurately reflect actual costs to
delivering wholesale energy to transmission customers. Since the
transmission system is operated to withstand contingencies, the use of
unique emergency ratings, where appropriate, allows for greater flows
during normal conditions as well. The Commission further stated that
this greater transfer capability can provide significant cost savings
and afford transmission providers additional flexibility in how to
respond to unforeseen events.\583\ Noting the potential negative
consequences of emergency ratings, however, the Commission recognized
concerns that the use of emergency ratings could impact reliability by
degrading affected transmission facilities and ultimately reducing the
equipment's useful life.\584\
---------------------------------------------------------------------------

    \583\ Id. P 112.
    \584\ Id. P 113.
---------------------------------------------------------------------------

2. Emergency Ratings Definition and Implementation Requirements
a. Comments
    269. Some transmission owners oppose a potential mandate to require
unique emergency ratings,\585\ while others do not oppose the use of
emergency ratings, but oppose a mandate, asking for flexibility to
determine how and when to use emergency ratings.\586\ Some transmission
owners note that they use emergency ratings on their systems,\587\
while several of these support the use of emergency ratings.\588\ PG&E,
for example, notes that it currently uses emergency ratings for both
planning and real-time operations.\589\ APS states that the use of
emergency ratings gives operators sufficient time to respond and
supports their use during post-contingency operations for a 30-minute
timeframe.\590\ Tangibl notes that PJM's experience shows that
implementation and use of unique emergency ratings is longstanding and
feasible.\591\
---------------------------------------------------------------------------

    \585\ Dominion Comments at 12; EEI Comments at 16-17; MISO
Transmission Owners Comments at 17; NRECA/LPPC Comments at 25-26;
Southern Company Comments at 4.
    \586\ See, e.g., EEI Comments at 16-17; SDG&E Comments at 4-5.
Exelon and ITC, while not opposing or supporting a mandate for the
use of emergency ratings, similarly contend that transmission owners
should be responsible for calculating emergency ratings and
determining the facilities for which they are appropriate. Exelon
Comments at 19-20; ITC Comments at 12.
    \587\ APS Comments at 7; Dominion Comments at 4; Entergy
Comments at 1; EEI Comments at 16; Exelon Comments at 22; Indicated
PJM Transmission Owners Comments at 2; PacifiCorp Comments at 4;
PG&E Comments at 12; SDG&E Comments at 3; WAPA Comments at 8.
    \588\ APS Comments at 7; Dominion Comments at 4; Exelon Comments
at 22; Indicated PJM Transmission Owners Comments at 15; PacifiCorp
Comments at 4.
    \589\ PG&E Comments at 12.
    \590\ APS Comments at 7.
    \591\ Tangibl Comments at 4.
---------------------------------------------------------------------------

    270. Four RTOs/ISOs indicate that they use emergency ratings.\592\
RTOs/ISOs are evenly divided on potential requirements to calculate and
implement emergency ratings. CAISO and MISO oppose an emergency rating
mandate. CAISO believes that there is no need for a mandate since it
already maintains emergency ratings in the CAISO register of
transmission and facility line ratings; MISO argues that any such
mandate, if directed, should be to transmission owners.\593\ Of the
RTOs/ISOs in support of potential emergency ratings requirements, ISO-
NE recognizes the benefits resulting from their use and NYISO is
supportive so long as the equipment supports the transmission line
rating.\594\
---------------------------------------------------------------------------

    \592\ CAISO Comments at 1; NYISO Comments at 3; ISO-NE Comments
at 6; MISO Comments at 25.
    \593\ CAISO Comments at 15; MISO Comments at 24-25 & n.45.
    \594\ NYISO Comments at 14 n.13; ISO-NE Comments at 10.
---------------------------------------------------------------------------

    271. Market monitors, independent agencies, technical experts,
renewable energy advocates, generation companies, and load all
generally support the use of unique emergency ratings \595\ and most
support requirements for their use.\596\ The SPP MMU and Potomac
Economics support requiring transmission providers to establish
emergency ratings using unique technical inputs that are separate from
normal ratings.\597\ Potomac Economics notes that transmission owners
will not voluntarily adopt broad or consistent emergency ratings use
without a requirement.\598\ Industrial Customer Organizations state
that the need for accurate transmission line ratings applies especially
during emergency operations.\599\ Tangibl contends that a spot check of
facilities in PJM shows that almost all have unique emergency
ratings.\600\
---------------------------------------------------------------------------

    \595\ ACPA/SEIA Comments at 17; EDFR Comments at 6; Industrial
Customer Organizations Comments at 27; R Street Institute Comments
at 3; Tangibl Comments at 2; WATT Comments at 13 (supported in
general by LineVision).
    \596\ EDFR Comments at 6; Potomac Economics Comments at 4; R
Street Institute Comments at 3; SPP MMU Comments at 5; Tangibl
Comments at 2; WATT Comments at 13 (supported in general by
LineVision).
    \597\ Potomac Economics Comments at 4; SPP MMU Comments at 5.
    \598\ Potomac Economics Comments at 4.
    \599\ Industrial Customer Organizations Comments at 27.
    \600\ Tangibl Comments at 3.
---------------------------------------------------------------------------

    272. Many transmission owners emphasize that emergency ratings can
be the same as the normal rating \601\ and state the importance of
transmission owner discretion in setting emergency ratings.\602\ MISO
and CAISO oppose any unique emergency ratings mandate, claiming that
good reasons may exist to justify their not being unique.\603\ CAISO,
NYISO, and MISO provide examples of cases where emergency ratings could
be the same as the normal rating for a transmission facility.\604\
Recognizing these cases, CAISO requests that any final rule requiring
unique emergency ratings allow for and appropriately account for
exceptions.\605\ The SPP MMU and Potomac Economics support requiring
transmission providers to establish emergency ratings using unique
technical inputs that are separate from normal ratings.\606\
---------------------------------------------------------------------------

    \601\ See, e.g., Entergy Comments at 4; Exelon Comments at 19-
20; ITC Comments at 3; MISO Transmission Owners Comments at 17;
NRECA/LPPC Comments at 25; SDG&E Comments at 4.
    \602\ See, e.g., EEI Comments at 16-17; Exelon Comments at 19-
20; ITC Comments at 12; MISO Transmission Owners Comments at 40-41;
Indicated PJM Transmission Owners Comments at 15; SDG&E Comments at
4-5.
    \603\ CAISO Comments at 15; MISO Comments at 24-25.
    \604\ CAISO Comments at 15; NYISO Comments at 14 n.13; MISO
Comments at 24-25.
    \605\ CAISO Comments at 15.
    \606\ SPP MMU Comments at 5; Potomac Economics Comments at 4.
---------------------------------------------------------------------------

    273. ITC and MISO Transmission Owners argue that requiring unique
emergency ratings could create a perverse incentive for normal ratings
to be revised downward so that there can be unique emergency
ratings.\607\ Similarly, MISO argues that it is sub-optimal to
artificially lower the normal ratings to create the appearance of a
deviation from the emergency rating when they would otherwise be
equal.\608\ MISO Transmission Owners assert that requiring emergency
ratings that are unique from normal ratings is unnecessary and
arbitrary.\609\
---------------------------------------------------------------------------

    \607\ ITC Comments at 12; MISO Transmission Owners Comments at
17; MISO Comments at 25.
    \608\ MISO Comments at 25.
    \609\ MISO Transmission Owners Comments at 40.
---------------------------------------------------------------------------

    274. MISO states that the NOPR appears to regard cases where
transmission lines have equal emergency and normal ratings as
exceptional although they may occur regularly.\610\ MISO Transmission

Owners read the NOPR as suggesting that having the same rating for
normal and emergency operations reflects a lack of effort by
transmission owners to analyze and incorporate appropriate emergency
ratings.\611\ According to MISO Transmission Owners, it would not be
problematic for the Commission to require separate normal and emergency
ratings on facilities where transmission owners determine they are
appropriate.\612\ Similarly, MISO argues that transmission owners
should evaluate a facility's normal and emergency capability separately
and distinctly where each transmission line rating fully uses the
technical capabilities of the installed equipment considering good
utility practice, sound engineering judgment, manufacturer guidance,
and equipment reliability experience for each rating type.\613\
---------------------------------------------------------------------------

    \610\ MISO Comments at 25.
    \611\ MISO Transmission Owners Comments at 17.
    \612\ Id. at 40.
    \613\ MISO Comments at 25-26.
---------------------------------------------------------------------------

    275. The SPP MMU states that there may be cases when normal and
emergency ratings are legitimately equal, but that should only be true
for a very small number of transmission lines.\614\ The SPP MMU notes
that nearly 60% of transmission lines in SPP have identical normal and
emergency ratings and argues that emergency ratings should only rarely
be equal to normal ratings. Potomac Economics states that only roughly
one third of the transmission line ratings provided for contingency
constraints in MISO are emergency ratings compared to MISO's report
that 90% of its binding constraints are contingent constraints that
should be based on emergency ratings.\615\
---------------------------------------------------------------------------

    \614\ SPP MMU Comments at 4-5.
    \615\ Potomac Economics Comments at 7, 11.
---------------------------------------------------------------------------

    276. OMS contends that emergency ratings should serve as the
foundation for AARs.\616\ OMS agrees with MISO Transmission Owners that
normal and emergency ratings should not always be unique, but argues
that transmission line ratings that are the same value can be derived
using different methodologies.\617\ OMS contends that transmission
owners have the responsibility to judge the reasonableness of using
non-unique emergency ratings subject to transmission provider and
market monitor review.\618\ EPRI states that high operating
temperatures, other limiting elements in the circuit, and inability to
withstand additional annealing (loss of tensile strength of the
conductor through heating) may all contribute to finding emergency
ratings that are identical to normal ratings, although such ratings
would nonetheless be considered unique if they were developed using
appropriate technical inputs.\619\ Many commenters express support for
requirements to provide justifications when normal and emergency
ratings are identical, given that it may be appropriate in some
situations for normal and emergency ratings to be identical.\620\ TAPS
states that the result of any individual transmission owner decision
not to provide accurate emergency ratings may tie the hands of RTOs/
ISOs dealing with contingencies.\621\
---------------------------------------------------------------------------

    \616\ OMS Reply Comments at 11-12.
    \617\ Id. at 12.
    \618\ OMS Comments at 15.
    \619\ EPRI Comments at 7, 9-10.
    \620\ R Street Institute Comments at 3, 5; ACPA/SEIA Comments at
16-17; EDFR Comments at 6; TAPS Comments at 2.
    \621\ TAPS Comments at 18.
---------------------------------------------------------------------------

    277. Transmission owners indicate that they use different durations
for calculating emergency ratings, including hourly, daily, and two-day
ahead short-term emergency ratings by Entergy,\622\ up to 30 minutes
during post-contingency operations by APS,\623\ 30 minutes by
PacifiCorp,\624\ and four hours by PG&E.\625\ Exelon states that it
calculates four-hour emergency ratings, with long-term emergency and
short-term emergency ratings set equal unless a shorter duration
transmission line rating is feasible on the facility, as well as load
dump ratings for up to 15 minutes.\626\ Exelon notes that flexibility
in the duration of emergency ratings can be beneficial and some
equipment, such as phase angle regulators, can allow the transmission
owner to control the flow and avoid damage from shorter-term
ratings.\627\ R Street Institute notes that some transmission operators
use a 30 minute duration and others use two to four hour
durations.\628\ OMS argues that emergency ratings must accurately
reflect the capability of the transmission element for a standardized,
limited period of time.\629\ OMS also contends that the Commission
should require transmission providers to define what constitutes an
emergency rating in their region and how they should be used.\630\
---------------------------------------------------------------------------

    \622\ Entergy Comments at 4.
    \623\ APS Comments at 7.
    \624\ PacifiCorp Comments at 4.
    \625\ PG&E Comments at 12.
    \626\ Exelon Comments at 21.
    \627\ Id. at 20.
    \628\ R Street Institute Comments at 7.
    \629\ OMS Comments at 13-14.
    \630\ Id. at 15.
---------------------------------------------------------------------------

    278. RTOs/ISOs similarly indicate that they use different durations
for calculating emergency ratings, including long time emergency (four
hours for winter, 12 hours for summer), short time emergency (15
minutes), and drastic action limits (five minutes) in ISO-NE,\631\ up
to four hours in CAISO (with some transmission owners providing shorter
duration transmission line ratings),\632\ and 30 minutes in MISO.\633\
The SPP MMU recommends that emergency ratings be applicable on a
shorter-term basis, meaning less than four hours in SPP, to observe
limits of the equipment and prevent degradation.\634\ The SPP MMU does
not recommend requiring transmission owners to exceed normal ratings to
address challenges during sustained periods of contingencies or long
duration events, such as polar vortex conditions.\635\ Potomac
Economics recommends that any emergency ratings requirements specify
the maximum permissible duration to enhance RTOs/ISOs' situational
awareness and reliability.\636\
---------------------------------------------------------------------------

    \631\ ISO-NE Comments at 6.
    \632\ CAISO Comments at 1, 3.
    \633\ MISO Comments at 23.
    \634\ SPP MMU Comments at 13-14.
    \635\ Id. at 5.
    \636\ Potomac Economics Comments at 13.
---------------------------------------------------------------------------

    279. Many transmission owners express concern that the use of
emergency ratings could risk degrading the asset and reducing its
useful life.\637\ SDG&E states that it does not issue unique emergency
ratings for certain types of equipment due to the potential for
permanent damage.\638\ A few transmission owners note that the age and
condition of the facilities impact whether an emergency rating may risk
further damage to transmission equipment.\639\ Indicated PJM
Transmission Owners state that for some facilities, even minimal use of
emergency ratings can have a significant impact on the facility's
useful life.\640\ Indicated PJM Transmission Owners note that the
overuse of emergency ratings could cause asset degradation and in turn
increase costs to consumers as those facilities have to be upgraded or
replaced, while also having a negative impact on system
reliability.\641\ Both NRECA/LPPC and Entergy note that if conductors
violate sag requirements from the use of emergency ratings then they
pose a risk to public

safety and reliability.\642\ Entergy lists several risks from the use
of emergency ratings, including creep, elongation, and loss of
conductor strength as well as the fact that several factors that
determine emergency ratings cannot be known in advance, such as pre-
load current, pre-load temperature, contingency current, and
theoretical contingency steady state temperature.\643\ According to
EPRI, there are conditions when emergency ratings cannot be safely
used, including when other parts of the circuit are already overloaded
or when the conductor would be compromised or is too old.\644\ Entergy
states that emergency ratings are risker than, and have a significantly
greater potential to damage transmission equipment than, the use of
AARs; therefore, Entergy contends, emergency ratings should be used for
a short-term basis, on a limited number of facilities, and carefully
monitored.\645\ Exelon states that emergency ratings are acceptable for
a short duration, but warns that regular excessive loading will impact
a facility's useful life.\646\
---------------------------------------------------------------------------

    \637\ See, e.g., APS Comments at 7; Dominion Comments at 4; EEI
Comments at 17; Entergy Comments at 2; Exelon Comments at 22-23;
Indicated PJM Transmission Owners Comments at 16-17; ITC Comments at
12.
    \638\ SDG&E Comments at 4.
    \639\ EEI Comments at 17; Exelon Comments at 20.
    \640\ Indicated PJM Transmission Owners Comments at 17.
    \641\ Id. at 2-3; Entergy Comments at 15.
    \642\ NRECA/LPPC Comments at 25; Entergy Comments at 13.
    \643\ Entergy Comments at 13-14.
    \644\ EPRI Comments at 7.
    \645\ Entergy Comments at 11.
    \646\ Exelon Comments at 22-23.
---------------------------------------------------------------------------

    280. NRECA/LPPC argues that emergency ratings may not be
applicable, beneficial, or sustainable for all transmission lines.\647\
Indicated PJM Transmission Owners note that there is a balance between
the benefits of emergency ratings and the negative impacts of overuse
or misuse of emergency ratings.\648\ Indicated PJM Transmission Owners
claim that the use of emergency ratings may reduce costs to consumers
in some short-term cases but there is no evidence to support savings in
the long term and instead their use will likely increase transmission
costs.\649\ PacifiCorp asserts that implementing requirements for
emergency ratings on equipment other than transmission lines would
require voluminous amounts of data and additional databases and
personnel.\650\ EEI states that universal use of seasonal and emergency
ratings may provide only a negligible improvement beyond current
transmission line ratings.\651\ BPA asserts that it currently operates
to its maximum operating temperature limits, and therefore would see no
increase in capacity from the use of emergency ratings.\652\ Dominion
states that it does not use emergency ratings for ATC calculations on
the Dominion Energy South Carolina system because emergency ratings are
for short durations and specific circumstances.\653\
---------------------------------------------------------------------------

    \647\ NRECA/LPPC Comments at 25.
    \648\ Indicated PJM Transmission Owners Comments at 3.
    \649\ Id. at 15-17.
    \650\ PacifiCorp Comments at 5.
    \651\ EEI Comments at 4.
    \652\ BPA Comments at 7.
    \653\ Dominion Comments at 13.
---------------------------------------------------------------------------

    281. On the other hand, PacifiCorp states that it has seen no
detriment to reliability from using emergency ratings for their
transmission lines for over a decade.\654\ WAPA states that using
emergency ratings for short durations does not pose too much risk to
the integrity and condition of the device.\655\
---------------------------------------------------------------------------

    \654\ PacifiCorp Comments at 4.
    \655\ WAPA Comments at 8.
---------------------------------------------------------------------------

    282. Several commenters note methods to manage the impact of
emergency ratings on equipment. MISO recommends that the Commission
allow transmission owners to establish reasonable and supported
reliability margins where higher emergency ratings are established such
as: (1) A safety margin to ensure the transmission line rating is less
than the relay trip rating and maximum power transfer rating; and (2)
allowing defined, reasonable limits on the duration and frequency of
emergency ratings.\656\ Potomac Economics argues that emergency ratings
are designed to permit temporary use without equipment damage, such as
significant annealing, and states that if post-contingent responses are
in question, RTOs/ISOs can and do develop special operating guides to
specify the operating conditions required to use emergency ratings and
maintain reliability.\657\ Potomac Economics contends that transmission
owners should continue to have the authority and responsibility to
determine reliable emergency ratings, but states that vague or general
concerns should not forestall requirements to provide emergency ratings
for most facilities.\658\ Tangibl also notes that sag limitations can
be addressed in some cases.\659\
---------------------------------------------------------------------------

    \656\ MISO Comments at 26.
    \657\ Potomac Economics Comments at 14.
    \658\ Id. at 14.
    \659\ Tangibl Comments at 5.
---------------------------------------------------------------------------

    283. Several commenters identify benefits of emergency ratings use,
including increased transfer capability and relieving congestion, which
can be a valuable reliability tool \660\ and also lead to lower prices
for customers.\661\ Several other commenters point to more efficient
use of the transmission system as a result of emergency ratings.\662\
Potomac Economics' analysis, for example, found the potential for $48.1
million in 2019 and $49.5 million in 2020 in savings in MISO alone that
could have been realized by using emergency ratings for facilities for
which only normal ratings were provided.\663\
---------------------------------------------------------------------------

    \660\ EDFR Comments at 6.
    \661\ ISO-NE Comments at 10; New England State Agencies Comments
at 21; PacifiCorp Comments at 4; Potomac Economics Comments at 8,
10; WAPA Comments at 8.
    \662\ Tangibl Comments at 5; EDFR Comments at 6; ACP Comments at
16-17.
    \663\ Potomac Economics Comments at 8.
---------------------------------------------------------------------------

    284. Indicated PJM Transmission Owners express concern with Potomac
Economics' emergency rating cost and benefit analysis, though, noting
the absence of increased operations, maintenance, and capital costs
associated with running the system at emergency conditions.\664\ MISO
Transmission Owners similarly express concern with Potomac Economics'
analysis and state that the Commission should not rely on that
analysis, including estimates that the lack of unique emergency ratings
by some transmission owners in MISO contributed to $62-68 million in
extra congestion costs.\665\
---------------------------------------------------------------------------

    \664\ Indicated PJM Transmission Owners Comments at 16.
    \665\ MISO Transmission Owners Comments at 43-44.
---------------------------------------------------------------------------

    285. In its reply comments, Potomac Economics contends that their
estimations are conservative and emphasize the importance of using
emergency ratings, since the cost savings are comparable to the
benefits of AARs.\666\ Potomac Economics also notes that requirements
to implement emergency ratings would still be placed on transmission
owners, and they retain discretion in setting emergency ratings based
on reliability, subject to transparency and their reasonableness.\667\
The SPP MMU states that accurate emergency ratings would make
transmission congestion more uniformly defined throughout the
footprint, thus helping reduce congestion and creating more uniform
prices.\668\ Potomac Economics argues that emergency ratings provide
additional benefits beyond more efficient use of the transmission
system and enhanced reliability, including increased operational
awareness for RTOs/ISOs and other transmission providers regarding the
capability of the transmission facilities.\669\ New England State
Agencies argue that accurate emergency ratings could prevent
unnecessary curtailment of generation, and in extreme circumstances,
avoid

shedding load.\670\ R Street Institute similarly contends that the
benefits of emergency ratings go beyond the production cost savings
estimated by Potomac Economics and include avoided customer
outages.\671\ R Street Institute notes that the cost of additional wear
must consider the frequency and duration of emergency rating use, which
is usually uncommon and brief.\672\ EPRI contends that emergency
ratings will provide less benefits when AARs or DLRs are already used
because the starting temperature of the conductor may be higher than
under static ratings.\673\
---------------------------------------------------------------------------

    \666\ Potomac Economics Reply Comments at 6-7.
    \667\ Id. at 11.
    \668\ SPP MMU Comments at 13.
    \669\ Potomac Economics Comments at 8, 10.
    \670\ New England State Agencies Comments at 21.
    \671\ R Street Institute Comments at 8.
    \672\ Id. at 8.
    \673\ EPRI Comments at 8.
---------------------------------------------------------------------------

    286. ACPA/SEIA state that emergency ratings are important to ensure
safe operating conditions and because they often determine the loading
allowed on constrained facilities even during normal conditions.\674\
Tangibl also contends that unique emergency ratings may reveal
potential low-cost system upgrades, allow more efficient transmission
planning, reduce the time and cost of interconnection studies, and
reduce barriers to the development of new generation.\675\
Additionally, Tangibl notes that when unique emergency ratings are not
used, it potentially causes needless curtailments for renewable energy
projects.\676\ R Street Institute contends that emergency ratings
should be required regardless of RTO/ISO participation, to avoid a
disincentive to RTO/ISO membership, and that inaccurate emergency
ratings are unjust and unreasonable.\677\ R Street Institute recognizes
that the record on emergency ratings is sparse and that implementing
emergency ratings may be prone to operator error, but notes that they
are sometimes used implicitly during emergency conditions.\678\
---------------------------------------------------------------------------

    \674\ ACPA/SEIA Comments at 16-17.
    \675\ Tangibl Comments at 4-6.
    \676\ Id. at 5-6.
    \677\ R Street Institute Comments at 5-7.
    \678\ Id. at 3, 7.
---------------------------------------------------------------------------

    287. Almost all transmission owners that discussed emergency
ratings in their comments agree that emergency ratings should be used
judiciously for reliability reasons, and not regularly for economics,
to access additional transfer capability.\679\ Entergy states that
emergency ratings can be used only in real-time operations and should
not be used in markets.\680\ Indicated PJM Transmission Owners agree
with the NOPR statement that emergency ratings allow for higher
operating limits, and thus, more efficient system commitment and
dispatch solutions, but argues that emergency ratings should be used
only during emergencies and not to increase capacity during normal
operating conditions due to the risks of wear and additional
costs.\681\ Dominion and EEI advocate for using emergency ratings only
on an as-needed basis.\682\ Exelon contends that the benefits of using
emergency ratings under emergency conditions outweigh the costs.\683\
---------------------------------------------------------------------------

    \679\ See, e.g., Dominion Comments at 13; Entergy Comments at 2;
Exelon Comments at 22; Indicated PJM Transmission Owners Comments at
17.
    \680\ Entergy Comments at 2.
    \681\ Indicated PJM Transmission Owners Comments at 15-16.
    \682\ Dominion Comments at 13; EEI Comments at 16-17.
    \683\ Exelon Comments at 22.
---------------------------------------------------------------------------

    288. Potomac Economics argues that the Commission should clarify
that the unique emergency ratings be applied for contingent