Managing Transmission Line Ratings, 2244-2307 [2021-27735]
Download as PDF
2244
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
Federal Energy Regulatory
Commission
First Street NE, Washington, DC 20426,
(202) 502–8099, Ryan.Stroschein@
ferc.gov.
SUPPLEMENTARY INFORMATION:
18 CFR Part 35
Table of Contents
[Docket No. RM20–16–000; Order No. 881]
Paragraph Numbers
I. Introduction 1
II. Background 13
III. Need for Reform 17
A. NOPR Proposal 17
B. Comments 23
C. Commission Determination 29
IV. Discussion 40
A. Transmission Line Ratings Definition 40
1. NOPR Proposal 40
2. Comments 42
3. Commission Determination 44
B. Ambient-Adjusted Ratings 47
1. AAR Definition and Transmission
Provider Obligations 47
2. Specific AAR Implementation
Requirements 104
3. Other AAR Implementation Issues 151
C. Seasonal Line Ratings 193
1. Seasonal Line Ratings Requirements 193
2. Seasonal Line Rating Implementation
Requirements 204
D. Exceptions and Alternate Ratings 217
1. NOPR Proposal 217
2. Comments 219
3. Commission Determination 227
E. Dynamic Line Ratings 235
1. Dynamic Line Ratings Definition 235
2. DLR Requirements 240
3. Extending to non-RTO/ISO
Transmission Providers the Requirement
To Allow Transmission Owners To
Electronically Update Transmission Line
Ratings at Least Hourly 256
4. DLR Studies 259
5. Advanced Transmission Technology
Cost Recovery 265
F. Emergency Ratings 267
1. NOPR Request for Comments 267
2. Emergency Ratings Definition and
Implementation Requirements 269
3. Equipment for Which Emergency
Ratings Must Be Calculated 304
G. Transparency 306
1. NOPR Proposal 306
2. Comments 309
3. Commission Determination 330
H. Other Miscellaneous Issues 344
1. Comments 344
2. Commission Determination 346
I. Compliance 348
1. NOPR Proposal 348
2. Comments 351
3. Commission Determination 360
V. Information Collection Statement 364
VI. Environmental Analysis 383
VII. Regulatory Flexibility Act 384
VIII. Document Availability 399
IX. Effective Date and Congressional
Notification 402
Appendix A: Abbreviated Names of
Commenters
Appendix B: Pro Forma Open Access
Transmission Tariff
DEPARTMENT OF ENERGY
Managing Transmission Line Ratings
Federal Energy Regulatory
Commission, Department of Energy.
ACTION: Final rule.
AGENCY:
The Federal Energy
Regulatory Commission (Commission) is
revising both the pro forma Open
Access Transmission Tariff and the
Commission’s regulations under the
Federal Power Act to improve the
accuracy and transparency of electric
transmission line ratings. Specifically,
the Commission is requiring: Public
utility transmission providers to
implement ambient-adjusted ratings on
the transmission lines over which they
provide transmission service; regional
transmission organizations (RTO) and
independent system operators (ISO) to
establish and implement the systems
and procedures necessary to allow
transmission owners to electronically
update transmission line ratings at least
hourly; public utility transmission
providers to use uniquely determined
emergency ratings; public utility
transmission owners to share
transmission line ratings and
transmission line rating methodologies
with their respective transmission
provider(s) and with market monitors in
RTOs/ISOs; and public utility
transmission providers to maintain a
database of transmission owners’
transmission line ratings and
transmission line rating methodologies
on the transmission provider’s Open
Access Same-Time Information System
site or other password-protected
website.
SUMMARY:
This rule will become effective
March 14, 2022.
FOR FURTHER INFORMATION CONTACT:
Dillon Kolkmann (Technical
Information), Office of Energy Policy
and Innovation, Federal Energy
Regulatory Commission, 888 First Street
NE, Washington, DC 20426, (202) 502–
8650, Dillon.kolkmann@ferc.gov.
Mark Armamentos (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, (202) 502–8103,
Mark.armamentos@ferc.gov.
Ryan Stroschein (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
jspears on DSK121TN23PROD with RULES2
DATES:
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
I. Introduction
1. In this final rule, the Federal
Energy Regulatory Commission
PO 00000
Frm 00002
Fmt 4701
Sfmt 4700
(Commission) is adopting reforms,
pursuant to section 206 of the Federal
Power Act (FPA),1 to the pro forma
Open Access Transmission Tariff
(OATT) and the Commission’s
regulations to improve the accuracy and
transparency of electric transmission
line ratings used by transmission
providers.2 As discussed below, we
adopt the Commission’s proposal in the
Notice of Proposed Rulemaking (NOPR)
to define a transmission line rating as
‘‘the maximum transfer capability of a
transmission line, computed in
accordance with a written transmission
line rating methodology and consistent
with Good Utility Practice,3 considering
the technical limitations on conductors
and relevant transmission equipment
(such as thermal flow limits), as well as
technical limitations of the
Transmission System (such as system
voltage and stability limits).’’ 4
2. The transfer capability of a
transmission line can change with
ambient weather conditions. Thus, a
transmission line rating can be
determined by taking into consideration
the physical characteristics of the
conductor and making assumptions
about ambient weather conditions to
determine the maximum amount of
power that can flow through a
conductor while keeping the conductor
under its maximum operating
temperature. Conductor temperatures
are impacted by a variety of factors,
1 16
U.S.C. 824e.
this final rule, we use transmission provider
to mean any public utility that owns, operates, or
controls facilities used for the transmission of
electric energy in interstate commerce. 18 CFR 37.3
(2021). Therefore, unless otherwise noted,
‘‘transmission provider’’ refers only to public utility
transmission providers. Furthermore, the term
‘‘public utility’’ as found in section 201(e) of the
FPA means ‘‘any person who owns or operates
facilities subject to the jurisdiction of the
Commission under this subchapter . . .’’ 16 U.S.C.
824(e).
3 The Commission’s pro forma OATT defines
Good Utility Practice as: ‘‘[a]ny of the practices,
methods and acts engaged in or approved by a
significant portion of the electric utility industry
during the relevant time period, or any of the
practices, methods and acts which, in the exercise
of reasonable judgment in light of the facts known
at the time the decision was made, could have been
expected to accomplish the desired result at a
reasonable cost consistent with good business
practices, reliability, safety and expedition. Good
Utility Practice is not intended to be limited to the
optimum practice, method, or act to the exclusion
of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region,
including those practices required by Federal Power
Act section 215(a)(4).’’ Pro forma OATT section
1.15.
4 The definition also states, ‘‘Relevant
transmission equipment may include, but is not
limited to, circuit breakers, line traps, and
transformers.’’ Managing Transmission Line
Ratings, Notice of Proposed Rulemaking, 86 FR
6420 (Jan. 21, 2021), 173 FERC ¶ 61,165, at P 85
(2020) (NOPR).
2 In
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
including ambient air temperatures.
Increases in ambient air temperatures
tend to increase a transmission line’s
operating temperature and lower a
transmission line’s rating, while lower
ambient air temperatures tend to lower
a transmission line’s operating
temperature and increase the
transmission line’s rating.
3. Many transmission line ratings are
currently calculated based on
assumptions about ambient conditions
that are not regularly adjusted and
therefore do not accurately reflect the
near-term transfer capability of the
transmission system.5 For example,
when seasonal or static temperature
assumptions exceed actual ambient air
temperatures, transmission line ratings
may understate the near-term transfer
capability that the transmission system
can actually provide, leading to
unnecessarily restricted flows and
potentially increased congestion costs.
Alternatively, when ambient air
temperatures exceed seasonal or static
temperature assumptions, transmission
line ratings may overstate the near-term
transfer capability of the system,
creating potential reliability and safety
problems. In either case, the continued
use of seasonal and static temperature
assumptions may result in transmission
line ratings that do not accurately
represent the transfer capability of the
transmission system. We find that
transmission line ratings and the rules
by which they are established are
practices that directly affect the cost of
wholesale energy, capacity, and
ancillary services, as well as the cost of
delivering wholesale energy to
transmission customers; thus, we find
that inaccurate transmission line ratings
result in Commission-jurisdictional
rates that are unjust and unreasonable.
4. To address these issues with
respect to transmission service in the
near term, we adopt, with certain
modifications, the NOPR proposal’s
definition of an ambient-adjusted rating
(AAR) as a transmission line rating that:
(1) Applies to a time period of not
greater than one hour; (2) reflects an upto-date forecast of ambient air
temperature across the time period to
which the rating applies; (3) reflects the
absence of solar heating during
nighttime periods where the local
sunrise/sunset times used to determine
daytime and nighttime periods are
updated at least monthly, if not more
frequently; and (4) is calculated at least
5 Federal Energy Regulatory Commission, Staff
Paper, Managing Transmission Line Ratings, Docket
No. AD19–15–000 (Aug. 2019) (Commission Staff
Paper), https://www.ferc.gov/sites/default/files/
2020-05/tran-line-ratings.pdf.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
each hour, if not more frequently.6
Additionally, we adopt two
requirements for greater use of AARs.
First, we require that transmission
providers—including RTOs/ISOs for
transmission service at their seams 7—
use AARs as the basis for evaluation of
transmission service requests that will
end within 10 days of the request.
Second, we require that transmission
providers—including RTOs/ISOs for
transmission service at their seams—use
AARs as the basis for their
determination of the necessity of certain
curtailment, interruption, or redispatch
of transmission service anticipated to
occur within those 10 days.
5. To address these issues with
respect to transmission service in the
longer term, we require that
transmission providers use seasonal line
ratings as the basis for evaluation of
transmission service requests ending
more than 10 days from the date of the
request. We also require that
transmission providers use seasonal line
ratings as the basis for the determination
of the necessity of curtailment,
interruption, or redispatch of
transmission service that is anticipated
to occur more than 10 days in the
future.8
6. For both longer term and shorter
term transmission service, we adopt
exceptions to the AAR and seasonal line
rating requirements to accommodate
instances in which the transmission line
rating of a transmission line is not
affected by ambient air temperature and
instances in which a transmission
provider reasonably determines,
consistent with good utility practice,
that the use of a temporary alternate
rating is necessary to ensure the safety
and reliability of the transmission
system.9
6 18 CFR 35.28(b)(10) (2021); Pro Forma OATT
attach. M, AAR Definition.
7 The term ‘‘seam’’ is commonly used by the
industry to indicate the border between two
transmission provider’s service territories. Service
at the seam can take different forms, such as pointto-point service or market-to-market service.
8 The use of seasonal line ratings for long-term
requests for transmission service and as the basis
for the determination of curtailment, interruption,
or redispatch is currently standard practice.
However, as discussed below, we adopt certain
reforms to change seasonal line rating
implementation.
9 Because the new requirements related to AARs
and seasonal line ratings are implemented through
the new pro forma OATT Attachment M, these
requirements are placed upon transmission
providers. However, we recognize that transmission
owners (not transmission providers) determine
transmission line ratings. In many instances, the
transmission provider and transmission owner are
the same entity. However, below in Section
IV.B.2.b, we discuss compliance within RTOs/ISOs,
where the transmission provider and transmission
owner are separate entities.
PO 00000
Frm 00003
Fmt 4701
Sfmt 4700
2245
7. In certain situations, using
transmission line ratings that are based
on factors beyond forecasted ambient air
temperatures and the presence or
absence of solar heating may lead to
greater accuracy. For example, the use
of dynamic line ratings (DLRs) presents
opportunities for transmission line
ratings that may be more accurate than
those established with AARs. Unlike
AARs, DLRs are based not only on
forecasted ambient air temperatures and
the presence or absence of solar heating,
but also on other weather conditions
such as (but not limited to) wind, cloud
cover, solar heating intensity (instead of
mere daytime/nighttime distinctions
used in AARs), and precipitation, and/
or on transmission line conditions such
as tension or sag. As discussed below,
we adopt the NOPR’s proposed
definition of DLR as a transmission line
rating that: (1) Applies to a time period
of not greater than one hour; and (2)
reflects up-to-date forecasts of inputs
such as (but not limited to) ambient air
temperature, wind, solar heating
intensity, transmission line tension, or
transmission line sag.
8. Although some transmission
owners have adopted the use of DLRs
for individual transmission lines, there
is not currently widespread use of DLRs.
While DLRs can represent more accurate
transmission line ratings than AARs,
based on the record in this proceeding,
we decline to mandate DLR
implementation in this final rule. We
instead incorporate the record in this
proceeding on DLRs into new Docket
No. AD22–5–000, which we open to
further explore DLR implementation.
9. One factor that may contribute to
the limited deployment of DLRs by
transmission owners is that the RTOs/
ISOs that operate a large portion of the
transmission system in the United
States and oversee organized wholesale
electric markets may not be able to
automatically incorporate frequently
updated transmission line ratings such
as DLRs into their operating and market
models. Although the record does not
support a mandate for DLR
implementation at this time, we require
RTOs/ISOs to establish and maintain
the systems and procedures necessary to
allow transmission owners in their
regions to electronically update
transmission line ratings on at least an
hourly basis.
10. In addition to reforms to improve
the accuracy of transmission line ratings
used during normal (pre-contingency)
operations,10 we revise the pro forma
10 The North American Electric Reliability
Corporation (NERC) Glossary defines ‘‘normal
E:\FR\FM\13JAR2.SGM
Continued
13JAR2
2246
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
OATT to require transmission providers
to use uniquely determined emergency
ratings for contingency analysis in the
operations horizon and in postcontingency simulations of
constraints.11 Such uniquely
determined emergency ratings must also
incorporate an adjustment for ambient
air temperature and daytime/nighttime
solar heating, consistent with our AAR
requirements for normal ratings. Most
transmission equipment can withstand
high currents for short periods of time
without sustaining damage. Emergency
ratings reflect this technical capability,
defining the specific additional current
that a transmission line can withstand
and for what duration the transmission
line can withstand that additional
current without sustaining damage.
Because emergency ratings reflect this
capability, uniquely determined
emergency ratings will ensure more
accurate transmission line ratings.
11. Finally, we adopt four
requirements to enhance transparency.
First, we require public utility
transmission owners to share
transmission line ratings and
methodologies with their transmission
provider(s) and with market monitors in
RTOs/ISOs. Second, we require
transmission providers to share their
transmission owners’ transmission line
ratings and methodologies with any
transmission provider(s) upon request.
Third, we require transmission
providers to maintain a database of their
transmission owners’ transmission line
ratings and methodologies on the
transmission provider’s Open Access
Same-Time Information System (OASIS)
site or another password-protected
website. Fourth, we require
transmission providers to post on
OASIS or another password-protected
website any uses of exceptions or
temporary alternate ratings. Availability
of this additional information on
transmission line ratings and their
methodologies will facilitate more costeffective decisions by transmission
customers and more accurate
transmission line ratings. We find that
these transparency reforms will ensure
that prices reflect the true cost of the
rating’’ as: ‘‘[t]he rating as defined by the equipment
owner that specifies the level of electrical loading
. . . that a system, facility, or element can support
or withstand through the daily demand cycles
without loss of equipment life.’’ NERC, Glossary of
Terms Used in NERC Reliability Standards (June 28,
2021), https://www.nerc.com/pa/Stand/
Glossary%20of%20Terms/Glossary_of_Terms.pdf.
11 As discussed below in Section IV.F.2.b,
uniquely determined means the ratings are
determined based on assumptions that reflect the
specific, finite duration of emergency ratings, as
opposed to using assumptions used to calculate
normal ratings.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
wholesale service being provided and
thereby are necessary to ensure just and
reasonable wholesale rates.
12. We require each transmission
provider to submit a compliance filing
within 120 days of the effective date of
this final rule revising their OATT to
incorporate pro forma OATT
Attachment M. We further require that
all requirements adopted herein be fully
implemented no later than three years
from the compliance filing due date.
II. Background
13. In August 2019, Commission staff
issued a paper entitled ‘‘Managing
Transmission Line Ratings,’’ which
drew upon Commission staff outreach
conducted in spring 2019 with RTOs/
ISOs, transmission owners, and trade
groups, as well as staff participation in
a November 2017 Idaho National
Laboratory workshop. The report
included background on common
transmission line rating approaches,
current practices in RTOs/ISOs, a
review of pilot projects, and a
discussion of potential improvements.12
14. On September 10 and 11, 2019,
Commission staff convened a technical
conference (September 2019 Technical
Conference) to discuss what
transmission line ratings and related
practices might constitute best practices,
and what, if any, Commission action in
these areas might be appropriate. In
particular, the September 2019
Technical Conference covered issues
such as: (1) Common transmission line
rating methodologies; (2) AAR and DLR
implementation benefits and challenges;
(3) the ability of RTOs/ISOs to accept
and use DLRs; and (4) the transparency
of transmission line rating
methodologies.13
15. In October 2019, the Commission
requested comments on questions that
arose from the September 2019
Technical Conference.14 In response,
commenters addressed issues related to
AARs and DLRs, emergency ratings, and
transparency, as discussed below.
16. On November 19, 2020, the
Commission issued the NOPR in this
proceeding, proposing to amend the pro
forma OATT and its regulations under
the FPA to improve the accuracy and
transparency of transmission line
ratings.15 Specifically, the Commission
proposed a new pro forma OATT
12 Commission Staff Paper, https://www.ferc.gov/
sites/default/files/2020-05/tran-line-ratings.pdf.
13 Supplemental Notice of Technical Conference,
Docket No. AD19–15–000 (Sep. 4, 2019).
14 Notice Inviting Post-Technical Conference
Comments, Docket No. AD19–15–000 (Oct. 2, 2019).
15 Managing Transmission Line Ratings, Notice of
Proposed Rulemaking, 86 FR 6420 (Jan. 21, 2021),
173 FERC ¶ 61,165 (2020) (NOPR).
PO 00000
Frm 00004
Fmt 4701
Sfmt 4700
Attachment M ‘‘Transmission Line
Ratings’’ to require transmission
providers to implement AARs on the
transmission lines over which they
provide transmission service. The
Commission also proposed revisions to
its regulations to require RTOs/ISOs to
establish and implement the systems
and procedures necessary to allow
transmission owners to electronically
update transmission line ratings at least
hourly and to require transmission
owners to share transmission line
ratings and transmission line rating
methodologies with their transmission
provider(s) and, in RTOs/ISOs, with
their market monitor(s). The
Commission received comments from
56 entities on the NOPR proposals from
a diverse set of stakeholders.16
III. Need for Reform
A. NOPR Proposal
17. In the NOPR, the Commission
preliminarily found that transmission
line ratings and the rules by which they
are established are practices that
directly affect the cost of wholesale
energy, capacity, and ancillary services,
as well as the cost of delivering
wholesale energy to transmission
customers. The Commission explained
that, because of the relationship
between transmission line ratings and
costs, inaccurate transmission line
ratings may result in Commissionjurisdictional rates that are unjust and
unreasonable.17
18. The Commission explained that
most transmission owners implement
seasonal or static transmission line
rating methodologies based on
conservative, worst-case assumptions,
such as high temperatures that are likely
to occur over the longer term, but that
often do not reflect the true near-term
transfer capability of transmission
facilities. Thus, the Commission
reasoned, seasonal and static line
ratings fail to reflect the true cost of
delivering wholesale energy to
transmission customers, and
incorporating near-term forecasts of
ambient air temperatures in
transmission line ratings would more
accurately reflect the actual cost of
delivering wholesale energy to
transmission customers.18
19. Because actual ambient air
temperatures are usually not as high as
the ambient air temperatures
conservatively assumed in seasonal and
static line ratings, the Commission
16 See Appendix A for a list of entities that
submitted comments and the shortened names used
throughout this final rule to describe those entities.
17 NOPR, 173 FERC ¶ 61,165 at P 38.
18 Id. P 39.
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
observed that updating transmission
line ratings used in near-term
transmission service to reflect actual
ambient air temperatures usually results
in increased system transfer capability
and, in turn, lower costs for consumers.
However, the Commission also observed
that seasonal and static line ratings can
at times assume temperatures that are
lower than the actual ambient air
temperatures in the short term. In doing
so, the Commission noted that seasonal
or static transmission line rating
methodologies can at times result in
transmission line ratings that reflect
more transfer capability than physically
exists. The Commission observed that
this overstatement of transmission line
ratings similarly results in wholesale
energy rates that fail to reflect the actual
cost of delivering wholesale energy to
transmission customers, and may also
create reliability and safety problems,
risk damage to equipment, and prevent
occurrences of rates for scarcity pricing
or transmission constraint penalty
factors.19
20. Regarding DLR implementation,
the Commission observed that some
RTOs/ISOs may rely on software and
systems that cannot accommodate
transmission line ratings that frequently
change, such as DLRs, and that, without
reflecting such frequent changes to
transmission line ratings, such software
may serve as a barrier that prevents
transmission owners in RTOs/ISOs from
implementing DLRs, which can better
reflect the actual transfer capability of
the transmission system. The
Commission explained that, in addition
to ambient air temperature, DLRs
incorporate additional inputs, including
wind, cloud cover, solar heating, and
precipitation, as well as transmission
line conditions such as tension and sag.
DLRs thereby provide transmission line
ratings that are closer to the true thermal
transmission line limit than AARs,
which can result in rates that even more
accurately reflect the costs of delivering
wholesale energy to transmission
customers than relying on AARs.
However, the Commission explained
that the potential inability of RTOs/ISOs
to automatically accept and use DLRs
provided by transmission owners may
prevent RTO/ISO markets from
benefiting from the more accurate
representation of current RTO/ISO
system conditions. In turn, by ensuring
RTO/ISO market models can
incorporate more accurate
representations of system conditions
when transmission owners use DLRs,
RTO/ISO markets would produce prices
that more accurately reflect the costs of
delivering wholesale energy to
transmission customers. For this reason,
the Commission also preliminarily
found in the NOPR that current
transmission line rating practices in
RTOs/ISOs that do not permit the
acceptance of DLRs from transmission
owners may result in rates that do not
reflect the actual costs of delivering
wholesale energy to transmission
customers.20
21. Regarding emergency ratings, the
Commission found that current
transmission line rating practices may
fail to use emergency ratings, and in
failing to do so, may result in
transmission line ratings that do not
accurately reflect the near-term transfer
capability of the system. This, in turn,
may result in rates that do not reflect
actual costs of delivering wholesale
energy to transmission customers. In
support, the Commission stated that
transmission owners often develop two
sets of transmission line ratings for most
facilities: Normal ratings that can be
safely used continuously, and
emergency ratings that can be used for
a specified shorter period of time,
typically during post-contingency
operations. Because emergency ratings
are a more accurate representation of the
flow limits over shorter timeframes, the
Commission preliminarily found that
their use in models of post-contingency
flows may produce prices that more
accurately reflect actual costs of
delivering wholesale energy to
transmission customers.21
22. Finally, in the NOPR, the
Commission preliminarily found that,
by preventing transmission providers
and, in RTO/ISOs, market monitors
from having the opportunity to validate
transmission line ratings in situations
where a transmission provider serves
any transmission owners that are not
itself, current levels of transparency into
transmission line ratings and
transmission line rating methodologies
may result in unjust and unreasonable
rates. The Commission observed that a
consequence of a lack of transparency
could be inaccurate near-term
transmission line ratings, which may
result in rates that do not accurately
reflect congestion and reserve costs on
the system. As one example, the
Commission stated that, without
knowing the basis for a given
transmission line rating that frequently
binds and elevates prices, a
transmission provider and/or market
monitor cannot determine whether the
transmission line rating is accurately
calculated and therefore whether unjust
20 Id.
19 Id.
P 42.
VerDate Sep<11>2014
21 Id.
18:58 Jan 12, 2022
Jkt 256001
PO 00000
P 43.
PP 44–46.
Frm 00005
Fmt 4701
Sfmt 4700
2247
and unreasonable wholesale rates are
being created through use of inaccurate
transmission line ratings.22
B. Comments
23. Commenters overwhelmingly
agree with the Commission’s
preliminary finding that transmission
line ratings and the rules by which they
are established are practices that
directly affect the cost of wholesale
energy, capacity, and ancillary services,
as well as the cost of delivering
wholesale energy to transmission
customers.23 Commenters also agree
with the Commission’s preliminary
finding that, because of the relationship
between transmission line ratings and
wholesale energy costs, inaccurate
transmission line ratings may result in
Commission-jurisdictional rates that are
unjust and unreasonable.24
24. The majority of commenters
representing state agencies support the
Commission’s basis for reform. New
England State Agencies explain that,
because transmission lines are used to
control the amount of energy on electric
power systems, transmission line ratings
affect the price of electric power as well
as the reliability of the electric grid.25
OMS also agrees with the Commission’s
preliminary finding that transmission
line ratings directly affect wholesale
energy costs and artificially limit
transfers within and between regions,
stating that such a conclusion is obvious
and correct.26 OMS further contends
that the slow pace of action on this issue
by RTOs/ISOs and transmission owners
makes the issue ripe for Commission
action.27 Ohio FEA maintains that
transmission line ratings have a direct
and significant influence on wholesale
energy and capacity markets and,
therefore, must be accurate. Ohio FEA
further argues that inaccurate
transmission line ratings may also cause
Locational Deliverability Areas (LDAs)
to unnecessarily constrain in the
22 Id.
P 47.
Comments at 3; Ohio FEA Comments at
6; New England State Agencies Comments at 8;
OMS Comments at 6; Potomac Economics
Comments at 5; CAISO DMM Comments at 4; SPP
MMU Comments at 1–2; R Street Institute
Comments at 2; Industrial Customer Organizations
Comments at 11–12; TAPS Comments at 5–6;
WATT Comments at 3–5; Certain TDU Comments
at 4–5; Clean Energy Parties Comments at 2–3;
EDFR Comments at 3.
24 SPP MMU Comments at 1–2; Potomac
Economics Comments at 5; CAISO DMM Comments
at 4; Industrial Customer Organizations Comments
at 11–12; TAPS Comments at 5–6; Certain TDU
Comments at 4–5; Clean Energy Parties Comments
at 2–3.
25 New England State Agencies Comments at 8.
26 OMS Comments at 6.
27 OMS Reply Comments at 2–3.
23 AEP
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
2248
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
capacity market, resulting in higher
capacity prices.28
25. Each of the commenting market
monitors supports the Commission’s
basis for reform. For example, Potomac
Economics agrees with the
Commission’s finding that inaccurate
transmission line ratings may result in
rates that are not just and reasonable
and notes that facility ratings are used
in virtually every aspect of electricity
markets and system operations. Potomac
Economics further avers that
transmission line ratings determine the
transmission limits input into market
models, which, in turn, determine the
commitment and dispatch needed to
satisfy load and manage congestion.
Potomac Economics further explains
that underestimated transmission line
ratings cause inefficient operations,
higher congestion, reduced transmission
availability, higher costs, higher
renewable energy curtailments, and a
greater perceived need for new
transmission facilities.29 The SPP MMU
also agrees with the Commission’s
assertion that transmission line ratings
can directly affect the cost of producing
wholesale energy, capacity, and
ancillary services, as well as the cost of
delivering such products. The SPP
MMU explains that the cost of
congestion is directly impacted by
transmission line ratings and that
inaccurate transmission line ratings
cause price distortions, which may
result in unjust and unreasonable
rates.30 The CAISO DMM also agrees
with the Commission’s assessment that
transmission line ratings and the rules
by which they are established directly
impact the cost of wholesale energy
delivery and related services, explaining
that static or seasonal line ratings can
lead to increased costs when their
assumptions are not realized, which
may be inefficient and can result in
excess cost paid by load.31
26. Other commenters also support
the Commission’s basis for reform. R
Street Institute states that the
Commission’s problem statement is
sound, explaining that transmission line
ratings are chronically understated
because they do not reflect current
weather conditions, and as a result,
according to R Street Institute, fail to
allow for significant cost savings.32
Industrial Customer Organizations state
that transmission line ratings and
associated rules directly affect the cost
of wholesale energy, capacity, and
28 Ohio
FEA Comments at 6.
Economics Comments at 5.
30 SPP MMU Comments at 1–2.
31 CAISO DMM Comments at 4.
32 R Street Institute Comments at 2.
29 Potomac
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
ancillary services, and the cost of
delivering wholesale energy to
transmission customers, and the
rulemaking is therefore consistent with
the Commission’s authority and
obligations under the FPA.33 TAPS
states that reliance on static or seasonal
line ratings inflicts unnecessary costs on
consumers and that AAR deployment
can provide significant benefits to
consumers.34 WATT explains that
accurate transmission line ratings lower
costs for consumers.35 Certain TDUs
assert that enhanced transmission line
ratings, including AARs and DLRs, are
tools that maximize the efficiency of the
existing transmission system and lower
costs for consumers.36
27. Finally, clean energy and
generator representatives also support
the Commission’s basis for reform.37 For
example, Clean Energy Parties conclude
that, due to the impact that transmission
line ratings have on wholesale rates
requirements, accurate transmission line
ratings are consistent with the
Commission’s mandate under sections
205 and 206 of the FPA.38
28. However, NYTOs question the
Commission’s legal standing to regulate
transmission line ratings, noting that the
U.S. Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) found
that there are limits to the Commission’s
FPA section 206 jurisdiction over
‘‘practices’’ and that the term may not
include all utility operations.39 NYTOs
note that the Commission’s authority to
regulate transmission planning was
upheld on appeal but that Order No.
1000 40 is not prescriptive; therefore,
NYTOs request that the Commission
similarly allow utilities to make their
own decisions related to advanced line
rating technologies.41
C. Commission Determination
29. We find that transmission line
ratings, and the rules by which they are
established, are practices that directly
affect the rates for the transmission of
33 Industrial Customer Organizations Comments
at 11–12.
34 TAPS Comments at 5–6.
35 WATT Comments at 3–5.
36 Certain TDUs Comments at 4.
37 Clean Energy Parties Comments at 2–3; EDFR
Comments at 3.
38 Clean Energy Parties Comments at 2–3.
39 NYTOs Comments at 9 (referencing Cal. Indep.
Sys. Operator Corp. v. FERC, 372 F.3d 395, 402
(D.C. Cir. 2004)).
40 Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public
Utilities, Order No. 1000, 77 FR 32184 (May 31,
2012), 136 FERC ¶ 61,051 (2011), order on reh’g,
Order No. 1000–A, 139 FERC ¶ 61,132, order on
reh’g and clarification, Order No. 1000–B, 141
FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv.
Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
41 NYTOs Comments at 9–10.
PO 00000
Frm 00006
Fmt 4701
Sfmt 4700
electric energy in interstate commerce
and the sale of electric energy at
wholesale in interstate commerce
(hereinafter referred to collectively as
‘‘wholesale rates’’). Thus, the
Commission has jurisdiction over
transmission line ratings.42 We further
find that, because of the relationship
between transmission line ratings and
wholesale rates, inaccurate transmission
line ratings result in wholesale rates that
are unjust and unreasonable.
Accordingly, pursuant to FPA section
206,43 we conclude that certain
revisions to the pro forma OATT and
the Commission’s regulations are
necessary to ensure just and reasonable
wholesale rates. We adopt most of the
reforms proposed in the NOPR, with
certain clarifications, as discussed
further herein, and revisions to the
proposed pro forma OATT Attachment
M and to the Commission’s regulations.
30. We find that transmission line
ratings directly affect wholesale rates
because transmission line ratings and
wholesale rates are inextricably linked.
As explained above, transmission line
ratings represent the maximum transfer
capability of each transmission line.
That transfer capability determines the
quantity of energy that can be
transmitted from suppliers to load in
any given moment. Supply and demand
fundamentals dictate that less transfer
capability (i.e., less supply) will result
in higher rates, all else being equal.
Inaccurate transmission line ratings can
result in underutilization (or
overutilization) of existing transmission
facilities, thereby sending a signal that
there is less (or more) transfer capability
than is truly available. This signal
impacts the wholesale rates charged for
providing energy and other ancillary
services. For example, if the system
operator believes there is less transfer
capability than is truly available, it may
dispatch more expensive generators to
serve load, when less expensive
generators (which would have resulted
in lower congestion costs) could have
been used to reliably serve the same
load. Alternatively, inaccurate
transmission line ratings can result in
oversubscription of existing
transmission facilities, thereby sending
the opposite signal—that there is more
transfer capability than is truly
available—which may risk damage to
equipment, may fail to accurately price
congestion costs, and may fail to signal
to the market that more generation and/
or transmission investment may be
needed in the long term. We therefore
find that transmission line ratings
42 16
43 16
E:\FR\FM\13JAR2.SGM
U.S.C. 824(b)(1), 824d.
U.S.C. 824e.
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
directly affect wholesale rates and,
concomitantly, that inaccurate
transmission line ratings result in unjust
and unreasonable wholesale rates.44
31. Most commenters, except NYTOs,
agree with the Commission’s
preliminary conclusion that
transmission line ratings directly affect
wholesale rates.45 NYTOs caution that
the D.C. Circuit found there are limits to
the Commission’s FPA section 206
jurisdiction over ‘‘practices’’ and that
the term may not include all utility
operations.46 But, the inextricable link
between transmission line ratings and
wholesale rates places transmission line
ratings within the Commission’s FPA
section 206 jurisdiction.
32. Some commenters, in response to
the preliminary finding that accurate
transmission line ratings are necessary
for just and reasonable wholesale rates,
argue that transmission line ratings are
fundamentally a reliability tool.47 We
agree that system safety and reliability
are paramount to the proposed
requirements for transmission line
ratings. But we disagree with the
suggestion that because transmission
line ratings are critical to reliability,
economic considerations are an
inappropriate basis for requiring a
certain type of transmission line ratings.
Instead, we find that commenters
present a false choice; economic
considerations and reliability
considerations are inextricably linked as
reliability constraints bound the
potential economic transactions of
market participants. In the case of
transmission line ratings, transmission
owners calculate the maximum transfer
capability of a transmission line.
Transmission providers, in order to
maintain reliable system operations,
incorporate those ratings and other
constraints into operations, and the
results determine dispatch and
commitment instructions and wholesale
rates. Even though transmission line
ratings can be seen as a reliability tool,
44 SPP MMU Comments at 1–2; Potomac
Economics Comments at 5; CAISO DMM Comments
at 4; Industrial Customer Organizations Comments
at 11–12; TAPS Comments at 5–6; Certain TDU
Comments at 4–5; Clean Energy Parties Comments
at 2–3.
45 AEP Comments at 3; Ohio FEA Comments at
6; New England State Agencies Comments at 8;
OMS Comments at 6; Potomac Economics
Comments at 5; CAISO DMM Comments at 4; SPP
MMU Comments at 1–2; R Street Institute
Comments at 2; Industrial Customer Organizations
Comments at 11–12; TAPS Comments at 5–6;
WATT Comments at 3–5; Certain TDU Comments
at 4–5; Clean Energy Parties Comments at 2–3;
EDFR Comments at 3.
46 NYTOs Comments at 9–10.
47 See, e.g., Dominion Comments at 13; Exelon
Comments at 6; PJM Indicated Transmission
Owners Comments at 2; EEI Comments at 5.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
that does not obviate the need to ensure
that the wholesale rates resulting from
such reliability tools are just and
reasonable.
33. Regarding that incorporation of
transmission line ratings into operations
and resulting wholesale rates, as the
Commission explained in the NOPR,
most transmission owners implement
seasonal or static line ratings. Such
seasonal or static line ratings are based
on conservative, worst-case assumptions
about long-term conditions, such as the
expected high temperatures that are
likely to occur over the longer term.
While such long-term assumptions may
be appropriate in various planning
contexts, they often do not reflect the
true near-term transfer capability of
transmission facilities and, when used
in near-term operations, produce unjust
and unreasonable wholesale rates.
34. As explained in the NOPR,
incorporating near-term forecasts of
ambient air temperatures in
transmission line ratings can more
accurately reflect the true near-term
transfer capability of transmission
facilities than continuing to rely on
seasonal or static line ratings. Because
actual ambient air temperatures are
usually not as high as the ambient air
temperatures conservatively assumed in
seasonal and static line ratings,
updating the transmission line ratings
used in near-term transmission service
to reflect actual ambient air
temperatures usually results in
increased system transfer capability. By
increasing transfer capability,
congestion costs will, on average,
decline because transmission providers
will be able to serve load with less
expensive resources from what were
previously constrained areas. For
example, Potomac Economics has found
that AAR implementation by those not
already using AARs in MISO alone
would have produced approximately
$66.5 million and $49 million in
reduced congestion costs in 2019 and in
2020, respectively.48 Such congestion
cost changes and related overall price
changes will more accurately reflect the
actual congestion on the system, leading
to wholesale rates that more accurately
reflect the cost of the wholesale service
being provided. Likewise, the ability to
increase transmission flows into load
pockets may reduce transmission
provider reliance on local reserves
inside load pockets, which may reduce
local reserve requirements and the costs
to maintain that required level of
reserves.
35. Moreover, while current
transmission line rating practices
48 Potomac
PO 00000
Economics Comments at 8.
Frm 00007
Fmt 4701
Sfmt 4700
2249
usually understate transfer capability,
they can also overstate transfer
capability and, in doing so, place
transmission lines at risk of inadvertent
overload. While actual ambient air
temperatures are usually not as high as
the assumed seasonal or static line
rating temperature input, in some
instances actual ambient air
temperatures exceed those assumed
temperatures. In those instances,
seasonal or static line ratings might
reflect more transfer capability than
physically exists, and therefore such
transmission line ratings might allow
access to some electric power supplies
and/or demand that would not be
available if transmission line ratings
reflected the true transfer capability.
Overstating transfer capability, like
understating transfer capability, can
result in wholesale rates that fail to
reflect the cost of the wholesale service
being provided, though, in the case of
overstated transfer capability, through
inaccurately low congestion pricing and
failing to signal to the market that more
generation and/or transmission
investment may be needed in the long
term.
36. Regarding DLRs, in addition to
ambient air temperatures and the
presence or absence of solar heating,
other weather conditions such as (but
not limited to) wind, cloud cover, solar
heating intensity, and precipitation, and
transmission line conditions such as
tension and sag, can affect the amount
of transfer capability of a given
transmission facility. DLRs incorporate
these additional inputs and thereby
provide transmission line ratings that
are closer to the true thermal
transmission line limits than AARs.
However, as noted above and explained
in greater detail in Section IV.E below,
based on the record in this proceeding,
we decline to mandate DLR
implementation in this final rule. We
instead incorporate the record in this
proceeding on DLRs into new Docket
No. AD22–5–000, which we open to
further explore DLR implementation.
37. While we believe additional
record is needed regarding DLR
implementation, we can determine
based on the record that current
transmission line rating practices in
RTOs/ISOs that do not permit the
acceptance of DLRs from transmission
owners that use DLRs are contributing
to unjust and unreasonable wholesale
rates by acting as a barrier to accurate
transmission line ratings. Therefore, as
part of remedying inaccurate
transmission line ratings that result in
unjust and unreasonable wholesale
rates, we require RTOs/ISOs to establish
and maintain the systems and
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
2250
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
procedures necessary to permit the
acceptance of DLRs from transmission
owners that use them. As the
Commission explained in the NOPR,
some RTOs/ISOs rely on software that
cannot accommodate transmission line
ratings that frequently change, such as
DLRs.49 Without reflecting such
frequent changes to transmission line
ratings, such software serves as a barrier
that prevents transmission owners in
RTOs/ISOs from implementing DLRs
and better reflecting the actual transfer
capability of the transmission system.
The result is that, even if a transmission
owner sought to implement DLRs, the
RTO’s/ISO’s energy management system
(EMS) may not be able to accept and use
the resulting transmission line rating.
The potential inability of RTOs/ISOs to
accept and use a DLR prevents RTO/ISO
markets from benefiting from the more
accurate representation of current
system conditions. Therefore, we
require RTOs/ISOs to establish and
maintain the systems and procedures
necessary to permit the acceptance of
DLRs from transmission owners that use
them.
38. Regarding emergency ratings, we
find that many transmission owners’
current transmission line rating
practices fail to use emergency ratings,
and in failing to do so, lead to
transmission line ratings that do not
accurately reflect the near-term transfer
capability of the transmission system,
and therefore result in wholesale rates
that do not reflect costs of the wholesale
service being provided. As the
Commission explained in the NOPR,
transmission owners often develop two
sets of transmission line ratings for most
facilities: Normal ratings that can be
safely used continuously, and
emergency ratings that can be used for
a specified shorter period of time,
typically during post-contingency
operations. Transmission providers
generally calculate resource dispatch
and commitments to ensure that all
facilities are within applicable facility
ratings both during normal operations
and following any modeled contingency
(e.g., following the loss of a
transmission line). In ensuring that the
system is stable and reliable following a
contingency, transmission providers
often allow post-contingency flows on
transmission lines to exceed normal
ratings for short periods of time, as long
as those flows do not exceed the
applicable emergency rating for the
corresponding timeframe. Because these
emergency ratings are a more accurate
representation of the flow limits over
those shorter timeframes, their use in
49 NOPR,
173 FERC ¶ 61,165 at P 43.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
models of post-contingency flows
produces wholesale rates that more
accurately reflect the costs of the
wholesale service being provided and
therefore is necessary to ensure just and
reasonable wholesale rates. For this
reason, as described below, we require
that transmission providers implement
uniquely determined emergency ratings.
Additionally, we require that
transmission providers use uniquely
determined emergency ratings for
contingency analysis in the operations
horizon and in post-contingency
simulations of constraints. Such
uniquely determined emergency ratings
must also include separate AAR
calculations for each emergency rating
duration used.
39. Finally, we find that the current
level of transparency into transmission
line ratings and methodologies may
result in unjust and unreasonable
wholesale rates. In some regions, where
the transmission owner and
transmission provider are not the same
entity, such as RTOs/ISOs, current
transparency levels prevent the
transmission provider and market
monitor(s) from having the opportunity
to assess the accuracy of transmission
line ratings. For example, as the
Commission described in the NOPR,
without knowing the basis for a given
transmission line rating that frequently
binds and elevates prices, a
transmission provider and/or market
monitor cannot determine whether the
transmission line rating is accurately
calculated.50 Moreover, we find that,
absent additional information to market
participants on transmission line ratings
and their methodologies, the status quo
does not provide market participants
with information important to making
cost-effective decisions and, thereby,
impedes such decisions. For example,
without accurate transmission line
rating information, market participants
operate without information that is
important in making accurate economic
decisions regarding where to build
generation or where to site load.
Further, this lack of transparency could
allow transmission owners to submit
inaccurate near-term transmission line
ratings, which, in turn, would result in
wholesale rates that do not accurately
reflect the cost of the wholesale service
being provided, as discussed above. For
these reasons, we require: (1) Public
utility transmission owners to share
transmission line ratings and
methodologies with their transmission
provider(s) and with market monitors in
RTOs/ISOs; (2) transmission providers
to share their transmission owners’
50 Id.
PO 00000
P 47.
Frm 00008
transmission line ratings and
methodologies with any transmission
provider(s) upon request; (3)
transmission providers to maintain a
database of their transmission owners’
transmission line ratings and
methodologies on the transmission
provider’s OASIS site or another
password-protected website; and (4)
transmission providers to post on
OASIS or another password-protected
website any uses of exceptions or
temporary alternate ratings.
IV. Discussion
A. Transmission Line Ratings Definition
1. NOPR Proposal
40. In the NOPR, the Commission
proposed to define a transmission line
rating in pro forma OATT Attachment
M as the maximum transfer capability of
a transmission line, computed in
accordance with a written transmission
line rating methodology and consistent
with good utility practice, considering
the technical limitations on conductors
and relevant transmission equipment
(such as thermal flow limits), as well as
technical limitations of the transmission
system (such as system voltage and
stability limits). Relevant transmission
equipment may include, but is not
limited to, circuit breakers, line traps,
and transformers.51
41. Under the ‘‘Obligations of
Transmission Provider’’ section in pro
forma OATT Attachment M, the
Commission further proposed to require
that the transmission provider must use
either AARs or seasonal line ratings, as
appropriate, as the relevant
transmission line ratings. Similarly, and
as described in more detail in Section
IV.D.3, the Commission proposed
exceptions to the AAR and seasonal line
rating requirements for certain
transmission line ratings.
2. Comments
42. Some commenters support the
proposed definition of transmission line
rating, while others request clarity or
modifications be made, specifically
around the list of relevant transmission
equipment. AEP supports the
Commission’s proposed transmission
line rating definition, explaining that
the Commission’s proposed definition
reflects the fact that transmission line
ratings incorporate a set of electrical
equipment that collectively operate as a
single bulk electric system element (e.g.,
transformers, relay protective devices,
terminal equipment, and series and
shunt compensation devices) and that
the most limiting component from that
51 NOPR,
Fmt 4701
Sfmt 4700
E:\FR\FM\13JAR2.SGM
173 FERC ¶ 61,165 at P 85.
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
set determines the transmission line
rating.52 Similarly, Indicated PJM
Transmission Owners address the
NOPR’s proposed AAR requirements set
forth in pro forma OATT Attachment M
under ‘‘Obligations of Transmission
Provider’’ (hereinafter referred to as ‘‘the
proposed AAR requirements’’) as
ambient-adjusted and seasonal line
ratings, consistent with NERC’s
definition of facility rating,53 and
describe Indicated PJM Transmission
Owners’ implementation of AARs,
consistent with NERC’s definition of
facility ratings.54 PJM also describes the
implementation of AARs for each of its
transmission facilities.55
43. Entergy explains that overhead
conductor ratings and ratings for
‘‘ancillary equipment,’’ or equipment
that does not include a primary element,
like conductors and transformers, can be
temperature adjusted. According to
Entergy, examples of ‘‘ancillary
equipment’’ include breakers, switches,
traps, busses, jumpers, current
transformers, potential transformers,
and relay equipment. Entergy further
asserts, however, that shunt reactors,
series capacitors, relays, current
transformers, static VAR compensators,
circuit breakers, autotransformers,
copper weld (‘‘CW’’) buses, conductors,
risers or jumpers, and, subject to limited
exceptions, customer equipment have
ratings that cannot be temperature
adjusted.56 Eversource states that the
ratings for relays and other equipment,
such as splices, switches, and terminal
equipment, are not impacted by ambient
air temperatures.57 NYISO states that
the majority of the bulk electric system
equipment ratings in New York are able
to be rated using AARs or DLRs,58 while
NYTOs note that transmission line
ratings may be based on non-conductor
components which are not affected by
ambient air temperatures.59 EEI and
MISO Transmission Owners request
clarity on the definition of transmission
line rating and its specific applicability,
stating that the AAR requirements
should not apply to power transformers,
52 AEP
Comments at 2–3.
NERC Glossary defines a ‘‘Facility Rating’’
as: ‘‘[t]he maximum or minimum voltage, current,
frequency, or real or reactive power flow through
a facility that does not violate the applicable
equipment rating of any equipment comprising the
facility.’’ NERC, Glossary of Terms Used in NERC
Reliability Standards (June 28, 2021), https://
www.nerc.com/pa/Stand/Glossary%20of
%20Terms/Glossary_of_Terms.pdf.
54 Indicated PJM Transmission Owners
Comments at 1–2, 6–7.
55 PJM Comments at 2–3.
56 Entergy Comments at 5–6.
57 Eversource Comments at 3.
58 NYISO Comments at 3–4.
59 NYTOs Comments at 8.
jspears on DSK121TN23PROD with RULES2
53 The
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
but instead, under certain
circumstances, to other types of
transformers, including current
transformers.60 EEI further explains that
ratings for power transformers are
generally the result of the efficiency of
the heat transfer process, not ambient
air temperatures directly, and thus
requests that the Commission clarify
that the references to transformers apply
only to transformers that limit or impact
transmission line ratings and not power
transformers generally.61 Entergy
similarly notes that transformer and
relay ratings do not change with
ambient conditions.62 ITC states that
AARs cannot be applied to voltage or
stability limits and therefore
recommends that ‘‘transmission line
rating’’ reflect the concepts of
equipment and facility rating as defined
by NERC in order to avoid confusion
with a system operating limit.63 APS
states that transmission lines with
limitations associated with substation
equipment or series capacitors, among
other equipment in which the
transmission line is not the limiting
factor, may not experience changes to
their transfer capabilities.64 MISO
contends that the list could include
potential relay trip limits and maximum
power transfer limits.65
3. Commission Determination
44. In this final rule, we adopt the
definition of transmission line rating
proposed in the NOPR. Specifically, we
adopt the proposed definition that a
transmission line rating means the
maximum transfer capability of a
transmission line, computed in
60 EEI Comments at 17–18; MISO Transmission
Owners Comments at 39–40.
61 EEI Comments at 17–18.
62 Entergy Comments at 9–10.
63 ITC Comments at 11–12. The NERC Glossary
defines an ‘‘Equipment Rating’’ as: ‘‘[t]he maximum
and minimum voltage, current, frequency, real and
reactive power flows on individual equipment
under steady state, short-circuit and transient
conditions, as permitted or assigned by the
equipment owner.’’ It defines a ‘‘System Operating
Limit’’ as: ‘‘[t]he value (such as MW, Mvar,
amperes, frequency or volts) that satisfies the most
limiting of the prescribed operating criteria for a
specified system configuration to ensure operation
within acceptable reliability criteria. System
Operating Limits are based upon certain operating
criteria. These include, but are not limited to:
Facility Ratings (applicable pre- and postContingency Equipment Ratings or Facility
Ratings); transient stability ratings (applicable preand post-Contingency stability limits); voltage
stability ratings (applicable pre- and postContingency voltage stability); and system voltage
limits (applicable pre- and post-Contingency
voltage limits).’’ NERC, Glossary of Terms Used in
NERC Reliability Standards (June 28, 2021), https://
www.nerc.com/pa/Stand/Glossary%20of
%20Terms/Glossary_of_Terms.pdf.
64 APS Comments at 3.
65 MISO Comments at 34.
PO 00000
Frm 00009
Fmt 4701
Sfmt 4700
2251
accordance with a written transmission
line rating methodology and consistent
with good utility practice, considering
the technical limitations on conductors
and relevant transmission equipment
(such as thermal flow limits), as well as
technical limitations of the transmission
system (such as system voltage and
stability limits). Relevant transmission
equipment may include, but is not
limited to, circuit breakers, line traps,
and transformers. As the Commission
stated in the NOPR, system safety and
reliability are paramount to the
proposed requirements for transmission
line ratings. We agree with AEP that the
definition adopted herein reflects the
fact that transmission line ratings must
incorporate a set of electrical equipment
ratings that collectively operate as a
single bulk electric system element (e.g.,
transformers, relay protective devices,
terminal equipment, and series and
shunt compensation devices) and that
the most limiting component from that
set determines the transmission line
rating.66
45. In response to comments about the
definition’s inclusion of the technical
limitations (such as thermal flow limits)
on conductors and relevant
transmission equipment, we clarify that
the definition of transmission line rating
encompasses transmission line ratings
for electric system equipment that
includes more than just overhead
conductors. For example, it includes
ratings for electric system equipment
such as circuit breakers, line traps, and
transformers. Additionally, as described
in more detail below in Section IV.D.3,
we adopt the list of proposed exceptions
from the NOPR. Consequently, we do
not require transmission line ratings
that are not affected by ambient air
temperatures to be rated using forecasts
of ambient air temperatures. That said,
we decline to define in this final rule
which electric system equipment ratings
are (or are not) affected by ambient air
temperatures. Instead, we allow
flexibility for individual transmission
owners and transmission providers to
apply good utility practice to determine
which specific electric system
equipment has ratings that are (or are
not) affected by ambient air
temperatures.
46. Finally, in response to requests for
clarification from EEI and MISO
Transmission Owners regarding the
applicability of the proposed AAR
requirements to power transformers, we
decline to provide a generic exception
from the AAR requirement for power
transformers. The operating limits of a
power transformer are bounded by the
66 AEP
E:\FR\FM\13JAR2.SGM
Comments at 2–3.
13JAR2
2252
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
ambient air temperature, the average
winding temperature, and the maximum
winding hottest-spot temperature.67
However, we reiterate the exceptions
adopted herein and discussed further
below, which provide that any rating
not affected by ambient air temperatures
would not be required to incorporate
forecasts of ambient air temperatures
into the rating. Thus, if a transmission
provider determines, consistent with
good utility practice, that a specific
power transformer’s rating is not
affected by ambient air temperature,
then that power transformer would fall
within the scope of such exceptions to
the AAR requirement.
B. Ambient-Adjusted Ratings
1. AAR Definition and Transmission
Provider Obligations
a. NOPR Proposal
jspears on DSK121TN23PROD with RULES2
47. In the NOPR, the Commission
proposed to define an AAR in pro forma
OATT Attachment M and in the
Commission’s regulations as a
transmission line rating that: (1) Applies
to a time period of not greater than one
hour; (2) reflects an up-to-date forecast
of ambient air temperature across the
time period to which the rating applies;
and (3) is calculated at least each hour,
if not more frequently. As obligations of
the transmission provider set forth in
pro forma OATT Attachment M, the
Commission proposed to require that
transmission providers use AARs as the
applicable line rating: (1) For requests
for near-term point-to-point
transmission service ending within 10
days of the request date, as defined in
pro forma OATT Attachment M; (2) for
determining the necessity of near-term
curtailment or interruption of near-term
point-to-point transmission service
anticipated to occur (start and end)
within the next 10 days; and (3) for
determining the necessity of near-term
interruption or redispatch of network
transmission service anticipated to
occur (start and end) within the next 10
days. The Commission proposed to
require transmission providers to
implement the use of AARs and
seasonal line ratings on all historically
congested transmission lines 68 within
one year after the compliance filing due
date and on all other transmission lines
within two years after the compliance
67 Institute of Electrical and Electronics
Engineers, IEEE Standard for General Requirements
for Liquid-Immersed Distribution, Power, and
Regulating Transformers, IEEE Std C57.91.00–2021.
68 The Commission proposed to define a
historically congested transmission line as ‘‘a
transmission line that was congested at any time in
the five years prior to the effective date of [this final
rule].’’ NOPR, 173 FERC ¶ 61,165 at P 92.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
filing due date.69 For RTOs/ISOs, for
which the Commission has approved
variations from the pro forma OATT to
manage congestion and initiate
curtailments and/or redispatch of
transmission service within their
footprints (although generally not at
their borders), the Commission
proposed two requirements. First, the
Commission proposed requirements for
RTOs/ISOs to implement AARs in both
the day-ahead and real-time markets
and any intra-day reliability unit
commitment. Second, the Commission
proposed to require AARs as the
relevant transmission line rating for any
near-term point-to-point transmission
service offered (e.g., at the RTO’s/ISO’s
borders).
48. As justification for the NOPR
proposal to require AAR
implementation on all transmission
lines and not only on historically
congested lines, the Commission noted
that any facility can become the most
limiting element as the transmission
system changes, and in certain
circumstances flows may change
considerably from normal operations.
Therefore, the Commission proposed to
require AARs be implemented on all
transmission lines but recognized that a
staggered implementation schedule
would allow transmission providers and
transmission owners to focus initial
implementation where it would have
the most impact.70
49. As justification for requiring
AARs, the Commission preliminarily
found that AAR requirements strike an
appropriate balance between benefits
and challenges. First, the Commission
observed that, while there are
differences across transmission systems,
simply accounting for ambient air
temperatures in transmission line
ratings can reliably increase power
transfer capability and significantly
lower production costs at a manageable
implementation cost. The Commission
next explained that, according to
Potomac Economics’ estimates, the
benefits to AAR implementation by
those not already implementing AARs
in MISO alone would have produced
approximately $94 million and $78
million in reduced congestion costs in
2017 and in 2018, respectively. The
Commission further explained that,
while several entities noted
implementation costs as a barrier to
AAR implementation, the costs
identified were mostly initial
investments in upgraded OASIS and/or
EMS and ratings databases and that
once these systems are upgraded,
69 Id.
70 Id.
PO 00000
P 131.
PP 93–94.
Frm 00010
Fmt 4701
Sfmt 4700
adding AARs to additional transmission
lines appears to have a minimal
incremental cost.71
b. Comments
50. In response to the proposed AAR
requirements, RTO/ISO comments are
mixed, with most requesting flexibility
to accommodate regional or market
differences,72 while market monitors are
generally supportive of the NOPR
proposal.73 Transmission owners are
conceptually supportive of AAR
implementation but request flexibility
in response to what they generally
describe as an overly broad
requirement.74 The PJM transmission
owners that submitted comments are
generally supportive of the proposed
AAR requirements in pro forma OATT
Attachment M, explaining that they
have experience using AARs.75 Other
commenters, including state
governments, generation, load,
renewable energy advocates, and other
technical experts, are generally
supportive of the proposed AAR
requirements.76
51. Several transmission owners
explain that they currently use AARs on
all or parts of their transmission lines
and support the Commission’s NOPR
proposal to implement widespread AAR
use. AEP notes that it has used AARs in
real-time operations for decades and
that AARs have provided both
reliability and financial benefits.77 AEP
notes that the use of AARs is common
in PJM and that it similarly implements
AARs for its facilities in SPP and the
Electric Reliability Council of Texas
(ERCOT).78 Exelon states that it
71 Id.
P 99.
e.g., MISO Comments at 7, 9, 14–16;
NYISO Comments at 9–11; ISO–NE Comments at 9.
73 Potomac Economics Comments at 3–4; CAISO
DMM Comments at 2–4; SPP MMU Comments at 1,
4.
74 MISO Transmission Owners Comments at 8–9;
PacifiCorp Comments at 2; EEI Comments at 2–5;
NRECA/LPPC Comments at 2–3; Entergy Comments
at 1–2; BPA Comments at 2–4; WAPA Comments
at 4–5; APS Comments at 2–4; Southern Company
Comments at 2–3; NYTOs Comments at 2–3; Duke
Energy Comments at 1–2; PG&E Comments at 3;
SCE Comments at 1–2; SDG&E Comments at 1–2;
LADWP Comments at 2–3; IID Comments at 4–6;
ITC Comments at 1–3; Sunflower Comments at 2;
Eversource Comments at 5–7.
75 Exelon Comments at 1–2; AEP Comments at 5–
6; Dominion Comments at 3–4; Indicated PJM
Transmission Owner Comments at 1–4.
76 New England State Agencies Comments at 10;
OMS Comments at 2; Ohio FEA Comments at 2; R
Street Institute Comments at 1–2; WATT Comments
at 1–2; DC Energy Comments at 1–2; ACORE
Comments at 1; Clean Energy Parties Comments at
2, 4–6; ENEL Comments at 1; EDFR Comments at
1–2; Vistra Comments at 1–2; EPSA Comments at
2; Industrial Customers Comments at 1–2; TAPS
Comments at 1–2; Certain TDU Comments at 1.
77 AEP Comments at 3.
78 Id. at 3–4.
72 See,
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
considers AARs to be a best practice,
explaining that all of its six utilities
have implemented AARs on their
transmission systems, without any
adverse reliability or safety impacts, and
have found the practice to be a costeffective tool to enhance grid
reliability.79 Dominion states that,
because PJM has implemented AARs for
transmission service and for use in its
day-ahead and real-time markets,
Dominion Energy Virginia has adopted
and uses PJM’s AAR methodology on all
its transmission lines, while Dominion
Energy South Carolina uses AARs on
only a portion of its transmission
system.80 Indicated PJM Transmission
Owners support efforts to enhance
transmission utilization by requiring
AAR and seasonal line rating
implementation, explaining that such
practices improve efficiency; they also
state that transmission line ratings are
fundamentally a reliability tool.81 While
generally supportive of the NOPR
proposal, Dominion, AEP, and Indicated
PJM Transmission Owners all request
flexibility to accommodate PJM’s
current AAR implementation and ask
that the Commission not require hourly
updates to AARs.82
52. Both ITC and Sunflower state that
they are generally supportive of AAR
implementation, but urge flexibility for
transmission providers to implement
AARs.83 MISO Transmission Owners,
explaining that they have initiated a
process to implement AARs, state that
they support certain aspects of the
NOPR, but also state that other aspects
are overly broad and will not yield
sufficient benefits to justify the costs.84
MISO Transmission Owners urge the
Commission to allow for regional
flexibility in any requirements and state
that AAR deployment should focus on
where it is expected to provide benefits
by ‘‘freeing up’’ additional transfer
capability.85 MISO Transmission
Owners state that, over the past five
years, congestion arose on only 10% of
the nearly 10,000 transmission facilities
under MISO’s functional control and
that there would be no benefit to
implementing AARs on non-congested
lines.86 MISO Transmission Owners
also state that there are several
79 Exelon
Comments at 1–2.
Comments at 6.
81 Indicated PJM Transmission Owners
Comments at 1–2.
82 Dominion Comments at 3; AEP Comments at 6–
7; Indicated PJM Transmission Owners Comments
at 5.
83 ITC Comments at 1–3; Sunflower Comments at
2.
84 MISO Transmission Owners Comments at 3–4.
85 Id. at 13.
86 Id. at 28.
jspears on DSK121TN23PROD with RULES2
80 Dominion
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
necessary steps to implement AARs,
which can be costly and time
consuming.87 Additionally, MISO
Transmission Owners state that the
Commission should not rely upon
Potomac Economics’ estimates of AAR
benefits, explaining that Potomac
Economics inaccurately assumed that:
(1) All transmission lines are ambient
adjustable; (2) all transmission owners
are using worst-case assumptions; and
(3) congestion caused by transient
outages existed even though it has since
been alleviated by recent upgrades.88
53. NYTOs, Eversource, and Southern
Company request that the Commission
refrain from adopting blanket AAR
requirements for all transmission lines
and instead require transmission
providers to adopt a process for
determining whether to apply AARs or
DLRs to certain transmission facilities.89
Southern Company suggests that such a
process could be similar to the
Commission’s available transfer
capability (ATC) requirements, whereby
a public utility could include the
metrics and criteria for determining
when to use AAR or DLR in its OATT
and implementation details in its
guidelines or business practices.90
Southern Company states that, while
broader use of AARs and DLRs may
provide cost savings to customers, the
Commission’s proposed approach in the
NOPR is overly prescriptive and may
therefore create unnecessary
implementation complications and limit
the deployment of other grid-enhancing
technologies.91 Southern Company and
NRECA/LPPC also argue that non-RTO/
ISO regions are characterized by longterm transmission commitments and
that incremental short-term transfer
capability is less relevant and less likely
to result in cost savings.92 Eversource
contends that it applies AARs where it
is beneficial, but states that the benefits
of AARs will depend on specific
circumstances within a region, noting
that there is little congestion in ISO–
NE.93
54. Southern Company states that
reliability issues may arise as a result of
the NOPR proposal because AARs may
create difficulties in identifying the
most limiting element, which may
change as the temperature changes, and
similar difficulties may arise in
complying with Reliability Standard
PRC–023–4’s transmission relay
loadability requirements that depend on
maximum published ratings.94 EEI
states that, to ensure compliance with
Reliability Standard PRC–023–4,
significant amounts of field engineering
time could be required to install and test
new settings for thousands of relays.95
NYTOs state that implementing the
AAR requirements will require
significant time and resources and
would divert scarce resources from
ongoing efforts to meet the goals of New
York’s Climate Leadership and
Community Protection Act.96 NERC
contends that the Commission should
keep in mind considerations for
implementing AARs across long
transmission lines that span multiple
climates.97
55. Duke Energy states that it already
employs AARs in real-time operations
and supports the Commission’s
proposed requirements for transmission
providers to implement AARs in realtime operations.98 However, Duke
Energy also argues that, because
incorporating AARs into ATC
calculations would require fundamental
software changes that may take several
million dollars and multiple years to
complete, the benefits may not outweigh
the costs.99 Duke Energy suggests that
the Commission should instead require
transmission providers to submit a
compliance filing in which they may
propose a process to identify the
transmission facilities for which the
implementation of AARs and seasonal
line ratings will provide the most
benefits to customers.100
56. EEI states that its experience with
AARs is that their use can provide
benefits on a subset of transmission
lines 101 and requests flexibility for
transmission owners and transmission
providers to implement transmission
line rating solutions that best suit their
needs.102 EEI recommends a staggered
AAR approach whereby AARs would
first be implemented on priority
designated facilities, using established
and studied criteria, and any subsequent
AAR implementation would occur
following further studies of potential
benefits.103 Similarly, Entergy states that
AARs allow for more flexibility in realtime operations than static/thermal
values for real-time contingency studies,
94 Southern
87 Id.
at 22.
88 Id. at 43–45.
89 Southern Company Comments at 1–2;
Eversource Comments at 6; NYTOs Comments at
10.
90 Southern Company Comments at 1–2.
91 Id. at 2.
92 Id. at 4–5; NRECA/LPPC Comments at 19.
93 Eversource Comments at 4–5.
PO 00000
Frm 00011
Fmt 4701
Sfmt 4700
2253
Company Comments at 6.
Comments at 5–6.
96 NYTOs Comments at 6–7.
97 NERC Comments at 7.
98 Duke Energy Comments at 5.
99 Id. at 10.
100 Id. at 5.
101 EEI Comments at 5.
102 Id. at 2–4.
103 Id.
95 EEI
E:\FR\FM\13JAR2.SGM
13JAR2
2254
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
but contends that the use of AARs
should follow a scientific application of
factors that can reasonably result in an
adjustment of facility ratings to those
facilities for which an adjustment would
be reasonably expected to provide
benefits that exceed costs.104
57. NRECA/LPPC, Sunflower, and
WAPA contend that the promised
benefits, costs, and risks of AARs are
not evenly distributed nationwide and
that blanket application of the proposed
AAR requirements poses difficult
operating challenges.105 NRECA/LPPC
argue that the Commission should
maintain a focus on safety and
reliability and limit the scope of any
final rule by applying the AAR
requirements to transmission lines: (1)
Rated 100 kV and above; (2) that are
historically congested due to conductor
limitations only; and (3) that are under
RTO/ISO control. In addition, NRECA/
LPPC argue that AAR requirements
should be limited to transmission
service used for near-term wholesale
transactions, which in the RTOs/ISOs
would be the day-head and real-time
markets, and outside of the RTOs/ISOs,
if applied, would be daily and hourly
ATC, curtailment, and redispatch.106
NRECA/LPPC and Sunflower further
contend that, due to challenges in
implementing AARs, utilities should
have the flexibility to choose the AAR
methodology best suited to their needs
and should provide a waiver
mechanism for particular circuits on
which AAR implementation is
difficult.107
58. Several Western Interconnection,
non-CAISO transmission owners,
including PacifiCorp, BPA, WAPA, and
APS, broadly support the adoption of
AARs due to the associated reduction in
congestion, increase in transfer
capability, and reliability
improvements. However, these
transmission owners request additional
flexibility in how transmission owners
apply AARs and urge the Commission
to not adopt blanket AAR requirements
for all transmission lines given
differences in terrain, line lengths, and
scarcity of temperature data for such
lines.108 In explaining the drawbacks to
blanket AAR implementation, APS
explains that non-congested
transmission lines, transmission lines
that are substation equipment-limited,
and transmission lines that are voltage104 Entergy
Comments at 8.
Comments at 15–16, 19;
Sunflower Comments at 5; WAPA Comments at 5.
106 NRECA/LPPC Comments at 2–3.
107 Id. at 3; Sunflower Comments at 5.
108 PacifiCorp Comments at 2; BPA Comments at
2–4; WAPA Comments at 4–5; APS Comments at 2–
4.
105 NRECA/LPPC
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
and stability-limited will not benefit
from AAR implementation.109 WAPA
further identifies additional AAR
implementation challenges, including
the installation of new devices,
communication equipment, and
cybersecurity challenges. To reduce
implementation burdens, WAPA
recommends that the Commission
examine real-time Total Transfer
Capability (TTC) calculations.110 WAPA
further cautions that it would have to
pass the costs of AAR implementation
on to all customers, even though only
some customers would benefit.111 BPA
states that if it uses AARs as proposed,
it would need to make its wind
assumptions more conservative, derating transmission, to mitigate the risk
of operating near the conductor limit.112
59. PacifiCorp, BPA, EEI, and IID
further explain additional difficulties
they would face implementing the
proposed requirements to incorporate
AARs into ATC that could render AAR
implementation infeasible.113 IID
explains that, in the Western
Interconnection, path limits are the
result of multiple limits in series and in
parallel. TTC calculations involve
adjusting a base case with an associated
series of activities, and failures in base
case studies have to be evaluated
manually, such that a generic equation
would be insufficient in calculating
transmission line ratings.114 BPA and
PacifiCorp explain that most congested
parts on their transmission systems are
lines that are operated in parallel as part
of a rated transmission path,115 that
such rated paths have interactions with
other paths, which result in operating
nomograms,116 and that the NOPR
proposal may be more appropriate for a
flow-based transmission system.117
According to PacifiCorp and BPA, it
may be infeasible to implement AARs as
it would substantially increase the time
to compute the constraints that they use
to calculate TTC.118 CAISO also
describes the TTC calculation process
using rated paths and states that using
hourly AARs would exponentially
109 APS
Comments at 2–4.
Comments at 7–9.
111 Id. at 4–5.
112 BPA Comments at 4–5.
113 Id. at 3–4; PacifiCorp Comments at 2; IID
Comments at 5–6; EEI Comments at 10–11.
114 IID Comments at 5.
115 BPA Comments at 3; PacifiCorp Comments at
2.
116 Nomograms are operating constraints related
to the flow on multiple paths that generally result
from the simultaneous interaction between those
paths.
117 BPA Comments at 3; PacifiCorp Comments at
2.
118 BPA Comments at 3; PacifiCorp Comments at
2.
110 WAPA
PO 00000
Frm 00012
Fmt 4701
Sfmt 4700
increase the complexity of such
calculations and would necessitate
further automation.119 Similarly
describing the challenges of
incorporating AARs into ATC, EEI
explains that, in some areas, TTC values
are determined annually, or even less
frequently.120
60. California transmission owners
urge more targeted AAR
implementation.121 PG&E recommends
requiring transmission owners to
determine which lines would realize net
benefits for customers if AARs were
deployed, noting that deployment of
AARs across all transmission lines
could result in a negative return on
investment and an increased risk profile
for the transmission system.122 PG&E
notes that most of its weather stations
are currently located in ‘‘High Fire
Threat Districts’’ and contends that AAR
implementation on 500 kV lines will
require planning for additional weather
station equipment to ensure that
accurate weather data is available.123
SCE advocates for phased AAR
implementation in which transmission
owners identify priority facilities, and,
after implementation, study their
implementation in a report filed with
the Commission.124 SDG&E contends
that settings for all relays will have to
be studied and installed in the field,
causing a significant cost burden
unaccounted for in the Commission’s
analysis.125 IID contends that the
Commission should not take a one-sizefits-all approach and, in addition to the
challenges of AAR implementation,
encourages the Commission to consider
the costs of software, equipment, and
staffing in comparison to the benefits of
AARs providing congestion relief.126
61. LADWP states that Southern
California loads peak in the summer
when temperatures are already high and
may not allow AARs to expand transfer
capability. Conversely, according to
LADWP, there is already abundant
transfer capability in the winter
months.127 Describing AAR
implementation challenges, LADWP
notes that, due to the diversity in terrain
and microclimates that western
transmission lines traverse, weather
forecasts can vary significantly during
volatile weather seasons and present
119 CAISO
Comments at 10.
Comments at 11.
121 PG&E Comments at 3; SCE Comments at 1–2;
SDG&E Comments at 1–2; LADWP Comments at 2–
3.
122 PG&E Comments at 3.
123 Id. at 9–10.
124 SCE Comments at 3–4.
125 SDG&E Comments at 4.
126 IID Comments at 5.
127 LADWP Comments at 3–4.
120 EEI
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
challenges in identifying the most
constraining ambient conditions for a
given transmission line.128 LADWP
therefore contends that the Commission
should consider offering regional
exceptions from the AAR requirements
or prescribing AARs only in areas where
significant benefits are expected.129
62. PJM generally supports the
adoption of AARs by transmission
providers. PJM states that it already
employs AARs in its operations and
day-ahead and real-time markets and
that the use of AARs is commonplace
among the overwhelming majority of
transmission owners in the PJM region.
PJM states that transmission owners’
utilization of AARs increases
operational flexibility, promotes a more
efficient use of the transmission system,
and results in more reliable system
dispatch and cost-effective market
operations.130
63. CAISO states that it currently uses
seasonal line ratings, emergency ratings,
and AARs. However, CAISO notes that
AARs are used on relatively few
facilities and involve a manual process
to update transmission line ratings for
an applicable period. CAISO states that,
while AARs provide a more accurate
understanding of the transfer capability
of the transmission system, CAISO
recommends that the Commission allow
transmission owners and transmission
providers to justify when they use
AARs.131
64. MISO states that AAR and DLR
deployment can support the efficient
use of existing transmission
infrastructure but is not a long-term
solution to meet emerging system needs.
MISO states that the Commission
should not mandate the use of AARs
where the burden of that deployment is
greater than the benefits to be expected.
MISO contends that the Commission
should explore options for a more
targeted application of identifying
facilities that are good candidates for
AARs based on objective criteria and
documented methodologies.132 MISO
notes that it and MISO Transmission
Owners have already commenced an
effort to identify a prioritized list of
candidate transmission facilities for
deployment of real-time AARs in
MISO.133
65. NYISO does not support a uniform
approach to managing transmission line
ratings and instead requests that each
RTO/ISO work with the Commission to
128 Id.
at 5–6.
at 4–5.
130 PJM Comments at 2.
131 CAISO Comments at 2.
132 MISO Comments at 9.
133 MISO Comments at 14.
129 Id.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
set objectives for its markets.134 NYISO
contends that AAR use would not
provide benefits everywhere.135 NYISO
explains that using AARs to modify dayahead transmission line ratings would
overly complicate the day-ahead market
solution and would reduce
efficiency.136 NYISO requests flexibility
for regional variation with transmission
line ratings given regional differences,
such as transmission scheduling and
market rules.137 NYISO states that it
could work with stakeholders to
develop a proposal to implement three
to four sets of seasonal line ratings that
would be easier to implement and still
achieve many of the NOPR
objectives.138
66. Neither ISO–NE nor SPP explicitly
takes a position on the NOPR proposal
to implement AARs. However, ISO–NE
states that most of the congestion that
occurs on its system is due to voltage or
stability limitations, and thus AAR
benefits may be limited.139 ISO–NE
estimates that the implementation of
AARs could result in the lowering of
thermal congestion costs by, at most,
approximately $5–10 million per
year.140 ISO–NE also contends,
however, that AAR implementation may
expose other binding system limitations
without appreciably increasing transfer
capability or reducing congestion.141
67. Market monitors are mostly
supportive of the proposed AAR
requirements.142 The SPP MMU
supports the proposed reforms to
improve the accuracy and transparency
of transmission line ratings used by
transmission providers. The SPP MMU
notes that numerous SPP transmission
lines are not rated according to SPP
Planning Criteria.143 The SPP MMU
states that it supports the use of DLRs
for all transmission lines.144 According
to the SPP MMU, when transmission
line ratings underestimate the actual
transfer capability of the transmission
system, this can result in restricted
flows on certain paths while
overloading others and can create a
potential for de facto physical
withholding of the available transfer
134 NYISO
Comments at 1.
at 2.
136 Id. at 1–2.
137 Id. at 2.
138 Id. at 20.
139 ISO–NE Comments at 4–6.
140 Id. at 5 (basing estimates on 2019 data
contained in IMM and EMM Reports and the
Commission’s estimates of potential savings from
AARs in other RTO/ISO regions).
141 Id. at 6.
142 Potomac Economics Comments at 3–4; CAISO
DMM Comments at 2–4; SPP MMU Comments at 1,
4.
143 SPP MMU Comments at 4.
144 Id. at 1, 4.
135 Id.
PO 00000
Frm 00013
Fmt 4701
Sfmt 4700
2255
capability by transmission owners.145
The SPP MMU argues that more
accurate transmission line ratings will
improve the robustness of price
formation, particularly in congested
areas.146
68. Potomac Economics states that
only 8% of the transmission line ratings
in MISO are adjusted for changes in
ambient air temperatures. Potomac
Economics indicates that it
conservatively estimates that the
benefits of using AARs and emergency
ratings in 2019 and 2020 would have
been between 9% and 13% of the realtime congestion value, or $98 million
and $114 million per year.147 Potomac
Economics notes that transmission
owners have little or no economic
incentive to provide temperatureadjusted ratings and that transmission
operators 148 rarely verify or validate
transmission line rating methodologies
or transmission line rating
calculations.149 Potomac Economics
contends that it would be unreasonable
to require AARs on all transmission
facilities, and instead argues that it
would be more reasonable to require
that processes be established to allow
for additional AARs to be deployed
quickly when new constraints begin to
bind or other studies indicate it may be
appropriate.150 Potomac Economics
cautions, however, against requiring any
cost-benefit analysis, noting that the
incremental cost of initiating AARs on
new constraints is near zero so such
analysis is unnecessary.151 Finally,
Potomac Economics contends that using
AARs and emergency ratings will not
create reliability concerns as the NOPR
proposal only requires that decisions to
not implement AARs or emergency
ratings be based on reliability and not a
preference or policy decision.152 CAISO
DMM supports the proposed
requirements to implement hourly
AARs as a way to improve both the
accuracy of congestion costs and
transmission system efficiency.153
145 Id.
at 7.
at 9.
147 Potomac Economics Comments at 7–9; see
also Potomac Economics Reply Comments at 2–6.
148 The NERC Glossary defines a ‘‘Transmission
Operator’’ as: ‘‘[t]he entity responsible for the
reliability of its ‘local’ transmission system, and
that operates or directs the operations of the
transmission Facilities.’’ NERC, Glossary of Terms
Used in NERC Reliability Standards (June 28, 2021),
https://www.nerc.com/pa/Stand/Glossary%20of
%20Terms/Glossary_of_Terms.pdf.
149 Potomac Economics Comments at 9–10; see
also Potomac Economics Reply Comments at 6–7.
150 Potomac Economics Comments at 20; see also
Potomac Economics Reply Comments at 9.
151 Potomac Economics Reply Comments at 7.
152 Id. at 11.
153 CAISO DMM Comments at 2, 4.
146 Id.
E:\FR\FM\13JAR2.SGM
13JAR2
2256
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
69. State government agencies are also
mostly supportive of the proposed AAR
requirements.154 New England State
Agencies state that they strongly
support the Commission’s proposed
AAR requirements.155 New England
State Agencies state that the
transmission system was built on behalf
of and paid for by ratepayers, and argue
that the Commission should take all
reasonable steps to protect those
ratepayers from excessive costs. New
England State Agencies contend that the
use of AARs can be an important tool
in this regard.156 New England State
Agencies state that a transmission
system operated using AARs may
provide benefits by possibly: (1)
Obviating the need for new transmission
lines, thus deferring capital costs; 157 (2)
reducing reliance on higher cost local
reserves which will reduce costs and
local reserve requirements resulting
from an increased ability to flow power
into load pockets; 158 and (3) helping
with the integration of new clean energy
resources.159 Finally, New England
State Agencies argue that, because parts
of MISO as well as most of ERCOT are
already employing AARs, there can be
no serious argument that AARs are too
difficult or costly to implement as was
suggested by some transmission
owners.160
70. OMS states that it supports the
NOPR proposal that AAR requirements
generally apply to all transmission lines
and not just those with historical
congestion.161 OMS notes that the most
expensive energy prices typically occur
after unforeseen outages or weather
events and are not the result of chronic,
well understood scenarios. However,
OMS also states that it does not support
requiring AARs on those facilities where
it is uneconomical or unreliable to do
so.162 OMS contends that the
Commission should require RTOs/ISOs
to develop a process whereby
transmission owners transparently work
with the RTOs/ISOs and market
monitors to demonstrate why any
exceptions from the requirements are
justified.163
71. Ohio FEA also supports the AAR
NOPR proposal, stating that AARs help
ratepayers to realize the full benefits of
154 New England State Agencies Comments at 10;
OMS Comments at 2; Ohio FEA Comments at 2.
155 New England State Agencies Comments at 10.
156 Id.
157 Id. at 10–11.
158 Id. at 12.
159 Id.
160 Id.
161 OMS Comments at 8–10; see also OMS Reply
Comments at 7, 10.
162 OMS Comments at 9.
163 Id.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
their transmission system investment.
Ohio FEA explains that the four Ohio
transmission owners have already
recognized the benefits of AARs, as a
way of moving away from static
ratings.164 However, UDPU contends
that the AAR NOPR proposal should be
limited to certain historically congested
facilities until the Commission has
better information to assess the costs
and benefits of broad AAR
implementation.165
72. CEA encourages the Commission
to further consider the costs associated
with the proposed changes, as a broader
use of AARs may over-estimate the
benefit to cost ratio. CEA contends that
the use of AARs presents a significant
cost challenge considering the number
of upgrades required.166
73. Other technical experts are also
supportive of more accurate
transmission line ratings.167 R Street
Institute states that understated
transmission line ratings can result in
increased congestion costs and
underutilization of generation in exportconstrained locales, which is
disproportionately zero-emission
generation.168 R Street Institute
contends that the Commission should
require DLRs by default and permit
exceptions where justified by a costbenefit analysis.169
74. WATT supports the direction the
Commission is taking with the NOPR’s
AAR requirements, but explains that
additional factors that affect
transmission line ratings but are not
incorporated into AARs are very
knowable.170 WATT contends that the
Commission should require the use of
DLRs when certain criteria are met.171
LineVision supports WATT’s comments
and states that DLR implementation will
also result in additional accuracy and
situational awareness.172
75. Renewable energy advocates are
also generally supportive of the AAR
NOPR proposal, but urge the
Commission to take further measures to
spur the implementation of DLRs.173 For
example, ACORE commends the
Commission for issuing the NOPR, but
recommends the Commission take
further steps to encourage DLR
deployment by incenting its deployment
FEA Comments at 2–4.
Comments at 1–3.
166 CEA Comments at 2.
167 R Street Institute Comments at 1; WATT
Comments at 1–2; LineVision Comments at 1–2.
168 R Street Institute Comments at 1.
169 Id. at 3, 5–7.
170 WATT Comments at 1–2.
171 Id. at 10–12.
172 LineVision Comments at 1–2.
173 ACORE Comments at 1; Clean Energy Parties
Comments at 2, 4–6.
through transmission incentives and
incorporating its assessment into
transmission planning processes.174
Similarly, Clean Energy Parties contend
that AARs are easy to implement and a
modest improvement over static line
ratings.175 However, Clean Energy
Parties argue that DLR is superior to
AAR, though Clean Energy Parties do
not contend a blanket DLR mandate is
appropriate.176 ACPA/SEIA support
accurate transmission line ratings, and
contend that the Commission should
require all transmission owners and
transmission providers to study the
costs and benefits of implementing
DLRs on persistently congested
transmission lines and require
implementation where warranted.177
ACPA/SEIA and Clean Energy Parties
both argue that the Commission should
alter its NOPR proposal to prioritize
transmission lines that are expected to
be congested, persistently congested, or
likely to be congested in the future.178
76. Generator owners and
representatives are also generally
supportive of the proposed AAR
requirements.179 EDFR argues that
getting the transmission line rating
policy right is important due to the
urgency of addressing the climate crisis
and President Biden’s carbon emissions
reduction goals. EDFR contends that a
lack of adequate transfer capability can
cripple clean energy generation.180
EDFR further explains that, under many
offtake agreements in RTO/ISO markets,
the developer is paid a fixed price for
energy at a market hub and if congestion
limits the project’s ability to deliver
power to the hub, then the developer
bears the risk (known as basis risk).
EDFR argues that congestion is difficult
to hedge in an effective way because
system topology and conditions change
unexpectedly over time, but states that
more accurate transmission line ratings
will decrease basis risk and hedging
difficulties.181 EDFR contends that
prioritization should not only consider
historical congestion, but should
consider future congestion based on
transmission planning, interconnection,
and transmission service studies for
purposes of prioritizing
implementation.182
164 Ohio
165 UDPU
PO 00000
Frm 00014
Fmt 4701
Sfmt 4700
174 ACORE
Comments at 1.
Energy Parties Comments at 4–5.
176 Id. at 5, 8.
177 ACPA/SEIA Comments at 5–7.
178 Id. at 8–9; Clean Energy Parties Comments at
8, 10.
179 ENEL Comments at 1; EDFR Comments at 1–
2; Vistra Comments at 1–2; EPSA Comments at 2.
180 EDFR Comments at 2.
181 Id.
182 Id. at 4.
175 Clean
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
77. EPSA contends that the
Commission should encourage the use
of technological advances that improve
transmission operators’ ability to track
and optimize transmission line ratings
and usage where feasible and cost
effective. EPSA states that PJM’s
adoption of AAR requirements has
shown clear benefits.183 Vistra is
supportive of the Commission’s NOPR
proposal, stating that it is imperative
that the Commission act now to make
best use of existing infrastructure and
that AARs and DLRs are the best way to
do that.184
78. Industrial Customer
Organizations, TAPS, and Certain TDUs
are also broadly supportive of the AAR
NOPR proposal.185 Certain TDUs state
that they support the proposed rule and
encourage the Commission to mandate
improvements to the accuracy and
transparency of transmission line
ratings because not all transmission
owners have shown a willingness to
make these improvements
voluntarily.186 Certain TDUs state that
they support the use of AARs as a way
to better utilize the existing
transmission system, noting that it will
become imperative that the existing
transmission system is utilized to the
greatest extent possible as additional
renewable resources come online.187
79. Industrial Customer Organizations
state that they generally support the
proposed rules, but assert that these
rules should be implemented as soon as
practicable.188 Industrial Customer
Organizations argue that, if
prioritization is needed, congested
circuits should be prioritized.189
Industrial Customer Organizations
explain that understated transmission
line ratings increase congestion and may
lead to curtailments. Industrial
Customer Organizations contend that
transmission owners that understate
transmission line ratings may create an
illusory need for transmission upgrades.
Further, Industrial Customer
Organizations contend that some
transmission line ratings may be
deliberately understated because
transmission owners may have a profit
incentive to calculate understated
transmission line ratings in order to
benefit local generation.190
jspears on DSK121TN23PROD with RULES2
183 EPSA
Comments at 2.
184 Vistra Comments at 1–2.
185 Industrial Customer Organizations Comments
at 1–2; TAPS Comments at 1–2; Certain TDU
Comments at 1.
186 Certain TDUs Comments at 4.
187 Id. at 4–5.
188 Industrial Customer Organizations Comments
at 15–18.
189 Id. at 18–19.
190 Id. at 4.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
80. TAPS states that it supports the
proposed broad application of AARs
because it reduces the likelihood that
AARs will be implemented in a
discriminatory manner.191 Similarly,
Clean Energy Parties cite Order No.
888,192 in which the Commission stated
that ‘‘[d]enials of access [to transmission
services] (whether they are blatant or
subtle), and the potential for future
denials of access [to transmission
services], require the Commission to
revisit and reform its regulation of
transmission in interstate
commerce.’’ 193 According to Clean
Energy Parties, Order No. 888 supports
the assertion that a lack of consistency
and transparency in transmission line
ratings creates the potential for future
denials of access to transmission
service, as inaccurate transmission line
ratings are used to provide
discriminatory transmission service to
preferential customers.194
81. Additionally, TAPS notes that the
NOPR proposal would require the use of
AARs when evaluating requests for
near-term point-to-point transmission
service and contends that the
Commission should also apply the
requirements to requests for near-term
secondary service requests and nearterm network resource designations.
TAPS explains that secondary service
comes ahead of non-firm point-to-point
transmission service in curtailment
priority, and the NOPR proposal flips
this priority.195
82. Prysmian discourages mandatory
AAR implementation without
consideration of other variables and
without a holistic evaluation of all
transmission line rating inputs to
determine whether an overall
transmission line rating methodology is
conservative or not. Prysmian states that
AARs can also lead to situations in
which near-term transfer capability is
overstated.196
191 TAPS
Comments at 7.
Wholesale Competition Through
Open Access Non-Discriminatory Transmission
Services by Public Utilities; Recovery of Stranded
Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21540 (May 10, 1996), FERC
Stats. & Regs. ¶ 31,036 (1996) (cross-referenced at 75
FERC ¶ 61,080), order on reh’g, Order No. 888–A,
62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs.
¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220),
order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248
(1997), order on reh’g, Order No. 888–C, 82 FERC
¶ 61,046 (1998), aff’d in relevant part sub nom.
Transmission Access Policy Study Group v. FERC,
225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New
York v. FERC, 535 U.S. 1 (2002).
193 Id. at 31,652.
194 Clean Energy Parties Comments at 2–3.
195 TAPS Comments at 20.
196 Prysmian Comments at 1.
192 Promoting
PO 00000
Frm 00015
Fmt 4701
Sfmt 4700
2257
c. Commission Determination
83. In this final rule, we adopt with
certain modifications the NOPR
proposal to require transmission
providers to apply the AAR
requirements set forth in pro forma
OATT Attachment M to all transmission
lines, subject to the exceptions
described below in Section IV.D.3.197 As
discussed above, the AAR requirements
will ensure that transmission line
ratings are more accurate. In turn, more
accurate transmission line ratings will
ensure wholesale rates more accurately
reflect the cost of the wholesale service
being provided (i.e., energy, capacity,
ancillary services, or transmission
service) and, thus, that those wholesale
rates are just and reasonable. We further
describe, below, the requirements and
the modifications to the NOPR proposal
adopted herein.
84. First, we adopt the proposal to
apply the AAR requirements as set forth
under ‘‘Obligations of Transmission
Provider’’ in pro forma OATT
Attachment M to all transmission lines
subject to the exceptions described
below in Section IV.D.3. We find that
applying the AAR requirements to all
transmission lines will both ensure that
wholesale rates remain just and
reasonable and strike an appropriate
balance between benefits and challenges
of AAR implementation. For this reason,
we do not adopt the phased-in
implementation schedule proposed in
the NOPR in which a transmission
provider would initially implement
AARs on only historically congested
lines.
85. As the Commission preliminarily
found in the NOPR 198 and as the record
demonstrates, despite differences across
transmission systems, simply
accounting for ambient air temperatures
in transmission line ratings can reliably
increase power transfer capability,
resulting in significant reliability,
operational, and economic benefits.
Numerous commenters describe these
benefits.199 For example, Potomac
Economics estimates that the benefits to
AAR implementation in MISO alone
would have produced approximately
$67 million and $49 million in reduced
congestion costs in 2019 and in 2020,
197 NOPR,
173 FERC ¶ 61,165 at PP 92, 102.
P 99.
199 MISO Transmission Owners Comments at 8–
9; PacifiCorp Comments at 2; EEI Comments at 4–
5; Entergy Comments at 1–2; BPA Comments at 2–
4; NYTOs Comments at 2–3, 5; Duke Energy
Comments at 6–7; PG&E Comments at 1; LADWP
Comments at 2–3; ITC Comments at 1–3; Sunflower
Comments at 2; Exelon Comments at 1–2; AEP
Comments at 3; Indicated PJM Transmission Owner
Comments at 2; PJM Comments at 2; PJM Comments
at 2; New England State Agencies Comments at 7;
TAPS Comments at 5.
198 Id.
E:\FR\FM\13JAR2.SGM
13JAR2
2258
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
respectively.200 Exelon describes AARs
as a best practice that cost-effectively
enhances transmission utilization,
benefiting customers, without adverse
safety and reliability impacts.201 EEI
acknowledges that experience with
AARs shows that their use can provide
benefits on certain subsets of
transmission facilities.202 PJM states
that, in its experience, AARs increase
operational flexibility, promote a more
efficient use of the transmission system,
and result in more reliable system
dispatch and cost-effective market
operations.203 New England State
Agencies argue that the Commission
should take all reasonable steps to
protect ratepayers from excessive costs
and that the use of AARs, by permitting
more power to flow than a system
operated using static or seasonal line
ratings, can be an important tool in this
regard.204 Similarly, TAPS explains that
reliance on static and seasonal line
ratings inflicts unnecessary costs on
consumers and contends that
deployment of AARs using commercial
temperature forecasts can produce
significant benefits to consumers at low
cost.205 While several entities note
implementation costs as a barrier, these
costs are mostly initial investment costs
in EMS improvements to accommodate
AARs, implementation of a ratings
database, and review (and potentially
reset) of protective relays settings.206
Once these initial investments are made,
adding AARs to additional transmission
lines appears to have a minimal
incremental cost.207
86. Second, in this final rule we adopt
a requirement for transmission
providers to use AARs when evaluating
the availability of and requests for nearterm transmission service (under
sections 15, 17, 18, and 29 of the pro
forma OATT).208 For purposes of this
requirement, we define ‘‘requests for
near-term transmission service’’ to
include not only requests for near-term
point-to-point transmission service, but
also network resource designations and
secondary service where the start and
end date of the designation/request is
within the next 10 days. Specifically,
200 Potomac
Economics Comments at 7–8.
Comments at 1.
202 EEI Comments at 5.
203 PJM Comments at 2.
204 New England State Agencies Comments at 5–
6, 10–11.
205 TAPS Comments at 5.
206 Indicated PJM Transmission Owner Comments
at 5–6; Exelon Comments at 14; AEP AD19–15 Post
Technical Conference Comments at 3.
207 Exelon Comments at 8; Indicated PJM
Transmission Owner Comments at 5–6; AEP PostTechnical Conference Comments at 2–3; September
2019 Technical Conference, Day 1 Tr. at 180–181.
208 NOPR, 173 FERC ¶ 61,165 at P 87.
jspears on DSK121TN23PROD with RULES2
201 Exelon
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
we require transmission providers to
use AARs as the relevant transmission
line ratings when: (1) Evaluating
requests for near-term transmission
service, defined as transmission service
ending within 10 days of the date of the
request; (2) responding to requests for
information on the availability of
potential near-term transmission service
(including requests for ATC or other
information related to potential service);
and (3) posting ATC or other
information related to near-term
transmission service to their OASIS site.
As discussed further below, in response
to comments, we modify this
requirement from the NOPR proposal to
include near-term network and nearterm secondary service, as well as the
near-term point-to-point transmission
service proposed in the NOPR.209
87. Third, we adopt the Commission’s
proposal in the NOPR to require that
transmission providers use AARs as the
relevant transmission line rating when
determining whether to curtail or
interrupt near-term point-to-point
transmission service (under sections
13.6 and/or 14.7 of the pro forma
OATT) 210 if such curtailment or
interruption is both necessary because
of issues related to flow limits on
transmission lines and anticipated to
occur (start and end) within the next 10
days.211
88. Fourth, we adopt the proposal in
the NOPR 212 to require that
transmission providers use AARs as the
relevant transmission line ratings when
determining whether to curtail network
or secondary service (under section 33
of the pro forma OATT) or redispatch
network or secondary service (under
sections 30.5 and/or 33 of the pro forma
OATT), if such curtailment or
209 Although requests for network transmission
service are typically long-term requests, meriting
their evaluation using seasonal line ratings, we note
the Commission’s finding in Order No. 890 that the
minimum term for network transmission service
should be the same as the minimum time period
used for firm point-to-point transmission service
(i.e., daily). See Preventing Undue Discrimination
and Preference in Transmission Service, Order No.
890, 72 FR 12266 (Mar. 15, 2007), 118 FERC
¶ 61,119, at P 1505, order on reh’g, Order No. 890–
A, 73 FR 2984 (Jan. 16, 2008), 121 FERC ¶ 61,297
(2007), order on reh’g, Order No. 890–B, 123 FERC
¶ 61,299 (2008), order on reh’g, Order No. 890–C,
74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228,
order on clarification, Order No. 890–D, 129 FERC
¶ 61,126 (2009). As such, any requests for
transmission service that fall within the near-term
threshold defined herein would qualify as nearterm network transmission service.
210 Additionally, we add references to
interruption or curtailment of near-term point-topoint transmission service occurring pursuant to
13.6 of the pro forma OATT to Attachment M in
order to ensure consistent treatment of firm and
non-firm point-to-point transmission service.
211 NOPR, 173 FERC ¶ 61,165 at P 89.
212 Id. P 90.
PO 00000
Frm 00016
Fmt 4701
Sfmt 4700
redispatch is both necessary because of
issues related to flow limits on
transmission lines and anticipated to
occur (start and end) within 10 days of
such determination.
89. Fifth, we adopt and modify the
proposal in the NOPR to allow RTOs/
ISOs to comply with the final rule’s
AAR requirements by revising their
OATTs to require implementation of
AARs within their security constrained
economic dispatch (SCED) and security
constrained unit commitment (SCUC)
models (and in any relevant related
models) in both the day-ahead and realtime markets and reliability unit
commitment (RUC) processes,213 and
any other intra-day RUC processes.214
As the Commission recognized in the
NOPR, such entities have Commissionapproved variations from the pro forma
OATT to manage congestion and initiate
curtailments and/or redispatch of
transmission service within their
footprints (although generally not at
their borders) through mechanisms such
as SCED and SCUC. As discussed in
Section IV.B.3.b, we adopt the
Commission’s NOPR proposal to require
that transmission providers—including
RTOs/ISOs—update their AARs at least
hourly. As discussed in Sections
IV.B.3.b and IV.B.3.c, for any seamsbased transmission service offered by
RTOs/ISOs, we adopt the Commission’s
NOPR proposal to implement the nearterm transmission service requirements
for inclusion of up-to-date hourly AAR
calculations in ATC.
90. We do not adopt the NOPR
proposal to establish a definition of
historically congested transmission
lines. Accordingly, since we are not
adopting the NOPR’s proposed
definition of historically congested
transmission line, and instead apply the
AAR requirements adopted herein to all
transmission lines, we do not address
comments related to the NOPR’s
proposed definition of historically
congested transmission line. To the
213 After the day-ahead market process takes
place, RTOs/ISOs typically perform one or more
residual unit commitment processes, or what we
refer to here as RUC, to address remaining resource
gaps and reliability issues or to manage uncertainty
and the potential for real-time operational issues.
The exact names, definitions, and market processes
implementing what we refer here to as RUC
processes differ across RTOs/ISOs. For example,
CAISO refers to its process as residual unit
commitment, SPP uses reliability unit commitment,
and MISO uses reliability assessment commitment.
For simplicity, however, this final rule uses the
term RUC to refer to all of these relevant processes
in all of the RTO/ISO markets interchangeably.
214 NOPR, 173 FERC ¶ 61,165 at P 91. The
statement ‘‘(and in any relevant related models)’’
was intended to encompass all RUC processes
within the timeframe. In the interest of clarity, we
modify the NOPR proposal here to make that more
explicit.
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
extent that commenters were arguing for
a narrower application than what we
adopt in this final rule, below we
explain the basis for application of the
AAR requirements to all transmission
lines.
91. Finally, we alter the proposed
compliance schedule. Specifically, we
require each transmission provider to
submit a compliance filing within 120
days of the effective date of this final
rule to incorporate into its OATT the
changes adopted herein consistent with
pro forma OATT Attachment M and the
changes to the Commission’s regulations
set forth below. Additionally, we further
require that all requirements adopted
herein be fully implemented no later
than three years from the compliance
filing due date established by this final
rule.
92. In response to comments received
in response to the NOPR, we modify the
NOPR proposal’s defined term ‘‘nearterm point-to-point transmission
service’’ to instead be ‘‘near-term
transmission service.’’ As a result, the
AAR requirements will apply to
requests for near-term network
transmission service, near-term
secondary service, and near-term pointto-point transmission service, provided
that such service meets the 10-day
threshold defined in the near-term
transmission service definition. We
agree with TAPS that it would be
inappropriate to apply the AAR
requirements only to requests for nearterm point-to-point transmission service
and not to requests for near-term
network and near-term secondary
service because secondary service
comes before non-firm point-to-point
transmission service in curtailment
priority.215 More generally, we find that
a requirement to use AARs on all types
of near-term transmission service will
better ensure that transmission line
ratings are accurate and that wholesale
rates are just and reasonable.
93. Although commenters broadly
raise concerns with adopting
transmission line ratings that may
fluctuate widely or contend that
implementing AARs on certain
transmission lines may not yield
benefits, we do not find that these
concerns and arguments overcome the
need to improve the accuracy of
transmission line ratings through
applying the AAR requirements to all
transmission lines. Specifically, we
decline to accommodate requests for
more targeted AAR requirements in
which transmission providers would
either have flexibility to identify
candidate transmission lines or the
215 TAPS
Comments at 18–20.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
Commission would require AAR
implementation on only priority
transmission lines, such as only on
historically congested lines.
94. We recognize commenters’
concerns, such as those from NRECA/
LPPC, that the promised benefits, costs,
and risks of implementing AARs may
not be evenly distributed nationwide.216
Nevertheless, we find that with the
broad AAR requirements adopted
herein, the overall benefits via savings
to load and lower congestion charges to
generators will on balance outweigh the
costs. Moreover, we acknowledge the
difficulty of knowing in advance all the
locations and situations in which the
benefits of AAR implementation will
outweigh the costs. Given the difficulty
in predicting unexpected congestion
before it happens, narrowing the scope
of the AAR requirements would limit
the ability of these reforms to ensure
just and reasonable wholesale rates. In
particular, we find that the AAR
requirements adopted in this final rule
are beneficial in mitigating the impact of
transient congestion, i.e., temporary or
short-term congestion that does not
occur on a regular basis, such as
congestion caused by unexpected
equipment outages or other unusual
conditions. Furthermore, given the
increasing occurrence of extreme
weather events, we expect that assessing
the benefits of broader AAR
implementation based on historical
congestion likely understates the
potential savings associated with
implementation of the AAR
requirements adopted in this final rule.
By contrast, the record demonstrates
that AAR implementation costs are
predominantly one-time investment
costs in EMS improvements to
accommodate AARs, implementation of
a ratings database, and review (and
potentially reset) of protective relays
settings.217 Once these costs have been
incurred, the incremental cost of
applying AARs to additional
transmission facilities is minimal.218
95. Attempts to anticipate the
situations in which AARs will not be
cost beneficial (e.g., attempts to forecast
locations and situations in which there
will be future congestion and deploy
AARs in only those anticipated
situations) will necessarily be imperfect
and complex, especially during
infrequent but consequential events.
Additionally, since many emergencies
may come and go before new AARs can
216 NRECA/LPPC
Comments at 15.
Comments at 8–9.
218 Id. at 8; Indicated PJM Transmission Owner
Comments at 5–6; AEP Post-Technical Conference
Comments at 2–3; September 2019 Technical
Conference, Day 1 Tr. at 180–181.
217 Exelon
PO 00000
Frm 00017
Fmt 4701
Sfmt 4700
2259
be developed and implemented for
newly congested transmission lines, a
more targeted AAR requirement
advocated by some commenters may not
accurately represent system transfer
capability in such critical situations. As
the Commission recognized in the
NOPR, congestion is difficult to predict,
particularly during emergency
conditions.219 The 2019 FERC and
NERC Staff Report on the January 2018
South Central cold weather event
illustrates this point.220 As shown by
that event, during times of emergency or
system stress, flows may change
considerably from normal operations
and the increased transfer capability
provided through AARs may prove
valuable even on transmission lines that
are not typically congested.221 In
addition, in the February 2021 cold
weather event, MISO experienced
unprecedented east-to-west flows
throughout the footprint and accrued
$773 million in congestion charges in
just a few days.222 We note that with
broad AAR implementation, given
Potomac Economics’ finding that AAR
implementation consistently results in
savings of approximately 5% to 8% of
total congestion,223 congestion cost
savings from this single event might
have exceeded the total costs of AAR
implementation in the region. Moreover,
many argue that the changing generation
mix makes congestion prediction even
more difficult.224 Additionally, AAR
implementation itself will have
secondary consequences for congestion
patterns, as changes to transmission line
ratings may change generation dispatch
patterns and, by extension, congestion
patterns. Such secondary congestion
consequences may only be able to be
promptly addressed by a broad AAR
requirement that applies to all
transmission lines.
96. Beyond congestion costs, during
times of stressed system conditions,
operators in RTOs/ISOs might have to
219 NOPR,
173 FERC ¶ 61,165 at P 93.
FERC and NERC Staff Report, The South
Central United States Cold Weather Bulk Electric
System Event of January 17, 2018, at 96 (July 2019)
(FERC and NERC Staff Report), https://
www.ferc.gov/sites/default/files/2020-05/07-18-19ferc-nerc-report_0.pdf.
221 NOPR, 173 FERC ¶ 61,165 at P 93.
222 OMS Comments at 10; OMS Reply Comments
at 7; see FERC, NERC and Regional Entity Staff
Report, The February 2021 Cold Weather Outages
in Texas and the South Central United States (Nov.
16, 2021), https://www.ferc.gov/media/february2021-cold-weather-outages-texas-and-south-centralunited-states-ferc-nerc-and.
223 Potomac Economics Comments at 8; Potomac
Economics Post-Technical Conference Comments at
5–6.
224 ACPA/SEIA Comments at 8, 11; EPSA
Comments at 4; New England State Agencies
Comments at 6.
220 2019
E:\FR\FM\13JAR2.SGM
13JAR2
2260
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
spend limited time requesting AARs
from transmission owners on an ad hoc
basis.225 AAR implementation on all
transmission lines will help ensure
transmission providers have sufficient
transfer capability and flexibility to
manage emergency conditions. Delayed
access to AARs could force transmission
operators to spend precious time
reaching out to transmission owners for
AARs, rather than using such time to
manage emergency conditions. Instead,
AAR implementation on all
transmission lines will alleviate the
need for transmission providers to
spend time requesting AARs when there
may be no time to waste.
97. Further, arguments that the
benefits of broad AAR implementation
will not outweigh the costs are
inconsistent with the ERCOT and PJM
transmission owners’ actual AAR
implementation experience. AEP has
been implementing AARs for decades
and has realized both reliability and
financial benefits for its customers.226
As Indicated PJM Transmission Owners
state, transmission owners in PJM
provide AARs for each of their facility
ratings.227 PJM further states that the
use of AARs is commonplace among the
overwhelming majority of transmission
owners in PJM.228 As New England
State Agencies observe, the broad
experience implementing AARs does
not support the argument that AARs are
too difficult or costly to implement.229
98. In response to MISO Transmission
Owners’ argument that the Commission
should not rely on Potomac Economics’
estimates of the benefits of AARs, our
rationale for the AAR requirements
adopted in this final rule is not solely
based on Potomac Economics’ analysis.
Rather, our rationale is based on the
finding that AARs on all transmission
lines will ensure that wholesale rates
more accurately reflect the cost of the
wholesale service being provided, and,
thus that those wholesale rates are just
and reasonable. This finding is further
informed by the widespread benefits
experienced by commenters
implementing AARs broadly in PJM and
ERCOT, the expectation that the benefits
of AAR implementation will be greatest
on transmission lines that are frequently
congested, along with the understanding
225 OMS Reply Comments at 7; see also FERC and
NERC Staff Report at 56–59; ISO–NE, Cold Weather
Operations: December 24, 2017—January 8, 2018, at
41 (Jan. 16, 2019), https://www.iso-ne.com/staticassets/documents/2018/01/20180112_cold_
weather_ops_npc.pdf.
226 AEP Comments at 3.
227 Indicated PJM Transmission Owners
Comments at 6–7.
228 PJM Comments at 2.
229 New England State Agencies Comments at 11–
12.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
of the difficulty of predicting congestion
and the low incremental cost to
implement AARs. However, in response
to MISO Transmission Owners’ critique
that Potomac Economics’ analysis
erroneously assumes that all
transmission lines in MISO are ambient
adjustable, we note that, in response to
MISO Transmission Owners’ comments,
Potomac Economics states that its
analysis does not assume that all
transmission lines are able to be rated
using AARs and instead removes from
the analysis all transmission lines that
currently have summer ratings equal to
winter ratings.230 With respect to MISO
Transmission Owners’ argument that
Potomac Economics’ analysis
erroneously assumes that all
transmission lines in MISO are
currently using worst-case ambient air
temperature assumptions, we note that
Potomac Economics does not uniformly
assume worst-case 104 degrees
Fahrenheit as the basis for adjusting
AARs, but instead infers unique
transmission owner base assumptions
using maximum historical temperatures
in each transmission owner service
territory.231 Finally, we disagree with
MISO Transmission Owners’ assertion
that the benefits in Potomac Economics’
analysis are inflated because of certain
transmission outages or upgrades
assumptions. As Potomac Economics
explains, there are many generalized
and localized factors that might increase
or decrease congestion in an individual
year and, given the highly complex
nature of the electric system,
incorporating all of these factors is not
possible.232 Despite certain
generalizations, which we believe are
likely to render Potomac Economics’
analysis conservative, Potomac
Economics has consistently found that
AARs and emergency ratings will
reduce congestion by 10% to 15%
annually.233
99. We disagree with arguments from
Southern Company, EEI, and other
commenters that reliability issues may
arise because AARs may create
difficulties in identifying the most
limiting element and similar difficulties
and costs associated with complying
with Reliability Standard PRC–023–4’s
transmission relay loadability
requirements that depend on maximum
published ratings. Reliability Standard
PRC–023–4 requires setting
transmission line relays at values at or
above 115 to 170% of various maximum
values for current or power carrying
230 Potomac
Economics Reply Comments at 3–5.
at 2–3.
232 Id. at 5–6.
233 Id. at 5.
231 Id.
PO 00000
Frm 00018
Fmt 4701
Sfmt 4700
capability, e.g., 115% of the highest
seasonal 15-minute Facility Rating of a
circuit or 150% of the highest seasonal
four-hour Facility Rating of a circuit. We
do not agree that this final rule will
result in PRC–023–4 related relay
setting changes to ‘‘thousands’’ 234 of
relays, since the relay settings are
currently calculated based on practical
limitations which in the majority of
cases should not exceed AAR values. In
addition, PJM has long implemented
AARs and, rather than describing
reliability challenges, contends that
AAR implementation creates reliability
benefits.235 For example, PJM states that
the adoption of AARs increases
operational flexibility, promotes a more
efficient use of the transmission system,
and results in more reliable system
dispatch and cost-effective market
operations.236 Transmission owners in
PJM have implemented AARs despite
the initial cost incurred to update relay
settings. Likewise, AEP submits that it
has implemented AARs for decades and
that AAR implementation presents
reliability benefits.237
100. In response to concerns about the
additional challenges associated with
incorporating AARs into ATC, as raised
by Duke Energy, EEI, and several nonRTO/ISO transmission owners with
service territories in the Western
Interconnection, we note that such TTC
calculation practices, and in turn ATC
practices, particularly those which only
update TTC values annually,238 will
need to be updated in order to comply
with this final rule’s AAR requirements.
In fact, such practices may already be
out of compliance with the
Commission’s existing ATC calculation
rules. For example, while Order No. 890
provides transmission providers with
significant flexibility in what approach
they take to determine ATC in their
transmission paths, it also requires that
ATC values (regardless of the approach
used to calculate them) be ‘‘updated and
benchmarked to actual events.’’ 239
Furthermore, in May 2021, the
Commission issued Order No. 676–J,240
in which the Commission (among other
things) codified the ‘‘fundamentals of
Order No. 890 requirements for
calculating ATC’’ in the Commission’s
regulations.241 Specifically, Order No.
234 EEI
Comments at 5–6.
Comments at 7.
236 Id. at 2.
237 AEP Comments at 3.
238 EEI Comments at 11.
239 Order No. 890, 118 FERC ¶ 61,119 at P 290.
240 Standards for Business Practices and
Communication Protocols for Public Utilities, Order
No. 676–J, 86 FR 29491 (June 2, 2021), 175 FERC
¶ 61,139 (2021).
241 Id. P 38.
235 PJM
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
676–J revised section 37.6(b)(2)(i) of the
Commission’s regulations to codify that
ATC calculations must be ‘‘conducted
in a manner that is . . . consistent with
anticipated system conditions and
outages for the relevant timeframe.’’ 242
We find that transmission line ratings
represent one such ‘‘system condition’’
with which ATC calculations must be
consistent.
101. In response to specific concerns
from PacifiCorp and BPA about
nomogram constraints, we note that
nomogram constraints are typically used
to represent transfer capability on
facilities with stability or voltage
limitations. The AAR requirements
adopted in pro forma OATT Attachment
M exempt transmission lines whose
ratings are not affected by ambient air
temperature.
102. In response to comments from
NERC requesting further consideration
of AAR implementation on long
transmission lines, and from LADWP,
and other, primarily western
transmission owners, which describe
AAR implementation challenges due to
the diversity in terrain and
microclimates that western transmission
lines traverse, we agree that longer
transmission lines can and will
experience differing weather conditions
across the length of those transmission
lines. To maintain reliable system
operations, we expect transmission
providers to implement the
transmission line rating calculated
based on the most limiting element
under the prevailing weather conditions
(actual or anticipated) at the relevant
point on the transmission line. In the
case of transmission conductors, which
might be exposed to different weather
conditions along the length of the
transmission line, transmission
providers must rate such elements using
the most limiting weather conditions, in
accordance with good utility practice.
However, this requirement does not
require the installation of field devices
or sensors, as some transmission owners
suggest.243 Rather, as proposed in the
NOPR, the AAR requirements can be
met through the use of a weather data
service.244
103. Similarly, in response to
comments from BPA that if BPA uses
AARs as proposed, it would need to
make its current liberal wind
assumptions (and therefore, the
resultant transmission line ratings) more
conservative to mitigate the risk of
2. Specific AAR Implementation
Requirements
a. Use of AARs 10-Days Forward in
Transmission Service and Operations
i. NOPR Proposal
104. In the NOPR, within the context
of the AAR requirements described and
adopted above in Section IV.B.1, the
Commission proposed to apply the AAR
requirements to transmission service
that starts/ends within 10 days, to the
curtailment or interruption of point-topoint transmission service anticipated
to occur (start and end) within the next
10 days, and to the curtailment of
network transmission service or
secondary service or redispatch network
transmission service or secondary
transmission service anticipated to
occur (start and end) within 10 days
(hereinafter referred to as the ‘‘10-day
threshold’’).
105. The Commission justified the
proposed 10-day threshold as a
reasonable cut-off beyond which
forecasts may not be accurate enough for
AARs to provide significant value, and
by stating that the Commission believed
that such a limit would reasonably
accommodate requests for weekly pointto-point transmission service. The
Commission further noted that ambient
air temperature forecasts for intervals
beyond the proposed 10-day threshold
tend to converge to the longer-term
ambient air temperature forecasts used
in seasonal line ratings.247 Finally, the
Commission noted that its proposal
allowed transmission providers to
determine (consistent with good utility
practice) the needed degree of certainty
when constructing their forecasts of
ambient air temperature.248
106. With respect to RTOs/ISOs, the
Commission proposed to require AARs
as the relevant transmission line rating
for any point-to-point transmission
service offered (e.g., at their borders).
245 BPA
242 Id.
243 WAPA
operating near the conductor limit,245
we reiterate that the AAR requirements
will ensure more accurate transmission
line ratings, not necessarily higher
transmission line ratings. We further
clarify that there is no requirement to
change wind speed assumptions.
Utilities have operated reliably for
decades with AARs.246 However, if any
transmission owner finds it necessary to
change its wind speed assumptions
consistent with good utility practice, we
clarify that nothing in this rulemaking
prevents it from doing so.
Comments at 7–9; PG&E Comments at
9–10.
244 NOPR, 173 FERC ¶ 61,165 at P 95.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
Comments at 4.
Comments at 3.
247 NOPR, 173 FERC ¶ 61,165 at PP 87–88.
248 Id. P 102.
246 AEP
PO 00000
Frm 00019
Fmt 4701
Sfmt 4700
2261
However, the Commission also
recognized that RTOs/ISOs have
Commission-approved variations from
the pro forma OATT to manage internal
congestion and initiate curtailments
and/or redispatch of transmission
service within their footprints through
mechanisms such as SCED and SCUC.
To accommodate these variations, the
Commission proposed that RTOs/ISOs
comply with the proposed requirements
by revising their OATTs to require
implementation of AARs within their
SCED and SCUC models (and in any
relevant related models) in both the dayahead and real-time markets and any
intra-day RUC processes. For real-time
markets, the Commission proposed that
RTOs/ISOs update their AARs at least
hourly. For any point-to-point
transmission service offered by RTOs/
ISOs (e.g., at their borders), the
Commission proposed that the AAR
requirements discussed above for pointto-point transmission service would
apply. As justification, the Commission
explained that day-ahead markets
already rely upon forecasts of weather to
inform next-day load and intermittent
generation availability. The Commission
preliminarily agreed with PJM that
temperatures can be forecast with a
reasonable degree of certainty in dayahead markets.249 The Commission
further stated that, within its NOPR
proposal, transmission providers could
(consistent with good utility practice)
determine the needed degree of
certainty when constructing their
forecasts of ambient air temperature,
and that, because one of the goals of the
day-ahead market is to align prices with
those eventually determined in the realtime market, maintaining policy
consistency between the day-ahead and
real-time markets, where practical, is
desirable.250
ii. Comments
107. Many commenters generally
support the Commission’s proposed
AAR requirements without specifically
discussing the 10-day threshold.251
Industrial Customer Organizations
specifically agree with the Commission
that implementing AARs in near-term
transmission service will more
accurately reflect the cost of delivering
249 PJM
Post-Technical Conference Comments at
3.
250 NOPR,
173 FERC ¶ 61,165 at P 102.
Comments at 2; Clean Energy Parties
Comments at 2–3; R Street Institute Comments at
2–3; TAPS Comments at 1–3; ACORE Comments at
3; OMS Comments at 2; New England State
Agencies Comments at 10; Vistra Comments at 2–
3.
251 EPSA
E:\FR\FM\13JAR2.SGM
13JAR2
2262
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
energy to load.252 CEA states that using
AARs to calculate transmission line
ratings for service requests up to 10 days
has proven to be reliable and to provide
benefits to effective and reliable
transmission operations.253 EDFR
contends that the distinction between
AARs and seasonal line ratings
depending on the applicable time frame
appears sensible.254 ACPA/SEIA state
that they support the Commission’s
proposed requirements for near-term
point-to-point transmission service and
curtailments expected to occur within
the next 10 days.255 The Ohio FEA does
not take a firm position, but states that
implementing AARs for the next 10
days is reasonable.256 OMS states that
the weather data required to implement
AARs is already widely available
through public sources and used for
load and resource forecasting.257
108. While not supporting or
opposing the proposed 10-day
threshold, EPRI recommends an
independent assessment that documents
the accuracy and risk associated with
weather forecast data, explaining that
not all weather forecast data will be
appropriate for transmission line ratings
and that some limiting spans run
through microclimates. EPRI further
explains that inaccurate forecast risks
can be mitigated by identifying and
implementing corrective factors to allow
forecasts to be used consistent with
good utility practice. EPRI suggests
utility-specific rating studies would be
required to assess and mitigate forecast
risk,258 to update and revise weather
condition assumptions, and possibly to
adjust transmission reliability
margins.259 EPRI contends that further
studies are needed to determine a
technical basis for updated wind speed
assumptions and that such studies may
take between one and two years.260
Similarly, NERC asserts that the
Commission should consider how
variations in the temperature and load
forecast should be addressed, what
temperature sets should be used when
considering requests to grant firm
transmission service, and whether
252 Industrial Customer Organizations Comments
at 4–6.
253 CEA Comments at 2.
254 EDFR Comments at 7.
255 ACPA/SEIA Comments at 16–17.
256 Ohio FEA Comments at 5.
257 OMS Comments at 11.
258 EPRI Comments at 10–11.
259 Id. at 12. Transmission reliability margin, or
TRM, means the amount of TTC necessary to
provide reasonable assurance that the
interconnected transmission network will be
secure, or such definition as contained in
Commission-approved Reliability Standards. 18
CFR 37.6(b)(1)(viii) (2021)..
260 EPRI Comments at 12.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
additional AAR calculation information
should be incorporated into
transmission line rating
methodologies.261
109. Other commenters also discuss
risk management for forecasted ambient
air temperatures. For example, Entergy
states that forecasted ambient air
temperatures should include
appropriate safety margins to account
for historical forecast uncertainty.262
Similarly, the SPP MMU states that,
ideally, congestion costs should, to
some extent, represent the risk assumed
to serve the load.263 Finally, the CAISO
DMM argues that AAR requirements
should allow leeway for RTOs/ISOs to
adjust modeled transmission limits for
reliability reasons, as CAISO does in the
case of flowgates and nomograms whose
modeled flows frequently differ from
actual flows.264 The CAISO DMM
asserts that lower or more conservative
transmission limits might be needed for
temporally distant intervals to ensure
commitments made in an advisory
interval horizon are feasible in the
binding market interval and at the time
of power flow. The CAISO DMM further
asserts that lower day-ahead
transmission limits could promote the
feasibility of day-ahead commitments in
real time.265
110. Many RTOs/ISOs, however,
oppose or urge caution on the proposed
10-day threshold, with many advocating
instead for a 48-hour threshold.266 PJM
does not support use of AARs in ATC
calculations beyond 48 hours, arguing
that it would require significant system
changes and increase the compliance
burden.267 PJM proposes AARs for 48
hours, and a more conservative
approach for hours 48–240 to avoid
potential volatility and over-selling.268
Both NYISO and ISO–NE argue that the
transmission service offered in their
respective regions differs from that
contemplated by the pro forma OATT,
and request flexibility in implementing
any transmission line rating
requirements.269
111. NYISO does not support
extending the AAR requirements or
DLRs into the day-ahead market, or for
use up to 10 days into the future,
contending that such a requirement
261 NERC
Comments at 7.
Comments at 11.
263 SPP MMU Comments at 1.
264 CAISO DMM Comments at 3, 4–5, 7.
265 Id. at 3.
266 PJM Comments at 7–8; ISO–NE Comments at
10; MISO Comments at 10, 16–17; NYISO
Comments at 13–14.
267 PJM Comments at 7–8.
268 Id.
269 ISO–NE Comments at 10; NYISO Comments at
9.
262 Entergy
PO 00000
Frm 00020
Fmt 4701
Sfmt 4700
could result in costly and unnecessary
uplift payments, which could lead to
significant cost increases to customers,
and could present reliability concerns if
transmission line ratings decline in real
time from the day-ahead schedule,
forcing NYISO to rapidly reduce the
schedules of certain generators while
quickly ramping up other generators.270
NYISO also states that it would consider
designating a portion of transfer
capability to be able to respond to the
operational and cost volatility that
would come with DLR use, although
such a process would limit overall
efficiency and increase production
costs.271
112. Without taking a position on the
proposed 10-day threshold, CAISO
explains that the NOPR proposal would
significantly increase the complexity of
its day-ahead market and introduce
possible variances between real-time
and day-ahead schedules.272 Also
without taking a position on the
proposed 10-day threshold, SPP states
that, to use AARs to evaluate
transmission service requests that end
within 10 days or as the basis for
curtailment, SPP would have to make
several technical and process upgrades
and align its operating horizon and
planning horizon.273
113. MISO argues that the vast
majority of the benefit from AARs is in
addressing real-time congestion, and
that implementing AARs in MISO’s dayahead market would be difficult to do in
less than three years, while offering
comparatively little benefit. MISO
further claims that requiring hourly
AARs 10 days in advance will provide
little to no benefit because the accuracy
of temperature forecasts diminishes
considerably beyond 48 hours, and
precipitously by the five to seven day
mark.274 MISO urges the Commission to
limit AAR implementation to 48 hours
from the start of the operating day.275
Similarly, Potomac Economics
recommends that the Commission
require that AARs be used in the dayahead and real-time markets, stating that
this will allow the RTOs/ISOs to focus
their resources on improving the
transmission line ratings that will
generate almost all of the savings.
114. Similar to RTOs/ISOs,
transmission owners also urge caution
on, or oppose, the proposed 10-day
threshold.276 Those transmission
270 NYISO
Comments at 13–14.
271 Id.
272 CAISO
Comments at 9–11.
Comments at 5–7, 9.
274 MISO Comments at 18.
275 Id. at 19.
276 BPA Comments at 7; Indicated PJM
Transmission Owners Comments at 2; Dominion
273 SPP
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
owners generally argue that there is too
much risk forecasting 10 days forward
and generally support more limited
forecasting of either 24 277 or 48
hours.278 For example, Indicated PJM
Transmission Owners contend that
forecasting AARs beyond two or three
days in advance provides little benefit
because weather conditions beyond that
are too difficult to predict.279 Dominion
similarly argues there is no benefit to
extending the AAR requirements
beyond three to five days because
forecasts beyond five days tend to
reflect seasonal averages.280 Entergy
contends that forecasts should be
limited to three days and include
appropriate safety margins for historical
forecast uncertainty and geographic
variability.281
115. Several commenters argue that
requiring AARs 10 days in advance
presents the potential problem of selling
transmission service based on a given
ambient air temperature forecast only
for the temperature to be higher in real
time, causing curtailments or safety and
reliability risks.282 BPA argues that it
could result in an inefficient use of the
transmission system because
transmission could be sold, curtailed,
and then available again, all prior to the
transmission service window.283 NYTOs
note that, because there is generally less
flexibility in real time, if operators do
not have sufficient resources to restore
flow to a lower limit within the required
time, they may need to shed load or
damage equipment.284
116. Arguing that the Commission
should not extend the AAR
requirements beyond the operating day,
MISO Transmission Owners state that
using AARs any further forward than in
real time introduces uncertainty and
error. MISO Transmission Owners
Comments at 8–9; Duke Energy Comments at 8–9;
SDG&E Comments at 2–3; Southern Company
Comments at 5–6; MISO Transmission Owners
Comments at 15–16; EEI Comments at 10–11; APS
Comments at 8; NYTOs Comments at 5–6; AEP
Comments at 6–7; NRECA/LPPC Comments at 19–
20; SDG&E Comments at 2–3; LADWP Comments at
7; ITC Comments at 7–9.
277 BPA Comments at 7; Duke Energy Comments
at 8–9; Southern Company Comments at 5–6; MISO
Transmission Owners Comments at 15–16; EEI
Comments at 10–11; APS Comments at 8; NYTOs
Comments at 5–6.
278 AEP Comments at 6–7; NRECA/LPPC
Comments at 19–20; SDG&E Comments at 2–3;
LADWP Comments at 7.
279 Indicated PJM Transmission Owners
Comments at 2.
280 Dominion Comments at 9.
281 Entergy Comments at 11.
282 MISO Transmission Owners Comments at 15–
16; Duke Energy Comments at 8–9; Southern
Company Comments at 5–6; NYTOs Comments at
5.
283 BPA Comments at 7.
284 NYTOs Comments at 5–6.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
acknowledge that these risks exist
today, but argue that AARs introduce
further complexity and explain that
lowering transmission line ratings in
real time would compound the
problems.285 Similarly, Duke Energy
presents an example of transmission
sold based on a 60 degree Fahrenheit
temperature forecast four days forward
and, on the operating day having the
transmission system oversubscribed,
with greater pressure on operators to
curtail transmission schedules to avoid
safety and reliability risks, because the
actual temperature was 75 degrees
Fahrenheit.286 Southern Company states
that AARs have the potential to create
reliability concerns if transmission
service is oversold due to inaccurate
weather forecasts, especially for
transmission service that is scheduled
10 days ahead.287 Southern Company
also states that reliability issues may
arise because AARs may create
difficulties in identifying the most
limiting element, which may change as
the temperature changes, for the
purpose of complying with Reliability
Standard FAC–008–5, and similar
difficulties in complying with
Reliability Standard PRC–023 relay
loadability requirements that depend on
maximum published ratings.288
117. NRECA/LPPC contend that such
a requirement is unduly burdensome
because most of the benefits of using
AARs are for real-time and day-ahead
transactions. NRECA/LPPC add that
hourly weather forecasts and the
resulting hourly transmission line
ratings are unlikely to be accurate for
more than a very few days.289 IID
explains that the Commission should
provide flexibility in the forward AAR
application period, noting that weather
patterns may not be stable everywhere.
IID contends that the Commission
should consider implementation
challenges associated with looking 10
days ahead, calculating what could be
several hundred transmission line
ratings per year.290
118. EEI and APS contend that AARs
should only be implemented in realtime operations.291 EEI contends that
such AAR values should not extend to
the day-ahead or intra-day unit
commitment values and that hourly
ATC for up to 10 days would introduce
uncertainty and ATC fluctuations that
result in curtailment of sold service and
285 MISO
Transmission Owners Comments at 15–
16.
Energy Comments at 8–9.
Company Comments at 5–6.
288 Id. at 6.
289 NRECA/LPPC Comments at 19–20.
290 IID Comments at 4–6.
291 APS Comments at 8; EEI Comments at 10–12.
resale of previously curtailed service.
EEI further explains that the
Commission has previously recognized
the reliability harm associated with
overestimated ATC and explains that
the harm may result from using hourly
AARs for transmission service available
for up to 10 days. EEI also states that the
NOPR proposal for hourly ATC for
every hour in the next 10 days is
complex, with a burden that may
outweigh the benefits since the NOPR
proposal fundamentally requires a TTC
determination. However, EEI states that
TTC is path dependent and is based on
many transmission line ratings,
contingencies, and power flow
assumptions. Because of this
complexity, some transmission owners
only determine TTC annually or less
frequently and, for these transmission
owners, the NOPR proposal for
transmission providers to recalculate
TTC every hour, and perform 240
calculations every hour, is infeasible.292
NERC contends that the Commission
should consider how entities should
reconcile AARs used for planning and
operations functions. NERC also argues
that there is potential confusion
regarding transmission line ratings used
in transmission operator operations and
planning system operating limits and
interconnection reliability operating
limits, but believes the confusion can be
avoided through the timing of
Commission action to retire the NERC
Modeling, Data, and Analysis (MOD) A
Reliability Standards.293
119. NYTOs explain that requiring
AARs for up to 10 days forward, even
for a subset of the transmission system,
would be a significant change requiring
major software buildout and
corresponding market design changes,
which would create a significant burden
on NYISO and its associated utilities.
NYTOs assert that this burden would be
further complicated by the fact that
vendor availability for such a buildout
is unknown.294 NYTOs also explain that
implementing AARs 10 days forward
has the potential to create reliability
concerns through disconnects between
forecasted and real-time conditions 295
and that extending the AAR
requirements to the day-ahead market
would make security analysis more
difficult.296 LADWP contends that the
Commission should align any final rule
requirements with NERC Reliability
Standards and asserts that the proposed
10-day threshold would conflict with
286 Duke
287 Southern
PO 00000
Frm 00021
Fmt 4701
Sfmt 4700
2263
292 EEI
Comments at 10–12.
Comments at 7–8.
294 NYTOs Comments at 5–6.
295 Id.
296 Id. at 7.
293 NERC
E:\FR\FM\13JAR2.SGM
13JAR2
2264
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
the requirements specified in Reliability
Standard MOD–001–1a that ATC be
calculated hourly for the next 48
hours.297 Moreover, recognizing the
variability in weather, LADWP asks that
system operators be afforded the
flexibility to recall transfer capability
awarded during moderate conditions at
least 24 hours in advance.298
iii. Commission Determination
120. We adopt the NOPR proposal to
require transmission providers to use
AARs when evaluating the availability
of and requests for near-term
transmission service (under sections 15,
17, 18, and 29 of the pro forma
OATT) 299 as set forth under
‘‘Obligations of Transmission Provider’’
in the pro forma OATT Attachment M
adopted in this final rule. We further
adopt the Commission’s proposal in the
NOPR to require transmission providers
to use AARs as the relevant
transmission line rating when
determining whether to curtail or
interrupt point-to-point transmission
service (under sections 13.6 and/or 14.7
of the pro forma OATT) if such
curtailment or interruption is both
necessary because of issues related to
flow limits on transmission lines and
anticipated to occur (start and end)
within the next 10 days. Additionally,
we adopt the Commission’s proposal in
the NOPR to require transmission
providers to use AARs as the relevant
transmission line rating when
determining whether to curtail network
or secondary service (under section 33
of the pro forma OATT) or redispatch
network or secondary service (under
sections 30.5 and/or 33 of the pro forma
OATT), if such curtailment or
redispatch is both necessary because of
issues related to flow limits on
transmission lines and anticipated to
occur (start and end) within 10 days of
such determination (i.e., the 10-day
threshold). Finally, consistent with the
NOPR, we clarify that AARs must be
calculated using the temperature at
which there is sufficient confidence that
the actual temperature will not be
greater than that temperature (i.e.,
expected temperature plus an
appropriate forecast margin).300
121. We believe that the 10-day
threshold is justified by: (1) The
additional benefits gained by adopting a
threshold that permits weekly point-topoint transmission service requests to be
evaluated using AARs; (2) the additional
benefits gained by the use of daytime/
297 LADWP
Comments at 7.
at 6.
299 See supra P 85.
300 See NOPR, 173 FERC ¶ 61,165 at PP 97, 102.
298 Id.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
nighttime ratings (discussed below in
Section IV.B.2.c) within the 10-day
threshold; (3) the adequate accuracy of
ambient air temperature forecasts
combined with the ability to implement
appropriate forecast margins to alleviate
operational concerns associated with
persistently decreasing real-time
transmission line ratings; and (4) the
low relative cost difference between a
shorter forward threshold and the
proposed 10-day threshold. As the
Commission stated in the NOPR, AAR
requirements up to 10 days forward will
permit weekly point-to-point
transmission service to be evaluated
using AARs. Because weekly point-topoint transmission service is one of
several types of transmission products
provided under the Commission’s pro
forma OATT, by adopting the 10-day
threshold for AAR implementation
rather than a shorter forward duration,
weekly point-to-point transmission
customers will receive the benefits of
AAR implementation rather than only
transmission customers taking shorter
duration transmission service, thereby
not just increasing the expected benefits
from the implementation of AARs by
improving the accuracy of transmission
line ratings for a wider range of
transmission services but also for a
potentially wider range of transmission
customers.
122. We also require AARs to include
separate daytime and nighttime ratings.
This daytime/nighttime ratings
requirement, combined with the
addition of weekly point-to-point
transmission service, will produce
further benefits in forward nighttime
hours that would not see such benefits
if the AAR requirements were imposed
over a timeframe shorter than 10 days
forward. These benefits of increased
accuracy that result from applying
daytime/nighttime ratings to weekly
point-to-point transmission service and
to shorter duration transmission service
up to 10 days forward are significant on
their own, even in the unlikely event
that the use of ambient air temperature
forecasts 10 days forward results in no
hours where daytime AARs are greater
than seasonal line ratings. In other
words, if we were to adopt a shorter
threshold for the AAR requirements
than 10 days forward, the significant
benefits derived from the more accurate
transmission line ratings during the
additional nighttime hours included in
the 10-day threshold would be lost. We
further note that weather forecast
quality is not static, but rather is
steadily improving such that the
benefits of the 10-day threshold
PO 00000
Frm 00022
Fmt 4701
Sfmt 4700
requirement are likely to increase over
time.301
123. Although we acknowledge that
the accuracy of forecasts decreases the
further in advance the forecast is made,
we disagree that ambient air
temperature forecasts made 10 days in
advance are so inaccurate that they
cannot provide any benefits when used
as part of AARs, even when adjusted
with appropriate forecast margins, as
discussed herein. Neither commenters
supporting nor opposing the 10-day
threshold provide quantitative evidence
related to the accuracy of 10-day
forecasts; however, a published analysis
of the NOAA National Blend of Models
(NBM) forecast—one of the publicly
available NOAA forecasts that looks out
at least 10 days—indicates that the
mean absolute error for 240 hour (10
day) forward continental United States
surface temperature forecasts was
approximately four to six degrees
Fahrenheit in July to November 2016.302
We find that such levels of error would
likely allow for a meaningful number of
hours in any season where a 10-day
forward AAR would provide benefits
relative to the seasonal line rating. We
also note that this finding is consistent
with the support for the 10-day
threshold by various commenters.303
124. We do not find persuasive
arguments that the AAR requirements
adopted in this final rule will be unduly
burdensome. Contrary to such
assertions, because we expect the
increased costs of implementing AARs
under a 10-day threshold (as opposed to
a shorter threshold) to be primarily
related to increased forecasting and data
storage/hardware needs, we do not
expect such costs to be excessive.
Moreover, in certain situations,
especially outside the RTO/ISO context,
adopting the 10-day threshold will
301 See, e.g., NOAA, Annual WPC Mean Absolute
Errors, https://www.wpc.ncep.noaa.gov/images/
hpcvrf/maemaxyr.gif (last visited Oct. 28, 2021)
(showing NOAA data on the evolving accuracy of
their Weather Prediction Center forecasts of daily
high temperature).
302 Tabitha Huntemann, Daniel Plumb, and David
Ruth, Verification of the National Blend of Models
(2017), https://www.weather.gov/media/mdl/
AMS2017-NBMVerification.pdf. We note that this
analysis was applicable to the 2016 National Blend
of Models (NBM) Version 2.0 forecast, and that
several improved versions of the NBM forecast have
been implemented since that time. The current
NBM Version 4.0 was implemented in September
2020. See NBM: National Blend of Models, https://
vlab.noaa.gov/web/mdl/nbm. While we take notice
of this NBM forecast accuracy data as a point of
reference, we emphasize that the NBM forecasts are
just one example of the types of forecasts that
transmission providers might rely on in complying
with this final rule.
303 CEA Comments at 2; EDFR Comments at 7;
Ohio FEA Comments at 5; New England State
Agencies Comments at 9–10; ACPA/SEIA
Comments at 13.
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
allow more transfer capability to be
made available to customers than
simply adopting seasonal worst-case
assumptions. In addition, as CEA states,
using AARs to calculate transmission
line ratings for service requests up to 10
days has proven to be reliable and to
provide benefits to effective and reliable
transmission operations.304 In that
context, commenters have not provided
evidence that the cost to procure or
develop 10-day forward forecasts is
materially different from the cost to
procure or develop two- or three-day
forward forecasts and, in any case, that
such cost outweighs the added benefits
of extending the forward period from
two or three days to 10 days. For these
reasons, we expect the material benefits
resulting from adopting the 10-day
threshold to, on balance, outweigh the
costs.
125. We emphasize that any benefit
from the AAR requirements, and the 10day threshold in particular, should be
compared to the relative costs of
alternatives. And we find that the cost
associated with requiring AARs for
additional days forward is essentially
the cost of accessing, storing, and
processing the additional forecast data,
and the cost of calculating, storing, and
incorporating into transmission service
the additional hours of AARs. As we
expect this process will be largely
automated, we do not anticipate that the
cost of the 10-day threshold, as opposed
to a shorter threshold, will be
significantly higher. Although the
question of where to draw the line in
terms of the time threshold for AAR
implementation is not clear cut, we find
that 10 days strikes an appropriate
balance between the benefits of more
accurate transmission line ratings that
result from the AAR requirements
adopted in this final rule, and the likely
costs of implementing those
requirements.
126. We note that some commenters
may have misunderstood the
Commission’s proposal in the NOPR as
requiring the use of expected ambient
air temperatures in forecasts of AARs for
future periods. That is, they may have
read the Commission’s NOPR proposal
as requiring that if the forecasted
ambient air temperature at a given
transmission line 10 days in advance
(without any forecast margin applied,
i.e., the expected temperature) was X
degrees, that the transmission provider
was required to use an AAR for that
hour 10 days forward that assumed an
air temperature of X degrees. This is not
the case. Rather, AARs must be
calculated using the temperature at
304 CEA
Comments at 2.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
which there is sufficient confidence that
the actual temperature will not be
greater than that temperature (i.e.,
expected temperature plus an
appropriate forecast margin).305 This
approach to calculations is consistent
with EPRI’s recommendation and also
comments from Entergy and the CAISO
DMM, which suggest margins to account
for forecast error.306
127. In response to requests for
clarification from BPA, LADWP, and
EEI that transmission providers can
curtail transmission sold at least 24
hours in advance, consistent with
existing curtailment prioritization,
should temperature forecasts dictate
such curtailment, we confirm that we
are not changing the existing
curtailment prioritization. In
implementing the 10-day threshold, it
may be necessary in some instances for
transmission providers to curtail
transmission sold based on ambient air
temperature forecasts (including
forecast margins) that end up being
lower than real-time temperatures.
Although transmission providers will
continue to curtail transmission at times
due to unrealized ambient air
temperature assumptions, the need for
such curtailments should be decreased
as a result of the AAR requirements
adopted herein.307 We reiterate that
under the AAR requirements that we
adopt in this final rule, transmission
providers have the latitude (and
obligation) to develop accurate, safe,
and reliable transmission line ratings,308
and we do not expect that such
transmission line ratings will
necessitate an increase in the need for
curtailments due to inaccurate AARs. If
a transmission provider determines
(whether during pre-testing of its AAR
methodologies or during actual
operations) that a given level of forecast
margins yields an unreasonable
frequency of such curtailment, it should
305 See
NOPR, 173 FERC ¶ 61,165 at PP 97, 102.
Comments at 10–12; Entergy Comments
at 11; CAISO DMM Comments at 3.
307 We note, for example, that a typical winter
seasonal line rating temperature assumption today
is 32 degrees Fahrenheit—a temperature
assumption which in many parts of the United
States is violated frequently over the current typical
six-month ‘‘winter season’’ used in seasonal line
ratings. Commission Staff Paper at 7; see also
Midwest Reliability Organization Standards
Committee, Standard Application Guide: FAC–008,
Version 1.1, p. 14 (March 21, 2017), https://
www.nerc.com/pa/comp/guidance/EROEndorsed
ImplementationGuidance/FAC-008-3%20
Standard%20Application%20Guide.pdf. We expect
such assumption violations to be less frequent
under our required approach, where transmission
providers will apply reasonable forecast margins
when developing their AARs
308 NOPR, 173 FERC ¶ 61,165 at P 97.
306 EPRI
PO 00000
Frm 00023
Fmt 4701
Sfmt 4700
2265
re-evaluate and adjust its forecast
margins.
128. We further acknowledge that, in
addition to the concerns of some
commenters related to forecast margins
being too low, certain forecast margins
could also prove to be too high. In those
instances, as with the implementation of
static transmission line ratings,
transmission line ratings using
unreasonably high forecast margins
would also yield inaccurate
transmission line ratings and, in turn,
would result in an underutilization of
existing transmission facilities, price
signals based on less transfer capability
than is truly available, and wholesale
rates that are unjust and unreasonable.
Similar to unreasonably low forecast
margins, if a transmission provider
determines (whether during pre-testing
of its AAR methodologies or during
actual operations) that a given forecast
margin is unreasonably high, it should
re-evaluate and adjust its forecast
margins.
129. Similarly, contrary to comments
from CAISO, NYISO, NYTOs, and EEI
that describe the operational risks
associated with overestimating ATC,309
we do not expect that the AAR
requirements adopted herein will result
in a frequent number of instances when
transmission line ratings used in the
real-time market are lower than
transmission line ratings used in the
day-ahead market. Some such instances
will occur, but we believe that there is
sufficient latitude within our
requirements, as discussed above, for
day-ahead transmission line ratings to
be determined with sufficient forecast
margins to avoid this concern.
Furthermore, as the Commission stated
in the NOPR, day-ahead markets already
rely heavily upon weather forecasts to
inform next-day load and intermittent
generation availability. This final rule
does not change reliance upon weather
forecasting; instead, the AAR
requirements we adopt herein will
improve the accuracy of transmission
line ratings and, if anything, lead to cost
savings to consumers and reliability
benefits. Additionally, as PJM’s AAR
implementation experience
demonstrates, temperatures can be
forecast day ahead with a reasonable
degree of certainty.310 We also find that
operational risks that might result from
the use of transmission line ratings in
the real-time market that are lower than
the transmission line ratings used in the
day-ahead market can further be
309 NYTOs Comments at 5–6; EEI Comments at
10–12; NYISO Comments at 13–14; CAISO
Comments at 9–11.
310 PJM Comments at 3.
E:\FR\FM\13JAR2.SGM
13JAR2
2266
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
managed and mitigated through the use
of AARs in the RUC processes, which
will have the benefit of updated
temperature forecasts. Finally, we
reiterate that PJM and AEP report
reliability benefits from AAR
implementation.
130. In response to comments from
EEI and other transmission owners
about the complexities of calculating
AARs up to the 10-day threshold, we
find that such complexities are
predominately reflected in the upfront
set-up and investment costs 311 and that
these costs will be primarily related to
increased forecasting and data storage/
hardware needs.
131. In response to NERC’s request
that the Commission consider how
entities should reconcile AARs used for
planning and operations functions,312
we find that AARs used in near-term
operations will deviate from those
transmission line ratings used in various
planning functions. As transmission
providers progress closer in time to a
given interval, near-term ambient air
temperature forecasts will necessarily be
updated. These updates will impact
TTC, and, as a result, ATC and system
operating limits. In addition, regarding
implementation of this final rule and
currently effective MOD A Reliability
Standards,313 this final rule does not
advocate for operating the transmission
system beyond the system operating
limits and established facility ratings.
132. In response to requests for
clarification of the NOPR proposal from
NERC and BPA with respect to
temperature variations,314 transmission
providers must consider the relevant
ambient air temperature forecasts along
the transmission line, and determine the
transmission line rating based on the
most limiting combination of equipment
limitations and forecasted local ambient
air temperature along the transmission
line. We note that NERC additionally
requested that the Commission consider
how variations in load forecasts would
be addressed when using values for
each of the 240 hours in the next 10
days for each transmission line in
granting firm point-to-point
transmission service.315 In response, we
reiterate that the requirements adopted
herein are designed to ensure accurate
transmission line ratings. We also
reiterate that AARs must be calculated
using the temperature at which there is
311 Exelon Comments at 8; AEP Post-Technical
Conference Comments at 2–3; see also supra
Section IV.B.1.c.
312 NERC Comments at 6–7.
313 Id. at 7.
314 NERC Comments at 6–7; BPA Comments at 2–
4.
315 NERC Comments at 6–7.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
sufficient confidence that the actual
temperature will not be greater than that
temperature (i.e., expected temperature
plus an appropriate forecast margin).
We further clarify, in response to NERC,
that transmission line rating
methodologies must be updated. In
particular, pro forma OATT Attachment
M, as adopted by this final rule, requires
transmission line ratings to be
computed in accordance with a written
transmission line rating methodology
and consistent with good utility
practice. Moreover, we note that
Reliability Standard FAC–008–5
Requirement 3.2 requires transmission
line rating methodologies to identify
how ambient conditions are
considered.316 Thus, transmission line
rating methodologies need to document
methods used to calculate AARs.
133. In response to LADWP’s
argument that the Commission should
align AAR requirements with the NERC
Reliability Standards—and that the
proposed 10-day threshold would
conflict with the requirement specified
in Reliability Standard MOD–001–1a
that ATC be calculated hourly for the
next 48 hours—we note that Reliability
Standard MOD–001–1a requires that
ATC be calculated for at least the next
48 hours, not for only the next 48 hours.
Furthermore, the Commission’s
regulations require ATC to be calculated
and/or posted for periods more than 48
hours in the future (e.g., when
transmission service is requested or
inquired about).
134. Finally, in response to RTO/ISO
requests for flexibility, we clarify the
applicability of the 10-day threshold to
RTOs/ISOs. The vast majority of energy
transactions in RTOs/ISOs are executed
and financially settled in the day-ahead
and real-time energy markets; thus, we
find that requiring AARs for the realtime and day-ahead energy markets in
RTOs/ISOs is necessary to ensure the
accuracy of transmission line ratings
and just and reasonable wholesale rates.
Because these transactions take place
within a one-day forward timeframe, the
10-day threshold will provide very little
additional benefits in existing RTO/ISO
markets. Accordingly, the 10-day
threshold will not apply to internal
transactions or internal flows associated
with through-and-out transactions in
RTOs/ISOs. However, given that RTOs/
ISOs generally use the pro forma OATT
transmission service model for
movement of electricity into/out of their
service territories, the 10-day threshold
316 Reliability Standard FAC–008–5, Requirement
R3.2, p.4, https://www.nerc.com/pa/Stand/
Project%20201803%20Standards%20Efficiency
%20Review%20Require/2018-03lFAC-0085lcleanl01192021.pdf.
PO 00000
Frm 00024
Fmt 4701
Sfmt 4700
requirement will apply to RTOs/ISOs’
evaluation or determination of
availability of transmission service at
the seams of RTO/ISO service
territories, in order to improve the
accuracy of transmission line ratings
and ensure just and reasonable
wholesale rates.
b. Role of the Transmission Owner and
Transmission Provider in AAR
Implementation
i. NOPR Proposal
135. In proposing AAR
implementation in the pro forma OATT,
the Commission proposed for
transmission providers—not
transmission owners—to implement
AARs because transmission providers—
not transmission owners—must have an
OATT.317
ii. Comments
136. Several commenters clarify that
transmission owners, not transmission
providers, calculate transmission line
ratings.318 For example, MISO states
that its formational documents reflect,
and have codified, the responsibility of
transmission owners to calculate facility
ratings, not MISO.319 MISO
Transmission Owners explain that
Reliability Standard FAC–008–5
requires transmission owners to have ‘‘a
documented methodology for
determining facility ratings of its solely
and jointly owned Facilities’’ based on
the electrical characteristics of the
transmission equipment or other
industry standard.320 Southern
Company states that the MOD suite of
NERC Reliability Standards governing
TTC/ATC calculations requires
transmission line ratings as provided by
transmission owners.321 Similarly, ISO–
NE explains that its Transmission
Operating Agreement requires its
participating transmission owners to
establish transmission line ratings for
each transmission facility.322
Additionally, NYISO states that in the
New York Control Area, the
transmission owners are responsible for
developing transmission line ratings
and providing the element ratings
directly to NYISO. In turn, according to
NYISO, NYISO determines the most
limiting element, which sets the
applicable facility rating.323
317 NOPR,
173 FERC ¶ 61,165 at P 84.
Comments at 27; Vistra Comments at 3–
4; TAPS Comments at 13–14; Southern Company
Comments at 6; EEI Comments at 2–4; MISO
Transmission Owners at 29; EEI Comments at 2–4.
319 MISO Comments at 27.
320 MISO Transmission Owners at 29.
321 Southern Company Comments at 3, 6.
322 ISO–NE Comments at 6.
323 NYISO Comments at 3.
318 MISO
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
137. Because of these differing
transmission owner and transmission
provider roles and responsibilities,
these commenters request that the
Commission recognize and make these
differing roles explicit in any final
rule.324 Some recommend further
Commission action to ensure
transmission owners have an obligation
to implement the AAR requirements in
proposed pro forma OATT Attachment
M. For example, Vistra encourages the
Commission to modify its regulations to
create a compliance obligation for each
transmission owner to provide RTOs/
ISOs all information necessary to
implement proposed pro forma OATT
Attachment M.325 Similarly, TAPS
requests that the Commission clarify
that: (1) RTOs/ISOs have the authority
to require transmission owners to
provide the information they will need
to implement AARs; or (2) transmission
owners within RTOs/ISOs must provide
the information RTOs/ISOs will need to
implement AARs to the relevant RTO/
ISO.326 Additionally, TAPS argues that
in order to achieve efficient and
consistent application of AARs, the
Commission should direct RTOs/ISOs to
use, or at minimum accommodate the
use of, ‘‘look-up tables.’’ 327 TAPS
explains that, using the ‘‘look-up table’’
approach will limit the obligation to
continuously monitor weather reports to
recalculate AARs and communicate
those transmission line ratings to the
RTO/ISO on an hourly basis.328
138. Noting the applicability of the
pro forma OATT to transmission
providers and that transmission owners
and transmission providers are different
in RTO/ISOs, Exelon comments on the
phrasing ‘‘is calculated’’ in the AAR
definition, explaining that, while it
largely supports the proposed AAR
definition, it does not ‘‘calculate’’
transmission line ratings hourly. Exelon
states that it calculates 64 different
transmission line rating cases (for nine
temperatures sets, across normal, longterm emergency, short-term emergency,
emergency load dump, and for both day
and night), and then references the
relevant existing calculations in a ‘‘lookup table’’ through its Inter-Control
Center Communications Protocol signal.
Exelon proposes to refine the AAR term
324 MISO Comments at 27; Vistra Comments at 3–
4; TAPS Comments at 13–14; Southern Company
Comments at 6; EEI Comments at 2–4.
325 Vistra Comments at 3–4.
326 TAPS Comments at 14.
327 Id. at 8. TAPS states that, for each of their
transmission facilities, transmission owners should
be required to provide RTOs/ISOs with a table
showing their temperature-adjusted rating for a preestablished set of ambient air temperatures.
328 Id. at 8–10.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
to: ‘‘a transmission line rating that
reflects the appropriate temperatureadjusted rating for a facility based on an
up-to-date forecast of ambient air
temperatures across the time period to
which the rating applies.’’ 329
139. Finally, CAISO argues that
RTOs/ISOs and their stakeholders will
have to answer many questions in
developing tariff provisions for using
hourly transmission line ratings. Several
of these questions relate to AAR
implementation timelines, including the
time hourly transmission line ratings
must be submitted by the transmission
owners to RTOs/ISOs and the time
period that transmission owners will
have to update hourly transmission line
ratings for use in real-time markets after
day-ahead results are published.330 As
an example, BPA explains that its
dynamically established TTC
calculations are based on schedules
submitted 20 minutes before the
operating hour.331
iii. Commission Determination
140. We clarify that transmission
owners, not transmission providers, are
responsible for calculating transmission
line ratings. This responsibility is
codified in the NERC Reliability
Standards, as well as in RTO/ISO
foundational documents.332 Nothing in
this final rule changes that
responsibility. In the non-RTO/ISO
regions, this detail is generally not a
concern because the transmission
provider is usually the transmission
owner. However, in the RTO/ISO
regions, there is a distinction between
transmission owners and transmission
providers. Thus, in order to comply
with this final rule, RTOs/ISOs—the
transmission provider with the OATT
on file—will need to rely on their
member transmission owners to
calculate transmission line ratings and
provide them to the RTO/ISO.333
141. In response to concerns about the
responsibility for calculating
transmission line ratings in RTOs/ISOs,
we clarify that we expect RTOs/ISOs to
329 Exelon
Comments at 11–12.
Comments at 12–13.
331 BPA Comments at 5.
332 See, e.g., Reliability Standards FAC–008–5,
Requirement R3 and FAC–008–5, Requirement R6.
333 We note that, as discussed below, in RTO/ISO
regions, in addition to AARs, transmission owners
will be required to calculate and provide other
transmission line ratings to the RTO/ISO, including
seasonal line ratings and emergency ratings.
Moreover, in RTO/ISO regions, transmission
owners will be required to provide to the RTO/ISO
the list of transmission lines which have been
exempted from the AAR requirement (under the
‘‘Exceptions’’ paragraph of pro forma OATT
Attachment M) or temporary alternate ratings
(under the ‘‘System Reliability’’ section of pro
forma OATT Attachment M).
330 CAISO
PO 00000
Frm 00025
Fmt 4701
Sfmt 4700
2267
require their member transmission
owners to make timely calculations and
determinations as required for
transmission line ratings, and to provide
them to the RTO/ISO.334 Where the
transmission provider is not the
transmission owner (e.g., RTOs/ISOs),
we require the transmission provider to
explain in its compliance filing, as part
of its implementation of the new pro
forma OATT Attachment M, through
what mechanism (tariff, membership
agreement, etc.) the transmission
owner(s) will have the obligation for
making and communicating to the
transmission provider the timely
calculations and determinations related
to transmission line ratings (including
the exercise of any discretion in
calculations or application of
exceptions).
142. In response to Exelon’s concerns
about the proposed AAR definition,335
we clarify that hourly (or more frequent)
querying of ‘‘look-up tables’’ or similar
pre-calculated AAR databases will
satisfy the requirement that AARs be
calculated at least each hour. While we
expect transmission owners to calculate
transmission line ratings, given the
difference between transmission owners
and transmission providers in RTOs/
ISOs, we require RTOs/ISOs on
compliance to propose and justify a
334 See, e.g., MISO, MISO Rate Schedules, MISO
Transmission Owner Agreement, art. 4, § II.A
Providing Information (30.0.0) (‘‘Each Owner and
User shall provide such information to [MISO] as
is necessary for [MISO] to perform its obligations
under this Agreement and the Tariff.’’); SPP,
Governing Documents Tariff, Membership
Agreement, § 3.5 Providing Information (0.0.0)
(‘‘Member shall provide such information to SPP as
is necessary for SPP to perform its obligations under
this Agreement and the OATT, and for planning
and operational purposes.’’); PJM, Rate Schedules,
§ 4.11 Transmission Facility Ratings (0.0.0) (‘‘All
Parties shall regularly update and verify
Transmission Facility ratings, subject to review and
approval by PJM, in accordance with the following
procedures and the procedures in the PJM Manuals
. . . .’’); ISO–NE, ISO New England Inc.
Agreements and Contracts, Transmission Operating
Agreement, §§ 3.02(a)(ii) (5.0.0) (stating that ISO–
NE shall ‘‘determine Operating Limits based on
forecasted or real-time system conditions and in
accordance with the facility ratings established by
the PTOs in collaboration with the ISO pursuant to
Section 3.06’’), 3.06(a)(v) (5.0.0) (stating that the
transmission owner shall: ‘‘(v) Collaborate with the
ISO with respect to: (A) The development of Rating
Procedures, (B) the establishment of ratings for each
PTO’s New Transmission Facilities; (C) the
establishment of ratings for each PTO’s Acquired
Transmission Facilities that do not have an existing
rating as of the Operations Date, and (D) the
establishment of any changes to existing ratings for
Transmission Facilities in effect as of the
Operations Date’’); CAISO, CAISO eTariff,
Transmission Control Agreement, § 4.2 (0.0.0)
(stating that facility ratings are required CAISO’s
database of all facilities under the CAISO’s control
and that transmission owners are responsible for
providing updates to that database when there is a
change in ratings, which CAISO reviews).
335 Exelon Comments at 11–12.
E:\FR\FM\13JAR2.SGM
13JAR2
2268
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
methodology for AAR implementation,
delineating the expected roles between
transmission owners and transmission
provider. In doing so, we encourage
RTO/ISO transmission owners to
coordinate implementation
methodologies and promote
implementation consistency to the
greatest extent possible within an RTO/
ISO service territory. However, in
response to comments from TAPS that
the Commission should require use of a
‘‘look-up table’’ approach, or at least
require that approach be an option,336
we decline to require a specific AAR
implementation methodology, noting
regional software and procedural
differences.
143. In response to requests for
clarification from CAISO, we decline to
require in this final rule a specific
timeline by which AARs will need to be
calculated or submitted to the
transmission provider (either in the
context of the day-ahead and real-time
markets in RTOs/ISOs, or in terms of
how far in advance of an operating hour
an AAR should be calculated in a
bilateral market).337 However, we note
that the AAR definition we adopt in this
final rule requires that AARs ‘‘[r]eflect[]
an up-to-date [emphasis added] forecast
of ambient air temperature across the
time period to which the rating
applies,’’ by which we mean that new
forecast data should be incorporated
into AAR calculations as close to real
time as reasonably possible given the
timelines needed to obtain forecast data
and perform the AAR calculation, as
well as any other steps needed for
validation, communication, or
implementation of AARs.338
Furthermore, transmission providers
must explain their timelines as part of
their compliance filings. We recognize
that transmission providers already
manage similar timing issues with
respect to load forecasts, forecasts for
renewable energy production, and
generation bid deadlines, and it may be
that deadlines for AAR calculation/
submission are not significantly
different from existing deadlines for
submission of updates to generation
supply offers and load.
jspears on DSK121TN23PROD with RULES2
336 TAPS
Comments at 7–10.
note that in some instances RTOs/ISOs
may propose (as we understand PJM does now for
its AARs) to have the RTO/ISO select AARs based
on temperature forecasts and pre-calculated AAR
tables/databases. In such cases, it may not be (as
CAISO’s comments suggest) that transmission
owners will be sending entire sets of AARs to
RTOs/ISOs every time they are calculated.
338 Pro Forma OATT attach. M, AAR Definition.
337 We
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
c. Solar Heating in AAR Calculations
i. NOPR Proposal
144. In the NOPR, the Commission
proposed to require AARs that reflect
up-to-date forecasts of ambient air
temperature, but noted that AARs could
possibly incorporate other forecasted
inputs.339 As an example of other
inputs, the Commission pointed to
PJM’s implementation of ‘‘day and night
ambient air temperature tables, where
the night ambient air temperature table
assumes zero solar irradiance.’’ 340 The
Commission also sought comment on
whether to require transmission
providers to implement DLRs, rather
than only AARs, noting that DLRs can
incorporate solar heating intensity,
among other ambient conditions, to
calculate the amount of transfer
capability of a given transmission line
in near real time.341
ii. Comments
145. Several commenters discuss the
incorporation of solar heating into
transmission line ratings. For example,
Vistra suggests that, instead of requiring
full DLRs, the Commission instead
adopt a ‘‘middle ground’’ of requiring
AARs that incorporate consideration of
predictable solar heating (at least
considering daytime/nighttime hours,
similar to PJM’s existing
implementation of AARs).342 Potomac
Economics and Vistra contend that such
a requirement would not necessitate
sophisticated monitoring or forecasting,
and instead would produce significant
benefits with minimal cost.343 R Street
Institute, PG&E, Indicated PJM
Transmission Owners, Dominion, and
Potomac Economics also support
incorporating predictable daytime/
nighttime solar heating into AARs, with
Dominion and Indicated PJM
Transmission Owners noting that this is
already the practice in PJM.344 Entergy,
without taking a position on whether it
would be appropriate for the
Commission to require separately
calculated daytime and nighttime
ratings, states that the shade of night
provides an additional 5% to the
transmission line’s transmission line
339 NOPR,
173 FERC ¶ 61,165 at P 23.
P 23 n.40; see also id. P 21 (explaining that
different types of ambient weather assumptions can
be incorporated into transmission line ratings,
including updated air temperature, solar irradiance,
and wind speed, among others).
341 Id. PP 25–26, 43.
342 Vistra Comments at 4–5.
343 Id. at 4–5; Potomac Economics Comments at
14–15.
344 R Street Institute Comments at 3; PG&E
Comments at 11–12; Indicated PJM Transmission
Owner Comments at 8–9; Dominion Comments at
8; Potomac Economics Comments at 14–15.
340 Id.
PO 00000
Frm 00026
Fmt 4701
Sfmt 4700
ratings.345 PG&E states that it supports
separately calculated daytime and
nighttime ratings and indicates that its
research from PJM’s posted transmission
line ratings shows that at least 14% of
PJM’s transmission line ratings would
increase by 10% by considering solar
heating.346 Potomac Economics
estimates that considering daytime/
nighttime could increase thermal
transmission line ratings on average by
11% during nighttime hours and the
potential benefits would be
approximately $30 million per year in
MISO alone.347
146. Vistra points out that solar
heating varies in several ways: Between
daytime and nighttime (with sunrise/
sunset times and day length varying
significantly across the year), across the
hours during the day (varying—under
worst-case, clear-sky assumptions—
from close to zero just after and before
sunrise and sunset, respectively, to a
daily mid-day peak), and across the
days of the year (with higher mid-day
peaks in the summer and lower peaks in
the winter).348 Vistra and PG&E both
suggest that the Commission consider
requiring regular updates to sunrise/
sunset times, with Vistra discussing
possible daily or seasonal updates, and
PG&E discussing possible monthly
updates.349 Furthermore, while Vistra
recommends that the Commission at the
very least require separate daytime and
nighttime AARs, Vistra also provides
data for how solar heating varies
significantly across the day, and
discusses how more granular solar
forecasting might reflect these solar
variations.350
iii. Commission Determination
147. Upon consideration of the
comments received in response to the
NOPR, we require transmission
providers to incorporate solar heating
into AARs by implementing separate
AARs for daytime and nighttime
periods. Specifically, we require
transmission providers to reflect the
lack of solar heating in the technical
assumptions for nighttime AARs. As
noted by Dominion and Indicated PJM
Transmission Owners, incorporating
solar heating into AARs is consistent
with PJM’s existing AAR
implementation.351 Absent this
requirement for daytime/nighttime
345 Entergy
Comments at 8.
Comments at 11.
347 Potomac Economics Comments at 14–15.
348 Vistra Comments at 4–6; see also PG&E
Comments at 11–12.
349 Vistra Comments at 5; PG&E Comments at 12.
350 Vistra Comments at 4–5.
351 Dominion Comments at 7–8; Indicated PJM
Transmission Owners Comments at 7.
346 PG&E
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
AARs, AARs would assume the worstcase solar heating assumptions in every
hour, even at night when there is no
solar heating of transmission lines at all.
148. The consideration of daytime/
nighttime solar heating in the AARs
used by transmission providers will
further the Commission’s goal of
ensuring more accurate transmission
line ratings, which result in just and
reasonable wholesale rates.
Furthermore, as commenters note, the
improvements to the accuracy of
transmission line ratings that will result
from adopting a daytime/nighttime AAR
requirement can yield significant
economic benefits at minimal cost.352
149. We agree with commenters that
sunrise/sunset times should be updated
periodically to ensure the accuracy of
both daytime and nighttime ratings.
Specifically, we clarify that in order to
comply with the requirement in pro
forma OATT Attachment M for AARs to
reflect the absence of solar heating
during nighttime periods, transmission
providers must update the sunrise and
sunset times used to calculate their
AARs at least monthly, if not more
frequently. We find that among the
daily, monthly, and seasonal timeframes
suggested by commenters, the
requirement to update sunrise/sunset
times on a monthly basis strikes an
appropriate balance between achieving
the greatest benefits of AAR
implementation and not imposing an
unreasonable burden on transmission
providers. Given the speed at which
sunrise and sunset times change in
many areas of the country during certain
times of the year, monthly updates will
result in significantly more accuracy in
transmission line ratings and capture
significantly greater value than seasonal
updates. Because sunrise/sunset times
can be easily calculated with precision
based on location and day of the year,353
and because we expect AAR
implementation to be largely automated,
we do not expect monthly updates to
sunrise/sunset times to impose a
significant additional implementation
burden relative to seasonal updates.
Nothing in this final rule would prevent
a transmission provider from updating
its sunrise/sunset times more frequently
352 Vistra
Comments at 4–5; Potomac Economics
Comments at 14–15.
353 See, e.g., National Oceanic and Atmospheric
Administration, Global Monitoring Division,
General Solar Position Calculations, https://
gml.noaa.gov/grad/solcalc/solareqns.PDF
(providing formulas for calculating sunrise/sunset
times based on latitude, longitude, and day of the
year).
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
than monthly and we encourage
transmission providers to do so.354
150. Vistra correctly points out that,
in addition to sunrise/sunset times,
solar heating also varies across the days
of the year and the hours of the day.
However, again, to maintain a balance of
benefits and burdens, we decline to
require regular updates to mid-day peak
solar heating to account for differences
across days of the year. As such,
transmission providers may use
maximum annual assumptions for solar
heating when determining daytime
AARs. Furthermore, to balance benefits
and burdens, we decline to require more
granularity (e.g., hourly forecasts) in
solar heating assumptions and only
require daytime/nighttime
consideration. We note, however, that
nothing in this final rule would prohibit
a transmission provider that wants to
voluntarily implement regular updates
to peak mid-day solar heating, or to
voluntarily implement hourly forecasts
for solar heating, from doing so. We
further note that peak or hourly daytime
solar heating (under worst-case clearsky assumptions) can be accurately
computed based on location using
equations such as those presented in
IEEE (Institute of Electrical and
Electronics Engineers) Standard 738.355
3. Other AAR Implementation Issues
a. Reliability Unit Commitment
Processes
i. NOPR Proposal
151. In the NOPR, the Commission
proposed that RTOs/ISOs comply with
the AAR requirements by revising their
OATTs to implement AARs within their
SCED and SCUC models (and in any
relevant related models) in both the dayahead and real-time markets and in any
intra-day RUC processes.356
ii. Comments
152. CAISO requests clarification on
whether hourly transmission line
ratings should be constant in RUC
processes.357
iii. Commission Determination
153. In response to CAISO, we clarify
that transmission providers should
propose on compliance to use updated
AARs as part of any market process
associated with the day-ahead and real354 We note that PJM currently updates its
sunrise/sunset times more frequently than monthly
in its day/night AAR implementation.
355 Institute of Electrical and Electronics
Engineers, IEEE Standard for Calculating the
Current-Temperature Relationship of Bare
Overhead Conductors 18–20, IEEE Std 738–2012
Cor 1–2013 (2013) (IEEE 738).
356 NOPR, 173 FERC ¶ 61,165 at P 91.
357 CAISO Comments at 12–13.
PO 00000
Frm 00027
Fmt 4701
Sfmt 4700
2269
time markets (including RUC, as well as
any look-ahead commitment processes
or other such processes). In the event an
RTO/ISO believes that AARs should not
be used as part of any market process
associated with the day-ahead and realtime markets (or that updated AARs
should not be required for any market
process), it should propose and justify
such deviations on compliance.
b. Time Resolution and Calculation
Frequency of AAR Requirements
i. NOPR Proposal
154. In defining AARs, the
Commission proposed to require that
AARs be calculated at least each hour,
if not more frequently, and for AARs to
apply to a time period of not greater
than one hour.358
ii. Comments
155. Many state agencies, supply and
load representatives, renewable energy
advocates, and independent experts
support the proposed AAR requirements
overall, which includes the proposed
time resolution or calculation
frequency.359 RTOs/ISOs are mixed in
whether they take a position and
generally discuss their ability to accept
AARs calculated hourly. For example,
while not taking a position on the
appropriateness of this part of the NOPR
proposal, MISO explains that its EMS
and SCED are capable of receiving and
leveraging AARs provided by their
transmission owners at least hourly.360
156. CAISO explains that its
transmission owners can submit AARs,
but that the fundamental challenge with
using AARs is timely communication of
forecasted transmission line ratings.
According to CAISO, participating
transmission owners currently submit
AARs as an equipment rating change
through CAISO’s outage management
system (webOMS).361 CAISO further
states that using hourly adjusted
transmission line ratings for
transmission lines across the 24-hour
horizon of a trading day will necessarily
and significantly increase the
complexity of CAISO’s day-ahead
optimization processes.362 In addition,
CAISO contends that hourly
transmission line ratings in real-time
markets may drive uplift costs by
causing variances between total transfer
358 NOPR,
173 FERC ¶ 61,165 at P 95.
Comments at 2; Clean Energy Parties
Comments at 2–3; R Street Institute Comments at
2–3; TAPS Comments at 1–3; ACORE Comments at
3; ACPA/SEIA Comments at 7; OMS Comments at
2; New England State Agencies Comments at 10;
Vistra Comments at 2–3.
360 MISO Comments at 12.
361 CAISO Comments at 4.
362 Id. at 9–10.
359 EPSA
E:\FR\FM\13JAR2.SGM
13JAR2
2270
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
capability used in each of CAISO’s
commitment and dispatch processes. In
addition, CAISO asserts that
transmission line rating changes over
the market run’s look-ahead period can
generate inefficient outcomes through
deviations from day-ahead schedules.363
157. Similarly, NYISO cautions
against requiring hourly updates to
transmission line ratings if they are not
already used by RTOs/ISOs.364 NYISO
explains that introducing hourly
transmission line ratings could result in
divergences from the day-ahead
schedule, creating uplift or potential
reliability risks, if hourly transmission
line ratings cause a transmission line
rating to decline.365 On hourly updates
to AARs, NYISO notes that its market
software looks ahead, including a 24hour day-ahead optimization and multiperiod commitment for the real-time
market.366 NYTOs note that NYISO and
NYTOs can apply AARs and DLRs to
congested transmission lines currently
in real time to increase transmission
line ratings.367
158. ISO–NE states that it allows for
short-term changes to transmission line
ratings, though not at an hourly level.368
ISO–NE further states that its
coordinated transaction scheduling with
NYISO runs every 15 minutes and
therefore a shorter interval would have
to be considered.369
159. While PJM supports the adoption
of AARs, it opposes the requirements
that a transmission line rating apply to
a period not greater than one hour and
that transmission line ratings be
updated hourly. PJM states that the key
factor for determining the transmission
line rating is the temperature and, as a
result, the primary event that triggers a
change in AARs is the ambient air
temperature. PJM states that, in
implementing AARs, it continuously
monitors temperatures and updates
transmission line ratings for
temperature fluctuations in accordance
with the transmission owners’ look-up
table, so there is no benefit to updating
the AARs hourly if no temperature
change has occurred.370 Relatedly, PJM
and Duke Energy state that the proposed
requirements in the NOPR that
transmission line ratings be updated
hourly could harm operations.371 This is
because, according to PJM, a significant
temperature change could occur
jspears on DSK121TN23PROD with RULES2
363 Id.
at 10–11.
364 NYISO Comments at 4.
365 Id. at 4–5.
366 Id. at 13.
367 NYTOs Comments at 4.
368 ISO–NE Comments at 6–7.
369 Id. at 9.
370 PJM Comments at 4–5.
371 Id. at 5; Duke Energy Comments at 8.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
between required hourly updates and, if
a transmission operator is not
continuously monitoring ambient air
temperature, an incorrect transmission
line rating would be effective from the
time of the temperature change until the
next mandated hourly update.372 PJM
states that these temporal requirements
simply add an administrative burden
without providing additional
benefits.373 PJM requests that the
Commission refrain from requiring
transmission providers to apply AARs
in hourly intervals but rather require
them to be continuously monitored with
changes triggered by temperature
changes and the other relevant factors in
the look-up tables.374
160. Many transmission owners also
request flexibility on the proposed
requirement for AARs to be calculated
‘‘at least each hour.’’ 375 ITC asks that
the Commission instead only require
daily AAR updates and notes that this
is the prevailing practice for
transmission owners using AARs in
MISO.376 MISO Transmission Owners
also request flexibility to implement
daily rather than hourly AARs.377
Indicated PJM Transmission Owners
argue against requiring hourly AAR
calculations.378 Indicated PJM
Transmission Owners explain that PJM
adjusts transmission line ratings over
the day as temperatures change, but
state that there is little benefit to hourly
verification of temperature changes
because transmission line ratings in PJM
do not typically change hourly.
Similarly, EEI argues for a requirement
for daily AAR updates for real-time
operations.379
161. In contrast, Entergy explains that
it automatically updates AARs every
hour for the approximately 1,000
facilities for which it calculates AARs,
and this information is automatically
updated hourly in Entergy’s Real Time
Contingency Analysis so the operator
does not have to look at charts.380
Exelon also contends that an hourly
transmission line ratings check would
not be overly burdensome and instead
could help to prevent overloading a
transmission line.381 Exelon also urges
372 PJM
Comments at 5.
at 2 n.5.
374 Id. at 6.
375 ITC Comments at 9; MISO Transmission
Owners Comments at 24; EEI Comments at 12; Duke
Energy Comments at 10.
376 ITC Comments at 9.
377 MISO Transmission Owners Comments at 24.
378 AEP Comments at 6–7; Dominion Comments
at 3; Indicated PJM Transmission Owners
Comments at 7–9.
379 EEI Comments at 12; PacifiCorp Comments at
2; BPA Comments at 3; WAPA Comments at 6–7.
380 Entergy Comments at 3.
381 Exelon Comments at 9–10.
373 Id.
PO 00000
Frm 00028
Fmt 4701
Sfmt 4700
the Commission to provide sufficient
flexibility to ensure transmission line
ratings can change intra-hourly.382
Moreover, Exelon comments that it
believes that the Commission’s
proposed requirements are sufficiently
flexible to accommodate PJM’s current
approach.383
iii. Commission Determination
162. We adopt the Commission’s
proposal in the NOPR to require the
calculation of AARs ‘‘at least each hour,
if not more frequently’’ and the
requirement that AARs ‘‘appl[y] to a
time period of not greater than one
hour.’’ 384
163. With respect to calculation
frequency, we believe that performing
AAR calculations at least hourly
appropriately balances requiring
updates at a frequency that captures
meaningful changes in ambient air
temperature forecasts, and not
overburdening transmission providers.
In response to concerns that the
requirement for hourly calculations may
be unduly burdensome because
temperature forecasts do not always
fluctuate hour by hour, we recognize
that in some hours forecasts for
temperatures do not change, primarily
because weather services do not always
have updated forecasted values for
every location each hour. However, it is
not known exactly when such
forecasted values will be updated, and,
therefore, our requirement to calculate
AARs hourly appropriately requires
transmission providers to check for
forecast updates and apply any updates
that are available. We believe that the
requirement to calculate AARs hourly
ensures that any such publication of
forecast updates are incorporated into
AARs in a reasonable timeframe.385 If
we were to instead require such
calculations on a longer time period
(e.g., every eight hours), then there
would be some instances when
published available weather forecast
updates would not be incorporated into
AARs in time to accurately reflect the
transmission line’s true transfer
capability. Moreover, we expect this
process for AAR implementation to be
largely automated, with computer
systems querying or receiving updated
forecasts and processing any such data
382 Id.
383 Id.
at 9.
173 FERC ¶ 61,165 at P 3 n.3.
385 For example, we understand that the NBM
forecast (which is a blend of distinct constituent
forecasts) has updates published at least every hour,
but the constituent forecasts are typically updated
only three times per day. Exactly when the
constituent forecasts will be updated is not precise,
such that an update to any forecasted value might
change in any hour.
384 NOPR,
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
into updated AARs, such that
calculating AARs hourly should not be
significantly more burdensome than
calculating AARs daily. We agree with
Exelon that AAR calculations at least
hourly are likely to be an important tool
used to prevent any transmission
overload that might occur as a result of
a sudden, unexpected temperature
increase.386 We add that this
requirement does not preclude intrahour updates.
164. We acknowledge, in response to
comments by CAISO and NYISO, that
within RTOs/ISOs there will be times
when AARs produce real-time
transmission line ratings that diverge
from what was previously calculated in
the day-ahead market (based on earlier
forecasts), and that this may result in
operating considerations and uplift
costs. However, we are not persuaded
that such considerations or costs
outweigh the benefits of updating realtime transmission line ratings discussed
above. Further, updating transmission
line ratings closer to real time will help
ensure that the most accurate
transmission line ratings are used in the
real-time energy market and, in turn,
tend to reduce costs and promote
reliable operations. Commenters seem to
argue that if the weather conditions
unexpectedly change, such that
temperatures are significantly lower and
significantly more transfer capability is
able to be used in real time compared
to day ahead, the markets should keep
such transfer capability in reserve in
order to minimize uplift. We disagree
that a concern about potential uplift
should result in transfer capability being
withheld from the real-time energy
market with associated limits on the
economic benefits of using AARs.
Further, we do not believe that any
operating considerations associated
with updating transmission line ratings
in real time will compromise reliable
operations. As PJM states, AARs are
already employed in PJM in both the
day-ahead and real-time markets and, in
its experience, AARs increase
operational flexibility, promote a more
efficient use of the transmission system,
and result in more reliable system
dispatch and cost-effective market
operations.387
165. One of the reasons that
substantial uplift is sometimes
considered problematic is that it may be
evidence that the market is not
accurately considering operating
constraints, which gives rise to out-ofmarket actions and distorts short-term
386 Exelon
387 PJM
Comments at 9–10.
Comments at 2.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
and long-term price signals.388 While
we acknowledge the potential for uplift
in certain situations, the reason for
incurring uplift here is very different.
Updating transmission line ratings in
real time will result in more accurate
prices that reflect actual real-time
operating constraints. Accordingly, the
potential for the generation of uplift
through our AAR requirements would
not be evidence of market design
concerns or inaccurate price signals.
166. As discussed above, we believe
that, under the AAR requirements
adopted in this final rule, transmission
providers will implement AARs with
sufficient forecast margins in forward
periods such that instances of
reductions in transfer capability in real
time and the related operational
challenges will be infrequent.
Accordingly, we anticipate that transfer
capability will typically be freed up as
forecasts become more certain (and
require smaller forecast margins) from
forward periods to actual operation,
which will typically result in additional
transmission being made available as we
approach real time, and this will create
some uplift. But we find this is the
result of the policies that are needed to
ensure transmission line ratings are
sufficiently accurate to produce just and
reasonable wholesale rates, and that any
resulting uplift is, therefore,
appropriate. Additionally, however, we
acknowledge that transmission
providers might also implement
unreasonably high ambient air
temperature forecast margins. In such
instances, such unreasonably high
forecast margins would need to be
adjusted to ensure transmission line
ratings are accurate.
167. We clarify that this final rule
does not prohibit transmission
providers from utilizing AARs that are
calculated on a more frequent basis than
hourly. Relatedly, in response to
comments from PJM, we clarify that
nothing in this final rule prevents a
transmission provider from utilizing a
transmission line rating calculated in
between whatever standard AAR
calculation period is established.
168. Turning to the hourly resolution
(as opposed to the hourly frequency of
calculation) of AARs, we adopt the
NOPR proposal to require that AARs
‘‘appl[y] to a time period of not greater
than one hour’’ because we find such a
policy strikes an appropriate balance
between providing sufficient granularity
to transmission line ratings to reflect
meaningful predictable changes in
ambient air temperature across each
day, and not overburdening
transmission providers.389 These
changes are different from changes in
ambient air temperatures discussed
above, which are changes in forecasts
due to improved information as a time
period moves closer to real time as time
advances.
169. We find that ambient air
temperatures typically vary sufficiently
across the day to produce meaningful
differences in hourly transmission line
ratings. For example, we expect
temperatures during morning or evening
hours to typically be significantly
different than the noon temperature.
Recognizing such temperature
differences through transmission line
ratings may be particularly important,
since increasingly systems are being
challenged during such morning or
evening hours due to ramp or peak net
load challenges. We find that hourly
AAR calculations will create important
additional operational flexibility for
operators and more accurate
transmission line ratings. And because
we expect the AAR process to be largely
automated, we do not believe that the
requirement for hourly AARs will be
significantly more burdensome than a
less granular requirement (e.g., a
requirement that AARs apply to a time
period of not greater than one day). In
any event, we clarify that this final rule
does not preclude a transmission
provider from implementing AARs on a
more granular basis than hourly, such as
the 15-minute basis suggested by ISO–
NE with respect to its coordinated
transaction scheduling.
c. AAR Coordination
i. Comments
170. Several commenters argue that
further consideration is needed on AAR
implementation in certain
circumstances.390 For example, while
not supporting or opposing an AAR
mandate, NERC stresses the importance
of reliability, explaining that reliability
of the transmission system depends
upon the proper coordination of
transmission line ratings,391 and states
that special attention must be paid to
reliability considerations in the
implementation of any reforms in this
proceeding.392 Specifically, NERC notes
that the Commission should consider
whether to require transmission
389 Pro
Forma OATT attach. M, AAR Definition.
Comments at 6–7; EEI Comments at 14–
15; NYTOs Comments at 7; CAISO Comments at
12–13.
391 NERC Comments at 4.
392 Id.
390 NERC
388 Uplift Cost Allocation and Transparency in
Mkts. Operated by Reg’l Transmission Orgs. and
Indep. Sys. Operators, Order No. 844, 83 FR 18134
(Apr. 25, 2018), 163 FERC ¶ 61,041, at P 3 (2018).
PO 00000
Frm 00029
Fmt 4701
Sfmt 4700
2271
E:\FR\FM\13JAR2.SGM
13JAR2
2272
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
providers to coordinate AAR
implementation methods since
temperature readings and
methodologies may differ on tie lines,
and which transmission line rating
should be used in the event of a
disagreement among entities receiving
transmission line ratings or
methodologies.393
171. EEI asserts that the NOPR
proposal was unclear about how AARs
on transmission lines across seams
should be determined, where
transmission line ratings could be
subject to assumptions from two
different transmission providers, and
how AAR compliance could be
determined for non-jurisdictional
transmission facilities. EEI urges
flexibility on seams issues and for the
Commission to enforce reciprocity
conditions for non-jurisdictional
entities, should the Commission require
targeted AAR implementation.394 IID
also encourages the Commission to
consider seams issues that may need to
be addressed if AARs are different
among neighboring utilities.395 MISO
Transmission Owners similarly state
that ATC calculations on joint flowgates
and tie lines between RTOs/ISOs will
require coordination among all parties
each time a transmission line rating
changes, increasing the level of
communication necessary. According to
MISO Transmission Owners, along
these joint flowgates and tie lines,
transmission owners and RTOs/ISOs
will need to decide which forecast will
govern and whether to use multiple
weather forecasts.396
ii. Commission Determination
172. We agree with NERC’s comments
stressing the importance of reliability
and reiterate that system safety and
reliability are paramount to the
requirements for transmission line
ratings that we adopt in this final rule.
We agree with NERC and other
commenters that implementation of
AAR requirements on tie lines may
necessitate increased communication
among neighboring transmission
providers and relevant transmission
owners. While we expect that parties
will work collaboratively to ensure that
appropriate ratings are determined for
each tie line, we decline to adopt
specific requirements for coordinating
AAR implementation across
transmission provider seams. Parties
along these seams have a long history of
393 Id.
at 6–7.
Comments at 14–15.
395 IID Comments at 6–7.
396 MISO Transmission Owners Comments at 32–
33.
working collaboratively to ensure the
reliable implementation of transmission
facility ratings and we are not
persuaded that specific requirements for
coordination are required at this time.
Moreover, we note that, in the event of
a disagreement over the appropriate
facility rating, the NERC Reliability
Standards already establish a framework
for how entities should proceed, i.e.,
that the system should be operated to
the most limiting parameter.397
However, as described further in
Section IV.G.3.b, to ensure that
transmission providers have adequate
transparency into the transmission line
ratings methodologies of their
neighbors, we require transmission
providers to share transmission line
ratings and transmission line rating
methodologies with other transmission
providers, upon request.
173. In response to EEI and NERC, we
further clarify that, to the extent there is
a disagreement among entities about the
calculated AAR, transmission providers
should use the most limiting AAR in
order to ensure reliability and that
thermal limits are respected. As IID
suggests, however, if the most limiting
AAR along a mutual seam is based on
one transmission provider’s ambient air
temperature assumptions that are more
risk averse than another transmission
provider’s ambient air temperature
assumptions, the inevitable result will
be increased congestion between control
areas. While using the more risk averse
transmission line rating may result in an
increase in congestion relative to the
alternative of using a lower forecasted
ambient air temperature, we do not, in
this final rule, revise each transmission
provider’s authority to set the
transmission line ratings within its
control area.
174. In response to EEI’s request for
clarification on the applicability of the
AAR requirements to non-jurisdictional
entities, we note that the Commission’s
pro forma OATT requirements apply
only to Commission-jurisdictional
transmission providers. However, to the
extent non-jurisdictional entities have
reciprocity tariffs on file with the
Commission, such reciprocity tariffs
will need to implement pro forma
OATT Attachment M adopted herein in
order to satisfy the Commission’s
comparability (non-discrimination)
standards established in Order No. 888.
394 EEI
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
397 Reliability Standard TOP–001–5, Requirement
R 18, p. 7, https://www.nerc.com/pa/Stand/
Reliability%20Standards/TOP-001-5.pdf.
PO 00000
Frm 00030
Fmt 4701
Sfmt 4700
d. Applicability of AARs to
Transmission Loading Relief (TLR)
Events
i. NOPR Proposal
175. In the NOPR, the Commission
proposed to require transmission
providers to use AARs as the relevant
transmission line rating when
determining whether to curtail or
interrupt point-to-point transmission
service (under section 14.7 of the pro
forma OATT) if such curtailment or
interruption is necessary because of a
reduction in transfer capability
anticipated to occur (start and end)
within the next 10 days. The
Commission also proposed to require
transmission providers to use AARs as
the relevant transmission line rating
when determining whether to curtail
network transmission service or
secondary service (under section 33 of
the pro forma OATT) or redispatch
network transmission service or
secondary service (under sections 30.5
and/or 33 of the pro forma OATT), if
such curtailment or redispatch is both
necessary because of issues related to
flow limits on transmission lines and
anticipated to occur (start and end)
within 10 days of such
determination.398
ii. Comments
176. MISO states that the Commission
should clarify that use of AARs in
congestion management should not
discriminate based on the type of flows
being curtailed, be it transmission
service or market flow, as some
processes, such as the interregional TLR
process, differentiate between the types
of flow.399
iii. Commission Determination
177. We clarify that AARs should not
discriminate based on the type of flows
being curtailed, interrupted, or
redispatched. Accordingly, we modify
certain aspects of pro forma OATT
Attachment M, as proposed in the
NOPR, to clarify that AARs must be
used as the relevant transmission line
rating when determining whether to
initiate TLR procedures anticipated to
occur (start and end) within the next 10
days. We note that TLR procedures
occur pursuant to the curtailment,
interruption, and/or redispatch
procedures outlined in pro forma OATT
sections 13.6, 14.7, 30.5, and/or 33,
which are also referenced in pro forma
OATT Attachment M, as proposed in
the NOPR, as requiring the use of AARs
as the relevant transmission line rating.
398 NOPR,
399 MISO
E:\FR\FM\13JAR2.SGM
173 FERC ¶ 61,165 at PP 87, 89, 90.
Comments at 8.
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
In these instances, we find that
proposed pro forma OATT Attachment
M is already sufficiently clear: AARs
must be used as the relevant
transmission line rating when
determining whether to initiate TLR
procedures anticipated to occur (start
and end) within the next 10 days.
However, because pro forma OATT
Attachment M, as proposed in the
NOPR, only referenced curtailment and
interruption procedures that occur
pursuant to pro forma OATT section
14.7, for clarity, we modify the
proposed pro forma OATT Attachment
M to also reference curtailment and
interruption procedures that occur
pursuant to pro forma OATT section
13.6.
jspears on DSK121TN23PROD with RULES2
e. Communication and Verification of
AARs
i. Comments
178. With regard to the Commission’s
NOPR proposal that AAR data be
submitted by the transmission owner to
the RTO/ISO through Supervisory
Control and Data Acquisition (SCADA)
or related systems, MISO states that it
strongly urges the Commission not to
require any specific data
communication medium due to rapid
and frequent changes in technology.
MISO emphasizes that the scale and
scope of AARs as proposed in the NOPR
would require electronic and
programmatic updates to the RTO/ISO,
and using manual communication
methods, such as phone calls or written
messaging, would not be practical.
MISO adds that the requirements to
coordinate data interchange for
reliability are currently regulated by the
NERC Reliability Standards.400 CAISO
states that a fundamental challenge will
be to ensure entities can transmit
forecasted AARs in a timely manner.401
As a result of this challenge, CAISO
requests clarification on what to do in
cases of communication failure between
the transmission owner and the RTO’s/
ISO’s EMS and what an RTO/ISO
should do if a transmission owner
submits an incorrect transmission line
rating.402 NYISO clarifies that it receives
updates of transmission line ratings
from asset owners via the Inter-Control
Center Communication Protocol.403
NYTOs explain that, since AARs and
DLRs are constantly changing,
independent software validation
solutions will be needed to avoid
violating NERC Reliability Standard
FAC–008, which would occur when
400 MISO
Comments at 15–16.
Comments at 4–5.
402 Id. at 12–13.
403 NYISO Comments at 4.
there is any accidental discrepancy
between a calculated transmission line
rating and the transmission line rating
methodology.404
ii. Commission Determination
179. In response to comments
requesting that the Commission not
dictate communication mediums for
transmission owners submitting AARs
to RTOs/ISOs, we clarify that this final
rule requires that electronic
transmission line rating data be
submitted by transmission owners
directly into an RTO’s/ISO’s EMS
through SCADA or similar
communication systems. We clarify that
other electronic systems, such as InterControl Center Communication
Protocol, can be used to comply with
this requirement, and RTOs/ISOs may
propose to use such systems on
compliance.
180. In response to concerns about
potential scarcity of temperature data
and/or AAR communication failures, we
modify the NOPR proposal to require
that, if an AAR otherwise required to be
used under pro forma OATT
Attachment M is unavailable, the
transmission provider must use the
relevant seasonal line rating as the
appropriate transmission line rating.
This requirement does not relieve any
transmission provider of the obligation
in the first instance to provide an AAR
but provides an alternate only if an AAR
otherwise required under pro forma
OATT Attachment M is not available.
Further, while this provision establishes
the seasonal line rating as the default
recourse rating, the transmission
provider retains the ability under the
‘‘System Reliability’’ section of pro
forma OATT Attachment M to use a
different recourse rating where the
transmission provider reasonably
determines such a rating is necessary to
ensure the safety and reliability of the
transmission system.
181. In response to NYTOs’ comments
that changing transmission line ratings
will necessitate additional transmission
line rating validation tools, we reiterate
that the definitions of Transmission
Line Rating, AARs, and Seasonal Line
Rating we adopt in this final rule—as set
forth in pro forma OATT Attachment
M—require computation of transmission
line ratings in accordance with good
utility practice, including up-to-date
forecasts, to ensure the accuracy of the
relevant transmission line rating.405
And as NYTOs note, inaccurate
transmission line ratings or a
discrepancy between transmission line
401 CAISO
VerDate Sep<11>2014
18:58 Jan 12, 2022
404 NYTOs
405 Pro
Jkt 256001
PO 00000
Comments at 7.
Forma OATT attach. M, AAR Definition.
Frm 00031
Fmt 4701
Sfmt 4700
2273
ratings and the transmission line rating
methodology could trigger a violation of
NERC Reliability Standard FAC–008 by
the relevant transmission owner. In
other words, pro forma OATT
Attachment M imposes an affirmative
obligation on transmission providers to
implement accurate transmission line
ratings and the NERC Reliability
Standards similarly require accuracy in
transmission line ratings by the
transmission owners that calculate such
ratings. In RTOs/ISOs, where the
transmission provider (i.e., the RTO/
ISO) must rely on its transmission
owners to calculate and provide the
required transmission line ratings, we
acknowledge that there might be some
increased complexity in ensuring the
accuracy of the transmission line
ratings. However, we do not prescribe
the method for a transmission
provider—including an RTO/ISO—to
screen for issues with transmission line
ratings,406 instead leaving it up to the
transmission provider to develop a
general validation system that ensures
its compliance with the requirements of
this final rule and relevant NERC
Reliability Standards. We agree with
MISO that it is unable—and indeed is
not required—to audit transmission line
ratings; 407 rather, the type of validation
that we reference here would be akin to
the automated validation referenced by
CAISO, SPP, and PJM,408 where the
RTO/ISO runs checks for obvious signs
of data errors or corruption.
182. In response to CAISO’s request
for clarification on what an RTO/ISO
should do if a transmission owner
submits an incorrect transmission line
rating, we do not require RTOs/ISOs to
audit or recalculate transmission line
ratings submitted to them (except in
instances where their procedures
provide for them to calculate
406 For example, a transmission provider might
consider screening for such issues as: Missing data;
significant changes in transmission line ratings;
illogical data (such as ratings that increase with
increasing temperature, or daytime ratings that are
higher than nighttime ratings); and transmission
line ratings outside feasible ranges for particular
transmission lines.
407 MISO Comments at 27.
408 PJM Comments at 8; CAISO Comments at 13;
SPP Comments at 5–6. We note that, according to
the MISO Transmission Owners’ Agreement (TOA),
MISO also has a responsibility to verify
transmission line ratings. MISO, Open Access
Transmission, Energy and Operating Reserve
Markets Tariff, Rate Schedule 1, Appendix B,
Section V (30.0.0) (‘‘Each Owner shall file with
MISO information regarding the physical ratings of
all of its equipment in the Transmission System.
This information is intended to reflect the normal
and emergency ratings routinely used in regional
load flow and stability analyses. In carrying out its
responsibilities, MISO shall apply ratings that have
been provided by the respective Owners and have
been verified and accepted as appropriate by MISO
where such ratings affect MISO reliability.’’).
E:\FR\FM\13JAR2.SGM
13JAR2
2274
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
transmission line ratings, such as for
RTOs/ISOs that calculate AARs from
tables or databases). To the extent any
transmission provider becomes aware of
an apparent inaccurate transmission
line rating, the transmission provider is
expected to inform the transmission
owner immediately and both the
transmission provider and transmission
owner should take appropriate action to
correct any inaccuracy. If the
transmission provider and transmission
owner are unable to resolve the
inaccuracy of a submitted AAR, then, as
discussed above, the transmission
provider must use an appropriate
recourse rating until the AAR
inaccuracy is resolved. To the extent the
transmission provider and/or
transmission owner is out of compliance
with any applicable requirements, they
should report such noncompliance as
dictated by the applicable requirement.
f. Minimum AAR Temperature Range
and AAR Granularity
jspears on DSK121TN23PROD with RULES2
i. Comments
183. Vistra contends that the
Commission should provide guidance
on the range and granularity of
temperatures to be used in AARs.409
Vistra argues that the Commission’s
AAR policy will be undermined if
implementation decisions reintroduce
unnecessary conservativism (such as
only altering AARs for every 20 degrees
Fahrenheit of ambient air temperature,
or developing AARs for only a limited
range of ambient air temperatures).410
Vistra suggests that it would not be
unreasonable for AARs to change for
every one or two degrees Fahrenheit
change in ambient air temperature, and
that AARs be calculated for a range of
temperatures that cover the historical
low and historical high 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
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
409 Vistra
Comments at 6–7.
at 6.
411 Id. at 6–7.
412 Id. at 7.
413 ITC Comments at 15–16.
410 Id.
VerDate Sep<11>2014
18:58 Jan 12, 2022
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 precalculated 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.
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 fivedegree 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
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 dayahead 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
415 Commission
414 Vistra
Jkt 256001
PO 00000
Comments at 6–7.
Frm 00032
Fmt 4701
Sfmt 4700
416 Vistra
E:\FR\FM\13JAR2.SGM
Staff Paper at 7.
Comments at 6–7.
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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
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
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
jspears on DSK121TN23PROD with RULES2
417 MISO
Transmission Owners Comments at 18–
21.
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.
422 ITC Comments at 3.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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.
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-topoint 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-topoint transmission service to their
OASIS site.
194. For network transmission
service, the Commission proposed to
require transmission providers to
423 NOPR,
PO 00000
173 FERC ¶ 61,165 at P 107.
Frm 00033
Fmt 4701
Sfmt 4700
2275
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
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
424 Id.
PP 88, 90.
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.
425 See,
E:\FR\FM\13JAR2.SGM
13JAR2
2276
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
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 oneday, 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
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
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
429 MISO
Transmission Owners Comments at 17–
18.
430 Entergy
431 SPP
Comments at 15.
Comments at 7.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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 longerterm 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
PO 00000
Frm 00034
Fmt 4701
Sfmt 4700
(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
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
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 threemonth 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
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).
433 Proposed pro forma OATT attach. M, Seasonal
Line Rating definition.
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.
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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
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
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
208. SPP notes that the three-month
season duration conflicts with the fourmonth season length established by
SPP’s stakeholders.442
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
jspears on DSK121TN23PROD with RULES2
435 NRECA/LPPC
Comments at 23–24.
Transmission Owners Comments at 18.
437 Duke Energy Comments at 12.
438 MISO Comments at 20–21.
439 ITC Comments at 9–10.
440 PacifiCorp Comments at 3.
441 Id. at 7.
442 SPP Comments at 8.
443 SDG&E Comments at 3.
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
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
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,
436 MISO
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
444 MISO
Transmission Owners Comments at 34.
Comments at 21.
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.
445 MISO
PO 00000
Frm 00035
Fmt 4701
Sfmt 4700
2277
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 worstcase 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
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
2278
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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.
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
450 ACPA/SEIA Comments at 8, 11; EPSA
Comments at 4; New England State Agencies
Comments at 6.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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
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
451 NOPR,
173 FERC ¶ 61,165 at P 103.
pro forma OATT attach. M, ‘‘System
452 Proposed
Reliability’’.
PO 00000
Frm 00036
Fmt 4701
Sfmt 4700
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 linespecific 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
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
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
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.
459 NYTOs Comments at 7; NRECA/LPPC
Comments at 22.
460 NRECA/LPPC Comments at 22.
461 EEI Comments at 7.
462 NRECA/LPPC Comments at 17.
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
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
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.
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
Comments at 10–11.
Comments at 7.
465 LADWP Comments at 6–7.
466 PG&E Comments at 5.
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.
increase the complexity of the remedial
action scheme.470
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
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
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
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
463 Entergy
470 SDG&E
464 EEI
471 NYISO
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
Comments at 4.
Comments at 7–8; ISO–NE Comments
at 9.
472 NYISO
Comments at 7–8.
Comments at 9.
474 Exelon Comments at 2; EEI Comments at 6.
475 Exelon Comments at 11.
476 EPSA Comments at 4.
473 ISO–NE
PO 00000
Frm 00037
Fmt 4701
Sfmt 4700
2279
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
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
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.
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
E:\FR\FM\13JAR2.SGM
Continued
13JAR2
2280
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
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
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
transmission provider ‘‘will use’’ an alternate
transmission line rating as was proposed in the
NOPR.
480 NOPR, 173 FERC ¶ 61,165 at P 97.
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.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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.
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.
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
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).
483 Entergy Comments at 10–11.
PO 00000
Frm 00038
Fmt 4701
Sfmt 4700
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.
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
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.
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.
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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 reevaluation 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.
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
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
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-todate forecasts of ambient air
temperature, implementing DLRs
satisfies the requirements in pro forma
OATT Attachment M to implement
AARs.
2. DLR Requirements
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
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
487 18 CFR 37.6 (Information to be posted on the
OASIS).
488 NOPR, 173 FERC ¶ 61,165 at P 25.
489 Industrial Customer Organizations Comments
at 26.
490 ACPA/SEIA Comments at 12–13.
b. Comments
jspears on DSK121TN23PROD with RULES2
transmission line’s physical capability
than calendar age.489
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
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
PO 00000
Frm 00039
Fmt 4701
Sfmt 4700
2281
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
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
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
243. In opposing a mandate to
implement DLRs on all transmission
lines, many transmission owners focus
on the cost and challenges associated
491 NOPR,
173 FERC ¶ 61,165 at P 100.
173 FERC ¶ 61,165 at P 108.
493 Id. P 109.
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.
492 NOPR,
E:\FR\FM\13JAR2.SGM
13JAR2
2282
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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
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 realtime 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
497 BPA
Comments at 6.
Transmission Owners Comments at 47.
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.
jspears on DSK121TN23PROD with RULES2
498 MISO
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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
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
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.
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.
PO 00000
Frm 00040
Fmt 4701
Sfmt 4700
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 dayahead market resulting in increased
commitments are then reduced in the
real-time markets could increase uplift
costs.519
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
514 PJM
Comments at 12.
Comments at 12.
516 ISO–NE Comments at 19.
517 NYISO Comments at 6.
518 Id. at 7–8.
519 Id. at 14.
515 SPP
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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
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
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
520 SPP
MMU Comments at 4.
Economics Comments at 20.
522 CAISO DMM Comments at 2–3.
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.
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
jspears on DSK121TN23PROD with RULES2
521 Potomac
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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
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
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
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.
536 TAPS Comments at 15–17.
537 Industrial Customer Organizations Comments
at 25.
538 Certain TDUs Comments at 6–7.
PO 00000
Frm 00041
Fmt 4701
Sfmt 4700
2283
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
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
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,
539 PacifiCorp
Comments at 6.
Comments at 11–12.
541 NYISO Comments at 4.
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.
540 PJM
E:\FR\FM\13JAR2.SGM
13JAR2
2284
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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.
3. Extending to Non-RTO/ISO
Transmission Providers the
Requirement To Allow Transmission
Owners To Electronically Update
Transmission Line Ratings at Least
Hourly
jspears on DSK121TN23PROD with RULES2
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.
18:58 Jan 12, 2022
Jkt 256001
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
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
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
VerDate Sep<11>2014
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
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
b. Comments
260. Most transmission owners
oppose requirements for RTOs/ISOs to
study the cost effectiveness of DLR
implementation.553 One exception is
548 NOPR,
549 EEI
173 FERC ¶ 61,165 at P 109.
Comments at 18–19; PacifiCorp Comments
at 6.
550 R
Street Institute Comments at 5.
Comments at 15.
552 NOPR, 173 FERC ¶ 61,165 at P 110.
553 MISO Transmission Owners Comments at 38;
ITC Comments at 15; Exelon Comments at 6;
551 WATT
PO 00000
Frm 00042
Fmt 4701
Sfmt 4700
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
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
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.
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.
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
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
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
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
565 CAISO
Comments at 16.
Comments at 13–14.
567 SPP Comments at 15.
568 EPRI Comments at 5.
569 New England State Agencies Comments at 14.
570 Ohio FEA Comments at 6–7.
571 CEA Comments at 2–3.
566 PJM
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
effectiveness of DLR implementation.572
OMS contends that industry and
regulators need more information to
better understand the potential benefits
of DLRs.573
c. Commission Determination
264. In consideration of the comments
on this issue, we decline to require onetime 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.
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
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
572 Clean
Energy Parties Comments at 11.
Comments at 12.
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.
578 ENEL Comments at 2–3.
573 OMS
PO 00000
Frm 00043
Fmt 4701
Sfmt 4700
2285
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
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
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
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).
580 NOPR, 173 FERC ¶ 61,165 at PP 111–113.
581 Id. P 110.
582 Id. P 46 n.57.
E:\FR\FM\13JAR2.SGM
13JAR2
2286
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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
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
583 Id.
jspears on DSK121TN23PROD with RULES2
P 112.
584 Id. P 113.
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.
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 postcontingency 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
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
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
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
589 PG&E
Comments at 12.
Comments at 7.
591 Tangibl Comments at 4.
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.
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.
590 APS
PO 00000
Frm 00044
Fmt 4701
Sfmt 4700
operations.599 Tangibl contends that a
spot check of facilities in PJM shows
that almost all have unique emergency
ratings.600
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
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 suboptimal 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
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
599 Industrial Customer Organizations Comments
at 27.
600 Tangibl Comments at 3.
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.
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.
610 MISO Comments at 25.
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
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
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
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
611 MISO
Transmission Owners Comments at 17.
at 40.
613 MISO Comments at 25–26.
614 SPP MMU Comments at 4–5.
615 Potomac Economics Comments at 7, 11.
616 OMS Reply Comments at 11–12.
617 Id. at 12.
618 OMS Comments at 15.
612 Id.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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
277. Transmission owners indicate
that they use different durations for
calculating emergency ratings, including
hourly, daily, and two-day ahead shortterm emergency ratings by Entergy,622
up to 30 minutes during postcontingency 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 shortterm 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
278. RTOs/ISOs similarly indicate
that they use different durations for
calculating emergency ratings, including
long time emergency (four hours for
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.
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.
PO 00000
Frm 00045
Fmt 4701
Sfmt 4700
2287
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
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
631 ISO–NE
Comments at 6.
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.
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.
632 CAISO
E:\FR\FM\13JAR2.SGM
13JAR2
2288
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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, preload 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
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
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
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
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
652 BPA
jspears on DSK121TN23PROD with RULES2
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.
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.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
Comments at 7.
Comments at 13.
654 PacifiCorp Comments at 4.
655 WAPA Comments at 8.
656 MISO Comments at 26.
657 Potomac Economics Comments at 14.
658 Id. at 14.
659 Tangibl Comments at 5.
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.
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
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
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
653 Dominion
PO 00000
Frm 00046
Fmt 4701
Sfmt 4700
662 Tangibl Comments at 5; EDFR Comments at 6;
ACP Comments at 16–17.
663 Potomac Economics Comments at 8.
664 Indicated PJM Transmission Owners
Comments at 16.
665 MISO Transmission Owners Comments at 43–
44.
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.
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
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
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
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
670 New
England State Agencies Comments at 21.
Street Institute Comments at 8.
672 Id. at 8.
673 EPRI Comments at 8.
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.
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.
jspears on DSK121TN23PROD with RULES2
671 R
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
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
288. Potomac Economics argues that
the Commission should clarify that the
unique emergency ratings be applied for
contingent constraints, stating that
approximately half of the potential
benefits and reduced production costs
of the rulemaking could be lost without
such a clarification.684 New England
State Agencies and OMS agree that
accurate emergency ratings could
provide important benefits.685 However,
New England State Agencies argue that
more information is needed.686
289. Regarding implementation,
PacifiCorp states that the ability to use
emergency ratings in TTC on path
ratings 687 is more complex than being
able to calculate them because this
requires contingency analysis.688
Entergy states that emergency ratings
implementation is complicated by the
thermal time constraint being different
for all conductors based on size and
construction.689
290. ITC asserts that AARs should be
used for both normal ratings (precontingency operations) and emergency
ratings (post-contingency operations)
because congestion is often caused by
projected post-contingency flows.690
EDFR and Industrial Customer
Organizations state that, where
appropriate, emergency ratings could be
combined with DLRs for additional
benefits.691 Similarly, PG&E supports
681 Indicated PJM Transmission Owners
Comments at 15–16.
682 Dominion Comments at 13; EEI Comments at
16–17.
683 Exelon Comments at 22.
684 Potomac Economics Comments at 4.
685 New England State Agencies Comments at 21;
OMS Comments at 13–14.
686 New England State Agencies Comments at 22.
687 The NERC Glossary defines ‘‘Rated System
Path Methodology,’’ which includes an initial TTC
from which the ATC is derived and is generally
reported as specific transmission path capabilities.
NERC, Glossary of Terms Used in NERC Reliability
Standards (June 28, 2021), https://www.nerc.com/
pa/Stand/Glossary%20of%20Terms/Glossary_of_
Terms.pdf.
688 PacifiCorp Comments at 5.
689 Entergy Comments at 13–14.
690 ITC Comments at 12.
691 EDFR Comments at 6; Industrial Customer
Organizations Comments at 27.
PO 00000
Frm 00047
Fmt 4701
Sfmt 4700
2289
considering the benefits of AARs for
both normal and emergency ratings.692
By contrast, ACPA/SEIA encourage the
consideration of seasonal line rating
information in developing emergency
ratings, similar to the framework for
using seasonal line ratings for long-term
transmission service.693
291. ISO–NE states that an update to
the overall transmission line rating
methodology to include AARs may also
necessitate the need for new emergency
ratings based on those AARs.694
Potomac Economics supports a
requirement that transmission owners
calculate and use AARs based on
emergency ratings for contingency
constraints.695 NYTOs state that having
normal and emergency ratings could
preempt the need to establish an AAR
mandate on all transmission lines.696
b. Commission Determination
292. Based on the record developed in
this proceeding, we are persuaded that
it is appropriate to adopt certain
requirements for emergency ratings.
Whether and how a transmission owner
establishes emergency ratings is
important because emergency ratings
are a critical input into determining
transfer capability, both during normal
operations and during post-contingency
operations. There is a significant record
of transmission owners and
transmission providers already using
emergency ratings.697 For example,
Exelon notes that it already calculates
emergency ratings for its transmission
facilities and that the benefits of using
emergency ratings during emergencies
outweigh the costs of establishing
them.698 There is also an extensive
record on the role of emergency ratings
in ensuring reliable and efficient
operations. Specifically, transmission
owners and transmission providers
report benefits from implementing
emergency ratings including increased
transmission capacity,699 additional
time to respond to contingencies,700
lower costs to consumers,701 and help
692 PG&E
Comments at 12.
Comments at 17.
694 ISO–NE Comments at 10–11.
695 Potomac Economics Reply Comments at 8.
696 NYTOs Comments at 11.
697 See, e.g., 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.
698 Exelon Comments at 22.
699 ISO–NE Comments at 10; PacifiCorp
Comments at 4.
700 APS Comments at 7.
701 ISO–NE Comments at 10; PacifiCorp
Comments at 4; WAPA Comments at 8.
693 ACPA/SEIA
E:\FR\FM\13JAR2.SGM
13JAR2
2290
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
maintaining reliability and avoiding
unnecessary load shed.702 Emergency
ratings have an extensive record of use
and are a more accurate representation
of the flow limits over shorter
timeframes and are thus necessary to
ensure just and reasonable wholesale
rates.
293. First, as set forth under
‘‘Obligations of Transmission Provider’’
in pro forma OATT Attachment M, we
require that transmission providers use
emergency ratings for contingency
analysis in the operations horizon and
in post-contingency simulations of
constraints. We define an ‘‘emergency
rating’’ in pro forma OATT Attachment
M as a transmission line rating that
reflects operation for a specified, finite
period, rather than reflecting continuous
operation. An emergency rating may
assume acceptable loss of equipment
life or other physical or safety
limitations for the equipment
involved.703 We adopt this emergency
ratings requirement to ensure the
accuracy of transmission line ratings,
particularly during emergency
operations. Emergency ratings are a
critical input into determining transfer
capabilities and congestion costs during
emergency operations and can provide
temporarily expanded operating
flexibility to allow higher loading and
higher operating limits on transmission
facilities for a short time during
unexpected tight system conditions,
emergency events, or contingencies.
Emergency ratings are also a critical
input into the scheduling of transactions
that can be executed under real-time
operating constraints. Because real-time,
unforeseen contingencies can occur that
stress the system’s transfer capabilities
(e.g., forced outages on generation or
transmission), transmission providers
operate their systems in normal
conditions to be able to withstand such
contingencies. Should such a
contingency occur, transmission
providers are thus prepared to
redispatch resources. Dispatching and
scheduling resources to accommodate
such contingency events can cause a
large increase in wholesale rates, due to
congestion costs. More accurate
702 Exelon
Comments at 22.
NERC Glossary defines an ‘‘Emergency
Rating’’ as: ‘‘[t]he rating as defined by the
equipment owner that specifies the level of
electrical loading or output, usually expressed in
megawatts (MW) or Mvar or other appropriate units,
that a system, facility, or element can support,
produce, or withstand for a finite period. The rating
assumes acceptable loss of equipment life or other
physical or safety limitations for the equipment
involved.’’ NERC, Glossary of Terms Used in NERC
Reliability Standards (June 28, 2021), https://
www.nerc.com/pa/Stand/Glossary%20of
%20Terms/Glossary_of_Terms.pdf.
jspears on DSK121TN23PROD with RULES2
703 The
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
emergency ratings (like more accurate
transmission line ratings generally) will
better reflect the near-term transfer
capability of the system, more
accurately reflect the cost of serving
load, and avoid unnecessary transient
congestion costs. For these reasons, we
adopt the emergency ratings
requirement as set forth in pro forma
OATT Attachment M.
294. Second, we require that
transmission providers use uniquely
determined emergency ratings. Under
this requirement, transmission
providers must use emergency ratings
that transmission owners determine
uniquely from their determination of
normal ratings.704 This requirement
ensures that transmission providers use
emergency ratings that reflect that a
transmission facility’s transfer
capabilities may differ for shorter
periods of time; that is, transfer
capabilities differ if calculated for use
over a short period of time (i.e., for
emergency ratings) rather than for use
over an indefinite period of time (i.e.,
for normal ratings).
295. In response to commenters
stating that the Commission should not
require that emergency ratings be
unique from normal ratings, we clarify
that we are not requiring that emergency
ratings be arbitrarily higher than normal
ratings. Instead, we are requiring that
emergency ratings be uniquely
determined, meaning determined based
on assumptions that reflect the
specified, finite duration of emergency
ratings, as distinct from the assumptions
used to calculate normal ratings, which
reflect a power transfer capability that
can be maintained indefinitely.
Consistent with the Commission’s
statements in the NOPR,705 transmission
owners will have discretion to
determine the procedure used to
calculate emergency ratings, so long as
they do so in accordance with good
utility practice and the other
requirements in pro forma OATT
Attachment M. Accordingly, a
transmission provider may use an
emergency rating equal to a normal
rating, provided that both ratings were
calculated uniquely using appropriate
assumptions, sound engineering
judgment, and good utility practice.
296. We agree with PacifiCorp’s
comment that the ability to use uniquely
determined emergency ratings requires
real-time and near real-time horizons
704 As clarified below, consistent with our
determination in Section IV.B.2.b.iii. on the role of
the transmission owner and transmission provider
in AAR implementation, transmission owners, not
transmission providers, are responsible for
calculating emergency ratings.
705 NOPR, 173 FERC ¶ 61,165 at P 46 n.57.
PO 00000
Frm 00048
Fmt 4701
Sfmt 4700
contingency analysis tools that can
handle variable limits (i.e., normal
rating for normal operating conditions,
and emergency ratings in contingency
conditions) and perform iterative
simulations to calculate TTC on path
ratings.706 Such contingency analysis is
already required under NERC Reliability
Standards, including, e.g., Reliability
Standards TOP–001 and IRO–008,
which require transmission providers
and reliability coordinators to perform a
real-time assessment at least once every
30 minutes to ensure that instability,
uncontrolled separation, or cascading
outages that could adversely impact the
reliability of the interconnection will
not occur.707 Modifications to futurelooking cases to increase flow, and to
iteratively run contingency analysis, is
common practice since system loading
conditions change throughout the day.
However, we agree that these tools
require additional data points and
simulation process modifications to
observe the emergency rating of bulk
electric system facilities, if not currently
used.
297. Third, we require that emergency
ratings also incorporate an adjustment
for ambient air temperature and for
daytime/nighttime solar heating,
consistent with the AAR requirements
for normal ratings. Based on the record,
we find that the calculation of AARs for
both normal and emergency ratings will
enhance the accuracy of transmission
line ratings and ensure just and
reasonable wholesale rates. As
commenters point out, congestion is
often caused by post-contingency
transmission flows that are modeled and
managed as part of normal operations,
and thus not requiring AARs to be
applied to emergency ratings would
inaccurately constrain even normal
operations and prevent significant
potential benefits of AAR
implementation. Finally, we note that
applying AARs to emergency ratings is
consistent with the implementation of
AARs in PJM, where nearly all
emergency ratings are dependent on
ambient air temperatures.708
706 PacifiCorp
Comments at 5–6.
Standard TOP–001–5 R13 requires
a transmission operator to perform a Real-Time
Assessment at least once every 30 minutes.
According to the NERC Glossary, a ‘‘Real-Time
Assessment’’ is: ‘‘[a]n evaluation of system
conditions using Real-time data to assess existing
(pre-Contingency) and potential (post-Contingency)
operating conditions. The assessment shall reflect
applicable inputs including, but not limited to: . . .
Facility Ratings; and identified phase angle and
equipment limitations.’’ NERC, Glossary of Terms
Used in NERC Reliability Standards (June 28, 2021),
https://www.nerc.com/pa/Stand/Glossary%20of
%20Terms/Glossary_of_Terms.pdf.
708 See PJM Ratings Information, https://
www.pjm.com/markets-and-operations/etools/
707 Reliability
E:\FR\FM\13JAR2.SGM
13JAR2
jspears on DSK121TN23PROD with RULES2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
298. As with the application of AARs
to normal ratings, transmission owners
have discretion to determine which
specific electric system equipment has
emergency ratings that are affected by
ambient air temperatures, consistent
with good utility practice and the
requirements of pro forma OATT
Attachment M.
299. Consistent with our
determination in Section IV.B.2.b.iii on
the role of the transmission owner and
transmission provider in AAR
implementation, we clarify that
transmission owners, not transmission
providers, are responsible for
calculating emergency ratings. This
responsibility is set forth in the NERC
Reliability Standards, as well as in RTO/
ISO foundational documents.709
Nothing in this final rule changes that
responsibility. In the non-RTO/ISO
regions, this is generally not a concern
because the transmission provider is
usually the transmission owner.
However, in the RTO/ISO regions, there
is a distinction between transmission
owners and transmission providers.
Thus, in order to comply with this final
rule, RTOs/ISOs—the transmission
provider with the OATT on file—will
need to rely on their member
transmission owners to calculate
emergency ratings and provide them to
the RTO/ISO.710 Additionally, unlike
normal transmission line ratings,
emergency ratings correspond to a
specific duration. Thus, the duration of
each uniquely determined emergency
rating determined by a transmission
owner must be specified and
communicated by the transmission
provider, consistent with our
determination on the transparency and
reporting requirements of transmission
line ratings in Section IV.G.3 below.
300. Where the transmission provider
is not the transmission owner (e.g.,
RTOs/ISOs), we require the
transmission provider to explain in its
compliance filing, as part of its
implementation of new pro forma
OATT Attachment M, through what
mechanism (tariff, membership
agreement, etc.) the transmission owner
has the obligation for making and
communicating to the transmission
provider the timely calculations and
determinations related to emergency
ratings (including any discretion in
calculations).
301. In response to commenter
requests for a minimum, maximum, or
oasis/system-information/ratings-information.aspx
(last visited Nov. 1, 2021).
709 See, e.g., Reliability Standards FAC–008–5,
Requirement R3 and FAC–008–5, Requirement R6.
710 See supra note 326.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
standardized emergency rating duration,
we recognize that transmission owners
use a range of durations and find that
transmission owners are best situated to
make judgments on the appropriate
emergency rating duration based on the
technical capabilities of the installed
equipment, consistent with good utility
practice, using sound engineering
judgment, manufacturer guidance, and
equipment reliability experience.
302. We recognize, as pointed out by
some commenters, that emergency
ratings can affect the safe operation and
useful life of transmission facilities.
However, as several commenters
explain, most transmission equipment
has the ability to withstand high
currents for short periods of time
without sustaining damage.711 The
requirement to implement uniquely
determined emergency ratings simply
requires that emergency ratings
calculations be based on this existing
ability, where it exists. In response to
comments from MISO that the
Commission allow transmission owners
to establish reasonable and supported
reliability margins,712 as the
Commission stated in the NOPR,
transmission providers that find they
need a reliability margin have existing
Commission-approved mechanisms,
such as the transmission reliability
margin component of ATC, for
establishing such a margin on a
consistent and transparent basis.713
303. In response to Indicated PJM
Transmission Owners and MISO
Transmission Owners’ concerns with
Potomac Economics’ analysis, we note
that our findings in this final rule are
not solely based on Potomac Economics’
analysis. Rather, our rationale for
adopting the requirement to implement
uniquely determined emergency ratings,
similar to the AAR requirements
discussed above, is based on the finding
that implementing uniquely determined
emergency ratings will ensure that
transmission line ratings are more
accurate, that more accurate
transmission line ratings will ensure
wholesale rates more accurately reflect
the cost of the wholesale service being
provided, and, thus, that those
wholesale rates are just and reasonable.
3. Equipment for Which Emergency
Ratings Must Be Calculated
a. Comments
304. Exelon and APS note that they
can and do calculate emergency ratings
on equipment other than conductors
711 See, e.g., Entergy Comments at 6–8; BPA
Comments at 7; Exelon Comments at 21–23.
712 MISO Comments at 26.
713 NOPR, 173 FERC ¶ 61,165 at P 104.
PO 00000
Frm 00049
Fmt 4701
Sfmt 4700
2291
and transformers.714 APS notes that its
use of emergency ratings often does not
impact, and typically is not limited by,
substation equipment.715 Entergy states
that emergency ratings cannot be used
on many components of facilities.716
However, Entergy explains that
autotransformers can have emergency
ratings about 25 to 30% over their
normal rating for up to two hours.717
Tangibl notes that different equipment
may be limiting under different
operating scenarios and that, while
secondary and control components
often have identical normal and
emergency ratings, it is rare for relays to
be the limiting element in PJM winter
ratings.718
b. Commission Determination
305. As we determined in Section
IV.A above, emergency ratings, like all
transmission line ratings, must
incorporate a set of electrical equipment
ratings that collectively operate as a
single electric system element (e.g.,
transformers, relay protective devices,
terminal equipment, and series and
shunt compensation devices), and the
most limiting component from that set
will determine the transmission line
rating. Consistent with our
determination on the use of AARs in
Section IV.B.1 above, we find that
transmission providers must use
uniquely determined emergency ratings
on all conductors and all relevant
transmission equipment, in order to
ensure that transmission line ratings are
accurate.
G. Transparency
1. NOPR Proposal
306. The Commission proposed in the
NOPR to require transmission owners to
share transmission line ratings for each
period for which they are calculated and
transmission line rating methodologies
with their transmission provider(s), and,
in regions served by an RTO/ISO, also
with the market monitor(s) of that RTO/
ISO.719 The Commission preliminarily
found that this requirement would
afford transmission providers and
market monitors more operational and
situational awareness.720
307. The Commission also
acknowledged that sharing transmission
line ratings and transmission line rating
methodologies with other, additional,
interested parties would allow for
714 APS
Comments at 7; Exelon Comments at 21.
Comments at 7.
716 Entergy Comments at 7.
717 Id. at 7.
718 Tangibl Comments at 3.
719 NOPR, 173 FERC ¶ 61,165 at P 125.
720 Id. P 126.
715 APS
E:\FR\FM\13JAR2.SGM
13JAR2
2292
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
greater transparency and, in the case of
transmission providers, may aid efforts
to manage congestion along mutual
seams and may be beneficial for the
study of affected systems during the
interconnection process.721 The
Commission thus sought comment on
whether to require transmission owners
to share, upon request, their
transmission line ratings and
transmission line rating methodologies
with transmission providers other than
the transmission owner’s own
transmission provider. The Commission
also sought comment on whether to
require transmission owners to make
their transmission line ratings and
transmission line rating methodologies
available to other interested
stakeholders, including by posting
information on their OASIS page or
other password-protected online
forums.722
308. While the Commission did not
propose new auditing requirements in
the NOPR, the Commission reiterated
that it would continue to conduct
reviews of transmission line ratings as a
component of broader tariff compliance
audits.723
2. Comments
a. Increased Transparency Requirements
for Transmission Line Ratings
Methodologies
jspears on DSK121TN23PROD with RULES2
309. Many commenters express
general support for the Commission’s
efforts to increase transparency
surrounding transmission line ratings
and methodologies.724 MISO
Transmission Owners argue that the
transparency proposal in the NOPR
seems reasonable, but should not be
broadened, explaining that the
transparency proposal in the NOPR
balances the need for transparency for
RTOs/ISOs and market monitors with
the need for confidentiality.725
Industrial Customer Organizations state
that transparency is a prerequisite for
stakeholders to independently evaluate
the potential reliability benefits of more
accurate transmission line ratings, for
the Commission to ensure just and
reasonable rates, to reduce the
incentives and opportunities for
transmission owners to understate or
manipulate transmission line ratings,
and for transmission providers to
identify cost-effective congestion
721 Id.
P 129.
722 Id.
723 Id.
P 130.
724 MISO Transmission Owners Comments at 19;
Entergy Comments at 16; NRECA/LPPC Comments
at 27–28; AEP Comments at 5; DC Energy
Comments at 5; IID Comments at 7.
725 MISO Transmission Owners Comments at 36.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
management solutions.726 EDFR claims
that increased transparency may result
in more efficient and standardized
transmission line rating methodologies
while identifying outliers more quickly
and that transparency encourages the
use of a balanced, reasonable
transmission line rating methodology,
which should result in more accurate
transmission line ratings.727 OMS states
that the Commission’s regulations
require transmission line rating
transparency.728 OMS further contends
that transparency should be the default
position and should only be restricted
where demonstrably necessary.729 EPSA
states that transparent collection and
disclosure of quality data is the
lynchpin of an efficient transmission
system.730 Certain TDUs state that
improved transparency of transmission
line ratings processes will ultimately
lead to a more efficient and costeffective grid.731 IID supports the
Commission’s proposed requirements
and encourages the Commission to
consider how such information can be
shared in a timely manner, such that
adjacent operators and users of the grid
can account for current transmission
line ratings in their weekly and dayahead planning.732
b. Sharing Transmission Line Ratings
and Methodologies With Transmission
Providers and Market Monitors
310. Nearly all commenters support
the proposal in the NOPR to require
transmission owners to share
transmission line ratings and
methodologies with the relevant
transmission provider and, in the case
of transmission providers that are RTOs/
ISOs, the relevant market monitor.733
AEP and Exelon note that PJM posts
actual transmission line ratings
publicly.734
311. DC Energy contends that
implementing AARs and DLRs and
requiring RTOs/ISOs to post the
transmission line ratings used for each
constraint-binding interval for both the
726 Industrial Customer Organizations Comments
at 28–29.
727 EDFR Comments at 7.
728 OMS Comments at 17 n.57 (citing 18 CFR
37.6).
729 OMS Reply Comments at 3–4.
730 EPSA Comments at 3.
731 Certain TDUs Comments 8.
732 IID Comments at 7.
733 AEP Comments at 8; CAISO DMM Comments
at 3, 7–8; OMS Comments at 16; Exelon Comments
at 23–24; DC Energy Comments at 5; Potomac
Economics Comments at 16; IID Comments at 7;
New England State Agencies Comments at 17–19;
R Street Institute Comments at 3; SPP MMU
Comments at 5; TAPS Comments at 23.
734 AEP Comments at 8; Exelon Comments at 23–
24.
PO 00000
Frm 00050
Fmt 4701
Sfmt 4700
day-ahead and real-time markets is not
an infeasible or unduly burdensome
task.735 DC Energy notes that ERCOT
publishes every transmission line rating
used for every constraint’s binding
interval for both its day-ahead and realtime markets on its market information
system portal accessible by all market
participants.736
312. Potomac Economics contends
that the information shared must
include the limiting element for each
transmission line rating and the inputs
necessary to replicate the transmission
line rating calculation to monitor for
transmission withholding, and that such
information should be maintained in a
database accessible by those with a role
in monitoring, operating, and planning
the transmission system.737 EDFR
supports a requirement that
transmission owners provide
information identifying the transmission
line’s limiting element.738 New England
State Agencies agree with the reforms
proposed in the NOPR with a minimum
of requiring disclosure of transmission
line ratings and methodologies to all
grid operators and market monitors.739
New England State Agencies state such
a requirement would allow verification
of the existing transmission line ratings
by independent authorities.740 New
England State Agencies assert that
providing data to the RTO/ISO market
monitor would allow the market
monitor to verify the quality and
accuracy of the information.741 New
England State Agencies contend that
transmission owners may have an
incentive to be overly conservative with
transmission line ratings methodologies
because there is no financial incentive
for more efficient operation of existing
transmission assets and there is
significant incentive for transmission
owners to build new transmission lines
and substations and include these new
assets in their rate base.742 Because
NYISO and PJM already require similar
data disclosure, New England State
Agencies claim that transmission
owners can comply without undue
difficulty with the proposed
requirements and that there is no actual
evidence in the record of any increased
litigation in those regions where
disclosure is common.743
313. NRECA/LPPC caution that their
members do not believe the Commission
735 DC
Energy Comments at 5.
736 Id.
737 Potomac
Economics Comments at 16–17.
Comments at 6.
739 New England State Agencies Comments at 19.
740 Id.
741 Id. at 17–18.
742 Id. at 18.
743 Id. at 20.
738 EDFR
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
should require RTOs/ISOs to develop
and maintain comprehensive databases
to document the limiting element of all
transmission circuits and facilities in
their regions, arguing that the benefit to
consumers is unclear and that the NOPR
does not support such a requirement.744
314. Only two commenters object to
the proposed transparency
requirements. Dominion states that
requiring that transmission line ratings
and methodologies be disclosed to the
RTO/ISO market monitor is
unwarranted because transmission line
ratings are primarily reliability tools and
are effectively overseen by NERC.745
Dominion states that it already provides
transmission line ratings to PJM and
PJM makes them publicly available.746
While Dominion does not object to
continuing these practices, Dominion
does object to providing its transmission
line rating methodology to the PJM
market monitor, which Dominion argues
has no oversight over the operation of
the PJM transmission system.747
Separately, ITC argues that requirements
to make all transmission line ratings
available to the RTOs/ISOs, market
monitor, and other stakeholders would
be unduly burdensome.748 ITC states
that only a small number of
transmission lines contribute to
congestion and that regular reporting
may increase the probability of
inconsistencies between ITC’s internal
databases and those used for external
data requests.749 ITC therefore requests
that the final rule require transmission
owners to provide such data only upon
request. ITC argues that RTOs/ISOs and
market monitors should use shared
transmission line ratings for
informational purposes only and not for
standardization purposes.750
c. Transmission Providers Sharing
Transmission Line Ratings and
Methodologies With Any Transmission
Provider
315. Several commenters support a
requirement for transmission providers
to share, upon request, transmission line
ratings and methodologies with any
transmission provider.751 APS states
that this sharing of information is
essential to ensure security in APS’s
transmission operator area.752 MISO
jspears on DSK121TN23PROD with RULES2
744 NRECA/LPPC
Comments at 27–28.
745 Dominion Comments at 14–15.
746 Id.
747 Id.
748 ITC Comments at 13.
749 Id.
750 Id.
751 APS Comments at 8; PacifiCorp Comments at
3; MISO Comments at 29; EPSA Comments at 3;
Exelon Comments at 27; IID Comments at 7.
752 APS Comments at 8.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
states that, in addition to the proposed
transparency requirements in the NOPR,
sharing the same information with
neighboring transmission providers that
share a seam with MISO is needed.753
MISO asserts that such sharing of these
transmission line ratings would be
necessary for both tie lines and
interregional congestion management,
useful for reliability studies involving
the neighboring regions, consistent with
other coordination practices, and
subject to confidentiality restrictions to
control dissemination.754 Similarly,
Vistra argues that the Commission
should clarify that transmission
providers must share AAR information
with neighboring transmission
providers because transmission line
rating calculations typically consider
loop flows.755 Vistra explains that,
logistically, this information sharing
could take many forms, including direct
data pushes between transmission
providers or publishing such
information on OASIS sites and that the
Commission need not dictate a
particular information sharing
method.756
d. Sharing Transmission Line Ratings
and Methodologies With Other Entities
316. Some commenters support
requiring the sharing of transmission
line ratings and methodologies with
entities other than transmission
providers and market monitors.757 For
example, WATT contends that
transmission line rating methodologies
need to be shared with all transmission
customers.758 R Street Institute argues
that the NOPR proposal would provide
insufficient transparency and that,
ideally, transmission line ratings and
methodologies would be available to a
broader set of market participants and
state commissions as well.759 OMS
similarly asserts that all stakeholders
should be able to see transmission line
ratings and that the market monitor and
MISO should be granted complete
transparency into the methods used to
create these transmission line ratings,
recognizing that the regional entities are
strictly focused on reliability.760
317. TAPS urges the Commission to
allow interested persons to access
753 MISO
Comments at 29.
754 Id.
755 Vistra
Comments at 7–8.
transmission line ratings and
methodologies through passwordprotected interfaces, such as OASIS,
such that if a transmission customer has
concerns about the impact of a
constraint, it should be able to obtain
information on the transmission line
ratings and methodologies used to
establish such ratings. TAPS contends
that doing so would enable transmission
customers to better understand what is
driving the prices that they are required
to pay.761 APS states it would not
support posting transmission line
ratings and methodologies on OASIS,
but would support other passwordprotected online forums where access
could be controlled.762 To expand
transmission line rating information and
reduce the information gap, ACPA/SEIA
suggests that there are several options,
including expanding the FERC Form
715 reporting requirements or making
this information available on OASIS
sites.763 DC Energy asks that the
Commission require transmission
owners outside of organized electricity
markets to post transmission line ratings
and methodologies on their OASIS
pages or another password-protected
online forum.764
318. Clean Energy Parties contend
that requiring transmission owners to
disclose their transmission line ratings
and methodologies to RTOs/ISOs and
market monitors but not share with the
broader public is unduly
discriminatory.765 Exelon requests
flexibility to allow transmission
providers, like PJM, to publish
transmission line ratings consistent with
existing practices.766 ACPA/SEIA
contends that the Commissions should
require that all market participants have
comparable information on near-term
transmission service.767 ACPA/SEIA
argues that because near-term
transmission service information would
only be available to transmission
owners, RTOs/ISOs, and market
monitors, there would be a
discriminatory ‘‘information gap,’’
putting transmission customers at a
disadvantage by not being able to easily
identify optimal interconnection
locations and not being able to
understand or reproduce AAR or DLR
congestion analyses.768
319. New England State Agencies
argue that it is important to states that
756 Id.
757 APS Comments at 9; Clean Energy Parties
Comments at 14; EPSA Comments at 3; Exelon
Comments at 28–29; EDFR Comments at 7; New
England State Agencies Comments at 20; OMS
Comments at 16; R Street Institute Comments at 3;
TAPS Comments at 24; WATT Comments at 14.
758 WATT Comments at 14.
759 R Street Institute Comments at 3.
760 OMS Comments at 16.
PO 00000
Frm 00051
Fmt 4701
Sfmt 4700
2293
761 TAPS
Comments at 24.
Comments at 9.
763 ACPA/SEIA Comments at 19–20.
764 DC Energy Comments at 5–6.
765 Clean Energy Parties Comments at 14.
766 Exelon Comments at 28–29.
767 ACPA/SEIA Comments at 19–20.
768 Id. at 18–19.
762 APS
E:\FR\FM\13JAR2.SGM
13JAR2
2294
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
have relied on competitive
procurements for certain types of energy
development needs to have access to
transmission line ratings and
methodologies.769 According to New
England State Agencies, the
Commission’s requirement in Order No.
1000 that transmission providers
consider public policy transmission
needs as part of regional transmission
planning processes would be materially
aided by allowing open access to
transmission line ratings and similar
data.770 New England State Agencies
state that password protections and nondisclosure agreements can be used in
protecting confidential information in a
wide variety of circumstances if there is
concern about loss of confidential
business information.771
320. Conversely, several commenters
oppose further sharing beyond
transmission providers and, where
appropriate, market monitors.
PacifiCorp states that it strongly opposes
making its transmission line ratings
broadly available to stakeholders or
posting such information to OASIS due
to the potential for reliability risks and
unclear benefits.772 MISO Transmission
Owners state that there appears to be no
need for transmission line ratings to be
public because: (1) ATC is made
available to the public; (2) transmission
line ratings are only one of many inputs
into ATC; and (3) ATC is made available
on OASIS pages.773 PG&E recommends
against requiring transmission owners
and transmission providers to post realtime transmission line ratings on their
OASIS pages, noting that transmission
line rating methodologies should also
not be disclosed to any parties other
than the Commission and other
transmission providers.774 Indicated
PJM Transmission Owners argue that
requiring transmission line ratings and
methodologies to be made public would
be unnecessary in PJM, given the
existing information is made
available.775 EEI recommends that the
Commission not require transmission
owners and transmission providers to
post real-time transmission line ratings
on their OASIS pages but instead
provide only the methodologies for
determining AARs and seasonal line
ratings.776
jspears on DSK121TN23PROD with RULES2
769 New
England State Agencies Comments at 20.
770 Id.
771 Id.
772 PacifiCorp
Comments at 4.
Transmission Owners Comments at 37.
774 PG&E Comments at 12.
775 Indicated PJM Transmission Owners
Comments at 23–24.
776 EEI Comments at 13.
773 MISO
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
e. Auditing, Enforcement, and Litigation
321. Several commenters note that
NERC already audits transmission line
ratings and argue that any transmission
line ratings verification or transmission
line ratings auditing performed by
market monitors would be unnecessary
or harmful.777 Exelon states that, were a
market monitor to allege improper
transmission line rating calculations
which NERC has already approved,
there could be dueling determinations
and confusion and potential
inconsistency with FPA section 215,
which specifies that NERC, as the
Electric Reliability Organization, is
responsible for enforcing mandatory
Reliability Standards.778 Exelon, AEP,
and MISO Transmission Owners allege
that calculating transmission line
ratings requires a degree of engineering
judgment, reflective of transmission
owners’ operational experience, risk
tolerance, and local knowledge.779
Exelon argues that market monitors lack
this knowledge.780 AEP argues that
RTOs/ISOs should have no role beyond
applying submitted transmission line
ratings.781 EEI asks that the Commission
emphasize that any final rule would not
change the audit and enforcement
construct already in place and that the
audits should not specifically review
the transmission line rating
methodologies and assumptions.782
MISO Transmission Owners explain
that it may not present a problem for
RTOs/ISOs and market monitors to
identify computational transmission
line ratings errors, but RTOs/ISOs and
market monitors should not be
permitted to second-guess transmission
line rating methodologies.783 Indicated
PJM Transmission Owners explain that
the functions of the PJM market monitor
are limited to those items identified by
Attachment M of the PJM OATT,
requiring the market monitor to assess
the competitiveness of the ‘‘PJM
markets, but not monitor transmission
line ratings as it does not have the
requisite expertise or reliability
authority.784 Indicated PJM
Transmission Owners disagree with the
Commission’s statement that the NERC
Reliability Standards may be
777 Exelon Comments at 24; AEP Comments at 8–
9; EEI Comments at 13–14; Indicated PJM
Transmission Owners Comments at 17–18.
778 Exelon Comments at 25–26.
779 Id. at 26–27; AEP Comments at 9; MISO
Transmission Owners Comments at 37–38.
780 Exelon Comments at 26–27.
781 AEP Comments at 9.
782 EEI Comments at 13–14.
783 MISO Transmission Owners Comments at 37–
38.
784 Indicated PJM Transmission Owners
Comments at 22–23.
PO 00000
Frm 00052
Fmt 4701
Sfmt 4700
insufficient to ensure accurate
transmission line ratings.785 Sunflower
argues that the Commission should
require specific measures for
transmission providers to monitor the
impact of AARs and seasonal line
ratings on the safety and reliability of
the electric system.786
322. Some commenters argue for
further oversight and expansion of the
auditing of transmission line ratings and
methodologies. Potomac Economics
recommends that the Commission
require some form of independent
oversight, verification, and monitoring
of the transmission line ratings
calculated and used in non-RTO/ISO
areas.787 Potomac Economics contends
that it is important to clarify that
transmission line rating information that
underlies curtailments under
transmission line ratings or joint
operating agreements be available to
other transmission providers, reliability
coordinators, or RTOs/ISOs that are
affected by the curtailments.788 Ohio
FEA recommends that PJM routinely
review submitted transmission line
ratings and the methodologies used in
their development; otherwise, Ohio FEA
continues, the benefits associated with
implementing AARs may prove to be
illusory if the transmission line ratings
themselves are not based on objective
and accurate criteria.789 Ohio FEA
insists that the PJM market monitor
must be granted the authority to review
transmission line ratings and take
corrective actions deemed necessary if
the market monitor concludes that a
transmission owner’s transmission line
ratings are inaccurate, consistent with
the market monitor’s role as defined in
Attachment M of the PJM OATT.790
323. Many commenters express
concern over potential litigation
regarding transmission line ratings and
methodologies (though AEP states that
the proposed requirements in the NOPR
adequately mitigate litigation risks).791
EEI argues that third parties should not
be able to litigate or dispute
transmission line ratings or
methodologies.792 Exelon caveats that
its position supporting additional
transparency is contingent on the
Commission ensuring that the enhanced
transparency does not result in constant
litigation from market participants,
provided such transmission line ratings
785 Id.
at 19–21.
Comments at 4.
787 Potomac Economics Comments at 18; see also
Potomac Economics Reply Comments at 12.
788 Potomac Economics Comments at 18.
789 Ohio FEA Comments at 5–6.
790 Id. at 6.
791 AEP Comments at 10.
792 EEI Comments at 13–14.
786 Sunflower
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
and calculations are reasonably accurate
at reflecting a transmission facility’s
power transfer capability, as
transmission line ratings are
fundamentally a reliability concept.793
MISO Transmission Owners argue that
transparency requirements beyond those
proposed in the NOPR that result in an
increase in disputes and litigation
surrounding transmission line ratings
and/or methodologies would reduce the
benefits of the proposed reforms. MISO
Transmission Owners therefore contend
that the Commission should clarify its
statement in the NOPR that the
proposed increased transparency will
allow RTOs/ISOs and market monitors
to verify transmission line ratings.794
Similarly, Indicated PJM Transmission
Owners warn that further transparency
disclosure requirements would result in
costly and time consuming litigation,
and thereby increased burdens on
transmission owners and the
Commission, as a result of arguments
from market participants soliciting
changes designed to benefit themselves
and negatively affect others. Indicated
PJM Transmission Owners stress that
this would be inappropriate because
transmission line ratings are complex
calculations, based on many different
factors, including local assets,
engineering judgment, and how assets
are traditionally operated, and therefore
litigation with the Commission would
be inappropriate.795 ITC requests that
the final rule clarify that incorrect
transmission line ratings due to changes
in weather or unintentional errors in
data that were submitted in good faith
should not create additional legal or
regulatory liability for transmission
owners. ITC states that it would not
benefit from such errors since it is
primarily concerned with reliability and
does not participate in markets.796
Conversely to these commenters, AEP
expresses that the Commission’s NOPR
strikes the right balance between
providing transparency without creating
risks of unnecessary litigation for
transmission owners if transmission line
ratings cannot be precisely replicated by
third parties.797 Furthermore, DC Energy
contends that the need for disclosure
outweighs transmission owners’ claims
of confidentiality or fear of potential
litigation.798
793 Exelon
Comments at 29.
Transmission Owners Comments at 37–
38 (citing NOPR, 173 FERC ¶ 61,165 at P 127).
795 Indicated PJM Transmission Owners Comment
at 24.
796 ITC Comments at 16.
797 AEP Comments at 9–10.
798 DC Energy Comments at 5.
794 MISO
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
f. Posting of Exceptions to OASIS
324. 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.799
g. Other Transparency Topics
325. ISO–NE states that to comply
with the NOPR’s proposed transparency
requirements, it would need to modify
Planning Procedure No. 7, Procedures
for Determining and Implementing
Transmission Facility Ratings (PP7) as
New England Transmission Owners are
required to follow the PP7 procedures to
determine transmission line rating
methodologies.800 ISO–NE requests that
the Commission allow for sufficient
time for the PP7 changes to make their
way through the applicable processes
for the transmission owners to
implement those changes and then
provide new transmission line ratings to
ISO–NE and its market monitor in the
manner contemplated in the NOPR.801
326. NRECA/LPPC recommend that
any measures in the final rule to
improve the transparency of
transmission line ratings should be
consistent with the requirements of
existing mandatory NERC Reliability
Standards, including Critical
Infrastructure Protection (CIP)
Standards, as well as requirements to
protect Critical Electric/Energy
Infrastructure Information (CEII).802
327. OMS suggests that the
Commission could revisit the data it
currently collects in FERC Form 715 to
better analyze how the data already
being collected can be used to
understand some transmission owners’
transmission line ratings and
methodologies but not others.803 OMS
also suggests that the Commission
consider a comment and response
process between transmission owners,
transmission providers, and market
monitors to provide additional oversight
into the appropriateness of transmission
line ratings throughout the bulk power
system.804
328. Clean Energy Parties contend
that RTOs/ISOs should be required to
discuss with stakeholders and report to
the Commission how winter capacity
deliverability differs from summer and
identify possible reliability
improvements or cost savings arising
from those differences.805
329. Some commenters assert a
connection between transparency
around transmission line ratings and
FTR markets. EDFR states that
transparency provides market
participants with a better understanding
of how transmission line ratings could
change over time while helping to
anticipate congestion, hedge congestion,
and participate in the FTR markets.806
DC Energy states that market
participants, particularly those that
purchase and sell FTRs, need
transparency in order to critically
analyze and address market
inefficiencies.807 DC Energy contends
that FTR market participants will
require transparent transmission line
rating and methodology information in
order to accurately forecast
congestion.808 DC Energy asserts that
transparency is essential for the
transition to AARs and DLRs because,
without adequate transparency, AARs
and DLRs could actually make
congestion hedges less accurate. This is
because, according to DC Energy, AARs
and DLRs will cause transmission line
ratings to change without advance
notification and, in times of adverse
system conditions, AARs and DLRs will
more accurately reflect the fact that less
transfer capability is available.809
3. Commission Determination
330. Upon consideration of the
comments received, we adopt the NOPR
proposal to require public utility
transmission owners to share their
transmission line ratings for each period
for which they are calculated and
transmission line rating methodologies
with their transmission providers and
with market monitors in RTOs/ISOs. We
acknowledge situations in which the
transmission owner and transmission
provider are the same entity, and we
expect that in such cases compliance
with this final rule’s transparency
requirements will be simple in the sense
that the transmission provider will not
have to rely on a separate transmission
804 Id.
799 EPSA
Comments at 4.
800 ISO–NE Comments at 11.
801 Id. at 11.
802 NRECA/LPPC Comments at 3.
803 OMS Comments at 17.
PO 00000
Frm 00053
Fmt 4701
Sfmt 4700
2295
805 Clean
Energy Parties Comments at 12.
Comments at 7.
807 DC Energy Comments at 3–4.
808 Id. at 4.
809 Id. at 5.
806 EDFR
E:\FR\FM\13JAR2.SGM
13JAR2
2296
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
owner to provide the transmission line
ratings and methodologies. We also
adopt three additional transparency
requirements. First, we require each
transmission provider to share
transmission line ratings and
methodologies with any transmission
provider(s) upon request. Second, we
require each transmission provider to
maintain a database of its transmission
line ratings and methodologies on the
transmission provider’s OASIS site, or
other password-protected website. We
require that this database be in such a
form that can be accessed by all parties
with OASIS access or access to the
password-protected website. The
database should archive and allow for
querying of all current transmission line
ratings and all transmission line ratings
used in the past five years. Third, we
require transmission providers to post
on OASIS, or other password-protected
website, which transmission lines
qualify for an exception to the AAR or
seasonal line rating requirements and
the reasons why such transmission lines
qualify for an exception.
a. Transmission Owners Sharing Ratings
and Methodologies With Transmission
Providers and, Where Applicable,
Market Monitors
331. We find that requiring public
utility transmission owners to share
transmission line ratings and
methodologies with their transmission
providers and, in RTOs/ISOs, market
monitors, will help remedy unjust and
unreasonable wholesale rates caused by
inaccurate transmission line ratings. We
affirm the Commission’s preliminary
finding in the NOPR that this
requirement will enhance operational
and situational awareness by ensuring
that transmission providers know the
effect that changes in ambient air
temperature would have on
transmission line ratings within their
system.810 Further, as the Commission
explained in the NOPR, this
requirement will provide transmission
providers and market monitor(s) the
information necessary to verify the
resulting transmission line ratings and
to identify potential errors.811
332. We agree with EDFR that the
transparency-increasing effects of
requiring public utility transmission
owners to share transmission line
ratings and methodologies with their
transmission provider(s), and with
market monitors in RTOs/ISOs, will
result in more accurate transmission
line ratings. By sharing transmission
line ratings and methodologies with
810 NOPR,
173 FERC ¶ 61,165 at P 127.
811 Id.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
transmission providers and market
monitors, these parties will be better
positioned to develop automated
screens and other techniques to detect
corrupted data or other errors that could
negatively impact operations or
planning processes.
333. We disagree with arguments that
because transmission line ratings are
reliability tools that are effectively
overseen by NERC, additional
transparency requirements are
unnecessary. While transmission line
ratings are an important reliability tool,
we find (as discussed above in Section
III) that transmission line ratings
directly affect wholesale rates. Further,
commenters have not explained why a
relationship between transmission line
ratings and reliability would represent a
reason not to adopt the transparency
requirements. We also disagree with
comments that requiring public utility
transmission owners to share
transmission line ratings and
methodologies with their transmission
provider(s) and with market monitors in
RTOs/ISOs would be unduly
burdensome and could create
inconsistencies between transmission
line ratings used internally by
transmission owners and transmission
line ratings used by transmission
providers. We recognize comments from
New England State Agencies noting that
such disclosure is already common in
some markets, and that this indicates
that transmission owners can comply
without undue difficulty.812 Moreover,
we think it is unlikely that sharing of
transmission line ratings would create
inconsistencies in the manner described
by ITC. On the contrary, we believe that
a benefit of this requirement would be
to identify and promote the resolution
of such inconsistencies.
334. Finally, we reiterate that the
Commission will continue to conduct
reviews of transmission line ratings as a
component of broader tariff compliance
audits 813 and that this final rule does
not change the auditing requirements or
authorities of any entity.
b. Transmission Providers Sharing With
Any Transmission Provider(s) Upon
Request
335. As set forth under ‘‘Obligations
of Transmission Provider’’ in pro forma
OATT Attachment M, we further require
transmission providers to share
transmission line ratings and
812 New
England State Agencies Comments at 20.
commenters use the term ‘‘audit’’ to
describe activities by market monitors and other
entities that the Commission’s rules do not define
as auditing. We note that the Commission retains
its authority to formally audit for compliance with
OATTs and other Commission-jurisdictional rules.
813 Many
PO 00000
Frm 00054
Fmt 4701
Sfmt 4700
methodologies with any transmission
provider(s) upon request and in a timely
manner. We agree with commenters that
contend that this requirement is
necessary because transmission
operators often consider the effect that
power flows on their transmission lines
will have on other transmission
providers’ transmission lines, and
transmission providers will need
transmission line ratings on other
systems to evaluate these effects
properly. While we acknowledge that
Vistra’s example involved neighboring
transmission providers, we do not limit
this requirement to neighboring
transmission providers, as such power
flow effects can sometimes extend
beyond neighboring transmission
providers (particularly if a neighboring
transmission provider’s system is
geographically/electrically narrow
where it approaches another
transmission provider’s system).
Further, we agree with commenters that
this information sharing could take
several forms, and that the Commission
need not dictate an information sharing
method. However, any such information
sharing method should be sufficient to
accommodate the reasonable business
needs of the other transmission
provider(s) (e.g., to allow the other
transmission provider(s) to process
transmission service requests in a timely
manner).
c. Transmission Providers Sharing With
Other Entities
336. We further require each
transmission provider to maintain a
database of their transmission owners’
transmission line ratings and
methodologies on the passwordprotected section of their OASIS site or
other password-protected website. This
requirement will allow other entities
(beyond transmission providers and
market monitors) that are able to access
the password-protected section of the
transmission provider’s OASIS site or
other password-protected website to
have access to the database of
transmission line ratings and
methodologies. This requirement is set
forth under ‘‘Obligations of
Transmission Provider’’ in pro forma
OATT Attachment M. We agree with
commenters that making transmission
line ratings and methodologies available
to a broader range of stakeholders will
amplify the expected benefits of the
proposal included in the NOPR, further
facilitate more accurate transmission
line ratings, and facilitate more costeffective decisions by market
participants and, as described by New
England State Agencies, state agencies.
For example, without accurate
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
transmission line rating information,
market participants may be unable to
make informed siting decisions
regarding where to build generation or
where to site load. Also, without
accurate transmission line rating
information, market participants may be
unable to accurately predict and hedge
against transmission congestion.
Moreover, as New England State
Agencies argue, access to transmission
line ratings and transmission line rating
methodologies is important to states that
have relied on competitive
procurements for certain types of energy
development needs.814 We acknowledge
that requiring this information to be
placed on OASIS or other passwordprotected website presents a burden on
transmission providers, but we find that
the benefits of increased transparency
are likely to outweigh any such burden.
337. Beyond enhancing the general
benefits of the transmission line rating
requirements adopted herein, we find
that transparency for transmission line
ratings and methodologies will also be
particularly beneficial to wholesale
market participants trying to manage
uncertainty. With respect to FTR market
participants, for example, we agree with
DC Energy that, because FTR payouts
are based on congestion costs that
change with transmission line ratings,
sharing transmission line ratings and
methodologies with a wider range of
stakeholders will help establish efficient
FTR market price discovery by
improving FTR market participants’
understanding of certain drivers of
congestion, and allow such market
participants to build such
understanding into their FTR bids and
offers.815
338. We disagree with arguments
contending that requiring each
transmission provider to maintain a
database of each transmission owner’s
transmission line ratings and
methodologies on the transmission
provider’s OASIS site or other
password-protected website will lead to
unjust and unreasonable wholesale rates
or other undesirable outcomes.
Specifically, we are not persuaded by
comments that making transmission line
ratings and methodologies available to a
broader range of stakeholders could
result in increased litigation whereby
customers initiate complaints against
transmission owners regarding the
814 New
England State Agencies Comments at 20.
Energy Comments at 3. While different
RTOs/ISOs have different names for these financial
products, such as financial transmission rights,
transmission congestion rights, congestion revenue
rights, etc., for simplicity here we will use FTRs to
refer to any such financial product in the RTOs/
ISOs.
815 DC
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
underlying assumptions used to
calculate transmission line ratings or
regarding the calculations themselves.
There is a lack of evidence of increased
litigation in those regions where
disclosure is already common, as noted
by the New England State Agencies.816
Moreover, commenters have not
identified any complaints or other such
litigation about transmission line ratings
related to this existing requirement.
Further, consistent with the
Commission’s statement in the
NOPR,817 we intend to give latitude to
transmission owners to determine their
transmission line ratings in accordance
with good utility practice. Finally, we
note that section 37.6 of the
Commission’s regulations already
requires transmission providers, upon
customer request, to make all data used
to calculate ATC for any constrained
posted path publicly available on
OASIS. This includes the limiting
elements and the cause of the limit (e.g.,
thermal, voltage, stability), as well as
load forecast assumptions.818 The
posting requirement for transmission
line ratings and methodologies is
consistent with that existing
requirement.
339. Transmission line ratings stored
in the required database must include a
full record of all transmission line
ratings, both as used in real-time
operations, and as used for all future
market periods for which transmission
service is offered. For example, a
transmission provider that implements
AARs calculated for the next 240 hours
(for use in evaluating near-term
transmission service requests), recalculates such AARs every hour, and
calculates seasonal line ratings (for use
in evaluating longer-term transmission
service requests) would keep records of
its transmission line ratings in the
following manner. With respect to its
AARs, such a transmission provider
would insert records into its
transmission line rating database each
hour, shortly after calculation of its
AARs. In each such hour, the
transmission provider would insert a
separate AAR record into its database
for: (1) Each transmission line; (2) each
current and forward hour for which
transmission line ratings are calculated
(at least one rating for each of the 240
hours in the next 10 days); and (3) each
rating type (normal and each type of
emergency rating (e.g., 30 minute, one
hour, etc.)). If such a transmission
provider had 1,000 transmission lines
and four rating types (e.g., normal, 30
816 New
England State Agencies Comments at 20.
173 FERC ¶ 61,165 at PP 98, 105.
818 See 18 CFR 37.6.
817 NOPR,
PO 00000
Frm 00055
Fmt 4701
Sfmt 4700
2297
minute, one hour, and four hour), then
each hour the transmission provider
would insert into its database 960,000
new AAR records (1000 × 240 × 4).819
Furthermore, such a transmission
provider would also maintain in its
database records of which seasonal line
ratings (for use in evaluating longerterm transmission service requests) or
other types of transmission line ratings
(as permitted under pro forma OATT
Attachment M, e.g., static line ratings)
were in effect at which times for each
transmission line.820 Finally, while we
are not requiring implementation of
DLRs at this time, we note that if a
transmission provider implements DLRs
on any of its transmission lines, then
under this requirement it would
document the DLR ratings on such
transmission lines in the same way that
it documents its AAR ratings, as
discussed above.
340. Transmission providers must
maintain in their database 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 other
document retention periods required for
OASIS postings.821 Each record in the
database must indicate to which
transmission line the record applies,
and the date and time the record was
entered into the database. Finally, the
database must be maintained such that
users can view, download, and query
data in standard formats, using standard
protocols.
d. Transmission Providers Posting
Exceptions and Temporary Alternate
Ratings to OASIS
341. Finally, in response to EPSA, we
require transmission providers to make
postings to the database of transmission
line ratings on their OASIS site or other
password-protected website (discussed
above in Section IV.G.3.d) documenting
819 We note that transmission providers may
determine that there are more efficient ways of
storing the AAR data than presented in the example
above, and such approaches may be acceptable as
long as users of the database can readily identify
which such ratings (including for the operational
hour and any forward hours) were in effect for
which transmission lines at which times.
820 We do not specify exactly how records of
seasonal or static line ratings should be stored in
the line rating database. However, such longer-term
transmission line ratings do not necessarily need to
be stored on an hourly basis, so long as users of the
database can readily identify which such ratings
were in effect for which transmission lines at which
times. We note that some transmission lines may
not have any AAR ratings at all, where permitted
under pro forma OATT Attachment M, and so may
only have ratings such as seasonal or static line
ratings.
821 18 CFR 37.6 (Information to be posted on the
OASIS).
E:\FR\FM\13JAR2.SGM
13JAR2
2298
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
any uses of exceptions (under the
‘‘Exceptions’’ paragraph of pro forma
OATT Attachment M) or temporary
alternate ratings (under the ‘‘System
Reliability’’ section of pro forma OATT
Attachment M). This requirement to
post exceptions and temporary alternate
ratings on OASIS or other passwordprotected website is set forth in pro
forma OATT Attachment M. 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.
342. We find that the requirement for
such postings will help ensure proper
transparency for the use of such
exceptions and temporary alternate
ratings, similar to the transparency
provided through other posting
requirements of this final rule.822
Furthermore, these postings of
exceptions will support the fulfillment
of and verification of compliance with
the requirement, discussed above in
Section IV.D.3, that exceptions be reevaluated at least every five years.
343. Similar to the benefits discussed
above in Section IV.G.3.c related to
requiring transmission line ratings and
methodologies to be available on OASIS
sites or other password-protected
websites, we find that this requirement
for exceptions postings will enable and
support verification of the accuracy of
transmission line ratings.
H. Other Miscellaneous Issues
jspears on DSK121TN23PROD with RULES2
1. Comments
344. Some commenters argue for
incentives to encourage DLR
deployment. Specifically, NYTOs and
ACORE request financial incentives for
AARs and DLRs under FPA section
219.823 ACPA/SEIA contend that the
Commission should consider
accelerated cost recovery of
depreciation to implement sensor-based
DLRs.824 Although WATT urges the
Commission to address the
misalignment of incentives to adopt
DLRs or other grid-enhancing
technologies, WATT asserts that the
Commission should not grant incentives
for DLRs in this docket.825
345. MISO contends that while AARs
may provide incremental transfer
capability on existing transmission
lines, they cannot solve significant long822 See, 18 CFR 37.6 (Information to be posted on
the OASIS).
823 NYTOs Comments at 2; ACORE Comments at
3–4.
824 ACPA/SEIA Comments at 11.
825 WATT Comments at 16.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
range transmission problems.826
Moreover, EEI argues that chronic
congestion should be reviewed and
alleviated in the transmission planning
process.827
2. Commission Determination
346. In response to arguments about
incentives for advanced transmission
technology deployment, we find such
arguments about incentivizing certain
technology to be outside the scope of
this proceeding, which is limited to the
Commission’s proposed requirements
for transmission line ratings.
347. In response to MISO’s assertion
that AARs cannot solve significant longrange transmission problems, we find
transmission planning and development
to be outside the scope of this
proceeding. For the same reason, we
find EEI’s claim that chronic congestion
should be reviewed and alleviated in
the transmission planning process to be
outside the scope of this proceeding. 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. RM21–17–000.828
I. Compliance
1. NOPR Proposal
348. In the NOPR, the Commission
proposed to require each transmission
provider to submit a compliance filing
within 60 days of the effective date of
any final rule. The Commission clarified
that this compliance deadline would be
for transmission providers to submit
proposed AAR tariff changes, RTOs/
ISOs to submit proposed tariff changes
designed to maintain systems and
procedures needed to allow for the use
of AARs and DLRs, transmission owners
to submit tariff changes implementing
the proposed transparency reforms, or
for each entity to otherwise comply with
any final rule. As justification, the
Commission acknowledged that
implementing the reforms required by
any final rule in this proceeding may be
complex, but preliminarily found that
implementation of these reforms is
important to ensure wholesale rates are
just and reasonable.
349. Recognizing the complexity of
the proposed AAR requirements, the
Commission proposed a staggered
implementation approach that would
826 MISO
Comments at 2, 6–7.
Comments at 6.
828 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).
827 EEI
PO 00000
Frm 00056
Fmt 4701
Sfmt 4700
prioritize implementation on
historically congested transmission
lines (within one year from the date of
the compliance filing), but further
proposed a less aggressive
implementation of AARs on all other
transmission lines (within two years
from the date of the compliance filing).
For the proposed DLR requirements and
proposed transparency requirements,
the Commission proposed that tariff
changes filed in response to a final rule
in this proceeding would become
effective within one year from the date
of the compliance filing.
350. The Commission recognized that
some transmission providers may have
provisions in their existing OATTs or
other document(s) subject to the
Commission’s jurisdiction that the
Commission has deemed to be
consistent with or superior to the pro
forma OATT or that are permissible
under the independent entity variation
standard or regional reliability standard.
Where these provisions would be
modified, the Commission proposed to
require transmission providers to either
comply with the proposed requirements
or demonstrate that these previously
approved variations continue to be
consistent with or superior to the pro
forma OATT as modified by the
proposed requirements or demonstrate
that these previously approved
variations are just and reasonable and
meet the purpose of the final rule under
the independent entity variation
standard or regional reliability
standard.829
2. Comments
351. Comments on the proposed
compliance and implementation
timelines came predominately from
RTOs/ISOs and transmission owners
requesting more time. Most commenters
suggest a minimum 120-day compliance
deadline,830 but some suggest a
minimum 180-day compliance
deadline,831 and others suggest a
minimum 90-day compliance
deadline.832 Most transmission owners
commenting argue that three years is
needed to implement AARs on priority
transmission lines; 833 however,
829 NOPR,
173 FERC ¶ 61,165 at P 132.
Comments at 19; NRECA/LPPC Comments
at 28–29; MISO Transmission Owners Comments at
38–39; SCE Comments at 2; SDG&E Comments at
1–2; APS Comments at 10; WFEC Comments at 1;
Southern Company Comments at 6–7; MISO
Comments at 31; ISO–NE Comments at 12.
831 CAISO Comments at 2; NYISO Comments at
18.
832 SPP Comments at 16; PacifiCorp Comments at
7.
833 EEI Comments at 18; NRECA/LPPC Comments
at 28–29; MISO Transmission Owners Comments at
22–23; SCE Comments at 2; SDG&E Comments at
830 EEI
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
PacifiCorp suggests that two years
would be sufficient, while PG&E
suggests that at least four years would
be needed.834 NYTOs, WAPA, and BPA
also contend that the proposed
implementation timeline is insufficient
but do not proposed an alternative
schedule.835 Some commenters support
the proposed timeline.836 Industrial
Customer Organizations recommend
that the proposed implementation
timeline be halved.837
352. Arguing that one year is
insufficient to implement AARs on
historically congested transmission
lines, MISO Transmission Owners
explain that their experience is that, on
average, it takes several years to
implement AARs on even a subset of
transmission lines.838 According to
MISO Transmission Owners, at least
three years is needed for AAR
implementation because of all the steps
needed to implement AARs, including
developing and updating the
transmission line rating methodologies,
analyzing historical weather
information, identifying limiting
elements, developing a transmission
line ratings database, updating the
transmission management system,
testing the transmission line ratings, and
linking the transmission owners’
transmission management system to the
RTO/ISO EMS, all while maintaining
cybersecurity standards.839 EEI similarly
states that it could take up to two years
just to upgrade operating and data
systems to create the capability to
produce and update AAR
calculations.840 Southern Company and
SCE support EEI’s comments.841
Specifically, Southern Company
requests at least 120 days for
compliance filings and at least three
years for AAR implementation.842 SCE
claims that the Commission’s proposed
implementation schedule is not
realistic.843
353. PacifiCorp states that
implementation of the NOPR proposal
would be complicated as it would
1–2; APS Comments at 10; WFEC Comments at 1;
Southern Company Comments at 6–7; ITC
Comments at 5; LADWP Comments at 8–9.
834 PacifiCorp Comments at 2–3; PG&E Comments
at 6–8.
835 NYTOs Comments at 1; WAPA Comments at
6; BPA Comments at 6.
836 OMS Comments at 9; Potomac Economics
Comments at 19–20.
837 Industrial Customer Organizations Comments
at 22.
838 MISO Transmission Owners Comments at 22.
839 Id.
840 EEI Comments at 18.
841 Southern Company Comments at 3–4; SCE
Comments at 2.
842 Southern Company Comments at 3–4.
843 SCE Comments at 2.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
require updates to PacifiCorp’s EMS,
SCADA, and other software that
communicates transmission line ratings
with CAISO, RC West, and other
transmission providers.844 APS argues
that adequate time is needed to develop
the business requirements for the
software vendors and that APS will
have to work with multiple software
vendors to comply with the TLR
provisions as currently delineated in the
NOPR.845 NRECA states that its
members need a minimum of three
years to implement AARs on all their
transmission lines in order to identify,
document, and implement the necessary
system and process changes.846
Presenting a five year implementation
approach, PG&E states that AAR
implementation will require significant
initial investments and that the
Commission should allow for sufficient
time for RTOs/ISOs and transmission
owners to collaborate to develop new
communication systems and new
processes for determining and operating
with AARs.847
354. ITC states that the proposed
requirements in the NOPR would be
complicated to implement for
transmission owners that currently do
not use AARs, and the implementation
timeline would exceed one year since it
would require coordination with the
transmission management system,
development of internal transmission
line ratings software or a software
purchase from a vendor, and analysis of
how AARs will affect ITC’s internal
transmission line ratings database.848
The proposed one-year implementation
timelines suggest that ITC would need
to first develop a costly and error-prone
manual process as a short-term solution
before developing a more permanent
automated process.849 ITC states that
additional time should be built into the
Commission’s proposed timeline so that
initial implementation issues can be
identified and corrected.850 Similarly,
NYTOs argue that the one-year
compliance timeline for AARs is overly
ambitious and could have adverse
effects, be costly, and potentially
impossible.851
355. Other transmission owners
voicing concern with the proposed
schedule include WAPA, LADWP, and
BPA. WAPA notes that it is concerned
about the proposed timeline, given its
844 PacifiCorp
Comments at 3–4.
Comments at 6.
846 NRECA/LPPC Comments at 28–29.
847 PG&E Comments at 6–7.
848 ITC Comments at 6.
849 Id. at 6–7.
850 Id. at 7.
851 NYTOs Comments at 1.
845 APS
PO 00000
Frm 00057
Fmt 4701
Sfmt 4700
2299
expansive geographic area and
transmission system of over 17,000 line
miles, and its other statutory duties it
must meet to operate its system
reliably.852 LADWP recommends an
implementation period of no less than
three years for congested transmission
lines, noting that the proposed AAR
requirements will necessitate extensive
re-negotiations of long-term reservation
rights and arguing that the AAR
implementation timeline is not
sufficient to address challenges
associated with calculating hourly ATC
based on AARs, including development
of additional reliability tools and
ongoing maintenance of these tools by
additional skilled employees.853
Similarly, BPA asserts that the proposed
implementation period is too short
because it fails to account for the
different transmission provider service
territory sizes and for the complexity of
AAR implementation.854
356. However, according to OMS, the
deadlines seem to be reasonable and
necessary. OMS states that: MISO
Transmission Owners are already
working on implementing AARs; since
2016, MISO has had an Integrated
Roadmap item called ‘‘Application of
Forecasted and Real-time Ambient
Adjusted Ratings’’ ranked as a high
priority in MISO’s 2021 Integrated
Roadmap Work Plan; and, because
MISO Transmission Owners have begun
developing a framework to identify
candidate AAR facilities based on
historical congestion, they should have
already begun phase one compliance.855
Industrial Customer Organizations
similarly state that transmission owners
should begin AAR implementation now
and that, without strict deadlines, AAR
implementation before 2022 is
unlikely.856
357. RTOs/ISOs generally request
additional implementation time.857
CAISO claims that the compliance
schedule set forth in the NOPR is
neither realistic nor achievable because
the proposal for hourly updates to
transmission line ratings will require
additional market design changes and
significant technology enhancements.
For the implementation schedule,
CAISO requests an additional 18
months from the submission of a
compliance filing, explaining that
implementation will require technology
852 WAPA
Comments at 6.
Comments at 8–9.
854 BPA Comments at 6.
855 OMS Comments at 9.
856 Industrial Customer Organizations Comments
at 22.
857 CAISO Comments at 2; ISO–NE Comments at
8; SPP Comments at 10; MISO Comments at 30–32;
NYISO Comments at 16–18.
853 LADWP
E:\FR\FM\13JAR2.SGM
13JAR2
2300
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
enhancements necessary to automate
the submission and use of hourly
adjusted transmission line ratings.858
SPP contends that 60 days would be
insufficient time for SPP to complete its
stakeholder process to review any
proposed tariff language and notes that,
depending on the changes, the process
would take at least three months. For
implementation, SPP requests an
additional two years from the
submission of a compliance filing.859
ISO–NE explains that it will need to
upgrade its systems to accept hourly
transmission line ratings, and that it
does not believe one year would be
enough time to do so, but does not
propose a timeline.860 Additionally,
ISO–NE asks for sufficient time to
analyze how AARs would impact the
emergency ratings currently employed
and flexibility in implementation
timing, and states that an update to the
overall rating methodology to include
AARs may also necessitate the need for
new emergency ratings based on those
AARs.861 MISO states that it would be
able to implement the NOPR proposal in
the real-time market in a year, but states
that it would need until mid-2023 and
the end of 2024 to implement the NOPR
proposal in the day-ahead market and
Intra-day and Foreword Reliability
Assessment Commitment
respectively.862 NYISO requests
flexibility for each RTO/ISO to develop
its own implementation schedule,863
arguing that the AAR schedule proposed
is not enough time to develop the
significant changes to software and rules
needed,864 and stating that it could
incur significant risk and expense if it
is required to comply within the
proposed one to two years.865 PJM,
however, states that, while the NOPR
proposal will likely require some
additional system changes and data
validation to comply, it believes the
time proposed would be sufficient.866
358. Potomac Economics states that
clarification may be needed as to
whether the requirements for
automation are on the transmission line
rating submission process and use of
AARs or the entire transmission line
rating process. Potomac Economics
states that requiring full automation
may delay implementation and may not
jspears on DSK121TN23PROD with RULES2
858 CAISO
Comments at 2.
Comments at 10.
860 ISO–NE Comments at 8.
861 Id. at 11.
862 MISO Comments at 30–32.
863 NYISO Comments at 16.
864 Id. at 18.
865 Id. at 19.
866 PJM Comments at 8.
18:58 Jan 12, 2022
3. Commission Determination
360. Upon consideration of the
comments received, we modify the
compliance deadline proposed in the
NOPR. Instead of 60 days, we require
each transmission provider to submit a
compliance filing within 120 days of the
effective date of this final rule. We
clarify that this compliance deadline is
for transmission providers to revise
their OATTs to incorporate pro forma
OATT Attachment M. We agree with
EEI’s compliance recommendation 869
and find that 120 days will be sufficient
to allow for a robust stakeholder
evaluation and development of revised
tariff language to comply with the
requirements adopted in this final rule.
361. In addition, we modify the
proposed implementation schedule.
Instead of the proposed one-year/twoyear staggered implementation timeline
based on priority, we require that all
requirements adopted herein be
implemented no later than three years
from the compliance filing due date.
Three years is consistent with the
implementation schedule most
commonly suggested by transmission
owners for AAR implementation on
priority transmission lines.870 We find
that three years should be sufficient
time for transmission owners and
transmission providers to implement
changes to their processes and systems
to comply with the requirements
adopted in this final rule.
362. In response to comments about
automation from Potomac Economics,
we clarify that while we are not
adopting a specific automation
requirement, we nonetheless believe it
is likely that all or much of AAR
calculation processes will be automated.
However, nothing in this final rule
prevents an individual transmission
provider from implementing certain
portions of the pro forma OATT
Attachment M requirements manually,
867 Potomac
Economics Comments at 19.
Comments at 15.
869 EEI Comments at 19.
870 Id. at 18; NRECA/LPPC Comments at 28–29;
MISO Transmission Owners Comments at 22–23;
SCE Comments at 2; SDG&E Comments at 1–2; APS
Comments at 10; WFEC Comments at 1; Southern
Company Comments at 6–7; ITC Comments at 5;
LADWP Comments at 8–9.
859 SPP
VerDate Sep<11>2014
be appropriate for all transmission
owners.867
359. Finally, PJM requests clarity that
public utilities are able to demonstrate
compliance via the independent entity
variation standard, regional reliability
standard, or demonstrate that their
existing rules are consistent with or
superior to the reforms adopted by the
Commission.868
868 PJM
Jkt 256001
PO 00000
Frm 00058
Fmt 4701
Sfmt 4700
should it prefer manual implementation
and can satisfy the requirements of this
final rule.
363. Finally, some public utility
transmission providers may have
provisions in their existing pro forma
OATTs or other document(s) subject to
the Commission’s jurisdiction that the
Commission has deemed to be
consistent with or superior to the pro
forma OATT. Where these provisions
would be modified by this final rule,
transmission providers must either
comply with the requirements adopted
in this final rule or demonstrate that
these previously approved variations
continue to be consistent with or
superior to the pro forma OATT, as
modified by this final rule.871
V. Information Collection Statement
364. The information collection (IC)
requirements contained in this final rule
are subject to review by the Office of
Management and Budget (OMB) under
section 3507(d) of the Paperwork
Reduction Act of 1995.872 OMB’s
regulations require approval of certain
information collection requirements
imposed by agency rules.873
Respondents subject to the filing
requirements of this final rule will not
be penalized for failing to respond to
these collections of information unless
the collections of information display a
valid OMB control number.
365. This final rule, pursuant to
section 206 of the FPA, reforms the pro
forma OATT and the Commission’s
regulations to improve the accuracy and
transparency of electric transmission
line ratings used by transmission
providers. These provisions affect the
following collections of information:
FERC–516H, Pro Forma Open Access
Transmission Tariff (Control No. 1902–
0297); and FERC–725A, Mandatory
Reliability Standards for the Bulk-Power
System (Control No. 1902–0244).
366. In the NOPR, the Commission
solicited comments on the
Commission’s need for this information,
whether the information will have
practical utility, the accuracy of the
burden estimates, ways to enhance the
quality, utility, and clarity of the
information to be collected or retained,
and any suggested methods for
minimizing respondents’ burden,
including the use of automated
information techniques.
367. Summary of the Collection of
Information in the Final Rule:
FERC 516H: This final rule amends 18
CFR 35.28(c)(5) to require any public
871 See
18 CFR 35.28(c)(1)(vi).
U.S.C. 3507(d).
873 5 CFR 1320.11 (2021).
872 44
E:\FR\FM\13JAR2.SGM
13JAR2
2301
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
utility that owns transmission facilities
that are not under the public utility’s
control to, consistent with the pro forma
OATT required by 18 CFR 35.28(c)(1),
share with the public utility that
controls such facilities (and its Market
Monitoring Unit(s), if applicable):
(i) Transmission line ratings for each
period for which transmission line
ratings are calculated for such facilities
(with updated ratings shared each time
ratings are calculated); and
(ii) Written transmission line rating
methodologies used to calculate the
transmission line ratings for such
facilities provided under subparagraph
(i), above.
Section 35.28(g)(13) of this final rule
requires each RTO and ISO to establish
and maintain systems and procedures
necessary to allow any public utility
whose transmission facilities are under
the independent control of the ISO or
RTO to electronically update
transmission line ratings for such
facilities (for each period for which
transmission line ratings are calculated)
at least hourly, with such data
submitted by those public utility
transmission owners directly into the
ISO’s or RTO’s Energy Management
System through Supervisory Control
and Data Acquisition or related systems.
FERC–725A: Reliability Standard
FAC–008–5 is not being revised in this
proceeding. However, as shown in the
burden table below, the requirements of
this final rule under section 206 of the
FPA affect the burden for Requirements
2, 3, and 6 in Reliability Standard FAC–
008–5.
368. Title: Pro Forma Open Access
Transmission Tariff (FERC–516H) and
Mandatory Reliability Standards for the
Bulk-Power System (FERC–725A).
369. Action: Revision of collections of
information in accordance with Docket
No. RM20–16–000.
370. OMB Control Nos.: 1902–0297
(FERC–516H) and 1902–0244 (FERC–
725A).
371. Respondents: Transmission
owners, transmission service providers,
generator owners, and RTOs/ISOs.
372. Frequency of Information
Collection: One time and annually.
373. Necessity of Information: The
reforms to the pro forma OATT and the
Commission’s regulations will improve
the accuracy and transparency of
electric transmission line ratings used
by transmission providers.
374. Internal Review: The
Commission has reviewed the changes
and has determined that such changes
are necessary. These requirements
conform to the Commission’s need for
efficient information collection,
communication, and management
within the energy industry. The
Commission has specific, objective
support for the burden estimates
associated with the information
collection requirements.
375. Our estimates are based on the
NERC Compliance Registry as of
September 3, 2020, which indicates that
78 transmission service providers,874
797 generator owners,875 and 289
transmission owners are registered
within the United States and are subject
to this rulemaking.876 There are also six
RTOs/ISOs in the United States subject
to this rulemaking.
376. Public Reporting Burden: The
burden and cost estimates below are
based on the need for applicable entities
to revise documentation, already
required by the pro forma OATT and
the Commission’s regulations as well as
Reliability Standard FAC–008–5,
Facility Ratings.877
377. The Commission estimates that
the final rule will affect the burden 878
and cost of FERC–516H and FERC–725A
as follows:
CHANGES IN FINAL RULE IN DOCKET NO. RM20–16–000
A.
B.
C.
D.
E.
F.
Area of modification
Number of respondents
Annual
estimated
number of
responses per
respondent
Annual estimated
number of responses
(column B × column C)
Average burden hours &
cost 879 per response
Total estimated burden
hours & total
estimated cost
(column D × column E)
FERC–516H, Pro Forma Open Access Transmission Tariff (Control No. 1902–0297)
jspears on DSK121TN23PROD with RULES2
For point-to-point transmission service requests within ten days, use
AARs in determining ATC and
TTC. (One-Time Burden in Year
1).
Where network transmission service
is provided, use hourly AARs to
determine curtailment or redispatch of network transmission
service. (One-Time Burden in
Year 1).
Transmission Providers to implement uniquely determined emergency ratings (One-Time Burden
in Year 1).
Implement software and systems to
communicate the required transmission line ratings with relevant
parties. (One-Time Burden in
Year 1).
129 (TOs 880 not in RTOs/
ISOs 881).
1
129
1,440 hrs; $120,485 ......
185,760 hrs; $15,542,539.
160 (to account for those
TOs in RTOs/ISOs that
are not included in the
line above).
1
160
1,440 hrs; $120,485 ......
230,400 hrs; $19,277,568.
160 (to account for those
TOs in RTOs/ISOs that
are not included in the
line above).
78 (TSPs 882) ....................
1
160
360 hrs; $30,121 ...........
57,600 hrs; $4,819,392.
1
78
352 hrs; $29,452 ...........
27,456 hrs; $2,297,243.
874 The transmission service provider (TSP)
function is a NERC registration function which is
similar to the transmission provider that is
referenced in the pro forma OATT. The TSP
function is being used as a proxy to estimate the
number of transmission providers that are impacted
by this rulemaking.
875 Of the 797 generator owners listed in the
September 3, 2020 NERC Compliance Registry, the
Commission estimates that only 10% of all NERC
registered generator owners own facilities between
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
the step-up transformer and the point of
interconnection. For this reason, the Commission
estimates that only 80 generator owners are
affected.
876 The number of entities listed from the NERC
Compliance Registry reflects the omission of the
Texas RE registered entities.
877 The burden associated with Reliability
Standard FAC–008–5, approved by the Commission
under section 215 of the FPA, is included in the
OMB-approved inventory for FERC–725A.
PO 00000
Frm 00059
Fmt 4701
Sfmt 4700
Reliability Standard FAC–008–5 is not being
revised in this proceeding; however, the
requirements of this final rule under section 206 of
the FPA affect the burden for three requirements in
Reliability Standard FAC–008–5.
878 ‘‘Burden’’ is the total time, effort, or financial
resources expended by persons to generate,
maintain, retain, or disclose or provide information
to or for a Federal agency. For further explanation
of what is included in the information collection
burden, refer to 5 CFR 1320.3.
E:\FR\FM\13JAR2.SGM
13JAR2
2302
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
CHANGES IN FINAL RULE IN DOCKET NO. RM20–16–000—Continued
A.
B.
C.
D.
E.
F.
Area of modification
Number of respondents
Annual
estimated
number of
responses per
respondent
Annual estimated
number of responses
(column B × column C)
Average burden hours &
cost 879 per response
Total estimated burden
hours & total
estimated cost
(column D × column E)
RTOs/ISOs implement software with
the ability to accommodate AARs
in both the day-ahead and realtime markets on an hourly basis.
(One-Time Burden in Year 1).
RTOs/ISOs establish the systems
and procedures necessary to
allow transmission owners to update line ratings on an hourly
basis directly into an EMS. (OneTime Burden in Year 1).
Transmission owners update forecasts and ratings, and share
transmission line ratings and facility ratings methodologies w/transmission providers and, if applicable, RTOs/ISOs & market monitors (Year 1 and Ongoing).
Compliance Filings (One-Time Burden in Year 1).
6 (RTOs/ISOs) ..................
1
6
9,000 hrs; $753,030 ......
54,000 hrs; $4,518,180.
6 (RTOs/ISOs) ..................
1
6
1,056 hrs; $88,356 ........
6,336 hrs; $530,133.
289 (TOs) .........................
1
289
176 hrs; $14,726 ...........
50,864 hrs; $4,255,791.
295 (TOs and (RTOs/
ISOs).
1
295
160 hrs; $13,387 ...........
47,200 hrs; $3,949,224.
Net Subtotal for FERC–516H
(Year 1).
...........................................
........................
373
13,984 hrs; $1,170,041
429,216 hrs; $50,671,891.
Net Subtotal for FERC–516H
(Ongoing).
...........................................
........................
289
176 hrs; $14,726 ...........
50,864 hrs; $4,255,791.
FERC–725A, Mandatory Reliability Standards for the Bulk-Power System—Reliability Standard FAC–008–5
369 (TOs & GOs) 883 ........
1
369
40 hrs; $3,347 ...............
14,760 hrs; $1,234,969.
369 (TOs & GOs) .............
1
369
8 hrs; $669 ....................
2,952 hrs; $246,994.
Net Subtotal for FERC–725A
(Year 1).
...........................................
........................
369
48 hrs; $4,016 ...............
17,712 hrs; $1,481,963.
Net Subtotal for FERC–725A
(Ongoing).
...........................................
........................
369
8 hrs; $669 ....................
2,952 hrs; $246,994.
Review and update facility ratings
methodology, Requirements R2
and R3. (One-Time Burden in
Year 1).
Determine facility ratings consistent
with methodology, Requirement
R6. (Burden in Year 1 and Ongoing).
jspears on DSK121TN23PROD with RULES2
378. The Commission noted in the
NOPR that, for purposes of estimating
879 The hourly cost (for salary plus benefits) uses
the figures from the Bureau of Labor Statistics (BLS)
for three positions involved in the reporting and
recordkeeping requirements. These figures include
salary (based on BLS data for May 2019, https://
bls.gov/oes/current/naics2_22.htm) and benefits
(based on BLS data for December 2019; issued
March 19, 2020, https://www.bls.gov/news.release/
ecec.nr0.htm) and are Manager (Code 11–0000
$97.15/hour), Electrical Engineer (Code 17–2071
$70.19/hour), and File Clerk (Code 43–4071 $34.79/
hour). The hourly cost for the reporting
requirements ($83.67) is an average of the cost of
a manager and engineer. The hourly cost for
recordkeeping requirements uses the cost of a file
clerk.
880 Transmission Owners. While the AAR reforms
in the final rule apply to transmission providers,
the Commission computes an implementation
burden based on the number of transmission
owners because transmission owners typically
calculate transmission line ratings and are therefore
likely to be the entities that update computations
to determine the effect of changing ambient air
temperatures on transmission line ratings.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
burden in the NOPR, the Commission
conservatively estimated these values
based on the maximum number of
entities and burden. The Commission
noted that some entities may, for
example, already use AARs in their
existing operations, in which case the
actual burden associated with specific
reforms associated with the use of AARs
would be lower than the estimate. The
Commission added that, on the other
hand, changing approaches to facility
ratings may require extra testing and
training for some entities to ensure
reliable operations and gain familiarity
with the approach. In the NOPR, the
Commission explained that it estimated
881 Regional Transmission Organizations/
Independent System Operators.
882 Transmission Service Providers.
883 This number reflects 289 transmission owners
and 10% of the 797 generator owners (GOs)
estimated to own facilities between the step-up
transformer and the point of interconnection.
PO 00000
Frm 00060
Fmt 4701
Sfmt 4700
that the majority of the additional
burden associated with the NOPR
would occur in the first year, and that,
once established, the ongoing burden
would closely approach the existing
burden of operating the transmission
system. The Commission sought
comment on the estimates in the table
provided in the NOPR and the
assumptions described in the NOPR.
379. We have revised the table above
to reflect the additional burden
associated with the additional
requirements issued in this final rule
related to emergency ratings and
daytime and nighttime ratings.
380. We have also revised the table
based on comments provided by MISO.
MISO states that it estimates costs of
approximately $200,000 to implement
AARs for current hour transmission
service, and costs to implement
forecasted AARs in the forward markets
and for transmission service, such as in
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
the day-ahead market, between
$500,000 and $750,000.884 The
Commission has conservatively applied
this estimate to all of the RTOs/ISOs.
The Commission notes, however, that
this is a conservative maximum estimate
and that some RTOs/ISOs might have
pre-existing plans to upgrade software
in the coming years, which may
implement many of the same
functionalities necessitated by this final
rule that are captured in these RTO/ISO
cost estimates.
381. In this final rule, besides the
noted revisions, the Commission used
the numbers provided in the NOPR.
382. Interested persons may obtain
information on the reporting
requirements by contacting Ellen
Brown, Office of the Executive Director,
Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC
20426 via email (DataClearance@
ferc.gov) or telephone ((202) 502–8663).
VI. Environmental Analysis
383. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.885 We conclude that
neither an Environmental Assessment
nor an Environmental Impact Statement
is required for this final rule under
section 380.4(a)(15) of the Commission’s
regulations, which provides a
categorical exemption for approval of
actions under sections 205 and 206 of
the FPA relating to the filing of
schedules containing all rates and
charges for the transmission or sale of
electric energy subject to the
Commission’s jurisdiction, plus the
classification, practices, contracts, and
regulations that affect rates, charges,
classification, and services.886
jspears on DSK121TN23PROD with RULES2
VII. Regulatory Flexibility Act
384. The Regulatory Flexibility Act of
1980 887 generally requires a description
and analysis of proposed and final rules
that will have significant economic
impact on a substantial number of small
entities. The Small Business
Administration (SBA) sets the threshold
for what constitutes a small business.
The small business size standards are
provided in 13 CFR 121.201 (2021).
Under SBA’s size standards,888 RTOs/
ISOs, planning regions, and
884 MISO
Comments at 32.
885 Reguls. Implementing the Nat’l Envt’l Pol’y
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987),
FERC Stats. & Regs. Preambles 1986–1990 ¶ 30,783
(1987) (cross-referenced at 41 FERC ¶ 61,284).
886 18 CFR 380.4(a)(15) (2021).
887 5 U.S.C. 601–612.
888 13 CFR 121.201.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
transmission owners all fall under the
category of Electric Bulk Power
Transmission and Control (NAICS code
221121), with a size threshold of 500
employees (including the entity and its
associates).889
385. The six RTOs/ISOs (SPP, MISO,
PJM, ISO–NE, NYISO, and CAISO) each
employ more than 500 employees and
are not considered small.
386. We estimate that 337
transmission owners and six planning
authorities are also affected by this final
rule. Using the list of transmission
owners from the NERC Registry (dated
September 3, 2020), we estimate that
approximately 68% of those entities are
small entities.
387. We estimate that 80 generator
owners own facilities between the stepup transformer and the point of
interconnection. We estimate again that
68% of these are small entities.
388. We estimate that 78 transmission
service providers are affected by this
final rule. We estimate again that 68%
of these are small entities.
389. We estimate additional one-time
costs associated with this final rule (as
shown in the table above) of:
390. $854,773 for each RTO/ISO
(FERC–516H).
391. $178,719 for each transmission
owner (FERC–516H).
392. $3,347 for each transmission
owner (FERC–725A).
393. $13,387 for each affected
generator owner (FERC–516H).
394. $3,347 for each generator owner
(FERC–725A).
395. $29,452 for each transmission
service provider (FERC–516H).
396. Therefore, the estimated
additional one-time cost per entity
ranges from $16,734 to $854,773.
397. We estimate that the majority of
the additional burden associated with
this final rule occurs in the first year (as
shown in the table above), and that,
once established, the ongoing burden
will closely approach the existing
burden of operating the transmission
system.
398. According to SBA guidance, the
determination of significance of impact
‘‘should be seen as relative to the size
of the business, the size of the
competitor’s business, and the impact
the regulation has on larger
2303
competitors.’’ 890 We do not consider the
estimated cost to be a significant
economic impact. As a result, we certify
that this final rule will not have a
significant economic impact on a
substantial number of small entities.
VIII. Document Availability
399. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the internet through the
Commission’s Home Page (https://
www.ferc.gov). At this time, the
Commission has suspended access to
the Commission’s Public Reference
Room due to the President’s March 13,
2020 proclamation declaring a National
Emergency concerning the Novel
Coronavirus Disease (COVID–19).
400. From FERC’s Home Page on the
internet, this information is available on
eLibrary. The full text of this document
is available on eLibrary in PDF and
Microsoft Word format for viewing,
printing, and/or downloading. To access
this document in eLibrary, type the
docket number excluding the last three
digits of this document in the docket
number field.
401. User assistance is available for
eLibrary and the FERC’s website during
normal business hours from FERC
Online Support at (202) 502–6652 (toll
free at 1–866–208–3676) or email at
ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. Email the
Public Reference Room at
public.referenceroom@ferc.gov.
IX. Effective Date and Congressional
Notification
402. This final rule is effective 60
days from the later of the date Congress
receives the agency notice or the date
the rule is published in the Federal
Register. The Commission has
determined, with the concurrence of the
Administrator of the Office of
Information and Regulatory Affairs of
OMB, that this rule is a ‘‘major rule’’ as
defined in section 351 of the Small
Business Regulatory Enforcement
Fairness Act of 1996.
List of Subjects in 18 CFR Part 35
889 The
RFA definition of ‘‘small entity’’ refers to
the definition provided in the Small Business Act,
which defines a ‘‘small business concern’’ as a
business that is independently owned and operated
and that is not dominant in its field of operation.
The Small Business Administrations’ regulations at
13 CFR 121.201 define the threshold for a small
Electric Bulk Power Transmission and Control
entity (NAICS code 221121) to be 500 employees.
See 5 U.S.C. 601(3) (citing to Section 3 of the Small
Business Act, 15 U.S.C. 632).
PO 00000
Frm 00061
Fmt 4701
Sfmt 4700
Electric power rates, Electric utilities,
Reporting and recordkeeping
requirements.
890 U.S. Small Business Administration, A Guide
for Government Agencies How to Comply with the
Regulatory Flexibility Act, at 18 (May 2012), https://
www.sba.gov/sites/default/files/advocacy/rfaguide_
0512_0.pdf.
E:\FR\FM\13JAR2.SGM
13JAR2
2304
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
By the Commission. Commissioner Danly
is concurring with a separate statement
attached.
Commissioner Phillips is not participating.
Issued: December 16, 2021.
Debbie-Anne A. Reese,
Deputy Secretary.
In consideration of the foregoing, the
Commission amends part 35, chapter I,
Title 18, Code of Federal Regulations, as
follows:
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for part 35
continues to read as follows:
■
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
2. Amend § 35.28 by adding
paragraphs (b)(12) through (16), (c)(5),
and (g)(13) to read as follows:
■
§ 35.28 Non-discriminatory open access
transmission tariff.
*
*
*
*
*
(b) * * *
(12) Ambient-adjusted rating means a
transmission line rating that applies to
a time period of not greater than one
hour; reflects an up-to-date forecast of
ambient air temperature across the time
period to which the rating applies;
reflects the absence of solar heating
during nighttime periods where the
local sunrise/sunset times used to
determine daytime and nighttime
periods are updated at least monthly, if
not more frequently; and is calculated at
least each hour, if not more frequently.
ratings are calculated for such facilities
(with updated ratings shared each time
ratings are calculated); and
(ii) Written transmission line rating
methodologies used to calculate the
transmission line ratings for such
facilities provided under subparagraph
(i).
*
*
*
*
*
(g) * * *
(13) Transmission line ratings. (i)
Each Commission-approved
independent system operator or regional
transmission organization must
establish and maintain systems and
procedures necessary to allow any
public utility whose transmission
facilities are under the independent
control of the independent system
operator or regional transmission
organization to electronically update
transmission line ratings for such
facilities (for each period for which
transmission line ratings are calculated)
at least hourly, with such data
submitted by those public utility
transmission owners directly into the
independent system operator’s or
regional transmission organization’s
EMS through SCADA or related
systems.
(ii) [Reserved]
Note: The following appendix will not be
published in the Code of Federal Regulations.
Appendix A: Abbreviated Names of
Commenters
The following table contains the
abbreviated names of the commenters that
are used in this final rule.
Short name/acronym
Commenter
AEP ......................................................
ACORE .................................................
ACPA/SEIA ...........................................
APS ......................................................
BPA ......................................................
CAISO ..................................................
CAISO DMM .........................................
CEA ......................................................
Certain TDU .........................................
American Electric Power Company, Inc.
The American Council on Renewable Energy.
American Clean Power Association (ACPA) and the Solar Energy Industries Association (SEIA).
Arizona Public Service Company.
Bonneville Power Administration.
California Independent System Operator Corporation.
California Independent System Operator Corporation Department of Market Monitoring.
Canadian Electricity Association.
Certain Transmission Dependent Utilities consist of Alliant Energy Corporate Services, Inc. (Alliant Energy); Consumers Energy Company (Consumers Energy); and DTE Electric Company (DTE Electric).
Clean Energy Parties consist of the Natural Resources Defense Council, Sustainable FERC Project,
Conservation Law Foundation, Sierra Club, Western Resource Advocates, Western Grid Group,
Clean Grid Alliance, NW Energy Coalition, and Southern Environmental Law Center.
DC Energy, LLC.
Dominion Energy Services, Inc.
Duke Energy Corporation.
EDF Renewables, Inc.
Edison Electric Institute.
ENEL North America.
Entergy Services, LLC.
Electric Power Research Institute.
Electric Power Supply Association.
Eversource Energy Service Company.
Exelon Corporation.
Imperial Irrigation District.
Clean Energy Parties ...........................
jspears on DSK121TN23PROD with RULES2
(13) Emergency rating means a
transmission line rating that reflects
operation for a specified, finite period,
rather than reflecting continuous
operation. An emergency rating may
assume an acceptable loss of equipment
life or other physical or safety
limitations for the equipment involved.
(14) Dynamic line rating means a
transmission line rating that applies to
a time period of not greater than one
hour and reflects up-to-date forecasts of
inputs such as (but not limited to)
ambient air temperature, wind, solar
heating intensity, transmission line
tension, or transmission line sag.
(15) Energy Management System
(EMS) means a computer control system
used by electric utility dispatchers to
monitor the real-time performance of
the various elements of an electric
system and to dispatch, schedule, and/
or control generation and transmission
facilities.
(16) Supervisory Control and Data
Acquisition (SCADA) means a computer
system that allows an electric system
operator to remotely monitor and
control elements of an electric system.
(c) * * *
(5) Any public utility that owns
transmission facilities that are not under
the public utility’s control must,
consistent with the pro forma tariff
required by paragraph (c)(1) of this
section, share with the public utility
that controls such facilities (and its
Market Monitoring Unit(s), if
applicable):
(i) Transmission line ratings for each
period for which transmission line
DC Energy ............................................
Dominion ..............................................
Duke Energy .........................................
EDFR ....................................................
EEI ........................................................
ENEL ....................................................
Entergy .................................................
EPRI .....................................................
EPSA ....................................................
Eversource ...........................................
Exelon ...................................................
IID .........................................................
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
PO 00000
Frm 00062
Fmt 4701
Sfmt 4700
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
Short name/acronym
Commenter
Indicated PJM Transmission Owners ..
Indicated PJM Transmission Owners consist of: American Electric Power Service Corporation on behalf
of its affiliates, Appalachian Power Company, Indiana Michigan Power Company, Kentucky Power
Company, Kingsport Power Company, Ohio Power Company, Wheeling Power Company, AEP Appalachian Transmission Company, Inc., AEP Indiana Michigan Transmission Company, Inc., AEP Kentucky Transmission Company, Inc., AEP Ohio Transmission Company, Inc., and AEP West Virginia
Transmission Company, Inc. (collectively ‘‘AEP’’); Dominion Energy Services, Inc. on behalf of Virginia Electric and Power Company d/b/a Dominion Energy Virginia; Duke Energy Corporation on behalf of its affiliates Duke Energy Ohio, Inc., Duke Energy Kentucky, Inc., and Duke Energy Business
Services LLC; Exelon Corporation; FirstEnergy Service Company, on behalf of its affiliates American
Transmission Systems, Incorporated, Jersey Central Power & Light Company, MidAtlantic Interstate
Transmission LLC, West Penn Power Company, The Potomac Edison Company, Monongahela
Power Company, and Trans-Allegheny Interstate Line Company; PPL Electric Utilities Corporation;
and Rockland Electric Company.
Industrial Customer Organizations consists of: American Forest & Paper Association (AF&PA), Coalition
of MISO Transmission Customers (CMTC), Electricity Consumers Resource Council (ELCON), Industrial Energy Consumers of America (IECA), and the PJM Industrial Customer Coalition (PJMICC).
ISO New England Inc.
International Transmission Company d/b/a ITC Transmission, Michigan Electric Transmission Company,
LLC, ITC Midwest LLC, and ITC Great Plains, LLC.
Los Angeles Department of Water and Power.
LineVision, Inc.
Midcontinent Independent System Operator, Inc.
MISO Transmission Owners consist of: Ameren Services Company, as agent for Union Electric Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois, and Ameren Transmission Company of Illinois; American Transmission Company LLC; Big Rivers Electric Corporation;
Central Minnesota Municipal Power Agency; City Water, Light & Power (Springfield, IL); Cleco Power
LLC; Cooperative Energy; Dairyland Power Cooperative; Duke Energy Business Services, LLC for
Duke Energy Indiana, LLC; East Texas Electric Cooperative; Great River Energy; Hoosier Energy
Rural Electric Cooperative, Inc.; Indiana Municipal Power Agency; Indianapolis Power & Light Company; International Transmission Company d/b/a ITC Transmission; ITC Midwest LLC; Lafayette Utilities System; Michigan Electric Transmission Company, LLC; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; MontanaDakota Utilities Co.; Northern Indiana Public Service Company LLC; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company;
Prairie Power Inc.; Southern Illinois Power Cooperative; Southern Indiana Gas & Electric Company
(d/b/a Vectren Energy Delivery of Indiana); Southern Minnesota Municipal Power Agency; Wabash
Valley Power Association, Inc.; and Wolverine Power Supply Cooperative, Inc.
North American Electric Reliability Corporation.
New England State Agencies consist of: Connecticut Attorney General William Tong; Massachusetts
Attorney General Maura Healey; the Connecticut Department of Energy and Environmental Protection; the Connecticut Office of Consumer Counsel; the Maine Office of the Public Advocate; the New
Hampshire Consumer Advocate; Peter F. Neronha, Rhode Island Attorney General; and Thomas J.
Donovan, Jr., Attorney General of Vermont.
National Rural Electric Cooperative Association (NRECA) and the Large Public Power Council (LPPC).
New York Independent System Operator, Inc.
The New York Transmission Owners consist of: Central Hudson Gas & Electric Corporation (Central
Hudson); Consolidated Edison Company of New York, Inc. (Consolidated Edison); Niagara Mohawk
Power Corporation d/b/a National Grid (National Grid); New York Power Authority (NYPA); New York
State Electric & Gas Corporation (NYSEG); Orange and Rockland Utilities, Inc. (O&R); Long Island
Power Authority (LIPA); and Rochester Gas and Electric Corporation (RG&E).
Public Utilities Commission of Ohio’s Office of the Ohio Federal Energy Advocate.
Organization of MISO States.
PacifiCorp.
Pacific Gas and Electric Company.
PJM Interconnection, L.L.C.
Potomac Economics, LTD.
The Prysmian Group.
R Street Institute.
Southern California Edison Company.
San Diego Gas & Electric Company.
Solar Energy Industries Association.
Southern Company Services, Inc.
Southwest Power Pool, Inc.
Sunflower Electric Power Corporation.
Tangibl Group, Inc.
Transmission Access Policy Study Group.
Utah Division of Public Utilities.
Vistra Corp.
Western Area Power Administration.
Working for Advanced Transmission Technologies.
Western Farmers Electric Cooperative.
Industrial Customer Organizations .......
ISO–NE ................................................
ITC ........................................................
LADWP .................................................
LineVision .............................................
MISO ....................................................
MISO Transmission Owners ................
NERC ...................................................
New England State Agencies ..............
NRECA/LPPC .......................................
NYISO ..................................................
NYTOs ..................................................
jspears on DSK121TN23PROD with RULES2
2305
Ohio FEA ..............................................
OMS .....................................................
PacifiCorp .............................................
PG&E ....................................................
PJM ......................................................
Potomac Economics .............................
Prysmian ...............................................
R Street Institute ..................................
SCE ......................................................
SDG&E .................................................
Southern Company ..............................
SPP ......................................................
SPP MMU .............................................
Sunflower ..............................................
Tangibl ..................................................
TAPS ....................................................
UDPU ...................................................
Vistra ....................................................
WAPA ...................................................
WATT ...................................................
WFEC ...................................................
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
PO 00000
Frm 00063
Fmt 4701
Sfmt 4700
E:\FR\FM\13JAR2.SGM
13JAR2
2306
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
Appendix B: Pro Forma Open Access
Transmission Tariff
ATTACHMENT M
Transmission Line Ratings
jspears on DSK121TN23PROD with RULES2
General
The Transmission Provider will implement
Transmission Line Ratings on the
transmission lines over which it provides
Transmission Service, as provided below.
Definitions
The following definitions apply for
purposes of this Attachment:
(1) ‘‘Transmission Line Rating’’ means the
maximum transfer capability of a
transmission line, computed in accordance
with a written Transmission Line Rating
methodology and consistent with Good
Utility Practice, considering the technical
limitations on conductors and relevant
transmission equipment (such as thermal
flow limits), as well as technical limitations
of the Transmission System (such as system
voltage and stability limits). Relevant
transmission equipment may include, but is
not limited to, circuit breakers, line traps,
and transformers.
(2) ‘‘Ambient-Adjusted Rating’’ (AAR)
means a Transmission Line Rating that:
(a) Applies to a time period of not greater
than one hour.
(b) Reflects an up-to-date forecast of
ambient air temperature across the time
period to which the rating applies.
(c) Reflects the absence of solar heating
during nighttime periods, where the local
sunrise/sunset times used to determine
daytime and nighttime periods are updated at
least monthly, if not more frequently.
(d) Is calculated at least each hour, if not
more frequently.
(3) ‘‘Seasonal Line Rating’’ means a
Transmission Line Rating that:
(a) Applies to a specified season, where
seasons are defined by the Transmission
Provider to include not fewer than four
seasons in each year, and to reasonably
reflect portions of the year where expected
high temperatures are relatively consistent.
(b) Reflects an up-to-date forecast of
ambient air temperature across the relevant
season over which the rating applies.
(c) Is calculated annually, if not more
frequently, for each season in the future for
which Transmission Service can be
requested.
(4) ‘‘Near-Term Transmission Service’’
means Transmission Service which ends not
more than 10 days after the Transmission
Service request date. When the description of
obligations below refers to either a request for
information about the availability of potential
Transmission Service (including, but not
limited to, a request for ATC), or to the
posting of ATC or other information related
to potential service, the date that the
information is requested or posted will serve
as the Transmission Service request date.
‘‘Near-Term Transmission Service’’ includes
any Point-To-Point Transmission Service,
Network Resource designations, or secondary
service where the start and end date of the
designation or request is within the next 10
days.
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
(5) ‘‘Emergency Rating’’ means a
Transmission Line Rating that reflects
operation for a specified, finite period, rather
than reflecting continuous operation. An
Emergency Rating may assume an acceptable
loss of equipment life or other physical or
safety limitations for the equipment
involved.
System Reliability
If the Transmission Provider reasonably
determines, consistent with Good Utility
Practice, that the temporary use of a
Transmission Line Rating different than
would otherwise be required by this
Attachment is necessary to ensure the safety
and reliability of the Transmission System,
then the Transmission Provider may use such
an alternate rating. The Transmission
Provider must document in its database of
Transmission Line Ratings and Transmission
Line Rating methodologies on OASIS or
another password-protected website, as
required by this Attachment, the use of an
alternate Transmission Line Rating under
this paragraph, including the nature of and
basis for the alternate rating, the date and
time that the alternate rating was initiated,
and (if applicable) the date and time that the
alternate rating was withdrawn and the
standard rating became effective again.
Obligations of Transmission Provider
The Transmission Provider will have the
following obligations.
The Transmission Provider must use AARs
as the relevant Transmission Line Ratings
when performing any of the following
functions: (1) Evaluating requests for NearTerm Transmission Service; (2) responding to
requests for information on the availability of
potential Near-Term Transmission Service
(including requests for ATC or other
information related to potential service); or
(3) posting ATC or other information related
to Near-Term Transmission Service to the
Transmission Provider’s OASIS site or
another password-protected website.
The Transmission Provider must use AARs
as the relevant Transmission Line Ratings
when determining whether to curtail (under
section 13.6) Firm Point-To-Point
Transmission Service or when determining
whether to curtail and/or interrupt (under
section 14.7) Non-Firm Point-To-Point
Transmission Service if such curtailment
and/or interruption is both necessary because
of issues related to flow limits on
transmission lines and anticipated to occur
(start and end) within 10 days of such
determination. For determining whether to
curtail or interrupt Point-To-Point
Transmission Service in other situations, the
Transmission Provider must use Seasonal
Line Ratings as the relevant Transmission
Line Ratings.
The Transmission Provider must use AARs
as the relevant Transmission Line Ratings
when determining whether to curtail (under
section 33) or redispatch (under sections 30.5
and/or 33) Network Integration Transmission
Service or secondary service if such
curtailment or redispatch is both necessary
because of issues related to flow limits on
transmission lines and anticipated to occur
(start and end) within 10 days of such
PO 00000
Frm 00064
Fmt 4701
Sfmt 4700
determination. For determining the necessity
of curtailment or redispatch of Network
Integration Transmission Service or
secondary service in other situations, the
Transmission Provider must use Seasonal
Line Ratings as the relevant Transmission
Line Ratings.
The Transmission Provider must use
Seasonal Line Ratings as the relevant
Transmission Line Ratings when evaluating
requests for and whether to curtail, interrupt,
or redispatch any Transmission Service not
otherwise covered above in this section
(including, but not limited to, requests for
non-Near-Term Transmission Service or
requests to designate or change the
designation of Network Resources or
Network Load), when developing any ATC or
other information posted or provided to
potential customers related to such services.
The Transmission Provider must use
Seasonal Line Ratings as a recourse rating in
the event that an AAR otherwise required to
be used under this Attachment is
unavailable.
The Transmission Provider must use
uniquely determined Emergency Ratings for
contingency analysis in the operations
horizon and in post-contingency simulations
of constraints. Such uniquely determined
Emergency Ratings must also include
separate AAR calculations for each
Emergency Rating duration used.
In developing forecasts of ambient air
temperature for AARs and Seasonal Line
Ratings, the Transmission Provider must
develop such forecasts consistent with Good
Utility Practice and on a non-discriminatory
basis.
Postings to OASIS or another passwordprotected website: The Transmission
Provider must maintain on the passwordprotected section of its OASIS page or on
another password-protected website a
database of Transmission Line Ratings and
Transmission Line Rating methodologies.
The database must include a full record of all
Transmission Line Ratings, both as used in
real-time operations, and as used for all
future periods for which Transmission
Service is offered. Any postings of temporary
alternate Transmission Line Ratings or
exceptions used under the System Reliability
section above or the Exceptions section
below, respectively, are considered part of
the database. The database must include
records of which Transmission Line Ratings
and Transmission Line Rating methodologies
were in effect at which times over at least the
previous five years, including records of
which temporary alternate Transmission Line
Ratings or exceptions were in effect at which
times during the previous five years. Each
record in the database must indicate which
transmission line the record applies to, and
the date and time the record was entered into
the database. The database must be
maintained such that users can view,
download, and query data in standard
formats, using standard protocols.
Sharing with Transmission Providers: The
Transmission Provider must share, upon
request by any Transmission Provider and in
a timely manner, the following information:
(1) Transmission Line Ratings for each
period for which Transmission Line Ratings
E:\FR\FM\13JAR2.SGM
13JAR2
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 / Rules and Regulations
jspears on DSK121TN23PROD with RULES2
are calculated, with updated ratings shared
each time Transmission Line Ratings are
calculated, and
(2) Written Transmission Line Rating
methodologies used to calculate the
Transmission Line Ratings in (1) above.
Exceptions: Where the Transmission
Provider determines, consistent with Good
Utility Practice, that the Transmission Line
Rating of a transmission line is not affected
by ambient air temperature or solar heating,
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 temperature or solar heating; 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 temperature or solar heating. The
Transmission Provider must document in its
database of Transmission Line Ratings and
Transmission Line Rating methodologies on
OASIS or another password-protected
website any exceptions to the requirements
contained in this Attachment initiated under
this paragraph, including the nature of and
basis for each exception, the date(s) and
time(s) that the exception was initiated, and
(if applicable) the date(s) and time(s) that
each exception was withdrawn and the
standard rating became effective again. If the
VerDate Sep<11>2014
18:58 Jan 12, 2022
Jkt 256001
technical basis for an exception under this
paragraph changes, then the Transmission
Provider must update the relevant
Transmission Line Rating(s) in a timely
manner. The Transmission Provider must
reevaluate any exceptions taken under this
paragraph at least every five years.
FEDERAL ENERGY REGULATORY
COMMISSION
Managing Transmission Line Ratings
Docket No. RM20–16–000
(Issued December 16, 2021)
DANLY, Commissioner, concurring:
1. I concur with the issuance of this final
rule because I agree that the record in this
proceeding supports a finding that current
transmission rates are unjust and
unreasonable because line rating information
is often inaccurate.1 The rates customers pay
to support transmission are distorted because
the ratings that purport to represent the true
operating characteristics of the transmission
system are distorted. The voluminous record
evidence in this proceeding is sufficient to
support a Federal Power Act section 206
action to remedy unjust and unreasonable
rates.2 The record also is sufficient to support
the replacement rates we order in this rule.
2. Of course, we cannot act pursuant to
section 206 without substantial record
evidence that the existing rate is unjust and
unreasonable and further record support for
1 Managing
Transmission Line Ratings, 177 FERC
¶ 61,179 at P 29 (2021).
2 16 U.S.C. 824e.
PO 00000
Frm 00065
Fmt 4701
Sfmt 9990
2307
a replacement rate. We cannot impose a
requirement for dynamic line ratings, for
example, because we do not have the record
support to do so at this time.3 Action cannot
be taken under section 206 merely because a
potential reform is a good idea or because a
contemplated policy might yield greater
efficiencies.
3. Here, I am persuaded that we have
sufficient record evidence to require ambientadjusted ratings (AAR) on all transmission
lines because the record shows the existing
paradigm significantly distorts efficient use
of the transmission system.4 In addition,
AAR is a just and reasonable replacement
rate because the record evidence shows the
additional costs are incremental and will
provide significant benefits.
4. In this case, the requirements of both
steps of section 206 have been satisfied. As
a Commission, we must ensure that every
action taken under section 206 fully meets
these burdens and I will apply the same
rigorous analysis to every future section 206
proposal to improve the transmission system.
For these reasons, I respectfully concur.
James P. Danly,
Commissioner.
[FR Doc. 2021–27735 Filed 1–12–22; 8:45 am]
BILLING CODE 6717–01–P
3 See Managing Transmission Line Ratings, 177
FERC ¶ 61,179 at P 36 (declining to require dynamic
line ratings).
4 Id. at P 83.
E:\FR\FM\13JAR2.SGM
13JAR2
Agencies
[Federal Register Volume 87, Number 9 (Thursday, January 13, 2022)]
[Rules and Regulations]
[Pages 2244-2307]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-27735]
[[Page 2243]]
Vol. 87
Thursday,
No. 9
January 13, 2022
Part II
Department of Energy
-----------------------------------------------------------------------
Federal Energy Regulatory Commission
-----------------------------------------------------------------------
18 CFR Part 35
Managing Transmission Line Ratings; Final Rule
Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 /
Rules and Regulations
[[Page 2244]]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM20-16-000; Order No. 881]
Managing Transmission Line Ratings
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Federal Energy Regulatory Commission (Commission) is
revising both the pro forma Open Access Transmission Tariff and the
Commission's regulations under the Federal Power Act to improve the
accuracy and transparency of electric transmission line ratings.
Specifically, the Commission is requiring: Public utility transmission
providers to implement ambient-adjusted ratings on the transmission
lines over which they provide transmission service; regional
transmission organizations (RTO) and independent system operators (ISO)
to establish and implement the systems and procedures necessary to
allow transmission owners to electronically update transmission line
ratings at least hourly; public utility transmission providers to use
uniquely determined emergency ratings; public utility transmission
owners to share transmission line ratings and transmission line rating
methodologies with their respective transmission provider(s) and with
market monitors in RTOs/ISOs; and public utility transmission providers
to maintain a database of transmission owners' transmission line
ratings and transmission line rating methodologies on the transmission
provider's Open Access Same-Time Information System site or other
password-protected website.
DATES: This rule will become effective March 14, 2022.
FOR FURTHER INFORMATION CONTACT: Dillon Kolkmann (Technical
Information), Office of Energy Policy and Innovation, Federal Energy
Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202)
502-8650, [email protected].
Mark Armamentos (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-8103, [email protected].
Ryan Stroschein (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, (202) 502-8099, [email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph Numbers
I. Introduction 1
II. Background 13
III. Need for Reform 17
A. NOPR Proposal 17
B. Comments 23
C. Commission Determination 29
IV. Discussion 40
A. Transmission Line Ratings Definition 40
1. NOPR Proposal 40
2. Comments 42
3. Commission Determination 44
B. Ambient-Adjusted Ratings 47
1. AAR Definition and Transmission Provider Obligations 47
2. Specific AAR Implementation Requirements 104
3. Other AAR Implementation Issues 151
C. Seasonal Line Ratings 193
1. Seasonal Line Ratings Requirements 193
2. Seasonal Line Rating Implementation Requirements 204
D. Exceptions and Alternate Ratings 217
1. NOPR Proposal 217
2. Comments 219
3. Commission Determination 227
E. Dynamic Line Ratings 235
1. Dynamic Line Ratings Definition 235
2. DLR Requirements 240
3. Extending to non-RTO/ISO Transmission Providers the
Requirement To Allow Transmission Owners To Electronically Update
Transmission Line Ratings at Least Hourly 256
4. DLR Studies 259
5. Advanced Transmission Technology Cost Recovery 265
F. Emergency Ratings 267
1. NOPR Request for Comments 267
2. Emergency Ratings Definition and Implementation Requirements
269
3. Equipment for Which Emergency Ratings Must Be Calculated 304
G. Transparency 306
1. NOPR Proposal 306
2. Comments 309
3. Commission Determination 330
H. Other Miscellaneous Issues 344
1. Comments 344
2. Commission Determination 346
I. Compliance 348
1. NOPR Proposal 348
2. Comments 351
3. Commission Determination 360
V. Information Collection Statement 364
VI. Environmental Analysis 383
VII. Regulatory Flexibility Act 384
VIII. Document Availability 399
IX. Effective Date and Congressional Notification 402
Appendix A: Abbreviated Names of Commenters
Appendix B: Pro Forma Open Access Transmission Tariff
I. Introduction
1. In this final rule, the Federal Energy Regulatory Commission
(Commission) is adopting reforms, pursuant to section 206 of the
Federal Power Act (FPA),\1\ to the pro forma Open Access Transmission
Tariff (OATT) and the Commission's regulations to improve the accuracy
and transparency of electric transmission line ratings used by
transmission providers.\2\ As discussed below, we adopt the
Commission's proposal in the Notice of Proposed Rulemaking (NOPR) to
define a transmission line rating as ``the maximum transfer capability
of a transmission line, computed in accordance with a written
transmission line rating methodology and consistent with Good Utility
Practice,\3\ considering the technical limitations on conductors and
relevant transmission equipment (such as thermal flow limits), as well
as technical limitations of the Transmission System (such as system
voltage and stability limits).'' \4\
---------------------------------------------------------------------------
\1\ 16 U.S.C. 824e.
\2\ In this final rule, we use transmission provider to mean any
public utility that owns, operates, or controls facilities used for
the transmission of electric energy in interstate commerce. 18 CFR
37.3 (2021). Therefore, unless otherwise noted, ``transmission
provider'' refers only to public utility transmission providers.
Furthermore, the term ``public utility'' as found in section 201(e)
of the FPA means ``any person who owns or operates facilities
subject to the jurisdiction of the Commission under this subchapter
. . .'' 16 U.S.C. 824(e).
\3\ The Commission's pro forma OATT defines Good Utility
Practice as: ``[a]ny of the practices, methods and acts engaged in
or approved by a significant portion of the electric utility
industry during the relevant time period, or any of the practices,
methods and acts which, in the exercise of reasonable judgment in
light of the facts known at the time the decision was made, could
have been expected to accomplish the desired result at a reasonable
cost consistent with good business practices, reliability, safety
and expedition. Good Utility Practice is not intended to be limited
to the optimum practice, method, or act to the exclusion of all
others, but rather to be acceptable practices, methods, or acts
generally accepted in the region, including those practices required
by Federal Power Act section 215(a)(4).'' Pro forma OATT section
1.15.
\4\ The definition also states, ``Relevant transmission
equipment may include, but is not limited to, circuit breakers, line
traps, and transformers.'' Managing Transmission Line Ratings,
Notice of Proposed Rulemaking, 86 FR 6420 (Jan. 21, 2021), 173 FERC
] 61,165, at P 85 (2020) (NOPR).
---------------------------------------------------------------------------
2. The transfer capability of a transmission line can change with
ambient weather conditions. Thus, a transmission line rating can be
determined by taking into consideration the physical characteristics of
the conductor and making assumptions about ambient weather conditions
to determine the maximum amount of power that can flow through a
conductor while keeping the conductor under its maximum operating
temperature. Conductor temperatures are impacted by a variety of
factors,
[[Page 2245]]
including ambient air temperatures. Increases in ambient air
temperatures tend to increase a transmission line's operating
temperature and lower a transmission line's rating, while lower ambient
air temperatures tend to lower a transmission line's operating
temperature and increase the transmission line's rating.
3. Many transmission line ratings are currently calculated based on
assumptions about ambient conditions that are not regularly adjusted
and therefore do not accurately reflect the near-term transfer
capability of the transmission system.\5\ For example, when seasonal or
static temperature assumptions exceed actual ambient air temperatures,
transmission line ratings may understate the near-term transfer
capability that the transmission system can actually provide, leading
to unnecessarily restricted flows and potentially increased congestion
costs. Alternatively, when ambient air temperatures exceed seasonal or
static temperature assumptions, transmission line ratings may overstate
the near-term transfer capability of the system, creating potential
reliability and safety problems. In either case, the continued use of
seasonal and static temperature assumptions may result in transmission
line ratings that do not accurately represent the transfer capability
of the transmission system. We find that transmission line ratings and
the rules by which they are established are practices that directly
affect the cost of wholesale energy, capacity, and ancillary services,
as well as the cost of delivering wholesale energy to transmission
customers; thus, we find that inaccurate transmission line ratings
result in Commission-jurisdictional rates that are unjust and
unreasonable.
---------------------------------------------------------------------------
\5\ Federal Energy Regulatory Commission, Staff Paper, Managing
Transmission Line Ratings, Docket No. AD19-15-000 (Aug. 2019)
(Commission Staff Paper), https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.
---------------------------------------------------------------------------
4. To address these issues with respect to transmission service in
the near term, we adopt, with certain modifications, the NOPR
proposal's definition of an ambient-adjusted rating (AAR) as a
transmission line rating that: (1) Applies to a time period of not
greater than one hour; (2) reflects an up-to-date forecast of ambient
air temperature across the time period to which the rating applies; (3)
reflects the absence of solar heating during nighttime periods where
the local sunrise/sunset times used to determine daytime and nighttime
periods are updated at least monthly, if not more frequently; and (4)
is calculated at least each hour, if not more frequently.\6\
Additionally, we adopt two requirements for greater use of AARs. First,
we require that transmission providers--including RTOs/ISOs for
transmission service at their seams \7\--use AARs as the basis for
evaluation of transmission service requests that will end within 10
days of the request. Second, we require that transmission providers--
including RTOs/ISOs for transmission service at their seams--use AARs
as the basis for their determination of the necessity of certain
curtailment, interruption, or redispatch of transmission service
anticipated to occur within those 10 days.
---------------------------------------------------------------------------
\6\ 18 CFR 35.28(b)(10) (2021); Pro Forma OATT attach. M, AAR
Definition.
\7\ The term ``seam'' is commonly used by the industry to
indicate the border between two transmission provider's service
territories. Service at the seam can take different forms, such as
point-to-point service or market-to-market service.
---------------------------------------------------------------------------
5. To address these issues with respect to transmission service in
the longer term, we require that transmission providers use seasonal
line ratings as the basis for evaluation of transmission service
requests ending more than 10 days from the date of the request. We also
require that transmission providers use seasonal line ratings as the
basis for the determination of the necessity of curtailment,
interruption, or redispatch of transmission service that is anticipated
to occur more than 10 days in the future.\8\
---------------------------------------------------------------------------
\8\ The use of seasonal line ratings for long-term requests for
transmission service and as the basis for the determination of
curtailment, interruption, or redispatch is currently standard
practice. However, as discussed below, we adopt certain reforms to
change seasonal line rating implementation.
---------------------------------------------------------------------------
6. For both longer term and shorter term transmission service, we
adopt exceptions to the AAR and seasonal line rating requirements to
accommodate instances in which the transmission line rating of a
transmission line is not affected by ambient air temperature and
instances in which a transmission provider reasonably determines,
consistent with good utility practice, that the use of a temporary
alternate rating is necessary to ensure the safety and reliability of
the transmission system.\9\
---------------------------------------------------------------------------
\9\ Because the new requirements related to AARs and seasonal
line ratings are implemented through the new pro forma OATT
Attachment M, these requirements are placed upon transmission
providers. However, we recognize that transmission owners (not
transmission providers) determine transmission line ratings. In many
instances, the transmission provider and transmission owner are the
same entity. However, below in Section IV.B.2.b, we discuss
compliance within RTOs/ISOs, where the transmission provider and
transmission owner are separate entities.
---------------------------------------------------------------------------
7. In certain situations, using transmission line ratings that are
based on factors beyond forecasted ambient air temperatures and the
presence or absence of solar heating may lead to greater accuracy. For
example, the use of dynamic line ratings (DLRs) presents opportunities
for transmission line ratings that may be more accurate than those
established with AARs. Unlike AARs, DLRs are based not only on
forecasted ambient air temperatures and the presence or absence of
solar heating, but also on other weather conditions such as (but not
limited to) wind, cloud cover, solar heating intensity (instead of mere
daytime/nighttime distinctions used in AARs), and precipitation, and/or
on transmission line conditions such as tension or sag. As discussed
below, we adopt the NOPR's proposed definition of DLR as a transmission
line rating that: (1) Applies to a time period of not greater than one
hour; and (2) reflects up-to-date forecasts of inputs such as (but not
limited to) ambient air temperature, wind, solar heating intensity,
transmission line tension, or transmission line sag.
8. Although some transmission owners have adopted the use of DLRs
for individual transmission lines, there is not currently widespread
use of DLRs. While DLRs can represent more accurate transmission line
ratings than AARs, based on the record in this proceeding, we decline
to mandate DLR implementation in this final rule. We instead
incorporate the record in this proceeding on DLRs into new Docket No.
AD22-5-000, which we open to further explore DLR implementation.
9. One factor that may contribute to the limited deployment of DLRs
by transmission owners is that the RTOs/ISOs that operate a large
portion of the transmission system in the United States and oversee
organized wholesale electric markets may not be able to automatically
incorporate frequently updated transmission line ratings such as DLRs
into their operating and market models. Although the record does not
support a mandate for DLR implementation at this time, we require RTOs/
ISOs to establish and maintain the systems and procedures necessary to
allow transmission owners in their regions to electronically update
transmission line ratings on at least an hourly basis.
10. In addition to reforms to improve the accuracy of transmission
line ratings used during normal (pre-contingency) operations,\10\ we
revise the pro forma
[[Page 2246]]
OATT to require transmission providers to use uniquely determined
emergency ratings for contingency analysis in the operations horizon
and in post-contingency simulations of constraints.\11\ Such uniquely
determined emergency ratings must also incorporate an adjustment for
ambient air temperature and daytime/nighttime solar heating, consistent
with our AAR requirements for normal ratings. Most transmission
equipment can withstand high currents for short periods of time without
sustaining damage. Emergency ratings reflect this technical capability,
defining the specific additional current that a transmission line can
withstand and for what duration the transmission line can withstand
that additional current without sustaining damage. Because emergency
ratings reflect this capability, uniquely determined emergency ratings
will ensure more accurate transmission line ratings.
---------------------------------------------------------------------------
\10\ The North American Electric Reliability Corporation (NERC)
Glossary defines ``normal rating'' as: ``[t]he rating as defined by
the equipment owner that specifies the level of electrical loading .
. . that a system, facility, or element can support or withstand
through the daily demand cycles without loss of equipment life.''
NERC, Glossary of Terms Used in NERC Reliability Standards (June 28,
2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\11\ As discussed below in Section IV.F.2.b, uniquely determined
means the ratings are determined based on assumptions that reflect
the specific, finite duration of emergency ratings, as opposed to
using assumptions used to calculate normal ratings.
---------------------------------------------------------------------------
11. Finally, we adopt four requirements to enhance transparency.
First, we require public utility transmission owners to share
transmission line ratings and methodologies with their transmission
provider(s) and with market monitors in RTOs/ISOs. Second, we require
transmission providers to share their transmission owners' transmission
line ratings and methodologies with any transmission provider(s) upon
request. Third, we require transmission providers to maintain a
database of their transmission owners' transmission line ratings and
methodologies on the transmission provider's Open Access Same-Time
Information System (OASIS) site or another password-protected website.
Fourth, we require transmission providers to post on OASIS or another
password-protected website any uses of exceptions or temporary
alternate ratings. Availability of this additional information on
transmission line ratings and their methodologies will facilitate more
cost-effective decisions by transmission customers and more accurate
transmission line ratings. We find that these transparency reforms will
ensure that prices reflect the true cost of the wholesale service being
provided and thereby are necessary to ensure just and reasonable
wholesale rates.
12. We require each transmission provider to submit a compliance
filing within 120 days of the effective date of this final rule
revising their OATT to incorporate pro forma OATT Attachment M. We
further require that all requirements adopted herein be fully
implemented no later than three years from the compliance filing due
date.
II. Background
13. In August 2019, Commission staff issued a paper entitled
``Managing Transmission Line Ratings,'' which drew upon Commission
staff outreach conducted in spring 2019 with RTOs/ISOs, transmission
owners, and trade groups, as well as staff participation in a November
2017 Idaho National Laboratory workshop. The report included background
on common transmission line rating approaches, current practices in
RTOs/ISOs, a review of pilot projects, and a discussion of potential
improvements.\12\
---------------------------------------------------------------------------
\12\ Commission Staff Paper, https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.
---------------------------------------------------------------------------
14. On September 10 and 11, 2019, Commission staff convened a
technical conference (September 2019 Technical Conference) to discuss
what transmission line ratings and related practices might constitute
best practices, and what, if any, Commission action in these areas
might be appropriate. In particular, the September 2019 Technical
Conference covered issues such as: (1) Common transmission line rating
methodologies; (2) AAR and DLR implementation benefits and challenges;
(3) the ability of RTOs/ISOs to accept and use DLRs; and (4) the
transparency of transmission line rating methodologies.\13\
---------------------------------------------------------------------------
\13\ Supplemental Notice of Technical Conference, Docket No.
AD19-15-000 (Sep. 4, 2019).
---------------------------------------------------------------------------
15. In October 2019, the Commission requested comments on questions
that arose from the September 2019 Technical Conference.\14\ In
response, commenters addressed issues related to AARs and DLRs,
emergency ratings, and transparency, as discussed below.
---------------------------------------------------------------------------
\14\ Notice Inviting Post-Technical Conference Comments, Docket
No. AD19-15-000 (Oct. 2, 2019).
---------------------------------------------------------------------------
16. On November 19, 2020, the Commission issued the NOPR in this
proceeding, proposing to amend the pro forma OATT and its regulations
under the FPA to improve the accuracy and transparency of transmission
line ratings.\15\ Specifically, the Commission proposed a new pro forma
OATT Attachment M ``Transmission Line Ratings'' to require transmission
providers to implement AARs on the transmission lines over which they
provide transmission service. The Commission also proposed revisions to
its regulations to require RTOs/ISOs to establish and implement the
systems and procedures necessary to allow transmission owners to
electronically update transmission line ratings at least hourly and to
require transmission owners to share transmission line ratings and
transmission line rating methodologies with their transmission
provider(s) and, in RTOs/ISOs, with their market monitor(s). The
Commission received comments from 56 entities on the NOPR proposals
from a diverse set of stakeholders.\16\
---------------------------------------------------------------------------
\15\ Managing Transmission Line Ratings, Notice of Proposed
Rulemaking, 86 FR 6420 (Jan. 21, 2021), 173 FERC ] 61,165 (2020)
(NOPR).
\16\ See Appendix A for a list of entities that submitted
comments and the shortened names used throughout this final rule to
describe those entities.
---------------------------------------------------------------------------
III. Need for Reform
A. NOPR Proposal
17. In the NOPR, the Commission preliminarily found that
transmission line ratings and the rules by which they are established
are practices that directly affect the cost of wholesale energy,
capacity, and ancillary services, as well as the cost of delivering
wholesale energy to transmission customers. The Commission explained
that, because of the relationship between transmission line ratings and
costs, inaccurate transmission line ratings may result in Commission-
jurisdictional rates that are unjust and unreasonable.\17\
---------------------------------------------------------------------------
\17\ NOPR, 173 FERC ] 61,165 at P 38.
---------------------------------------------------------------------------
18. The Commission explained that most transmission owners
implement seasonal or static transmission line rating methodologies
based on conservative, worst-case assumptions, such as high
temperatures that are likely to occur over the longer term, but that
often do not reflect the true near-term transfer capability of
transmission facilities. Thus, the Commission reasoned, seasonal and
static line ratings fail to reflect the true cost of delivering
wholesale energy to transmission customers, and incorporating near-term
forecasts of ambient air temperatures in transmission line ratings
would more accurately reflect the actual cost of delivering wholesale
energy to transmission customers.\18\
---------------------------------------------------------------------------
\18\ Id. P 39.
---------------------------------------------------------------------------
19. Because actual ambient air temperatures are usually not as high
as the ambient air temperatures conservatively assumed in seasonal and
static line ratings, the Commission
[[Page 2247]]
observed that updating transmission line ratings used in near-term
transmission service to reflect actual ambient air temperatures usually
results in increased system transfer capability and, in turn, lower
costs for consumers. However, the Commission also observed that
seasonal and static line ratings can at times assume temperatures that
are lower than the actual ambient air temperatures in the short term.
In doing so, the Commission noted that seasonal or static transmission
line rating methodologies can at times result in transmission line
ratings that reflect more transfer capability than physically exists.
The Commission observed that this overstatement of transmission line
ratings similarly results in wholesale energy rates that fail to
reflect the actual cost of delivering wholesale energy to transmission
customers, and may also create reliability and safety problems, risk
damage to equipment, and prevent occurrences of rates for scarcity
pricing or transmission constraint penalty factors.\19\
---------------------------------------------------------------------------
\19\ Id. P 42.
---------------------------------------------------------------------------
20. Regarding DLR implementation, the Commission observed that some
RTOs/ISOs may rely on software and systems that cannot accommodate
transmission line ratings that frequently change, such as DLRs, and
that, without reflecting such frequent changes to transmission line
ratings, such software may serve as a barrier that prevents
transmission owners in RTOs/ISOs from implementing DLRs, which can
better reflect the actual transfer capability of the transmission
system. The Commission explained that, in addition to ambient air
temperature, DLRs incorporate additional inputs, including wind, cloud
cover, solar heating, and precipitation, as well as transmission line
conditions such as tension and sag. DLRs thereby provide transmission
line ratings that are closer to the true thermal transmission line
limit than AARs, which can result in rates that even more accurately
reflect the costs of delivering wholesale energy to transmission
customers than relying on AARs. However, the Commission explained that
the potential inability of RTOs/ISOs to automatically accept and use
DLRs provided by transmission owners may prevent RTO/ISO markets from
benefiting from the more accurate representation of current RTO/ISO
system conditions. In turn, by ensuring RTO/ISO market models can
incorporate more accurate representations of system conditions when
transmission owners use DLRs, RTO/ISO markets would produce prices that
more accurately reflect the costs of delivering wholesale energy to
transmission customers. For this reason, the Commission also
preliminarily found in the NOPR that current transmission line rating
practices in RTOs/ISOs that do not permit the acceptance of DLRs from
transmission owners may result in rates that do not reflect the actual
costs of delivering wholesale energy to transmission customers.\20\
---------------------------------------------------------------------------
\20\ Id. P 43.
---------------------------------------------------------------------------
21. Regarding emergency ratings, the Commission found that current
transmission line rating practices may fail to use emergency ratings,
and in failing to do so, may result in transmission line ratings that
do not accurately reflect the near-term transfer capability of the
system. This, in turn, may result in rates that do not reflect actual
costs of delivering wholesale energy to transmission customers. In
support, the Commission stated that transmission owners often develop
two sets of transmission line ratings for most facilities: Normal
ratings that can be safely used continuously, and emergency ratings
that can be used for a specified shorter period of time, typically
during post-contingency operations. Because emergency ratings are a
more accurate representation of the flow limits over shorter
timeframes, the Commission preliminarily found that their use in models
of post-contingency flows may produce prices that more accurately
reflect actual costs of delivering wholesale energy to transmission
customers.\21\
---------------------------------------------------------------------------
\21\ Id. PP 44-46.
---------------------------------------------------------------------------
22. Finally, in the NOPR, the Commission preliminarily found that,
by preventing transmission providers and, in RTO/ISOs, market monitors
from having the opportunity to validate transmission line ratings in
situations where a transmission provider serves any transmission owners
that are not itself, current levels of transparency into transmission
line ratings and transmission line rating methodologies may result in
unjust and unreasonable rates. The Commission observed that a
consequence of a lack of transparency could be inaccurate near-term
transmission line ratings, which may result in rates that do not
accurately reflect congestion and reserve costs on the system. As one
example, the Commission stated that, without knowing the basis for a
given transmission line rating that frequently binds and elevates
prices, a transmission provider and/or market monitor cannot determine
whether the transmission line rating is accurately calculated and
therefore whether unjust and unreasonable wholesale rates are being
created through use of inaccurate transmission line ratings.\22\
---------------------------------------------------------------------------
\22\ Id. P 47.
---------------------------------------------------------------------------
B. Comments
23. Commenters overwhelmingly agree with the Commission's
preliminary finding that transmission line ratings and the rules by
which they are established are practices that directly affect the cost
of wholesale energy, capacity, and ancillary services, as well as the
cost of delivering wholesale energy to transmission customers.\23\
Commenters also agree with the Commission's preliminary finding that,
because of the relationship between transmission line ratings and
wholesale energy costs, inaccurate transmission line ratings may result
in Commission-jurisdictional rates that are unjust and
unreasonable.\24\
---------------------------------------------------------------------------
\23\ AEP Comments at 3; Ohio FEA Comments at 6; New England
State Agencies Comments at 8; OMS Comments at 6; Potomac Economics
Comments at 5; CAISO DMM Comments at 4; SPP MMU Comments at 1-2; R
Street Institute Comments at 2; Industrial Customer Organizations
Comments at 11-12; TAPS Comments at 5-6; WATT Comments at 3-5;
Certain TDU Comments at 4-5; Clean Energy Parties Comments at 2-3;
EDFR Comments at 3.
\24\ SPP MMU Comments at 1-2; Potomac Economics Comments at 5;
CAISO DMM Comments at 4; Industrial Customer Organizations Comments
at 11-12; TAPS Comments at 5-6; Certain TDU Comments at 4-5; Clean
Energy Parties Comments at 2-3.
---------------------------------------------------------------------------
24. The majority of commenters representing state agencies support
the Commission's basis for reform. New England State Agencies explain
that, because transmission lines are used to control the amount of
energy on electric power systems, transmission line ratings affect the
price of electric power as well as the reliability of the electric
grid.\25\ OMS also agrees with the Commission's preliminary finding
that transmission line ratings directly affect wholesale energy costs
and artificially limit transfers within and between regions, stating
that such a conclusion is obvious and correct.\26\ OMS further contends
that the slow pace of action on this issue by RTOs/ISOs and
transmission owners makes the issue ripe for Commission action.\27\
Ohio FEA maintains that transmission line ratings have a direct and
significant influence on wholesale energy and capacity markets and,
therefore, must be accurate. Ohio FEA further argues that inaccurate
transmission line ratings may also cause Locational Deliverability
Areas (LDAs) to unnecessarily constrain in the
[[Page 2248]]
capacity market, resulting in higher capacity prices.\28\
---------------------------------------------------------------------------
\25\ New England State Agencies Comments at 8.
\26\ OMS Comments at 6.
\27\ OMS Reply Comments at 2-3.
\28\ Ohio FEA Comments at 6.
---------------------------------------------------------------------------
25. Each of the commenting market monitors supports the
Commission's basis for reform. For example, Potomac Economics agrees
with the Commission's finding that inaccurate transmission line ratings
may result in rates that are not just and reasonable and notes that
facility ratings are used in virtually every aspect of electricity
markets and system operations. Potomac Economics further avers that
transmission line ratings determine the transmission limits input into
market models, which, in turn, determine the commitment and dispatch
needed to satisfy load and manage congestion. Potomac Economics further
explains that underestimated transmission line ratings cause
inefficient operations, higher congestion, reduced transmission
availability, higher costs, higher renewable energy curtailments, and a
greater perceived need for new transmission facilities.\29\ The SPP MMU
also agrees with the Commission's assertion that transmission line
ratings can directly affect the cost of producing wholesale energy,
capacity, and ancillary services, as well as the cost of delivering
such products. The SPP MMU explains that the cost of congestion is
directly impacted by transmission line ratings and that inaccurate
transmission line ratings cause price distortions, which may result in
unjust and unreasonable rates.\30\ The CAISO DMM also agrees with the
Commission's assessment that transmission line ratings and the rules by
which they are established directly impact the cost of wholesale energy
delivery and related services, explaining that static or seasonal line
ratings can lead to increased costs when their assumptions are not
realized, which may be inefficient and can result in excess cost paid
by load.\31\
---------------------------------------------------------------------------
\29\ Potomac Economics Comments at 5.
\30\ SPP MMU Comments at 1-2.
\31\ CAISO DMM Comments at 4.
---------------------------------------------------------------------------
26. Other commenters also support the Commission's basis for
reform. R Street Institute states that the Commission's problem
statement is sound, explaining that transmission line ratings are
chronically understated because they do not reflect current weather
conditions, and as a result, according to R Street Institute, fail to
allow for significant cost savings.\32\ Industrial Customer
Organizations state that transmission line ratings and associated rules
directly affect the cost of wholesale energy, capacity, and ancillary
services, and the cost of delivering wholesale energy to transmission
customers, and the rulemaking is therefore consistent with the
Commission's authority and obligations under the FPA.\33\ TAPS states
that reliance on static or seasonal line ratings inflicts unnecessary
costs on consumers and that AAR deployment can provide significant
benefits to consumers.\34\ WATT explains that accurate transmission
line ratings lower costs for consumers.\35\ Certain TDUs assert that
enhanced transmission line ratings, including AARs and DLRs, are tools
that maximize the efficiency of the existing transmission system and
lower costs for consumers.\36\
---------------------------------------------------------------------------
\32\ R Street Institute Comments at 2.
\33\ Industrial Customer Organizations Comments at 11-12.
\34\ TAPS Comments at 5-6.
\35\ WATT Comments at 3-5.
\36\ Certain TDUs Comments at 4.
---------------------------------------------------------------------------
27. Finally, clean energy and generator representatives also
support the Commission's basis for reform.\37\ For example, Clean
Energy Parties conclude that, due to the impact that transmission line
ratings have on wholesale rates requirements, accurate transmission
line ratings are consistent with the Commission's mandate under
sections 205 and 206 of the FPA.\38\
---------------------------------------------------------------------------
\37\ Clean Energy Parties Comments at 2-3; EDFR Comments at 3.
\38\ Clean Energy Parties Comments at 2-3.
---------------------------------------------------------------------------
28. However, NYTOs question the Commission's legal standing to
regulate transmission line ratings, noting that the U.S. Court of
Appeals for the District of Columbia Circuit (D.C. Circuit) found that
there are limits to the Commission's FPA section 206 jurisdiction over
``practices'' and that the term may not include all utility
operations.\39\ NYTOs note that the Commission's authority to regulate
transmission planning was upheld on appeal but that Order No. 1000 \40\
is not prescriptive; therefore, NYTOs request that the Commission
similarly allow utilities to make their own decisions related to
advanced line rating technologies.\41\
---------------------------------------------------------------------------
\39\ NYTOs Comments at 9 (referencing Cal. Indep. Sys. Operator
Corp. v. FERC, 372 F.3d 395, 402 (D.C. Cir. 2004)).
\40\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 77 FR 32184
(May 31, 2012), 136 FERC ] 61,051 (2011), order on reh'g, Order No.
1000-A, 139 FERC ] 61,132, order on reh'g and clarification, Order
No. 1000-B, 141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv.
Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
\41\ NYTOs Comments at 9-10.
---------------------------------------------------------------------------
C. Commission Determination
29. We find that transmission line ratings, and the rules by which
they are established, are practices that directly affect the rates for
the transmission of electric energy in interstate commerce and the sale
of electric energy at wholesale in interstate commerce (hereinafter
referred to collectively as ``wholesale rates''). Thus, the Commission
has jurisdiction over transmission line ratings.\42\ We further find
that, because of the relationship between transmission line ratings and
wholesale rates, inaccurate transmission line ratings result in
wholesale rates that are unjust and unreasonable. Accordingly, pursuant
to FPA section 206,\43\ we conclude that certain revisions to the pro
forma OATT and the Commission's regulations are necessary to ensure
just and reasonable wholesale rates. We adopt most of the reforms
proposed in the NOPR, with certain clarifications, as discussed further
herein, and revisions to the proposed pro forma OATT Attachment M and
to the Commission's regulations.
---------------------------------------------------------------------------
\42\ 16 U.S.C. 824(b)(1), 824d.
\43\ 16 U.S.C. 824e.
---------------------------------------------------------------------------
30. We find that transmission line ratings directly affect
wholesale rates because transmission line ratings and wholesale rates
are inextricably linked. As explained above, transmission line ratings
represent the maximum transfer capability of each transmission line.
That transfer capability determines the quantity of energy that can be
transmitted from suppliers to load in any given moment. Supply and
demand fundamentals dictate that less transfer capability (i.e., less
supply) will result in higher rates, all else being equal. Inaccurate
transmission line ratings can result in underutilization (or
overutilization) of existing transmission facilities, thereby sending a
signal that there is less (or more) transfer capability than is truly
available. This signal impacts the wholesale rates charged for
providing energy and other ancillary services. For example, if the
system operator believes there is less transfer capability than is
truly available, it may dispatch more expensive generators to serve
load, when less expensive generators (which would have resulted in
lower congestion costs) could have been used to reliably serve the same
load. Alternatively, inaccurate transmission line ratings can result in
oversubscription of existing transmission facilities, thereby sending
the opposite signal--that there is more transfer capability than is
truly available--which may risk damage to equipment, may fail to
accurately price congestion costs, and may fail to signal to the market
that more generation and/or transmission investment may be needed in
the long term. We therefore find that transmission line ratings
[[Page 2249]]
directly affect wholesale rates and, concomitantly, that inaccurate
transmission line ratings result in unjust and unreasonable wholesale
rates.\44\
---------------------------------------------------------------------------
\44\ SPP MMU Comments at 1-2; Potomac Economics Comments at 5;
CAISO DMM Comments at 4; Industrial Customer Organizations Comments
at 11-12; TAPS Comments at 5-6; Certain TDU Comments at 4-5; Clean
Energy Parties Comments at 2-3.
---------------------------------------------------------------------------
31. Most commenters, except NYTOs, agree with the Commission's
preliminary conclusion that transmission line ratings directly affect
wholesale rates.\45\ NYTOs caution that the D.C. Circuit found there
are limits to the Commission's FPA section 206 jurisdiction over
``practices'' and that the term may not include all utility
operations.\46\ But, the inextricable link between transmission line
ratings and wholesale rates places transmission line ratings within the
Commission's FPA section 206 jurisdiction.
---------------------------------------------------------------------------
\45\ AEP Comments at 3; Ohio FEA Comments at 6; New England
State Agencies Comments at 8; OMS Comments at 6; Potomac Economics
Comments at 5; CAISO DMM Comments at 4; SPP MMU Comments at 1-2; R
Street Institute Comments at 2; Industrial Customer Organizations
Comments at 11-12; TAPS Comments at 5-6; WATT Comments at 3-5;
Certain TDU Comments at 4-5; Clean Energy Parties Comments at 2-3;
EDFR Comments at 3.
\46\ NYTOs Comments at 9-10.
---------------------------------------------------------------------------
32. Some commenters, in response to the preliminary finding that
accurate transmission line ratings are necessary for just and
reasonable wholesale rates, argue that transmission line ratings are
fundamentally a reliability tool.\47\ We agree that system safety and
reliability are paramount to the proposed requirements for transmission
line ratings. But we disagree with the suggestion that because
transmission line ratings are critical to reliability, economic
considerations are an inappropriate basis for requiring a certain type
of transmission line ratings. Instead, we find that commenters present
a false choice; economic considerations and reliability considerations
are inextricably linked as reliability constraints bound the potential
economic transactions of market participants. In the case of
transmission line ratings, transmission owners calculate the maximum
transfer capability of a transmission line. Transmission providers, in
order to maintain reliable system operations, incorporate those ratings
and other constraints into operations, and the results determine
dispatch and commitment instructions and wholesale rates. Even though
transmission line ratings can be seen as a reliability tool, that does
not obviate the need to ensure that the wholesale rates resulting from
such reliability tools are just and reasonable.
---------------------------------------------------------------------------
\47\ See, e.g., Dominion Comments at 13; Exelon Comments at 6;
PJM Indicated Transmission Owners Comments at 2; EEI Comments at 5.
---------------------------------------------------------------------------
33. Regarding that incorporation of transmission line ratings into
operations and resulting wholesale rates, as the Commission explained
in the NOPR, most transmission owners implement seasonal or static line
ratings. Such seasonal or static line ratings are based on
conservative, worst-case assumptions about long-term conditions, such
as the expected high temperatures that are likely to occur over the
longer term. While such long-term assumptions may be appropriate in
various planning contexts, they often do not reflect the true near-term
transfer capability of transmission facilities and, when used in near-
term operations, produce unjust and unreasonable wholesale rates.
34. As explained in the NOPR, incorporating near-term forecasts of
ambient air temperatures in transmission line ratings can more
accurately reflect the true near-term transfer capability of
transmission facilities than continuing to rely on seasonal or static
line ratings. Because actual ambient air temperatures are usually not
as high as the ambient air temperatures conservatively assumed in
seasonal and static line ratings, updating the transmission line
ratings used in near-term transmission service to reflect actual
ambient air temperatures usually results in increased system transfer
capability. By increasing transfer capability, congestion costs will,
on average, decline because transmission providers will be able to
serve load with less expensive resources from what were previously
constrained areas. For example, Potomac Economics has found that AAR
implementation by those not already using AARs in MISO alone would have
produced approximately $66.5 million and $49 million in reduced
congestion costs in 2019 and in 2020, respectively.\48\ Such congestion
cost changes and related overall price changes will more accurately
reflect the actual congestion on the system, leading to wholesale rates
that more accurately reflect the cost of the wholesale service being
provided. Likewise, the ability to increase transmission flows into
load pockets may reduce transmission provider reliance on local
reserves inside load pockets, which may reduce local reserve
requirements and the costs to maintain that required level of reserves.
---------------------------------------------------------------------------
\48\ Potomac Economics Comments at 8.
---------------------------------------------------------------------------
35. Moreover, while current transmission line rating practices
usually understate transfer capability, they can also overstate
transfer capability and, in doing so, place transmission lines at risk
of inadvertent overload. While actual ambient air temperatures are
usually not as high as the assumed seasonal or static line rating
temperature input, in some instances actual ambient air temperatures
exceed those assumed temperatures. In those instances, seasonal or
static line ratings might reflect more transfer capability than
physically exists, and therefore such transmission line ratings might
allow access to some electric power supplies and/or demand that would
not be available if transmission line ratings reflected the true
transfer capability. Overstating transfer capability, like understating
transfer capability, can result in wholesale rates that fail to reflect
the cost of the wholesale service being provided, though, in the case
of overstated transfer capability, through inaccurately low congestion
pricing and failing to signal to the market that more generation and/or
transmission investment may be needed in the long term.
36. Regarding DLRs, in addition to ambient air temperatures and the
presence or absence of solar heating, other weather conditions such as
(but not limited to) wind, cloud cover, solar heating intensity, and
precipitation, and transmission line conditions such as tension and
sag, can affect the amount of transfer capability of a given
transmission facility. DLRs incorporate these additional inputs and
thereby provide transmission line ratings that are closer to the true
thermal transmission line limits than AARs. However, as noted above and
explained in greater detail in Section IV.E below, based on the record
in this proceeding, we decline to mandate DLR implementation in this
final rule. We instead incorporate the record in this proceeding on
DLRs into new Docket No. AD22-5-000, which we open to further explore
DLR implementation.
37. While we believe additional record is needed regarding DLR
implementation, we can determine based on the record that current
transmission line rating practices in RTOs/ISOs that do not permit the
acceptance of DLRs from transmission owners that use DLRs are
contributing to unjust and unreasonable wholesale rates by acting as a
barrier to accurate transmission line ratings. Therefore, as part of
remedying inaccurate transmission line ratings that result in unjust
and unreasonable wholesale rates, we require RTOs/ISOs to establish and
maintain the systems and
[[Page 2250]]
procedures necessary to permit the acceptance of DLRs from transmission
owners that use them. As the Commission explained in the NOPR, some
RTOs/ISOs rely on software that cannot accommodate transmission line
ratings that frequently change, such as DLRs.\49\ Without reflecting
such frequent changes to transmission line ratings, such software
serves as a barrier that prevents transmission owners in RTOs/ISOs from
implementing DLRs and better reflecting the actual transfer capability
of the transmission system. The result is that, even if a transmission
owner sought to implement DLRs, the RTO's/ISO's energy management
system (EMS) may not be able to accept and use the resulting
transmission line rating. The potential inability of RTOs/ISOs to
accept and use a DLR prevents RTO/ISO markets from benefiting from the
more accurate representation of current system conditions. Therefore,
we require RTOs/ISOs to establish and maintain the systems and
procedures necessary to permit the acceptance of DLRs from transmission
owners that use them.
---------------------------------------------------------------------------
\49\ NOPR, 173 FERC ] 61,165 at P 43.
---------------------------------------------------------------------------
38. Regarding emergency ratings, we find that many transmission
owners' current transmission line rating practices fail to use
emergency ratings, and in failing to do so, lead to transmission line
ratings that do not accurately reflect the near-term transfer
capability of the transmission system, and therefore result in
wholesale rates that do not reflect costs of the wholesale service
being provided. As the Commission explained in the NOPR, transmission
owners often develop two sets of transmission line ratings for most
facilities: Normal ratings that can be safely used continuously, and
emergency ratings that can be used for a specified shorter period of
time, typically during post-contingency operations. Transmission
providers generally calculate resource dispatch and commitments to
ensure that all facilities are within applicable facility ratings both
during normal operations and following any modeled contingency (e.g.,
following the loss of a transmission line). In ensuring that the system
is stable and reliable following a contingency, transmission providers
often allow post-contingency flows on transmission lines to exceed
normal ratings for short periods of time, as long as those flows do not
exceed the applicable emergency rating for the corresponding timeframe.
Because these emergency ratings are a more accurate representation of
the flow limits over those shorter timeframes, their use in models of
post-contingency flows produces wholesale rates that more accurately
reflect the costs of the wholesale service being provided and therefore
is necessary to ensure just and reasonable wholesale rates. For this
reason, as described below, we require that transmission providers
implement uniquely determined emergency ratings. Additionally, we
require that transmission providers use uniquely determined emergency
ratings for contingency analysis in the operations horizon and in post-
contingency simulations of constraints. Such uniquely determined
emergency ratings must also include separate AAR calculations for each
emergency rating duration used.
39. Finally, we find that the current level of transparency into
transmission line ratings and methodologies may result in unjust and
unreasonable wholesale rates. In some regions, where the transmission
owner and transmission provider are not the same entity, such as RTOs/
ISOs, current transparency levels prevent the transmission provider and
market monitor(s) from having the opportunity to assess the accuracy of
transmission line ratings. For example, as the Commission described in
the NOPR, without knowing the basis for a given transmission line
rating that frequently binds and elevates prices, a transmission
provider and/or market monitor cannot determine whether the
transmission line rating is accurately calculated.\50\ Moreover, we
find that, absent additional information to market participants on
transmission line ratings and their methodologies, the status quo does
not provide market participants with information important to making
cost-effective decisions and, thereby, impedes such decisions. For
example, without accurate transmission line rating information, market
participants operate without information that is important in making
accurate economic decisions regarding where to build generation or
where to site load. Further, this lack of transparency could allow
transmission owners to submit inaccurate near-term transmission line
ratings, which, in turn, would result in wholesale rates that do not
accurately reflect the cost of the wholesale service being provided, as
discussed above. For these reasons, we require: (1) Public utility
transmission owners to share transmission line ratings and
methodologies with their transmission provider(s) and with market
monitors in RTOs/ISOs; (2) transmission providers to share their
transmission owners' transmission line ratings and methodologies with
any transmission provider(s) upon request; (3) transmission providers
to maintain a database of their transmission owners' transmission line
ratings and methodologies on the transmission provider's OASIS site or
another password-protected website; and (4) transmission providers to
post on OASIS or another password-protected website any uses of
exceptions or temporary alternate ratings.
---------------------------------------------------------------------------
\50\ Id. P 47.
---------------------------------------------------------------------------
IV. Discussion
A. Transmission Line Ratings Definition
1. NOPR Proposal
40. In the NOPR, the Commission proposed to define a transmission
line rating in pro forma OATT Attachment M as the maximum transfer
capability of a transmission line, computed in accordance with a
written transmission line rating methodology and consistent with good
utility practice, considering the technical limitations on conductors
and relevant transmission equipment (such as thermal flow limits), as
well as technical limitations of the transmission system (such as
system voltage and stability limits). Relevant transmission equipment
may include, but is not limited to, circuit breakers, line traps, and
transformers.\51\
---------------------------------------------------------------------------
\51\ NOPR, 173 FERC ] 61,165 at P 85.
---------------------------------------------------------------------------
41. Under the ``Obligations of Transmission Provider'' section in
pro forma OATT Attachment M, the Commission further proposed to require
that the transmission provider must use either AARs or seasonal line
ratings, as appropriate, as the relevant transmission line ratings.
Similarly, and as described in more detail in Section IV.D.3, the
Commission proposed exceptions to the AAR and seasonal line rating
requirements for certain transmission line ratings.
2. Comments
42. Some commenters support the proposed definition of transmission
line rating, while others request clarity or modifications be made,
specifically around the list of relevant transmission equipment. AEP
supports the Commission's proposed transmission line rating definition,
explaining that the Commission's proposed definition reflects the fact
that transmission line ratings incorporate a set of electrical
equipment that collectively operate as a single bulk electric system
element (e.g., transformers, relay protective devices, terminal
equipment, and series and shunt compensation devices) and that the most
limiting component from that
[[Page 2251]]
set determines the transmission line rating.\52\ Similarly, Indicated
PJM Transmission Owners address the NOPR's proposed AAR requirements
set forth in pro forma OATT Attachment M under ``Obligations of
Transmission Provider'' (hereinafter referred to as ``the proposed AAR
requirements'') as ambient-adjusted and seasonal line ratings,
consistent with NERC's definition of facility rating,\53\ and describe
Indicated PJM Transmission Owners' implementation of AARs, consistent
with NERC's definition of facility ratings.\54\ PJM also describes the
implementation of AARs for each of its transmission facilities.\55\
---------------------------------------------------------------------------
\52\ AEP Comments at 2-3.
\53\ The NERC Glossary defines a ``Facility Rating'' as: ``[t]he
maximum or minimum voltage, current, frequency, or real or reactive
power flow through a facility that does not violate the applicable
equipment rating of any equipment comprising the facility.'' NERC,
Glossary of Terms Used in NERC Reliability Standards (June 28,
2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\54\ Indicated PJM Transmission Owners Comments at 1-2, 6-7.
\55\ PJM Comments at 2-3.
---------------------------------------------------------------------------
43. Entergy explains that overhead conductor ratings and ratings
for ``ancillary equipment,'' or equipment that does not include a
primary element, like conductors and transformers, can be temperature
adjusted. According to Entergy, examples of ``ancillary equipment''
include breakers, switches, traps, busses, jumpers, current
transformers, potential transformers, and relay equipment. Entergy
further asserts, however, that shunt reactors, series capacitors,
relays, current transformers, static VAR compensators, circuit
breakers, autotransformers, copper weld (``CW'') buses, conductors,
risers or jumpers, and, subject to limited exceptions, customer
equipment have ratings that cannot be temperature adjusted.\56\
Eversource states that the ratings for relays and other equipment, such
as splices, switches, and terminal equipment, are not impacted by
ambient air temperatures.\57\ NYISO states that the majority of the
bulk electric system equipment ratings in New York are able to be rated
using AARs or DLRs,\58\ while NYTOs note that transmission line ratings
may be based on non-conductor components which are not affected by
ambient air temperatures.\59\ EEI and MISO Transmission Owners request
clarity on the definition of transmission line rating and its specific
applicability, stating that the AAR requirements should not apply to
power transformers, but instead, under certain circumstances, to other
types of transformers, including current transformers.\60\ EEI further
explains that ratings for power transformers are generally the result
of the efficiency of the heat transfer process, not ambient air
temperatures directly, and thus requests that the Commission clarify
that the references to transformers apply only to transformers that
limit or impact transmission line ratings and not power transformers
generally.\61\ Entergy similarly notes that transformer and relay
ratings do not change with ambient conditions.\62\ ITC states that AARs
cannot be applied to voltage or stability limits and therefore
recommends that ``transmission line rating'' reflect the concepts of
equipment and facility rating as defined by NERC in order to avoid
confusion with a system operating limit.\63\ APS states that
transmission lines with limitations associated with substation
equipment or series capacitors, among other equipment in which the
transmission line is not the limiting factor, may not experience
changes to their transfer capabilities.\64\ MISO contends that the list
could include potential relay trip limits and maximum power transfer
limits.\65\
---------------------------------------------------------------------------
\56\ Entergy Comments at 5-6.
\57\ Eversource Comments at 3.
\58\ NYISO Comments at 3-4.
\59\ NYTOs Comments at 8.
\60\ EEI Comments at 17-18; MISO Transmission Owners Comments at
39-40.
\61\ EEI Comments at 17-18.
\62\ Entergy Comments at 9-10.
\63\ ITC Comments at 11-12. The NERC Glossary defines an
``Equipment Rating'' as: ``[t]he maximum and minimum voltage,
current, frequency, real and reactive power flows on individual
equipment under steady state, short-circuit and transient
conditions, as permitted or assigned by the equipment owner.'' It
defines a ``System Operating Limit'' as: ``[t]he value (such as MW,
Mvar, amperes, frequency or volts) that satisfies the most limiting
of the prescribed operating criteria for a specified system
configuration to ensure operation within acceptable reliability
criteria. System Operating Limits are based upon certain operating
criteria. These include, but are not limited to: Facility Ratings
(applicable pre- and post-Contingency Equipment Ratings or Facility
Ratings); transient stability ratings (applicable pre- and post-
Contingency stability limits); voltage stability ratings (applicable
pre- and post-Contingency voltage stability); and system voltage
limits (applicable pre- and post-Contingency voltage limits).''
NERC, Glossary of Terms Used in NERC Reliability Standards (June 28,
2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\64\ APS Comments at 3.
\65\ MISO Comments at 34.
---------------------------------------------------------------------------
3. Commission Determination
44. In this final rule, we adopt the definition of transmission
line rating proposed in the NOPR. Specifically, we adopt the proposed
definition that a transmission line rating means the maximum transfer
capability of a transmission line, computed in accordance with a
written transmission line rating methodology and consistent with good
utility practice, considering the technical limitations on conductors
and relevant transmission equipment (such as thermal flow limits), as
well as technical limitations of the transmission system (such as
system voltage and stability limits). Relevant transmission equipment
may include, but is not limited to, circuit breakers, line traps, and
transformers. As the Commission stated in the NOPR, system safety and
reliability are paramount to the proposed requirements for transmission
line ratings. We agree with AEP that the definition adopted herein
reflects the fact that transmission line ratings must incorporate a set
of electrical equipment ratings that collectively operate as a single
bulk electric system element (e.g., transformers, relay protective
devices, terminal equipment, and series and shunt compensation devices)
and that the most limiting component from that set determines the
transmission line rating.\66\
---------------------------------------------------------------------------
\66\ AEP Comments at 2-3.
---------------------------------------------------------------------------
45. In response to comments about the definition's inclusion of the
technical limitations (such as thermal flow limits) on conductors and
relevant transmission equipment, we clarify that the definition of
transmission line rating encompasses transmission line ratings for
electric system equipment that includes more than just overhead
conductors. For example, it includes ratings for electric system
equipment such as circuit breakers, line traps, and transformers.
Additionally, as described in more detail below in Section IV.D.3, we
adopt the list of proposed exceptions from the NOPR. Consequently, we
do not require transmission line ratings that are not affected by
ambient air temperatures to be rated using forecasts of ambient air
temperatures. That said, we decline to define in this final rule which
electric system equipment ratings are (or are not) affected by ambient
air temperatures. Instead, we allow flexibility for individual
transmission owners and transmission providers to apply good utility
practice to determine which specific electric system equipment has
ratings that are (or are not) affected by ambient air temperatures.
46. Finally, in response to requests for clarification from EEI and
MISO Transmission Owners regarding the applicability of the proposed
AAR requirements to power transformers, we decline to provide a generic
exception from the AAR requirement for power transformers. The
operating limits of a power transformer are bounded by the
[[Page 2252]]
ambient air temperature, the average winding temperature, and the
maximum winding hottest-spot temperature.\67\ However, we reiterate the
exceptions adopted herein and discussed further below, which provide
that any rating not affected by ambient air temperatures would not be
required to incorporate forecasts of ambient air temperatures into the
rating. Thus, if a transmission provider determines, consistent with
good utility practice, that a specific power transformer's rating is
not affected by ambient air temperature, then that power transformer
would fall within the scope of such exceptions to the AAR requirement.
---------------------------------------------------------------------------
\67\ Institute of Electrical and Electronics Engineers, IEEE
Standard for General Requirements for Liquid-Immersed Distribution,
Power, and Regulating Transformers, IEEE Std C57.91.00-2021.
---------------------------------------------------------------------------
B. Ambient-Adjusted Ratings
1. AAR Definition and Transmission Provider Obligations
a. NOPR Proposal
47. In the NOPR, the Commission proposed to define an AAR in pro
forma OATT Attachment M and in the Commission's regulations as a
transmission line rating that: (1) Applies to a time period of not
greater than one hour; (2) reflects an up-to-date forecast of ambient
air temperature across the time period to which the rating applies; and
(3) is calculated at least each hour, if not more frequently. As
obligations of the transmission provider set forth in pro forma OATT
Attachment M, the Commission proposed to require that transmission
providers use AARs as the applicable line rating: (1) For requests for
near-term point-to-point transmission service ending within 10 days of
the request date, as defined in pro forma OATT Attachment M; (2) for
determining the necessity of near-term curtailment or interruption of
near-term point-to-point transmission service anticipated to occur
(start and end) within the next 10 days; and (3) for determining the
necessity of near-term interruption or redispatch of network
transmission service anticipated to occur (start and end) within the
next 10 days. The Commission proposed to require transmission providers
to implement the use of AARs and seasonal line ratings on all
historically congested transmission lines \68\ within one year after
the compliance filing due date and on all other transmission lines
within two years after the compliance filing due date.\69\ For RTOs/
ISOs, for which the Commission has approved variations from the pro
forma OATT to manage congestion and initiate curtailments and/or
redispatch of transmission service within their footprints (although
generally not at their borders), the Commission proposed two
requirements. First, the Commission proposed requirements for RTOs/ISOs
to implement AARs in both the day-ahead and real-time markets and any
intra-day reliability unit commitment. Second, the Commission proposed
to require AARs as the relevant transmission line rating for any near-
term point-to-point transmission service offered (e.g., at the RTO's/
ISO's borders).
---------------------------------------------------------------------------
\68\ The Commission proposed to define a historically congested
transmission line as ``a transmission line that was congested at any
time in the five years prior to the effective date of [this final
rule].'' NOPR, 173 FERC ] 61,165 at P 92.
\69\ Id. P 131.
---------------------------------------------------------------------------
48. As justification for the NOPR proposal to require AAR
implementation on all transmission lines and not only on historically
congested lines, the Commission noted that any facility can become the
most limiting element as the transmission system changes, and in
certain circumstances flows may change considerably from normal
operations. Therefore, the Commission proposed to require AARs be
implemented on all transmission lines but recognized that a staggered
implementation schedule would allow transmission providers and
transmission owners to focus initial implementation where it would have
the most impact.\70\
---------------------------------------------------------------------------
\70\ Id. PP 93-94.
---------------------------------------------------------------------------
49. As justification for requiring AARs, the Commission
preliminarily found that AAR requirements strike an appropriate balance
between benefits and challenges. First, the Commission observed that,
while there are differences across transmission systems, simply
accounting for ambient air temperatures in transmission line ratings
can reliably increase power transfer capability and significantly lower
production costs at a manageable implementation cost. The Commission
next explained that, according to Potomac Economics' estimates, the
benefits to AAR implementation by those not already implementing AARs
in MISO alone would have produced approximately $94 million and $78
million in reduced congestion costs in 2017 and in 2018, respectively.
The Commission further explained that, while several entities noted
implementation costs as a barrier to AAR implementation, the costs
identified were mostly initial investments in upgraded OASIS and/or EMS
and ratings databases and that once these systems are upgraded, adding
AARs to additional transmission lines appears to have a minimal
incremental cost.\71\
---------------------------------------------------------------------------
\71\ Id. P 99.
---------------------------------------------------------------------------
b. Comments
50. In response to the proposed AAR requirements, RTO/ISO comments
are mixed, with most requesting flexibility to accommodate regional or
market differences,\72\ while market monitors are generally supportive
of the NOPR proposal.\73\ Transmission owners are conceptually
supportive of AAR implementation but request flexibility in response to
what they generally describe as an overly broad requirement.\74\ The
PJM transmission owners that submitted comments are generally
supportive of the proposed AAR requirements in pro forma OATT
Attachment M, explaining that they have experience using AARs.\75\
Other commenters, including state governments, generation, load,
renewable energy advocates, and other technical experts, are generally
supportive of the proposed AAR requirements.\76\
---------------------------------------------------------------------------
\72\ See, e.g., MISO Comments at 7, 9, 14-16; NYISO Comments at
9-11; ISO-NE Comments at 9.
\73\ Potomac Economics Comments at 3-4; CAISO DMM Comments at 2-
4; SPP MMU Comments at 1, 4.
\74\ MISO Transmission Owners Comments at 8-9; PacifiCorp
Comments at 2; EEI Comments at 2-5; NRECA/LPPC Comments at 2-3;
Entergy Comments at 1-2; BPA Comments at 2-4; WAPA Comments at 4-5;
APS Comments at 2-4; Southern Company Comments at 2-3; NYTOs
Comments at 2-3; Duke Energy Comments at 1-2; PG&E Comments at 3;
SCE Comments at 1-2; SDG&E Comments at 1-2; LADWP Comments at 2-3;
IID Comments at 4-6; ITC Comments at 1-3; Sunflower Comments at 2;
Eversource Comments at 5-7.
\75\ Exelon Comments at 1-2; AEP Comments at 5-6; Dominion
Comments at 3-4; Indicated PJM Transmission Owner Comments at 1-4.
\76\ New England State Agencies Comments at 10; OMS Comments at
2; Ohio FEA Comments at 2; R Street Institute Comments at 1-2; WATT
Comments at 1-2; DC Energy Comments at 1-2; ACORE Comments at 1;
Clean Energy Parties Comments at 2, 4-6; ENEL Comments at 1; EDFR
Comments at 1-2; Vistra Comments at 1-2; EPSA Comments at 2;
Industrial Customers Comments at 1-2; TAPS Comments at 1-2; Certain
TDU Comments at 1.
---------------------------------------------------------------------------
51. Several transmission owners explain that they currently use
AARs on all or parts of their transmission lines and support the
Commission's NOPR proposal to implement widespread AAR use. AEP notes
that it has used AARs in real-time operations for decades and that AARs
have provided both reliability and financial benefits.\77\ AEP notes
that the use of AARs is common in PJM and that it similarly implements
AARs for its facilities in SPP and the Electric Reliability Council of
Texas (ERCOT).\78\ Exelon states that it
[[Page 2253]]
considers AARs to be a best practice, explaining that all of its six
utilities have implemented AARs on their transmission systems, without
any adverse reliability or safety impacts, and have found the practice
to be a cost-effective tool to enhance grid reliability.\79\ Dominion
states that, because PJM has implemented AARs for transmission service
and for use in its day-ahead and real-time markets, Dominion Energy
Virginia has adopted and uses PJM's AAR methodology on all its
transmission lines, while Dominion Energy South Carolina uses AARs on
only a portion of its transmission system.\80\ Indicated PJM
Transmission Owners support efforts to enhance transmission utilization
by requiring AAR and seasonal line rating implementation, explaining
that such practices improve efficiency; they also state that
transmission line ratings are fundamentally a reliability tool.\81\
While generally supportive of the NOPR proposal, Dominion, AEP, and
Indicated PJM Transmission Owners all request flexibility to
accommodate PJM's current AAR implementation and ask that the
Commission not require hourly updates to AARs.\82\
---------------------------------------------------------------------------
\77\ AEP Comments at 3.
\78\ Id. at 3-4.
\79\ Exelon Comments at 1-2.
\80\ Dominion Comments at 6.
\81\ Indicated PJM Transmission Owners Comments at 1-2.
\82\ Dominion Comments at 3; AEP Comments at 6-7; Indicated PJM
Transmission Owners Comments at 5.
---------------------------------------------------------------------------
52. Both ITC and Sunflower state that they are generally supportive
of AAR implementation, but urge flexibility for transmission providers
to implement AARs.\83\ MISO Transmission Owners, explaining that they
have initiated a process to implement AARs, state that they support
certain aspects of the NOPR, but also state that other aspects are
overly broad and will not yield sufficient benefits to justify the
costs.\84\ MISO Transmission Owners urge the Commission to allow for
regional flexibility in any requirements and state that AAR deployment
should focus on where it is expected to provide benefits by ``freeing
up'' additional transfer capability.\85\ MISO Transmission Owners state
that, over the past five years, congestion arose on only 10% of the
nearly 10,000 transmission facilities under MISO's functional control
and that there would be no benefit to implementing AARs on non-
congested lines.\86\ MISO Transmission Owners also state that there are
several necessary steps to implement AARs, which can be costly and time
consuming.\87\ Additionally, MISO Transmission Owners state that the
Commission should not rely upon Potomac Economics' estimates of AAR
benefits, explaining that Potomac Economics inaccurately assumed that:
(1) All transmission lines are ambient adjustable; (2) all transmission
owners are using worst-case assumptions; and (3) congestion caused by
transient outages existed even though it has since been alleviated by
recent upgrades.\88\
---------------------------------------------------------------------------
\83\ ITC Comments at 1-3; Sunflower Comments at 2.
\84\ MISO Transmission Owners Comments at 3-4.
\85\ Id. at 13.
\86\ Id. at 28.
\87\ Id. at 22.
\88\ Id. at 43-45.
---------------------------------------------------------------------------
53. NYTOs, Eversource, and Southern Company request that the
Commission refrain from adopting blanket AAR requirements for all
transmission lines and instead require transmission providers to adopt
a process for determining whether to apply AARs or DLRs to certain
transmission facilities.\89\ Southern Company suggests that such a
process could be similar to the Commission's available transfer
capability (ATC) requirements, whereby a public utility could include
the metrics and criteria for determining when to use AAR or DLR in its
OATT and implementation details in its guidelines or business
practices.\90\ Southern Company states that, while broader use of AARs
and DLRs may provide cost savings to customers, the Commission's
proposed approach in the NOPR is overly prescriptive and may therefore
create unnecessary implementation complications and limit the
deployment of other grid-enhancing technologies.\91\ Southern Company
and NRECA/LPPC also argue that non-RTO/ISO regions are characterized by
long-term transmission commitments and that incremental short-term
transfer capability is less relevant and less likely to result in cost
savings.\92\ Eversource contends that it applies AARs where it is
beneficial, but states that the benefits of AARs will depend on
specific circumstances within a region, noting that there is little
congestion in ISO-NE.\93\
---------------------------------------------------------------------------
\89\ Southern Company Comments at 1-2; Eversource Comments at 6;
NYTOs Comments at 10.
\90\ Southern Company Comments at 1-2.
\91\ Id. at 2.
\92\ Id. at 4-5; NRECA/LPPC Comments at 19.
\93\ Eversource Comments at 4-5.
---------------------------------------------------------------------------
54. Southern Company states that reliability issues may arise as a
result of the NOPR proposal because AARs may create difficulties in
identifying the most limiting element, which may change as the
temperature changes, and similar difficulties may arise in complying
with Reliability Standard PRC-023-4's transmission relay loadability
requirements that depend on maximum published ratings.\94\ EEI states
that, to ensure compliance with Reliability Standard PRC-023-4,
significant amounts of field engineering time could be required to
install and test new settings for thousands of relays.\95\ NYTOs state
that implementing the AAR requirements will require significant time
and resources and would divert scarce resources from ongoing efforts to
meet the goals of New York's Climate Leadership and Community
Protection Act.\96\ NERC contends that the Commission should keep in
mind considerations for implementing AARs across long transmission
lines that span multiple climates.\97\
---------------------------------------------------------------------------
\94\ Southern Company Comments at 6.
\95\ EEI Comments at 5-6.
\96\ NYTOs Comments at 6-7.
\97\ NERC Comments at 7.
---------------------------------------------------------------------------
55. Duke Energy states that it already employs AARs in real-time
operations and supports the Commission's proposed requirements for
transmission providers to implement AARs in real-time operations.\98\
However, Duke Energy also argues that, because incorporating AARs into
ATC calculations would require fundamental software changes that may
take several million dollars and multiple years to complete, the
benefits may not outweigh the costs.\99\ Duke Energy suggests that the
Commission should instead require transmission providers to submit a
compliance filing in which they may propose a process to identify the
transmission facilities for which the implementation of AARs and
seasonal line ratings will provide the most benefits to customers.\100\
---------------------------------------------------------------------------
\98\ Duke Energy Comments at 5.
\99\ Id. at 10.
\100\ Id. at 5.
---------------------------------------------------------------------------
56. EEI states that its experience with AARs is that their use can
provide benefits on a subset of transmission lines \101\ and requests
flexibility for transmission owners and transmission providers to
implement transmission line rating solutions that best suit their
needs.\102\ EEI recommends a staggered AAR approach whereby AARs would
first be implemented on priority designated facilities, using
established and studied criteria, and any subsequent AAR implementation
would occur following further studies of potential benefits.\103\
Similarly, Entergy states that AARs allow for more flexibility in real-
time operations than static/thermal values for real-time contingency
studies,
[[Page 2254]]
but contends that the use of AARs should follow a scientific
application of factors that can reasonably result in an adjustment of
facility ratings to those facilities for which an adjustment would be
reasonably expected to provide benefits that exceed costs.\104\
---------------------------------------------------------------------------
\101\ EEI Comments at 5.
\102\ Id. at 2-4.
\103\ Id.
\104\ Entergy Comments at 8.
---------------------------------------------------------------------------
57. NRECA/LPPC, Sunflower, and WAPA contend that the promised
benefits, costs, and risks of AARs are not evenly distributed
nationwide and that blanket application of the proposed AAR
requirements poses difficult operating challenges.\105\ NRECA/LPPC
argue that the Commission should maintain a focus on safety and
reliability and limit the scope of any final rule by applying the AAR
requirements to transmission lines: (1) Rated 100 kV and above; (2)
that are historically congested due to conductor limitations only; and
(3) that are under RTO/ISO control. In addition, NRECA/LPPC argue that
AAR requirements should be limited to transmission service used for
near-term wholesale transactions, which in the RTOs/ISOs would be the
day-head and real-time markets, and outside of the RTOs/ISOs, if
applied, would be daily and hourly ATC, curtailment, and
redispatch.\106\ NRECA/LPPC and Sunflower further contend that, due to
challenges in implementing AARs, utilities should have the flexibility
to choose the AAR methodology best suited to their needs and should
provide a waiver mechanism for particular circuits on which AAR
implementation is difficult.\107\
---------------------------------------------------------------------------
\105\ NRECA/LPPC Comments at 15-16, 19; Sunflower Comments at 5;
WAPA Comments at 5.
\106\ NRECA/LPPC Comments at 2-3.
\107\ Id. at 3; Sunflower Comments at 5.
---------------------------------------------------------------------------
58. Several Western Interconnection, non-CAISO transmission owners,
including PacifiCorp, BPA, WAPA, and APS, broadly support the adoption
of AARs due to the associated reduction in congestion, increase in
transfer capability, and reliability improvements. However, these
transmission owners request additional flexibility in how transmission
owners apply AARs and urge the Commission to not adopt blanket AAR
requirements for all transmission lines given differences in terrain,
line lengths, and scarcity of temperature data for such lines.\108\ In
explaining the drawbacks to blanket AAR implementation, APS explains
that non-congested transmission lines, transmission lines that are
substation equipment-limited, and transmission lines that are voltage-
and stability-limited will not benefit from AAR implementation.\109\
WAPA further identifies additional AAR implementation challenges,
including the installation of new devices, communication equipment, and
cybersecurity challenges. To reduce implementation burdens, WAPA
recommends that the Commission examine real-time Total Transfer
Capability (TTC) calculations.\110\ WAPA further cautions that it would
have to pass the costs of AAR implementation on to all customers, even
though only some customers would benefit.\111\ BPA states that if it
uses AARs as proposed, it would need to make its wind assumptions more
conservative, de-rating transmission, to mitigate the risk of operating
near the conductor limit.\112\
---------------------------------------------------------------------------
\108\ PacifiCorp Comments at 2; BPA Comments at 2-4; WAPA
Comments at 4-5; APS Comments at 2-4.
\109\ APS Comments at 2-4.
\110\ WAPA Comments at 7-9.
\111\ Id. at 4-5.
\112\ BPA Comments at 4-5.
---------------------------------------------------------------------------
59. PacifiCorp, BPA, EEI, and IID further explain additional
difficulties they would face implementing the proposed requirements to
incorporate AARs into ATC that could render AAR implementation
infeasible.\113\ IID explains that, in the Western Interconnection,
path limits are the result of multiple limits in series and in
parallel. TTC calculations involve adjusting a base case with an
associated series of activities, and failures in base case studies have
to be evaluated manually, such that a generic equation would be
insufficient in calculating transmission line ratings.\114\ BPA and
PacifiCorp explain that most congested parts on their transmission
systems are lines that are operated in parallel as part of a rated
transmission path,\115\ that such rated paths have interactions with
other paths, which result in operating nomograms,\116\ and that the
NOPR proposal may be more appropriate for a flow-based transmission
system.\117\ According to PacifiCorp and BPA, it may be infeasible to
implement AARs as it would substantially increase the time to compute
the constraints that they use to calculate TTC.\118\ CAISO also
describes the TTC calculation process using rated paths and states that
using hourly AARs would exponentially increase the complexity of such
calculations and would necessitate further automation.\119\ Similarly
describing the challenges of incorporating AARs into ATC, EEI explains
that, in some areas, TTC values are determined annually, or even less
frequently.\120\
---------------------------------------------------------------------------
\113\ Id. at 3-4; PacifiCorp Comments at 2; IID Comments at 5-6;
EEI Comments at 10-11.
\114\ IID Comments at 5.
\115\ BPA Comments at 3; PacifiCorp Comments at 2.
\116\ Nomograms are operating constraints related to the flow on
multiple paths that generally result from the simultaneous
interaction between those paths.
\117\ BPA Comments at 3; PacifiCorp Comments at 2.
\118\ BPA Comments at 3; PacifiCorp Comments at 2.
\119\ CAISO Comments at 10.
\120\ EEI Comments at 11.
---------------------------------------------------------------------------
60. California transmission owners urge more targeted AAR
implementation.\121\ PG&E recommends requiring transmission owners to
determine which lines would realize net benefits for customers if AARs
were deployed, noting that deployment of AARs across all transmission
lines could result in a negative return on investment and an increased
risk profile for the transmission system.\122\ PG&E notes that most of
its weather stations are currently located in ``High Fire Threat
Districts'' and contends that AAR implementation on 500 kV lines will
require planning for additional weather station equipment to ensure
that accurate weather data is available.\123\ SCE advocates for phased
AAR implementation in which transmission owners identify priority
facilities, and, after implementation, study their implementation in a
report filed with the Commission.\124\ SDG&E contends that settings for
all relays will have to be studied and installed in the field, causing
a significant cost burden unaccounted for in the Commission's
analysis.\125\ IID contends that the Commission should not take a one-
size-fits-all approach and, in addition to the challenges of AAR
implementation, encourages the Commission to consider the costs of
software, equipment, and staffing in comparison to the benefits of AARs
providing congestion relief.\126\
---------------------------------------------------------------------------
\121\ PG&E Comments at 3; SCE Comments at 1-2; SDG&E Comments at
1-2; LADWP Comments at 2-3.
\122\ PG&E Comments at 3.
\123\ Id. at 9-10.
\124\ SCE Comments at 3-4.
\125\ SDG&E Comments at 4.
\126\ IID Comments at 5.
---------------------------------------------------------------------------
61. LADWP states that Southern California loads peak in the summer
when temperatures are already high and may not allow AARs to expand
transfer capability. Conversely, according to LADWP, there is already
abundant transfer capability in the winter months.\127\ Describing AAR
implementation challenges, LADWP notes that, due to the diversity in
terrain and microclimates that western transmission lines traverse,
weather forecasts can vary significantly during volatile weather
seasons and present
[[Page 2255]]
challenges in identifying the most constraining ambient conditions for
a given transmission line.\128\ LADWP therefore contends that the
Commission should consider offering regional exceptions from the AAR
requirements or prescribing AARs only in areas where significant
benefits are expected.\129\
---------------------------------------------------------------------------
\127\ LADWP Comments at 3-4.
\128\ Id. at 5-6.
\129\ Id. at 4-5.
---------------------------------------------------------------------------
62. PJM generally supports the adoption of AARs by transmission
providers. PJM states that it already employs AARs in its operations
and day-ahead and real-time markets and that the use of AARs is
commonplace among the overwhelming majority of transmission owners in
the PJM region. PJM states that transmission owners' utilization of
AARs increases operational flexibility, promotes a more efficient use
of the transmission system, and results in more reliable system
dispatch and cost-effective market operations.\130\
---------------------------------------------------------------------------
\130\ PJM Comments at 2.
---------------------------------------------------------------------------
63. CAISO states that it currently uses seasonal line ratings,
emergency ratings, and AARs. However, CAISO notes that AARs are used on
relatively few facilities and involve a manual process to update
transmission line ratings for an applicable period. CAISO states that,
while AARs provide a more accurate understanding of the transfer
capability of the transmission system, CAISO recommends that the
Commission allow transmission owners and transmission providers to
justify when they use AARs.\131\
---------------------------------------------------------------------------
\131\ CAISO Comments at 2.
---------------------------------------------------------------------------
64. MISO states that AAR and DLR deployment can support the
efficient use of existing transmission infrastructure but is not a
long-term solution to meet emerging system needs. MISO states that the
Commission should not mandate the use of AARs where the burden of that
deployment is greater than the benefits to be expected. MISO contends
that the Commission should explore options for a more targeted
application of identifying facilities that are good candidates for AARs
based on objective criteria and documented methodologies.\132\ MISO
notes that it and MISO Transmission Owners have already commenced an
effort to identify a prioritized list of candidate transmission
facilities for deployment of real-time AARs in MISO.\133\
---------------------------------------------------------------------------
\132\ MISO Comments at 9.
\133\ MISO Comments at 14.
---------------------------------------------------------------------------
65. NYISO does not support a uniform approach to managing
transmission line ratings and instead requests that each RTO/ISO work
with the Commission to set objectives for its markets.\134\ NYISO
contends that AAR use would not provide benefits everywhere.\135\ NYISO
explains that using AARs to modify day-ahead transmission line ratings
would overly complicate the day-ahead market solution and would reduce
efficiency.\136\ NYISO requests flexibility for regional variation with
transmission line ratings given regional differences, such as
transmission scheduling and market rules.\137\ NYISO states that it
could work with stakeholders to develop a proposal to implement three
to four sets of seasonal line ratings that would be easier to implement
and still achieve many of the NOPR objectives.\138\
---------------------------------------------------------------------------
\134\ NYISO Comments at 1.
\135\ Id. at 2.
\136\ Id. at 1-2.
\137\ Id. at 2.
\138\ Id. at 20.
---------------------------------------------------------------------------
66. Neither ISO-NE nor SPP explicitly takes a position on the NOPR
proposal to implement AARs. However, ISO-NE states that most of the
congestion that occurs on its system is due to voltage or stability
limitations, and thus AAR benefits may be limited.\139\ ISO-NE
estimates that the implementation of AARs could result in the lowering
of thermal congestion costs by, at most, approximately $5-10 million
per year.\140\ ISO-NE also contends, however, that AAR implementation
may expose other binding system limitations without appreciably
increasing transfer capability or reducing congestion.\141\
---------------------------------------------------------------------------
\139\ ISO-NE Comments at 4-6.
\140\ Id. at 5 (basing estimates on 2019 data contained in IMM
and EMM Reports and the Commission's estimates of potential savings
from AARs in other RTO/ISO regions).
\141\ Id. at 6.
---------------------------------------------------------------------------
67. Market monitors are mostly supportive of the proposed AAR
requirements.\142\ The SPP MMU supports the proposed reforms to improve
the accuracy and transparency of transmission line ratings used by
transmission providers. The SPP MMU notes that numerous SPP
transmission lines are not rated according to SPP Planning
Criteria.\143\ The SPP MMU states that it supports the use of DLRs for
all transmission lines.\144\ According to the SPP MMU, when
transmission line ratings underestimate the actual transfer capability
of the transmission system, this can result in restricted flows on
certain paths while overloading others and can create a potential for
de facto physical withholding of the available transfer capability by
transmission owners.\145\ The SPP MMU argues that more accurate
transmission line ratings will improve the robustness of price
formation, particularly in congested areas.\146\
---------------------------------------------------------------------------
\142\ Potomac Economics Comments at 3-4; CAISO DMM Comments at
2-4; SPP MMU Comments at 1, 4.
\143\ SPP MMU Comments at 4.
\144\ Id. at 1, 4.
\145\ Id. at 7.
\146\ Id. at 9.
---------------------------------------------------------------------------
68. Potomac Economics states that only 8% of the transmission line
ratings in MISO are adjusted for changes in ambient air temperatures.
Potomac Economics indicates that it conservatively estimates that the
benefits of using AARs and emergency ratings in 2019 and 2020 would
have been between 9% and 13% of the real-time congestion value, or $98
million and $114 million per year.\147\ Potomac Economics notes that
transmission owners have little or no economic incentive to provide
temperature-adjusted ratings and that transmission operators \148\
rarely verify or validate transmission line rating methodologies or
transmission line rating calculations.\149\ Potomac Economics contends
that it would be unreasonable to require AARs on all transmission
facilities, and instead argues that it would be more reasonable to
require that processes be established to allow for additional AARs to
be deployed quickly when new constraints begin to bind or other studies
indicate it may be appropriate.\150\ Potomac Economics cautions,
however, against requiring any cost-benefit analysis, noting that the
incremental cost of initiating AARs on new constraints is near zero so
such analysis is unnecessary.\151\ Finally, Potomac Economics contends
that using AARs and emergency ratings will not create reliability
concerns as the NOPR proposal only requires that decisions to not
implement AARs or emergency ratings be based on reliability and not a
preference or policy decision.\152\ CAISO DMM supports the proposed
requirements to implement hourly AARs as a way to improve both the
accuracy of congestion costs and transmission system efficiency.\153\
---------------------------------------------------------------------------
\147\ Potomac Economics Comments at 7-9; see also Potomac
Economics Reply Comments at 2-6.
\148\ The NERC Glossary defines a ``Transmission Operator'' as:
``[t]he entity responsible for the reliability of its `local'
transmission system, and that operates or directs the operations of
the transmission Facilities.'' NERC, Glossary of Terms Used in NERC
Reliability Standards (June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\149\ Potomac Economics Comments at 9-10; see also Potomac
Economics Reply Comments at 6-7.
\150\ Potomac Economics Comments at 20; see also Potomac
Economics Reply Comments at 9.
\151\ Potomac Economics Reply Comments at 7.
\152\ Id. at 11.
\153\ CAISO DMM Comments at 2, 4.
---------------------------------------------------------------------------
[[Page 2256]]
69. State government agencies are also mostly supportive of the
proposed AAR requirements.\154\ New England State Agencies state that
they strongly support the Commission's proposed AAR requirements.\155\
New England State Agencies state that the transmission system was built
on behalf of and paid for by ratepayers, and argue that the Commission
should take all reasonable steps to protect those ratepayers from
excessive costs. New England State Agencies contend that the use of
AARs can be an important tool in this regard.\156\ New England State
Agencies state that a transmission system operated using AARs may
provide benefits by possibly: (1) Obviating the need for new
transmission lines, thus deferring capital costs; \157\ (2) reducing
reliance on higher cost local reserves which will reduce costs and
local reserve requirements resulting from an increased ability to flow
power into load pockets; \158\ and (3) helping with the integration of
new clean energy resources.\159\ Finally, New England State Agencies
argue that, because parts of MISO as well as most of ERCOT are already
employing AARs, there can be no serious argument that AARs are too
difficult or costly to implement as was suggested by some transmission
owners.\160\
---------------------------------------------------------------------------
\154\ New England State Agencies Comments at 10; OMS Comments at
2; Ohio FEA Comments at 2.
\155\ New England State Agencies Comments at 10.
\156\ Id.
\157\ Id. at 10-11.
\158\ Id. at 12.
\159\ Id.
\160\ Id.
---------------------------------------------------------------------------
70. OMS states that it supports the NOPR proposal that AAR
requirements generally apply to all transmission lines and not just
those with historical congestion.\161\ OMS notes that the most
expensive energy prices typically occur after unforeseen outages or
weather events and are not the result of chronic, well understood
scenarios. However, OMS also states that it does not support requiring
AARs on those facilities where it is uneconomical or unreliable to do
so.\162\ OMS contends that the Commission should require RTOs/ISOs to
develop a process whereby transmission owners transparently work with
the RTOs/ISOs and market monitors to demonstrate why any exceptions
from the requirements are justified.\163\
---------------------------------------------------------------------------
\161\ OMS Comments at 8-10; see also OMS Reply Comments at 7,
10.
\162\ OMS Comments at 9.
\163\ Id.
---------------------------------------------------------------------------
71. Ohio FEA also supports the AAR NOPR proposal, stating that AARs
help ratepayers to realize the full benefits of their transmission
system investment. Ohio FEA explains that the four Ohio transmission
owners have already recognized the benefits of AARs, as a way of moving
away from static ratings.\164\ However, UDPU contends that the AAR NOPR
proposal should be limited to certain historically congested facilities
until the Commission has better information to assess the costs and
benefits of broad AAR implementation.\165\
---------------------------------------------------------------------------
\164\ Ohio FEA Comments at 2-4.
\165\ UDPU Comments at 1-3.
---------------------------------------------------------------------------
72. CEA encourages the Commission to further consider the costs
associated with the proposed changes, as a broader use of AARs may
over-estimate the benefit to cost ratio. CEA contends that the use of
AARs presents a significant cost challenge considering the number of
upgrades required.\166\
---------------------------------------------------------------------------
\166\ CEA Comments at 2.
---------------------------------------------------------------------------
73. Other technical experts are also supportive of more accurate
transmission line ratings.\167\ R Street Institute states that
understated transmission line ratings can result in increased
congestion costs and underutilization of generation in export-
constrained locales, which is disproportionately zero-emission
generation.\168\ R Street Institute contends that the Commission should
require DLRs by default and permit exceptions where justified by a
cost-benefit analysis.\169\
---------------------------------------------------------------------------
\167\ R Street Institute Comments at 1; WATT Comments at 1-2;
LineVision Comments at 1-2.
\168\ R Street Institute Comments at 1.
\169\ Id. at 3, 5-7.
---------------------------------------------------------------------------
74. WATT supports the direction the Commission is taking with the
NOPR's AAR requirements, but explains that additional factors that
affect transmission line ratings but are not incorporated into AARs are
very knowable.\170\ WATT contends that the Commission should require
the use of DLRs when certain criteria are met.\171\ LineVision supports
WATT's comments and states that DLR implementation will also result in
additional accuracy and situational awareness.\172\
---------------------------------------------------------------------------
\170\ WATT Comments at 1-2.
\171\ Id. at 10-12.
\172\ LineVision Comments at 1-2.
---------------------------------------------------------------------------
75. Renewable energy advocates are also generally supportive of the
AAR NOPR proposal, but urge the Commission to take further measures to
spur the implementation of DLRs.\173\ For example, ACORE commends the
Commission for issuing the NOPR, but recommends the Commission take
further steps to encourage DLR deployment by incenting its deployment
through transmission incentives and incorporating its assessment into
transmission planning processes.\174\ Similarly, Clean Energy Parties
contend that AARs are easy to implement and a modest improvement over
static line ratings.\175\ However, Clean Energy Parties argue that DLR
is superior to AAR, though Clean Energy Parties do not contend a
blanket DLR mandate is appropriate.\176\ ACPA/SEIA support accurate
transmission line ratings, and contend that the Commission should
require all transmission owners and transmission providers to study the
costs and benefits of implementing DLRs on persistently congested
transmission lines and require implementation where warranted.\177\
ACPA/SEIA and Clean Energy Parties both argue that the Commission
should alter its NOPR proposal to prioritize transmission lines that
are expected to be congested, persistently congested, or likely to be
congested in the future.\178\
---------------------------------------------------------------------------
\173\ ACORE Comments at 1; Clean Energy Parties Comments at 2,
4-6.
\174\ ACORE Comments at 1.
\175\ Clean Energy Parties Comments at 4-5.
\176\ Id. at 5, 8.
\177\ ACPA/SEIA Comments at 5-7.
\178\ Id. at 8-9; Clean Energy Parties Comments at 8, 10.
---------------------------------------------------------------------------
76. Generator owners and representatives are also generally
supportive of the proposed AAR requirements.\179\ EDFR argues that
getting the transmission line rating policy right is important due to
the urgency of addressing the climate crisis and President Biden's
carbon emissions reduction goals. EDFR contends that a lack of adequate
transfer capability can cripple clean energy generation.\180\ EDFR
further explains that, under many offtake agreements in RTO/ISO
markets, the developer is paid a fixed price for energy at a market hub
and if congestion limits the project's ability to deliver power to the
hub, then the developer bears the risk (known as basis risk). EDFR
argues that congestion is difficult to hedge in an effective way
because system topology and conditions change unexpectedly over time,
but states that more accurate transmission line ratings will decrease
basis risk and hedging difficulties.\181\ EDFR contends that
prioritization should not only consider historical congestion, but
should consider future congestion based on transmission planning,
interconnection, and transmission service studies for purposes of
prioritizing implementation.\182\
---------------------------------------------------------------------------
\179\ ENEL Comments at 1; EDFR Comments at 1-2; Vistra Comments
at 1-2; EPSA Comments at 2.
\180\ EDFR Comments at 2.
\181\ Id.
\182\ Id. at 4.
---------------------------------------------------------------------------
[[Page 2257]]
77. EPSA contends that the Commission should encourage the use of
technological advances that improve transmission operators' ability to
track and optimize transmission line ratings and usage where feasible
and cost effective. EPSA states that PJM's adoption of AAR requirements
has shown clear benefits.\183\ Vistra is supportive of the Commission's
NOPR proposal, stating that it is imperative that the Commission act
now to make best use of existing infrastructure and that AARs and DLRs
are the best way to do that.\184\
---------------------------------------------------------------------------
\183\ EPSA Comments at 2.
\184\ Vistra Comments at 1-2.
---------------------------------------------------------------------------
78. Industrial Customer Organizations, TAPS, and Certain TDUs are
also broadly supportive of the AAR NOPR proposal.\185\ Certain TDUs
state that they support the proposed rule and encourage the Commission
to mandate improvements to the accuracy and transparency of
transmission line ratings because not all transmission owners have
shown a willingness to make these improvements voluntarily.\186\
Certain TDUs state that they support the use of AARs as a way to better
utilize the existing transmission system, noting that it will become
imperative that the existing transmission system is utilized to the
greatest extent possible as additional renewable resources come
online.\187\
---------------------------------------------------------------------------
\185\ Industrial Customer Organizations Comments at 1-2; TAPS
Comments at 1-2; Certain TDU Comments at 1.
\186\ Certain TDUs Comments at 4.
\187\ Id. at 4-5.
---------------------------------------------------------------------------
79. Industrial Customer Organizations state that they generally
support the proposed rules, but assert that these rules should be
implemented as soon as practicable.\188\ Industrial Customer
Organizations argue that, if prioritization is needed, congested
circuits should be prioritized.\189\ Industrial Customer Organizations
explain that understated transmission line ratings increase congestion
and may lead to curtailments. Industrial Customer Organizations contend
that transmission owners that understate transmission line ratings may
create an illusory need for transmission upgrades. Further, Industrial
Customer Organizations contend that some transmission line ratings may
be deliberately understated because transmission owners may have a
profit incentive to calculate understated transmission line ratings in
order to benefit local generation.\190\
---------------------------------------------------------------------------
\188\ Industrial Customer Organizations Comments at 15-18.
\189\ Id. at 18-19.
\190\ Id. at 4.
---------------------------------------------------------------------------
80. TAPS states that it supports the proposed broad application of
AARs because it reduces the likelihood that AARs will be implemented in
a discriminatory manner.\191\ Similarly, Clean Energy Parties cite
Order No. 888,\192\ in which the Commission stated that ``[d]enials of
access [to transmission services] (whether they are blatant or subtle),
and the potential for future denials of access [to transmission
services], require the Commission to revisit and reform its regulation
of transmission in interstate commerce.'' \193\ According to Clean
Energy Parties, Order No. 888 supports the assertion that a lack of
consistency and transparency in transmission line ratings creates the
potential for future denials of access to transmission service, as
inaccurate transmission line ratings are used to provide discriminatory
transmission service to preferential customers.\194\
---------------------------------------------------------------------------
\191\ TAPS Comments at 7.
\192\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ]
31,036 (1996) (cross-referenced at 75 FERC ] 61,080), order on
reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. &
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
\193\ Id. at 31,652.
\194\ Clean Energy Parties Comments at 2-3.
---------------------------------------------------------------------------
81. Additionally, TAPS notes that the NOPR proposal would require
the use of AARs when evaluating requests for near-term point-to-point
transmission service and contends that the Commission should also apply
the requirements to requests for near-term secondary service requests
and near-term network resource designations. TAPS explains that
secondary service comes ahead of non-firm point-to-point transmission
service in curtailment priority, and the NOPR proposal flips this
priority.\195\
---------------------------------------------------------------------------
\195\ TAPS Comments at 20.
---------------------------------------------------------------------------
82. Prysmian discourages mandatory AAR implementation without
consideration of other variables and without a holistic evaluation of
all transmission line rating inputs to determine whether an overall
transmission line rating methodology is conservative or not. Prysmian
states that AARs can also lead to situations in which near-term
transfer capability is overstated.\196\
---------------------------------------------------------------------------
\196\ Prysmian Comments at 1.
---------------------------------------------------------------------------
c. Commission Determination
83. In this final rule, we adopt with certain modifications the
NOPR proposal to require transmission providers to apply the AAR
requirements set forth in pro forma OATT Attachment M to all
transmission lines, subject to the exceptions described below in
Section IV.D.3.\197\ As discussed above, the AAR requirements will
ensure that transmission line ratings are more accurate. In turn, more
accurate transmission line ratings will ensure wholesale rates more
accurately reflect the cost of the wholesale service being provided
(i.e., energy, capacity, ancillary services, or transmission service)
and, thus, that those wholesale rates are just and reasonable. We
further describe, below, the requirements and the modifications to the
NOPR proposal adopted herein.
---------------------------------------------------------------------------
\197\ NOPR, 173 FERC ] 61,165 at PP 92, 102.
---------------------------------------------------------------------------
84. First, we adopt the proposal to apply the AAR requirements as
set forth under ``Obligations of Transmission Provider'' in pro forma
OATT Attachment M to all transmission lines subject to the exceptions
described below in Section IV.D.3. We find that applying the AAR
requirements to all transmission lines will both ensure that wholesale
rates remain just and reasonable and strike an appropriate balance
between benefits and challenges of AAR implementation. For this reason,
we do not adopt the phased-in implementation schedule proposed in the
NOPR in which a transmission provider would initially implement AARs on
only historically congested lines.
85. As the Commission preliminarily found in the NOPR \198\ and as
the record demonstrates, despite differences across transmission
systems, simply accounting for ambient air temperatures in transmission
line ratings can reliably increase power transfer capability, resulting
in significant reliability, operational, and economic benefits.
Numerous commenters describe these benefits.\199\ For example, Potomac
Economics estimates that the benefits to AAR implementation in MISO
alone would have produced approximately $67 million and $49 million in
reduced congestion costs in 2019 and in 2020,
[[Page 2258]]
respectively.\200\ Exelon describes AARs as a best practice that cost-
effectively enhances transmission utilization, benefiting customers,
without adverse safety and reliability impacts.\201\ EEI acknowledges
that experience with AARs shows that their use can provide benefits on
certain subsets of transmission facilities.\202\ PJM states that, in
its experience, AARs increase operational flexibility, promote a more
efficient use of the transmission system, and result in more reliable
system dispatch and cost-effective market operations.\203\ New England
State Agencies argue that the Commission should take all reasonable
steps to protect ratepayers from excessive costs and that the use of
AARs, by permitting more power to flow than a system operated using
static or seasonal line ratings, can be an important tool in this
regard.\204\ Similarly, TAPS explains that reliance on static and
seasonal line ratings inflicts unnecessary costs on consumers and
contends that deployment of AARs using commercial temperature forecasts
can produce significant benefits to consumers at low cost.\205\ While
several entities note implementation costs as a barrier, these costs
are mostly initial investment costs in EMS improvements to accommodate
AARs, implementation of a ratings database, and review (and potentially
reset) of protective relays settings.\206\ Once these initial
investments are made, adding AARs to additional transmission lines
appears to have a minimal incremental cost.\207\
---------------------------------------------------------------------------
\198\ Id. P 99.
\199\ MISO Transmission Owners Comments at 8-9; PacifiCorp
Comments at 2; EEI Comments at 4-5; Entergy Comments at 1-2; BPA
Comments at 2-4; NYTOs Comments at 2-3, 5; Duke Energy Comments at
6-7; PG&E Comments at 1; LADWP Comments at 2-3; ITC Comments at 1-3;
Sunflower Comments at 2; Exelon Comments at 1-2; AEP Comments at 3;
Indicated PJM Transmission Owner Comments at 2; PJM Comments at 2;
PJM Comments at 2; New England State Agencies Comments at 7; TAPS
Comments at 5.
\200\ Potomac Economics Comments at 7-8.
\201\ Exelon Comments at 1.
\202\ EEI Comments at 5.
\203\ PJM Comments at 2.
\204\ New England State Agencies Comments at 5-6, 10-11.
\205\ TAPS Comments at 5.
\206\ Indicated PJM Transmission Owner Comments at 5-6; Exelon
Comments at 14; AEP AD19-15 Post Technical Conference Comments at 3.
\207\ Exelon Comments at 8; Indicated PJM Transmission Owner
Comments at 5-6; AEP Post-Technical Conference Comments at 2-3;
September 2019 Technical Conference, Day 1 Tr. at 180-181.
---------------------------------------------------------------------------
86. Second, in this final rule we adopt a requirement for
transmission providers to use AARs when evaluating the availability of
and requests for near-term transmission service (under sections 15, 17,
18, and 29 of the pro forma OATT).\208\ For purposes of this
requirement, we define ``requests for near-term transmission service''
to include not only requests for near-term point-to-point transmission
service, but also network resource designations and secondary service
where the start and end date of the designation/request is within the
next 10 days. Specifically, we require transmission providers to use
AARs as the relevant transmission line ratings when: (1) Evaluating
requests for near-term transmission service, defined as transmission
service ending within 10 days of the date of the request; (2)
responding to requests for information on the availability of potential
near-term transmission service (including requests for ATC or other
information related to potential service); and (3) posting ATC or other
information related to near-term transmission service to their OASIS
site. As discussed further below, in response to comments, we modify
this requirement from the NOPR proposal to include near-term network
and near-term secondary service, as well as the near-term point-to-
point transmission service proposed in the NOPR.\209\
---------------------------------------------------------------------------
\208\ NOPR, 173 FERC ] 61,165 at P 87.
\209\ Although requests for network transmission service are
typically long-term requests, meriting their evaluation using
seasonal line ratings, we note the Commission's finding in Order No.
890 that the minimum term for network transmission service should be
the same as the minimum time period used for firm point-to-point
transmission service (i.e., daily). See Preventing Undue
Discrimination and Preference in Transmission Service, Order No.
890, 72 FR 12266 (Mar. 15, 2007), 118 FERC ] 61,119, at P 1505,
order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), 121
FERC ] 61,297 (2007), order on reh'g, Order No. 890-B, 123 FERC ]
61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar.
25, 2009), 126 FERC ] 61,228, order on clarification, Order No. 890-
D, 129 FERC ] 61,126 (2009). As such, any requests for transmission
service that fall within the near-term threshold defined herein
would qualify as near-term network transmission service.
---------------------------------------------------------------------------
87. Third, we adopt the Commission's proposal in the NOPR to
require that transmission providers use AARs as the relevant
transmission line rating when determining whether to curtail or
interrupt near-term point-to-point transmission service (under sections
13.6 and/or 14.7 of the pro forma OATT) \210\ if such curtailment or
interruption is both necessary because of issues related to flow limits
on transmission lines and anticipated to occur (start and end) within
the next 10 days.\211\
---------------------------------------------------------------------------
\210\ Additionally, we add references to interruption or
curtailment of near-term point-to-point transmission service
occurring pursuant to 13.6 of the pro forma OATT to Attachment M in
order to ensure consistent treatment of firm and non-firm point-to-
point transmission service.
\211\ NOPR, 173 FERC ] 61,165 at P 89.
---------------------------------------------------------------------------
88. Fourth, we adopt the proposal in the NOPR \212\ to require that
transmission providers use AARs as the relevant transmission line
ratings when determining whether to curtail network or secondary
service (under section 33 of the pro forma OATT) or redispatch network
or secondary service (under sections 30.5 and/or 33 of the pro forma
OATT), if such curtailment or redispatch is both necessary because of
issues related to flow limits on transmission lines and anticipated to
occur (start and end) within 10 days of such determination.
---------------------------------------------------------------------------
\212\ Id. P 90.
---------------------------------------------------------------------------
89. Fifth, we adopt and modify the proposal in the NOPR to allow
RTOs/ISOs to comply with the final rule's AAR requirements by revising
their OATTs to require implementation of AARs within their security
constrained economic dispatch (SCED) and security constrained unit
commitment (SCUC) models (and in any relevant related models) in both
the day-ahead and real-time markets and reliability unit commitment
(RUC) processes,\213\ and any other intra-day RUC processes.\214\ As
the Commission recognized in the NOPR, such entities have Commission-
approved variations from the pro forma OATT to manage congestion and
initiate curtailments and/or redispatch of transmission service within
their footprints (although generally not at their borders) through
mechanisms such as SCED and SCUC. As discussed in Section IV.B.3.b, we
adopt the Commission's NOPR proposal to require that transmission
providers--including RTOs/ISOs--update their AARs at least hourly. As
discussed in Sections IV.B.3.b and IV.B.3.c, for any seams-based
transmission service offered by RTOs/ISOs, we adopt the Commission's
NOPR proposal to implement the near-term transmission service
requirements for inclusion of up-to-date hourly AAR calculations in
ATC.
---------------------------------------------------------------------------
\213\ After the day-ahead market process takes place, RTOs/ISOs
typically perform one or more residual unit commitment processes, or
what we refer to here as RUC, to address remaining resource gaps and
reliability issues or to manage uncertainty and the potential for
real-time operational issues. The exact names, definitions, and
market processes implementing what we refer here to as RUC processes
differ across RTOs/ISOs. For example, CAISO refers to its process as
residual unit commitment, SPP uses reliability unit commitment, and
MISO uses reliability assessment commitment. For simplicity,
however, this final rule uses the term RUC to refer to all of these
relevant processes in all of the RTO/ISO markets interchangeably.
\214\ NOPR, 173 FERC ] 61,165 at P 91. The statement ``(and in
any relevant related models)'' was intended to encompass all RUC
processes within the timeframe. In the interest of clarity, we
modify the NOPR proposal here to make that more explicit.
---------------------------------------------------------------------------
90. We do not adopt the NOPR proposal to establish a definition of
historically congested transmission lines. Accordingly, since we are
not adopting the NOPR's proposed definition of historically congested
transmission line, and instead apply the AAR requirements adopted
herein to all transmission lines, we do not address comments related to
the NOPR's proposed definition of historically congested transmission
line. To the
[[Page 2259]]
extent that commenters were arguing for a narrower application than
what we adopt in this final rule, below we explain the basis for
application of the AAR requirements to all transmission lines.
91. Finally, we alter the proposed compliance schedule.
Specifically, we require each transmission provider to submit a
compliance filing within 120 days of the effective date of this final
rule to incorporate into its OATT the changes adopted herein consistent
with pro forma OATT Attachment M and the changes to the Commission's
regulations set forth below. Additionally, we further require that all
requirements adopted herein be fully implemented no later than three
years from the compliance filing due date established by this final
rule.
92. In response to comments received in response to the NOPR, we
modify the NOPR proposal's defined term ``near-term point-to-point
transmission service'' to instead be ``near-term transmission
service.'' As a result, the AAR requirements will apply to requests for
near-term network transmission service, near-term secondary service,
and near-term point-to-point transmission service, provided that such
service meets the 10-day threshold defined in the near-term
transmission service definition. We agree with TAPS that it would be
inappropriate to apply the AAR requirements only to requests for near-
term point-to-point transmission service and not to requests for near-
term network and near-term secondary service because secondary service
comes before non-firm point-to-point transmission service in
curtailment priority.\215\ More generally, we find that a requirement
to use AARs on all types of near-term transmission service will better
ensure that transmission line ratings are accurate and that wholesale
rates are just and reasonable.
---------------------------------------------------------------------------
\215\ TAPS Comments at 18-20.
---------------------------------------------------------------------------
93. Although commenters broadly raise concerns with adopting
transmission line ratings that may fluctuate widely or contend that
implementing AARs on certain transmission lines may not yield benefits,
we do not find that these concerns and arguments overcome the need to
improve the accuracy of transmission line ratings through applying the
AAR requirements to all transmission lines. Specifically, we decline to
accommodate requests for more targeted AAR requirements in which
transmission providers would either have flexibility to identify
candidate transmission lines or the Commission would require AAR
implementation on only priority transmission lines, such as only on
historically congested lines.
94. We recognize commenters' concerns, such as those from NRECA/
LPPC, that the promised benefits, costs, and risks of implementing AARs
may not be evenly distributed nationwide.\216\ Nevertheless, we find
that with the broad AAR requirements adopted herein, the overall
benefits via savings to load and lower congestion charges to generators
will on balance outweigh the costs. Moreover, we acknowledge the
difficulty of knowing in advance all the locations and situations in
which the benefits of AAR implementation will outweigh the costs. Given
the difficulty in predicting unexpected congestion before it happens,
narrowing the scope of the AAR requirements would limit the ability of
these reforms to ensure just and reasonable wholesale rates. In
particular, we find that the AAR requirements adopted in this final
rule are beneficial in mitigating the impact of transient congestion,
i.e., temporary or short-term congestion that does not occur on a
regular basis, such as congestion caused by unexpected equipment
outages or other unusual conditions. Furthermore, given the increasing
occurrence of extreme weather events, we expect that assessing the
benefits of broader AAR implementation based on historical congestion
likely understates the potential savings associated with implementation
of the AAR requirements adopted in this final rule. By contrast, the
record demonstrates that AAR implementation costs are predominantly
one-time investment costs in EMS improvements to accommodate AARs,
implementation of a ratings database, and review (and potentially
reset) of protective relays settings.\217\ Once these costs have been
incurred, the incremental cost of applying AARs to additional
transmission facilities is minimal.\218\
---------------------------------------------------------------------------
\216\ NRECA/LPPC Comments at 15.
\217\ Exelon Comments at 8-9.
\218\ Id. at 8; Indicated PJM Transmission Owner Comments at 5-
6; AEP Post-Technical Conference Comments at 2-3; September 2019
Technical Conference, Day 1 Tr. at 180-181.
---------------------------------------------------------------------------
95. Attempts to anticipate the situations in which AARs will not be
cost beneficial (e.g., attempts to forecast locations and situations in
which there will be future congestion and deploy AARs in only those
anticipated situations) will necessarily be imperfect and complex,
especially during infrequent but consequential events. Additionally,
since many emergencies may come and go before new AARs can be developed
and implemented for newly congested transmission lines, a more targeted
AAR requirement advocated by some commenters may not accurately
represent system transfer capability in such critical situations. As
the Commission recognized in the NOPR, congestion is difficult to
predict, particularly during emergency conditions.\219\ The 2019 FERC
and NERC Staff Report on the January 2018 South Central cold weather
event illustrates this point.\220\ As shown by that event, during times
of emergency or system stress, flows may change considerably from
normal operations and the increased transfer capability provided
through AARs may prove valuable even on transmission lines that are not
typically congested.\221\ In addition, in the February 2021 cold
weather event, MISO experienced unprecedented east-to-west flows
throughout the footprint and accrued $773 million in congestion charges
in just a few days.\222\ We note that with broad AAR implementation,
given Potomac Economics' finding that AAR implementation consistently
results in savings of approximately 5% to 8% of total congestion,\223\
congestion cost savings from this single event might have exceeded the
total costs of AAR implementation in the region. Moreover, many argue
that the changing generation mix makes congestion prediction even more
difficult.\224\ Additionally, AAR implementation itself will have
secondary consequences for congestion patterns, as changes to
transmission line ratings may change generation dispatch patterns and,
by extension, congestion patterns. Such secondary congestion
consequences may only be able to be promptly addressed by a broad AAR
requirement that applies to all transmission lines.
---------------------------------------------------------------------------
\219\ NOPR, 173 FERC ] 61,165 at P 93.
\220\ 2019 FERC and NERC Staff Report, The South Central United
States Cold Weather Bulk Electric System Event of January 17, 2018,
at 96 (July 2019) (FERC and NERC Staff Report), https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf.
\221\ NOPR, 173 FERC ] 61,165 at P 93.
\222\ OMS Comments at 10; OMS Reply Comments at 7; see FERC,
NERC and Regional Entity Staff Report, The February 2021 Cold
Weather Outages in Texas and the South Central United States (Nov.
16, 2021), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and.
\223\ Potomac Economics Comments at 8; Potomac Economics Post-
Technical Conference Comments at 5-6.
\224\ ACPA/SEIA Comments at 8, 11; EPSA Comments at 4; New
England State Agencies Comments at 6.
---------------------------------------------------------------------------
96. Beyond congestion costs, during times of stressed system
conditions, operators in RTOs/ISOs might have to
[[Page 2260]]
spend limited time requesting AARs from transmission owners on an ad
hoc basis.\225\ AAR implementation on all transmission lines will help
ensure transmission providers have sufficient transfer capability and
flexibility to manage emergency conditions. Delayed access to AARs
could force transmission operators to spend precious time reaching out
to transmission owners for AARs, rather than using such time to manage
emergency conditions. Instead, AAR implementation on all transmission
lines will alleviate the need for transmission providers to spend time
requesting AARs when there may be no time to waste.
---------------------------------------------------------------------------
\225\ OMS Reply Comments at 7; see also FERC and NERC Staff
Report at 56-59; ISO-NE, Cold Weather Operations: December 24,
2017--January 8, 2018, at 41 (Jan. 16, 2019), https://www.iso-ne.com/static-assets/documents/2018/01/20180112_cold_weather_ops_npc.pdf.
---------------------------------------------------------------------------
97. Further, arguments that the benefits of broad AAR
implementation will not outweigh the costs are inconsistent with the
ERCOT and PJM transmission owners' actual AAR implementation
experience. AEP has been implementing AARs for decades and has realized
both reliability and financial benefits for its customers.\226\ As
Indicated PJM Transmission Owners state, transmission owners in PJM
provide AARs for each of their facility ratings.\227\ PJM further
states that the use of AARs is commonplace among the overwhelming
majority of transmission owners in PJM.\228\ As New England State
Agencies observe, the broad experience implementing AARs does not
support the argument that AARs are too difficult or costly to
implement.\229\
---------------------------------------------------------------------------
\226\ AEP Comments at 3.
\227\ Indicated PJM Transmission Owners Comments at 6-7.
\228\ PJM Comments at 2.
\229\ New England State Agencies Comments at 11-12.
---------------------------------------------------------------------------
98. In response to MISO Transmission Owners' argument that the
Commission should not rely on Potomac Economics' estimates of the
benefits of AARs, our rationale for the AAR requirements adopted in
this final rule is not solely based on Potomac Economics' analysis.
Rather, our rationale is based on the finding that AARs on all
transmission lines will ensure that wholesale rates more accurately
reflect the cost of the wholesale service being provided, and, thus
that those wholesale rates are just and reasonable. This finding is
further informed by the widespread benefits experienced by commenters
implementing AARs broadly in PJM and ERCOT, the expectation that the
benefits of AAR implementation will be greatest on transmission lines
that are frequently congested, along with the understanding of the
difficulty of predicting congestion and the low incremental cost to
implement AARs. However, in response to MISO Transmission Owners'
critique that Potomac Economics' analysis erroneously assumes that all
transmission lines in MISO are ambient adjustable, we note that, in
response to MISO Transmission Owners' comments, Potomac Economics
states that its analysis does not assume that all transmission lines
are able to be rated using AARs and instead removes from the analysis
all transmission lines that currently have summer ratings equal to
winter ratings.\230\ With respect to MISO Transmission Owners' argument
that Potomac Economics' analysis erroneously assumes that all
transmission lines in MISO are currently using worst-case ambient air
temperature assumptions, we note that Potomac Economics does not
uniformly assume worst-case 104 degrees Fahrenheit as the basis for
adjusting AARs, but instead infers unique transmission owner base
assumptions using maximum historical temperatures in each transmission
owner service territory.\231\ Finally, we disagree with MISO
Transmission Owners' assertion that the benefits in Potomac Economics'
analysis are inflated because of certain transmission outages or
upgrades assumptions. As Potomac Economics explains, there are many
generalized and localized factors that might increase or decrease
congestion in an individual year and, given the highly complex nature
of the electric system, incorporating all of these factors is not
possible.\232\ Despite certain generalizations, which we believe are
likely to render Potomac Economics' analysis conservative, Potomac
Economics has consistently found that AARs and emergency ratings will
reduce congestion by 10% to 15% annually.\233\
---------------------------------------------------------------------------
\230\ Potomac Economics Reply Comments at 3-5.
\231\ Id. at 2-3.
\232\ Id. at 5-6.
\233\ Id. at 5.
---------------------------------------------------------------------------
99. We disagree with arguments from Southern Company, EEI, and
other commenters that reliability issues may arise because AARs may
create difficulties in identifying the most limiting element and
similar difficulties and costs associated with complying with
Reliability Standard PRC-023-4's transmission relay loadability
requirements that depend on maximum published ratings. Reliability
Standard PRC-023-4 requires setting transmission line relays at values
at or above 115 to 170% of various maximum values for current or power
carrying capability, e.g., 115% of the highest seasonal 15-minute
Facility Rating of a circuit or 150% of the highest seasonal four-hour
Facility Rating of a circuit. We do not agree that this final rule will
result in PRC-023-4 related relay setting changes to ``thousands''
\234\ of relays, since the relay settings are currently calculated
based on practical limitations which in the majority of cases should
not exceed AAR values. In addition, PJM has long implemented AARs and,
rather than describing reliability challenges, contends that AAR
implementation creates reliability benefits.\235\ For example, PJM
states that the adoption of AARs increases operational flexibility,
promotes a more efficient use of the transmission system, and results
in more reliable system dispatch and cost-effective market
operations.\236\ Transmission owners in PJM have implemented AARs
despite the initial cost incurred to update relay settings. Likewise,
AEP submits that it has implemented AARs for decades and that AAR
implementation presents reliability benefits.\237\
---------------------------------------------------------------------------
\234\ EEI Comments at 5-6.
\235\ PJM Comments at 7.
\236\ Id. at 2.
\237\ AEP Comments at 3.
---------------------------------------------------------------------------
100. In response to concerns about the additional challenges
associated with incorporating AARs into ATC, as raised by Duke Energy,
EEI, and several non-RTO/ISO transmission owners with service
territories in the Western Interconnection, we note that such TTC
calculation practices, and in turn ATC practices, particularly those
which only update TTC values annually,\238\ will need to be updated in
order to comply with this final rule's AAR requirements. In fact, such
practices may already be out of compliance with the Commission's
existing ATC calculation rules. For example, while Order No. 890
provides transmission providers with significant flexibility in what
approach they take to determine ATC in their transmission paths, it
also requires that ATC values (regardless of the approach used to
calculate them) be ``updated and benchmarked to actual events.'' \239\
Furthermore, in May 2021, the Commission issued Order No. 676-J,\240\
in which the Commission (among other things) codified the
``fundamentals of Order No. 890 requirements for calculating ATC'' in
the Commission's regulations.\241\ Specifically, Order No.
[[Page 2261]]
676-J revised section 37.6(b)(2)(i) of the Commission's regulations to
codify that ATC calculations must be ``conducted in a manner that is .
. . consistent with anticipated system conditions and outages for the
relevant timeframe.'' \242\ We find that transmission line ratings
represent one such ``system condition'' with which ATC calculations
must be consistent.
---------------------------------------------------------------------------
\238\ EEI Comments at 11.
\239\ Order No. 890, 118 FERC ] 61,119 at P 290.
\240\ Standards for Business Practices and Communication
Protocols for Public Utilities, Order No. 676-J, 86 FR 29491 (June
2, 2021), 175 FERC ] 61,139 (2021).
\241\ Id. P 38.
\242\ Id.
---------------------------------------------------------------------------
101. In response to specific concerns from PacifiCorp and BPA about
nomogram constraints, we note that nomogram constraints are typically
used to represent transfer capability on facilities with stability or
voltage limitations. The AAR requirements adopted in pro forma OATT
Attachment M exempt transmission lines whose ratings are not affected
by ambient air temperature.
102. In response to comments from NERC requesting further
consideration of AAR implementation on long transmission lines, and
from LADWP, and other, primarily western transmission owners, which
describe AAR implementation challenges due to the diversity in terrain
and microclimates that western transmission lines traverse, we agree
that longer transmission lines can and will experience differing
weather conditions across the length of those transmission lines. To
maintain reliable system operations, we expect transmission providers
to implement the transmission line rating calculated based on the most
limiting element under the prevailing weather conditions (actual or
anticipated) at the relevant point on the transmission line. In the
case of transmission conductors, which might be exposed to different
weather conditions along the length of the transmission line,
transmission providers must rate such elements using the most limiting
weather conditions, in accordance with good utility practice. However,
this requirement does not require the installation of field devices or
sensors, as some transmission owners suggest.\243\ Rather, as proposed
in the NOPR, the AAR requirements can be met through the use of a
weather data service.\244\
---------------------------------------------------------------------------
\243\ WAPA Comments at 7-9; PG&E Comments at 9-10.
\244\ NOPR, 173 FERC ] 61,165 at P 95.
---------------------------------------------------------------------------
103. Similarly, in response to comments from BPA that if BPA uses
AARs as proposed, it would need to make its current liberal wind
assumptions (and therefore, the resultant transmission line ratings)
more conservative to mitigate the risk of operating near the conductor
limit,\245\ we reiterate that the AAR requirements will ensure more
accurate transmission line ratings, not necessarily higher transmission
line ratings. We further clarify that there is no requirement to change
wind speed assumptions. Utilities have operated reliably for decades
with AARs.\246\ However, if any transmission owner finds it necessary
to change its wind speed assumptions consistent with good utility
practice, we clarify that nothing in this rulemaking prevents it from
doing so.
---------------------------------------------------------------------------
\245\ BPA Comments at 4.
\246\ AEP Comments at 3.
---------------------------------------------------------------------------
2. Specific AAR Implementation Requirements
a. Use of AARs 10-Days Forward in Transmission Service and Operations
i. NOPR Proposal
104. In the NOPR, within the context of the AAR requirements
described and adopted above in Section IV.B.1, the Commission proposed
to apply the AAR requirements to transmission service that starts/ends
within 10 days, to the curtailment or interruption of point-to-point
transmission service anticipated to occur (start and end) within the
next 10 days, and to the curtailment of network transmission service or
secondary service or redispatch network transmission service or
secondary transmission service anticipated to occur (start and end)
within 10 days (hereinafter referred to as the ``10-day threshold'').
105. The Commission justified the proposed 10-day threshold as a
reasonable cut-off beyond which forecasts may not be accurate enough
for AARs to provide significant value, and by stating that the
Commission believed that such a limit would reasonably accommodate
requests for weekly point-to-point transmission service. The Commission
further noted that ambient air temperature forecasts for intervals
beyond the proposed 10-day threshold tend to converge to the longer-
term ambient air temperature forecasts used in seasonal line
ratings.\247\ Finally, the Commission noted that its proposal allowed
transmission providers to determine (consistent with good utility
practice) the needed degree of certainty when constructing their
forecasts of ambient air temperature.\248\
---------------------------------------------------------------------------
\247\ NOPR, 173 FERC ] 61,165 at PP 87-88.
\248\ Id. P 102.
---------------------------------------------------------------------------
106. With respect to RTOs/ISOs, the Commission proposed to require
AARs as the relevant transmission line rating for any point-to-point
transmission service offered (e.g., at their borders). However, the
Commission also recognized that RTOs/ISOs have Commission-approved
variations from the pro forma OATT to manage internal congestion and
initiate curtailments and/or redispatch of transmission service within
their footprints through mechanisms such as SCED and SCUC. To
accommodate these variations, the Commission proposed that RTOs/ISOs
comply with the proposed requirements by revising their OATTs to
require implementation of AARs within their SCED and SCUC models (and
in any relevant related models) in both the day-ahead and real-time
markets and any intra-day RUC processes. For real-time markets, the
Commission proposed that RTOs/ISOs update their AARs at least hourly.
For any point-to-point transmission service offered by RTOs/ISOs (e.g.,
at their borders), the Commission proposed that the AAR requirements
discussed above for point-to-point transmission service would apply. As
justification, the Commission explained that day-ahead markets already
rely upon forecasts of weather to inform next-day load and intermittent
generation availability. The Commission preliminarily agreed with PJM
that temperatures can be forecast with a reasonable degree of certainty
in day-ahead markets.\249\ The Commission further stated that, within
its NOPR proposal, transmission providers could (consistent with good
utility practice) determine the needed degree of certainty when
constructing their forecasts of ambient air temperature, and that,
because one of the goals of the day-ahead market is to align prices
with those eventually determined in the real-time market, maintaining
policy consistency between the day-ahead and real-time markets, where
practical, is desirable.\250\
---------------------------------------------------------------------------
\249\ PJM Post-Technical Conference Comments at 3.
\250\ NOPR, 173 FERC ] 61,165 at P 102.
---------------------------------------------------------------------------
ii. Comments
107. Many commenters generally support the Commission's proposed
AAR requirements without specifically discussing the 10-day
threshold.\251\ Industrial Customer Organizations specifically agree
with the Commission that implementing AARs in near-term transmission
service will more accurately reflect the cost of delivering
[[Page 2262]]
energy to load.\252\ CEA states that using AARs to calculate
transmission line ratings for service requests up to 10 days has proven
to be reliable and to provide benefits to effective and reliable
transmission operations.\253\ EDFR contends that the distinction
between AARs and seasonal line ratings depending on the applicable time
frame appears sensible.\254\ ACPA/SEIA state that they support the
Commission's proposed requirements for near-term point-to-point
transmission service and curtailments expected to occur within the next
10 days.\255\ The Ohio FEA does not take a firm position, but states
that implementing AARs for the next 10 days is reasonable.\256\ OMS
states that the weather data required to implement AARs is already
widely available through public sources and used for load and resource
forecasting.\257\
---------------------------------------------------------------------------
\251\ EPSA Comments at 2; Clean Energy Parties Comments at 2-3;
R Street Institute Comments at 2-3; TAPS Comments at 1-3; ACORE
Comments at 3; OMS Comments at 2; New England State Agencies
Comments at 10; Vistra Comments at 2-3.
\252\ Industrial Customer Organizations Comments at 4-6.
\253\ CEA Comments at 2.
\254\ EDFR Comments at 7.
\255\ ACPA/SEIA Comments at 16-17.
\256\ Ohio FEA Comments at 5.
\257\ OMS Comments at 11.
---------------------------------------------------------------------------
108. While not supporting or opposing the proposed 10-day
threshold, EPRI recommends an independent assessment that documents the
accuracy and risk associated with weather forecast data, explaining
that not all weather forecast data will be appropriate for transmission
line ratings and that some limiting spans run through microclimates.
EPRI further explains that inaccurate forecast risks can be mitigated
by identifying and implementing corrective factors to allow forecasts
to be used consistent with good utility practice. EPRI suggests
utility-specific rating studies would be required to assess and
mitigate forecast risk,\258\ to update and revise weather condition
assumptions, and possibly to adjust transmission reliability
margins.\259\ EPRI contends that further studies are needed to
determine a technical basis for updated wind speed assumptions and that
such studies may take between one and two years.\260\ Similarly, NERC
asserts that the Commission should consider how variations in the
temperature and load forecast should be addressed, what temperature
sets should be used when considering requests to grant firm
transmission service, and whether additional AAR calculation
information should be incorporated into transmission line rating
methodologies.\261\
---------------------------------------------------------------------------
\258\ EPRI Comments at 10-11.
\259\ Id. at 12. Transmission reliability margin, or TRM, means
the amount of TTC necessary to provide reasonable assurance that the
interconnected transmission network will be secure, or such
definition as contained in Commission-approved Reliability
Standards. 18 CFR 37.6(b)(1)(viii) (2021)..
\260\ EPRI Comments at 12.
\261\ NERC Comments at 7.
---------------------------------------------------------------------------
109. Other commenters also discuss risk management for forecasted
ambient air temperatures. For example, Entergy states that forecasted
ambient air temperatures should include appropriate safety margins to
account for historical forecast uncertainty.\262\ Similarly, the SPP
MMU states that, ideally, congestion costs should, to some extent,
represent the risk assumed to serve the load.\263\ Finally, the CAISO
DMM argues that AAR requirements should allow leeway for RTOs/ISOs to
adjust modeled transmission limits for reliability reasons, as CAISO
does in the case of flowgates and nomograms whose modeled flows
frequently differ from actual flows.\264\ The CAISO DMM asserts that
lower or more conservative transmission limits might be needed for
temporally distant intervals to ensure commitments made in an advisory
interval horizon are feasible in the binding market interval and at the
time of power flow. The CAISO DMM further asserts that lower day-ahead
transmission limits could promote the feasibility of day-ahead
commitments in real time.\265\
---------------------------------------------------------------------------
\262\ Entergy Comments at 11.
\263\ SPP MMU Comments at 1.
\264\ CAISO DMM Comments at 3, 4-5, 7.
\265\ Id. at 3.
---------------------------------------------------------------------------
110. Many RTOs/ISOs, however, oppose or urge caution on the
proposed 10-day threshold, with many advocating instead for a 48-hour
threshold.\266\ PJM does not support use of AARs in ATC calculations
beyond 48 hours, arguing that it would require significant system
changes and increase the compliance burden.\267\ PJM proposes AARs for
48 hours, and a more conservative approach for hours 48-240 to avoid
potential volatility and over-selling.\268\ Both NYISO and ISO-NE argue
that the transmission service offered in their respective regions
differs from that contemplated by the pro forma OATT, and request
flexibility in implementing any transmission line rating
requirements.\269\
---------------------------------------------------------------------------
\266\ PJM Comments at 7-8; ISO-NE Comments at 10; MISO Comments
at 10, 16-17; NYISO Comments at 13-14.
\267\ PJM Comments at 7-8.
\268\ Id.
\269\ ISO-NE Comments at 10; NYISO Comments at 9.
---------------------------------------------------------------------------
111. NYISO does not support extending the AAR requirements or DLRs
into the day-ahead market, or for use up to 10 days into the future,
contending that such a requirement could result in costly and
unnecessary uplift payments, which could lead to significant cost
increases to customers, and could present reliability concerns if
transmission line ratings decline in real time from the day-ahead
schedule, forcing NYISO to rapidly reduce the schedules of certain
generators while quickly ramping up other generators.\270\ NYISO also
states that it would consider designating a portion of transfer
capability to be able to respond to the operational and cost volatility
that would come with DLR use, although such a process would limit
overall efficiency and increase production costs.\271\
---------------------------------------------------------------------------
\270\ NYISO Comments at 13-14.
\271\ Id.
---------------------------------------------------------------------------
112. Without taking a position on the proposed 10-day threshold,
CAISO explains that the NOPR proposal would significantly increase the
complexity of its day-ahead market and introduce possible variances
between real-time and day-ahead schedules.\272\ Also without taking a
position on the proposed 10-day threshold, SPP states that, to use AARs
to evaluate transmission service requests that end within 10 days or as
the basis for curtailment, SPP would have to make several technical and
process upgrades and align its operating horizon and planning
horizon.\273\
---------------------------------------------------------------------------
\272\ CAISO Comments at 9-11.
\273\ SPP Comments at 5-7, 9.
---------------------------------------------------------------------------
113. MISO argues that the vast majority of the benefit from AARs is
in addressing real-time congestion, and that implementing AARs in
MISO's day-ahead market would be difficult to do in less than three
years, while offering comparatively little benefit. MISO further claims
that requiring hourly AARs 10 days in advance will provide little to no
benefit because the accuracy of temperature forecasts diminishes
considerably beyond 48 hours, and precipitously by the five to seven
day mark.\274\ MISO urges the Commission to limit AAR implementation to
48 hours from the start of the operating day.\275\ Similarly, Potomac
Economics recommends that the Commission require that AARs be used in
the day-ahead and real-time markets, stating that this will allow the
RTOs/ISOs to focus their resources on improving the transmission line
ratings that will generate almost all of the savings.
---------------------------------------------------------------------------
\274\ MISO Comments at 18.
\275\ Id. at 19.
---------------------------------------------------------------------------
114. Similar to RTOs/ISOs, transmission owners also urge caution
on, or oppose, the proposed 10-day threshold.\276\ Those transmission
[[Page 2263]]
owners generally argue that there is too much risk forecasting 10 days
forward and generally support more limited forecasting of either 24
\277\ or 48 hours.\278\ For example, Indicated PJM Transmission Owners
contend that forecasting AARs beyond two or three days in advance
provides little benefit because weather conditions beyond that are too
difficult to predict.\279\ Dominion similarly argues there is no
benefit to extending the AAR requirements beyond three to five days
because forecasts beyond five days tend to reflect seasonal
averages.\280\ Entergy contends that forecasts should be limited to
three days and include appropriate safety margins for historical
forecast uncertainty and geographic variability.\281\
---------------------------------------------------------------------------
\276\ BPA Comments at 7; Indicated PJM Transmission Owners
Comments at 2; Dominion Comments at 8-9; Duke Energy Comments at 8-
9; SDG&E Comments at 2-3; Southern Company Comments at 5-6; MISO
Transmission Owners Comments at 15-16; EEI Comments at 10-11; APS
Comments at 8; NYTOs Comments at 5-6; AEP Comments at 6-7; NRECA/
LPPC Comments at 19-20; SDG&E Comments at 2-3; LADWP Comments at 7;
ITC Comments at 7-9.
\277\ BPA Comments at 7; Duke Energy Comments at 8-9; Southern
Company Comments at 5-6; MISO Transmission Owners Comments at 15-16;
EEI Comments at 10-11; APS Comments at 8; NYTOs Comments at 5-6.
\278\ AEP Comments at 6-7; NRECA/LPPC Comments at 19-20; SDG&E
Comments at 2-3; LADWP Comments at 7.
\279\ Indicated PJM Transmission Owners Comments at 2.
\280\ Dominion Comments at 9.
\281\ Entergy Comments at 11.
---------------------------------------------------------------------------
115. Several commenters argue that requiring AARs 10 days in
advance presents the potential problem of selling transmission service
based on a given ambient air temperature forecast only for the
temperature to be higher in real time, causing curtailments or safety
and reliability risks.\282\ BPA argues that it could result in an
inefficient use of the transmission system because transmission could
be sold, curtailed, and then available again, all prior to the
transmission service window.\283\ NYTOs note that, because there is
generally less flexibility in real time, if operators do not have
sufficient resources to restore flow to a lower limit within the
required time, they may need to shed load or damage equipment.\284\
---------------------------------------------------------------------------
\282\ MISO Transmission Owners Comments at 15-16; Duke Energy
Comments at 8-9; Southern Company Comments at 5-6; NYTOs Comments at
5.
\283\ BPA Comments at 7.
\284\ NYTOs Comments at 5-6.
---------------------------------------------------------------------------
116. Arguing that the Commission should not extend the AAR
requirements beyond the operating day, MISO Transmission Owners state
that using AARs any further forward than in real time introduces
uncertainty and error. MISO Transmission Owners acknowledge that these
risks exist today, but argue that AARs introduce further complexity and
explain that lowering transmission line ratings in real time would
compound the problems.\285\ Similarly, Duke Energy presents an example
of transmission sold based on a 60 degree Fahrenheit temperature
forecast four days forward and, on the operating day having the
transmission system oversubscribed, with greater pressure on operators
to curtail transmission schedules to avoid safety and reliability
risks, because the actual temperature was 75 degrees Fahrenheit.\286\
Southern Company states that AARs have the potential to create
reliability concerns if transmission service is oversold due to
inaccurate weather forecasts, especially for transmission service that
is scheduled 10 days ahead.\287\ Southern Company also states that
reliability issues may arise because AARs may create difficulties in
identifying the most limiting element, which may change as the
temperature changes, for the purpose of complying with Reliability
Standard FAC-008-5, and similar difficulties in complying with
Reliability Standard PRC-023 relay loadability requirements that depend
on maximum published ratings.\288\
---------------------------------------------------------------------------
\285\ MISO Transmission Owners Comments at 15-16.
\286\ Duke Energy Comments at 8-9.
\287\ Southern Company Comments at 5-6.
\288\ Id. at 6.
---------------------------------------------------------------------------
117. NRECA/LPPC contend that such a requirement is unduly
burdensome because most of the benefits of using AARs are for real-time
and day-ahead transactions. NRECA/LPPC add that hourly weather
forecasts and the resulting hourly transmission line ratings are
unlikely to be accurate for more than a very few days.\289\ IID
explains that the Commission should provide flexibility in the forward
AAR application period, noting that weather patterns may not be stable
everywhere. IID contends that the Commission should consider
implementation challenges associated with looking 10 days ahead,
calculating what could be several hundred transmission line ratings per
year.\290\
---------------------------------------------------------------------------
\289\ NRECA/LPPC Comments at 19-20.
\290\ IID Comments at 4-6.
---------------------------------------------------------------------------
118. EEI and APS contend that AARs should only be implemented in
real-time operations.\291\ EEI contends that such AAR values should not
extend to the day-ahead or intra-day unit commitment values and that
hourly ATC for up to 10 days would introduce uncertainty and ATC
fluctuations that result in curtailment of sold service and resale of
previously curtailed service. EEI further explains that the Commission
has previously recognized the reliability harm associated with
overestimated ATC and explains that the harm may result from using
hourly AARs for transmission service available for up to 10 days. EEI
also states that the NOPR proposal for hourly ATC for every hour in the
next 10 days is complex, with a burden that may outweigh the benefits
since the NOPR proposal fundamentally requires a TTC determination.
However, EEI states that TTC is path dependent and is based on many
transmission line ratings, contingencies, and power flow assumptions.
Because of this complexity, some transmission owners only determine TTC
annually or less frequently and, for these transmission owners, the
NOPR proposal for transmission providers to recalculate TTC every hour,
and perform 240 calculations every hour, is infeasible.\292\ NERC
contends that the Commission should consider how entities should
reconcile AARs used for planning and operations functions. NERC also
argues that there is potential confusion regarding transmission line
ratings used in transmission operator operations and planning system
operating limits and interconnection reliability operating limits, but
believes the confusion can be avoided through the timing of Commission
action to retire the NERC Modeling, Data, and Analysis (MOD) A
Reliability Standards.\293\
---------------------------------------------------------------------------
\291\ APS Comments at 8; EEI Comments at 10-12.
\292\ EEI Comments at 10-12.
\293\ NERC Comments at 7-8.
---------------------------------------------------------------------------
119. NYTOs explain that requiring AARs for up to 10 days forward,
even for a subset of the transmission system, would be a significant
change requiring major software buildout and corresponding market
design changes, which would create a significant burden on NYISO and
its associated utilities. NYTOs assert that this burden would be
further complicated by the fact that vendor availability for such a
buildout is unknown.\294\ NYTOs also explain that implementing AARs 10
days forward has the potential to create reliability concerns through
disconnects between forecasted and real-time conditions \295\ and that
extending the AAR requirements to the day-ahead market would make
security analysis more difficult.\296\ LADWP contends that the
Commission should align any final rule requirements with NERC
Reliability Standards and asserts that the proposed 10-day threshold
would conflict with
[[Page 2264]]
the requirements specified in Reliability Standard MOD-001-1a that ATC
be calculated hourly for the next 48 hours.\297\ Moreover, recognizing
the variability in weather, LADWP asks that system operators be
afforded the flexibility to recall transfer capability awarded during
moderate conditions at least 24 hours in advance.\298\
---------------------------------------------------------------------------
\294\ NYTOs Comments at 5-6.
\295\ Id.
\296\ Id. at 7.
\297\ LADWP Comments at 7.
\298\ Id. at 6.
---------------------------------------------------------------------------
iii. Commission Determination
120. We adopt the NOPR proposal to require transmission providers
to use AARs when evaluating the availability of and requests for near-
term transmission service (under sections 15, 17, 18, and 29 of the pro
forma OATT) \299\ as set forth under ``Obligations of Transmission
Provider'' in the pro forma OATT Attachment M adopted in this final
rule. We further adopt the Commission's proposal in the NOPR to require
transmission providers to use AARs as the relevant transmission line
rating when determining whether to curtail or interrupt point-to-point
transmission service (under sections 13.6 and/or 14.7 of the pro forma
OATT) if such curtailment or interruption is both necessary because of
issues related to flow limits on transmission lines and anticipated to
occur (start and end) within the next 10 days. Additionally, we adopt
the Commission's proposal in the NOPR to require transmission providers
to use AARs as the relevant transmission line rating when determining
whether to curtail network or secondary service (under section 33 of
the pro forma OATT) or redispatch network or secondary service (under
sections 30.5 and/or 33 of the pro forma OATT), if such curtailment or
redispatch is both necessary because of issues related to flow limits
on transmission lines and anticipated to occur (start and end) within
10 days of such determination (i.e., the 10-day threshold). Finally,
consistent with the NOPR, we clarify that AARs must be calculated using
the temperature at which there is sufficient confidence that the actual
temperature will not be greater than that temperature (i.e., expected
temperature plus an appropriate forecast margin).\300\
---------------------------------------------------------------------------
\299\ See supra P 85.
\300\ See NOPR, 173 FERC ] 61,165 at PP 97, 102.
---------------------------------------------------------------------------
121. We believe that the 10-day threshold is justified by: (1) The
additional benefits gained by adopting a threshold that permits weekly
point-to-point transmission service requests to be evaluated using
AARs; (2) the additional benefits gained by the use of daytime/
nighttime ratings (discussed below in Section IV.B.2.c) within the 10-
day threshold; (3) the adequate accuracy of ambient air temperature
forecasts combined with the ability to implement appropriate forecast
margins to alleviate operational concerns associated with persistently
decreasing real-time transmission line ratings; and (4) the low
relative cost difference between a shorter forward threshold and the
proposed 10-day threshold. As the Commission stated in the NOPR, AAR
requirements up to 10 days forward will permit weekly point-to-point
transmission service to be evaluated using AARs. Because weekly point-
to-point transmission service is one of several types of transmission
products provided under the Commission's pro forma OATT, by adopting
the 10-day threshold for AAR implementation rather than a shorter
forward duration, weekly point-to-point transmission customers will
receive the benefits of AAR implementation rather than only
transmission customers taking shorter duration transmission service,
thereby not just increasing the expected benefits from the
implementation of AARs by improving the accuracy of transmission line
ratings for a wider range of transmission services but also for a
potentially wider range of transmission customers.
122. We also require AARs to include separate daytime and nighttime
ratings. This daytime/nighttime ratings requirement, combined with the
addition of weekly point-to-point transmission service, will produce
further benefits in forward nighttime hours that would not see such
benefits if the AAR requirements were imposed over a timeframe shorter
than 10 days forward. These benefits of increased accuracy that result
from applying daytime/nighttime ratings to weekly point-to-point
transmission service and to shorter duration transmission service up to
10 days forward are significant on their own, even in the unlikely
event that the use of ambient air temperature forecasts 10 days forward
results in no hours where daytime AARs are greater than seasonal line
ratings. In other words, if we were to adopt a shorter threshold for
the AAR requirements than 10 days forward, the significant benefits
derived from the more accurate transmission line ratings during the
additional nighttime hours included in the 10-day threshold would be
lost. We further note that weather forecast quality is not static, but
rather is steadily improving such that the benefits of the 10-day
threshold requirement are likely to increase over time.\301\
---------------------------------------------------------------------------
\301\ See, e.g., NOAA, Annual WPC Mean Absolute Errors, https://www.wpc.ncep.noaa.gov/images/hpcvrf/maemaxyr.gif (last visited Oct.
28, 2021) (showing NOAA data on the evolving accuracy of their
Weather Prediction Center forecasts of daily high temperature).
---------------------------------------------------------------------------
123. Although we acknowledge that the accuracy of forecasts
decreases the further in advance the forecast is made, we disagree that
ambient air temperature forecasts made 10 days in advance are so
inaccurate that they cannot provide any benefits when used as part of
AARs, even when adjusted with appropriate forecast margins, as
discussed herein. Neither commenters supporting nor opposing the 10-day
threshold provide quantitative evidence related to the accuracy of 10-
day forecasts; however, a published analysis of the NOAA National Blend
of Models (NBM) forecast--one of the publicly available NOAA forecasts
that looks out at least 10 days--indicates that the mean absolute error
for 240 hour (10 day) forward continental United States surface
temperature forecasts was approximately four to six degrees Fahrenheit
in July to November 2016.\302\ We find that such levels of error would
likely allow for a meaningful number of hours in any season where a 10-
day forward AAR would provide benefits relative to the seasonal line
rating. We also note that this finding is consistent with the support
for the 10-day threshold by various commenters.\303\
---------------------------------------------------------------------------
\302\ Tabitha Huntemann, Daniel Plumb, and David Ruth,
Verification of the National Blend of Models (2017), https://www.weather.gov/media/mdl/AMS2017-NBMVerification.pdf. We note that
this analysis was applicable to the 2016 National Blend of Models
(NBM) Version 2.0 forecast, and that several improved versions of
the NBM forecast have been implemented since that time. The current
NBM Version 4.0 was implemented in September 2020. See NBM: National
Blend of Models, https://vlab.noaa.gov/web/mdl/nbm. While we take
notice of this NBM forecast accuracy data as a point of reference,
we emphasize that the NBM forecasts are just one example of the
types of forecasts that transmission providers might rely on in
complying with this final rule.
\303\ CEA Comments at 2; EDFR Comments at 7; Ohio FEA Comments
at 5; New England State Agencies Comments at 9-10; ACPA/SEIA
Comments at 13.
---------------------------------------------------------------------------
124. We do not find persuasive arguments that the AAR requirements
adopted in this final rule will be unduly burdensome. Contrary to such
assertions, because we expect the increased costs of implementing AARs
under a 10-day threshold (as opposed to a shorter threshold) to be
primarily related to increased forecasting and data storage/hardware
needs, we do not expect such costs to be excessive. Moreover, in
certain situations, especially outside the RTO/ISO context, adopting
the 10-day threshold will
[[Page 2265]]
allow more transfer capability to be made available to customers than
simply adopting seasonal worst-case assumptions. In addition, as CEA
states, using AARs to calculate transmission line ratings for service
requests up to 10 days has proven to be reliable and to provide
benefits to effective and reliable transmission operations.\304\ In
that context, commenters have not provided evidence that the cost to
procure or develop 10-day forward forecasts is materially different
from the cost to procure or develop two- or three-day forward forecasts
and, in any case, that such cost outweighs the added benefits of
extending the forward period from two or three days to 10 days. For
these reasons, we expect the material benefits resulting from adopting
the 10-day threshold to, on balance, outweigh the costs.
---------------------------------------------------------------------------
\304\ CEA Comments at 2.
---------------------------------------------------------------------------
125. We emphasize that any benefit from the AAR requirements, and
the 10-day threshold in particular, should be compared to the relative
costs of alternatives. And we find that the cost associated with
requiring AARs for additional days forward is essentially the cost of
accessing, storing, and processing the additional forecast data, and
the cost of calculating, storing, and incorporating into transmission
service the additional hours of AARs. As we expect this process will be
largely automated, we do not anticipate that the cost of the 10-day
threshold, as opposed to a shorter threshold, will be significantly
higher. Although the question of where to draw the line in terms of the
time threshold for AAR implementation is not clear cut, we find that 10
days strikes an appropriate balance between the benefits of more
accurate transmission line ratings that result from the AAR
requirements adopted in this final rule, and the likely costs of
implementing those requirements.
126. We note that some commenters may have misunderstood the
Commission's proposal in the NOPR as requiring the use of expected
ambient air temperatures in forecasts of AARs for future periods. That
is, they may have read the Commission's NOPR proposal as requiring that
if the forecasted ambient air temperature at a given transmission line
10 days in advance (without any forecast margin applied, i.e., the
expected temperature) was X degrees, that the transmission provider was
required to use an AAR for that hour 10 days forward that assumed an
air temperature of X degrees. This is not the case. Rather, AARs must
be calculated using the temperature at which there is sufficient
confidence that the actual temperature will not be greater than that
temperature (i.e., expected temperature plus an appropriate forecast
margin).\305\ This approach to calculations is consistent with EPRI's
recommendation and also comments from Entergy and the CAISO DMM, which
suggest margins to account for forecast error.\306\
---------------------------------------------------------------------------
\305\ See NOPR, 173 FERC ] 61,165 at PP 97, 102.
\306\ EPRI Comments at 10-12; Entergy Comments at 11; CAISO DMM
Comments at 3.
---------------------------------------------------------------------------
127. In response to requests for clarification from BPA, LADWP, and
EEI that transmission providers can curtail transmission sold at least
24 hours in advance, consistent with existing curtailment
prioritization, should temperature forecasts dictate such curtailment,
we confirm that we are not changing the existing curtailment
prioritization. In implementing the 10-day threshold, it may be
necessary in some instances for transmission providers to curtail
transmission sold based on ambient air temperature forecasts (including
forecast margins) that end up being lower than real-time temperatures.
Although transmission providers will continue to curtail transmission
at times due to unrealized ambient air temperature assumptions, the
need for such curtailments should be decreased as a result of the AAR
requirements adopted herein.\307\ We reiterate that under the AAR
requirements that we adopt in this final rule, transmission providers
have the latitude (and obligation) to develop accurate, safe, and
reliable transmission line ratings,\308\ and we do not expect that such
transmission line ratings will necessitate an increase in the need for
curtailments due to inaccurate AARs. If a transmission provider
determines (whether during pre-testing of its AAR methodologies or
during actual operations) that a given level of forecast margins yields
an unreasonable frequency of such curtailment, it should re-evaluate
and adjust its forecast margins.
---------------------------------------------------------------------------
\307\ We note, for example, that a typical winter seasonal line
rating temperature assumption today is 32 degrees Fahrenheit--a
temperature assumption which in many parts of the United States is
violated frequently over the current typical six-month ``winter
season'' used in seasonal line ratings. Commission Staff Paper at 7;
see also Midwest Reliability Organization Standards Committee,
Standard Application Guide: FAC-008, Version 1.1, p. 14 (March 21,
2017), https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/FAC-008-3%20Standard%20Application%20Guide.pdf. We expect such assumption
violations to be less frequent under our required approach, where
transmission providers will apply reasonable forecast margins when
developing their AARs
\308\ NOPR, 173 FERC ] 61,165 at P 97.
---------------------------------------------------------------------------
128. We further acknowledge that, in addition to the concerns of
some commenters related to forecast margins being too low, certain
forecast margins could also prove to be too high. In those instances,
as with the implementation of static transmission line ratings,
transmission line ratings using unreasonably high forecast margins
would also yield inaccurate transmission line ratings and, in turn,
would result in an underutilization of existing transmission
facilities, price signals based on less transfer capability than is
truly available, and wholesale rates that are unjust and unreasonable.
Similar to unreasonably low forecast margins, if a transmission
provider determines (whether during pre-testing of its AAR
methodologies or during actual operations) that a given forecast margin
is unreasonably high, it should re-evaluate and adjust its forecast
margins.
129. Similarly, contrary to comments from CAISO, NYISO, NYTOs, and
EEI that describe the operational risks associated with overestimating
ATC,\309\ we do not expect that the AAR requirements adopted herein
will result in a frequent number of instances when transmission line
ratings used in the real-time market are lower than transmission line
ratings used in the day-ahead market. Some such instances will occur,
but we believe that there is sufficient latitude within our
requirements, as discussed above, for day-ahead transmission line
ratings to be determined with sufficient forecast margins to avoid this
concern. Furthermore, as the Commission stated in the NOPR, day-ahead
markets already rely heavily upon weather forecasts to inform next-day
load and intermittent generation availability. This final rule does not
change reliance upon weather forecasting; instead, the AAR requirements
we adopt herein will improve the accuracy of transmission line ratings
and, if anything, lead to cost savings to consumers and reliability
benefits. Additionally, as PJM's AAR implementation experience
demonstrates, temperatures can be forecast day ahead with a reasonable
degree of certainty.\310\ We also find that operational risks that
might result from the use of transmission line ratings in the real-time
market that are lower than the transmission line ratings used in the
day-ahead market can further be
[[Page 2266]]
managed and mitigated through the use of AARs in the RUC processes,
which will have the benefit of updated temperature forecasts. Finally,
we reiterate that PJM and AEP report reliability benefits from AAR
implementation.
---------------------------------------------------------------------------
\309\ NYTOs Comments at 5-6; EEI Comments at 10-12; NYISO
Comments at 13-14; CAISO Comments at 9-11.
\310\ PJM Comments at 3.
---------------------------------------------------------------------------
130. In response to comments from EEI and other transmission owners
about the complexities of calculating AARs up to the 10-day threshold,
we find that such complexities are predominately reflected in the
upfront set-up and investment costs \311\ and that these costs will be
primarily related to increased forecasting and data storage/hardware
needs.
---------------------------------------------------------------------------
\311\ Exelon Comments at 8; AEP Post-Technical Conference
Comments at 2-3; see also supra Section IV.B.1.c.
---------------------------------------------------------------------------
131. In response to NERC's request that the Commission consider how
entities should reconcile AARs used for planning and operations
functions,\312\ we find that AARs used in near-term operations will
deviate from those transmission line ratings used in various planning
functions. As transmission providers progress closer in time to a given
interval, near-term ambient air temperature forecasts will necessarily
be updated. These updates will impact TTC, and, as a result, ATC and
system operating limits. In addition, regarding implementation of this
final rule and currently effective MOD A Reliability Standards,\313\
this final rule does not advocate for operating the transmission system
beyond the system operating limits and established facility ratings.
---------------------------------------------------------------------------
\312\ NERC Comments at 6-7.
\313\ Id. at 7.
---------------------------------------------------------------------------
132. In response to requests for clarification of the NOPR proposal
from NERC and BPA with respect to temperature variations,\314\
transmission providers must consider the relevant ambient air
temperature forecasts along the transmission line, and determine the
transmission line rating based on the most limiting combination of
equipment limitations and forecasted local ambient air temperature
along the transmission line. We note that NERC additionally requested
that the Commission consider how variations in load forecasts would be
addressed when using values for each of the 240 hours in the next 10
days for each transmission line in granting firm point-to-point
transmission service.\315\ In response, we reiterate that the
requirements adopted herein are designed to ensure accurate
transmission line ratings. We also reiterate that AARs must be
calculated using the temperature at which there is sufficient
confidence that the actual temperature will not be greater than that
temperature (i.e., expected temperature plus an appropriate forecast
margin). We further clarify, in response to NERC, that transmission
line rating methodologies must be updated. In particular, pro forma
OATT Attachment M, as adopted by this final rule, requires transmission
line ratings to be computed in accordance with a written transmission
line rating methodology and consistent with good utility practice.
Moreover, we note that Reliability Standard FAC-008-5 Requirement 3.2
requires transmission line rating methodologies to identify how ambient
conditions are considered.\316\ Thus, transmission line rating
methodologies need to document methods used to calculate AARs.
---------------------------------------------------------------------------
\314\ NERC Comments at 6-7; BPA Comments at 2-4.
\315\ NERC Comments at 6-7.
\316\ Reliability Standard FAC-008-5, Requirement R3.2, p.4,
https://www.nerc.com/pa/Stand/Project%20201803%20Standards%20Efficiency%20Review%20Require/2018-03_FAC-008-5_clean_01192021.pdf.
---------------------------------------------------------------------------
133. In response to LADWP's argument that the Commission should
align AAR requirements with the NERC Reliability Standards--and that
the proposed 10-day threshold would conflict with the requirement
specified in Reliability Standard MOD-001-1a that ATC be calculated
hourly for the next 48 hours--we note that Reliability Standard MOD-
001-1a requires that ATC be calculated for at least the next 48 hours,
not for only the next 48 hours. Furthermore, the Commission's
regulations require ATC to be calculated and/or posted for periods more
than 48 hours in the future (e.g., when transmission service is
requested or inquired about).
134. Finally, in response to RTO/ISO requests for flexibility, we
clarify the applicability of the 10-day threshold to RTOs/ISOs. The
vast majority of energy transactions in RTOs/ISOs are executed and
financially settled in the day-ahead and real-time energy markets;
thus, we find that requiring AARs for the real-time and day-ahead
energy markets in RTOs/ISOs is necessary to ensure the accuracy of
transmission line ratings and just and reasonable wholesale rates.
Because these transactions take place within a one-day forward
timeframe, the 10-day threshold will provide very little additional
benefits in existing RTO/ISO markets. Accordingly, the 10-day threshold
will not apply to internal transactions or internal flows associated
with through-and-out transactions in RTOs/ISOs. However, given that
RTOs/ISOs generally use the pro forma OATT transmission service model
for movement of electricity into/out of their service territories, the
10-day threshold requirement will apply to RTOs/ISOs' evaluation or
determination of availability of transmission service at the seams of
RTO/ISO service territories, in order to improve the accuracy of
transmission line ratings and ensure just and reasonable wholesale
rates.
b. Role of the Transmission Owner and Transmission Provider in AAR
Implementation
i. NOPR Proposal
135. In proposing AAR implementation in the pro forma OATT, the
Commission proposed for transmission providers--not transmission
owners--to implement AARs because transmission providers--not
transmission owners--must have an OATT.\317\
---------------------------------------------------------------------------
\317\ NOPR, 173 FERC ] 61,165 at P 84.
---------------------------------------------------------------------------
ii. Comments
136. Several commenters clarify that transmission owners, not
transmission providers, calculate transmission line ratings.\318\ For
example, MISO states that its formational documents reflect, and have
codified, the responsibility of transmission owners to calculate
facility ratings, not MISO.\319\ MISO Transmission Owners explain that
Reliability Standard FAC-008-5 requires transmission owners to have ``a
documented methodology for determining facility ratings of its solely
and jointly owned Facilities'' based on the electrical characteristics
of the transmission equipment or other industry standard.\320\ Southern
Company states that the MOD suite of NERC Reliability Standards
governing TTC/ATC calculations requires transmission line ratings as
provided by transmission owners.\321\ Similarly, ISO-NE explains that
its Transmission Operating Agreement requires its participating
transmission owners to establish transmission line ratings for each
transmission facility.\322\ Additionally, NYISO states that in the New
York Control Area, the transmission owners are responsible for
developing transmission line ratings and providing the element ratings
directly to NYISO. In turn, according to NYISO, NYISO determines the
most limiting element, which sets the applicable facility rating.\323\
---------------------------------------------------------------------------
\318\ MISO Comments at 27; Vistra Comments at 3-4; TAPS Comments
at 13-14; Southern Company Comments at 6; EEI Comments at 2-4; MISO
Transmission Owners at 29; EEI Comments at 2-4.
\319\ MISO Comments at 27.
\320\ MISO Transmission Owners at 29.
\321\ Southern Company Comments at 3, 6.
\322\ ISO-NE Comments at 6.
\323\ NYISO Comments at 3.
---------------------------------------------------------------------------
[[Page 2267]]
137. Because of these differing transmission owner and transmission
provider roles and responsibilities, these commenters request that the
Commission recognize and make these differing roles explicit in any
final rule.\324\ Some recommend further Commission action to ensure
transmission owners have an obligation to implement the AAR
requirements in proposed pro forma OATT Attachment M. For example,
Vistra encourages the Commission to modify its regulations to create a
compliance obligation for each transmission owner to provide RTOs/ISOs
all information necessary to implement proposed pro forma OATT
Attachment M.\325\ Similarly, TAPS requests that the Commission clarify
that: (1) RTOs/ISOs have the authority to require transmission owners
to provide the information they will need to implement AARs; or (2)
transmission owners within RTOs/ISOs must provide the information RTOs/
ISOs will need to implement AARs to the relevant RTO/ISO.\326\
Additionally, TAPS argues that in order to achieve efficient and
consistent application of AARs, the Commission should direct RTOs/ISOs
to use, or at minimum accommodate the use of, ``look-up tables.'' \327\
TAPS explains that, using the ``look-up table'' approach will limit the
obligation to continuously monitor weather reports to recalculate AARs
and communicate those transmission line ratings to the RTO/ISO on an
hourly basis.\328\
---------------------------------------------------------------------------
\324\ MISO Comments at 27; Vistra Comments at 3-4; TAPS Comments
at 13-14; Southern Company Comments at 6; EEI Comments at 2-4.
\325\ Vistra Comments at 3-4.
\326\ TAPS Comments at 14.
\327\ Id. at 8. TAPS states that, for each of their transmission
facilities, transmission owners should be required to provide RTOs/
ISOs with a table showing their temperature-adjusted rating for a
pre-established set of ambient air temperatures.
\328\ Id. at 8-10.
---------------------------------------------------------------------------
138. Noting the applicability of the pro forma OATT to transmission
providers and that transmission owners and transmission providers are
different in RTO/ISOs, Exelon comments on the phrasing ``is
calculated'' in the AAR definition, explaining that, while it largely
supports the proposed AAR definition, it does not ``calculate''
transmission line ratings hourly. Exelon states that it calculates 64
different transmission line rating cases (for nine temperatures sets,
across normal, long-term emergency, short-term emergency, emergency
load dump, and for both day and night), and then references the
relevant existing calculations in a ``look-up table'' through its
Inter-Control Center Communications Protocol signal. Exelon proposes to
refine the AAR term to: ``a transmission line rating that reflects the
appropriate temperature-adjusted rating for a facility based on an up-
to-date forecast of ambient air temperatures across the time period to
which the rating applies.'' \329\
---------------------------------------------------------------------------
\329\ Exelon Comments at 11-12.
---------------------------------------------------------------------------
139. Finally, CAISO argues that RTOs/ISOs and their stakeholders
will have to answer many questions in developing tariff provisions for
using hourly transmission line ratings. Several of these questions
relate to AAR implementation timelines, including the time hourly
transmission line ratings must be submitted by the transmission owners
to RTOs/ISOs and the time period that transmission owners will have to
update hourly transmission line ratings for use in real-time markets
after day-ahead results are published.\330\ As an example, BPA explains
that its dynamically established TTC calculations are based on
schedules submitted 20 minutes before the operating hour.\331\
---------------------------------------------------------------------------
\330\ CAISO Comments at 12-13.
\331\ BPA Comments at 5.
---------------------------------------------------------------------------
iii. Commission Determination
140. We clarify that transmission owners, not transmission
providers, are responsible for calculating transmission line ratings.
This responsibility is codified in the NERC Reliability Standards, as
well as in RTO/ISO foundational documents.\332\ Nothing in this final
rule changes that responsibility. In the non-RTO/ISO regions, this
detail is generally not a concern because the transmission provider is
usually the transmission owner. However, in the RTO/ISO regions, there
is a distinction between transmission owners and transmission
providers. Thus, in order to comply with this final rule, RTOs/ISOs--
the transmission provider with the OATT on file--will need to rely on
their member transmission owners to calculate transmission line ratings
and provide them to the RTO/ISO.\333\
---------------------------------------------------------------------------
\332\ See, e.g., Reliability Standards FAC-008-5, Requirement R3
and FAC-008-5, Requirement R6.
\333\ We note that, as discussed below, in RTO/ISO regions, in
addition to AARs, transmission owners will be required to calculate
and provide other transmission line ratings to the RTO/ISO,
including seasonal line ratings and emergency ratings. Moreover, in
RTO/ISO regions, transmission owners will be required to provide to
the RTO/ISO the list of transmission lines which have been exempted
from the AAR requirement (under the ``Exceptions'' paragraph of pro
forma OATT Attachment M) or temporary alternate ratings (under the
``System Reliability'' section of pro forma OATT Attachment M).
---------------------------------------------------------------------------
141. In response to concerns about the responsibility for
calculating transmission line ratings in RTOs/ISOs, we clarify that we
expect RTOs/ISOs to require their member transmission owners to make
timely calculations and determinations as required for transmission
line ratings, and to provide them to the RTO/ISO.\334\ Where the
transmission provider is not the transmission owner (e.g., RTOs/ISOs),
we require the transmission provider to explain in its compliance
filing, as part of its implementation of the new pro forma OATT
Attachment M, through what mechanism (tariff, membership agreement,
etc.) the transmission owner(s) will have the obligation for making and
communicating to the transmission provider the timely calculations and
determinations related to transmission line ratings (including the
exercise of any discretion in calculations or application of
exceptions).
---------------------------------------------------------------------------
\334\ See, e.g., MISO, MISO Rate Schedules, MISO Transmission
Owner Agreement, art. 4, Sec. II.A Providing Information (30.0.0)
(``Each Owner and User shall provide such information to [MISO] as
is necessary for [MISO] to perform its obligations under this
Agreement and the Tariff.''); SPP, Governing Documents Tariff,
Membership Agreement, Sec. 3.5 Providing Information (0.0.0)
(``Member shall provide such information to SPP as is necessary for
SPP to perform its obligations under this Agreement and the OATT,
and for planning and operational purposes.''); PJM, Rate Schedules,
Sec. 4.11 Transmission Facility Ratings (0.0.0) (``All Parties
shall regularly update and verify Transmission Facility ratings,
subject to review and approval by PJM, in accordance with the
following procedures and the procedures in the PJM Manuals . . .
.''); ISO-NE, ISO New England Inc. Agreements and Contracts,
Transmission Operating Agreement, Sec. Sec. 3.02(a)(ii) (5.0.0)
(stating that ISO-NE shall ``determine Operating Limits based on
forecasted or real-time system conditions and in accordance with the
facility ratings established by the PTOs in collaboration with the
ISO pursuant to Section 3.06''), 3.06(a)(v) (5.0.0) (stating that
the transmission owner shall: ``(v) Collaborate with the ISO with
respect to: (A) The development of Rating Procedures, (B) the
establishment of ratings for each PTO's New Transmission Facilities;
(C) the establishment of ratings for each PTO's Acquired
Transmission Facilities that do not have an existing rating as of
the Operations Date, and (D) the establishment of any changes to
existing ratings for Transmission Facilities in effect as of the
Operations Date''); CAISO, CAISO eTariff, Transmission Control
Agreement, Sec. 4.2 (0.0.0) (stating that facility ratings are
required CAISO's database of all facilities under the CAISO's
control and that transmission owners are responsible for providing
updates to that database when there is a change in ratings, which
CAISO reviews).
---------------------------------------------------------------------------
142. In response to Exelon's concerns about the proposed AAR
definition,\335\ we clarify that hourly (or more frequent) querying of
``look-up tables'' or similar pre-calculated AAR databases will satisfy
the requirement that AARs be calculated at least each hour. While we
expect transmission owners to calculate transmission line ratings,
given the difference between transmission owners and transmission
providers in RTOs/ISOs, we require RTOs/ISOs on compliance to propose
and justify a
[[Page 2268]]
methodology for AAR implementation, delineating the expected roles
between transmission owners and transmission provider. In doing so, we
encourage RTO/ISO transmission owners to coordinate implementation
methodologies and promote implementation consistency to the greatest
extent possible within an RTO/ISO service territory. However, in
response to comments from TAPS that the Commission should require use
of a ``look-up table'' approach, or at least require that approach be
an option,\336\ we decline to require a specific AAR implementation
methodology, noting regional software and procedural differences.
---------------------------------------------------------------------------
\335\ Exelon Comments at 11-12.
\336\ TAPS Comments at 7-10.
---------------------------------------------------------------------------
143. In response to requests for clarification from CAISO, we
decline to require in this final rule a specific timeline by which AARs
will need to be calculated or submitted to the transmission provider
(either in the context of the day-ahead and real-time markets in RTOs/
ISOs, or in terms of how far in advance of an operating hour an AAR
should be calculated in a bilateral market).\337\ However, we note that
the AAR definition we adopt in this final rule requires that AARs
``[r]eflect[] an up-to-date [emphasis added] forecast of ambient air
temperature across the time period to which the rating applies,'' by
which we mean that new forecast data should be incorporated into AAR
calculations as close to real time as reasonably possible given the
timelines needed to obtain forecast data and perform the AAR
calculation, as well as any other steps needed for validation,
communication, or implementation of AARs.\338\ Furthermore,
transmission providers must explain their timelines as part of their
compliance filings. We recognize that transmission providers already
manage similar timing issues with respect to load forecasts, forecasts
for renewable energy production, and generation bid deadlines, and it
may be that deadlines for AAR calculation/submission are not
significantly different from existing deadlines for submission of
updates to generation supply offers and load.
---------------------------------------------------------------------------
\337\ We note that in some instances RTOs/ISOs may propose (as
we understand PJM does now for its AARs) to have the RTO/ISO select
AARs based on temperature forecasts and pre-calculated AAR tables/
databases. In such cases, it may not be (as CAISO's comments
suggest) that transmission owners will be sending entire sets of
AARs to RTOs/ISOs every time they are calculated.
\338\ Pro Forma OATT attach. M, AAR Definition.
---------------------------------------------------------------------------
c. Solar Heating in AAR Calculations
i. NOPR Proposal
144. In the NOPR, the Commission proposed to require AARs that
reflect up-to-date forecasts of ambient air temperature, but noted that
AARs could possibly incorporate other forecasted inputs.\339\ As an
example of other inputs, the Commission pointed to PJM's implementation
of ``day and night ambient air temperature tables, where the night
ambient air temperature table assumes zero solar irradiance.'' \340\
The Commission also sought comment on whether to require transmission
providers to implement DLRs, rather than only AARs, noting that DLRs
can incorporate solar heating intensity, among other ambient
conditions, to calculate the amount of transfer capability of a given
transmission line in near real time.\341\
---------------------------------------------------------------------------
\339\ NOPR, 173 FERC ] 61,165 at P 23.
\340\ Id. P 23 n.40; see also id. P 21 (explaining that
different types of ambient weather assumptions can be incorporated
into transmission line ratings, including updated air temperature,
solar irradiance, and wind speed, among others).
\341\ Id. PP 25-26, 43.
---------------------------------------------------------------------------
ii. Comments
145. Several commenters discuss the incorporation of solar heating
into transmission line ratings. For example, Vistra suggests that,
instead of requiring full DLRs, the Commission instead adopt a ``middle
ground'' of requiring AARs that incorporate consideration of
predictable solar heating (at least considering daytime/nighttime
hours, similar to PJM's existing implementation of AARs).\342\ Potomac
Economics and Vistra contend that such a requirement would not
necessitate sophisticated monitoring or forecasting, and instead would
produce significant benefits with minimal cost.\343\ R Street
Institute, PG&E, Indicated PJM Transmission Owners, Dominion, and
Potomac Economics also support incorporating predictable daytime/
nighttime solar heating into AARs, with Dominion and Indicated PJM
Transmission Owners noting that this is already the practice in
PJM.\344\ Entergy, without taking a position on whether it would be
appropriate for the Commission to require separately calculated daytime
and nighttime ratings, states that the shade of night provides an
additional 5% to the transmission line's transmission line
ratings.\345\ PG&E states that it supports separately calculated
daytime and nighttime ratings and indicates that its research from
PJM's posted transmission line ratings shows that at least 14% of PJM's
transmission line ratings would increase by 10% by considering solar
heating.\346\ Potomac Economics estimates that considering daytime/
nighttime could increase thermal transmission line ratings on average
by 11% during nighttime hours and the potential benefits would be
approximately $30 million per year in MISO alone.\347\
---------------------------------------------------------------------------
\342\ Vistra Comments at 4-5.
\343\ Id. at 4-5; Potomac Economics Comments at 14-15.
\344\ R Street Institute Comments at 3; PG&E Comments at 11-12;
Indicated PJM Transmission Owner Comments at 8-9; Dominion Comments
at 8; Potomac Economics Comments at 14-15.
\345\ Entergy Comments at 8.
\346\ PG&E Comments at 11.
\347\ Potomac Economics Comments at 14-15.
---------------------------------------------------------------------------
146. Vistra points out that solar heating varies in several ways:
Between daytime and nighttime (with sunrise/sunset times and day length
varying significantly across the year), across the hours during the day
(varying--under worst-case, clear-sky assumptions--from close to zero
just after and before sunrise and sunset, respectively, to a daily mid-
day peak), and across the days of the year (with higher mid-day peaks
in the summer and lower peaks in the winter).\348\ Vistra and PG&E both
suggest that the Commission consider requiring regular updates to
sunrise/sunset times, with Vistra discussing possible daily or seasonal
updates, and PG&E discussing possible monthly updates.\349\
Furthermore, while Vistra recommends that the Commission at the very
least require separate daytime and nighttime AARs, Vistra also provides
data for how solar heating varies significantly across the day, and
discusses how more granular solar forecasting might reflect these solar
variations.\350\
---------------------------------------------------------------------------
\348\ Vistra Comments at 4-6; see also PG&E Comments at 11-12.
\349\ Vistra Comments at 5; PG&E Comments at 12.
\350\ Vistra Comments at 4-5.
---------------------------------------------------------------------------
iii. Commission Determination
147. Upon consideration of the comments received in response to the
NOPR, we require transmission providers to incorporate solar heating
into AARs by implementing separate AARs for daytime and nighttime
periods. Specifically, we require transmission providers to reflect the
lack of solar heating in the technical assumptions for nighttime AARs.
As noted by Dominion and Indicated PJM Transmission Owners,
incorporating solar heating into AARs is consistent with PJM's existing
AAR implementation.\351\ Absent this requirement for daytime/nighttime
[[Page 2269]]
AARs, AARs would assume the worst-case solar heating assumptions in
every hour, even at night when there is no solar heating of
transmission lines at all.
---------------------------------------------------------------------------
\351\ Dominion Comments at 7-8; Indicated PJM Transmission
Owners Comments at 7.
---------------------------------------------------------------------------
148. The consideration of daytime/nighttime solar heating in the
AARs used by transmission providers will further the Commission's goal
of ensuring more accurate transmission line ratings, which result in
just and reasonable wholesale rates. Furthermore, as commenters note,
the improvements to the accuracy of transmission line ratings that will
result from adopting a daytime/nighttime AAR requirement can yield
significant economic benefits at minimal cost.\352\
---------------------------------------------------------------------------
\352\ Vistra Comments at 4-5; Potomac Economics Comments at 14-
15.
---------------------------------------------------------------------------
149. We agree with commenters that sunrise/sunset times should be
updated periodically to ensure the accuracy of both daytime and
nighttime ratings. Specifically, we clarify that in order to comply
with the requirement in pro forma OATT Attachment M for AARs to reflect
the absence of solar heating during nighttime periods, transmission
providers must update the sunrise and sunset times used to calculate
their AARs at least monthly, if not more frequently. We find that among
the daily, monthly, and seasonal timeframes suggested by commenters,
the requirement to update sunrise/sunset times on a monthly basis
strikes an appropriate balance between achieving the greatest benefits
of AAR implementation and not imposing an unreasonable burden on
transmission providers. Given the speed at which sunrise and sunset
times change in many areas of the country during certain times of the
year, monthly updates will result in significantly more accuracy in
transmission line ratings and capture significantly greater value than
seasonal updates. Because sunrise/sunset times can be easily calculated
with precision based on location and day of the year,\353\ and because
we expect AAR implementation to be largely automated, we do not expect
monthly updates to sunrise/sunset times to impose a significant
additional implementation burden relative to seasonal updates. Nothing
in this final rule would prevent a transmission provider from updating
its sunrise/sunset times more frequently than monthly and we encourage
transmission providers to do so.\354\
---------------------------------------------------------------------------
\353\ See, e.g., National Oceanic and Atmospheric
Administration, Global Monitoring Division, General Solar Position
Calculations, https://gml.noaa.gov/grad/solcalc/solareqns.PDF
(providing formulas for calculating sunrise/sunset times based on
latitude, longitude, and day of the year).
\354\ We note that PJM currently updates its sunrise/sunset
times more frequently than monthly in its day/night AAR
implementation.
---------------------------------------------------------------------------
150. Vistra correctly points out that, in addition to sunrise/
sunset times, solar heating also varies across the days of the year and
the hours of the day. However, again, to maintain a balance of benefits
and burdens, we decline to require regular updates to mid-day peak
solar heating to account for differences across days of the year. As
such, transmission providers may use maximum annual assumptions for
solar heating when determining daytime AARs. Furthermore, to balance
benefits and burdens, we decline to require more granularity (e.g.,
hourly forecasts) in solar heating assumptions and only require
daytime/nighttime consideration. We note, however, that nothing in this
final rule would prohibit a transmission provider that wants to
voluntarily implement regular updates to peak mid-day solar heating, or
to voluntarily implement hourly forecasts for solar heating, from doing
so. We further note that peak or hourly daytime solar heating (under
worst-case clear-sky assumptions) can be accurately computed based on
location using equations such as those presented in IEEE (Institute of
Electrical and Electronics Engineers) Standard 738.\355\
---------------------------------------------------------------------------
\355\ Institute of Electrical and Electronics Engineers, IEEE
Standard for Calculating the Current-Temperature Relationship of
Bare Overhead Conductors 18-20, IEEE Std 738-2012 Cor 1-2013 (2013)
(IEEE 738).
---------------------------------------------------------------------------
3. Other AAR Implementation Issues
a. Reliability Unit Commitment Processes
i. NOPR Proposal
151. In the NOPR, the Commission proposed that RTOs/ISOs comply
with the AAR requirements by revising their OATTs to implement AARs
within their SCED and SCUC models (and in any relevant related models)
in both the day-ahead and real-time markets and in any intra-day RUC
processes.\356\
---------------------------------------------------------------------------
\356\ NOPR, 173 FERC ] 61,165 at P 91.
---------------------------------------------------------------------------
ii. Comments
152. CAISO requests clarification on whether hourly transmission
line ratings should be constant in RUC processes.\357\
---------------------------------------------------------------------------
\357\ CAISO Comments at 12-13.
---------------------------------------------------------------------------
iii. Commission Determination
153. In response to CAISO, we clarify that transmission providers
should propose on compliance to use updated AARs as part of any market
process associated with the day-ahead and real-time markets (including
RUC, as well as any look-ahead commitment processes or other such
processes). In the event an RTO/ISO believes that AARs should not be
used as part of any market process associated with the day-ahead and
real-time markets (or that updated AARs should not be required for any
market process), it should propose and justify such deviations on
compliance.
b. Time Resolution and Calculation Frequency of AAR Requirements
i. NOPR Proposal
154. In defining AARs, the Commission proposed to require that AARs
be calculated at least each hour, if not more frequently, and for AARs
to apply to a time period of not greater than one hour.\358\
---------------------------------------------------------------------------
\358\ NOPR, 173 FERC ] 61,165 at P 95.
---------------------------------------------------------------------------
ii. Comments
155. Many state agencies, supply and load representatives,
renewable energy advocates, and independent experts support the
proposed AAR requirements overall, which includes the proposed time
resolution or calculation frequency.\359\ RTOs/ISOs are mixed in
whether they take a position and generally discuss their ability to
accept AARs calculated hourly. For example, while not taking a position
on the appropriateness of this part of the NOPR proposal, MISO explains
that its EMS and SCED are capable of receiving and leveraging AARs
provided by their transmission owners at least hourly.\360\
---------------------------------------------------------------------------
\359\ EPSA Comments at 2; Clean Energy Parties Comments at 2-3;
R Street Institute Comments at 2-3; TAPS Comments at 1-3; ACORE
Comments at 3; ACPA/SEIA Comments at 7; OMS Comments at 2; New
England State Agencies Comments at 10; Vistra Comments at 2-3.
\360\ MISO Comments at 12.
---------------------------------------------------------------------------
156. CAISO explains that its transmission owners can submit AARs,
but that the fundamental challenge with using AARs is timely
communication of forecasted transmission line ratings. According to
CAISO, participating transmission owners currently submit AARs as an
equipment rating change through CAISO's outage management system
(webOMS).\361\ CAISO further states that using hourly adjusted
transmission line ratings for transmission lines across the 24-hour
horizon of a trading day will necessarily and significantly increase
the complexity of CAISO's day-ahead optimization processes.\362\ In
addition, CAISO contends that hourly transmission line ratings in real-
time markets may drive uplift costs by causing variances between total
transfer
[[Page 2270]]
capability used in each of CAISO's commitment and dispatch processes.
In addition, CAISO asserts that transmission line rating changes over
the market run's look-ahead period can generate inefficient outcomes
through deviations from day-ahead schedules.\363\
---------------------------------------------------------------------------
\361\ CAISO Comments at 4.
\362\ Id. at 9-10.
\363\ Id. at 10-11.
---------------------------------------------------------------------------
157. Similarly, NYISO cautions against requiring hourly updates to
transmission line ratings if they are not already used by RTOs/
ISOs.\364\ NYISO explains that introducing hourly transmission line
ratings could result in divergences from the day-ahead schedule,
creating uplift or potential reliability risks, if hourly transmission
line ratings cause a transmission line rating to decline.\365\ On
hourly updates to AARs, NYISO notes that its market software looks
ahead, including a 24-hour day-ahead optimization and multi-period
commitment for the real-time market.\366\ NYTOs note that NYISO and
NYTOs can apply AARs and DLRs to congested transmission lines currently
in real time to increase transmission line ratings.\367\
---------------------------------------------------------------------------
\364\ NYISO Comments at 4.
\365\ Id. at 4-5.
\366\ Id. at 13.
\367\ NYTOs Comments at 4.
---------------------------------------------------------------------------
158. ISO-NE states that it allows for short-term changes to
transmission line ratings, though not at an hourly level.\368\ ISO-NE
further states that its coordinated transaction scheduling with NYISO
runs every 15 minutes and therefore a shorter interval would have to be
considered.\369\
---------------------------------------------------------------------------
\368\ ISO-NE Comments at 6-7.
\369\ Id. at 9.
---------------------------------------------------------------------------
159. While PJM supports the adoption of AARs, it opposes the
requirements that a transmission line rating apply to a period not
greater than one hour and that transmission line ratings be updated
hourly. PJM states that the key factor for determining the transmission
line rating is the temperature and, as a result, the primary event that
triggers a change in AARs is the ambient air temperature. PJM states
that, in implementing AARs, it continuously monitors temperatures and
updates transmission line ratings for temperature fluctuations in
accordance with the transmission owners' look-up table, so there is no
benefit to updating the AARs hourly if no temperature change has
occurred.\370\ Relatedly, PJM and Duke Energy state that the proposed
requirements in the NOPR that transmission line ratings be updated
hourly could harm operations.\371\ This is because, according to PJM, a
significant temperature change could occur between required hourly
updates and, if a transmission operator is not continuously monitoring
ambient air temperature, an incorrect transmission line rating would be
effective from the time of the temperature change until the next
mandated hourly update.\372\ PJM states that these temporal
requirements simply add an administrative burden without providing
additional benefits.\373\ PJM requests that the Commission refrain from
requiring transmission providers to apply AARs in hourly intervals but
rather require them to be continuously monitored with changes triggered
by temperature changes and the other relevant factors in the look-up
tables.\374\
---------------------------------------------------------------------------
\370\ PJM Comments at 4-5.
\371\ Id. at 5; Duke Energy Comments at 8.
\372\ PJM Comments at 5.
\373\ Id. at 2 n.5.
\374\ Id. at 6.
---------------------------------------------------------------------------
160. Many transmission owners also request flexibility on the
proposed requirement for AARs to be calculated ``at least each hour.''
\375\ ITC asks that the Commission instead only require daily AAR
updates and notes that this is the prevailing practice for transmission
owners using AARs in MISO.\376\ MISO Transmission Owners also request
flexibility to implement daily rather than hourly AARs.\377\ Indicated
PJM Transmission Owners argue against requiring hourly AAR
calculations.\378\ Indicated PJM Transmission Owners explain that PJM
adjusts transmission line ratings over the day as temperatures change,
but state that there is little benefit to hourly verification of
temperature changes because transmission line ratings in PJM do not
typically change hourly. Similarly, EEI argues for a requirement for
daily AAR updates for real-time operations.\379\
---------------------------------------------------------------------------
\375\ ITC Comments at 9; MISO Transmission Owners Comments at
24; EEI Comments at 12; Duke Energy Comments at 10.
\376\ ITC Comments at 9.
\377\ MISO Transmission Owners Comments at 24.
\378\ AEP Comments at 6-7; Dominion Comments at 3; Indicated PJM
Transmission Owners Comments at 7-9.
\379\ EEI Comments at 12; PacifiCorp Comments at 2; BPA Comments
at 3; WAPA Comments at 6-7.
---------------------------------------------------------------------------
161. In contrast, Entergy explains that it automatically updates
AARs every hour for the approximately 1,000 facilities for which it
calculates AARs, and this information is automatically updated hourly
in Entergy's Real Time Contingency Analysis so the operator does not
have to look at charts.\380\ Exelon also contends that an hourly
transmission line ratings check would not be overly burdensome and
instead could help to prevent overloading a transmission line.\381\
Exelon also urges the Commission to provide sufficient flexibility to
ensure transmission line ratings can change intra-hourly.\382\
Moreover, Exelon comments that it believes that the Commission's
proposed requirements are sufficiently flexible to accommodate PJM's
current approach.\383\
---------------------------------------------------------------------------
\380\ Entergy Comments at 3.
\381\ Exelon Comments at 9-10.
\382\ Id.
\383\ Id. at 9.
---------------------------------------------------------------------------
iii. Commission Determination
162. We adopt the Commission's proposal in the NOPR to require the
calculation of AARs ``at least each hour, if not more frequently'' and
the requirement that AARs ``appl[y] to a time period of not greater
than one hour.'' \384\
---------------------------------------------------------------------------
\384\ NOPR, 173 FERC ] 61,165 at P 3 n.3.
---------------------------------------------------------------------------
163. With respect to calculation frequency, we believe that
performing AAR calculations at least hourly appropriately balances
requiring updates at a frequency that captures meaningful changes in
ambient air temperature forecasts, and not overburdening transmission
providers. In response to concerns that the requirement for hourly
calculations may be unduly burdensome because temperature forecasts do
not always fluctuate hour by hour, we recognize that in some hours
forecasts for temperatures do not change, primarily because weather
services do not always have updated forecasted values for every
location each hour. However, it is not known exactly when such
forecasted values will be updated, and, therefore, our requirement to
calculate AARs hourly appropriately requires transmission providers to
check for forecast updates and apply any updates that are available. We
believe that the requirement to calculate AARs hourly ensures that any
such publication of forecast updates are incorporated into AARs in a
reasonable timeframe.\385\ If we were to instead require such
calculations on a longer time period (e.g., every eight hours), then
there would be some instances when published available weather forecast
updates would not be incorporated into AARs in time to accurately
reflect the transmission line's true transfer capability. Moreover, we
expect this process for AAR implementation to be largely automated,
with computer systems querying or receiving updated forecasts and
processing any such data
[[Page 2271]]
into updated AARs, such that calculating AARs hourly should not be
significantly more burdensome than calculating AARs daily. We agree
with Exelon that AAR calculations at least hourly are likely to be an
important tool used to prevent any transmission overload that might
occur as a result of a sudden, unexpected temperature increase.\386\ We
add that this requirement does not preclude intra-hour updates.
---------------------------------------------------------------------------
\385\ For example, we understand that the NBM forecast (which is
a blend of distinct constituent forecasts) has updates published at
least every hour, but the constituent forecasts are typically
updated only three times per day. Exactly when the constituent
forecasts will be updated is not precise, such that an update to any
forecasted value might change in any hour.
\386\ Exelon Comments at 9-10.
---------------------------------------------------------------------------
164. We acknowledge, in response to comments by CAISO and NYISO,
that within RTOs/ISOs there will be times when AARs produce real-time
transmission line ratings that diverge from what was previously
calculated in the day-ahead market (based on earlier forecasts), and
that this may result in operating considerations and uplift costs.
However, we are not persuaded that such considerations or costs
outweigh the benefits of updating real-time transmission line ratings
discussed above. Further, updating transmission line ratings closer to
real time will help ensure that the most accurate transmission line
ratings are used in the real-time energy market and, in turn, tend to
reduce costs and promote reliable operations. Commenters seem to argue
that if the weather conditions unexpectedly change, such that
temperatures are significantly lower and significantly more transfer
capability is able to be used in real time compared to day ahead, the
markets should keep such transfer capability in reserve in order to
minimize uplift. We disagree that a concern about potential uplift
should result in transfer capability being withheld from the real-time
energy market with associated limits on the economic benefits of using
AARs. Further, we do not believe that any operating considerations
associated with updating transmission line ratings in real time will
compromise reliable operations. As PJM states, AARs are already
employed in PJM in both the day-ahead and real-time markets and, in its
experience, AARs increase operational flexibility, promote a more
efficient use of the transmission system, and result in more reliable
system dispatch and cost-effective market operations.\387\
---------------------------------------------------------------------------
\387\ PJM Comments at 2.
---------------------------------------------------------------------------
165. One of the reasons that substantial uplift is sometimes
considered problematic is that it may be evidence that the market is
not accurately considering operating constraints, which gives rise to
out-of-market actions and distorts short-term and long-term price
signals.\388\ While we acknowledge the potential for uplift in certain
situations, the reason for incurring uplift here is very different.
Updating transmission line ratings in real time will result in more
accurate prices that reflect actual real-time operating constraints.
Accordingly, the potential for the generation of uplift through our AAR
requirements would not be evidence of market design concerns or
inaccurate price signals.
---------------------------------------------------------------------------
\388\ Uplift Cost Allocation and Transparency in Mkts. Operated
by Reg'l Transmission Orgs. and Indep. Sys. Operators, Order No.
844, 83 FR 18134 (Apr. 25, 2018), 163 FERC ] 61,041, at P 3 (2018).
---------------------------------------------------------------------------
166. As discussed above, we believe that, under the AAR
requirements adopted in this final rule, transmission providers will
implement AARs with sufficient forecast margins in forward periods such
that instances of reductions in transfer capability in real time and
the related operational challenges will be infrequent. Accordingly, we
anticipate that transfer capability will typically be freed up as
forecasts become more certain (and require smaller forecast margins)
from forward periods to actual operation, which will typically result
in additional transmission being made available as we approach real
time, and this will create some uplift. But we find this is the result
of the policies that are needed to ensure transmission line ratings are
sufficiently accurate to produce just and reasonable wholesale rates,
and that any resulting uplift is, therefore, appropriate. Additionally,
however, we acknowledge that transmission providers might also
implement unreasonably high ambient air temperature forecast margins.
In such instances, such unreasonably high forecast margins would need
to be adjusted to ensure transmission line ratings are accurate.
167. We clarify that this final rule does not prohibit transmission
providers from utilizing AARs that are calculated on a more frequent
basis than hourly. Relatedly, in response to comments from PJM, we
clarify that nothing in this final rule prevents a transmission
provider from utilizing a transmission line rating calculated in
between whatever standard AAR calculation period is established.
168. Turning to the hourly resolution (as opposed to the hourly
frequency of calculation) of AARs, we adopt the NOPR proposal to
require that AARs ``appl[y] to a time period of not greater than one
hour'' because we find such a policy strikes an appropriate balance
between providing sufficient granularity to transmission line ratings
to reflect meaningful predictable changes in ambient air temperature
across each day, and not overburdening transmission providers.\389\
These changes are different from changes in ambient air temperatures
discussed above, which are changes in forecasts due to improved
information as a time period moves closer to real time as time
advances.
---------------------------------------------------------------------------
\389\ Pro Forma OATT attach. M, AAR Definition.
---------------------------------------------------------------------------
169. We find that ambient air temperatures typically vary
sufficiently across the day to produce meaningful differences in hourly
transmission line ratings. For example, we expect temperatures during
morning or evening hours to typically be significantly different than
the noon temperature. Recognizing such temperature differences through
transmission line ratings may be particularly important, since
increasingly systems are being challenged during such morning or
evening hours due to ramp or peak net load challenges. We find that
hourly AAR calculations will create important additional operational
flexibility for operators and more accurate transmission line ratings.
And because we expect the AAR process to be largely automated, we do
not believe that the requirement for hourly AARs will be significantly
more burdensome than a less granular requirement (e.g., a requirement
that AARs apply to a time period of not greater than one day). In any
event, we clarify that this final rule does not preclude a transmission
provider from implementing AARs on a more granular basis than hourly,
such as the 15-minute basis suggested by ISO-NE with respect to its
coordinated transaction scheduling.
c. AAR Coordination
i. Comments
170. Several commenters argue that further consideration is needed
on AAR implementation in certain circumstances.\390\ For example, while
not supporting or opposing an AAR mandate, NERC stresses the importance
of reliability, explaining that reliability of the transmission system
depends upon the proper coordination of transmission line ratings,\391\
and states that special attention must be paid to reliability
considerations in the implementation of any reforms in this
proceeding.\392\ Specifically, NERC notes that the Commission should
consider whether to require transmission
[[Page 2272]]
providers to coordinate AAR implementation methods since temperature
readings and methodologies may differ on tie lines, and which
transmission line rating should be used in the event of a disagreement
among entities receiving transmission line ratings or
methodologies.\393\
---------------------------------------------------------------------------
\390\ NERC Comments at 6-7; EEI Comments at 14-15; NYTOs
Comments at 7; CAISO Comments at 12-13.
\391\ NERC Comments at 4.
\392\ Id.
\393\ Id. at 6-7.
---------------------------------------------------------------------------
171. EEI asserts that the NOPR proposal was unclear about how AARs
on transmission lines across seams should be determined, where
transmission line ratings could be subject to assumptions from two
different transmission providers, and how AAR compliance could be
determined for non-jurisdictional transmission facilities. EEI urges
flexibility on seams issues and for the Commission to enforce
reciprocity conditions for non-jurisdictional entities, should the
Commission require targeted AAR implementation.\394\ IID also
encourages the Commission to consider seams issues that may need to be
addressed if AARs are different among neighboring utilities.\395\ MISO
Transmission Owners similarly state that ATC calculations on joint
flowgates and tie lines between RTOs/ISOs will require coordination
among all parties each time a transmission line rating changes,
increasing the level of communication necessary. According to MISO
Transmission Owners, along these joint flowgates and tie lines,
transmission owners and RTOs/ISOs will need to decide which forecast
will govern and whether to use multiple weather forecasts.\396\
---------------------------------------------------------------------------
\394\ EEI Comments at 14-15.
\395\ IID Comments at 6-7.
\396\ MISO Transmission Owners Comments at 32-33.
---------------------------------------------------------------------------
ii. Commission Determination
172. We agree with NERC's comments stressing the importance of
reliability and reiterate that system safety and reliability are
paramount to the requirements for transmission line ratings that we
adopt in this final rule. We agree with NERC and other commenters that
implementation of AAR requirements on tie lines may necessitate
increased communication among neighboring transmission providers and
relevant transmission owners. While we expect that parties will work
collaboratively to ensure that appropriate ratings are determined for
each tie line, we decline to adopt specific requirements for
coordinating AAR implementation across transmission provider seams.
Parties along these seams have a long history of working
collaboratively to ensure the reliable implementation of transmission
facility ratings and we are not persuaded that specific requirements
for coordination are required at this time. Moreover, we note that, in
the event of a disagreement over the appropriate facility rating, the
NERC Reliability Standards already establish a framework for how
entities should proceed, i.e., that the system should be operated to
the most limiting parameter.\397\ However, as described further in
Section IV.G.3.b, to ensure that transmission providers have adequate
transparency into the transmission line ratings methodologies of their
neighbors, we require transmission providers to share transmission line
ratings and transmission line rating methodologies with other
transmission providers, upon request.
---------------------------------------------------------------------------
\397\ Reliability Standard TOP-001-5, Requirement R 18, p. 7,
https://www.nerc.com/pa/Stand/Reliability%20Standards/TOP-001-5.pdf.
---------------------------------------------------------------------------
173. In response to EEI and NERC, we further clarify that, to the
extent there is a disagreement among entities about the calculated AAR,
transmission providers should use the most limiting AAR in order to
ensure reliability and that thermal limits are respected. As IID
suggests, however, if the most limiting AAR along a mutual seam is
based on one transmission provider's ambient air temperature
assumptions that are more risk averse than another transmission
provider's ambient air temperature assumptions, the inevitable result
will be increased congestion between control areas. While using the
more risk averse transmission line rating may result in an increase in
congestion relative to the alternative of using a lower forecasted
ambient air temperature, we do not, in this final rule, revise each
transmission provider's authority to set the transmission line ratings
within its control area.
174. In response to EEI's request for clarification on the
applicability of the AAR requirements to non-jurisdictional entities,
we note that the Commission's pro forma OATT requirements apply only to
Commission-jurisdictional transmission providers. However, to the
extent non-jurisdictional entities have reciprocity tariffs on file
with the Commission, such reciprocity tariffs will need to implement
pro forma OATT Attachment M adopted herein in order to satisfy the
Commission's comparability (non-discrimination) standards established
in Order No. 888.
d. Applicability of AARs to Transmission Loading Relief (TLR) Events
i. NOPR Proposal
175. In the NOPR, the Commission proposed to require transmission
providers to use AARs as the relevant transmission line rating when
determining whether to curtail or interrupt point-to-point transmission
service (under section 14.7 of the pro forma OATT) if such curtailment
or interruption is necessary because of a reduction in transfer
capability anticipated to occur (start and end) within the next 10
days. The Commission also proposed to require transmission providers to
use AARs as the relevant transmission line rating when determining
whether to curtail network transmission service or secondary service
(under section 33 of the pro forma OATT) or redispatch network
transmission service or secondary service (under sections 30.5 and/or
33 of the pro forma OATT), if such curtailment or redispatch is both
necessary because of issues related to flow limits on transmission
lines and anticipated to occur (start and end) within 10 days of such
determination.\398\
---------------------------------------------------------------------------
\398\ NOPR, 173 FERC ] 61,165 at PP 87, 89, 90.
---------------------------------------------------------------------------
ii. Comments
176. MISO states that the Commission should clarify that use of
AARs in congestion management should not discriminate based on the type
of flows being curtailed, be it transmission service or market flow, as
some processes, such as the interregional TLR process, differentiate
between the types of flow.\399\
---------------------------------------------------------------------------
\399\ MISO Comments at 8.
---------------------------------------------------------------------------
iii. Commission Determination
177. We clarify that AARs should not discriminate based on the type
of flows being curtailed, interrupted, or redispatched. Accordingly, we
modify certain aspects of pro forma OATT Attachment M, as proposed in
the NOPR, to clarify that AARs must be used as the relevant
transmission line rating when determining whether to initiate TLR
procedures anticipated to occur (start and end) within the next 10
days. We note that TLR procedures occur pursuant to the curtailment,
interruption, and/or redispatch procedures outlined in pro forma OATT
sections 13.6, 14.7, 30.5, and/or 33, which are also referenced in pro
forma OATT Attachment M, as proposed in the NOPR, as requiring the use
of AARs as the relevant transmission line rating.
[[Page 2273]]
In these instances, we find that proposed pro forma OATT Attachment M
is already sufficiently clear: AARs must be used as the relevant
transmission line rating when determining whether to initiate TLR
procedures anticipated to occur (start and end) within the next 10
days. However, because pro forma OATT Attachment M, as proposed in the
NOPR, only referenced curtailment and interruption procedures that
occur pursuant to pro forma OATT section 14.7, for clarity, we modify
the proposed pro forma OATT Attachment M to also reference curtailment
and interruption procedures that occur pursuant to pro forma OATT
section 13.6.
e. Communication and Verification of AARs
i. Comments
178. With regard to the Commission's NOPR proposal that AAR data be
submitted by the transmission owner to the RTO/ISO through Supervisory
Control and Data Acquisition (SCADA) or related systems, MISO states
that it strongly urges the Commission not to require any specific data
communication medium due to rapid and frequent changes in technology.
MISO emphasizes that the scale and scope of AARs as proposed in the
NOPR would require electronic and programmatic updates to the RTO/ISO,
and using manual communication methods, such as phone calls or written
messaging, would not be practical. MISO adds that the requirements to
coordinate data interchange for reliability are currently regulated by
the NERC Reliability Standards.\400\ CAISO states that a fundamental
challenge will be to ensure entities can transmit forecasted AARs in a
timely manner.\401\ As a result of this challenge, CAISO requests
clarification on what to do in cases of communication failure between
the transmission owner and the RTO's/ISO's EMS and what an RTO/ISO
should do if a transmission owner submits an incorrect transmission
line rating.\402\ NYISO clarifies that it receives updates of
transmission line ratings from asset owners via the Inter-Control
Center Communication Protocol.\403\ NYTOs explain that, since AARs and
DLRs are constantly changing, independent software validation solutions
will be needed to avoid violating NERC Reliability Standard FAC-008,
which would occur when there is any accidental discrepancy between a
calculated transmission line rating and the transmission line rating
methodology.\404\
---------------------------------------------------------------------------
\400\ MISO Comments at 15-16.
\401\ CAISO Comments at 4-5.
\402\ Id. at 12-13.
\403\ NYISO Comments at 4.
\404\ NYTOs Comments at 7.
---------------------------------------------------------------------------
ii. Commission Determination
179. In response to comments requesting that the Commission not
dictate communication mediums for transmission owners submitting AARs
to RTOs/ISOs, we clarify that this final rule requires that electronic
transmission line rating data be submitted by transmission owners
directly into an RTO's/ISO's EMS through SCADA or similar communication
systems. We clarify that other electronic systems, such as Inter-
Control Center Communication Protocol, can be used to comply with this
requirement, and RTOs/ISOs may propose to use such systems on
compliance.
180. In response to concerns about potential scarcity of
temperature data and/or AAR communication failures, we modify the NOPR
proposal to require that, if an AAR otherwise required to be used under
pro forma OATT Attachment M is unavailable, the transmission provider
must use the relevant seasonal line rating as the appropriate
transmission line rating. This requirement does not relieve any
transmission provider of the obligation in the first instance to
provide an AAR but provides an alternate only if an AAR otherwise
required under pro forma OATT Attachment M is not available. Further,
while this provision establishes the seasonal line rating as the
default recourse rating, the transmission provider retains the ability
under the ``System Reliability'' section of pro forma OATT Attachment M
to use a different recourse rating where the transmission provider
reasonably determines such a rating is necessary to ensure the safety
and reliability of the transmission system.
181. In response to NYTOs' comments that changing transmission line
ratings will necessitate additional transmission line rating validation
tools, we reiterate that the definitions of Transmission Line Rating,
AARs, and Seasonal Line Rating we adopt in this final rule--as set
forth in pro forma OATT Attachment M--require computation of
transmission line ratings in accordance with good utility practice,
including up-to-date forecasts, to ensure the accuracy of the relevant
transmission line rating.\405\ And as NYTOs note, inaccurate
transmission line ratings or a discrepancy between transmission line
ratings and the transmission line rating methodology could trigger a
violation of NERC Reliability Standard FAC-008 by the relevant
transmission owner. In other words, pro forma OATT Attachment M imposes
an affirmative obligation on transmission providers to implement
accurate transmission line ratings and the NERC Reliability Standards
similarly require accuracy in transmission line ratings by the
transmission owners that calculate such ratings. In RTOs/ISOs, where
the transmission provider (i.e., the RTO/ISO) must rely on its
transmission owners to calculate and provide the required transmission
line ratings, we acknowledge that there might be some increased
complexity in ensuring the accuracy of the transmission line ratings.
However, we do not prescribe the method for a transmission provider--
including an RTO/ISO--to screen for issues with transmission line
ratings,\406\ instead leaving it up to the transmission provider to
develop a general validation system that ensures its compliance with
the requirements of this final rule and relevant NERC Reliability
Standards. We agree with MISO that it is unable--and indeed is not
required--to audit transmission line ratings; \407\ rather, the type of
validation that we reference here would be akin to the automated
validation referenced by CAISO, SPP, and PJM,\408\ where the RTO/ISO
runs checks for obvious signs of data errors or corruption.
---------------------------------------------------------------------------
\405\ Pro Forma OATT attach. M, AAR Definition.
\406\ For example, a transmission provider might consider
screening for such issues as: Missing data; significant changes in
transmission line ratings; illogical data (such as ratings that
increase with increasing temperature, or daytime ratings that are
higher than nighttime ratings); and transmission line ratings
outside feasible ranges for particular transmission lines.
\407\ MISO Comments at 27.
\408\ PJM Comments at 8; CAISO Comments at 13; SPP Comments at
5-6. We note that, according to the MISO Transmission Owners'
Agreement (TOA), MISO also has a responsibility to verify
transmission line ratings. MISO, Open Access Transmission, Energy
and Operating Reserve Markets Tariff, Rate Schedule 1, Appendix B,
Section V (30.0.0) (``Each Owner shall file with MISO information
regarding the physical ratings of all of its equipment in the
Transmission System. This information is intended to reflect the
normal and emergency ratings routinely used in regional load flow
and stability analyses. In carrying out its responsibilities, MISO
shall apply ratings that have been provided by the respective Owners
and have been verified and accepted as appropriate by MISO where
such ratings affect MISO reliability.'').
---------------------------------------------------------------------------
182. In response to CAISO's request for clarification on what an
RTO/ISO should do if a transmission owner submits an incorrect
transmission line rating, we do not require RTOs/ISOs to audit or
recalculate transmission line ratings submitted to them (except in
instances where their procedures provide for them to calculate
[[Page 2274]]
transmission line ratings, such as for RTOs/ISOs that calculate AARs
from tables or databases). To the extent any transmission provider
becomes aware of an apparent inaccurate transmission line rating, the
transmission provider is expected to inform the transmission owner
immediately and both the transmission provider and transmission owner
should take appropriate action to correct any inaccuracy. If the
transmission provider and transmission owner are unable to resolve the
inaccuracy of a submitted AAR, then, as discussed above, the
transmission provider must use an appropriate recourse rating until the
AAR inaccuracy is resolved. To the extent the transmission provider
and/or transmission owner is out of compliance with any applicable
requirements, they should report such noncompliance as dictated by the
applicable requirement.
f. Minimum AAR Temperature Range and AAR Granularity
i. Comments
183. Vistra contends that the Commission should provide guidance on
the range and granularity of temperatures to be used in AARs.\409\
Vistra argues that the Commission's AAR policy will be undermined if
implementation decisions reintroduce unnecessary conservativism (such
as only altering AARs for every 20 degrees Fahrenheit of ambient air
temperature, or developing AARs for only a limited range of ambient air
temperatures).\410\ Vistra suggests that it would not be unreasonable
for AARs to change for every one or two degrees Fahrenheit change in
ambient air temperature, and that AARs be calculated for a range of
temperatures that cover the historical low and historical high
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
[[Page 2275]]
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
[[Page 2276]]
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
[[Page 2277]]
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
[[Page 2278]]
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
[[Page 2279]]
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
[[Page 2280]]
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
[[Page 2281]]
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
[[Page 2282]]
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
[[Page 2283]]
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,
[[Page 2284]]
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
[[Page 2285]]
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
[[Page 2286]]
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
[[Page 2287]]
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
[[Page 2288]]
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
[[Page 2289]]
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
constraints, stating that approximately half of the potential benefits
and reduced production costs of the rulemaking could be lost without
such a clarification.\684\ New England State Agencies and OMS agree
that accurate emergency ratings could provide important benefits.\685\
However, New England State Agencies argue that more information is
needed.\686\
---------------------------------------------------------------------------
\684\ Potomac Economics Comments at 4.
\685\ New England State Agencies Comments at 21; OMS Comments at
13-14.
\686\ New England State Agencies Comments at 22.
---------------------------------------------------------------------------
289. Regarding implementation, PacifiCorp states that the ability
to use emergency ratings in TTC on path ratings \687\ is more complex
than being able to calculate them because this requires contingency
analysis.\688\ Entergy states that emergency ratings implementation is
complicated by the thermal time constraint being different for all
conductors based on size and construction.\689\
---------------------------------------------------------------------------
\687\ The NERC Glossary defines ``Rated System Path
Methodology,'' which includes an initial TTC from which the ATC is
derived and is generally reported as specific transmission path
capabilities. NERC, Glossary of Terms Used in NERC Reliability
Standards (June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\688\ PacifiCorp Comments at 5.
\689\ Entergy Comments at 13-14.
---------------------------------------------------------------------------
290. ITC asserts that AARs should be used for both normal ratings
(pre-contingency operations) and emergency ratings (post-contingency
operations) because congestion is often caused by projected post-
contingency flows.\690\ EDFR and Industrial Customer Organizations
state that, where appropriate, emergency ratings could be combined with
DLRs for additional benefits.\691\ Similarly, PG&E supports considering
the benefits of AARs for both normal and emergency ratings.\692\ By
contrast, ACPA/SEIA encourage the consideration of seasonal line rating
information in developing emergency ratings, similar to the framework
for using seasonal line ratings for long-term transmission
service.\693\
---------------------------------------------------------------------------
\690\ ITC Comments at 12.
\691\ EDFR Comments at 6; Industrial Customer Organizations
Comments at 27.
\692\ PG&E Comments at 12.
\693\ ACPA/SEIA Comments at 17.
---------------------------------------------------------------------------
291. ISO-NE states that an update to the overall transmission line
rating methodology to include AARs may also necessitate the need for
new emergency ratings based on those AARs.\694\ Potomac Economics
supports a requirement that transmission owners calculate and use AARs
based on emergency ratings for contingency constraints.\695\ NYTOs
state that having normal and emergency ratings could preempt the need
to establish an AAR mandate on all transmission lines.\696\
---------------------------------------------------------------------------
\694\ ISO-NE Comments at 10-11.
\695\ Potomac Economics Reply Comments at 8.
\696\ NYTOs Comments at 11.
---------------------------------------------------------------------------
b. Commission Determination
292. Based on the record developed in this proceeding, we are
persuaded that it is appropriate to adopt certain requirements for
emergency ratings. Whether and how a transmission owner establishes
emergency ratings is important because emergency ratings are a critical
input into determining transfer capability, both during normal
operations and during post-contingency operations. There is a
significant record of transmission owners and transmission providers
already using emergency ratings.\697\ For example, Exelon notes that it
already calculates emergency ratings for its transmission facilities
and that the benefits of using emergency ratings during emergencies
outweigh the costs of establishing them.\698\ There is also an
extensive record on the role of emergency ratings in ensuring reliable
and efficient operations. Specifically, transmission owners and
transmission providers report benefits from implementing emergency
ratings including increased transmission capacity,\699\ additional time
to respond to contingencies,\700\ lower costs to consumers,\701\ and
help
[[Page 2290]]
maintaining reliability and avoiding unnecessary load shed.\702\
Emergency ratings have an extensive record of use and are a more
accurate representation of the flow limits over shorter timeframes and
are thus necessary to ensure just and reasonable wholesale rates.
---------------------------------------------------------------------------
\697\ See, e.g., 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.
\698\ Exelon Comments at 22.
\699\ ISO-NE Comments at 10; PacifiCorp Comments at 4.
\700\ APS Comments at 7.
\701\ ISO-NE Comments at 10; PacifiCorp Comments at 4; WAPA
Comments at 8.
\702\ Exelon Comments at 22.
---------------------------------------------------------------------------
293. First, as set forth under ``Obligations of Transmission
Provider'' in pro forma OATT Attachment M, we require that transmission
providers use emergency ratings for contingency analysis in the
operations horizon and in post-contingency simulations of constraints.
We define an ``emergency rating'' in pro forma OATT Attachment M as a
transmission line rating that reflects operation for a specified,
finite period, rather than reflecting continuous operation. An
emergency rating may assume acceptable loss of equipment life or other
physical or safety limitations for the equipment involved.\703\ We
adopt this emergency ratings requirement to ensure the accuracy of
transmission line ratings, particularly during emergency operations.
Emergency ratings are a critical input into determining transfer
capabilities and congestion costs during emergency operations and can
provide temporarily expanded operating flexibility to allow higher
loading and higher operating limits on transmission facilities for a
short time during unexpected tight system conditions, emergency events,
or contingencies. Emergency ratings are also a critical input into the
scheduling of transactions that can be executed under real-time
operating constraints. Because real-time, unforeseen contingencies can
occur that stress the system's transfer capabilities (e.g., forced
outages on generation or transmission), transmission providers operate
their systems in normal conditions to be able to withstand such
contingencies. Should such a contingency occur, transmission providers
are thus prepared to redispatch resources. Dispatching and scheduling
resources to accommodate such contingency events can cause a large
increase in wholesale rates, due to congestion costs. More accurate
emergency ratings (like more accurate transmission line ratings
generally) will better reflect the near-term transfer capability of the
system, more accurately reflect the cost of serving load, and avoid
unnecessary transient congestion costs. For these reasons, we adopt the
emergency ratings requirement as set forth in pro forma OATT Attachment
M.
---------------------------------------------------------------------------
\703\ The NERC Glossary defines an ``Emergency Rating'' as:
``[t]he rating as defined by the equipment owner that specifies the
level of electrical loading or output, usually expressed in
megawatts (MW) or Mvar or other appropriate units, that a system,
facility, or element can support, produce, or withstand for a finite
period. The rating assumes acceptable loss of equipment life or
other physical or safety limitations for the equipment involved.''
NERC, Glossary of Terms Used in NERC Reliability Standards (June 28,
2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------
294. Second, we require that transmission providers use uniquely
determined emergency ratings. Under this requirement, transmission
providers must use emergency ratings that transmission owners determine
uniquely from their determination of normal ratings.\704\ This
requirement ensures that transmission providers use emergency ratings
that reflect that a transmission facility's transfer capabilities may
differ for shorter periods of time; that is, transfer capabilities
differ if calculated for use over a short period of time (i.e., for
emergency ratings) rather than for use over an indefinite period of
time (i.e., for normal ratings).
---------------------------------------------------------------------------
\704\ As clarified below, consistent with our determination in
Section IV.B.2.b.iii. on the role of the transmission owner and
transmission provider in AAR implementation, transmission owners,
not transmission providers, are responsible for calculating
emergency ratings.
---------------------------------------------------------------------------
295. In response to commenters stating that the Commission should
not require that emergency ratings be unique from normal ratings, we
clarify that we are not requiring that emergency ratings be arbitrarily
higher than normal ratings. Instead, we are requiring that emergency
ratings be uniquely determined, meaning determined based on assumptions
that reflect the specified, finite duration of emergency ratings, as
distinct from the assumptions used to calculate normal ratings, which
reflect a power transfer capability that can be maintained
indefinitely. Consistent with the Commission's statements in the
NOPR,\705\ transmission owners will have discretion to determine the
procedure used to calculate emergency ratings, so long as they do so in
accordance with good utility practice and the other requirements in pro
forma OATT Attachment M. Accordingly, a transmission provider may use
an emergency rating equal to a normal rating, provided that both
ratings were calculated uniquely using appropriate assumptions, sound
engineering judgment, and good utility practice.
---------------------------------------------------------------------------
\705\ NOPR, 173 FERC ] 61,165 at P 46 n.57.
---------------------------------------------------------------------------
296. We agree with PacifiCorp's comment that the ability to use
uniquely determined emergency ratings requires real-time and near real-
time horizons contingency analysis tools that can handle variable
limits (i.e., normal rating for normal operating conditions, and
emergency ratings in contingency conditions) and perform iterative
simulations to calculate TTC on path ratings.\706\ Such contingency
analysis is already required under NERC Reliability Standards,
including, e.g., Reliability Standards TOP-001 and IRO-008, which
require transmission providers and reliability coordinators to perform
a real-time assessment at least once every 30 minutes to ensure that
instability, uncontrolled separation, or cascading outages that could
adversely impact the reliability of the interconnection will not
occur.\707\ Modifications to future-looking cases to increase flow, and
to iteratively run contingency analysis, is common practice since
system loading conditions change throughout the day. However, we agree
that these tools require additional data points and simulation process
modifications to observe the emergency rating of bulk electric system
facilities, if not currently used.
---------------------------------------------------------------------------
\706\ PacifiCorp Comments at 5-6.
\707\ Reliability Standard TOP-001-5 R13 requires a transmission
operator to perform a Real-Time Assessment at least once every 30
minutes. According to the NERC Glossary, a ``Real-Time Assessment''
is: ``[a]n evaluation of system conditions using Real-time data to
assess existing (pre-Contingency) and potential (post-Contingency)
operating conditions. The assessment shall reflect applicable inputs
including, but not limited to: . . . Facility Ratings; and
identified phase angle and equipment limitations.'' NERC, Glossary
of Terms Used in NERC Reliability Standards (June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------
297. Third, we require that emergency ratings also incorporate an
adjustment for ambient air temperature and for daytime/nighttime solar
heating, consistent with the AAR requirements for normal ratings. Based
on the record, we find that the calculation of AARs for both normal and
emergency ratings will enhance the accuracy of transmission line
ratings and ensure just and reasonable wholesale rates. As commenters
point out, congestion is often caused by post-contingency transmission
flows that are modeled and managed as part of normal operations, and
thus not requiring AARs to be applied to emergency ratings would
inaccurately constrain even normal operations and prevent significant
potential benefits of AAR implementation. Finally, we note that
applying AARs to emergency ratings is consistent with the
implementation of AARs in PJM, where nearly all emergency ratings are
dependent on ambient air temperatures.\708\
---------------------------------------------------------------------------
\708\ See PJM Ratings Information, https://www.pjm.com/markets-and-operations/etools/oasis/system-information/ratings-information.aspx (last visited Nov. 1, 2021).
---------------------------------------------------------------------------
[[Page 2291]]
298. As with the application of AARs to normal ratings,
transmission owners have discretion to determine which specific
electric system equipment has emergency ratings that are affected by
ambient air temperatures, consistent with good utility practice and the
requirements of pro forma OATT Attachment M.
299. Consistent with our determination in Section IV.B.2.b.iii on
the role of the transmission owner and transmission provider in AAR
implementation, we clarify that transmission owners, not transmission
providers, are responsible for calculating emergency ratings. This
responsibility is set forth in the NERC Reliability Standards, as well
as in RTO/ISO foundational documents.\709\ Nothing in this final rule
changes that responsibility. In the non-RTO/ISO regions, this is
generally not a concern because the transmission provider is usually
the transmission owner. However, in the RTO/ISO regions, there is a
distinction between transmission owners and transmission providers.
Thus, in order to comply with this final rule, RTOs/ISOs--the
transmission provider with the OATT on file--will need to rely on their
member transmission owners to calculate emergency ratings and provide
them to the RTO/ISO.\710\ Additionally, unlike normal transmission line
ratings, emergency ratings correspond to a specific duration. Thus, the
duration of each uniquely determined emergency rating determined by a
transmission owner must be specified and communicated by the
transmission provider, consistent with our determination on the
transparency and reporting requirements of transmission line ratings in
Section IV.G.3 below.
---------------------------------------------------------------------------
\709\ See, e.g., Reliability Standards FAC-008-5, Requirement R3
and FAC-008-5, Requirement R6.
\710\ See supra note 326.
---------------------------------------------------------------------------
300. Where the transmission provider is not the transmission owner
(e.g., RTOs/ISOs), we require the transmission provider to explain in
its compliance filing, as part of its implementation of new pro forma
OATT Attachment M, through what mechanism (tariff, membership
agreement, etc.) the transmission owner has the obligation for making
and communicating to the transmission provider the timely calculations
and determinations related to emergency ratings (including any
discretion in calculations).
301. In response to commenter requests for a minimum, maximum, or
standardized emergency rating duration, we recognize that transmission
owners use a range of durations and find that transmission owners are
best situated to make judgments on the appropriate emergency rating
duration based on the technical capabilities of the installed
equipment, consistent with good utility practice, using sound
engineering judgment, manufacturer guidance, and equipment reliability
experience.
302. We recognize, as pointed out by some commenters, that
emergency ratings can affect the safe operation and useful life of
transmission facilities. However, as several commenters explain, most
transmission equipment has the ability to withstand high currents for
short periods of time without sustaining damage.\711\ The requirement
to implement uniquely determined emergency ratings simply requires that
emergency ratings calculations be based on this existing ability, where
it exists. In response to comments from MISO that the Commission allow
transmission owners to establish reasonable and supported reliability
margins,\712\ as the Commission stated in the NOPR, transmission
providers that find they need a reliability margin have existing
Commission-approved mechanisms, such as the transmission reliability
margin component of ATC, for establishing such a margin on a consistent
and transparent basis.\713\
---------------------------------------------------------------------------
\711\ See, e.g., Entergy Comments at 6-8; BPA Comments at 7;
Exelon Comments at 21-23.
\712\ MISO Comments at 26.
\713\ NOPR, 173 FERC ] 61,165 at P 104.
---------------------------------------------------------------------------
303. In response to Indicated PJM Transmission Owners and MISO
Transmission Owners' concerns with Potomac Economics' analysis, we note
that our findings in this final rule are not solely based on Potomac
Economics' analysis. Rather, our rationale for adopting the requirement
to implement uniquely determined emergency ratings, similar to the AAR
requirements discussed above, is based on the finding that implementing
uniquely determined emergency ratings will ensure that transmission
line ratings are more accurate, that more accurate transmission line
ratings will ensure wholesale rates more accurately reflect the cost of
the wholesale service being provided, and, thus, that those wholesale
rates are just and reasonable.
3. Equipment for Which Emergency Ratings Must Be Calculated
a. Comments
304. Exelon and APS note that they can and do calculate emergency
ratings on equipment other than conductors and transformers.\714\ APS
notes that its use of emergency ratings often does not impact, and
typically is not limited by, substation equipment.\715\ Entergy states
that emergency ratings cannot be used on many components of
facilities.\716\ However, Entergy explains that autotransformers can
have emergency ratings about 25 to 30% over their normal rating for up
to two hours.\717\ Tangibl notes that different equipment may be
limiting under different operating scenarios and that, while secondary
and control components often have identical normal and emergency
ratings, it is rare for relays to be the limiting element in PJM winter
ratings.\718\
---------------------------------------------------------------------------
\714\ APS Comments at 7; Exelon Comments at 21.
\715\ APS Comments at 7.
\716\ Entergy Comments at 7.
\717\ Id. at 7.
\718\ Tangibl Comments at 3.
---------------------------------------------------------------------------
b. Commission Determination
305. As we determined in Section IV.A above, emergency ratings,
like all transmission line ratings, must incorporate a set of
electrical equipment ratings that collectively operate as a single
electric system element (e.g., transformers, relay protective devices,
terminal equipment, and series and shunt compensation devices), and the
most limiting component from that set will determine the transmission
line rating. Consistent with our determination on the use of AARs in
Section IV.B.1 above, we find that transmission providers must use
uniquely determined emergency ratings on all conductors and all
relevant transmission equipment, in order to ensure that transmission
line ratings are accurate.
G. Transparency
1. NOPR Proposal
306. The Commission proposed in the NOPR to require transmission
owners to share transmission line ratings for each period for which
they are calculated and transmission line rating methodologies with
their transmission provider(s), and, in regions served by an RTO/ISO,
also with the market monitor(s) of that RTO/ISO.\719\ The Commission
preliminarily found that this requirement would afford transmission
providers and market monitors more operational and situational
awareness.\720\
---------------------------------------------------------------------------
\719\ NOPR, 173 FERC ] 61,165 at P 125.
\720\ Id. P 126.
---------------------------------------------------------------------------
307. The Commission also acknowledged that sharing transmission
line ratings and transmission line rating methodologies with other,
additional, interested parties would allow for
[[Page 2292]]
greater transparency and, in the case of transmission providers, may
aid efforts to manage congestion along mutual seams and may be
beneficial for the study of affected systems during the interconnection
process.\721\ The Commission thus sought comment on whether to require
transmission owners to share, upon request, their transmission line
ratings and transmission line rating methodologies with transmission
providers other than the transmission owner's own transmission
provider. The Commission also sought comment on whether to require
transmission owners to make their transmission line ratings and
transmission line rating methodologies available to other interested
stakeholders, including by posting information on their OASIS page or
other password-protected online forums.\722\
---------------------------------------------------------------------------
\721\ Id. P 129.
\722\ Id.
---------------------------------------------------------------------------
308. While the Commission did not propose new auditing requirements
in the NOPR, the Commission reiterated that it would continue to
conduct reviews of transmission line ratings as a component of broader
tariff compliance audits.\723\
---------------------------------------------------------------------------
\723\ Id. P 130.
---------------------------------------------------------------------------
2. Comments
a. Increased Transparency Requirements for Transmission Line Ratings
Methodologies
309. Many commenters express general support for the Commission's
efforts to increase transparency surrounding transmission line ratings
and methodologies.\724\ MISO Transmission Owners argue that the
transparency proposal in the NOPR seems reasonable, but should not be
broadened, explaining that the transparency proposal in the NOPR
balances the need for transparency for RTOs/ISOs and market monitors
with the need for confidentiality.\725\ Industrial Customer
Organizations state that transparency is a prerequisite for
stakeholders to independently evaluate the potential reliability
benefits of more accurate transmission line ratings, for the Commission
to ensure just and reasonable rates, to reduce the incentives and
opportunities for transmission owners to understate or manipulate
transmission line ratings, and for transmission providers to identify
cost-effective congestion management solutions.\726\ EDFR claims that
increased transparency may result in more efficient and standardized
transmission line rating methodologies while identifying outliers more
quickly and that transparency encourages the use of a balanced,
reasonable transmission line rating methodology, which should result in
more accurate transmission line ratings.\727\ OMS states that the
Commission's regulations require transmission line rating
transparency.\728\ OMS further contends that transparency should be the
default position and should only be restricted where demonstrably
necessary.\729\ EPSA states that transparent collection and disclosure
of quality data is the lynchpin of an efficient transmission
system.\730\ Certain TDUs state that improved transparency of
transmission line ratings processes will ultimately lead to a more
efficient and cost-effective grid.\731\ IID supports the Commission's
proposed requirements and encourages the Commission to consider how
such information can be shared in a timely manner, such that adjacent
operators and users of the grid can account for current transmission
line ratings in their weekly and day-ahead planning.\732\
---------------------------------------------------------------------------
\724\ MISO Transmission Owners Comments at 19; Entergy Comments
at 16; NRECA/LPPC Comments at 27-28; AEP Comments at 5; DC Energy
Comments at 5; IID Comments at 7.
\725\ MISO Transmission Owners Comments at 36.
\726\ Industrial Customer Organizations Comments at 28-29.
\727\ EDFR Comments at 7.
\728\ OMS Comments at 17 n.57 (citing 18 CFR 37.6).
\729\ OMS Reply Comments at 3-4.
\730\ EPSA Comments at 3.
\731\ Certain TDUs Comments 8.
\732\ IID Comments at 7.
---------------------------------------------------------------------------
b. Sharing Transmission Line Ratings and Methodologies With
Transmission Providers and Market Monitors
310. Nearly all commenters support the proposal in the NOPR to
require transmission owners to share transmission line ratings and
methodologies with the relevant transmission provider and, in the case
of transmission providers that are RTOs/ISOs, the relevant market
monitor.\733\ AEP and Exelon note that PJM posts actual transmission
line ratings publicly.\734\
---------------------------------------------------------------------------
\733\ AEP Comments at 8; CAISO DMM Comments at 3, 7-8; OMS
Comments at 16; Exelon Comments at 23-24; DC Energy Comments at 5;
Potomac Economics Comments at 16; IID Comments at 7; New England
State Agencies Comments at 17-19; R Street Institute Comments at 3;
SPP MMU Comments at 5; TAPS Comments at 23.
\734\ AEP Comments at 8; Exelon Comments at 23-24.
---------------------------------------------------------------------------
311. DC Energy contends that implementing AARs and DLRs and
requiring RTOs/ISOs to post the transmission line ratings used for each
constraint-binding interval for both the day-ahead and real-time
markets is not an infeasible or unduly burdensome task.\735\ DC Energy
notes that ERCOT publishes every transmission line rating used for
every constraint's binding interval for both its day-ahead and real-
time markets on its market information system portal accessible by all
market participants.\736\
---------------------------------------------------------------------------
\735\ DC Energy Comments at 5.
\736\ Id.
---------------------------------------------------------------------------
312. Potomac Economics contends that the information shared must
include the limiting element for each transmission line rating and the
inputs necessary to replicate the transmission line rating calculation
to monitor for transmission withholding, and that such information
should be maintained in a database accessible by those with a role in
monitoring, operating, and planning the transmission system.\737\ EDFR
supports a requirement that transmission owners provide information
identifying the transmission line's limiting element.\738\ New England
State Agencies agree with the reforms proposed in the NOPR with a
minimum of requiring disclosure of transmission line ratings and
methodologies to all grid operators and market monitors.\739\ New
England State Agencies state such a requirement would allow
verification of the existing transmission line ratings by independent
authorities.\740\ New England State Agencies assert that providing data
to the RTO/ISO market monitor would allow the market monitor to verify
the quality and accuracy of the information.\741\ New England State
Agencies contend that transmission owners may have an incentive to be
overly conservative with transmission line ratings methodologies
because there is no financial incentive for more efficient operation of
existing transmission assets and there is significant incentive for
transmission owners to build new transmission lines and substations and
include these new assets in their rate base.\742\ Because NYISO and PJM
already require similar data disclosure, New England State Agencies
claim that transmission owners can comply without undue difficulty with
the proposed requirements and that there is no actual evidence in the
record of any increased litigation in those regions where disclosure is
common.\743\
---------------------------------------------------------------------------
\737\ Potomac Economics Comments at 16-17.
\738\ EDFR Comments at 6.
\739\ New England State Agencies Comments at 19.
\740\ Id.
\741\ Id. at 17-18.
\742\ Id. at 18.
\743\ Id. at 20.
---------------------------------------------------------------------------
313. NRECA/LPPC caution that their members do not believe the
Commission
[[Page 2293]]
should require RTOs/ISOs to develop and maintain comprehensive
databases to document the limiting element of all transmission circuits
and facilities in their regions, arguing that the benefit to consumers
is unclear and that the NOPR does not support such a requirement.\744\
---------------------------------------------------------------------------
\744\ NRECA/LPPC Comments at 27-28.
---------------------------------------------------------------------------
314. Only two commenters object to the proposed transparency
requirements. Dominion states that requiring that transmission line
ratings and methodologies be disclosed to the RTO/ISO market monitor is
unwarranted because transmission line ratings are primarily reliability
tools and are effectively overseen by NERC.\745\ Dominion states that
it already provides transmission line ratings to PJM and PJM makes them
publicly available.\746\ While Dominion does not object to continuing
these practices, Dominion does object to providing its transmission
line rating methodology to the PJM market monitor, which Dominion
argues has no oversight over the operation of the PJM transmission
system.\747\ Separately, ITC argues that requirements to make all
transmission line ratings available to the RTOs/ISOs, market monitor,
and other stakeholders would be unduly burdensome.\748\ ITC states that
only a small number of transmission lines contribute to congestion and
that regular reporting may increase the probability of inconsistencies
between ITC's internal databases and those used for external data
requests.\749\ ITC therefore requests that the final rule require
transmission owners to provide such data only upon request. ITC argues
that RTOs/ISOs and market monitors should use shared transmission line
ratings for informational purposes only and not for standardization
purposes.\750\
---------------------------------------------------------------------------
\745\ Dominion Comments at 14-15.
\746\ Id.
\747\ Id.
\748\ ITC Comments at 13.
\749\ Id.
\750\ Id.
---------------------------------------------------------------------------
c. Transmission Providers Sharing Transmission Line Ratings and
Methodologies With Any Transmission Provider
315. Several commenters support a requirement for transmission
providers to share, upon request, transmission line ratings and
methodologies with any transmission provider.\751\ APS states that this
sharing of information is essential to ensure security in APS's
transmission operator area.\752\ MISO states that, in addition to the
proposed transparency requirements in the NOPR, sharing the same
information with neighboring transmission providers that share a seam
with MISO is needed.\753\ MISO asserts that such sharing of these
transmission line ratings would be necessary for both tie lines and
interregional congestion management, useful for reliability studies
involving the neighboring regions, consistent with other coordination
practices, and subject to confidentiality restrictions to control
dissemination.\754\ Similarly, Vistra argues that the Commission should
clarify that transmission providers must share AAR information with
neighboring transmission providers because transmission line rating
calculations typically consider loop flows.\755\ Vistra explains that,
logistically, this information sharing could take many forms, including
direct data pushes between transmission providers or publishing such
information on OASIS sites and that the Commission need not dictate a
particular information sharing method.\756\
---------------------------------------------------------------------------
\751\ APS Comments at 8; PacifiCorp Comments at 3; MISO Comments
at 29; EPSA Comments at 3; Exelon Comments at 27; IID Comments at 7.
\752\ APS Comments at 8.
\753\ MISO Comments at 29.
\754\ Id.
\755\ Vistra Comments at 7-8.
\756\ Id.
---------------------------------------------------------------------------
d. Sharing Transmission Line Ratings and Methodologies With Other
Entities
316. Some commenters support requiring the sharing of transmission
line ratings and methodologies with entities other than transmission
providers and market monitors.\757\ For example, WATT contends that
transmission line rating methodologies need to be shared with all
transmission customers.\758\ R Street Institute argues that the NOPR
proposal would provide insufficient transparency and that, ideally,
transmission line ratings and methodologies would be available to a
broader set of market participants and state commissions as well.\759\
OMS similarly asserts that all stakeholders should be able to see
transmission line ratings and that the market monitor and MISO should
be granted complete transparency into the methods used to create these
transmission line ratings, recognizing that the regional entities are
strictly focused on reliability.\760\
---------------------------------------------------------------------------
\757\ APS Comments at 9; Clean Energy Parties Comments at 14;
EPSA Comments at 3; Exelon Comments at 28-29; EDFR Comments at 7;
New England State Agencies Comments at 20; OMS Comments at 16; R
Street Institute Comments at 3; TAPS Comments at 24; WATT Comments
at 14.
\758\ WATT Comments at 14.
\759\ R Street Institute Comments at 3.
\760\ OMS Comments at 16.
---------------------------------------------------------------------------
317. TAPS urges the Commission to allow interested persons to
access transmission line ratings and methodologies through password-
protected interfaces, such as OASIS, such that if a transmission
customer has concerns about the impact of a constraint, it should be
able to obtain information on the transmission line ratings and
methodologies used to establish such ratings. TAPS contends that doing
so would enable transmission customers to better understand what is
driving the prices that they are required to pay.\761\ APS states it
would not support posting transmission line ratings and methodologies
on OASIS, but would support other password-protected online forums
where access could be controlled.\762\ To expand transmission line
rating information and reduce the information gap, ACPA/SEIA suggests
that there are several options, including expanding the FERC Form 715
reporting requirements or making this information available on OASIS
sites.\763\ DC Energy asks that the Commission require transmission
owners outside of organized electricity markets to post transmission
line ratings and methodologies on their OASIS pages or another
password-protected online forum.\764\
---------------------------------------------------------------------------
\761\ TAPS Comments at 24.
\762\ APS Comments at 9.
\763\ ACPA/SEIA Comments at 19-20.
\764\ DC Energy Comments at 5-6.
---------------------------------------------------------------------------
318. Clean Energy Parties contend that requiring transmission
owners to disclose their transmission line ratings and methodologies to
RTOs/ISOs and market monitors but not share with the broader public is
unduly discriminatory.\765\ Exelon requests flexibility to allow
transmission providers, like PJM, to publish transmission line ratings
consistent with existing practices.\766\ ACPA/SEIA contends that the
Commissions should require that all market participants have comparable
information on near-term transmission service.\767\ ACPA/SEIA argues
that because near-term transmission service information would only be
available to transmission owners, RTOs/ISOs, and market monitors, there
would be a discriminatory ``information gap,'' putting transmission
customers at a disadvantage by not being able to easily identify
optimal interconnection locations and not being able to understand or
reproduce AAR or DLR congestion analyses.\768\
---------------------------------------------------------------------------
\765\ Clean Energy Parties Comments at 14.
\766\ Exelon Comments at 28-29.
\767\ ACPA/SEIA Comments at 19-20.
\768\ Id. at 18-19.
---------------------------------------------------------------------------
319. New England State Agencies argue that it is important to
states that
[[Page 2294]]
have relied on competitive procurements for certain types of energy
development needs to have access to transmission line ratings and
methodologies.\769\ According to New England State Agencies, the
Commission's requirement in Order No. 1000 that transmission providers
consider public policy transmission needs as part of regional
transmission planning processes would be materially aided by allowing
open access to transmission line ratings and similar data.\770\ New
England State Agencies state that password protections and non-
disclosure agreements can be used in protecting confidential
information in a wide variety of circumstances if there is concern
about loss of confidential business information.\771\
---------------------------------------------------------------------------
\769\ New England State Agencies Comments at 20.
\770\ Id.
\771\ Id.
---------------------------------------------------------------------------
320. Conversely, several commenters oppose further sharing beyond
transmission providers and, where appropriate, market monitors.
PacifiCorp states that it strongly opposes making its transmission line
ratings broadly available to stakeholders or posting such information
to OASIS due to the potential for reliability risks and unclear
benefits.\772\ MISO Transmission Owners state that there appears to be
no need for transmission line ratings to be public because: (1) ATC is
made available to the public; (2) transmission line ratings are only
one of many inputs into ATC; and (3) ATC is made available on OASIS
pages.\773\ PG&E recommends against requiring transmission owners and
transmission providers to post real-time transmission line ratings on
their OASIS pages, noting that transmission line rating methodologies
should also not be disclosed to any parties other than the Commission
and other transmission providers.\774\ Indicated PJM Transmission
Owners argue that requiring transmission line ratings and methodologies
to be made public would be unnecessary in PJM, given the existing
information is made available.\775\ EEI recommends that the Commission
not require transmission owners and transmission providers to post
real-time transmission line ratings on their OASIS pages but instead
provide only the methodologies for determining AARs and seasonal line
ratings.\776\
---------------------------------------------------------------------------
\772\ PacifiCorp Comments at 4.
\773\ MISO Transmission Owners Comments at 37.
\774\ PG&E Comments at 12.
\775\ Indicated PJM Transmission Owners Comments at 23-24.
\776\ EEI Comments at 13.
---------------------------------------------------------------------------
e. Auditing, Enforcement, and Litigation
321. Several commenters note that NERC already audits transmission
line ratings and argue that any transmission line ratings verification
or transmission line ratings auditing performed by market monitors
would be unnecessary or harmful.\777\ Exelon states that, were a market
monitor to allege improper transmission line rating calculations which
NERC has already approved, there could be dueling determinations and
confusion and potential inconsistency with FPA section 215, which
specifies that NERC, as the Electric Reliability Organization, is
responsible for enforcing mandatory Reliability Standards.\778\ Exelon,
AEP, and MISO Transmission Owners allege that calculating transmission
line ratings requires a degree of engineering judgment, reflective of
transmission owners' operational experience, risk tolerance, and local
knowledge.\779\ Exelon argues that market monitors lack this
knowledge.\780\ AEP argues that RTOs/ISOs should have no role beyond
applying submitted transmission line ratings.\781\ EEI asks that the
Commission emphasize that any final rule would not change the audit and
enforcement construct already in place and that the audits should not
specifically review the transmission line rating methodologies and
assumptions.\782\ MISO Transmission Owners explain that it may not
present a problem for RTOs/ISOs and market monitors to identify
computational transmission line ratings errors, but RTOs/ISOs and
market monitors should not be permitted to second-guess transmission
line rating methodologies.\783\ Indicated PJM Transmission Owners
explain that the functions of the PJM market monitor are limited to
those items identified by Attachment M of the PJM OATT, requiring the
market monitor to assess the competitiveness of the ``PJM markets, but
not monitor transmission line ratings as it does not have the requisite
expertise or reliability authority.\784\ Indicated PJM Transmission
Owners disagree with the Commission's statement that the NERC
Reliability Standards may be insufficient to ensure accurate
transmission line ratings.\785\ Sunflower argues that the Commission
should require specific measures for transmission providers to monitor
the impact of AARs and seasonal line ratings on the safety and
reliability of the electric system.\786\
---------------------------------------------------------------------------
\777\ Exelon Comments at 24; AEP Comments at 8-9; EEI Comments
at 13-14; Indicated PJM Transmission Owners Comments at 17-18.
\778\ Exelon Comments at 25-26.
\779\ Id. at 26-27; AEP Comments at 9; MISO Transmission Owners
Comments at 37-38.
\780\ Exelon Comments at 26-27.
\781\ AEP Comments at 9.
\782\ EEI Comments at 13-14.
\783\ MISO Transmission Owners Comments at 37-38.
\784\ Indicated PJM Transmission Owners Comments at 22-23.
\785\ Id. at 19-21.
\786\ Sunflower Comments at 4.
---------------------------------------------------------------------------
322. Some commenters argue for further oversight and expansion of
the auditing of transmission line ratings and methodologies. Potomac
Economics recommends that the Commission require some form of
independent oversight, verification, and monitoring of the transmission
line ratings calculated and used in non-RTO/ISO areas.\787\ Potomac
Economics contends that it is important to clarify that transmission
line rating information that underlies curtailments under transmission
line ratings or joint operating agreements be available to other
transmission providers, reliability coordinators, or RTOs/ISOs that are
affected by the curtailments.\788\ Ohio FEA recommends that PJM
routinely review submitted transmission line ratings and the
methodologies used in their development; otherwise, Ohio FEA continues,
the benefits associated with implementing AARs may prove to be illusory
if the transmission line ratings themselves are not based on objective
and accurate criteria.\789\ Ohio FEA insists that the PJM market
monitor must be granted the authority to review transmission line
ratings and take corrective actions deemed necessary if the market
monitor concludes that a transmission owner's transmission line ratings
are inaccurate, consistent with the market monitor's role as defined in
Attachment M of the PJM OATT.\790\
---------------------------------------------------------------------------
\787\ Potomac Economics Comments at 18; see also Potomac
Economics Reply Comments at 12.
\788\ Potomac Economics Comments at 18.
\789\ Ohio FEA Comments at 5-6.
\790\ Id. at 6.
---------------------------------------------------------------------------
323. Many commenters express concern over potential litigation
regarding transmission line ratings and methodologies (though AEP
states that the proposed requirements in the NOPR adequately mitigate
litigation risks).\791\ EEI argues that third parties should not be
able to litigate or dispute transmission line ratings or
methodologies.\792\ Exelon caveats that its position supporting
additional transparency is contingent on the Commission ensuring that
the enhanced transparency does not result in constant litigation from
market participants, provided such transmission line ratings
[[Page 2295]]
and calculations are reasonably accurate at reflecting a transmission
facility's power transfer capability, as transmission line ratings are
fundamentally a reliability concept.\793\ MISO Transmission Owners
argue that transparency requirements beyond those proposed in the NOPR
that result in an increase in disputes and litigation surrounding
transmission line ratings and/or methodologies would reduce the
benefits of the proposed reforms. MISO Transmission Owners therefore
contend that the Commission should clarify its statement in the NOPR
that the proposed increased transparency will allow RTOs/ISOs and
market monitors to verify transmission line ratings.\794\ Similarly,
Indicated PJM Transmission Owners warn that further transparency
disclosure requirements would result in costly and time consuming
litigation, and thereby increased burdens on transmission owners and
the Commission, as a result of arguments from market participants
soliciting changes designed to benefit themselves and negatively affect
others. Indicated PJM Transmission Owners stress that this would be
inappropriate because transmission line ratings are complex
calculations, based on many different factors, including local assets,
engineering judgment, and how assets are traditionally operated, and
therefore litigation with the Commission would be inappropriate.\795\
ITC requests that the final rule clarify that incorrect transmission
line ratings due to changes in weather or unintentional errors in data
that were submitted in good faith should not create additional legal or
regulatory liability for transmission owners. ITC states that it would
not benefit from such errors since it is primarily concerned with
reliability and does not participate in markets.\796\ Conversely to
these commenters, AEP expresses that the Commission's NOPR strikes the
right balance between providing transparency without creating risks of
unnecessary litigation for transmission owners if transmission line
ratings cannot be precisely replicated by third parties.\797\
Furthermore, DC Energy contends that the need for disclosure outweighs
transmission owners' claims of confidentiality or fear of potential
litigation.\798\
---------------------------------------------------------------------------
\791\ AEP Comments at 10.
\792\ EEI Comments at 13-14.
\793\ Exelon Comments at 29.
\794\ MISO Transmission Owners Comments at 37-38 (citing NOPR,
173 FERC ] 61,165 at P 127).
\795\ Indicated PJM Transmission Owners Comment at 24.
\796\ ITC Comments at 16.
\797\ AEP Comments at 9-10.
\798\ DC Energy Comments at 5.
---------------------------------------------------------------------------
f. Posting of Exceptions to OASIS
324. 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.\799\
---------------------------------------------------------------------------
\799\ EPSA Comments at 4.
---------------------------------------------------------------------------
g. Other Transparency Topics
325. ISO-NE states that to comply with the NOPR's proposed
transparency requirements, it would need to modify Planning Procedure
No. 7, Procedures for Determining and Implementing Transmission
Facility Ratings (PP7) as New England Transmission Owners are required
to follow the PP7 procedures to determine transmission line rating
methodologies.\800\ ISO-NE requests that the Commission allow for
sufficient time for the PP7 changes to make their way through the
applicable processes for the transmission owners to implement those
changes and then provide new transmission line ratings to ISO-NE and
its market monitor in the manner contemplated in the NOPR.\801\
---------------------------------------------------------------------------
\800\ ISO-NE Comments at 11.
\801\ Id. at 11.
---------------------------------------------------------------------------
326. NRECA/LPPC recommend that any measures in the final rule to
improve the transparency of transmission line ratings should be
consistent with the requirements of existing mandatory NERC Reliability
Standards, including Critical Infrastructure Protection (CIP)
Standards, as well as requirements to protect Critical Electric/Energy
Infrastructure Information (CEII).\802\
---------------------------------------------------------------------------
\802\ NRECA/LPPC Comments at 3.
---------------------------------------------------------------------------
327. OMS suggests that the Commission could revisit the data it
currently collects in FERC Form 715 to better analyze how the data
already being collected can be used to understand some transmission
owners' transmission line ratings and methodologies but not
others.\803\ OMS also suggests that the Commission consider a comment
and response process between transmission owners, transmission
providers, and market monitors to provide additional oversight into the
appropriateness of transmission line ratings throughout the bulk power
system.\804\
---------------------------------------------------------------------------
\803\ OMS Comments at 17.
\804\ Id.
---------------------------------------------------------------------------
328. Clean Energy Parties contend that RTOs/ISOs should be required
to discuss with stakeholders and report to the Commission how winter
capacity deliverability differs from summer and identify possible
reliability improvements or cost savings arising from those
differences.\805\
---------------------------------------------------------------------------
\805\ Clean Energy Parties Comments at 12.
---------------------------------------------------------------------------
329. Some commenters assert a connection between transparency
around transmission line ratings and FTR markets. EDFR states that
transparency provides market participants with a better understanding
of how transmission line ratings could change over time while helping
to anticipate congestion, hedge congestion, and participate in the FTR
markets.\806\ DC Energy states that market participants, particularly
those that purchase and sell FTRs, need transparency in order to
critically analyze and address market inefficiencies.\807\ DC Energy
contends that FTR market participants will require transparent
transmission line rating and methodology information in order to
accurately forecast congestion.\808\ DC Energy asserts that
transparency is essential for the transition to AARs and DLRs because,
without adequate transparency, AARs and DLRs could actually make
congestion hedges less accurate. This is because, according to DC
Energy, AARs and DLRs will cause transmission line ratings to change
without advance notification and, in times of adverse system
conditions, AARs and DLRs will more accurately reflect the fact that
less transfer capability is available.\809\
---------------------------------------------------------------------------
\806\ EDFR Comments at 7.
\807\ DC Energy Comments at 3-4.
\808\ Id. at 4.
\809\ Id. at 5.
---------------------------------------------------------------------------
3. Commission Determination
330. Upon consideration of the comments received, we adopt the NOPR
proposal to require public utility transmission owners to share their
transmission line ratings for each period for which they are calculated
and transmission line rating methodologies with their transmission
providers and with market monitors in RTOs/ISOs. We acknowledge
situations in which the transmission owner and transmission provider
are the same entity, and we expect that in such cases compliance with
this final rule's transparency requirements will be simple in the sense
that the transmission provider will not have to rely on a separate
transmission
[[Page 2296]]
owner to provide the transmission line ratings and methodologies. We
also adopt three additional transparency requirements. First, we
require each transmission provider to share transmission line ratings
and methodologies with any transmission provider(s) upon request.
Second, we require each transmission provider to maintain a database of
its transmission line ratings and methodologies on the transmission
provider's OASIS site, or other password-protected website. We require
that this database be in such a form that can be accessed by all
parties with OASIS access or access to the password-protected website.
The database should archive and allow for querying of all current
transmission line ratings and all transmission line ratings used in the
past five years. Third, we require transmission providers to post on
OASIS, or other password-protected website, which transmission lines
qualify for an exception to the AAR or seasonal line rating
requirements and the reasons why such transmission lines qualify for an
exception.
a. Transmission Owners Sharing Ratings and Methodologies With
Transmission Providers and, Where Applicable, Market Monitors
331. We find that requiring public utility transmission owners to
share transmission line ratings and methodologies with their
transmission providers and, in RTOs/ISOs, market monitors, will help
remedy unjust and unreasonable wholesale rates caused by inaccurate
transmission line ratings. We affirm the Commission's preliminary
finding in the NOPR that this requirement will enhance operational and
situational awareness by ensuring that transmission providers know the
effect that changes in ambient air temperature would have on
transmission line ratings within their system.\810\ Further, as the
Commission explained in the NOPR, this requirement will provide
transmission providers and market monitor(s) the information necessary
to verify the resulting transmission line ratings and to identify
potential errors.\811\
---------------------------------------------------------------------------
\810\ NOPR, 173 FERC ] 61,165 at P 127.
\811\ Id.
---------------------------------------------------------------------------
332. We agree with EDFR that the transparency-increasing effects of
requiring public utility transmission owners to share transmission line
ratings and methodologies with their transmission provider(s), and with
market monitors in RTOs/ISOs, will result in more accurate transmission
line ratings. By sharing transmission line ratings and methodologies
with transmission providers and market monitors, these parties will be
better positioned to develop automated screens and other techniques to
detect corrupted data or other errors that could negatively impact
operations or planning processes.
333. We disagree with arguments that because transmission line
ratings are reliability tools that are effectively overseen by NERC,
additional transparency requirements are unnecessary. While
transmission line ratings are an important reliability tool, we find
(as discussed above in Section III) that transmission line ratings
directly affect wholesale rates. Further, commenters have not explained
why a relationship between transmission line ratings and reliability
would represent a reason not to adopt the transparency requirements. We
also disagree with comments that requiring public utility transmission
owners to share transmission line ratings and methodologies with their
transmission provider(s) and with market monitors in RTOs/ISOs would be
unduly burdensome and could create inconsistencies between transmission
line ratings used internally by transmission owners and transmission
line ratings used by transmission providers. We recognize comments from
New England State Agencies noting that such disclosure is already
common in some markets, and that this indicates that transmission
owners can comply without undue difficulty.\812\ Moreover, we think it
is unlikely that sharing of transmission line ratings would create
inconsistencies in the manner described by ITC. On the contrary, we
believe that a benefit of this requirement would be to identify and
promote the resolution of such inconsistencies.
---------------------------------------------------------------------------
\812\ New England State Agencies Comments at 20.
---------------------------------------------------------------------------
334. Finally, we reiterate that the Commission will continue to
conduct reviews of transmission line ratings as a component of broader
tariff compliance audits \813\ and that this final rule does not change
the auditing requirements or authorities of any entity.
---------------------------------------------------------------------------
\813\ Many commenters use the term ``audit'' to describe
activities by market monitors and other entities that the
Commission's rules do not define as auditing. We note that the
Commission retains its authority to formally audit for compliance
with OATTs and other Commission-jurisdictional rules.
---------------------------------------------------------------------------
b. Transmission Providers Sharing With Any Transmission Provider(s)
Upon Request
335. As set forth under ``Obligations of Transmission Provider'' in
pro forma OATT Attachment M, we further require transmission providers
to share transmission line ratings and methodologies with any
transmission provider(s) upon request and in a timely manner. We agree
with commenters that contend that this requirement is necessary because
transmission operators often consider the effect that power flows on
their transmission lines will have on other transmission providers'
transmission lines, and transmission providers will need transmission
line ratings on other systems to evaluate these effects properly. While
we acknowledge that Vistra's example involved neighboring transmission
providers, we do not limit this requirement to neighboring transmission
providers, as such power flow effects can sometimes extend beyond
neighboring transmission providers (particularly if a neighboring
transmission provider's system is geographically/electrically narrow
where it approaches another transmission provider's system). Further,
we agree with commenters that this information sharing could take
several forms, and that the Commission need not dictate an information
sharing method. However, any such information sharing method should be
sufficient to accommodate the reasonable business needs of the other
transmission provider(s) (e.g., to allow the other transmission
provider(s) to process transmission service requests in a timely
manner).
c. Transmission Providers Sharing With Other Entities
336. We further require each transmission provider to maintain a
database of their transmission owners' transmission line ratings and
methodologies on the password-protected section of their OASIS site or
other password-protected website. This requirement will allow other
entities (beyond transmission providers and market monitors) that are
able to access the password-protected section of the transmission
provider's OASIS site or other password-protected website to have
access to the database of transmission line ratings and methodologies.
This requirement is set forth under ``Obligations of Transmission
Provider'' in pro forma OATT Attachment M. We agree with commenters
that making transmission line ratings and methodologies available to a
broader range of stakeholders will amplify the expected benefits of the
proposal included in the NOPR, further facilitate more accurate
transmission line ratings, and facilitate more cost-effective decisions
by market participants and, as described by New England State Agencies,
state agencies. For example, without accurate
[[Page 2297]]
transmission line rating information, market participants may be unable
to make informed siting decisions regarding where to build generation
or where to site load. Also, without accurate transmission line rating
information, market participants may be unable to accurately predict
and hedge against transmission congestion. Moreover, as New England
State Agencies argue, access to transmission line ratings and
transmission line rating methodologies is important to states that have
relied on competitive procurements for certain types of energy
development needs.\814\ We acknowledge that requiring this information
to be placed on OASIS or other password-protected website presents a
burden on transmission providers, but we find that the benefits of
increased transparency are likely to outweigh any such burden.
---------------------------------------------------------------------------
\814\ New England State Agencies Comments at 20.
---------------------------------------------------------------------------
337. Beyond enhancing the general benefits of the transmission line
rating requirements adopted herein, we find that transparency for
transmission line ratings and methodologies will also be particularly
beneficial to wholesale market participants trying to manage
uncertainty. With respect to FTR market participants, for example, we
agree with DC Energy that, because FTR payouts are based on congestion
costs that change with transmission line ratings, sharing transmission
line ratings and methodologies with a wider range of stakeholders will
help establish efficient FTR market price discovery by improving FTR
market participants' understanding of certain drivers of congestion,
and allow such market participants to build such understanding into
their FTR bids and offers.\815\
---------------------------------------------------------------------------
\815\ DC Energy Comments at 3. While different RTOs/ISOs have
different names for these financial products, such as financial
transmission rights, transmission congestion rights, congestion
revenue rights, etc., for simplicity here we will use FTRs to refer
to any such financial product in the RTOs/ISOs.
---------------------------------------------------------------------------
338. We disagree with arguments contending that requiring each
transmission provider to maintain a database of each transmission
owner's transmission line ratings and methodologies on the transmission
provider's OASIS site or other password-protected website will lead to
unjust and unreasonable wholesale rates or other undesirable outcomes.
Specifically, we are not persuaded by comments that making transmission
line ratings and methodologies available to a broader range of
stakeholders could result in increased litigation whereby customers
initiate complaints against transmission owners regarding the
underlying assumptions used to calculate transmission line ratings or
regarding the calculations themselves. There is a lack of evidence of
increased litigation in those regions where disclosure is already
common, as noted by the New England State Agencies.\816\ Moreover,
commenters have not identified any complaints or other such litigation
about transmission line ratings related to this existing requirement.
Further, consistent with the Commission's statement in the NOPR,\817\
we intend to give latitude to transmission owners to determine their
transmission line ratings in accordance with good utility practice.
Finally, we note that section 37.6 of the Commission's regulations
already requires transmission providers, upon customer request, to make
all data used to calculate ATC for any constrained posted path publicly
available on OASIS. This includes the limiting elements and the cause
of the limit (e.g., thermal, voltage, stability), as well as load
forecast assumptions.\818\ The posting requirement for transmission
line ratings and methodologies is consistent with that existing
requirement.
---------------------------------------------------------------------------
\816\ New England State Agencies Comments at 20.
\817\ NOPR, 173 FERC ] 61,165 at PP 98, 105.
\818\ See 18 CFR 37.6.
---------------------------------------------------------------------------
339. Transmission line ratings stored in the required database must
include a full record of all transmission line ratings, both as used in
real-time operations, and as used for all future market periods for
which transmission service is offered. For example, a transmission
provider that implements AARs calculated for the next 240 hours (for
use in evaluating near-term transmission service requests), re-
calculates such AARs every hour, and calculates seasonal line ratings
(for use in evaluating longer-term transmission service requests) would
keep records of its transmission line ratings in the following manner.
With respect to its AARs, such a transmission provider would insert
records into its transmission line rating database each hour, shortly
after calculation of its AARs. In each such hour, the transmission
provider would insert a separate AAR record into its database for: (1)
Each transmission line; (2) each current and forward hour for which
transmission line ratings are calculated (at least one rating for each
of the 240 hours in the next 10 days); and (3) each rating type (normal
and each type of emergency rating (e.g., 30 minute, one hour, etc.)).
If such a transmission provider had 1,000 transmission lines and four
rating types (e.g., normal, 30 minute, one hour, and four hour), then
each hour the transmission provider would insert into its database
960,000 new AAR records (1000 x 240 x 4).\819\ Furthermore, such a
transmission provider would also maintain in its database records of
which seasonal line ratings (for use in evaluating longer-term
transmission service requests) or other types of transmission line
ratings (as permitted under pro forma OATT Attachment M, e.g., static
line ratings) were in effect at which times for each transmission
line.\820\ Finally, while we are not requiring implementation of DLRs
at this time, we note that if a transmission provider implements DLRs
on any of its transmission lines, then under this requirement it would
document the DLR ratings on such transmission lines in the same way
that it documents its AAR ratings, as discussed above.
---------------------------------------------------------------------------
\819\ We note that transmission providers may determine that
there are more efficient ways of storing the AAR data than presented
in the example above, and such approaches may be acceptable as long
as users of the database can readily identify which such ratings
(including for the operational hour and any forward hours) were in
effect for which transmission lines at which times.
\820\ We do not specify exactly how records of seasonal or
static line ratings should be stored in the line rating database.
However, such longer-term transmission line ratings do not
necessarily need to be stored on an hourly basis, so long as users
of the database can readily identify which such ratings were in
effect for which transmission lines at which times. We note that
some transmission lines may not have any AAR ratings at all, where
permitted under pro forma OATT Attachment M, and so may only have
ratings such as seasonal or static line ratings.
---------------------------------------------------------------------------
340. Transmission providers must maintain in their database 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 other document retention
periods required for OASIS postings.\821\ Each record in the database
must indicate to which transmission line the record applies, and the
date and time the record was entered into the database. Finally, the
database must be maintained such that users can view, download, and
query data in standard formats, using standard protocols.
---------------------------------------------------------------------------
\821\ 18 CFR 37.6 (Information to be posted on the OASIS).
---------------------------------------------------------------------------
d. Transmission Providers Posting Exceptions and Temporary Alternate
Ratings to OASIS
341. Finally, in response to EPSA, we require transmission
providers to make postings to the database of transmission line ratings
on their OASIS site or other password-protected website (discussed
above in Section IV.G.3.d) documenting
[[Page 2298]]
any uses of exceptions (under the ``Exceptions'' paragraph of pro forma
OATT Attachment M) or temporary alternate ratings (under the ``System
Reliability'' section of pro forma OATT Attachment M). This requirement
to post exceptions and temporary alternate ratings on OASIS or other
password-protected website is set forth in pro forma OATT Attachment M.
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.
342. We find that the requirement for such postings will help
ensure proper transparency for the use of such exceptions and temporary
alternate ratings, similar to the transparency provided through other
posting requirements of this final rule.\822\ Furthermore, these
postings of exceptions will support the fulfillment of and verification
of compliance with the requirement, discussed above in Section IV.D.3,
that exceptions be re-evaluated at least every five years.
---------------------------------------------------------------------------
\822\ See, 18 CFR 37.6 (Information to be posted on the OASIS).
---------------------------------------------------------------------------
343. Similar to the benefits discussed above in Section IV.G.3.c
related to requiring transmission line ratings and methodologies to be
available on OASIS sites or other password-protected websites, we find
that this requirement for exceptions postings will enable and support
verification of the accuracy of transmission line ratings.
H. Other Miscellaneous Issues
1. Comments
344. Some commenters argue for incentives to encourage DLR
deployment. Specifically, NYTOs and ACORE request financial incentives
for AARs and DLRs under FPA section 219.\823\ ACPA/SEIA contend that
the Commission should consider accelerated cost recovery of
depreciation to implement sensor-based DLRs.\824\ Although WATT urges
the Commission to address the misalignment of incentives to adopt DLRs
or other grid-enhancing technologies, WATT asserts that the Commission
should not grant incentives for DLRs in this docket.\825\
---------------------------------------------------------------------------
\823\ NYTOs Comments at 2; ACORE Comments at 3-4.
\824\ ACPA/SEIA Comments at 11.
\825\ WATT Comments at 16.
---------------------------------------------------------------------------
345. MISO contends that while AARs may provide incremental transfer
capability on existing transmission lines, they cannot solve
significant long-range transmission problems.\826\ Moreover, EEI argues
that chronic congestion should be reviewed and alleviated in the
transmission planning process.\827\
---------------------------------------------------------------------------
\826\ MISO Comments at 2, 6-7.
\827\ EEI Comments at 6.
---------------------------------------------------------------------------
2. Commission Determination
346. In response to arguments about incentives for advanced
transmission technology deployment, we find such arguments about
incentivizing certain technology to be outside the scope of this
proceeding, which is limited to the Commission's proposed requirements
for transmission line ratings.
347. In response to MISO's assertion that AARs cannot solve
significant long-range transmission problems, we find transmission
planning and development to be outside the scope of this proceeding.
For the same reason, we find EEI's claim that chronic congestion should
be reviewed and alleviated in the transmission planning process to be
outside the scope of this proceeding. 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.\828\
---------------------------------------------------------------------------
\828\ 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).
---------------------------------------------------------------------------
I. Compliance
1. NOPR Proposal
348. In the NOPR, the Commission proposed to require each
transmission provider to submit a compliance filing within 60 days of
the effective date of any final rule. The Commission clarified that
this compliance deadline would be for transmission providers to submit
proposed AAR tariff changes, RTOs/ISOs to submit proposed tariff
changes designed to maintain systems and procedures needed to allow for
the use of AARs and DLRs, transmission owners to submit tariff changes
implementing the proposed transparency reforms, or for each entity to
otherwise comply with any final rule. As justification, the Commission
acknowledged that implementing the reforms required by any final rule
in this proceeding may be complex, but preliminarily found that
implementation of these reforms is important to ensure wholesale rates
are just and reasonable.
349. Recognizing the complexity of the proposed AAR requirements,
the Commission proposed a staggered implementation approach that would
prioritize implementation on historically congested transmission lines
(within one year from the date of the compliance filing), but further
proposed a less aggressive implementation of AARs on all other
transmission lines (within two years from the date of the compliance
filing). For the proposed DLR requirements and proposed transparency
requirements, the Commission proposed that tariff changes filed in
response to a final rule in this proceeding would become effective
within one year from the date of the compliance filing.
350. The Commission recognized that some transmission providers may
have provisions in their existing OATTs or other document(s) subject to
the Commission's jurisdiction that the Commission has deemed to be
consistent with or superior to the pro forma OATT or that are
permissible under the independent entity variation standard or regional
reliability standard. Where these provisions would be modified, the
Commission proposed to require transmission providers to either comply
with the proposed requirements or demonstrate that these previously
approved variations continue to be consistent with or superior to the
pro forma OATT as modified by the proposed requirements or demonstrate
that these previously approved variations are just and reasonable and
meet the purpose of the final rule under the independent entity
variation standard or regional reliability standard.\829\
---------------------------------------------------------------------------
\829\ NOPR, 173 FERC ] 61,165 at P 132.
---------------------------------------------------------------------------
2. Comments
351. Comments on the proposed compliance and implementation
timelines came predominately from RTOs/ISOs and transmission owners
requesting more time. Most commenters suggest a minimum 120-day
compliance deadline,\830\ but some suggest a minimum 180-day compliance
deadline,\831\ and others suggest a minimum 90-day compliance
deadline.\832\ Most transmission owners commenting argue that three
years is needed to implement AARs on priority transmission lines; \833\
however,
[[Page 2299]]
PacifiCorp suggests that two years would be sufficient, while PG&E
suggests that at least four years would be needed.\834\ NYTOs, WAPA,
and BPA also contend that the proposed implementation timeline is
insufficient but do not proposed an alternative schedule.\835\ Some
commenters support the proposed timeline.\836\ Industrial Customer
Organizations recommend that the proposed implementation timeline be
halved.\837\
---------------------------------------------------------------------------
\830\ EEI Comments at 19; NRECA/LPPC Comments at 28-29; MISO
Transmission Owners Comments at 38-39; SCE Comments at 2; SDG&E
Comments at 1-2; APS Comments at 10; WFEC Comments at 1; Southern
Company Comments at 6-7; MISO Comments at 31; ISO-NE Comments at 12.
\831\ CAISO Comments at 2; NYISO Comments at 18.
\832\ SPP Comments at 16; PacifiCorp Comments at 7.
\833\ EEI Comments at 18; NRECA/LPPC Comments at 28-29; MISO
Transmission Owners Comments at 22-23; SCE Comments at 2; SDG&E
Comments at 1-2; APS Comments at 10; WFEC Comments at 1; Southern
Company Comments at 6-7; ITC Comments at 5; LADWP Comments at 8-9.
\834\ PacifiCorp Comments at 2-3; PG&E Comments at 6-8.
\835\ NYTOs Comments at 1; WAPA Comments at 6; BPA Comments at
6.
\836\ OMS Comments at 9; Potomac Economics Comments at 19-20.
\837\ Industrial Customer Organizations Comments at 22.
---------------------------------------------------------------------------
352. Arguing that one year is insufficient to implement AARs on
historically congested transmission lines, MISO Transmission Owners
explain that their experience is that, on average, it takes several
years to implement AARs on even a subset of transmission lines.\838\
According to MISO Transmission Owners, at least three years is needed
for AAR implementation because of all the steps needed to implement
AARs, including developing and updating the transmission line rating
methodologies, analyzing historical weather information, identifying
limiting elements, developing a transmission line ratings database,
updating the transmission management system, testing the transmission
line ratings, and linking the transmission owners' transmission
management system to the RTO/ISO EMS, all while maintaining
cybersecurity standards.\839\ EEI similarly states that it could take
up to two years just to upgrade operating and data systems to create
the capability to produce and update AAR calculations.\840\ Southern
Company and SCE support EEI's comments.\841\ Specifically, Southern
Company requests at least 120 days for compliance filings and at least
three years for AAR implementation.\842\ SCE claims that the
Commission's proposed implementation schedule is not realistic.\843\
---------------------------------------------------------------------------
\838\ MISO Transmission Owners Comments at 22.
\839\ Id.
\840\ EEI Comments at 18.
\841\ Southern Company Comments at 3-4; SCE Comments at 2.
\842\ Southern Company Comments at 3-4.
\843\ SCE Comments at 2.
---------------------------------------------------------------------------
353. PacifiCorp states that implementation of the NOPR proposal
would be complicated as it would require updates to PacifiCorp's EMS,
SCADA, and other software that communicates transmission line ratings
with CAISO, RC West, and other transmission providers.\844\ APS argues
that adequate time is needed to develop the business requirements for
the software vendors and that APS will have to work with multiple
software vendors to comply with the TLR provisions as currently
delineated in the NOPR.\845\ NRECA states that its members need a
minimum of three years to implement AARs on all their transmission
lines in order to identify, document, and implement the necessary
system and process changes.\846\ Presenting a five year implementation
approach, PG&E states that AAR implementation will require significant
initial investments and that the Commission should allow for sufficient
time for RTOs/ISOs and transmission owners to collaborate to develop
new communication systems and new processes for determining and
operating with AARs.\847\
---------------------------------------------------------------------------
\844\ PacifiCorp Comments at 3-4.
\845\ APS Comments at 6.
\846\ NRECA/LPPC Comments at 28-29.
\847\ PG&E Comments at 6-7.
---------------------------------------------------------------------------
354. ITC states that the proposed requirements in the NOPR would be
complicated to implement for transmission owners that currently do not
use AARs, and the implementation timeline would exceed one year since
it would require coordination with the transmission management system,
development of internal transmission line ratings software or a
software purchase from a vendor, and analysis of how AARs will affect
ITC's internal transmission line ratings database.\848\ The proposed
one-year implementation timelines suggest that ITC would need to first
develop a costly and error-prone manual process as a short-term
solution before developing a more permanent automated process.\849\ ITC
states that additional time should be built into the Commission's
proposed timeline so that initial implementation issues can be
identified and corrected.\850\ Similarly, NYTOs argue that the one-year
compliance timeline for AARs is overly ambitious and could have adverse
effects, be costly, and potentially impossible.\851\
---------------------------------------------------------------------------
\848\ ITC Comments at 6.
\849\ Id. at 6-7.
\850\ Id. at 7.
\851\ NYTOs Comments at 1.
---------------------------------------------------------------------------
355. Other transmission owners voicing concern with the proposed
schedule include WAPA, LADWP, and BPA. WAPA notes that it is concerned
about the proposed timeline, given its expansive geographic area and
transmission system of over 17,000 line miles, and its other statutory
duties it must meet to operate its system reliably.\852\ LADWP
recommends an implementation period of no less than three years for
congested transmission lines, noting that the proposed AAR requirements
will necessitate extensive re-negotiations of long-term reservation
rights and arguing that the AAR implementation timeline is not
sufficient to address challenges associated with calculating hourly ATC
based on AARs, including development of additional reliability tools
and ongoing maintenance of these tools by additional skilled
employees.\853\ Similarly, BPA asserts that the proposed implementation
period is too short because it fails to account for the different
transmission provider service territory sizes and for the complexity of
AAR implementation.\854\
---------------------------------------------------------------------------
\852\ WAPA Comments at 6.
\853\ LADWP Comments at 8-9.
\854\ BPA Comments at 6.
---------------------------------------------------------------------------
356. However, according to OMS, the deadlines seem to be reasonable
and necessary. OMS states that: MISO Transmission Owners are already
working on implementing AARs; since 2016, MISO has had an Integrated
Roadmap item called ``Application of Forecasted and Real-time Ambient
Adjusted Ratings'' ranked as a high priority in MISO's 2021 Integrated
Roadmap Work Plan; and, because MISO Transmission Owners have begun
developing a framework to identify candidate AAR facilities based on
historical congestion, they should have already begun phase one
compliance.\855\ Industrial Customer Organizations similarly state that
transmission owners should begin AAR implementation now and that,
without strict deadlines, AAR implementation before 2022 is
unlikely.\856\
---------------------------------------------------------------------------
\855\ OMS Comments at 9.
\856\ Industrial Customer Organizations Comments at 22.
---------------------------------------------------------------------------
357. RTOs/ISOs generally request additional implementation
time.\857\ CAISO claims that the compliance schedule set forth in the
NOPR is neither realistic nor achievable because the proposal for
hourly updates to transmission line ratings will require additional
market design changes and significant technology enhancements. For the
implementation schedule, CAISO requests an additional 18 months from
the submission of a compliance filing, explaining that implementation
will require technology
[[Page 2300]]
enhancements necessary to automate the submission and use of hourly
adjusted transmission line ratings.\858\ SPP contends that 60 days
would be insufficient time for SPP to complete its stakeholder process
to review any proposed tariff language and notes that, depending on the
changes, the process would take at least three months. For
implementation, SPP requests an additional two years from the
submission of a compliance filing.\859\ ISO-NE explains that it will
need to upgrade its systems to accept hourly transmission line ratings,
and that it does not believe one year would be enough time to do so,
but does not propose a timeline.\860\ Additionally, ISO-NE asks for
sufficient time to analyze how AARs would impact the emergency ratings
currently employed and flexibility in implementation timing, and states
that an update to the overall rating methodology to include AARs may
also necessitate the need for new emergency ratings based on those
AARs.\861\ MISO states that it would be able to implement the NOPR
proposal in the real-time market in a year, but states that it would
need until mid-2023 and the end of 2024 to implement the NOPR proposal
in the day-ahead market and Intra-day and Foreword Reliability
Assessment Commitment respectively.\862\ NYISO requests flexibility for
each RTO/ISO to develop its own implementation schedule,\863\ arguing
that the AAR schedule proposed is not enough time to develop the
significant changes to software and rules needed,\864\ and stating that
it could incur significant risk and expense if it is required to comply
within the proposed one to two years.\865\ PJM, however, states that,
while the NOPR proposal will likely require some additional system
changes and data validation to comply, it believes the time proposed
would be sufficient.\866\
---------------------------------------------------------------------------
\857\ CAISO Comments at 2; ISO-NE Comments at 8; SPP Comments at
10; MISO Comments at 30-32; NYISO Comments at 16-18.
\858\ CAISO Comments at 2.
\859\ SPP Comments at 10.
\860\ ISO-NE Comments at 8.
\861\ Id. at 11.
\862\ MISO Comments at 30-32.
\863\ NYISO Comments at 16.
\864\ Id. at 18.
\865\ Id. at 19.
\866\ PJM Comments at 8.
---------------------------------------------------------------------------
358. Potomac Economics states that clarification may be needed as
to whether the requirements for automation are on the transmission line
rating submission process and use of AARs or the entire transmission
line rating process. Potomac Economics states that requiring full
automation may delay implementation and may not be appropriate for all
transmission owners.\867\
---------------------------------------------------------------------------
\867\ Potomac Economics Comments at 19.
---------------------------------------------------------------------------
359. Finally, PJM requests clarity that public utilities are able
to demonstrate compliance via the independent entity variation
standard, regional reliability standard, or demonstrate that their
existing rules are consistent with or superior to the reforms adopted
by the Commission.\868\
---------------------------------------------------------------------------
\868\ PJM Comments at 15.
---------------------------------------------------------------------------
3. Commission Determination
360. Upon consideration of the comments received, we modify the
compliance deadline proposed in the NOPR. Instead of 60 days, we
require each transmission provider to submit a compliance filing within
120 days of the effective date of this final rule. We clarify that this
compliance deadline is for transmission providers to revise their OATTs
to incorporate pro forma OATT Attachment M. We agree with EEI's
compliance recommendation \869\ and find that 120 days will be
sufficient to allow for a robust stakeholder evaluation and development
of revised tariff language to comply with the requirements adopted in
this final rule.
---------------------------------------------------------------------------
\869\ EEI Comments at 19.
---------------------------------------------------------------------------
361. In addition, we modify the proposed implementation schedule.
Instead of the proposed one-year/two-year staggered implementation
timeline based on priority, we require that all requirements adopted
herein be implemented no later than three years from the compliance
filing due date. Three years is consistent with the implementation
schedule most commonly suggested by transmission owners for AAR
implementation on priority transmission lines.\870\ We find that three
years should be sufficient time for transmission owners and
transmission providers to implement changes to their processes and
systems to comply with the requirements adopted in this final rule.
---------------------------------------------------------------------------
\870\ Id. at 18; NRECA/LPPC Comments at 28-29; MISO Transmission
Owners Comments at 22-23; SCE Comments at 2; SDG&E Comments at 1-2;
APS Comments at 10; WFEC Comments at 1; Southern Company Comments at
6-7; ITC Comments at 5; LADWP Comments at 8-9.
---------------------------------------------------------------------------
362. In response to comments about automation from Potomac
Economics, we clarify that while we are not adopting a specific
automation requirement, we nonetheless believe it is likely that all or
much of AAR calculation processes will be automated. However, nothing
in this final rule prevents an individual transmission provider from
implementing certain portions of the pro forma OATT Attachment M
requirements manually, should it prefer manual implementation and can
satisfy the requirements of this final rule.
363. Finally, some public utility transmission providers may have
provisions in their existing pro forma OATTs or other document(s)
subject to the Commission's jurisdiction that the Commission has deemed
to be consistent with or superior to the pro forma OATT. Where these
provisions would be modified by this final rule, transmission providers
must either comply with the requirements adopted in this final rule or
demonstrate that these previously approved variations continue to be
consistent with or superior to the pro forma OATT, as modified by this
final rule.\871\
---------------------------------------------------------------------------
\871\ See 18 CFR 35.28(c)(1)(vi).
---------------------------------------------------------------------------
V. Information Collection Statement
364. The information collection (IC) requirements contained in this
final rule are subject to review by the Office of Management and Budget
(OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\872\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\873\ Respondents
subject to the filing requirements of this final rule will not be
penalized for failing to respond to these collections of information
unless the collections of information display a valid OMB control
number.
---------------------------------------------------------------------------
\872\ 44 U.S.C. 3507(d).
\873\ 5 CFR 1320.11 (2021).
---------------------------------------------------------------------------
365. This final rule, pursuant to section 206 of the FPA, reforms
the pro forma OATT and the Commission's regulations to improve the
accuracy and transparency of electric transmission line ratings used by
transmission providers. These provisions affect the following
collections of information: FERC-516H, Pro Forma Open Access
Transmission Tariff (Control No. 1902-0297); and FERC-725A, Mandatory
Reliability Standards for the Bulk-Power System (Control No. 1902-
0244).
366. In the NOPR, the Commission solicited comments on the
Commission's need for this information, whether the information will
have practical utility, the accuracy of the burden estimates, ways to
enhance the quality, utility, and clarity of the information to be
collected or retained, and any suggested methods for minimizing
respondents' burden, including the use of automated information
techniques.
367. Summary of the Collection of Information in the Final Rule:
FERC 516H: This final rule amends 18 CFR 35.28(c)(5) to require any
public
[[Page 2301]]
utility that owns transmission facilities that are not under the public
utility's control to, consistent with the pro forma OATT required by 18
CFR 35.28(c)(1), share with the public utility that controls such
facilities (and its Market Monitoring Unit(s), if applicable):
(i) Transmission line ratings for each period for which
transmission line ratings are calculated for such facilities (with
updated ratings shared each time ratings are calculated); and
(ii) Written transmission line rating methodologies used to
calculate the transmission line ratings for such facilities provided
under subparagraph (i), above.
Section 35.28(g)(13) of this final rule requires each RTO and ISO
to establish and maintain systems and procedures necessary to allow any
public utility whose transmission facilities are under the independent
control of the ISO or RTO to electronically update transmission line
ratings for such facilities (for each period for which transmission
line ratings are calculated) at least hourly, with such data submitted
by those public utility transmission owners directly into the ISO's or
RTO's Energy Management System through Supervisory Control and Data
Acquisition or related systems.
FERC-725A: Reliability Standard FAC-008-5 is not being revised in
this proceeding. However, as shown in the burden table below, the
requirements of this final rule under section 206 of the FPA affect the
burden for Requirements 2, 3, and 6 in Reliability Standard FAC-008-5.
368. Title: Pro Forma Open Access Transmission Tariff (FERC-516H)
and Mandatory Reliability Standards for the Bulk-Power System (FERC-
725A).
369. Action: Revision of collections of information in accordance
with Docket No. RM20-16-000.
370. OMB Control Nos.: 1902-0297 (FERC-516H) and 1902-0244 (FERC-
725A).
371. Respondents: Transmission owners, transmission service
providers, generator owners, and RTOs/ISOs.
372. Frequency of Information Collection: One time and annually.
373. Necessity of Information: The reforms to the pro forma OATT
and the Commission's regulations will improve the accuracy and
transparency of electric transmission line ratings used by transmission
providers.
374. Internal Review: The Commission has reviewed the changes and
has determined that such changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has specific, objective support for the burden estimates
associated with the information collection requirements.
375. Our estimates are based on the NERC Compliance Registry as of
September 3, 2020, which indicates that 78 transmission service
providers,\874\ 797 generator owners,\875\ and 289 transmission owners
are registered within the United States and are subject to this
rulemaking.\876\ There are also six RTOs/ISOs in the United States
subject to this rulemaking.
---------------------------------------------------------------------------
\874\ The transmission service provider (TSP) function is a NERC
registration function which is similar to the transmission provider
that is referenced in the pro forma OATT. The TSP function is being
used as a proxy to estimate the number of transmission providers
that are impacted by this rulemaking.
\875\ Of the 797 generator owners listed in the September 3,
2020 NERC Compliance Registry, the Commission estimates that only
10% of all NERC registered generator owners own facilities between
the step-up transformer and the point of interconnection. For this
reason, the Commission estimates that only 80 generator owners are
affected.
\876\ The number of entities listed from the NERC Compliance
Registry reflects the omission of the Texas RE registered entities.
---------------------------------------------------------------------------
376. Public Reporting Burden: The burden and cost estimates below
are based on the need for applicable entities to revise documentation,
already required by the pro forma OATT and the Commission's regulations
as well as Reliability Standard FAC-008-5, Facility Ratings.\877\
---------------------------------------------------------------------------
\877\ The burden associated with Reliability Standard FAC-008-5,
approved by the Commission under section 215 of the FPA, is included
in the OMB-approved inventory for FERC-725A. Reliability Standard
FAC-008-5 is not being revised in this proceeding; however, the
requirements of this final rule under section 206 of the FPA affect
the burden for three requirements in Reliability Standard FAC-008-5.
---------------------------------------------------------------------------
377. The Commission estimates that the final rule will affect the
burden \878\ and cost of FERC-516H and FERC-725A as follows:
---------------------------------------------------------------------------
\878\ ``Burden'' is the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. For
further explanation of what is included in the information
collection burden, refer to 5 CFR 1320.3.
Changes in Final Rule in Docket No. RM20-16-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
A. B. C. D. E. F.
Area of modification Number of Annual Annual estimated Average burden hours & cost Total estimated burden hours &
respondents. estimated number of responses \879\ per response. total
number of (column B x column C) estimated cost
responses per (column D x column E)
respondent
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC-516H, Pro Forma Open Access Transmission Tariff (Control No. 1902-0297)
--------------------------------------------------------------------------------------------------------------------------------------------------------
For point-to-point transmission 129 (TOs \880\ not 1 129 1,440 hrs; $120,485......... 185,760 hrs; $15,542,539.
service requests within ten in RTOs/ISOs
days, use AARs in determining \881\).
ATC and TTC. (One-Time Burden
in Year 1).
Where network transmission 160 (to account 1 160 1,440 hrs; $120,485......... 230,400 hrs; $19,277,568.
service is provided, use for those TOs in
hourly AARs to determine RTOs/ISOs that
curtailment or redispatch of are not included
network transmission service. in the line
(One-Time Burden in Year 1). above).
Transmission Providers to 160 (to account 1 160 360 hrs; $30,121............ 57,600 hrs; $4,819,392.
implement uniquely determined for those TOs in
emergency ratings (One-Time RTOs/ISOs that
Burden in Year 1). are not included
in the line
above).
Implement software and systems 78 (TSPs \882\)... 1 78 352 hrs; $29,452............ 27,456 hrs; $2,297,243.
to communicate the required
transmission line ratings with
relevant parties. (One-Time
Burden in Year 1).
[[Page 2302]]
RTOs/ISOs implement software 6 (RTOs/ISOs)..... 1 6 9,000 hrs; $753,030......... 54,000 hrs; $4,518,180.
with the ability to
accommodate AARs in both the
day-ahead and real-time
markets on an hourly basis.
(One-Time Burden in Year 1).
RTOs/ISOs establish the systems 6 (RTOs/ISOs)..... 1 6 1,056 hrs; $88,356.......... 6,336 hrs; $530,133.
and procedures necessary to
allow transmission owners to
update line ratings on an
hourly basis directly into an
EMS. (One-Time Burden in Year
1).
Transmission owners update 289 (TOs)......... 1 289 176 hrs; $14,726............ 50,864 hrs; $4,255,791.
forecasts and ratings, and
share transmission line
ratings and facility ratings
methodologies w/transmission
providers and, if applicable,
RTOs/ISOs & market monitors
(Year 1 and Ongoing).
Compliance Filings (One-Time 295 (TOs and (RTOs/ 1 295 160 hrs; $13,387............ 47,200 hrs; $3,949,224.
Burden in Year 1). ISOs).
----------------------------------------------------------------------------------------------------
Net Subtotal for FERC-516H .................. .............. 373 13,984 hrs; $1,170,041...... 429,216 hrs; $50,671,891.
(Year 1).
----------------------------------------------------------------------------------------------------
Net Subtotal for FERC-516H .................. .............. 289 176 hrs; $14,726............ 50,864 hrs; $4,255,791.
(Ongoing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC-725A, Mandatory Reliability Standards for the Bulk-Power System--Reliability Standard FAC-008-5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Review and update facility 369 (TOs & GOs) 1 369 40 hrs; $3,347.............. 14,760 hrs; $1,234,969.
ratings methodology, \883\.
Requirements R2 and R3. (One-
Time Burden in Year 1).
Determine facility ratings 369 (TOs & GOs)... 1 369 8 hrs; $669................. 2,952 hrs; $246,994.
consistent with methodology,
Requirement R6. (Burden in
Year 1 and Ongoing).
----------------------------------------------------------------------------------------------------
Net Subtotal for FERC-725A .................. .............. 369 48 hrs; $4,016.............. 17,712 hrs; $1,481,963.
(Year 1).
----------------------------------------------------------------------------------------------------
Net Subtotal for FERC-725A .................. .............. 369 8 hrs; $669................. 2,952 hrs; $246,994.
(Ongoing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
378. The Commission noted in the NOPR that, for purposes of
estimating burden in the NOPR, the Commission conservatively estimated
these values based on the maximum number of entities and burden. The
Commission noted that some entities may, for example, already use AARs
in their existing operations, in which case the actual burden
associated with specific reforms associated with the use of AARs would
be lower than the estimate. The Commission added that, on the other
hand, changing approaches to facility ratings may require extra testing
and training for some entities to ensure reliable operations and gain
familiarity with the approach. In the NOPR, the Commission explained
that it estimated that the majority of the additional burden associated
with the NOPR would occur in the first year, and that, once
established, the ongoing burden would closely approach the existing
burden of operating the transmission system. The Commission sought
comment on the estimates in the table provided in the NOPR and the
assumptions described in the NOPR.
---------------------------------------------------------------------------
\879\ The hourly cost (for salary plus benefits) uses the
figures from the Bureau of Labor Statistics (BLS) for three
positions involved in the reporting and recordkeeping requirements.
These figures include salary (based on BLS data for May 2019, https://bls.gov/oes/current/naics2_22.htm) and benefits (based on BLS data
for December 2019; issued March 19, 2020, https://www.bls.gov/news.release/ecec.nr0.htm) and are Manager (Code 11-0000 $97.15/
hour), Electrical Engineer (Code 17-2071 $70.19/hour), and File
Clerk (Code 43-4071 $34.79/hour). The hourly cost for the reporting
requirements ($83.67) is an average of the cost of a manager and
engineer. The hourly cost for recordkeeping requirements uses the
cost of a file clerk.
\880\ Transmission Owners. While the AAR reforms in the final
rule apply to transmission providers, the Commission computes an
implementation burden based on the number of transmission owners
because transmission owners typically calculate transmission line
ratings and are therefore likely to be the entities that update
computations to determine the effect of changing ambient air
temperatures on transmission line ratings.
\881\ Regional Transmission Organizations/Independent System
Operators.
\882\ Transmission Service Providers.
\883\ This number reflects 289 transmission owners and 10% of
the 797 generator owners (GOs) estimated to own facilities between
the step-up transformer and the point of interconnection.
---------------------------------------------------------------------------
379. We have revised the table above to reflect the additional
burden associated with the additional requirements issued in this final
rule related to emergency ratings and daytime and nighttime ratings.
380. We have also revised the table based on comments provided by
MISO. MISO states that it estimates costs of approximately $200,000 to
implement AARs for current hour transmission service, and costs to
implement forecasted AARs in the forward markets and for transmission
service, such as in
[[Page 2303]]
the day-ahead market, between $500,000 and $750,000.\884\ The
Commission has conservatively applied this estimate to all of the RTOs/
ISOs. The Commission notes, however, that this is a conservative
maximum estimate and that some RTOs/ISOs might have pre-existing plans
to upgrade software in the coming years, which may implement many of
the same functionalities necessitated by this final rule that are
captured in these RTO/ISO cost estimates.
---------------------------------------------------------------------------
\884\ MISO Comments at 32.
---------------------------------------------------------------------------
381. In this final rule, besides the noted revisions, the
Commission used the numbers provided in the NOPR.
382. Interested persons may obtain information on the reporting
requirements by contacting Ellen Brown, Office of the Executive
Director, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 via email ([email protected]) or telephone
((202) 502-8663).
VI. Environmental Analysis
383. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\885\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this final rule under section
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts, and regulations that affect rates, charges, classification,
and services.\886\
---------------------------------------------------------------------------
\885\ Reguls. Implementing the Nat'l Envt'l Pol'y Act, Order No.
486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles
1986-1990 ] 30,783 (1987) (cross-referenced at 41 FERC ] 61,284).
\886\ 18 CFR 380.4(a)(15) (2021).
---------------------------------------------------------------------------
VII. Regulatory Flexibility Act
384. The Regulatory Flexibility Act of 1980 \887\ generally
requires a description and analysis of proposed and final rules that
will have significant economic impact on a substantial number of small
entities. The Small Business Administration (SBA) sets the threshold
for what constitutes a small business. The small business size
standards are provided in 13 CFR 121.201 (2021). Under SBA's size
standards,\888\ RTOs/ISOs, planning regions, and transmission owners
all fall under the category of Electric Bulk Power Transmission and
Control (NAICS code 221121), with a size threshold of 500 employees
(including the entity and its associates).\889\
---------------------------------------------------------------------------
\887\ 5 U.S.C. 601-612.
\888\ 13 CFR 121.201.
\889\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3) (citing to Section 3 of the Small Business Act, 15 U.S.C.
632).
---------------------------------------------------------------------------
385. The six RTOs/ISOs (SPP, MISO, PJM, ISO-NE, NYISO, and CAISO)
each employ more than 500 employees and are not considered small.
386. We estimate that 337 transmission owners and six planning
authorities are also affected by this final rule. Using the list of
transmission owners from the NERC Registry (dated September 3, 2020),
we estimate that approximately 68% of those entities are small
entities.
387. We estimate that 80 generator owners own facilities between
the step-up transformer and the point of interconnection. We estimate
again that 68% of these are small entities.
388. We estimate that 78 transmission service providers are
affected by this final rule. We estimate again that 68% of these are
small entities.
389. We estimate additional one-time costs associated with this
final rule (as shown in the table above) of:
390. $854,773 for each RTO/ISO (FERC-516H).
391. $178,719 for each transmission owner (FERC-516H).
392. $3,347 for each transmission owner (FERC-725A).
393. $13,387 for each affected generator owner (FERC-516H).
394. $3,347 for each generator owner (FERC-725A).
395. $29,452 for each transmission service provider (FERC-516H).
396. Therefore, the estimated additional one-time cost per entity
ranges from $16,734 to $854,773.
397. We estimate that the majority of the additional burden
associated with this final rule occurs in the first year (as shown in
the table above), and that, once established, the ongoing burden will
closely approach the existing burden of operating the transmission
system.
398. According to SBA guidance, the determination of significance
of impact ``should be seen as relative to the size of the business, the
size of the competitor's business, and the impact the regulation has on
larger competitors.'' \890\ We do not consider the estimated cost to be
a significant economic impact. As a result, we certify that this final
rule will not have a significant economic impact on a substantial
number of small entities.
---------------------------------------------------------------------------
\890\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------
VIII. Document Availability
399. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (https://www.ferc.gov). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
400. From FERC's Home Page on the internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
401. User assistance is available for eLibrary and the FERC's
website during normal business hours from FERC Online Support at (202)
502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
IX. Effective Date and Congressional Notification
402. This final rule is effective 60 days from the later of the
date Congress receives the agency notice or the date the rule is
published in the Federal Register. The Commission has determined, with
the concurrence of the Administrator of the Office of Information and
Regulatory Affairs of OMB, that this rule is a ``major rule'' as
defined in section 351 of the Small Business Regulatory Enforcement
Fairness Act of 1996.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
[[Page 2304]]
By the Commission. Commissioner Danly is concurring with a
separate statement attached.
Commissioner Phillips is not participating.
Issued: December 16, 2021.
Debbie-Anne A. Reese,
Deputy Secretary.
In consideration of the foregoing, the Commission amends part 35,
chapter I, Title 18, Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
0
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
0
2. Amend Sec. 35.28 by adding paragraphs (b)(12) through (16), (c)(5),
and (g)(13) to read as follows:
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(b) * * *
(12) Ambient-adjusted rating means a transmission line rating that
applies to a time period of not greater than one hour; reflects an up-
to-date forecast of ambient air temperature across the time period to
which the rating applies; reflects the absence of solar heating during
nighttime periods where the local sunrise/sunset times used to
determine daytime and nighttime periods are updated at least monthly,
if not more frequently; and is calculated at least each hour, if not
more frequently.
(13) Emergency rating means a transmission line rating that
reflects operation for a specified, finite period, rather than
reflecting continuous operation. An emergency rating may assume an
acceptable loss of equipment life or other physical or safety
limitations for the equipment involved.
(14) Dynamic line rating means a transmission line rating that
applies to a time period of not greater than one hour and reflects up-
to-date forecasts of inputs such as (but not limited to) ambient air
temperature, wind, solar heating intensity, transmission line tension,
or transmission line sag.
(15) Energy Management System (EMS) means a computer control system
used by electric utility dispatchers to monitor the real-time
performance of the various elements of an electric system and to
dispatch, schedule, and/or control generation and transmission
facilities.
(16) Supervisory Control and Data Acquisition (SCADA) means a
computer system that allows an electric system operator to remotely
monitor and control elements of an electric system.
(c) * * *
(5) Any public utility that owns transmission facilities that are
not under the public utility's control must, consistent with the pro
forma tariff required by paragraph (c)(1) of this section, share with
the public utility that controls such facilities (and its Market
Monitoring Unit(s), if applicable):
(i) Transmission line ratings for each period for which
transmission line ratings are calculated for such facilities (with
updated ratings shared each time ratings are calculated); and
(ii) Written transmission line rating methodologies used to
calculate the transmission line ratings for such facilities provided
under subparagraph (i).
* * * * *
(g) * * *
(13) Transmission line ratings. (i) Each Commission-approved
independent system operator or regional transmission organization must
establish and maintain systems and procedures necessary to allow any
public utility whose transmission facilities are under the independent
control of the independent system operator or regional transmission
organization to electronically update transmission line ratings for
such facilities (for each period for which transmission line ratings
are calculated) at least hourly, with such data submitted by those
public utility transmission owners directly into the independent system
operator's or regional transmission organization's EMS through SCADA or
related systems.
(ii) [Reserved]
Note: The following appendix will not be published in the Code
of Federal Regulations.
Appendix A: Abbreviated Names of Commenters
The following table contains the abbreviated names of the
commenters that are used in this final rule.
------------------------------------------------------------------------
Short name/acronym Commenter
------------------------------------------------------------------------
AEP.......................... American Electric Power Company, Inc.
ACORE........................ The American Council on Renewable Energy.
ACPA/SEIA.................... American Clean Power Association (ACPA)
and the Solar Energy Industries
Association (SEIA).
APS.......................... Arizona Public Service Company.
BPA.......................... Bonneville Power Administration.
CAISO........................ California Independent System Operator
Corporation.
CAISO DMM.................... California Independent System Operator
Corporation Department of Market
Monitoring.
CEA.......................... Canadian Electricity Association.
Certain TDU.................. Certain Transmission Dependent Utilities
consist of Alliant Energy Corporate
Services, Inc. (Alliant Energy);
Consumers Energy Company (Consumers
Energy); and DTE Electric Company (DTE
Electric).
Clean Energy Parties......... Clean Energy Parties consist of the
Natural Resources Defense Council,
Sustainable FERC Project, Conservation
Law Foundation, Sierra Club, Western
Resource Advocates, Western Grid Group,
Clean Grid Alliance, NW Energy
Coalition, and Southern Environmental
Law Center.
DC Energy.................... DC Energy, LLC.
Dominion..................... Dominion Energy Services, Inc.
Duke Energy.................. Duke Energy Corporation.
EDFR......................... EDF Renewables, Inc.
EEI.......................... Edison Electric Institute.
ENEL......................... ENEL North America.
Entergy...................... Entergy Services, LLC.
EPRI......................... Electric Power Research Institute.
EPSA......................... Electric Power Supply Association.
Eversource................... Eversource Energy Service Company.
Exelon....................... Exelon Corporation.
IID.......................... Imperial Irrigation District.
[[Page 2305]]
Indicated PJM Transmission Indicated PJM Transmission Owners consist
Owners. of: American Electric Power Service
Corporation on behalf of its affiliates,
Appalachian Power Company, Indiana
Michigan Power Company, Kentucky Power
Company, Kingsport Power Company, Ohio
Power Company, Wheeling Power Company,
AEP Appalachian Transmission Company,
Inc., AEP Indiana Michigan Transmission
Company, Inc., AEP Kentucky Transmission
Company, Inc., AEP Ohio Transmission
Company, Inc., and AEP West Virginia
Transmission Company, Inc. (collectively
``AEP''); Dominion Energy Services, Inc.
on behalf of Virginia Electric and Power
Company d/b/a Dominion Energy Virginia;
Duke Energy Corporation on behalf of its
affiliates Duke Energy Ohio, Inc., Duke
Energy Kentucky, Inc., and Duke Energy
Business Services LLC; Exelon
Corporation; FirstEnergy Service
Company, on behalf of its affiliates
American Transmission Systems,
Incorporated, Jersey Central Power &
Light Company, MidAtlantic Interstate
Transmission LLC, West Penn Power
Company, The Potomac Edison Company,
Monongahela Power Company, and Trans-
Allegheny Interstate Line Company; PPL
Electric Utilities Corporation; and
Rockland Electric Company.
Industrial Customer Industrial Customer Organizations
Organizations. consists of: American Forest & Paper
Association (AF&PA), Coalition of MISO
Transmission Customers (CMTC),
Electricity Consumers Resource Council
(ELCON), Industrial Energy Consumers of
America (IECA), and the PJM Industrial
Customer Coalition (PJMICC).
ISO-NE....................... ISO New England Inc.
ITC.......................... International Transmission Company d/b/a
ITC Transmission, Michigan Electric
Transmission Company, LLC, ITC Midwest
LLC, and ITC Great Plains, LLC.
LADWP........................ Los Angeles Department of Water and
Power.
LineVision................... LineVision, Inc.
MISO......................... Midcontinent Independent System Operator,
Inc.
MISO Transmission Owners..... MISO Transmission Owners consist of:
Ameren Services Company, as agent for
Union Electric Company d/b/a Ameren
Missouri, Ameren Illinois Company d/b/a
Ameren Illinois, and Ameren Transmission
Company of Illinois; American
Transmission Company LLC; Big Rivers
Electric Corporation; Central Minnesota
Municipal Power Agency; City Water,
Light & Power (Springfield, IL); Cleco
Power LLC; Cooperative Energy; Dairyland
Power Cooperative; Duke Energy Business
Services, LLC for Duke Energy Indiana,
LLC; East Texas Electric Cooperative;
Great River Energy; Hoosier Energy Rural
Electric Cooperative, Inc.; Indiana
Municipal Power Agency; Indianapolis
Power & Light Company; International
Transmission Company d/b/a ITC
Transmission; ITC Midwest LLC; Lafayette
Utilities System; Michigan Electric
Transmission Company, LLC; MidAmerican
Energy Company; Minnesota Power (and its
subsidiary Superior Water, L&P);
Missouri River Energy Services; Montana-
Dakota Utilities Co.; Northern Indiana
Public Service Company LLC; Northern
States Power Company, a Minnesota
corporation, and Northern States Power
Company, a Wisconsin corporation,
subsidiaries of Xcel Energy Inc.;
Northwestern Wisconsin Electric Company;
Otter Tail Power Company; Prairie Power
Inc.; Southern Illinois Power
Cooperative; Southern Indiana Gas &
Electric Company (d/b/a Vectren Energy
Delivery of Indiana); Southern Minnesota
Municipal Power Agency; Wabash Valley
Power Association, Inc.; and Wolverine
Power Supply Cooperative, Inc.
NERC......................... North American Electric Reliability
Corporation.
New England State Agencies... New England State Agencies consist of:
Connecticut Attorney General William
Tong; Massachusetts Attorney General
Maura Healey; the Connecticut Department
of Energy and Environmental Protection;
the Connecticut Office of Consumer
Counsel; the Maine Office of the Public
Advocate; the New Hampshire Consumer
Advocate; Peter F. Neronha, Rhode Island
Attorney General; and Thomas J. Donovan,
Jr., Attorney General of Vermont.
NRECA/LPPC................... National Rural Electric Cooperative
Association (NRECA) and the Large Public
Power Council (LPPC).
NYISO........................ New York Independent System Operator,
Inc.
NYTOs........................ The New York Transmission Owners consist
of: Central Hudson Gas & Electric
Corporation (Central Hudson);
Consolidated Edison Company of New York,
Inc. (Consolidated Edison); Niagara
Mohawk Power Corporation d/b/a National
Grid (National Grid); New York Power
Authority (NYPA); New York State
Electric & Gas Corporation (NYSEG);
Orange and Rockland Utilities, Inc.
(O&R); Long Island Power Authority
(LIPA); and Rochester Gas and Electric
Corporation (RG&E).
Ohio FEA..................... Public Utilities Commission of Ohio's
Office of the Ohio Federal Energy
Advocate.
OMS.......................... Organization of MISO States.
PacifiCorp................... PacifiCorp.
PG&E......................... Pacific Gas and Electric Company.
PJM.......................... PJM Interconnection, L.L.C.
Potomac Economics............ Potomac Economics, LTD.
Prysmian..................... The Prysmian Group.
R Street Institute........... R Street Institute.
SCE.......................... Southern California Edison Company.
SDG&E........................ San Diego Gas & Electric Company.
Southern Company............. Solar Energy Industries Association.
SPP.......................... Southern Company Services, Inc.
SPP MMU...................... Southwest Power Pool, Inc.
Sunflower.................... Sunflower Electric Power Corporation.
Tangibl...................... Tangibl Group, Inc.
TAPS......................... Transmission Access Policy Study Group.
UDPU......................... Utah Division of Public Utilities.
Vistra....................... Vistra Corp.
WAPA......................... Western Area Power Administration.
WATT......................... Working for Advanced Transmission
Technologies.
WFEC......................... Western Farmers Electric Cooperative.
------------------------------------------------------------------------
[[Page 2306]]
Appendix B: Pro Forma Open Access Transmission Tariff
ATTACHMENT M
Transmission Line Ratings
General
The Transmission Provider will implement Transmission Line
Ratings on the transmission lines over which it provides
Transmission Service, as provided below.
Definitions
The following definitions apply for purposes of this Attachment:
(1) ``Transmission Line Rating'' means the maximum transfer
capability of a transmission line, computed in accordance with a
written Transmission Line Rating methodology and consistent with
Good Utility Practice, considering the technical limitations on
conductors and relevant transmission equipment (such as thermal flow
limits), as well as technical limitations of the Transmission System
(such as system voltage and stability limits). Relevant transmission
equipment may include, but is not limited to, circuit breakers, line
traps, and transformers.
(2) ``Ambient-Adjusted Rating'' (AAR) means a Transmission Line
Rating that:
(a) Applies to a time period of not greater than one hour.
(b) Reflects an up-to-date forecast of ambient air temperature
across the time period to which the rating applies.
(c) Reflects the absence of solar heating during nighttime
periods, where the local sunrise/sunset times used to determine
daytime and nighttime periods are updated at least monthly, if not
more frequently.
(d) Is calculated at least each hour, if not more frequently.
(3) ``Seasonal Line Rating'' means a Transmission Line Rating
that:
(a) Applies to a specified season, where seasons are defined by
the Transmission Provider to include not fewer than four seasons in
each year, and to reasonably reflect portions of the year where
expected high temperatures are relatively consistent.
(b) Reflects an up-to-date forecast of ambient air temperature
across the relevant season over which the rating applies.
(c) Is calculated annually, if not more frequently, for each
season in the future for which Transmission Service can be
requested.
(4) ``Near-Term Transmission Service'' means Transmission
Service which ends not more than 10 days after the Transmission
Service request date. When the description of obligations below
refers to either a request for information about the availability of
potential Transmission Service (including, but not limited to, a
request for ATC), or to the posting of ATC or other information
related to potential service, the date that the information is
requested or posted will serve as the Transmission Service request
date. ``Near-Term Transmission Service'' includes any Point-To-Point
Transmission Service, Network Resource designations, or secondary
service where the start and end date of the designation or request
is within the next 10 days.
(5) ``Emergency Rating'' means a Transmission Line Rating that
reflects operation for a specified, finite period, rather than
reflecting continuous operation. An Emergency Rating may assume an
acceptable loss of equipment life or other physical or safety
limitations for the equipment involved.
System Reliability
If the Transmission Provider reasonably determines, consistent
with Good Utility Practice, that the temporary use of a Transmission
Line Rating different than would otherwise be required by this
Attachment is necessary to ensure the safety and reliability of the
Transmission System, then the Transmission Provider may use such an
alternate rating. The Transmission Provider must document in its
database of Transmission Line Ratings and Transmission Line Rating
methodologies on OASIS or another password-protected website, as
required by this Attachment, the use of an alternate Transmission
Line Rating under this paragraph, including the nature of and basis
for the alternate rating, the date and time that the alternate
rating was initiated, and (if applicable) the date and time that the
alternate rating was withdrawn and the standard rating became
effective again.
Obligations of Transmission Provider
The Transmission Provider will have the following obligations.
The Transmission Provider must use AARs as the relevant
Transmission Line Ratings when performing any of the following
functions: (1) Evaluating requests for Near-Term Transmission
Service; (2) responding to requests for information on the
availability of potential Near-Term Transmission Service (including
requests for ATC or other information related to potential service);
or (3) posting ATC or other information related to Near-Term
Transmission Service to the Transmission Provider's OASIS site or
another password-protected website.
The Transmission Provider must use AARs as the relevant
Transmission Line Ratings when determining whether to curtail (under
section 13.6) Firm Point-To-Point Transmission Service or when
determining whether to curtail and/or interrupt (under section 14.7)
Non-Firm Point-To-Point Transmission Service if such curtailment
and/or interruption is both necessary because of issues related to
flow limits on transmission lines and anticipated to occur (start
and end) within 10 days of such determination. For determining
whether to curtail or interrupt Point-To-Point Transmission Service
in other situations, the Transmission Provider must use Seasonal
Line Ratings as the relevant Transmission Line Ratings.
The Transmission Provider must use AARs as the relevant
Transmission Line Ratings when determining whether to curtail (under
section 33) or redispatch (under sections 30.5 and/or 33) Network
Integration Transmission Service or secondary service if such
curtailment or redispatch is both necessary because of issues
related to flow limits on transmission lines and anticipated to
occur (start and end) within 10 days of such determination. For
determining the necessity of curtailment or redispatch of Network
Integration Transmission Service or secondary service in other
situations, the Transmission Provider must use Seasonal Line Ratings
as the relevant Transmission Line Ratings.
The Transmission Provider must use Seasonal Line Ratings as the
relevant Transmission Line Ratings when evaluating requests for and
whether to curtail, interrupt, or redispatch any Transmission
Service not otherwise covered above in this section (including, but
not limited to, requests for non-Near-Term Transmission Service or
requests to designate or change the designation of Network Resources
or Network Load), when developing any ATC or other information
posted or provided to potential customers related to such services.
The Transmission Provider must use Seasonal Line Ratings as a
recourse rating in the event that an AAR otherwise required to be
used under this Attachment is unavailable.
The Transmission Provider must use uniquely determined Emergency
Ratings for contingency analysis in the operations horizon and in
post-contingency simulations of constraints. Such uniquely
determined Emergency Ratings must also include separate AAR
calculations for each Emergency Rating duration used.
In developing forecasts of ambient air temperature for AARs and
Seasonal Line Ratings, the Transmission Provider must develop such
forecasts consistent with Good Utility Practice and on a non-
discriminatory basis.
Postings to OASIS or another password-protected website: The
Transmission Provider must maintain on the password-protected
section of its OASIS page or on another password-protected website a
database of Transmission Line Ratings and Transmission Line Rating
methodologies. The database must include a full record of all
Transmission Line Ratings, both as used in real-time operations, and
as used for all future periods for which Transmission Service is
offered. Any postings of temporary alternate Transmission Line
Ratings or exceptions used under the System Reliability section
above or the Exceptions section below, respectively, are considered
part of the database. The database must include records of which
Transmission Line Ratings and Transmission Line Rating methodologies
were in effect at which times over at least the previous five years,
including records of which temporary alternate Transmission Line
Ratings or exceptions were in effect at which times during the
previous five years. Each record in the database must indicate which
transmission line the record applies to, and the date and time the
record was entered into the database. The database must be
maintained such that users can view, download, and query data in
standard formats, using standard protocols.
Sharing with Transmission Providers: The Transmission Provider
must share, upon request by any Transmission Provider and in a
timely manner, the following information:
(1) Transmission Line Ratings for each period for which
Transmission Line Ratings
[[Page 2307]]
are calculated, with updated ratings shared each time Transmission
Line Ratings are calculated, and
(2) Written Transmission Line Rating methodologies used to
calculate the Transmission Line Ratings in (1) above.
Exceptions: Where the Transmission Provider determines,
consistent with Good Utility Practice, that the Transmission Line
Rating of a transmission line is not affected by ambient air
temperature or solar heating, 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 temperature or solar heating; 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 temperature or solar heating. The Transmission Provider
must document in its database of Transmission Line Ratings and
Transmission Line Rating methodologies on OASIS or another password-
protected website any exceptions to the requirements contained in
this Attachment initiated under this paragraph, including the nature
of and basis for each exception, the date(s) and time(s) that the
exception was initiated, and (if applicable) the date(s) and time(s)
that each exception was withdrawn and the standard rating became
effective again. If the technical basis for an exception under this
paragraph changes, then the Transmission Provider must update the
relevant Transmission Line Rating(s) in a timely manner. The
Transmission Provider must reevaluate any exceptions taken under
this paragraph at least every five years.
FEDERAL ENERGY REGULATORY COMMISSION
Managing Transmission Line Ratings
Docket No. RM20-16-000
(Issued December 16, 2021)
DANLY, Commissioner, concurring:
1. I concur with the issuance of this final rule because I agree
that the record in this proceeding supports a finding that current
transmission rates are unjust and unreasonable because line rating
information is often inaccurate.\1\ The rates customers pay to
support transmission are distorted because the ratings that purport
to represent the true operating characteristics of the transmission
system are distorted. The voluminous record evidence in this
proceeding is sufficient to support a Federal Power Act section 206
action to remedy unjust and unreasonable rates.\2\ The record also
is sufficient to support the replacement rates we order in this
rule.
---------------------------------------------------------------------------
\1\ Managing Transmission Line Ratings, 177 FERC ] 61,179 at P
29 (2021).
\2\ 16 U.S.C. 824e.
---------------------------------------------------------------------------
2. Of course, we cannot act pursuant to section 206 without
substantial record evidence that the existing rate is unjust and
unreasonable and further record support for a replacement rate. We
cannot impose a requirement for dynamic line ratings, for example,
because we do not have the record support to do so at this time.\3\
Action cannot be taken under section 206 merely because a potential
reform is a good idea or because a contemplated policy might yield
greater efficiencies.
---------------------------------------------------------------------------
\3\ See Managing Transmission Line Ratings, 177 FERC ] 61,179 at
P 36 (declining to require dynamic line ratings).
---------------------------------------------------------------------------
3. Here, I am persuaded that we have sufficient record evidence
to require ambient-adjusted ratings (AAR) on all transmission lines
because the record shows the existing paradigm significantly
distorts efficient use of the transmission system.\4\ In addition,
AAR is a just and reasonable replacement rate because the record
evidence shows the additional costs are incremental and will provide
significant benefits.
---------------------------------------------------------------------------
\4\ Id. at P 83.
---------------------------------------------------------------------------
4. In this case, the requirements of both steps of section 206
have been satisfied. As a Commission, we must ensure that every
action taken under section 206 fully meets these burdens and I will
apply the same rigorous analysis to every future section 206
proposal to improve the transmission system.
For these reasons, I respectfully concur.
James P. Danly,
Commissioner.
[FR Doc. 2021-27735 Filed 1-12-22; 8:45 am]
BILLING CODE 6717-01-P