[Federal Register Volume 89, Number 135 (Monday, July 15, 2024)]
[Proposed Rules]
[Pages 57690-57716]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-14666]
[[Page 57689]]
Vol. 89
Monday,
No. 135
July 15, 2024
Part IV
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Implementation of Dynamic Line Ratings; Proposed Rule
Federal Register / Vol. 89 , No. 135 / Monday, July 15, 2024 /
Proposed Rules
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM24-6-000]
Implementation of Dynamic Line Ratings
AGENCY: Federal Energy Regulatory Commission.
ACTION: Advance notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
issuing an advance notice of proposed rulemaking presenting potential
reforms to implement dynamic line ratings and, thereby, improve the
accuracy of transmission line ratings. These potential reforms would
require transmission line ratings to reflect solar heating based on the
sun's position and forecastable cloud cover and require transmission
line ratings to reflect forecasts of wind conditions on certain
transmission lines. The potential reforms would also ensure
transparency in the development and implementation of dynamic line
ratings and enhance data reporting practices related to congestion in
non-regional transmission organization/independent system operator
regions to identify candidate transmission lines for the requirement to
reflect forecasts of wind conditions. The Commission invites all
interested persons to submit comments on the potential reforms and in
response to specific questions.
DATES: Comments are due October 15, 2024 and Reply Comments are due
November 12, 2024.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways. Electronic filing through https://www.ferc.gov, is
preferred.
Electronic Filing: Documents must be filed in acceptable
native applications and print-to-PDF, but not in scanned or picture
format.
For those unable to file electronically, comments may be
filed by USPS mail or by hand (including courier) delivery.
[cir] Mail via U.S. Postal Service Only: Addressed to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street NE, Washington, DC 20426.
[cir] Hand (including courier) Delivery: Deliver to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
The Comment Procedures section of this document contains more
detailed filing procedures.
FOR FURTHER INFORMATION CONTACT:
Daniel Kheloussi (Technical Information), Office of Energy Policy and
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6391,
[email protected]
Lisa Sosna (Technical Information), Office of Energy Policy and
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6597,
[email protected]
Ryan Stroschein (Legal Information), Office of the General Counsel, 888
First Street NE, Washington, DC 20426, (202) 502-8099,
[email protected]
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph Nos.
I. Introduction...................................... 1
II. Background....................................... 4
A. Transmission Line Rating Proceedings.......... 5
1. Order No. 881............................. 5
2. Notice of Inquiry......................... 9
3. Comments Supporting DLRs.................. 10
B. Transmission Line Ratings Background.......... 14
1. Different Types of Transmission Line 15
Ratings: Based on Thermal, Voltage, and
Stability Limits............................
2. Calculating Thermal Ratings............... 16
3. Variables That Impact Thermal Ratings of 18
Transmission Lines..........................
a. Ambient Air Temperature............... 19
b. Solar Heating......................... 20
c. Wind Speed and Direction.............. 21
C. Incorporating Weather Variables Into Thermal 22
Ratings.........................................
1. Sensors and Their Use in DLRs............. 25
2. Incorporating Local Weather Forecasts Into 33
DLRs........................................
3. Current Use and Benefits of DLRs.......... 36
D. Pro forma Transmission Scheduling and 37
Congestion Management Practices.................
1. How Transmission Service Is Procured...... 38
a. Transmission Service Under the pro 39
forma OATT..............................
b. Congestion Management Under the pro 45
forma OATT..............................
c. Transmission Scheduling and Congestion 46
Management in the RTOs/ISOs.............
2. Existing Data Reporting on Congestion, or 47
Proxies of Congestion.......................
a. RTOs/ISOs............................. 48
b. Non-RTO/ISO Regions................... 49
i. ATC and Constrained Posted-Paths.. 50
ii. Redispatch Costs................. 53
III. The Potential Need for Reform................... 54
A. Demonstrated DLR Benefits..................... 55
1. U.S. Examples............................. 56
2. International Examples.................... 63
B. Consideration of Reforms...................... 69
IV. Potential Reforms and Request for Comment........ 79
A. Potential Transmission Line Ratings Reforms 79
and Request for Comment.........................
1. Framework for a Potential Requirement..... 81
2. Potential Solar Requirement............... 83
a. Reflecting Solar Heating Based on the 85
Sun's Position..........................
b. Reflecting Solar Heating Based on 91
Forecastable Cloud Cover................
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3. Potential Wind Requirement................ 97
a. Components of a Wind Requirement...... 99
i. Time Horizon and Forecasting 101
Requirement.............................
ii. Sensor Requirements.................. 109
b. Proposed Criteria To Identify 116
Transmission Lines Subject to a Wind
Requirement.............................
i. Number of Transmission Lines 117
Subject to the Wind Requirement
Annually............................
ii. Wind Speed Threshold............. 120
iii. Congestion Threshold............ 124
(a) RTO/ISO Regions.................. 125
(1) Congestion Costs................. 125
(b) Non-RTO/ISO Regions.............. 130
(1) Limiting Element Rate............ 130
(i) Overview......................... 130
(ii) Triggering Events............... 131
(iii) Data To Be Collected and 135
Reported............................
(iv) LER Threshold................... 137
(2) Potential Alternatives for 138
Comment.............................
(i) Non-RTO/ISO Congestion Costs..... 139
c. Self-Exceptions From the Wind 142
Requirement.............................
i. Self-Exception Categories......... 142
ii. Challenges to Self-Exceptions.... 151
d. Transmission Lines Formerly Subject to 152
the Wind Requirement....................
e. Potential Transparency Reforms and 153
Request for Comment.....................
i. Potential Reforms to Congestion 156
Data Collection.....................
ii. Posting of Congestion Data....... 158
iii. Posting of Transmission Line 160
Ratings Subject to a Wind
Requirement.........................
4. Requirements for Reflecting Solar and/or 162
Wind in Transmission Line Ratings in RTOs/
ISOs........................................
5. Implications for Emergency Ratings........ 166
6. Confidence Levels......................... 169
B. Compliance and Transition and Implementation 174
Timelines.......................................
1. Pro forma OATT Revisions and 174
Implementation..............................
2. Implementation Timeframe for the Solar 176
Requirement.................................
3. Phased-In Implementation Timeframe for the 177
Wind Requirement............................
a. Annual Wind Requirement Implementation 177
Cycles..................................
b. Transmission Provider Compliance 180
Requirement.............................
c. Compliance for Transmission Providers 182
That Are Subsidiaries of the Same Public
Utility Holding Company.................
V. Comment Procedures................................ 183
VI. Document Availability............................ 186
I. Introduction
1. In this advance notice of proposed rulemaking (ANOPR), the
Federal Energy Regulatory Commission (Commission), pursuant to its
authority under section 206 of the Federal Power Act (FPA),\1\ is
considering the need to establish requirements for transmission
providers to use dynamic line ratings to improve the accuracy of
transmission line ratings. Dynamic line ratings, or DLRs, are
transmission line ratings that reflect up-to-date forecasts of weather
conditions, such as ambient air temperature, wind, cloud cover, solar
heating, and precipitation, in addition to transmission line conditions
such as tension or sag.\2\ The Commission is also considering reforms
to ensure transparency in the development and implementation of dynamic
line ratings.
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\1\ 16 U.S.C. 824e.
\2\ See, e.g., 18 CFR 35.28(b)(14).
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2. In 2021, the Commission issued Order No. 881, to revise its pro
forma Open Access Transmission Tariff (OATT) and the Commission's
regulations to improve the accuracy and transparency of transmission
line ratings.\3\ Specifically, the Commission found that the use of
only seasonal and static temperature assumptions in developing
transmission line ratings would result in transmission line ratings
that do not accurately represent the transfer capability of the
transmission system.\4\ The Commission found that inaccurate
transmission line ratings result in unjust and unreasonable Commission-
jurisdictional rates.\5\
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\3\ Managing Transmission Line Ratings, Order No. 881, 87 FR
2244 (Jan. 13, 2022), 177 FERC ] 61,179 (2021), order addressing
arguments raised on reh'g, Order No. 881-A, 87 FR 31712 (May 25,
2022), 179 FERC ] 61,125 (2022).
\4\ Id. P 3.
\5\ Id. PP 3, 29.
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3. Building upon past Commission actions designed to improve the
accuracy and transparency of transmission line ratings, this ANOPR
raises questions and explores potential reforms to further enhance
transmission line ratings and congestion reporting practices. We
preliminarily propose and seek comment on a DLR framework for reforms
to improve the accuracy of transmission line ratings and ensure
transparency in the development and implementation of transmission line
ratings. These potential DLR reforms would require transmission line
ratings to reflect the impacts of solar heating by considering the
sun's position and forecastable cloud cover. They would also require
transmission line ratings to reflect forecasts of wind conditions--wind
speed and wind direction--on certain transmission lines. The potential
reforms also would enhance data reporting practices related to
congestion in non-regional transmission organization (RTO)/independent
system operator (ISO) regions to identify candidate transmission lines
for any wind requirement. We seek comment on this framework and whether
any reforms to alter the requirements for transmission line ratings are
needed to ensure rates for Commission-jurisdictional service are just
and
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reasonable, and not unduly discriminatory or preferential.
II. Background
4. This ANOPR proposes a DLR framework for reforms that would build
upon past Commission actions designed to improve the accuracy of
transmission line ratings and ensure transparency in the development
and implementation of transmission line ratings. This section describes
those past actions, related Commission proceedings, how transmission
line ratings are determined, including the incorporation of weather
variables into thermal ratings and the use of sensors, and how
transmission services are provided and procured in the bulk electric
system to provide context for the reforms proposed herein.
A. Transmission Line Rating Proceedings
1. Order No. 881
5. In December 2021, the Commission issued Order No. 881, which
reformed both the pro forma OATT and the Commission's regulations to
improve the accuracy and transparency of transmission line ratings.\6\
The Commission explained that seasonal or static transmission line
ratings, which represent the maximum transfer capability of each
transmission line and are typically based on conservative assumptions
about long-term air temperature and other weather conditions, may not
accurately reflect the near-term transfer capability of the
transmission system and that more accurate transmission line ratings
can be achieved through the use of ambient-adjusted ratings (AAR) and
DLRs.\7\ Therefore, the Commission adopted requirements for the use of
AARs,\8\ and the use of uniquely determined emergency ratings that
include separate AAR calculations, for use in the operations horizon
and in post-contingency simulations of constraints.\9\ The Commission
further required associated transparency requirements and certain
discrete requirements related to removing barriers to DLRs, including
requiring RTOs/ISOs to establish and implement the systems and
procedures necessary to allow transmission providers to electronically
update transmission line ratings at least hourly. The Commission also
required the consideration of solar heating as part of AARs in the form
of separate daytime and nighttime ratings. For this daytime/nighttime
ratings requirement, transmission providers must assume solar heating
during daylight hours, and nighttime ratings must reflect the absence
of solar heating.\10\ Although the Commission declined to require
hourly forecasts of solar heating, it clarified that nothing in the
final rule prohibited a transmission provider from voluntarily
implementing hourly forecasts for solar heating.\11\
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\6\ 177 FERC ] 61,179.
\7\ Unlike static thermal line ratings, which are calculated
annually or seasonally based on constant values of line current and
worst-case weather conditions, AARs are determined using near-term
forecasted ambient air temperatures and updated daytime/nighttime
solar heating values. As noted above, DLRs are calculated using up-
to-date forecasts of ambient air temperature, plus other weather
conditions such as wind, cloud cover, solar heating, and
precipitation, in addition to transmission line conditions such as
tension or sag.
\8\ AAR is defined as 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; and (d) is
calculated at least each hour, if not more frequently. Pro forma
OATT, attach. M, Definitions; see also 18 CFR 35.28(b)(12).
\9\ ``Emergency Rating'' is defined as 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. 18 CFR 35.28(b)(13);
pro forma OATT, attach. M, Definitions.
\10\ Order No. 881, 177 FERC ] 61,179 at P 149.
\11\ Id. P 150.
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6. With respect to DLRs, the Commission in Order No. 881 adopted as
the definition of DLR: 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.\12\ Although organizationally Order No. 881
discussed the DLR requirement for RTOs/ISOs separately from the AAR
requirement,\13\ the Commission defined DLRs to include ambient air
temperature and solar heating.\14\ Consistent with that definition, in
this ANOPR, references to DLR include AAR (which, as used in Order No.
881, includes ambient air temperatures and solar daytime/nighttime
ratings) as well as the solar requirement and wind requirement proposed
below.\15\
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\12\ 18 CFR 35.28(b)(14); see Order No. 881, 177 FERC ] 61,179
at PP 7, 235, 238.
\13\ Compare Order No. 881, 177 FERC ] 61,179 at PP 47-192
(section IV.B ``Ambient-Adjusted Ratings'') with id. PP 235-266
(section IV.E ``Dynamic Line Ratings'').
\14\ See supra n.12.
\15\ This ANOPR does not propose any changes to the requirements
of Order No. 881.
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7. The Commission agreed with commenters that highlighted the
benefits of DLR implementation. The Commission stated that, absent
RTOs/ISOs having the capability to incorporate DLRs, 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.\16\ For
example, the Commission acknowledged that the use of DLRs generally
allows for greater power flows than would otherwise be allowed, and
that their use can detect situations when power flows should be reduced
to maintain safe and reliable operation and avoid unnecessary wear on
transmission equipment.\17\ However, the Commission also recognized
that implementing DLRs is more costly and challenging than implementing
AARs, and found that the record in the proceeding was insufficient to
evaluate the benefits, costs, and challenges of DLR implementation at
that time.\18\ As a result, the Commission declined to adopt any
reforms that would mandate DLR implementation based on the record in
that proceeding and instead incorporated that record into a new
proceeding in Docket No. AD22-5-000 to further explore DLR
implementation.\19\
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\16\ Order No. 881, 177 FERC ] 61,179 at P 255.
\17\ Id. P 253.
\18\ Id. P 254.
\19\ Id. PP 7-9.
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8. The Commission required implementation of the requirements
adopted in Order No. 881 by July 12, 2025, three years after compliance
filings were due.\20\
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\20\ We note, however, that certain transmission providers
requested and were granted extensions by the Commission. E.g., N.Y.
Indep. Sys. Operator, Inc., 186 FERC ] 61,237 (2024) (granting an
extension until no later than December 31, 2028); S. Co. Servs.
Inc., 187 FERC ] 61,055 (2024) (granting an extension up to and
including December 31, 2026).
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2. Notice of Inquiry
9. On February 17, 2022, the Commission issued a Notice of Inquiry
\21\ in which the Commission asked a series of questions about whether
and how the use of DLRs might be needed to ensure just and reasonable
Commission-jurisdictional rates; potential criteria for DLR
requirements; the benefits, costs, and challenges of implementing DLRs;
the nature of potential DLR requirements; and potential timeframes for
implementing DLR requirements. The Commission received initial comments
from 40 entities, reply comments from six
[[Page 57693]]
entities, and supplemental comments from four entities.\22\
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\21\ Implementation of Dynamic Line Ratings, Notice of Inquiry,
178 FERC ] 61,110 (2022) (NOI).
\22\ A list of commenters in the NOI proceeding and their
abbreviated names is located in the appendix.
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3. Comments Supporting DLRs
10. Comments in response to the NOI suggest potential net benefits
of implementing DLRs in certain circumstances. Various commenters state
that DLRs would reduce congestion costs.\23\ Other commenters highlight
DLR benefits related to reduced renewable energy curtailment and
reduced interconnection costs.\24\
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\23\ WATT/CEE Comments, Docket No. AD22-5, at 4 (filed Apr. 25,
2022); DOE Comments, Docket No. AD22-5, app A (Grid-Enhancing
Technologies: A Case Study on Ratepayer Impact (Feb. 2022)) at 40-
41, 52-53 (filed Apr. 25, 2022); R Street Institute Comments, Docket
No. AD22-5, at 8 (filed Apr. 26, 2022); ELCON Comments, Docket No.
AD22-5, at 5-6 (filed Apr. 25, 2022); Certain TDUs Comments, Docket
No. AD22-5, at 7, 9 (filed Apr. 25, 2022).
\24\ WATT/CEE Comments, Docket No. AD22-5, at 4 (filed Apr. 25,
2022) (citing Consentec, The Benefits of Innovative Grid
Technologies (Dec. 8, 2021) and T. Bruce Tsuchida, Stephanie Ross,
and Adam Bigelow, Unlocking the Queue with Grid-Enhancing
Technologies (Feb. 1, 2021)); DOE Comments, Docket No. AD22-5,
attach. A at 44 (filed Apr. 25, 2022); ELCON Comments, Docket No.
AD22-5, at 7 (filed Apr. 25, 2022).
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11. Commenters assert that DLR implementation can help mitigate
congestion associated with planned and/or unplanned long-term outages
of generation or transmission.\25\ Clean Energy Parties identify two
examples in which sensors for transmission line sag and transmission
line temperature can serve a reliability function, indicating that the
cost-benefit analysis for installation of sensors to enable DLR is not
limited to economic benefits. Clean Energy Parties assert that DLR
sensors serve reliability by detecting potential fire danger during
high wind periods and detecting real-time transmission line
capacity.\26\
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\25\ PJM Comments, Docket No. AD22-5, at 5 (filed May 9, 2022);
Clean Energy Parties Comments, Docket No. AD22-5, at 21 (filed Apr.
25, 2022); LineVision Comments, Docket No. AD22-5, at 5 (filed Apr.
22, 2022).
\26\ Clean Energy Parties Comments, Docket No. AD22-5, at 15
(filed Apr. 25, 2022).
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12. Commenters also note that weather sensors (which measure, e.g.,
wind speed, wind direction and/or cloud cover) and conductor sensors
(which measure conductor properties such as temperature, sag or
tension) can provide real-time operational awareness. Commenters
explain that such operational awareness can be useful for a
transmission provider to monitor specific events, such as ice on a
transmission line or the response of a transmission line operating near
its rating limit. Commenters also state that local sensors provide an
additional way to verify weather conditions in real time, which may be
especially useful along frequently limiting spans.\27\
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\27\ See LineVision Comments, Docket No. AD22-5, at 8-10 (filed
Apr. 25, 2022); TAPS Comments, Docket No. AD22-5, at 7 (filed Apr.
25, 2022); TS Conductor Comments, Docket No. AD22-5, at 9-10 (filed
Mar. 13, 2022); WATT/CEE Comments, Docket No. AD22-5, at 14 (filed
Apr. 25, 2022); Electricity Canada Comments, Docket No. AD22-5, at 6
(filed Apr. 25, 2022). A transmission span is the distance between
specific transmission support towers.
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13. Some commenters discuss different considerations and challenges
with DLRs, which are described in more detail below.
B. Transmission Line Ratings Background
14. Transmission line ratings are determined by the most limiting
element among the components that make up the transmission facility,
which includes the conductors and the associated equipment necessary
for the transfer or movement of electric energy across a transmission
facility (e.g., switches, breakers, busses, line traps, metering
equipment, and relay equipment).\28\ A transmission line rating is the
maximum transfer capability of a transmission line taking into account
the technical limitations on conductors, relevant transmission
equipment, and the transmission system.\29\ As the Commission
explained, ``Relevant transmission equipment may include, but is not
limited to, circuit breakers, line traps, and transformers.'' \30\ For
purposes of the discussion that follows, references to transmission
``line'' ratings encompass ratings for all transmission equipment that
has a rating.
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\28\ Order No. 881, 177 FERC ] 61,179 at P 44.
\29\ Id.
\30\ Id.
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1. Different Types of Transmission Line Ratings: Based on Thermal,
Voltage, and Stability Limits
15. Transmission line ratings are based on the most limiting of
three types of limits: thermal limits; voltage limits; and stability
limits. The thermal limit reflects the maximum amount of power that can
safely flow on a transmission line without it overheating. Each
transmission line may have several thermal limits depending on the
duration of power flow considered, with a lower thermal limit for
normal operations and higher thermal limits for long-term and short-
term emergency operations. However, voltage and stability limits are
typically fixed values that limit the power flow on a transmission line
from exceeding the point above which there is an unacceptable risk of a
voltage or stability problem.
2. Calculating Thermal Ratings
16. Thermal ratings are determined based on the physical
characteristics of the conductor and assumptions about environmental
conditions (e.g., ambient air temperature, sun position, cloud cover,
wind, or other weather conditions). Thermal ratings determine the
maximum amount of power that can flow through a conductor while keeping
the conductor under its ``maximum operating temperature,'' a limit
designed to prevent wear on the conductor and comply with ground
clearance and conductor sag requirements. Engineering standards,
including those published by the Institute of Electrical and
Electronics Engineers (IEEE) and the International Council on Large
Electric Systems (CIGRE), establish methods for calculating
transmission line ratings based on the conductor properties and weather
conditions.\31\ The National Electrical Safety Code (NESC) provides
minimum clearance requirements between the transmission conductor and
other facilities, including, but not limited to, minimum clearances to
other electrical circuits, communications cables, structures below the
transmission conductor, vegetation, railroads, roadways, waterways, and
ground.\32\
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\31\ See, e.g., IEEE Standard 738-2023, ``IEEE Standard for
Calculating the Current-Temperature Relationship of Bare Overhead
Conductors,'' 2023 (IEEE 738); and CIGR[Eacute] Technical Brochure
207, ``Thermal Behavior of Overhead Conductors, Working Group
22.12,'' 2002 (CIGR[Eacute] 207).
\32\ See, e.g., IEEE Standard C2-2023, ``2023 National Electric
Safety Code,'' 2023, at section 23.
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17. Thermal ratings are calculated using formulas, which are based
on forecast- or assumption-based inputs that require the use of
confidence levels. Confidence levels represent the likelihood that the
actual real-time value of that input is less than or equal to the
assumption or forecast. For some inputs in thermal ratings formulas,
forecast uncertainty may not be normally distributed. In other words,
there may be more forecast uncertainty as the input approaches a
historic limit or extreme level. For example, if an ambient air
temperature forecast approaches an extreme level (e.g., an unusually
high temperature for a given location), the uncertainty about that
forecast may become skewed such that the actual ambient air temperature
value is more likely to be below the forecast temperature than above
it.\33\ Choosing
[[Page 57694]]
confidence levels requires a balance between realizing the benefits of
incorporating weather forecasts and ensuring that the estimate does not
overestimate the thermal capability of the transmission line, which
could create system management challenges for transmission providers
and/or jeopardize reliability.
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\33\ Lisa Sosna, et al., Demonstration of Potential Data/
Calculation Workflows Under FERC Order 881's Ambient-Adjusted Rating
(AAR) Requirements, joint FERC/NOAA staff presentation at FERC's
Software Conference at slide 24-25 (June 23, 2022), https://www.ferc.gov/media/demonstration-potential-datacalculation-workflows-under-ferc-order-no-881s-ambient-adjusted.
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3. Variables That Impact Thermal Ratings of Transmission Lines
18. Thermal ratings are affected by a variety of factors, including
ambient air temperatures, solar heating, and wind speed.
a. Ambient Air Temperature
19. Transmission line thermal ratings generally decrease with
warmer ambient air temperatures and generally increase with cooler
ambient air temperatures, because the heat generated within the
conductor due to resistive losses dissipates to the environment more
quickly at lower ambient temperatures.
b. Solar Heating
20. Transmission line thermal ratings generally decrease when
exposed to more intense solar heating conditions and generally increase
when exposed to less intense solar heating conditions, because lower
solar heating allows the conductor to carry more power without
overheating. Solar heating is most intense when there are clear-sky
conditions, and the sun is at its peak position in the sky.
c. Wind Speed and Direction
21. Wind cools a transmission line, which dissipates the heat
generated from resistive losses more quickly and results in greater
transmission transfer capability on that line. Transmission line
thermal ratings generally increase when wind speed is higher and when
wind direction is perpendicular to a line and generally decrease when
wind speed is lower and when wind direction is parallel to a line.
According to research presented by Idaho National Laboratory at the
Commission's 2019 DLR Workshop, consideration of wind speed and
direction could theoretically increase transmission line ratings by
more than 100% in certain periods.\34\ In practice, the typical
increase in transmission line ratings may be smaller than 100%, but it
would still be significant, because consideration of forecast
uncertainty and confidence levels for both wind speed forecasts and
wind direction forecasts would reduce the potential rating increases. A
higher confidence level would proportionally discount the impact of
reflecting wind speed and direction on a transmission line rating.\35\
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\34\ Jake Gentle, et al., Forecasting for Dynamic Line Ratings,
Idaho National Laboratory presentation at FERC DLR Workshop slide 13
(Sept. 10, 2019), https://www.ferc.gov/sites/default/files/2020-09/Gentle-INL.pdf.
\35\ See Order No. 881, 177 FERC ] 61,179 at P 128
(acknowledging concerns about temperature forecast margins being too
low or too high).
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C. Incorporating Weather Variables Into Thermal Ratings
22. Because a variety of weather variables affect thermal ratings,
DLRs can incorporate weather variables that ``reflect transfer
capability even more accurately'' than static line ratings.\36\ In
addition to ambient air temperature, DLRs can incorporate weather
variables and other inputs into the calculation of thermal ratings
``such as (but not limited to) wind, cloud cover, solar heating (beyond
daytime/nighttime distinctions), precipitation, and transmission line
conditions such as tension or sag.'' \37\ Moreover, the use of sensors
installed on or near the transmission line can provide localized and
potentially more accurate weather forecasts when compared to large-area
weather forecasts, such as those provided by the National Weather
Service, further improving DLR accuracy.
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\36\ See id. P 26.
\37\ See id. P 7.
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23. DLR implementation requires making reliable short-term
forecasts \38\ at very specific locations. In DLR implementation,
weather measurements and, potentially, other data from sensors are
combined with data from the recent past to create short-term weather
forecasts for the specific location of the transmission line. These
short-term weather forecasts are the basis of the DLRs themselves.\39\
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\38\ Although clear-sky solar heating calculations are generally
referred to as forecasts, they may be better thought of as
``determinations'' because they carry no forecast uncertainty. Total
solar power along a transmission line can be calculated based on the
location and orientation of a transmission line, at any time and day
of the year. See Conseil International des Grands R[eacute]seaux
[Eacute]lectriques/International Council of Large Electric Systems
(CIGRE), Guide for Thermal Rating Calculations of Overhead Lines,
Technical Brochure 601, Dec. 2014 (CIGRE TB 601). Thus, our use of
``forecast'' here when referring to clear-sky solar heating is not
intended to indicate any expected forecast uncertainty about the
determination of clear-sky solar heating.
\39\ See, e.g., Jake Gentle, et al., Dynamic Line Ratings
Forecast Time Frames, Idaho National Lab (2023), Dynamic-Line-
Rating-Forecasting-Time-Frames.pdf (inl.gov); Managing Transmission
Line Ratings, Docket No. AD19-15-000, Technical Conference, Day 1
(Sept. 10, 2019), Tr. 29:1-3 (Joey Alexander, Ampacimon SA) (filed
Oct. 8, 2019) (discussing a DLR project undertaken by Elia,
Belgium's transmission system operator and noting that, ``they
wanted to make sure they could implement a two-day ahead forecast of
the DLR because that's what that market traded on''); see also
Managing Transmission Line Ratings, Staff Report, Docket No. AD19-
15-000, at 10 (issued Aug. 23, 2019) (``As mentioned earlier,
forecasting of the relevant weather conditions and line ratings over
some operationally useful period . . . is necessary for DLR
implementation.'').
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24. DLRs are implemented through the following steps: identifying
candidate transmission lines; installing any needed sensors and data
communication systems; forecasting short-term weather conditions;
revising thermal ratings formulas; and validating thermal ratings and
integrating them in an energy management system (EMS).\40\
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\40\ See Order No. 881, 177 FERC ] 61,179 at P 7.
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1. Sensors and Their Use in DLRs
25. Generally, two types of sensors can be used to implement DLRs:
(1) weather sensors that measure factors like wind speed, wind
direction, and/or cloud cover; and (2) conductor sensors that measure
the condition of the transmission line itself, such as conductor
temperature, sag, or tension.
26. Sensors can be positioned either on the ground or on the
transmission line. Each option has advantages and disadvantages.\41\
For instance, sensors placed on a transmission line may require
transmission line outages for installation and maintenance, while
ground-based sensors can be easier to install and maintain. However,
ground-based sensors are more vulnerable to physical tampering and
could pose a security threat for safe operations.\42\ Some DLR systems
incorporate photo-spatial sensors (e.g., light detection and ranging
(LiDAR)) and/or line sensors installed on or close to the monitored
transmission line.\43\ The ideal placement of a sensor can depend upon
the sensor technology and which variable the sensor is trying to
measure. For example, optical fiber sensors that are placed inside a
conductor can measure conductor properties but may not be capable of
measuring ambient weather conditions.
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\41\ Managing Transmission Line Ratings, Staff Report, Docket
No. AD19-15-000, at 9 (issued Aug. 23, 2019).
\42\ Id.
\43\ Id. at 7-8.
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27. The real-time data acquired from either type of sensor can
provide many benefits to the DLR systems and the transmission providers
using them. For example, data from sensors can provide real-time
operational awareness to grid operators, helping to identify
[[Page 57695]]
unexpected changes in a transmission line's capacity. Data from sensors
can also be used to verify the thermal rating calculated for the
transmission line, a process known as ``ratings validation.'' Data from
sensors can also help measure the accuracy of the local weather
forecasts underlying DLRs and provide information with which to improve
the forecasting methodology, a process known as ``forecast training.''
Both ratings validation and forecast training can improve thermal
ratings over time. Moreover, forecast training can help transmission
providers discover systemic patterns in local forecast errors and thus
adjust their forecasting methods to improve local forecast accuracy. As
a simplified example, a transmission provider may observe that actual
wind speeds, as measured by a sensor, in a particular valley are
consistently lower than the weather forecasts indicate for the broader
area. In this case, the transmission provider could develop a
``trained'' forecast reflecting a lower localized wind speed forecast
for that valley, which could be used to calculate the transmission
line's thermal ratings more accurately.\44\
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\44\ Rating validation and forecast training do not necessarily
have to use weather sensors; conductor sensors can also be used for
these purposes. While conductor sensors do not measure weather
variables directly, conductor sensor measurements nonetheless
reflect the effects of real-time weather, and thus can be used to
indirectly validate and train weather forecasts.
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28. However, some weather elements can be incorporated into a
transmission line rating without a sensor. For instance, in addition to
ambient air temperature, initial outreach indicates that solar heating
based on the sun's position and some forecasts of cloud cover can be
incorporated into transmission line ratings without sensors.
29. The effective use of sensors to determine DLRs requires at
least four key considerations: what type of sensors and where to place
them; how many sensors are needed; how to configure them; and how to
ensure physical security and cybersecurity. Sensor placement requires a
careful assessment of the sensor type, the number of sensors needed,
and the location for each of the sensors to be installed.
30. The appropriate quantity and configuration of sensors depends
on the type of sensors used and the weather variables they measure.
Weather-based DLR systems may incorporate real-time measurements and/or
forecasts of wind conditions because wind conditions have the greatest
effect on the thermal rating of a transmission line.\45\ However,
because wind speed and direction are highly variable and subject to
local geographic differences,\46\ real time measurements of wind
conditions may require numerous sensors. As such, reflecting wind
conditions in transmission line ratings can be costly because it
requires installation and maintenance of sufficient local sensors and
communications equipment.
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\45\ WATT/CEE Comments, Docket No. AD22-5, at 14 (filed Apr. 25,
2022).
\46\ Clean Energy Parties Comments, Docket No. AD22-5, at 12
(filed Apr. 25, 2022).
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31. Generally, placing more sensors at rating-limiting elements or
spans ensures more granular data to calculate transmission line
ratings.\47\ Generally, placing fewer sensors can diminish the
granularity and accuracy and may require transmission providers to
interpolate the weather and transmission line data from sensors on
other parts of the transmission line, which could be difficult or
impractical, and factors such as varied terrain or turns in the
transmission line could make this calculation potentially inaccurate.
Varied terrain turns in the transmission line, and the length of the
transmission line, each create the need for more sensors, but each
sensor represents an additional cost. Thus, sensor placement can be
more expensive for both transmission providers with longer transmission
lines and those with transmission lines in hilly or mountainous areas.
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\47\ For example, BPA explains that it paid $50,000 for each of
its DLR sensors, and an additional $17,500 each for installation, in
its DLR study with EPRI. BPA Comments, Docket No. AD22-5, at 9
(filed Apr. 25, 2022).
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32. DLR implementation also involves physical security and
cybersecurity risks. Therefore, as with other transmission systems,
protections must be put in place to ensure the physical security and
cybersecurity of the communications equipment, computer hardware, and
computer software required to integrate and manage DLR systems, which
can include sensors and/or alternative data sources, and associated
data in the transmission provider's EMS. DLR systems may rely upon
numerous routable devices, each of which may be vulnerable to
cyberattack. Physical security and cybersecurity protections must be
installed to protect and ensure that the new sensor system is not
tampered with or compromised. Moreover, transmission providers
implementing DLRs may not be able to use the off-the-shelf computer
systems, cloud solutions, and/or services offered by vendors.\48\
Instead, transmission providers may have to build their own secure, on-
premises computer systems, rely on services that comply with applicable
North American Electric Reliability Corporation (NERC) Reliability
Standards, and quickly adopt developing best practices to ensure that
the DLR system is secure.
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\48\ See, e.g., PPL Comments, Docket No. AD22-5, at 17-18 (filed
Apr. 25, 2022).
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2. Incorporating Local Weather Forecasts Into DLRs
33. While DLRs that rely on weather forecasts may offer significant
value, forecasting local weather may present several challenges, with
related opportunities for solutions. First, because all transmission
line ratings--including DLRs--depend upon the transmission line's most-
limiting element, the location of the most-limiting element must be
determined to identify which local weather forecast is needed. Further,
changes in the local weather may change which of the weather-sensitive
elements is most limiting.\49\ However, while identifying limiting
segments across a transmission line may appear conceptually
challenging, a joint FERC/National Oceanic and Atmospheric
Administration (NOAA) staff presentation concluded that determining the
location of the most-limiting segment for purposes of AAR calculations
can be relatively simple once the transmission line rating formula and
weather data processing is established.\50\
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\49\ For example, if the wind were to stop blowing across one
segment of a transmission line and were to start blowing across
another segment, the former segment might become the most limiting
element. Therefore, thermal ratings for each segment on a
transmission line must be frequently redetermined based on up-to-
date weather forecasts, and thus the most limiting element or
transmission line span may vary.
\50\ See, e.g., Lisa Sosna, et al., Demonstration of Potential
Data/Calculation Workflows Under FERC Order 881's Ambient-Adjusted
Rating (AAR) Requirements, joint FERC/NOAA staff presentation at
FERC's Software Conference slides 10, 14 and 26 (June 23, 2022),
https://www.ferc.gov/media/demonstration-potential-datacalculation-workflows-under-ferc-order-no-881s-ambient-adjusted (FERC/NOAA staff
evaluated ratings at numerous elements on each line they
demonstrated AAR calculations for, adopting the rating at the most
conservative element as the rating of the overall line; ``Our
approach proved to support very quick calculation of line ratings
despite the large number of rating [elements].''). In theory,
establishing such a process could be more complicated for DLR
systems that consider additional weather variables.
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34. Second, incorporating additional weather variables into
transmission line ratings will require preparing forecasts for each
variable, which may be more resource intensive. For example, due to
increased variability and micro-geographic differences, forecasting
wind speed and direction may require more
[[Page 57696]]
analysis from meteorologists than ambient air temperature forecasts.
35. Third, relying on weather forecasts for calculating
transmission line ratings exposes transmission providers to forecasting
uncertainty. In most instances, reductions in forecasted transmission
line ratings can be identified hours or days ahead of the operating
hour, giving transmission providers and market participants time to act
to ensure flows do not exceed transmission line ratings. However, in
some instances, when changes in forecasts happen at or close to the
operating hour and cause potential reliability concerns, transmission
system operators may need to issue curtailment or redispatch
instructions to manage the shortage in transmission capability, which
could be operationally similar to transmission line derates that do not
involve DLRs. This challenge can be managed through specification of
appropriate forecast confidence levels and related forecast
margins.\51\ Where weather conditions are particularly challenging to
forecast, achieving the necessary confidence levels may require
significant forecast margins that may make DLRs impractical, even on
heavily congested transmission lines. We discuss this challenge further
below in section IV.A.6. Confidence Levels.
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\51\ A forecast margin is a margin by which a forecast of an
expected parameter is adjusted (up or down, depending on the
circumstance) to provide sufficient confidence that the actual
parameter value will not be less favorable than the forecast. See,
e.g., Order No. 881, 177 FERC ] 61,179 at P 128.
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3. Current Use and Benefits of DLRs
36. As discussed further in the Need for Reform section below,
numerous DLRs have already been deployed domestically and
internationally, with resulting benefits to the transmission system and
customers, including increased transmission capacity, reduced
congestion, and reduced costs.
D. Pro forma Transmission Scheduling and Congestion Management
Practices
37. As relevant here, transmission line ratings are used by
transmission providers \52\ in determining: (1) whether a transmission
service request is approved or denied; and (2) when and how
transmission service must be curtailed or redispatched to protect
reliability or interrupted to provide service to a higher-priority
customer.\53\
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\52\ In this ANOPR, 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. Therefore, unless otherwise noted, ``transmission provider''
refers only to public utility transmission providers. The term
``public utility'' as defined in 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).
\53\ Transmission line ratings are also used by transmission
providers for other purposes, including as part of transmission
planning.
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1. How Transmission Service Is Procured
38. Because the preliminary proposals discussed herein--both for
identifying the congested transmission lines that would be subject to a
DLR requirement and the transmission services that would be impacted by
such a DLR requirement--relate to the details of transmission service
and congestion management practices under the pro forma OATT, we
provide an overview of those services and practices.
a. Transmission Service Under the pro forma OATT
39. There are two types of transmission service provided under the
pro forma OATT: (1) point-to-point transmission service; and (2)
network integration transmission service.
40. Point-to-point transmission service is the reservation and
transmission of capacity and energy from the point(s) of receipt to the
point(s) of delivery.\54\ Point-to-point transmission service is
offered on a firm and non-firm basis.\55\ When evaluating a point-to-
point transmission service request, the transmission provider
determines whether there is sufficient available transfer capability
(ATC) from a specified point-of-receipt to a specified point-of-
delivery. ATC can be calculated for any path on the transmission system
to determine if the system has available capacity to reliably
accommodate new transmission customers, using as inputs total transfer
capability (TTC) and existing transmission commitments (ETC) on that
path, as well as the amount of transfer capability reserved as part of
the capacity benefit margin (CBM) and transmission reliability margin
(TRM).\56\ Specifically, ATC is calculated as: ATC = TTC - ETC - CBM -
TRM.\57\
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\54\ Pro forma OATT, section 1.37 (Point-To-Point Transmission
Service).
\55\ Id.; id. section 13.6 (Curtailment of Firm Transmission
Service).
\56\ Section 37.6 of the Commission's regulations defines CBM as
``the amount of TTC preserved by the transmission provider for load-
serving entities, whose loads are located on that Transmission
Provider's system, to enable access by the load-serving entities to
generation from interconnected systems to meet generation
reliability requirements, or such definition as contained in
Commission-approved Reliability Standards.'' 18 CFR 37.6(b)(1)(vii).
Section 37.6 defines TRM as ``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.'' Id. Sec. 37.6(b)(1)(viii).
\57\ Preventing Undue Discrimination & Preference in
Transmission Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), 118
FERC ] 61,119, at P 209, order on reh'g, Order No. 890-A, 72 FR
12266 (Mar. 15, 2007), 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, 74 FR 61511 (Nov. 25, 2009), 129
FERC ] 61,126 (2009).
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41. The transmission line rating of a given transmission line is
the primary input into determining its TTC and, thus, is a key
determinant of the transmission line's ATC. ATC on a path is not a
single, static value; rather, it has different values based on the
requested point-to-point transmission service duration (hourly, daily,
weekly, monthly, annual), time (when service is requested to start and
end), and priority (firm or non-firm). For example, firm annual ATC
starting January 1 of a given year might be zero because of high levels
of ETC during the summer months, while firm monthly, weekly, and daily
ATC on the same path may be higher during non-summer months.
42. In the event a transmission provider is unable to accommodate a
request for long-term (i.e., with a term of one year or more) firm
point-to-point transmission service, the pro forma OATT establishes
various obligations on the transmission provider, including obligations
related to redispatch and conditional firm transmission service. First,
such a transmission provider must (under certain conditions) use due
diligence to provide redispatch from its own resources and not
unreasonably deny self-provided redispatch or redispatch arranged by a
transmission customer from a third party.\58\ Second, such a
transmission provider must offer to provide firm transmission service
with the condition that it may curtail the service prior to the
curtailment of other firm transmission service for a specified number
of hours per year or during specified system condition(s) (i.e.,
conditional firm transmission service).\59\
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\58\ Pro forma OATT, section 15.4(b).
\59\ Id. section 15.4(c); id. section 19.3 (System Impact Study
Procedures).
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43. Network integration transmission service or network service
allows a network customer to use the transmission system in a manner
comparable to how the transmission provider uses its own transmission
system to serve its native load. Specifically, network service allows a
network customer's network resources (generators, firm energy
purchases, etc.) to be integrated and economically dispatched to serve
its network load.
[[Page 57697]]
44. Network service is provided from a fleet of network resources
to a set of network loads rather than from a single point-of-receipt to
a single point-of-delivery.\60\ As such, when evaluating network
integration transmission service requests, a transmission provider
performs load-flow modeling of various anticipated dispatches on its
system and compares the modeled flows on each impacted transmission
line to the transmission line's rating.\61\
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\60\ Pro forma OATT, pt. III (Network Integration Transmission
Service Preamble); id. section 28 (Nature of Network Integration
Transmission Service).
\61\ Pro forma OATT, section 32 Additional Study Procedures For
Network Integration Transmission Service Requests, attach. C
(Methodology To Assess Available Transfer Capability), and attach. D
(Methodology for Completing A System Impact Study).
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b. Congestion Management Under the pro forma OATT
45. Congestion is managed under the pro forma OATT according to
service priority. While there are some exceptions, the typical order of
service priority is: (1) network integration transmission service and
long-term (one year or longer) firm point-to-point; (2) short-term
(less than one year) firm point-to-point; (3) conditional firm
transmission service and secondary service; and (4) non-firm point-to-
point.\62\ Under the pro forma OATT, network integration transmission
service is subject to curtailment or redispatch, while point-to-point
transmission service is subject to curtailment or interruption.\63\
Under the pro forma OATT, curtailment and redispatch are typically done
for reliability reasons, whereas interruption is typically conducted
for economic reasons. Prior to curtailing network integration
transmission service and/or long-term firm point-to-point service,
transmission providers may, however, be required to redispatch network
customers' resources and the transmission provider's own resources, on
a least-cost and non-discriminatory basis and without respect to
ownership of such resources, to relieve a transmission constraint or
maintain reliability.\64\
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\62\ Id. section 13.6 (Curtailment of Firm Transmission
Service); id. section 14.7 (Curtailment or Interruption of Service);
id. section 33 (Load Shedding and Curtailments).
\63\ The pro forma OATT defines curtailment as a reduction in
firm or non-firm transmission service in response to a transfer
capability shortage as a result of system reliability conditions.
Id. section 1.8 (Curtailment). The pro forma OATT defines
interruption as a reduction in non-firm transmission service due to
economic reasons pursuant to section 14.7. Id. section 1.16
(Interruption).
\64\ Id. section 33.2 (Transmission Constraints).
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c. Transmission Scheduling and Congestion Management in the RTOs/ISOs
46. All RTO/ISO tariffs reflect Commission-approved variations from
the pro forma OATT provisions. In RTOs/ISOs, transmission service is
typically provided as part of the security-constrained economic
dispatch (SCED) and security-constrained unit commitment (SCUC)
processes performed by the market software. As part of SCED and SCUC,
the market software performs a constrained optimization based on supply
offers and demand that minimizes production costs and ensures (among
other things) that flows on transmission lines do not exceed
transmission line ratings. Therefore, transmission line ratings are a
primary factor in the optimization process and efficient pricing.\65\
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\65\ While SCED and SCUC processes consider power flow over the
interties, RTOs/ISOs do not typically optimize ATC in the same
manner as internal locations.
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2. Existing Data Reporting on Congestion, or Proxies of Congestion
47. The availability of data measuring the cost of congestion on
the transmission system, or proxies that could be used to estimate the
cost of congestion, varies between RTO/ISO and non-RTO/ISO regions.
a. RTOs/ISOs
48. In RTO/ISO markets, at least two types of congestion metrics
are computed and publicly reported. First, as part of solving their
real-time and day-ahead markets, RTOs/ISOs compute and publish
locational marginal prices (LMP) that include a ``congestion
component,'' indicating how much congestion has increased (or
decreased) a locational price at a node compared to reference
node(s).\66\ The congestion component of an LMP for a node reflects the
extent to which an additional increment of load at that node would,
because of binding transmission constraints, need to be supplied by
resources with different marginal costs than the resources available to
serve additional increments of load at the reference node(s).\67\ For
example, if an RTO/ISO must ramp up a higher-cost peaking unit in lieu
of a lower-cost baseload unit due to a transmission constraint, the
additional incremental cost of the peaking unit would be reflected in
the congestion component of LMP. Second, as part of solving their real-
time and day-ahead markets, RTOs/ISOs compute and publish the marginal
cost of each transmission flow constraint, sometimes called the
``shadow prices'' of those constraints. These shadow prices reflect the
marginal production cost savings that would occur if the flow limit on
a constraint were relaxed by one MW. Shadow prices are used to
calculate the marginal congestion component of LMP.\68\ LMPs and shadow
prices reflect marginal rather than total costs.
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\66\ See, e.g., ISO-NE, FAQs: Locational Marginal Pricing, (Feb.
2024), https://www.iso-ne.com/participate/support/faq/lmp; NYISO,
LBMP In-Depth Course: Congestion Price Component 4-15 (Nov. 2022),
https://www.nyiso.com/course-materials; MISO, MTEP18: Book 4
Regional Energy Information, at 8 (2018).
\67\ See NYISO, LBMP In-Depth Course: Congestion Price Component
19-21 (Nov. 2022), https://www.nyiso.com/course-materials; FERC,
Energy Primer: A Handbook for Energy Market Basics 69-71 (2024),
https://www.ferc.gov/sites/default/files/2024-01/24_Energy-Markets-Primer_0117_DIGITAL_0.pdf.
\68\ The MISO tariff and the CAISO Business Practice Manual for
Definitions and Acronyms both define ``shadow price'' as ``the
marginal value of relieving a particular constraint.'' See MISO,
MISO Tariff, Module A--Common Tariff Provisions, Definitions--S
(Shadow Price), https://www.misoenergy.org/legal/rules-manuals-and-agreements/tariff/; CAISO, Business Practice Manual for Definitions
& Acronyms 128, (Jan. 21, 2023), https://bpmcm.caiso.com/BPM%20Document%20Library/Definitions%20and%20Acronyms/2023-Jan31_BPM_for_Defintions_and_Acronyms_V20_Redline.pdf.
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b. Non-RTO/ISO Regions
49. Non-RTO/ISO regions do not publish nodal prices in the same
manner as RTOs/ISOs, which can result in less public information
available on congestion costs outside of RTOs/ISOs. However, practices
to manage congestion and redispatch of internal resources may be used
to assess congestion costs in non-RTO/ISO regions.
i. ATC and Constrained Posted-Paths
50. Section 37.6 of the Commission's regulations requires
transmission providers to calculate and post certain information,
including ATC and TTC.\69\ Such calculations and postings must be made
for the following posted paths: (1) any control-area-to-control area
interconnection; (2) any path for which service has been denied,
curtailed, or interrupted for more than 24 hours in the past 12 months;
and (3) any path for which a transmission customer has requested that
ATC or TTC be posted.\70\ For all posted paths, ATC, TTC, CBM, and TRM
values must be automatically posted.\71\ These postings allow potential
transmission customers to: (1) make requests for transmission services
offered by transmission providers, request the designation of a network
resource, and request the termination of
[[Page 57698]]
the designation of a network resource; (2) view and download
information regarding the transmission system necessary to enable
prudent business decision making; (3) post, view, upload and download
information regarding available products and desired services; (4)
identify the degree to which transmission service requests or schedules
were denied or interrupted; (5) obtain access to information to support
ATC calculations and historical transmission service requests and
schedules for various audit purposes; and (6) make file transfers and
automate computer-to-computer file transfers and queries.\72\
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\69\ 18 CFR 37.6.
\70\ Id. Sec. 37.6(b)(1)(i).
\71\ Id. Sec. 37.6(b)(3).
\72\ Id. Sec. 37.6(a).
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51. Section 37.6(b)(1)(ii) of the Commission's regulations defines
constrained posted paths as any posted paths that have ATC less than or
equal to 25 percent of TTC at any time during the preceding 168 hours
or for which ATC has been calculated to be less than or equal to 25
percent of TTC for any period during the current hour or the next 168
hours.\73\ For all constrained posted paths, additional detailed
information must be made available upon request.\74\ This includes
``all data used to calculate ATC [and] TTC,'' including relevant
transmission line ratings, identification of limiting element(s), the
cause of the limit (e.g., thermal, voltage, stability), and load
forecast assumptions.\75\
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\73\ Id. Sec. 37.6(b)(1)(ii).
\74\ Id. Sec. 37.6(b)(2)(ii).
\75\ Id.
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52. Under these requirements, depending on whether the paths are
constrained or unconstrained, transmission providers are required to
post firm and non-firm ATC and related data for many different
timeframes (e.g., daily, monthly, seasonally, annually) for different
durations into the future ranging from daily ATC for the next day to
annual ATC as far out as 10 years (in certain circumstances for some
constrained posted paths).\76\ Other posting requirements (including
posting of hourly ATC) apply to non-firm ATC. All such postings are
typically made to the transmission providers' Open Access Same-Time
Information System (OASIS) site.
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\76\ Id. Sec. 37.6(b)(3).
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ii. Redispatch Costs
53. Under the pro forma OATT, transmission providers may redispatch
resources due to the existence of transmission constraints in certain
circumstances.\77\ Because non-RTO/ISO regions do not publish nodal
prices that reflect congestion costs, the cost of redispatching
resources is less transparent.\78\ Nonetheless, redispatching of
resources in non-RTO/ISO regions to manage congestion may be comparable
to the practices in RTOs/ISOs in that both are tasked with reliably
serving wholesale transmission customers at least cost.
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\77\ Section 33.2 of the pro forma OATT provides that during any
period when the Transmission Provider determines that a transmission
constraint exists on the Transmission System, and such constraint
may impair the reliability of the Transmission Provider's system,
the Transmission Provider will take whatever actions, consistent
with Good Utility Practice, that are reasonably necessary to
maintain the reliability of the Transmission Provider's system.
Section 33.2 of the pro forma OATT provides that to the extent the
Transmission Provider determines that the reliability of the
Transmission System can be maintained by redispatching resources,
the Transmission Provider will initiate procedures pursuant to the
Network Operating Agreement to redispatch all Network Resources and
the Transmission Provider's own resources on a least-cost basis
without regard to the ownership of such resource. Section 33.2 of
the pro forma OATT further provides that any redispatch under this
section may not unduly discriminate between the Transmission
Provider's use of the Transmission System on behalf of its Native
Load Customers and any Network Customer's use of the Transmission
System to serve its designated Network Load.
\78\ Any redispatch costs are allocated proportionately to the
load ratio share of the transmission provider and network customers.
See pro forma OATT, section 33.3 (Cost Responsibility for Relieving
Transmission Constraints).
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III. The Potential Need for Reform
54. As a result of the continued development of DLR technology, the
record gathered in the NOI, and outreach conducted since the issuance
of the NOI, we believe that it is appropriate to examine whether
transmission line ratings that fail to reflect forecasts of solar
heating and wind speed and direction result in sufficiently accurate
transmission line ratings and whether reforms may be necessary to
improve the accuracy of transmission line ratings and ensure
transparency of their development and implementation. Without these
reforms, we believe that transmission line ratings may be
insufficiently accurate and may unjustly and unreasonably increase the
cost to reliably serve wholesale electric customers by forgoing many
potential benefits. As the Commission has previously found, inaccurate
transmission line ratings result in Commission-jurisdictional rates
that are unjust and unreasonable.\79\ Accordingly, we preliminarily
find that transmission line ratings that do not account for solar
heating and wind conditions may result in rates and practices that are
unjust, unreasonable, unduly discriminatory or preferential. We begin
with a discussion about existing uses of DLRs and their associated
benefits before discussing potential reforms.
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\79\ Order No. 881, 177 FERC ] 61,179 at P 3.
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A. Demonstrated DLR Benefits
55. DLRs have been deployed nationally and internationally, with
resulting benefits to the transmission system and customers, including
increased transmission capacity, reduced congestion, and reduced costs.
Existing DLR projects and data demonstrating their benefits strengthen
the potential need for reform.
1. U.S. Examples
56. In the United States, some transmission providers and system
operators report using DLR systems to curb congestion, increase
transmission capacity, and reduce costs. Below, we detail four specific
examples of DLR use. These examples illustrate how DLRs can more
accurately reflect the capability of a transmission facility and result
in cost savings where congestion is decreased due to increased
transmission capability.
57. First, PPL, which owns transmission facilities in PJM, has
spent approximately $1 million implementing DLRs, using 18 sensors on
more than 31 miles of three 230 kV transmission line segments, and has
integrated DLRs for these transmission lines into PJM's real-time and
day-ahead markets.\80\ By contrast, PPL states that it internally
estimated the cost to reconductor the Susquehanna-Harwood double-
circuit line to be approximately $12 million.\81\ PPL reports that,
based on 2022 data, implementing DLR on these three transmission lines
produced normal ratings gains above AARs of approximately 17% and
emergency ratings gains above AARs ranging from 8.5% to 16.5%.\82\ PPL
further reports that deploying DLR on two Susquehanna-Harwood lines
eliminated congestion, which was $12 million per year in the summer of
2022, and that, deploying DLR on the Juniata-Cumberland transmission
line decreased congestion costs from approximately $66 million in the
winter of 2021-22 to approximately $1.6 million in the winter of 2022-
23. PPL explains that it aims to implement DLR
[[Page 57699]]
on five additional transmission lines by the end of 2024.\83\
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\80\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies 11 (Oct. 2021), https://inl.gov/content/uploads/2023/03/A-Guide-to-Case-Studies-for-Grid-Enhancing-Technologies.pdf; T&D World, PPL Electric Utilities Wins 95th Annual
Edison Award (June 2023), https://www.tdworld.com/electric-utility-operations/article/21267742/ppl-electric-utilities-wins-95th-annual-edison-award.
\81\ PPL Comments, Docket No. AD22-5, at 14-15 (filed Apr. 25,
2022).
\82\ PPL Supplemental Comments, Docket No. AD22-5, at 2-4 (filed
Feb. 9, 2024).
\83\ Id.
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58. PJM notes that, during Winter Storm Elliott, DLRs on the
previously mentioned PPL transmission lines proved higher than the
AARs, and that, had PJM not had the higher DLRs, PJM would have had to
redispatch the system to maintain reliability. PJM adds that such
action would have been very difficult under the critical operating
conditions caused by the winter storm.\84\
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\84\ PJM Supplemental Comments, Docket No. AD22-5, at 2 (filed
Jan. 17, 2024).
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59. In a DLR deployment study of a single 115 kV transmission line
owned by National Grid in Massachusetts, DLRs were found to increase
transmission capacity by approximately 16% above AARs (excluding
periods when DLRs were lower than AARs). However, the project also
recorded that DLRs were below AARs 22% of the time in the summer and
27% of the time in the winter (at times when wind speed was low and the
AAR would have been overstated).\85\ The DLR sensors were reported as
``easy to install, reliable, and effective at reporting periods of
either excess or limited capacity.'' \86\
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\85\ K. Engel, J. Marmillo, M. Amini, H. Elyas, B. Enayati, An
Empirical Analysis of the Operational Efficiencies and Risks
Associated with Static, Ambient Adjusted, and Dynamic Line Rating
Methodologies 3, 8 (Jul. 2, 2021), https://cigre-usnc.org/wp-content/uploads/2021/11/An-Empirical-Analysis-of-the-Operational-Efficiencies-and-Risks-Associated-with-Line-Rating-Methodologies.pdf.
\86\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies 8 (Oct. 2022), https://inl.gov/content/uploads/2023/03/A-Guide-to-Case-Studies-for-Grid-Enhancing-Technologies.pdf.
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60. A Department of Energy (DOE) report described implementation of
DLRs using tension sensors along five 345 kV transmission lines and
three 138 kV transmission lines by Oncor Electric Delivery Company's
(Oncor), a transmission owner in ERCOT. The report noted that DLRs
increased the available capacity of the lines by between 6% and 14%
beyond the transmission lines' AARs, on average. As described in the
report, Oncor determined that the cost of installing DLRs ranged from
$16,000 to $56,000 per mile, depending on the type of transmission
towers upon which DLR equipment was installed.\87\ The report noted
that installation costs in this instance totaled approximately $4.8
million and that DLR system costs are often only a fraction of the cost
of reconductoring or rebuilding a transmission line.\88\
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\87\ Warren Wang and Sarah Pinter, U.S. Dept. of Energy, Dynamic
Line Rating Systems for Transmission Lines at 33, U.S. Dept. of
Energy (Apr. 2014), https://www.energy.gov/sites/prod/files/2016/10/f34/SGDP_Transmission_DLR_Topical_Report_04-25-14.pdf.
\88\ Id.
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61. In August 2021, Duquesne Light Company (Duquesne), a
transmission owner in PJM, partnered with LineVision on a DLR pilot
project.\89\ The pilot project installed DLRs on 345 kV lines in
southwestern Pennsylvania and increased the lines' available capacity
by 25%, on average. In 2022, Duquesne expanded the pilot program and
installed sensors to also monitor 138 kV transmission lines, reporting
an average transmission line rating increase of 25%, which, it asserts,
has helped to make way for more renewable energy sources.\90\
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\89\ Duquesne, Duquesne Light Company Investing in New
Technology to Enhance Grid Capacity and Reliance, NewsRoom (Aug.
2021), https://newsroom.duquesnelight.com/duquesne-light-company-investing-in-new-technology-to-enhance-grid-capacity-and-reliance.
\90\ LineVision, Inc, Duquesne Light Company Further Enhances
Transmission Capacity, Reliability with Grid-Enhancing Technology
(Aug. 2022), https://www.linevisioninc.com/news/duquesne-light-company-further-enhances-transmission-capacity-reliability-with-grid-enhancing-technology.
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62. In addition, a recent report on an initial deployment of DLRs
by subsidiaries of AES Corporation in Indiana and Ohio shows that
estimated costs to implement DLRs on the studied transmission lines are
generally lower than reconductoring alternatives and that DLRs can be
implemented more quickly than reconductoring.\91\
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\91\ AES Corporation and LineVision, Inc., Lessons from First
Deployment of Dynamic Line Ratings (Apr. 2024), https://www.aes.com/sites/aes.com/files/2024-04/AES-LineVision-Case-Study-2024.pdf. We
understand the report to refer to The Dayton Power and Light Company
as AES Ohio and Indianapolis Power & Light Company as AES Indiana,
each a subsidiary of AES Corporation.
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2. International Examples
63. Many transmission providers elsewhere in the world have
similar, or greater, levels of experience with DLRs as those in the
United States, with some running pilot projects and others using DLRs
in operations. Like the U.S. examples cited above, these projects
illustrate the potential for DLRs to more accurately estimate
transmission transfer capability and reduce costs due to decreased
congestion.
64. Elia (Belgium's system operator) uses DLRs on 33 transmission
lines that range from 70 kV to 380 kV.\92\ A representative from Elia
stated the following at a September 10, 2021 Commission workshop: ``the
lines equipped with [DLRs] are more reliable than other lines'' and
that Elia knows ``more about those lines than any other lines in the
grid.'' \93\ RTE, France's transmission operator, used DLR to integrate
wind power generation and avoid a $30 million transmission line
replacement.\94\
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\92\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies 33 (Dec. 2022), https://inldigitallibrary.inl.gov/sites/sti/sti/Sort_64025.pdf.
\93\ Workshop to Discuss Certain Performance-based Ratemaking
Approaches, Docket No. RM20-10, Technical Video Conference (Sept.
10, 2021), Tr. 240:9-13 (Victor le Maire, Elia System Operator)
(filed Oct. 13, 2021).
\94\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies, at 13 (Dec. 2022).
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65. Austria has installed DLR on 15% of its transmission system,
leading to almost $17 million in congestion cost savings in 2016.\95\
The Slovenian system operator has used DLR on each span of 31
transmission lines since 2016, increasing capacity an average of
22%.\96\ A joint project between the University of Palermo and Terna
Rete Italia SPA to install 90 DLR monitors in Italy saved roughly $1.25
million per transmission line per year, with a payback period of two
years or less.\97\
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\95\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies, at 22 (Oct. 2022).
\96\ [Scaron]pela Vidrih, Andrej Matko, Janko Kosma[ccaron],
Toma[zcaron] Tom[scaron]i[ccaron], Ale[scaron] Donko, Operational
Experiences with the Dynamic Thermal Rating System, at 8, 2d South
East European Regional CIGRE Conference, Kyiv (2018).
\97\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies, at 18 (Oct. 2022).
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66. In 2020, LineVision and the European Commission's FARCROSS
consortium, a project to boost cross-border transmission in the
European Union, announced a partnership to install DLR in Hungary,
Greece, Slovenia, and Austria.\98\
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\98\ T&D World, LineVision Announces EU-Funded Projects with
European Utilities (Apr. 14, 2020), https://www.tdworld.com/overhead-transmission/article/21128758/linevision-announces-eu-funded-projects-with-european-utilities.
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67. The United Kingdom's National Grid has installed DLR on a 275
kV circuit in Cumbria, with estimated savings of [pound]1.4 million per
year.\99\ In Scotland, SP Energy Networks installed DLR at a cost of
approximately $240,000 to increase capacity on two circuits and avoid
the need for a transmission line rebuild that would have cost $2.25
million, roughly 10 times the cost of DLR installation.\100\
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\99\ LineVision, National Grid installs LineVision's Dynamic
Line Rating sensors to expand the capacity of existing power lines,
(Oct. 2022), https://www.linevisioninc.com/news/national-grid-installs-linevisions-dynamic-line-rating-sensors-to-expand-the-capacity-of-existing-power-lines.
\100\ Idaho National Laboratory, A Guide to Case Studies of Grid
Enhancing Technologies, at 28 (October. 2022).
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68. Analysis of four AltaLink transmission lines in Canada found
[[Page 57700]]
DLRs were higher than static transmission line ratings ``up to 95.1% of
the time, with a mean increase of 72% over a static rating.'' \101\
Moreover, DLRs were higher than seasonal ratings 76.6% of the time,
with an average capacity improvement of 22% over static ratings.\102\
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\101\ Bishnu P. Bhattarai, Jake P. Gentle, Timothy McJunkin,
Porter J. Hill, Kurt S. Myers, Alexander W. Abboud, Rodger Renwick,
& David Hengst, Improvement of Transmission Line Ampacity
Utilization by Weather-Based Dynamic Line Rating, IEEE Transactions
on Power Delivery 1853, 1861 (2018), https://doi.org/10.1109/TPWRD.2018.2798411.
\102\ Id. at 1853, 1861.
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B. Consideration of Reforms
69. We are considering reforms that would require implementation of
certain DLR practices, including: requiring transmission line ratings
to reflect solar heating based on the sun's position and forecastable
cloud cover; requiring transmission line ratings to reflect forecasts
of wind conditions--wind speed and wind direction--on certain
transmission lines; and enhancing data reporting practices to identify
candidate transmission lines for the wind requirement in non-RTO/ISO
regions. Such reforms may ensure that transmission line ratings result
in jurisdictional rates that are just and reasonable.
70. In Order No. 881, the Commission found 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'').\103\ The Commission further found 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.\104\ Acting pursuant to FPA section
206, the Commission concluded that certain revisions to the pro forma
OATT and the Commission's regulations were necessary to ensure just and
reasonable wholesale rates.\105\
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\103\ Order No. 881, 177 FERC ] 61,179 at P 29.
\104\ Id.
\105\ Id.
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71. In Order No. 881, the Commission recognized that, in addition
to ambient air temperatures and daytime/nighttime solar heating, other
weather conditions such as wind, cloud cover, solar heating intensity,
precipitation, and transmission line conditions such as tension and
sag, can affect the amount of transfer capability of a given
transmission facility. The Commission explained that incorporating
these additional inputs provides transmission line ratings that are
closer to the true thermal transmission line limits than AARs.\106\
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\106\ Id. P 36.
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72. We preliminarily find that transmission line ratings that do
not reflect solar heating based on the sun's position and up-to-date
forecasts of forecastable cloud cover may result in unjust and
unreasonable wholesale rates. We further preliminarily find that
transmission line ratings that do not reflect up-to-date forecasts of
wind conditions on certain transmission lines may also result in unjust
and unreasonable wholesale rates. We seek comment on both of these
preliminary findings.
73. We also preliminarily find that transmission line ratings that
better reflect solar heating and, where appropriate, wind conditions
would result in more accurate system transfer capability, thereby
resulting in just and reasonable rates. As the Commission noted in
Order No. 881, increasing transfer capability will, on average, reduce
congestion costs because transmission providers will be able to import
less expensive power into what were previously constrained areas,
resulting in cost savings, as discussed above, and wholesale rates that
avoid unnecessary congestion costs.\107\ For example, as discussed
above, PPL's implementation of DLRs on just two of its transmission
lines reduced annual congestion costs by approximately $77 million
annually.\108\
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\107\ Id. P 34 (``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 the wholesale service bring
provided.''); see also supra section III.A.1.
\108\ See supra P 57.
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74. The use of DLRs may also provide benefits to customers by
mitigating the need for more expensive upgrades. PPL's internal
estimate to reconductor the Susquehanna-Harwood double-circuit line
discussed above was approximately $12 million. In contrast, the cost to
install DLRs on that line was less than $500,000.\109\ In addition, a
recent report on an initial deployment of DLRs by subsidiaries of AES
Corporation compares estimated costs and implementation times of DLR
deployment and reconductoring.\110\ For a 345 kV transmission line in
the AES Indiana footprint located in an area where significant load
growth was expected, the cost to reconductor the transmission line was
estimated to be $590,000 per mile, while the cost for DLR
implementation was estimated to be $45,000 per mile.\111\ The
implementation time for reconductoring was estimated to be two years
while the implementation for DLR was estimated to be nine months. For a
69 kV transmission line in the AES Ohio footprint that was experiencing
regular thermal overload, the cost for full reconductoring was
estimated to be $1.63 million, while the cost for DLR with targeted
reconductoring was estimated to be $390,000.\112\ The implementation
timelines were two years for full reconductoring and one year for DLR
with targeted reconductoring.
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\109\ See PPL Comments, Docket No. AD22-5, at 14-15 (filed Apr.
25, 2022).
\110\ AES Corporation and LineVision, Inc., Lessons from First
Deployment of Dynamic Line Ratings (Apr. 2024), https://www.aes.com/sites/aes.com/files/2024-04/AES-LineVision-Case-Study-2024.pdf. We
understand the report to refer to The Dayton Power and Light Company
as AES Ohio and Indianapolis Power & Light Company as AES Indiana,
each a subsidiary of AES Corporation.
\111\ Id. at 14.
\112\ Id. at 18.
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75. Likewise, the ability to increase transmission flows into load
pockets may reduce a transmission provider's reliance on local reserves
inside load pockets. This may reduce local reserve requirements and the
costs to maintain that required level of reserves, which, in turn, may
result in cost reductions and wholesale rates that avoid unnecessary
congestion costs.\113\
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\113\ Order No. 881, 177 FERC ] 61,179 at P 34.
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76. DLRs can also provide reliability benefits by increasing the
transfer capability on the existing transmission system in a way that
provides system operators with more options during stressed system
conditions. For example, as PJM explained, the presence of DLRs on its
system during Winter Storm Elliott contributed to system reliability
because the higher transmission line ratings allowed it to avoid re-
dispatching its system.\114\ DLR systems also give transmission
providers a more complete picture of how the system is operating,
particularly in contingency situations, which allows transmission
providers to maximize their system's performance while maintaining a
safe, reliable, and efficient system.\115\ DLRs can also improve
reliability by monitoring the condition of transmission lines and
alerting utilities to hazardous conditions or potential failures on
transmission lines, which may otherwise go
[[Page 57701]]
undetected.\116\ In addition, DLRs with certain sensors, such as LiDAR,
can support public safety by providing for greater situational
awareness by monitoring the clearance of transmission lines from the
ground or nearby vegetation and providing data to assist in wildfire
prevention strategies, including when to clear vegetation and when to
upgrade equipment.\117\
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\114\ See supra P 58.
\115\ See DOE Comments, Docket No. AD22-5, Attachment A at 58
(filed Apr. 25, 2022); AES Corporation and LineVision, Inc., Lessons
from First Deployment of Dynamic Line Ratings, at 5-6 (Apr. 2024).
\116\ See PPL Comments, Docket No. AD22-5, at 15 (filed Apr. 25,
2022).
\117\ See AES Corporation and LineVision, Inc., Lessons from
First Deployment of Dynamic Line Ratings, at 17 (Apr. 2024); DOE
Comments, Docket No. AD22-5, attach. A at 57-58 (filed Apr. 25,
2022).
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77. The Commission also explained that decreasing transfer
capability when it is overstated can avoid placing transmission lines
at risk of inadvertent overload and can signal to the market that more
generation and/or transmission investment may be needed in the long
term.\118\
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\118\ Order No. 881, 177 FERC ] 61,179 at P 35.
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78. Finally, we preliminarily find that certain transparency
reforms are necessary to ensure accurate transmission line ratings. As
discussed below, the record indicates a lack of transparency for
congestion costs in non-RTO/ISO regions. Understanding if, and how
much, congestion may exist on a transmission line is essential to
understanding whether that transmission line may benefit from the
preliminary proposals in this rulemaking. As the Commission explained
in Order No. 881, if a stakeholder does not know the basis for a given
transmission line rating, particularly for a transmission line that
frequently binds and elevates prices, it cannot determine whether the
transmission line rating is accurately calculated.\119\ We seek comment
on this preliminary finding.
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\119\ Id. P 39.
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IV. Potential Reforms and Request for Comment
A. Potential Transmission Line Ratings Reforms and Request for Comment
79. As detailed above in section II.C.3. Current Use of DLRs and
below in sections IV.A.2. Potential Solar Requirement and IV.A.3.
Potential Wind Requirement, the current record suggests that DLRs can
result in more accurate transmission line ratings \120\ and significant
benefits, including cost savings, through increased transfer
capability. Specifically, we preliminarily find that the benefits of
more accurate transmission line ratings outweigh the cost of
implementation for DLRs that reflect more detailed solar heating based
on the sun's position and forecastable cloud cover and, for certain
transmission lines, that reflect forecasts of wind conditions. The
applicability of the solar and wind requirements proposed below--
applying a solar requirement for all transmission lines and a wind
requirement for only certain lines--follows our understanding from
outreach that reflecting solar heating based on the sun's position and
forecastable cloud cover can be done without installing sensors and
that reflecting wind conditions likely requires sensors. We seek
comment on the proposed framework, as discussed below.
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\120\ The proposed reforms in this ANOPR apply only to thermal
ratings. Therefore, unless otherwise noted, use of the term
``rating'' hereafter should be assumed to mean ``thermal rating.''
---------------------------------------------------------------------------
80. As noted above, in Order No. 881, the Commission, in effect,
required RTOs/ISOs to be able to accept DLRs.\121\ We do not propose to
change this requirement here.
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\121\ Id. P 255.
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1. Framework for a Potential Requirement
81. We preliminarily propose a DLR framework for reforms to improve
the accuracy of transmission line ratings.\122\ These reforms would
require transmission providers to implement DLRs that--on all
transmission lines--reflect solar heating, based on the sun's position
and forecastable cloud cover, and--on certain transmission lines--
reflect forecasts of wind speed and wind direction. Thus, the proposed
DLR framework sets forth both a solar requirement and a wind
requirement. Additionally, the reforms would ensure transparency into
the development and implementation of transmission line ratings and
would enhance data reporting practices related to congestion in non-
RTO/ISO regions to identify candidate transmission lines for the wind
requirement. Under the proposed framework, these requirements would be
subject to certain exceptions and/or implementation limits, as detailed
below.
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\122\ We note that, per Attachment M of the pro forma OATT, a
transmission line rating would apply to both the conductor and any
relevant transmission equipment, which includes but is not limited
to circuit breakers, line traps, and transformers. See pro forma
OATT, attach. M, Transmission Line Rating.
---------------------------------------------------------------------------
82. The NOI asked whether other weather conditions should be part
of a potential DLR requirement.\123\ However, there appears to be
neither a strong record of the impact of other non-wind/non-solar
weather conditions on transmission line ratings nor a standard for
incorporating those weather conditions into transmission line ratings,
as there is for solar heating and wind conditions (e.g., IEEE 738 and
CIGRE TB 299).\124\ Thus, we do not propose to include such other
variables in the proposed framework. We seek comment on the impact of
non-wind/non-solar weather conditions on transmission line ratings,
relevant standards associated with those weather conditions, and
whether and how the Commission should require consideration of other
weather conditions in its proposed rule.
---------------------------------------------------------------------------
\123\ NOI, 178 FERC ] 61,110 at P 17 (Question 17).
\124\ Institute of Electrical and Electronics Engineers, IEEE
Standard for Calculating the Current-Temperature Relationship of
Bare Overhead Conductors 21-23, IEEE Std 738-2023 (2023) (IEEE 738);
Conseil International des Grands R[eacute]seaux [Eacute]lectriques/
International Council of Large Electric Systems (CIGRE), Guide for
selection of weather parameters for bare overhead conductor ratings,
Technical Brochure 299, Aug. 2006 (CIGRE TB 299).
---------------------------------------------------------------------------
2. Potential Solar Requirement
83. We preliminarily propose to require that all transmission line
ratings used for evaluating transmission service that ends not more
than 10 days after the transmission service request date (hereinafter
``near-term transmission service'') \125\ be subject to a solar
requirement to reflect solar heating in two ways, one based on solar
heating derived from the sun's position and one based on up-to-date
forecasts of forecastable cloud cover, subject to certain exceptions.
---------------------------------------------------------------------------
\125\ See pro forma OATT, attach. M, Near-Term Transmission
Service.
---------------------------------------------------------------------------
84. This proposal would apply to all transmission line ratings
because it is our understanding that the solar requirement can be
incorporated without installing sensors, enabling the benefit of
additional transfer capability through more accurate accounting of
solar heating with only minimal implementation costs. Further, this
proposal would apply the solar requirement to near-term transmission
service because the requirement effectively would subsume the daytime/
nighttime solar heating requirement set forth in Order No. 881, which
applies to near-term transmission service. The currently effective
Attachment M of the pro forma OATT already provides for transmission
providers to take a self-exception to the requirement to include solar
heating in transmission line ratings for transmission lines for which
the technical transfer capability of the limiting conductors and/or
limiting transmission equipment is not dependent on solar heating, and
for transmission lines whose transfer capability is limited by a
transmission
[[Page 57702]]
system limit that is not dependent on solar heating.\126\ The existing
exception would also apply to the proposed requirement that
transmission line ratings reflect solar heating based on the sun's
position and forecastable cloud cover.
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\126\ See id., attach. M, Obligations of the Transmission
Provider; see also Order No. 881, 177 FERC ] 61,179 at P 227.
---------------------------------------------------------------------------
a. Reflecting Solar Heating Based on the Sun's Position
85. We preliminarily propose to require that all transmission line
ratings used for near-term transmission service reflect solar heating
based on the sun's position accounting for the relevant geographic
location, date, and hour. Under this approach, transmission line
ratings would reflect the potential for the sun to heat the
transmission lines during each hour based on its position in the sky,
assuming zero cloud cover. Stated another way, transmission providers
will need to calculate, for each hour, the effect of the sun's position
on its transmission line ratings. Transmission providers would have the
discretion to calculate the effect of the sun's position on their
transmission line ratings using more granular time increments. Because
solar heating based on the sun's position starts at close to zero in
the hours shortly after sunrise, rises throughout the morning hours to
the midday peak, and then decreases through the afternoon to near zero
again in the hours shortly before sunset, requiring all transmission
line ratings used for near-term transmission service to reflect solar
heating based on the sun's position may produce more accurate
transmission line ratings than the daytime/nighttime assumptions
required under Order No. 881.
86. As the Commission explained in Order No. 881,\127\ clear-sky
solar heating assumptions based on the sun's position can be computed
with accuracy from formulas, such as those provided in standards like
IEEE 738 or CIGRE TB 601.\128\ Such calculations depend only on
geographic location, date, and time and are therefore free of any
forecast uncertainty. Likewise, such calculations do not require local
sensors or weather data. The Commission considered whether AARs should
incorporate such hourly clear-sky solar heating assumptions in Order
No. 881 but elected at that time to instead require the simpler but
less precise daytime/nighttime approach to solar heating. Under that
approach, the AARs are required to reflect only the absence of solar
heating during nighttime periods, where local sunrise/sunset times are
updated at least monthly. The Commission found that, compared to the
hourly clear-sky solar heating approach, the simpler daytime/nighttime
approach ``balance[d] the benefits and burdens'' associated with the
rule.\129\
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\127\ Order No. 881, 177 FERC ] 61,179 at P 150.
\128\ Institute of Electrical and Electronics Engineers, IEEE
Standard for Calculating the Current-Temperature Relationship of
Bare Overhead Conductors 21-23, IEEE Std 738-2023 (2023) (IEEE 738);
Conseil International des Grands R[eacute]seaux [Eacute]lectriques/
International Council of Large Electric Systems (CIGRE), Guide for
Thermal Rating Calculations of Overhead Lines, Technical Brochure
601, Dec. 2014.
\129\ Order No. 881, 177 FERC ] 61,179 at P 150.
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87. However, upon considering the NOI comments, and based on
subsequent outreach and further research, we preliminarily find that
the benefits of more accurate transmission line ratings that reflect
solar heating based on the sun's position are significant. This is
particularly true during the hours right after sunrise and right before
sunset--hours with relatively little solar heating. Because electric
demand often peaks in the hours just before sunset, assuming midday
solar heating during these hours may understate the amount of transfer
capability available and increase the costs and challenges of reliably
meeting peak demand. Additionally, regions with high levels of solar
generation may benefit from the additional transmission capacity as
load rises and solar generation declines, which further demonstrates
that understating the amount of transfer capability available during
these hours may increase the costs and challenges of maintaining
reliability.
88. The record in the Order No. 881 proceeding indicates that
considering solar heating based on the sun's position can affect a
transmission line's rating by as much as 5% to 11%.\130\ Also, joint
research by Commission staff and NOAA staff modeled the effect of the
absence of solar heating on the rating of a typical aluminum conductor
steel reinforced (ACSR) cable and found that transmission line ratings
could increase by about 12% in the hours immediately after sunrise and
before sunset.\131\ While this range of percentages represents expected
transmission line rating increases between assuming full midday sun and
assuming no sun whatsoever, they nonetheless demonstrate that
transmission line ratings would likely significantly increase in the
early morning and late afternoon hours, and moderately increase in most
other daytime hours, relative to assuming full midday sun conditions
during all daylight hours. For example, Commission and NOAA staff's
modeling found that considering hourly clear-sky solar heating
increased transmission line ratings (relative to the daytime/nighttime
ratings approach) in each of the four hours immediately after sunrise
and before sunset by 4% to 12%.\132\
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\130\ Potomac Economic Comments, Docket No. RM20-16, at 15
(filed Mar. 23, 2021) (``We estimate that the average size of
[setting solar irradiance to zero] for nighttime ratings to be an 11
percent increase''); PG&E Comments, Docket No. RM20-16, at 11 (filed
Mar. 22, 2021) (``PJM's research shows that at least 14% of their
line ratings are increased by 10% by considering solar
irradiance''); Entergy Comments, Docket No. RM20-16, at 8 (filed
Mar. 22, 2021) (``The shade of the night provides an additional 5%
to the ratings of the lines'').
\131\ Lisa Sosna, et al., Demonstration of Potential Data/
Calculation Workflows Under FERC Order 881's Ambient-Adjusted Rating
(AAR) Requirements, joint FERC/NOAA staff presentation at FERC's
2022 Software Conference at slide 29 (June 23, 2022), https://www.ferc.gov/media/demonstration-potential-datacalculation-workflows-under-ferc-order-no-881s-ambient-adjusted. Actual
increases could vary from the modeled increase, depending on
conductor surface conditions and other factors.
\132\ Id.
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89. We seek comment on our preliminary proposal to require that all
transmission line ratings used for near-term transmission service
reflect solar heating based on the sun's position for the relevant
geographic location, date, and hour under a clear sky. We also seek
comment on the costs, non-financial burdens, and financial and non-
financial benefits of this requirement.
90. As noted in section III. The Potential Need for Reform above,
we preliminarily find that transmission line ratings used for near-term
transmission service that do not reflect solar heating based on the
sun's position may result in unjust and unreasonable wholesale rates.
In addition to the requests for comments on specific aspects of this
preliminary proposal, we seek comment on whether reflecting solar
heating based on the sun's position in transmission line ratings used
for near-term transmission service would result in more accurate
transmission line ratings and would, in turn, better reflect system
transfer capability. We also seek comment on whether the greater
accuracy of transmission line ratings would result in cost savings and
just and reasonable wholesale rates. Further, given that the sun's
position is forecastable without uncertainty, we seek comment on
whether transmission providers should reflect solar heating based on
the sun's position for transmission service longer than 10 days
forward.
[[Page 57703]]
b. Reflecting Solar Heating Based on Forecastable Cloud Cover
91. We preliminarily propose to require that all transmission line
ratings used for near-term transmission service reflect solar heating
based on up-to-date forecasts of forecastable cloud cover. Transmission
providers will need to reflect, for each hour, the effect of
forecastable cloud cover on its transmission line ratings. Transmission
providers would have the discretion to calculate the effect of the
sun's position on their transmission line ratings using more granular
time increments. This proposal does not imply that the cloud cover must
be forecastable for the entire 10 days, but rather that transmission
providers should reflect forecastable cloud cover in their up-to-date
forecasts as that information becomes available.\133\ Based on outreach
and research, we understand that certain overcast periods can be
forecast accurately in certain conditions. For example, some portions
of the continental United States regularly see overcast conditions for
weeks at a time. During such periods, solar heating can be
significantly reduced, significantly increasing transmission transfer
capability.
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\133\ See infra P 95.
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92. We preliminarily propose to define forecastable cloud cover as
cloud cover that is reasonably determined, in accordance with good
utility practice, to be forecastable to a sufficient level of
confidence to be reflected in transmission line ratings. We clarify
that we are not proposing to require that transmission providers seek
to forecast individual clouds, or even most cloud formations. We seek
comment on this definition of forecastable cloud cover and the level of
confidence that is necessary to incorporate and benefit from a cloud
cover forecast.
93. We also seek comment on whether sensors are needed to
accurately forecast cloud cover. If commenters believe local sensors
are required to accurately forecast cloud cover events, we seek comment
on how such sensors improve such forecasts.
94. We note that some cloud cover events may be more easily
forecast forward than other cloud cover events. Some overcast
conditions will not be forecastable at all. For many or most weather
systems that produce forecastable cloud cover conditions, such
conditions may be forecastable only for a short time ahead of a given
operating hour, rather than for the full 10 days forward. For other
very large weather systems, or for periods of seasonal overcast
conditions in some parts of the country, such conditions may be
forecastable for longer periods.
95. Therefore, we propose to limit the proposed requirement to
reflect up-to-date forecasts of forecastable cloud cover because, if a
cloud cover event is not ``forecastable,'' then we believe it would not
be practical to require that it be reflected. However, if a cloud cover
event becomes ``forecastable'' during the relevant timeframe, it must
be reflected in the up-to-date forecasts under the proposed
requirement. Specifically, under the proposed requirement, forecastable
cloud cover data must be incorporated into ratings calculations as
close to real time as reasonably possible (i.e., as close to the time
that a relevant forecast becomes available) given the timelines needed
to obtain forecast data and perform the calculation, as well as any
other steps needed for validation, communication, or implementation of
the transmission line rating.\134\ We seek comment on this proposal to
require that transmission providers incorporate up-to-date forecasts of
forecastable cloud cover into all transmission line ratings used for
near-term transmission service. We also seek comment on whether the
requirement to incorporate up-to-date forecasts of forecastable cloud
cover should apply to transmission services other than near-term
transmission service and whether all transmission service should be
subject to this requirement, not just near-term transmission service.
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\134\ See Order No. 881, 177 FERC ] 61,179 at P 143.
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96. We seek comment on the costs, non-financial burdens, and
financial and non-financial benefits of reflecting solar heating
through the use of up-to-date forecasts of forecastable cloud cover in
transmission line ratings used for near-term transmission service, and
the extent to which this practice would increase the accuracy of the
resulting transmission line rating. Further, we seek comment on whether
transmission providers should reflect up-to-date forecasts of
forecastable cloud cover in transmission line ratings used for
transmission service up to 10 days forward or whether these forecasts
should be reflected only in the transmission line ratings used for a
shorter time frame, such as 36 or 48 hours forward. If parties believe
sensors are required to accurately forecast cloud cover, we seek
comment on whether cloud cover should alternatively be reflected only
in transmission line ratings for transmission lines that exceed a
congestion threshold, and what that threshold should be. We seek
comment on whether, alternatively, up-to-date forecasts of forecastable
cloud cover should be reflected only in the ratings of the more limited
set of transmission lines we propose would be subject to a wind
requirement (described below).
3. Potential Wind Requirement
97. We preliminarily propose to additionally require certain
transmission lines to reflect up-to-date forecasts of wind conditions,
including wind speed and direction, in their transmission line ratings
for use in 48-hour transmission service, as defined below in section
IV.A.3.a.i.a 48-Hour Transmission Service. We preliminarily propose
that this wind requirement would be implemented only on transmission
lines \135\ exceeding thresholds for wind speed \136\ and
congestion.\137\ Other transmission lines would not be subject to the
wind requirement but would still be subject to the solar requirement
discussed above.
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\135\ Id. P 44.
\136\ This threshold is described below in section IV.A.3.b.ii
Wind Speed Threshold.
\137\ This threshold is described below in section IV.A.3.b.iii
Congestion Threshold.
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98. We preliminarily propose that, for each transmission line that
is subject to the wind requirement, individual transmission providers
apply good utility practice to determine which specific electric system
equipment associated with that line--beyond the conductor--is affected
by wind conditions and thus also would be subject to the wind
requirement. This approach is similar to that taken by the Commission
in Order No. 881 with respect to AARs.\138\ We seek comment on whether
the wind requirement should explicitly apply only to the conductor
portion of a transmission line, and if so why.
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\138\ This proposal is consistent with the definition of
Transmission Line Rating in Attachment M of the pro forma OATT,
which includes ``considering the technical limitations on conductors
and relevant transmission equipment . . . [which] may include, but
is not limited to, circuit breakers, line traps, and transformers.''
See pro forma OATT, attach. M, Definitions; see also Order No. 881,
177 FERC ] 61,179 at PP 44-45.
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a. Components of a Wind Requirement
99. We preliminarily propose to require transmission providers to
reflect up-to-date forecasts of wind speed and wind direction in
transmission line ratings on lines subject to the wind requirement. We
propose to apply this wind requirement to only transmission lines
exceeding thresholds for wind speed and congestion. A potential final
rule imposing such a wind requirement would modify pro forma OATT
[[Page 57704]]
Attachment M and specify details of the wind requirement, including the
time horizon, wind forecasting requirements, sensor requirements,
exceptions, and transparency of relevant data. Below we provide
additional detail and seek comment on these elements of a wind
requirement.
100. As noted in section III. The Potential Need for Reform above,
we preliminarily find that certain transmission line ratings that do
not reflect up-to-date forecasts of wind speed and direction may result
in unjust and unreasonable wholesale rates.
i. Time Horizon and Forecasting Requirement
101. For transmission lines subject to a wind requirement, we
preliminarily propose to require transmission providers to use
transmission line ratings that account for wind speed and direction as
the basis for evaluating requests for transmission services that will
end within 48 hours of the transmission service request (48-hour
transmission service). For those transmission lines, this approach
would require transmission providers to use transmission line ratings
that reflect up-to-date forecasts of wind speed and direction to
evaluate requests for hourly and daily point-to-point transmission
services under the pro forma OATT that fall within the 48-hour time
horizon. All longer-term (weekly, monthly, yearly) point-to-point
services would not be affected by this requirement. For those
transmission lines, transmission providers would also use transmission
line ratings that incorporate the proposed wind requirement in
determining whether to curtail, interrupt, or redispatch transmission
service on transmission lines subject to a wind requirement, if such
curtailment or redispatch is necessary because of issues related to
flow limits on transmission lines and anticipated to occur within the
next 48 hours of such determination.
102. In the NOI, the Commission asked about the timeframes (and
corresponding types of transmission service) for which DLRs should be
used. In response, some commenters argue that DLRs should be used for a
variety of transmission services, including hourly, daily, and weekly
services.\139\ Other commenters argue that DLRs should be used only in
real-time operations for decisions regarding curtailment, interruption,
and redispatch.\140\
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\139\ Clean Energy Parties Comments, Docket No. AD22-5, at 15
(filed Apr. 25, 2022) (hourly or sub-hourly); LADWP Comments, Docket
No. AD22-5, at 7 (filed Apr. 25, 2022) (daily or hourly); WATT/CEE
Comments, Docket No. AD22-5, at 16 (filed Apr. 25, 2022) (near-term
transmission service as defined in Order 881).
\140\ APS Comments, Docket No. AD22-5, at 12 (filed Apr. 25,
2022); NYTOs Comments, Docket No. AD22-5, at 16 (filed Apr. 25,
2022); EEI Comments, Docket No. AD22-5, at 5 (filed Apr. 25, 2022);
Eversource Comments, Docket No. AD22-5, at 4-5 (filed Apr. 25,
2022); NYISO Comments, Docket No. AD22-5, at 6 (filed Apr. 25,
2022); Entergy Comments, Docket No. AD22-5, at 5 (filed Apr. 25,
2022); MISO Comments, Docket No. AD22-5, at 32 (filed Apr. 25,
2022).
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103. Accordingly, we seek comment on the appropriateness of the
proposed 48-hour time horizon. We note that current DLR implementations
reflect the use of DLRs across timeframes sufficient to include DLRs in
the real-time and day-ahead markets of RTOs/ISOs. For example, PPL uses
DLRs in the PJM real-time and day-ahead energy markets.\141\ We also
understand that DLR vendors offer services that calculate DLRs as far
as 10 days into the future.\142\ However, given that the forecast
uncertainty for wind speed and direction that would underlie a wind
requirement likely increases the longer the time period, we
preliminarily believe that the time horizon for a wind requirement
should be shorter than the 10-day horizon for the existing AAR
requirement.
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\141\ See PPL Comments, Docket No. AD22-5, at 14 (filed Apr. 25,
2022).
\142\ See, e.g., LineVision, Technology: Software, (stating that
LineVision's LineRate DLR product provides ``[f]orecasted DLR,
hourly, up to 240 hours (10 days) out''), www.linevisioninc.com/technology#software.
---------------------------------------------------------------------------
104. The appropriate time horizon for which transmission service
evaluations should incorporate a wind requirement depends on whether
the accuracy benefit of incorporating wind forecasts exceeds the burden
of calculating and managing the ratings for such forward hours. At
longer time horizons, forecast uncertainty increases, perhaps resulting
in the need for larger forecast margins to ensure the necessary level
of confidence in the forecasts.\143\ On the other hand, limiting the
wind requirement to a short time horizon would forego the benefits of
more accurate transmission line ratings because those benefits would
only accrue for a smaller number of hours and a more limited set of
transmission services.
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\143\ In Order No. 881, the Commission required transmission
providers to use AARs as the basis for evaluating ``near-term''
transmission service requests, defined as transmission service that
ends not more than 10 days after the transmission service request
date, because the Commission determined that forecasts of ambient
air temperature were sufficiently accurate up to 10 days into the
future, and that transmission line ratings based on such 10-day-
ahead forecasts would provide sufficient benefits. Order No. 881,
177 FERC ] 61,179 at PP 120-121. For transmission service that is
beyond 10 days forward, however, the Commission found that seasonal
line ratings are the appropriate transmission line ratings 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. Id. P 200; cf. id. P 105 (discussing the justification
for the 10-day threshold for the use of AARs).
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105. Because the bulk of the effort of calculating and archiving of
transmission line ratings on transmission lines subject to the wind
requirement is in the setup of the automated systems, we anticipate
that the data burdens of this option would not vary significantly
depending on the time horizons.\144\ Nevertheless, we seek comment on
whether applying a wind requirement to transmission line ratings over
longer time horizons would result in a greater data burden as compared
to a wind requirements for shorter-time horizons.
---------------------------------------------------------------------------
\144\ For example, Clean Energy Parties and WATT/CEE state that
system integration is a one-time engineering effort before it
becomes plug-and-play, and that resources for subsequent
installation on additional transmission lines will be limited to the
time needed to determine the location of, and to install, DLR
sensors. Clean Energy Parties Comments, Docket No. AD22-5, at 20
(filed Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 19-
20 (filed Apr. 25, 2022).
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106. Considering all of these factors, we preliminarily find that a
48-hour time horizon provides a reasonable balance between the benefits
and burdens associated with a wind requirement and may therefore be
appropriate for a potential wind requirement. Such a timeframe seems to
strike the right balance of creating significant benefits by covering
important transmission service transactions, such as those in the RTO/
ISO day-ahead markets, while reflecting that implementing a wind
requirement for longer timeframes may not supply sufficient value to
justify the burden. We seek comment on whether the 48-hour time horizon
is the appropriate timeframe or whether the Commission should consider
requiring a longer time horizon (e.g., a week, 10 days, monthly). We
seek comment on the accuracy of the forecasting of wind speed and wind
direction in these time horizons (including the 48-hour time horizon),
and any potential benefits and burdens that may result from a longer
time horizon. We also seek comment on the ability of DLR vendors to
calculate DLRs in these time horizons, and at what level of confidence.
ii. Sensor Requirements
107. We preliminarily propose that transmission providers, for
their transmission lines subject to the wind requirement, install
sensors that measure wind speed and direction as
[[Page 57705]]
determined to be necessary for forecast training or to otherwise ensure
adequate information about local weather conditions.
108. We seek comment on whether the Commission should require a
transmission provider to determine what sensors, if any, need to be
installed for forecast validation and forecast training in order to
ensure that forecasts of wind speed and direction are sufficiently
accurate. We propose that, in doing so, transmission providers should
consider a non-exhaustive list of factors including: average ambient
wind speed at the relevant altitude(s), distribution of wind direction
at the relevant altitude(s), length and configuration of conductors,
local topography, local vegetation, and position of weather stations.
We seek comment on what other factors transmission providers should be
required to consider when determining what sensors, if any, need to be
installed.
109. Further, if commenters believe that detailed sensor
configuration requirements are not necessary for transmission lines
subject to a wind requirement, we seek comment on why that approach is
preferable and how such requirements should be constructed.
110. We also seek comment on whether the Commission should mandate
sensors at all. We understand that some vendors are offering approaches
to DLRs that do not use sensors.\145\ For example, a wind requirement
could simply require that transmission line ratings reflect up-to-date
forecasts of wind speed and wind direction. Under such an approach, the
wind requirement would be defined in terms of the wind conditions that
must be reflected in the transmission line ratings, rather than what
technical equipment transmission providers must use to produce wind
forecasts. This approach is similar to the requirements adopted in
Order No. 881 for AARs to reflect up-to-date forecasts of ambient air
temperature. We seek comment on whether the technology and capability
to determine accurate forecasts of wind speed and wind direction
currently exists, or will exist in the near future, such that
transmission providers can use a sensor-less DLR to accurately and
safely determine their transmission line ratings. We seek comment on
whether there are benefits to a sensor-less approach, beyond cost
savings, as compared to a sensor-based approach. We also seek comment
on the costs of sensor-less approaches, including any comparison to the
costs of measuring wind speed and direction using sensors. We seek
comment on whether there any certain scenarios (i.e., line
configurations, types of lines) where a sensor-based approach may be
preferable to sensor-less approach.
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\145\ See, e.g., SPLIGHT Comments, Docket No. AD22-5, at 4
(filed Mar. 21, 2024) (referencing ``software-only solutions [that
can enable] DLR utilization across entire grid systems''); Renan
Giovanini, GE Digital Grid Software: Orchestrate the Clean Energy
Grid, General Electric presentation at FERC's Software Conference
referencing sensor-free digital twin DLR at slide 6 (June 27, 2023),
https://www.ferc.gov/media/renan-giovanini-general-electric-edinburgh-uk.
---------------------------------------------------------------------------
111. We also seek comment on whether, if a wind requirement
generally requires the use of sensors, the Commission should give
transmission providers the discretion to determine that no sensors are
required in certain instances. Specifically, we seek comment on what
types of factors transmission providers should consider when
identifying such instances and whether such factors should be reflected
in any ultimate Commission directive. We also seek comment on whether
an explicit provision would be necessary to give transmission providers
such latitude, or if requiring the use of sensors ``as determined to be
necessary'' would be sufficient to provide such latitude. Additionally,
to the extent that the Commission does not require the use of sensors,
we seek comment on how this would affect other proposals in this rule
(i.e., the congestion threshold, timing considerations, etc.).
112. We seek comment on the applicability of NERC Facility Ratings
Reliability Standard FAC-008-5 and NERC Transmission Relay Loadability
Reliability Standard PRC-023-4 to the wind requirement and whether any
changes would need to be made to these or other NERC Reliability
Standards to accommodate a potential wind requirement.
113. Further, we seek comment on the type and costs of needed
communications equipment, computer hardware, and computer software
required to integrate sensors and associated data into the transmission
provider's EMS. We seek comment on whether changes are needed to the
NERC Critical Infrastructure Protection (CIP) Reliability Standards or
other industry practices to ensure the physical security and
cybersecurity of the sensors, data communications, transmission line
rating and forecasting systems, and EMS improvements used to implement
a wind requirement. In particular, we seek comment on whether
additional controls are necessary to validate that sensors are
operating correctly and that any changes in ratings based on sensor
data are appropriate for that particular transmission line, taking all
relevant considerations into account. Further, we seek comment on
whether entities should have a backup or other means to acquire the
data or establish transmission line ratings if the DLR systems are
compromised or not functioning properly.
b. Proposed Criteria To Identify Transmission Lines Subject to a Wind
Requirement
114. As discussed in section II.C.3. Current Use of DLRs, research
and select experience suggest that incorporating a wind requirement
could provide significant benefits through more accurate line ratings.
However, the record gathered through the NOI suggests that implementing
the wind requirement would produce significant benefits only under
certain circumstances.\146\ We preliminarily agree with several
commenters to the NOI that candidate transmission lines for a wind
requirement should be identified through Commission-determined criteria
\147\ instead of relying on cost-benefit analyses. Thus, we
preliminarily propose to apply the wind requirement only to
transmission lines that meet certain wind speed and congestion
thresholds and to limit the number of lines subject to the wind
requirement in any one year.
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\146\ See, e.g., APPA/LPPC Comments, Docket No. AD22-5, at 8-
10,12 (filed Apr. 25, 2022); APS Comments, Docket No. AD22-5, at 4
(filed Apr. 25, 2022); DOE Comments, Docket No. AD22-5, Attachment A
at ii (filed Apr. 25, 2022) (addressing the impacts of grid-
enhancing technologies generally); AEP Comments, Docket No. AD22-5,
at 10 (filed Apr. 25, 2022); EGM Comments, Docket No. AD22-5, at 8
(filed Apr. 22, 2022); LADWP Comments, Docket No. AD22-5, at 3
(filed Apr. 25, 2022); MISO Comments, Docket No. AD22-5, at 17-18
(filed Apr. 25, 2022); NRECA Comments, Docket No. AD22-5, at 14
(filed Apr. 25, 2022); NYTOs Comments, Docket No. AD22-5, at 11
(filed Apr. 25, 2022); PPL Comments, Docket No. AD22-5, at 9 (filed
Apr. 25, 2022); PJM Comments, Docket No. AD22-5, at 2-3 (filed May
9, 2022); Southern Company Comments, Docket No. AD22-5, at 2-3
(filed Apr. 25, 2022); Tri-State Comments, Docket No. AD22-5, at 3
(Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 10 (filed
Apr. 25, 2022).
\147\ See, e.g., BPA Comments, Docket No. AD22-5, at 10-11
(filed Apr. 25, 2022); CAISO Comments, Docket No. AD22-5, at 3
(filed Apr. 25, 2022); Certain TDUs Comments, Docket No. AD22-5, at
7 (filed Apr. 25, 2022); EGM Comments, Docket No. AD22-5, at 5-6
(filed Apr. 22, 2022); PJM Comments, Docket No. AD22-5, at 5-9
(filed May 9, 2022).
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i. Number of Transmission Lines Subject to the Wind Requirement
Annually
115. We recognize that implementing the wind requirement may
present some challenges (particularly during the initial
implementation), such as siting
[[Page 57706]]
and installing sensors, particularly in remote locations, integrating
DLRs with existing operations, and ensuring secure data communication
and cybersecurity.\148\ Thus, in order to ensure that any wind
requirement is implemented in a reliable and effective manner, we
preliminarily propose to limit the number of transmission lines on
which a transmission provider must implement the wind requirement in
any given year. We preliminarily propose that such a limit account for
the fact that larger transmission providers tend to have more resources
to implement the wind requirement than smaller transmission providers.
With that in mind, we preliminarily propose to require that, for
transmission providers with transmission lines subject to the wind
requirement, transmission providers apply the wind requirement to, at
least, a number of transmission lines equal to 0.25% (or 1 in 400) of
that transmission provider's Commission-jurisdictional transmission
lines, rounded up to the next whole number.\149\ Alternatively, we seek
comment on whether the minimum number of lines that a transmission
provider must apply the wind requirement in an implementation cycle
should be based on a percentage of lines that meet the wind and
congestion thresholds rather than, as proposed above, a percentage of
all lines. We anticipate that, after initial implementation,
transmission providers will have the experience necessary to apply the
wind requirements on more lines per year. We are also concerned that
applying the wind requirements to only 0.25% of the transmission
provider's total transmission lines per year will be too slow of a
pace. Accordingly, we seek comment on the best approach to increasing
the requirement. We seek comment on whether the Commission should
increase the percentage of lines to which transmission providers must
apply the wind requirements, for any transmission lines that meet the
thresholds (i.e., 0.25% of lines in years 1 and 2 after implementation,
0.5% of lines in years 3 through 5, and 1% of lines in ensuing years)?
Alternatively, we seek comment on whether the Commission should select
a time upon which transmission providers must incorporate the wind
requirement to all lines that meet the wind speed and congestion
thresholds (i.e., at least 0.25% per year for the first five years
after implementation, but all lines that meet the thresholds must apply
the wind requirement by year six). Further, as discussed below,
transmission providers would be required to implement the wind
requirement only on transmission lines that meet both a wind speed
threshold and a congestion threshold.
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\148\ See, e.g., Order No. 881, 177 FERC ] 61,179 at P 254; AEP
Comments, Docket No. AD22-5, at 5 (filed Apr. 25, 2022); APPA/LPPC
Comments, Docket No. AD22-5, at 3-7 (filed Apr. 25, 2022), BPA
Comments, Docket No. AD22-5, at 7-8 (filed Apr. 25, 2022).
\149\ For example, for a transmission provider with 1,130
transmission lines in a given year, 0.25% of its lines would be
(0.0025) * (1,130) = 2.825 lines. As such, that transmission
provider would not be required to implement the wind requirement on
more than 3 of its transmission lines in that year, even if more
than 3 of its transmission lines meet both a wind speed threshold
and a congestion threshold. Transmission providers could, of course,
voluntarily implement the wind requirement on additional
transmission lines in any given year, but under this preliminary
proposal they would not be required to do so.
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116. For purposes of counting a transmission provider's total
number of transmission lines and determining the number of transmission
lines that would be subject to a wind requirement in a given year, we
preliminarily propose to define a single transmission line as the
transmission conductor that runs between its substation or switchyard
start and end points (e.g., dead-end structures). Other transmission
facilities and equipment, such as circuit breakers, line traps, and
transformers, would not count toward the transmission provider's total
number of transmission lines. We seek comment on whether we should
instead count the total number of transmission facilities based on the
number of pieces of individually rated Commission-jurisdictional
transmission equipment, as identified by the transmission provider and
included in the database of transmission line ratings.\150\ In other
words, the number of transmission lines would be approximated based on
the size of the transmission line ratings database developed for Order
No. 881 compliance for a given transmission provider.
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\150\ See Order No. 881, 177 FERC ] 61,179 at PP 330, 336-340.
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117. We seek comment on the preliminary proposal to require that
transmission providers implement the wind requirement, for any
transmission lines that meet the thresholds, on at least 0.25% of their
transmission lines in each annual cycle. We seek comment on
approximately how many jurisdictional transmission lines 0.25%
represents, and how many transmission lines the average transmission
provider operates. We seek comment on whether the Commission should
adopt a different initial annual percentage. Alternatively, should the
Commission consider a requirement for transmission providers, after a
few years of DLR experience, to review their pace of implementation? We
also seek comment on whether the Commission would need to adjust this
approach if it determines that sensors are not needed for the wind
requirement. We seek comment on whether we should consider alternative
approaches to limiting a transmission provider's annual implementation
requirements, such as limits based on the peak load on the transmission
provider's transmission system or other appropriate criteria or
metrics. We also seek comment on whether and how considerations such as
staffing, supply chains, vendor availability, and limited experience
with sensor technology for many transmission providers should factor
into any such annual limitation on implementation of the wind
requirement. We also seek comment on the appropriateness of
establishing a limit on the number of transmission lines subject to a
wind requirement.
ii. Wind Speed Threshold
118. We preliminarily propose to apply a wind requirement only to
transmission lines where at least 75% of the length of the transmission
line is located in areas with historical average wind speeds of at
least 3 meters per second (m/s) (6.7 miles per hour) measured at 10
meters above the ground, roughly the height of most transmission lines.
While we believe that requiring application of a wind speed threshold
over the entire length of the line could be too limiting, ultimately
excluding transmission lines where application of the wind requirement
would yield net benefits, we also believe that including too long of a
non-windy portions of the line will cause those segments to bind more
often and limit the additional capacity from the wind requirement.
Thus, we have proposed 75% of the line length located in areas with
wind as the threshold. In NOI comments, WATT/CEE suggests using a
similar wind speed threshold of 4 m/s.\151\ Based on outreach and
further research, however, we preliminarily propose a wind speed
threshold of 3 m/s, on average.\152\
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\151\ WATT/CEE Comments, Docket No. AD22-5, at 7 (filed Apr. 25,
2022).
\152\ See, e.g., Jake Gentle, et al., Forecasting for Dynamic
Line Ratings, Idaho National Laboratory presentation at FERC DLR
Workshop at slide 13 (Sept. 10, 2019), https://www.ferc.gov/sites/default/files/2020-09/Gentle-INL.pdf.
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119. We note that historical wind speed data are published in
graphical and raster format for the continental United States by the
National Renewable Energy Laboratory
[[Page 57707]]
(NREL),\153\ and we preliminarily propose that transmission providers
use this NREL data source as the basis for implementing the wind speed
threshold.
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\153\ NREL, Geospatial Data Science: Wind Resource Maps and
Data, https://www.nrel.gov/gis/wind-resource-maps.html.
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120. We seek comment on the proposed wind speed threshold of 3 m/s,
on average, including whether another wind speed would be a more
appropriate threshold. We also seek comment on the proposal to apply
the wind requirement only on transmission lines where at least 75% of
the transmission line length is located in areas with average wind
speeds at or above the threshold, including whether another approach to
applying the wind speed threshold would be more appropriate for
transmission lines located in areas both above and below the threshold.
Further, we seek comment on the preliminary proposal to require that
transmission providers use NREL data for historical wind speeds at 10
meters above the ground for purposes of evaluating whether a
transmission line is above or below the wind speed threshold, and
whether an alternative data source would be more appropriate.
121. Finally, we acknowledge that wind direction is another
important factor. Wind moving perpendicular to a transmission line
cools the line much more effectively than wind moving parallel to the
line. However, we preliminarily find that establishing a threshold that
includes an average historical wind direction would be much more
burdensome to calculate because it would require that the transmission
provider determine the wind direction relative to the position of each
transmission line. We seek comment on whether wind direction should
also be considered when identifying transmission lines subject to a
wind requirement, and if so, how such consideration should be
structured and what data sources should be used.
iii. Congestion Threshold
122. We preliminarily propose to use congestion caused by a
transmission line rating as a second threshold for identifying the
transmission lines that would be subject to a wind requirement. Below,
we discuss how to calculate a congestion value for each transmission
line in RTO/ISO regions and, separately, in non-RTO/ISO regions, and
how to establish a threshold to identify congested transmission lines
in each region. Transmission lines that have no congestion or
congestion levels below the proposed threshold would not be subject to
any wind requirement even if they meet the wind speed threshold
because, absent sufficient levels of congestion, we do not expect the
benefits resulting from a more accurate transmission line rating to
exceed the costs.
(a) RTO/ISO Regions
(1) Congestion Costs
123. We seek comment on the appropriate congestion cost threshold
to use in the RTO/ISO regions. In response to the NOI, some commenters
propose to directly use congestion costs to indicate which transmission
lines should be subject to a DLR requirement in RTO/ISO regions, and
even propose specific annual congestion cost thresholds. At the low end
of the range of suggestions, WATT/CEE and Clean Energy Parties
recommend requiring DLRs on any transmission line with congestion costs
of at least $500,000 over the past year.\154\ Citing the Midcontinent
Independent System Operator, Inc. transmission owners' cost estimate of
$100,000-$200,000 for DLR implementation per transmission line, WATT/
CEE argues that this threshold would allow customers to break even on
DLR installations within approximately two years.\155\ At the high end
of the range of suggestions, PJM recommends requiring DLRs on any
transmission line with annual congestion costs of at least $2
million.\156\
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\154\ Clean Energy Parties Comments, Docket No. AD22-5, at 8
(filed Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 6
(filed Apr. 25, 2022).
\155\ WATT/CEE Comments, Docket No. AD22-5, at 6 (filed Apr. 25,
2022).
\156\ PJM Comments, Docket No. AD22-5, at 9 (filed May 9, 2022).
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124. At this point, the Commission has a limited record on the best
approach for calculating congestion costs in RTOs/ISOs for purposes of
defining a congestion threshold for a wind requirement. As discussed
above in section II.D.2. Existing Data Reporting on Congestion, or
Proxies of Congestion, RTOs/ISOs regularly compute and publish various
congestion metrics, but these metrics generally relate to marginal
congestion costs rather than the total congestion costs caused by a
transmission constraint. Thus, we seek comment on what approaches to
calculating or estimating congestion costs caused by a transmission
constraint would be most appropriate to use as part of a congestion
threshold for a potential wind requirement in RTOs/ISOs. Relatedly, we
seek comment on whether congestion costs caused by a transmission
constraint should be determined based on the real-time markets, day-
ahead markets, or a combination of the two.
125. Further, we seek comment on what congestion threshold the
Commission should establish in RTO/ISO regions for a potential wind
requirement, recognizing that the appropriate level of the congestion
threshold could vary depending on the method used to calculate
congestion costs. For example, were the Commission to use an annual
congestion method as assumed by some commenters in response to the NOI,
we seek comment on the values proposed and approximately how many
transmission lines would meet the various thresholds. We note that
WATT/CEE proposed $500,000 per year,\157\ and PJM proposed $2 million
per year.\158\ Alternatively, as proposed by several commenters to the
NOI, a congestion threshold could be set so that only transmission
lines that have an average annual congestion cost of $1 million or more
during the data collection period, discussed below in section IV.B.3.
Phased-In Implementation Timeframe for the Wind Requirement, would be
subject to the wind requirement. We also seek comment on whether the
annual threshold should be annually adjusted for inflation; if so, how;
and whether that adjustment should vary based on the method used for
calculating congestion costs.
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\157\ WATT/CEE Comments, Docket No. AD22-5, at 6 (filed Apr. 25,
2022).
\158\ PJM Comments, Docket No. AD22-5, at 9 (filed May 9, 2022).
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126. We seek comment on how RTOs/ISOs should measure congestion
costs at interties and whether the same congestion threshold should be
used for both intertie and internal congestion costs measurements. We
also seek comment on how entities in non-RTO/ISO market constructs,
such as the Western Energy Imbalance Market, should measure congestion
costs at their interties.
127. Finally, we seek comment on whether a different congestion
threshold would be appropriate if it is determined that the wind
requirement does not require sensors. If the wind requirement can be
met without sensors, this may lower the costs necessary to comply with
the requirement. The lower costs may in turn provide more net benefits
at lower levels of congestion.
(b) Non-RTO/ISO Regions
(1) Limiting Element Rate
(i) Overview
128. In non-RTO/ISO regions, congestion costs are not reflected
separately as a component in market
[[Page 57708]]
prices and are not typically published in reports. Based on available
information (at least some of which is currently publicly reported in
some form,\159\ and some of which is available to transmission
providers but not currently published), we preliminarily propose a new
metric to serve as a proxy for congestion in these regions--a Limiting
Element Rate (LER). The LER metric would express, as an average rate
(in MWh/year), the adverse impacts on transmission service due to a
transmission line rating serving as a limiting element. Below we
discuss how a transmission provider would calculate the LER, including
data to be collected for certain ``triggering events,'' what LER metric
threshold would be appropriate to identify transmission lines that are
sufficiently congested to be subject to a wind requirement, and whether
there are alternatives measures of congestion to identify transmission
lines that should be subject to a wind requirement.
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\159\ For example, limiting element data are already required to
be made publicly available for certain constrained paths under Sec.
37.6(a)(2)(ii) of the Commission's regulations. 18 CFR
37.6(a)(2)(ii) (2023).
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(ii) Triggering Events
129. We preliminarily propose to require that transmission
providers record information for five types of triggering events where
firm transmission service is denied or disrupted because of a
transmission line's line rating. This information would provide the
basis to identify transmission lines that are subject to a wind
requirement.
130. In particular, the five events where firm transmission service
is denied or disrupted because of a transmission line's line rating
are: (1) denials of requested firm point-to-point transmission service;
(2) denials of requests to designate network resources or load; (3)
curtailment of firm point-to-point transmission service under section
13.6 of the pro forma OATT; (4) curtailment of network integration
transmission service or secondary network integration transmission
service under section 33 of the pro forma OATT; and/or (5) redispatch
of network integration transmission service or secondary network
integration transmission service under sections 30.5 and 33 of the pro
forma OATT.
131. While we preliminarily propose to reflect each hour of a firm
point-to-point transmission service reservation that is denied in the
calculation of LER, in practice transmission customers do not typically
schedule transmission service for every hour of their long-term
reservations. For example, a transmission customer requesting a 100 MW
reservation for annual transmission service may intend to use that
service only during select hours totaling only six months of that year.
Recognizing that fact, we seek comment on whether, for denials of
requested firm point-to-point transmission service, the number of hours
reflected in the LER calculations should reflect a discount from the
number of hours reflected in the actual request. If so, we seek comment
on what such discount factor(s) should be, and whether a specific
discount factor should apply to all such denied firm point-to-point
services, or if such a discount factor should vary by service type
(daily, weekly, monthly, or yearly) to reflect how different service
types might be scheduled at different rates.
132. We seek comment on whether it would be appropriate to include
a sixth triggering event as a proxy for congestion in the LER. This
event would account for times when ATC in the operating hour \160\ is
less than or equal to 25% of TTC.\161\ Such ``low ATC events'' would be
limited to events on paths that meet the definition of a ``posted
path'' under Sec. 37.6(b)(1)(i) of the Commission's regulations.
Accounting for low ATC events would be intended to capture instances
when such low ATC could dissuade potential transmission customers from
making a transmission service request in the first place. We seek
comment on whether, and to what extent, a transmission line's low
operating-hour ATC indicates congestion in any given hour, such that it
should reasonably be factored in as a proxy for congestion that may
trigger the wind requirement. We also seek comment on other triggering
events that the Commission should consider.
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\160\ Either the operating hour or the future hour closest to
the operating hour for which the transmission provider calculates
ATC, hereafter simply ``operating hour'' for conciseness.
\161\ This approach reflects that the Commission's regulations
already consider posted paths that have an ATC that is less than or
equal to 25% of TTC to be ``constrained.'' See 18 CFR
37.6(b)(1)(ii).
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(iii) Data To Be Collected and Reported
133. For any triggering event, we preliminarily propose to require
the transmission provider to record the: (1) date/time of the record
being added to its database of transmission line ratings; \162\ (2)
dates and times of the start and end of the event; \163\ (3) event
type; (4) specification of the transmission line with a transmission
line rating that was the limiting element causing the event; and (5)
MWh of transmission service (or potential transmission service) that
was impacted by the event.
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\162\ See infra P 156.
\163\ For denials or curtailments of service the date/time would
be the date/time for which the service was requested.
---------------------------------------------------------------------------
134. The details of how the transmission provider would determine
the impacted MWh vary by event type. For instances of denied firm
point-to-point service, the transmission provider would determine the
impacted MWh by multiplying the MW of the service requested by the
duration of the request in hours.\164\ If, instead of a complete denial
of requested point-to-point service, a lower level of interim service
is granted, then the MW value used in such a calculation would reflect
only the portion of the original requested service deferred or not
granted.\165\ For instances of curtailed or redispatched point-to-point
or network transmission service, the transmission provider would
determine the impacted MWh by multiplying the MW curtailed or
redispatched by the duration of the event in hours.\166\ If, in such an
instance, the MW curtailed or redispatched varies during the duration
of the curtailment or redispatch, then the transmission provider may
use an average MW value, or record the different hours or periods as
different events. We preliminarily propose that transmission providers
be required to reflect in such determinations any curtailments made as
part of conditional firm transmission service provided under section
15.4 of the pro forma OATT. Finally, for instances of denied requests
to designate new network resources or load without an end date, we
preliminarily propose to reflect that such designations are generally
long-term events by considering such denied requests to have a duration
of 180 days (4,320 hours).\167\ We seek comment on
[[Page 57709]]
the use of this assumed duration, or whether a different assumed
duration or another approach would result in a better consideration of
the congestion reflected in denials of requests to designate network
resources or load.
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\164\ For example, if a request for 100 MW of three weeks of
weekly firm point-to-point transmission service were denied, the MWh
impacted would be determined as (100 MW) * (3 weeks) * (7 days/week)
* (24 hours/day) = 50,400 MWh.
\165\ For example, if in the proceeding example 75 of the
requested 100 MW were ultimately granted, then the MWh impacted
would be determined as (25 MW) * (3 weeks) * (7 days/week) * (24
hours/day) = 12,600 MWh.
\166\ For example, if a transmission provider curtailed an
instance of transmission service by 25 MW for a period of 2 hours,
then the impacted MWh would be determined as (25 MW) * (2 hours) =
50 MWh. Similarly, if a transmission provider redispatched down one
if its network customer's network resources by 75 MW for 2 hours,
then the impacted MWh would be determined as (75 MW) * (2 hours) =
150 MWh.
\167\ For example, if a request to designate a network resource
with a capacity of 500 MW is denied, then the impacted MWh would be
determined as (500 MW) * (4,320 hours) = 2,160,000 MWh.
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(iv) LER Threshold
135. We seek comment on what LER metric threshold would be
appropriate to identify transmission lines that are sufficiently
congested to be subject to a wind requirement, along with an estimate
of how many transmission lines would meet any discussed threshold. As
proposed above, the LER measurement that will be compared to such a
threshold would be measured in impacted MWh. One potential approach is
to attempt to identify an LER threshold that would be the rough
equivalent of any congestion cost threshold that we might ultimately
adopt for RTO/ISO regions (discussed above), given an assumed cost of
impacted MWh. For example, if one assumes a cost of an impacted MWh of
$100, then an LER threshold that would be the rough equivalent of a $1
million RTO/ISO congestion cost threshold would be calculated as
($1,000,000)/($100/MWh) = 10,000 MWh. However, this would only be a
rough equivalence because what is measured by LER and the congestion
cost that we propose to be measured for RTO/ISO regions are not
reflective of the exact same events, and any assumption for the cost of
an impacted MWh will necessarily need to be some estimate of the
average cost of such MWh. Another potential approach is to use hourly
systemwide incremental costs, which are already required to be used for
both energy imbalances under Schedule 4 and generator imbalances under
Schedule 9 of the pro forma OATT, to calculate an estimated cost of
impacted MWh.\168\ We seek comment on the costs that transmission
providers include in hourly energy or generator imbalance charges, in
particular whether these charges reflect only the energy component or a
full redispatch cost, including congestion and production costs.
Finally, we seek comment on whether using a different value, or another
approach altogether, to identify transmission lines that should be
subject to a potential wind requirement would be appropriate.
---------------------------------------------------------------------------
\168\ See Pro forma OATT, Schedule 4 Energy Imbalance Service.
``The Transmission Provider may charge a Transmission Customer a
penalty for either hourly energy imbalances under this Schedule [4]
or a penalty for hourly generator imbalances under Schedule 9 for
imbalances occurring during the same hour, but not both unless the
imbalances aggravate rather than offset each other.'' Id.
---------------------------------------------------------------------------
(2) Potential Alternatives for Comment
136. We seek comment on alternatives to our preliminary proposal of
using LER as a proxy for congestion in non-RTO/ISO regions. In
particular, we seek comment on the possibility of using information
that is currently non-public, such as redispatch costs, to measure
actual congestion costs that are incurred in non-RTO/ISO regions.
(i) Non-RTO/ISO Congestion Costs
137. As an alternative to the LER metric, we seek comment on
whether non-RTO/ISO regions could measure congestion costs to identify
candidate transmission lines for a potential wind requirement. Under
section 33.2 of the pro forma OATT, a transmission provider must
perform redispatch of resources on a least-cost basis, without
consideration of whether a resource is owned by the transmission
provider or a network customer.\169\ Based on this requirement, we
believe that transmission providers consider redispatch costs for both
network resources and their own resources serving their native load,
although the information on such costs may currently be non-public.
Such congestion costs could be measured within non-RTO/ISO regions for
the purpose of identifying transmission lines that would benefit the
most from a potential wind requirement. Because we believe such costs
are formally tracked and associated with the limiting transmission line
ratings necessitating each instance of redispatch, it should be
possible to attribute redispatch costs to the particular transmission
line whose transmission line ratings are causing such costs. We seek
comment on using redispatch costs to measure congestion costs and to
what extent this approach would be preferable to the LER approach. We
seek comment on measuring congestion costs at intertie locations and
whether redispatch costs could be used to identify interties that would
benefit the most from a potential wind requirement.
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\169\ Pro forma OATT, section 33.2 (Transmission Constraints).
---------------------------------------------------------------------------
138. We also seek comment on whether measuring congestion costs in
non-RTO/ISO regions should be used in conjunction with an approach like
the LER approach (i.e., congested transmission lines would be
identified through some combination of how much redispatch cost their
transmission line ratings cause and how many MWh are impacted by
denials, disruptions, etc.).\170\ If using a combined approach, we seek
comment on how these components should be used together, e.g., how much
weight each measure of congestion is given, to develop an overall
indicator of how congested a transmission line in a non-RTO/ISO region
is.
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\170\ We preliminarily assume, if a redispatch cost approach
were used in conjunction with an LER approach, that the LER would be
modified to (at a minimum) exclude consideration of the impacted MWh
from redispatch of network resources, given that such events would
already be reflected in terms of their redispatch cost.
---------------------------------------------------------------------------
139. Finally, we seek comment on additional methods for calculating
congestion costs both within non-RTO/ISO regions and at interties
connecting with non-RTO/ISO regions. For instance, average hourly
incremental/decremental cost (that transmission providers are required
to use under pro forma OATT Schedules 4 and 9 in the calculation of
hourly imbalances charges discussed above) or electricity hub prices
could be used to estimate congestion costs.
c. Self-Exceptions From the Wind Requirement
i. Self-Exception Categories
140. We preliminarily propose to allow transmission providers to
self-except a transmission line from the wind requirement if it
determines, consistent with good utility practice: (1) that the
transmission line rating is not affected by wind conditions; or (2)
that implementing the wind requirement on such a transmission line
would not produce net benefits. These self-exceptions recognize that
there may be instances where the congestion threshold and wind speed
threshold criteria identify transmission lines that would nonetheless
not be good candidates for implementation of a wind requirement. For
example, certain transmission lines that might not benefit from the
wind requirement, such as a partially underground transmission line
where the cable is the limiting element, may nonetheless trigger the
proposed criteria. As another example, applying the wind requirement to
a particular transmission line may only relieve thermal constraints
slightly before a voltage or stability constraint bind, resulting in
little value for the cost of implementing the wind requirement.
141. Under either self-exception category, a transmission provider
would log the self-exception and justification in its transmission line
rating database (as outlined below). This proposal is supported by NOI
comments that argue a wind requirement should provide exceptions for
cost, reliability, and other negative impacts, and assert that the
[[Page 57710]]
cost exception should require a showing by the transmission
provider.\171\
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\171\ ELCON Comments, Docket No. AD22-5, at 8-9 (filed Apr. 25,
2022); R Street Institute Comments, Docket No. AD22-5, at 5-6 (filed
Apr. 26, 2022).
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142. We seek comment on the concept of allowing a transmission
provider to self-except transmission lines from the wind requirement.
143. The first self-exception category--that the transmission line
rating is not affected by wind speed--is similar to the exception to
the AAR requirement established by Order No. 881 and set forth in
Attachment M of the pro forma OATT that permits transmission providers
to use a transmission line rating that is not an AAR where the
transmission line is not affected by ambient air temperature or solar
heating.\172\ We expect that the same (or largely the same)
transmission lines that are excepted from Order No. 881's requirement
to implement AARs or seasonal line ratings (because the transmission
line is not affected by ambient air temperature) would be eligible for
exception from the wind requirement under the first self-exception
category. We seek comment on whether there are transmission lines whose
transmission line ratings would not be affected by wind speed and
whether the first self-exception category is appropriate in such cases.
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\172\ See Order No. 881, 177 FERC ] 61,179 at P 227; see supra P
84 (discussing the self-exception that would apply to the proposed
requirement to include solar heating in transmission line ratings).
---------------------------------------------------------------------------
144. To implement the second self-exception category, we
preliminarily propose that transmission providers conduct a net benefit
analysis that sums all of the anticipated benefits attributable to the
implementation of the wind requirement on the relevant line and,
similarly, sums all of the costs attributable to the wind requirement
on the relevant line. If the benefits do not exceed the costs, then a
transmission provider may self-except the transmission line. Examples
of benefits that could be considered in a net benefit analysis include:
production cost savings (including increased transmission capacity,
reduced congestion costs, reduced dispatch costs, and other related
factors), and deferred costs of new transmission lines. Examples of
costs in a net benefit analysis include: the installation of sensors,
as well as the communications equipment or other costs attributable to
implementing the wind requirement at the specified location or on the
specified transmission lines. We preliminarily propose that
transmission providers would not include, in the net benefit analysis,
costs that they must incur to implement DLRs generally, i.e., for
communication equipment needed for enterprise-wide DLR implementation,
computer hardware and software, EMS, physical security, and
cybersecurity protections. We seek comment on the net benefit analysis
proposal, including the potential benefits and costs to include in the
analysis; whether there are costs or benefits that should not be
included in a net benefits analysis; whether the Commission should
specify which costs and benefits can or should be included in a net
benefits analysis; whether such determinations should be left to the
transmission providers' discretion; and whether transmission providers
should be required to specify in their tariffs which costs and benefits
can or must be included in a net benefits analysis. We also seek
comment on whether benefits attributable to a wind requirement and used
in a net benefits analysis should be limited to a particular time
horizon, such as 10 years; or how transmission providers should
attribute costs, including whether treatments such as amortization or
depreciation would be appropriate, for purposes of the net benefits
analysis, and the relevant time horizon.
145. We also preliminarily propose that a transmission provider
that makes a self-exception finding must document, in its database of
transmission line ratings and transmission line rating methodologies on
OASIS or another website with authentication control including multi-
factor authentication,\173\ any exceptions to the wind requirement,
including the nature of and basis for each exception, the date(s) and
time(s) that the exception was initiated, and (if applicable)
documentation of the net benefit analysis calculation, methodology, and
assumptions. We seek comment on this approach to justifying and
documenting self-exceptions.
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\173\ While prior Commission orders, including Order No. 881,
have references to ``password-protected websites'' instead of
website(s) with authentication control, NAESB standards that
incorporate NIST standards require utilities to use authentication
control, including multi-factor authentication, on their OASIS
websites or any alternative websites. See National Institute of
Standards and Technology, NIST Special Publication 800-63B (Oct.
2023), https://pages.nist.gov/800-63-3/sp800-63b.html; North
American Energy Standards Board, Standards for Business Practices
and Communication Protocols for Public Utilities 5 (Mar. 2020),
https://www.naesb.org/pdf4/naesb_033020_weq_version_003.3_report.pdf
(``In response, the subcommittees revised WEQ-002-5 to require
transmission providers or the agent to whom a transmission provider
has delegated the responsibility of meeting any requirements
associated with OASIS, referred to as a Transmission Services
Information Provider (`TSIP'), to apply industry-recognized best
practices in the implementation and maintenance of OASIS nodes and
supporting infrastructure. Included in these modifications is a
requirement that TSIPs must implement guidelines for user passwords
and authentication aligned with NIST SP 800-63B.''). As such, we
believe that this text does not impose any new requirements on
utilities. The Commission has adopted these NAESB standards. See
Standards for Bus. Pracs. & Communication Protocols for Pub. Utils.,
Order No. 676-J, 86 FR 29491 (June 2, 2021), 175 FERC ] 61,139
(2021).
---------------------------------------------------------------------------
146. Under this preliminary proposal, a transmission provider would
not be required to implement the wind requirement on a specific
transmission line if it takes a self-exception for that particular
transmission line, but a self-exception would not reduce the
transmission provider's overall implementation burden with respect to
the wind requirement that year. A transmission provider would still be
required to implement the wind requirement on its next most congested
transmission line, unless no further transmission lines met the
criteria for the wind requirement that year.
147. Furthermore, under our preliminary proposal, a transmission
provider would be required to reevaluate and log any exceptions taken
every year during the annual wind requirement implementation cycles for
the wind requirement as discussed in the IV.B. Compliance and
Transition and Implementation Timelines section. In some instances,
this proposal may merely require a review of the inputs and assumptions
to the original self-exception analysis, to verify that they have not
changed. In other instances, if such inputs and assumptions have
changed, then analyses would need to be updated. If the technical basis
for an exception is found to no longer apply, the transmission provider
would be required to update the relevant transmission line rating(s) in
a timely manner. We seek comment on this proposal for annual re-
evaluations of self-exceptions, including whether another timeframe is
more appropriate. We seek comment on the information that should be
included in the transmission line rating log to justify a self-
exception under either self-exception finding.
148. We note that Order No. 881 and the System Reliability section
of the pro forma OATT Attachment M provides for the temporary use of a
transmission line rating different than would otherwise be required if
such rating is determined to be necessary to ensure the safety and
reliability of the transmission system.\174\ Under this preliminary
proposal, we would maintain that System Reliability provision in
Attachment M, which would similarly apply to any
[[Page 57711]]
transmission lines to which the wind requirement would otherwise apply.
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\174\ Order No. 881, 177 FERC ] 61,179 at P 232; pro forma OATT,
attach. M (System Reliability).
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ii. Challenges to Self-Exceptions
149. We propose to allow any person that disagrees with a
transmission provider's self-exception to challenge that self-exception
by filing a complaint with the Commission under FPA section 206.
Examples of potential complaints concerning a transmission provider's
self-exceptions could include that a transmission provider improperly
claimed that the transmission line is not affected by wind speed, or
that a transmission provider made a faulty demonstration that the
transmission line ratings subject to wind requirement would not produce
net benefits on the transmission line, such as through improper
calculations of costs or benefits. The Commission could also institute
an investigation under FPA section 206 on its own motion to examine any
self-exception. We seek comment on whether there should be another
means to challenge a self-exception.
d. Transmission Lines Formerly Subject to the Wind Requirement
150. In cases when a transmission provider determines that a
transmission line subject to a wind requirement no longer exceeds the
thresholds for high levels of congestion and wind speed, we
preliminarily propose that the wind requirement no longer apply to the
transmission line and that transmission providers will no longer be
required to include wind conditions when calculating the transmission
line rating. For example, the transmission provider would be permitted,
inter alia, to decommission the sensors if any, on that transmission
line. Similarly, if a transmission provider determines that a
transmission line previously subject to a wind requirement is no longer
expected to produce net benefits, then we preliminarily propose that
the wind requirement no longer apply to the transmission line and that
the transmission provider will no longer be required to include wind
measurements when calculating the transmission line rating and the
transmission provider would be permitted to decommission any sensors on
that transmission line. We further preliminarily propose that, when
calculating the net benefits of a wind requirement to determine if a
particular transmission line should be subject to the wind requirement
sunk costs, such as past installations of sensors, should not be
included. Under the preliminary proposal, such transmission providers
would be required to document their decision to stop applying the wind
requirement and to decommission any sensors and provide a
justification. Similar to the proposed self-exception process,
transmission providers would log such decision, including the nature of
and basis for each decommissioning, the date(s) and time(s) that the
decommissioning was initiated, and (if applicable) documentation of the
net benefit analysis calculation, methodology, and assumptions in their
database of transmission line ratings and transmission line rating
methodologies on OASIS or another website with authentication control
including multi-factor authentication at least one year prior to the
decommissioning. A justification could be, for example, that a
transmission line no longer meets the congestion or wind speed
thresholds or that the wind requirement no longer provides net benefits
on a transmission line. Such justifications for removing the wind
requirement would be subject to the same opportunities to be challenged
pursuant to FPA section 206 discussed above for the self-exception
process. Also, a goal of applying DLRs, including the wind requirement,
to a transmission line is to reduce congestion. It stands to reason
that a transmission line that is subject to the wind requirement may
experience less congestion because of the wind requirement, such that
it no longer meets the congestion threshold. In such cases, it may be
counterintuitive to remove the wind requirement. As such, we
preliminarily propose that any decision to remove the wind requirement
from a transmission line must examine and compare the congestion with
the wind requirement in place against the estimated congestion if the
wind requirement were not in place. We seek comment on this preliminary
proposal for a decommissioning process. Further, we seek comment on the
costs and other burdens associated with decommissioning DLR equipment.
We also seek comment on whether the threshold criteria should be
required to no longer be met for a longer period of time (e.g., 5
years) before decommissioning is allowed.
e. Potential Transparency Reforms and Request for Comment
151. We preliminarily propose new transparency reforms, including
requirements to enhance data reporting practices related to congestion
in non-RTO/ISO regions to identify candidate transmission lines for a
wind requirement, and posting and retention of congestion data in both
RTO/ISO and non-RTO/ISO regions. The proposed reforms will provide
transparency into the transmission providers' identification of
transmission lines that would be subject to the wind requirement and
enable the Commission and stakeholders to verify the transmission
providers' analysis. Order No. 881 already requires a database of
transmission line ratings and methodologies to be posted.\175\ This
posting requirement would extend to transmission line ratings on
transmission lines subject to the solar and wind requirements as well.
---------------------------------------------------------------------------
\175\ See Order No. 881, 177 FERC ] 61,179 at PP 330, 336-340.
The transmission provider must post the information on the password-
protected section (or section subject to authentication control
including multi-factor authentication) of its OASIS site or on
another website with authentication control including multi-factor
authentication. Id. P 336; see supra n.200.
---------------------------------------------------------------------------
152. Some commenters in the NOI proceeding support adopting the
same transparency measures for transmission lines subject to a wind
requirement as the Commission adopted in Order No. 881.\176\ In
addition, some commenters support going further and requiring the
filing and posting of informational reports on which transmission lines
meet the Commission's wind requirement criteria, as well as the
transmission line ratings and methodologies used for implementation of
the wind requirement.\177\
---------------------------------------------------------------------------
\176\ DC Energy Comments, Docket No. AD22-5, at 4 (filed Apr.
25, 2022); LADWP Comments, Docket No. AD22-5, at 4-5 (filed Apr. 25,
2022); PJM Comments, Docket No. AD22-5, at 6-7 (filed May 9, 2022);
TAPS Comments, Docket No. AD22-5, at 8 (filed Apr. 25, 2022).
\177\ DC Energy Comments, Docket No. AD22-5, at 5 (filed Apr.
25, 2022); ELCON Comments, Docket No. AD22-5, at 2, 8-9, 11 (filed
Apr. 25, 2022); LADWP Comments, Docket No. AD22-5, at 4-5 (filed
Apr. 25, 2022); R Street Institute Comments, Docket No. AD22-5, at 9
(filed Apr. 26, 2022); TAPS Comments, Docket No. AD22-5, at 7 (filed
Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 9 (filed
Apr. 25, 2022).
---------------------------------------------------------------------------
153. As noted in section III. The Potential Need for Reform above,
we preliminarily find that existing transmission line ratings and
transmission line rating methodologies may result in unjust and
unreasonable wholesale rates that result from inaccurate transmission
line ratings. In addition to the preliminarily proposed reforms
described above, we make a concomitant preliminary finding that certain
transparency reforms are necessary to implement the preliminary
proposal. In addition to the requests for comments on specific aspects
of the preliminary proposal, we seek comment on whether the proposed
data reporting practices related to congestion in non-RTO/ISO regions
that would identify transmission lines that are candidates for a wind
requirement and the posting
[[Page 57712]]
of underlying congestion data, as set forth below, would result in just
and reasonable rates.
i. Potential Reforms to Congestion Data Collection
154. As preliminarily proposed above in section IV.A.3.b.iii.b.1.
Limiting Element Rate, transmission providers would be required to
maintain a database of the following events: (1) denials of requested
firm point-to-point transmission service; (2) denials of requests to
designate network resources or load; (3) curtailment of firm point-to-
point transmission service under section 13.6 of the pro forma OATT;
(4) curtailment of network integration transmission service or
secondary network integration transmission service under section 33 of
the pro forma OATT; and (5) redispatch of network integration
transmission service or secondary network integration transmission
service under sections 30.5 and 33 of the pro forma OATT. Specifically,
as preliminarily proposed above, transmission providers would be
required to record for each event: (1) date/time of the record being
added to the database; (2) dates and times of the start and end of the
event; (3) event type; (4) specification of the transmission line with
a transmission line rating that was the limiting element causing the
event; and (5) the MWh of transmission service (or potential
transmission service) that was impacted by the event. We seek comment
on this preliminary proposal to require transmission providers to
record this LER metric data, including the changes in data collection
practices it would cause, and the associated burden. We seek comment on
whether data identifying limiting transmission lines during all the
periods of congestion listed above already exist, and whether the above
descriptions of those events (duration, energy impacted, etc.) are
being recorded by transmission providers and/or posted in OASIS
currently. We also seek comment on the challenges in data collection
practices and associated burden required to record the alternative
methods to estimate congestion costs in non-RTO/ISO regions and at non-
RTO/ISO seams discussed above in section IV.A.3.b.iii.b.2.i Non-RTO/ISO
Congestion Costs such as recording redispatch costs caused with a given
transmission constraint.
155. As discussed below in section IV.4. Requirements for
Reflecting Solar and/or Wind in Transmission Line Ratings in RTOs/ISOs,
we preliminarily propose that RTOs/ISOs would use the LER metric only
for congestion at their seams, and not on the internal transmission
lines for which they have explicit congestion data. However, we also
preliminarily propose to require that transmission providers in RTOs/
ISOs maintain data on annual overall congestion costs caused by binding
constraints on each transmission line. Finally, we also seek comment on
whether any changes or additional data requirements would be needed to
track congestion costs, or causes of congestion costs, in RTO/ISO
regions.
ii. Posting of Congestion Data
156. Similar to the Commission's determination in Order No. 881, we
preliminarily propose to require transmission providers to post on
OASIS or another website with authentication control including multi-
factor authentication the new congestion databases associated with this
rulemaking, such as an LER metric database, with a data retention
requirement of at least five years. We preliminarily find that, without
further transparency, the Commission and market participants would not
have the information needed to determine the transmission lines on
which transmission providers in non-RTO/ISO regions are required to
implement the wind requirement.
157. We seek comment on this congestion data transparency proposal,
including whether the congestion data proposed to be recorded in the
congestion databases or other elements should be posted on OASIS or
another website with authentication control including multi-factor
authentication. We also seek comment on posting on OASIS or another
website with authentication control including multi-factor
authentication the data associated with the alternative methods to
estimate congestion costs in non-RTO/ISO regions and at seams with non-
RTO/ISO regions discussed above in section IV.A.3.b.iii.b.2.i Non-RTO/
ISO Congestion Costs such as recording redispatch costs caused by a
given transmission constraint. We also seek comment on whether posting
of additional congestion cost data, beyond the overall congestion costs
caused by binding constraints on each transmission line, should be
required in RTO/ISO regions. We seek comment on whether a different
data posting, access restrictions, and data retention requirement is
appropriate.
iii. Posting of Transmission Line Ratings Subject to a Wind Requirement
158. In Order No. 881, the Commission required the maintenance and
posting of all transmission line ratings in a line rating
database.\178\ That requirement would apply to any transmission line
ratings under a potential final rule in this proceeding as well.\179\
---------------------------------------------------------------------------
\178\ Order No. 881, 177 FERC ] 61,179 at PP 330, 336; see pro
forma OATT, attach. M (Obligations of Transmission Provider).
\179\ See pro forma OATT, attach. M, Obligations of Transmission
Provider; see also Order No. 881, 177 FERC ] 61,179 at PP 330, 336-
340.
---------------------------------------------------------------------------
159. However, given the unique circumstances surrounding a
potential wind requirement, including the need to be able to evaluate
the effectiveness of such a requirement, we preliminarily propose that,
for transmission lines subject to a wind requirement, the transmission
provider would be required to post the transmission line ratings for
each period calculated both with and without the consideration of
forecasted wind conditions. We preliminarily believe that the posting
of both transmission line ratings for the periods in which the wind
requirement applies would provide the transparency necessary to
evaluate the effectiveness of implementing the wind requirement on each
transmission line subject to the wind requirement. We seek comment on
this proposed posting requirement.
4. Requirements for Reflecting Solar and/or Wind in Transmission Line
Ratings in RTOs/ISOs
160. In Order No. 881, the Commission required AARs to be used (1)
in the day-ahead and real-time energy markets, (2) in any reliability
or intra-day reliability unit commitment processes, and (3) for
transmission service over RTO/ISO seams.\180\ The Commission declined
to apply the AAR requirement to the evaluation of internal point-to-
point or through-and-out transactions.\181\ The Commission explained
that the vast majority of energy transactions in RTOs/ISOs are executed
and financially settled in the day-ahead and real-time markets, and
thus requiring AARs to be used for internal point-to-point and through-
and-out transactions would provide very little additional benefits in
the RTO/ISO markets.\182\
---------------------------------------------------------------------------
\180\ Order No. 881, 177 FERC ] 61,179 at P 89.
\181\ Id. P 134.
\182\ Id.
---------------------------------------------------------------------------
161. For the solar requirement, which we propose to apply to all
transmission lines, we preliminarily propose that RTOs/ISOs use
transmission line ratings that reflect solar heating based on the sun's
position and forecastable cloud cover in their day-ahead and real-time
markets as well as for seams transactions that are near-term
transmission service (i.e., that start and
[[Page 57713]]
stop within the next 10 days). We do not propose to require RTOs/ISOs
to use such transmission line ratings for internal point-to-point
transmission service or through-and-out service.
162. For the wind requirement, which we propose to apply only to
select transmission lines, we preliminarily propose a different
approach. Specifically, we preliminarily propose that RTOs/ISOs comply
with the wind requirement \183\ by using transmission line ratings that
reflect up-to-date forecasts of wind speed and wind direction: (1) in
their day-ahead and real-time markets; and (2) for seams transactions,
internal point-to-point transmission service, and for through-and-out
service that are 48-hour transmission services (i.e., that start and
end within 48 hours of the request). We preliminarily propose this
broader requirement for these transmission lines because we
preliminarily believe that the additional accuracy of using the
transmission line ratings that incorporate the wind requirement on
highly congested transmission lines may justify the burden.
---------------------------------------------------------------------------
\183\ Transmission lines subject to the wind requirement are
also subject to the solar requirement, as described above in section
IV.A.3 Potential Wind Requirement.
---------------------------------------------------------------------------
163. We seek comment on these preliminary proposals for applying
the proposed solar and wind requirements to transmission line ratings
in RTOs/ISOs. In particular, we seek comment on whether RTOs/ISOs
should instead not be required to apply the wind requirement for
internal point-to-point and through-and-out transactions, consistent
with the AAR requirements of Order No. 881 and the instant proposal for
the potential solar requirement.
5. Implications for Emergency Ratings
164. In Order No. 881, the Commission required that transmission
providers use uniquely determined emergency ratings for contingency
analysis in the operations horizon and in post-contingency simulation
of constraints. The Commission also required that such emergency
ratings include separate AAR calculations for each emergency rating
duration used.\184\
---------------------------------------------------------------------------
\184\ Id. P 297; pro forma OATT, attach. M, Obligations of
Transmission Provider.
---------------------------------------------------------------------------
165. We preliminarily propose to require that all uniquely
determined emergency ratings used for contingency analysis in the
operations horizon and in post-contingency simulation of constraints
must reflect solar heating based on the sun's position and up-to-date
forecasts of forecastable cloud cover. We preliminarily find that
applying the solar requirement to both normal and emergency ratings
will enhance the accuracy of transmission line ratings. We seek comment
on this proposed approach.
166. In addition, for transmission lines subject to a wind
requirement, we preliminarily propose to require that all uniquely
determined emergency ratings used for contingency analysis in the
operations horizon and in post-contingency simulation of constraints
must reflect up-to-date forecasts of wind speed and direction,
consistent with the wind requirement for normal ratings. We
preliminarily find that, for transmission lines that will be subject to
a wind requirement, reflecting wind conditions in both normal and
emergency ratings will enhance the accuracy of transmission line
ratings. We seek comment on this proposed approach.
6. Confidence Levels
167. In statistical forecasting, ``quantile forecasting'' is the
practice of forecasting upper or lower limits of a particular future
observation.\185\ Quantile forecasting is the type of forecasting
typically involved with determining transmission line ratings:
forecasters seek to predict the extreme values (upper or lower,
depending on the variable) of weather variables that serve as inputs
into transmission line rating calculations, and to calculate
sufficiently conservative transmission line ratings from those
forecasts. In quantile forecasting, a ``confidence level'' reflects how
much certainty forecasters have that a particular observation will not
exceed their forecast when the observation is repeated many times. For
example, if each day a meteorologist publishes a forecast of next-day
high temperatures, and the method for producing such forecast is
designed to meet a 98% confidence level, then over time the
corresponding observed high temperatures should be less than or equal
to such forecasts 98% of the time.
---------------------------------------------------------------------------
\185\ See, e.g., Electric Power Systems: Advanced Forecasting
Techniques and Optimal Generation Scheduling, section 5 at 20
(Jo[atilde]o P.S. Catal[atilde]o ed., 2017).
---------------------------------------------------------------------------
168. We understand that line ratings always have an associated
confidence level. Because such confidence levels are typically
relatively high, such as 98%, in most instances the forecasted
transmission line ratings are conservative, such that the observed
weather (when that forecasted hour becomes the operating hour) is
within the range predicted by the forecast. However, infrequently, as
the forecast for a given hour is updated it could cause a transmission
provider to have to manage (through curtailments or other actions) a
reduction in transmission capability from what had been previously
forecasted.
169. The Commission's outreach and research indicate that it is
commonplace for DLRs to be calculated to a default confidence of 98%.
We preliminarily believe that there may be some benefit to having a
default confidence level for calculations of transmission line ratings
subject to the solar and/or wind requirement across regions: first, to
discourage the use of overly conservative confidence levels, which will
erode the benefits of using weather forecasts; \186\ and second, to
ensure that sharply differing practices do not produce sharply
different transmission line ratings.
---------------------------------------------------------------------------
\186\ In Order No. 881 the Commission acknowledged that
``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.'' Order No. 881, 177 FERC ] 61,179 at P 52.
---------------------------------------------------------------------------
170. Given the importance of confidence levels to transmission line
ratings accuracy and reliability, we seek comment on whether the
Commission should establish a default confidence level transmission
providers are required to use when calculating transmission line
ratings subject to the solar and/or wind requirement, unless they
document a particular reason for needing and using a different
confidence level. If so, we seek comment on what such a default
confidence level should be, and how the use of confidence levels
different from the default should be documented by transmission
providers to justify such deviations.
171. If such a default confidence level were adopted, we
preliminarily propose that it apply not to the underlying weather
forecasts (wind speed, wind direction, ambient air temperature, solar
heating, etc.) individually, but instead to the forecast of the
transmission line rating overall. We preliminarily believe that
applying the default confidence level to the underlying weather
forecasts would result in a confidence level for the overall forecasted
transmission line rating that is less than the default level. We seek
comment on this proposal to apply any default confidence level to
overall transmission line rating forecasts. We seek comment on what
confidence levels are currently typically applied to different types of
transmission line ratings.
[[Page 57714]]
B. Compliance and Transition and Implementation Timelines
1. Pro Forma OATT Revisions and Implementation
172. We preliminarily propose to promulgate these potential reforms
through revisions to the pro forma OATT, which is applicable to all
transmission providers. We seek comment on this proposal including
whether such requirements should be reflected in Attachment M of the
pro forma OATT or elsewhere. Commenters are invited to propose pro
forma OATT language, including proposed revisions to existing pro forma
OATT language, and to explain why such language would be appropriate.
173. While the requirements we preliminarily propose here would be
imposed on transmission providers, we recognize as we did in Order No.
881 that transmission owners determine transmission line ratings.\187\
In many instances, particularly outside of RTOs/ISOs, the transmission
provider and transmission owner are the same entity. However, within
RTOs/ISOs and in limited other instances, the transmission provider and
transmission owner are separate entities. For such instances, we
preliminarily propose that the limit for how many transmission lines
must apply the wind requirement, for any transmission lines that meet
the thresholds, (i.e., the proposed 0.25% of the total number of the
transmission providers' transmission lines for the initial period)
apply to each individual transmission owner and not to the transmission
provider on an RTO-wide basis.\188\ We also preliminarily propose that
transmission owners will determine transmission line ratings for all of
their transmission lines. We also propose to require transmission
owners to provide their transmission line ratings and transmission line
rating methodology to the transmission provider. We seek comment on
this aspect of the preliminary proposal, including which
responsibilities would or should be carried out by transmission
providers and transmission owners, whether such roles and
responsibilities should be set forth in pro forma OATT provisions or
left to RTO/ISO compliance proceedings, and how transmission providers
should ensure that transmission owners appropriately perform their
responsibilities.
---------------------------------------------------------------------------
\187\ See Order No. 881, 177 FERC ] 61,179 at P 140; see also
id. P 300 (requiring transmission providers, where the transmission
provider is not the transmission owner, to include in its compliance
filing and implementation of pro forma Attachment M, that the
transmission owner has the obligation for making and communicating
to the transmission provider the timely calculations and
determinations related to emergency ratings).
\188\ For example, if an RTO has four transmission owners, each
with 1,600 transmission lines, each transmission owner would be
required to implement DLRs on at least four transmission lines per
year (provided that at least that many transmission lines meet the
criteria discussed above). The potential requirement would not be
implemented by the RTO transmission provider on 16 transmission
lines on an RTO-wide basis.
---------------------------------------------------------------------------
2. Implementation Timeframe for the Solar Requirement
174. Recognizing that the proposed solar requirement may not
require installing sensors, we preliminarily propose that this
requirement be met no more than twelve months after any final rule is
published in the Federal Register. We seek comment on the timeframe
necessary to implement the proposed solar requirement. We seek comment
on whether the clear-sky component and cloud cover component of a
proposed solar requirement should have different implementation
deadlines.
3. Phased-In Implementation Timeframe for the Wind Requirement
a. Annual Wind Requirement Implementation Cycles
175. We preliminarily propose to require transmission providers to
undertake an annual wind requirement implementation cycle. Starting
with the effective date of any potential final rule, transmission
providers would gather congestion data for each transmission line for
one year, as described above in section IV.A.3.b.iii. Congestion
Threshold, and determine during that year which of their transmission
lines meet the wind speed threshold, as described above in section
IV.A.3.b.ii. Wind Speed Threshold. Finally, for any transmission lines
that meet the determined wind speed and congestion thresholds,
transmission providers would have six months to implement the necessary
systems, based on the minimum implementation requirement as described
above in section IV.A.3.b.i. Number of Transmission Lines Subject to
the Wind Requirement Annually, to implement the wind requirement. This
proposal aims to provide ample time for transmission providers to use
congestion data that reflect implementation of AARs as required by
Order No. 881, while also ensuring that a wind requirement is applied
to transmission lines that would benefit from a wind requirement within
a reasonable timeframe. We seek comment on this proposed approach. We
specifically seek comment on the duration of the data collection
period, and implementation period. While we believe one year of
congestion data will be sufficient for the first implementation cycle,
we seek comment on whether this is the appropriate time period for data
collection and whether the Commission should mandate a different
timeframe for subsequent cycles (e.g., for cycle two, whether
transmission providers should consider two years of congestion data).
We also seek comment on whether the Commission should set a limit on
the vintage of the congestion data (i.e., whether congestion data from
five years ago is stale and no longer relevant). We also seek comment
on how this approach should change if the Commission does not require
sensors for the wind requirement.
176. Most commenters argue that the Commission should not require
implementation of any DLR requirements until after transmission
providers have implemented AARs in July 2025 and gained experience with
the use of AARs.\189\ While not explicitly tied to Order No. 881, the
preliminary proposal, if adopted in a final rule, is intended to
reflect the importance of having adequate data for the purpose of
identifying transmission lines where the wind requirement would be
implemented, particularly in light of the likely changing congestion
patterns after the implementation of Order No. 881. The Commission
seeks comment on when implementation of the proposal should commence.
---------------------------------------------------------------------------
\189\ AEP Reply Comments, Docket No. AD22-5, at 4-5 (filed May
25, 2022); APPA/LPPC Comments, Docket No. AD22-5, at 12-13 (filed
Apr. 25, 2022); APS Comments, Docket No. AD22-5, at 14 (filed Apr.
25, 2022); CAISO Comments, Docket No. AD22-5, at 2 (filed Apr. 25,
2022); EEI Comments, Docket No. AD22-5, at 33 (filed Apr. 25, 2022);
ELCON Comments, Docket No. AD22-5, at 12 (filed Apr. 25, 2022); ISO-
NE Comments, Docket No. AD22-5, at 5-6 (filed Apr. 25, 2022); ITC
Comments, Docket No. AD22-5, at 15 (filed Apr. 25, 2022); MISO
Comments, Docket No. AD22-5, at 8 (filed Apr. 25, 2022); NYISO
Comments, Docket No. AD22-5, at 1-2 (filed Apr. 25, 2022); Potomac
Economics Comments, Docket No. AD22-5, at 3 (filed Apr. 26, 2022);
Southern Company Comments, Docket No. AD22-5, at 11 (filed Apr. 25,
2022); Tri-State Comments, Docket No. AD22-5, at 4 (filed Apr. 25,
2022).
---------------------------------------------------------------------------
177. We seek comment on the preliminary proposal to use an annual
implementation cycle. We also seek comment on whether the proposed
annual implementation period would accurately identify transmission
lines for implementation of the wind requirement or if the Commission
should require (or allow, if preferred) a lower frequency (such as
every two to three years) of cycles and higher lines-per-cycle limit
for the wind requirement cycle.
[[Page 57715]]
b. Transmission Provider Compliance Requirement
178. As described above in section IV.A.3.b.i. Number of
Transmission Lines Subject to the Wind Requirement Annually, we
preliminarily propose that transmission providers be required to
implement the wind requirement on the whole number greater than 0.25%
(or 1 in 400) of the transmission provider's transmission lines in each
annual implementation cycle. As described above, transmission providers
would be required to implement the wind requirement only on
transmission lines that meet the congestion threshold and wind speed
threshold.
179. We preliminarily propose to require transmission providers to
implement the wind requirement on candidate transmission lines starting
with the most highly congested transmission line (based on the
congestion metric value, as discussed above) and moving on to the next
most highly congested transmission line, and so on. This process would
continue until either the yearly implementation requirement is met or
there are no more candidate transmission lines waiting for
implementation of the wind requirement.
c. Compliance for Transmission Providers That Are Subsidiaries of the
Same Public Utility Holding Company
180. Transmission providers (or transmission owners in cases where
the transmission owners and transmission provider are not the same
entity) that are operating company subsidiaries of the same public
utility holding company may operate their transmission facilities as a
single transmission system. We seek comment on whether such
transmission systems should be counted together for purposes of the
transmission providers' compliance with any wind requirement, such as
for counting the transmission providers' total number of transmission
lines and for determining the number of transmission lines that would
be included in the transmission providers' implementation cycle. This
may result in implementation of the wind requirement being distributed
unevenly across transmission providers that are operating company
subsidiaries of the same public utility holding company. We seek
comment on whether transmission providers in such situations, or the
RTOs/ISOs of which they are members, should propose on compliance how
they would treat such transmission providers and transmission systems.
V. Comment Procedures
181. The Commission invites interested persons to submit comments
on the matters and issues proposed in this ANOPR to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due October 15, 2024 and Reply
Comments are due November 12, 2024. Comments must refer to Docket No.
RM24-6-000, and must include the commenter's name, the organization
they represent, if applicable, and their address in their comments. All
comments will be placed in the Commission's public files and may be
viewed, printed, or downloaded remotely as described in the Document
Availability section below. Commenters on this proposal are not
required to serve copies of their comments on other commenters.
182. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software must be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
183. Commenters that are not able to file comments electronically
may file an original of their comment by USPS mail or by courier-or
other delivery services. For submission sent via USPS only, filings
should be mailed to: Federal Energy Regulatory Commission, Office of
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of
filings other than by USPS should be delivered to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
VI. Document Availability
184. 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).
185. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
186. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's 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].
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By direction of the Commission. Commissioner Rosner is not
participating.
Issued: June 27, 2024.
Debbie-Anne A. Reese,
Acting Secretary.
Note: The following appendix will not appear in the Code of
Federal Regulations.
Appendix A: List of Short Names/Acronyms of Commenters in Docket No.
AD22-5
------------------------------------------------------------------------
Short name/acronym Commenter
------------------------------------------------------------------------
AEP........................... American Electric Power Company, Inc.
APPA/LPPC..................... American Public Power Association (APPA)
and the Large Public Power Council
(LPPC).
APS........................... Arizona Public Service Company.
BPA........................... Bonneville Power Administration. The BPA
Comments were filed as appendix B to
the DOE Comments and were not submitted
as a separate filing. Pagination cited
in the ANOPR is internal to the BPA
Comments.
CAISO......................... California Independent System Operator
Corporation.
Certain TDUs.................. 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.......... Natural Resources Defense Council,
Sustainable FERC Project, Southern
Environmental Law Center, Western
Resource Advocates, Conservation Law
Foundation, RMI, and Fresh Energy.
DC Energy..................... DC Energy, LLC.
DOE........................... United States Department of Energy.
[[Page 57716]]
EEI........................... Edison Electric Institute.
EGM........................... Electrical Grid Monitoring.
ELCON......................... Electricity Consumers Resource Council.
Entergy....................... Entergy Services, LLC.
Idaho Power................... Idaho Power Company.
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.
NERC.......................... North American Electric Reliability
Corporation.
NRECA......................... National Rural Electric Cooperative
Association.
NYISO......................... New York Independent System Operator,
Inc.
NYTOs......................... The New York Transmission Owners consist
of: Central Hudson Gas & Electric
Corporation; Consolidated Edison
Company of New York, Inc.; Niagara
Mohawk Power Corporation d/b/a National
Grid; New York Power Authority; New
York State Electric & Gas Corporation;
Orange and Rockland Utilities, Inc.;
Long Island Power Authority; and
Rochester Gas and Electric Corporation.
OMS........................... Organization of MISO States.
Potomac Economics............. Potomac Economics, Ltd.
PPL........................... PPL Electric Utilities Corporation.
R Street Institute............ R Street Institute.
Southern Company.............. Southern Company Services, Inc. acting
as agent for Alabama Power Company,
Georgia Power Company, and Mississippi
Power Company.
TAPS.......................... Transmission Access Policy Study Group.
Tri-State..................... Tri-State Generation and Transmission
Association, Inc.
TS Conductor.................. TS Conductor Corporation.
WATT/CEE...................... Working for Advanced Transmission
Technologies (WATT) and Clean Energy
Entities (CEE), which consist of
American Clean Power Association,
Advanced Energy Economy, and the Solar
Energy Industries Association.
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[FR Doc. 2024-14666 Filed 7-12-24; 8:45 am]
BILLING CODE 6717-01-P