Notice2021-18259
Climate Change, Extreme Weather, and Electric System Reliability; Correction
Primary source
Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.
Published
August 25, 2021
Issuing agencies
Energy DepartmentFederal Energy Regulatory Commission
Abstract
The Federal Energy Regulatory Commission published a notice in the Federal Register of August 17, 2021, inviting comments to address a list of questions that were inadvertently omitted from the notice.
Full Text
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<title>Federal Register, Volume 86 Issue 162 (Wednesday, August 25, 2021)</title>
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[Federal Register Volume 86, Number 162 (Wednesday, August 25, 2021)]
[Notices]
[Pages 47485-47487]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2021-18259]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. AD21-13-000]
Climate Change, Extreme Weather, and Electric System Reliability;
Correction
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice; correction.
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SUMMARY: The Federal Energy Regulatory Commission published a notice in
the Federal Register of August 17, 2021, inviting comments to address a
list of questions that were inadvertently omitted from the notice.
FOR FURTHER INFORMATION CONTACT: Rahim Amerkhail, 202-502-8266 or
Michael Haddad, 202-502-8088.
SUPPLEMENTARY INFORMATION:
Correction
In the Federal Register of August 17, 2021, in FR Doc. 2021-17626,
on page
[[Page 47486]]
45980, in the first column after the words ``Kimberly D. Bose,
Secretary'' insert the following additional text:
Post-Technical Conference Questions for Comment
1. Multiple panelists at the technical conference suggested that
utilities and other industry participants should engage in an
assessment of climate change risks to their systems.\1\ Should public
utilities be required to engage in either a one-time assessment or
periodic assessments of climate change risks to their assets and/or on
how their system is expected to perform under expected climate change
driven scenarios? If so, should such requirements be incorporated into
jurisdictional local transmission planning and/or regional transmission
planning/cost allocation process tariff provisions? Similarly, should
such requirements be incorporated into FERC-jurisdictional resource
adequacy tariff provisions?
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\1\ See June 1 Tr. at 14 (Adam Smith); 17 (Jessica Hogle); 55,
83 (Romany Webb); 79 (Derek Stenclik).
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2. Several panelists at the technical conference suggested that
greater use of probabilistic approaches could provide a more robust
approach to accounting for extreme weather.\2\ Would incorporating
probabilistic methods into local transmission planning and/or regional
transmission planning/cost allocation processes allow public utility
transmission providers to more effectively assess low probability/high
impact events and common mode failures? \3\ If so, should such
practices be incorporated into public utility transmission providers'
local transmission planning and/or regional transmission planning/cost
allocation processes? What, if any, jurisdictional tariff changes would
be necessary to incorporate these practices into existing transmission
planning and cost allocation processes? Similarly, should such
practices be incorporated into any resource adequacy assessments
carried out under FERC-jurisdictional tariff provisions?
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\2\ See June 1 Tr. at 36-37, 81 (Lisa Barton); 53, 69-70 (Judy
Chang); 79, 92 (Derek Stenclik); 83 (Romany Webb); 119 (Richard
Tabors); 129 (Neil Millar).
\3\ As described in the March 15, 2021 Supplemental Notice of
Technical Conference Inviting Comments in this proceeding, common
mode failures occur where, due to climate change or an extreme
weather event, a large number of facilities critical to electric
reliability (e.g., generation resources, transmission lines,
substations, and natural gas pipelines) experience outages or
significant operational limitations, either simultaneously or in
close succession.
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3. At the technical conference, panelists noted the importance of
coordinating transfers across the seams between Regional Transmission
Organizations/Independent System Operators (RTOs/ISOs) and non-RTO/ISO
areas to both reduce costs and improve the resilience of the
transmission grid during extreme weather events.\4\ How do RTO/ISO and
non-RTO/ISO transmission providers manage congestion at system seams?
What are the benefits and drawbacks of the current management regime,
from the perspectives of cost, resource participation, and ability to
maximize reliability and other benefits of transmission service? Can
more cost-effective congestion management at the border between RTOs/
ISOs and neighboring non-RTO/ISO transmission providers be facilitated
through new pro forma Open Access Transmission Tariff (OATT)
provisions? If so, how could the pro forma OATT be modified to achieve
this enhanced coordination? For example, could existing pro forma OATT
section 33.2 (Transmission Constraints), which permits a transmission
provider to use redispatch to maintain reliability during transmission
constraints, be modified to enhance coordination with a neighboring
RTO/ISO during such redispatch? Are there any other potential
modifications to the pro forma OATT that might facilitate cost-
effective congestion management at the border between RTOs/ISOs and
neighboring non-RTO/ISO transmission providers? If so, please describe
them in as much detail as possible. If such modifications were made to
the pro forma OATT, could they also help improve coordination between
RTOs/ISOs and non-jurisdictional entities through their inclusion in
the reciprocity tariffs that are voluntarily filed by some non-
jurisdictional entities? What challenges would any such modifications
need to address?
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\4\ See June 2 Tr. at 64, 66-67 (Renuka Chatterjee); 68 (Amanda
Frazier); 153 (Dan Scripps); 66 (David Patton).
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4. RTOs/ISOs currently have differing levels of authority to
approve or recall outages.\5\ Can generation and transmission outage
scheduling practices be improved? For example, should RTOs/ISOs have
greater authority to deny generation and transmission outage requests,
such as having the ability to deny such a request based on estimated
economic impact, as ISO New England currently has? Similarly, should
transmission owners be given an incentive to schedule transmission
outages more efficiently by making transmission owners responsible for
uplift they cause from outages, as the New York Independent System
Operator currently does? Would such changes help system operators
better prepare for or respond to extreme weather events?
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\5\ See June 2 Tr. at 21-23, 32 (Wesley Yeomans); 23-24 (Renuka
Chatterjee); 30-31, 74-75 (David Patton).
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5. Transmission topology optimization (also sometimes known as
transmission switching) involves dynamically modifying transmission
topology as a component of determining optimal day-ahead and real-time
energy market solutions.\6\ Should RTOs/ISOs be required to incorporate
transmission switching or transmission topology optimization in their
day-ahead and real-time energy markets? Could the adoption of such
optimization approaches both reduce costs and improve the resilience of
the transmission grid?
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\6\ See June 2 Tr. at 7(Amanda Frazier), 55 (Renuka Chatterjee),
55-57 (Mads Almassalkhi), 58-59 (David Patton), 60-61 (Robin Broder-
Hytowitz), 61-62 (Anne Hoskins), 94-96 (Charles Long), 97-98 (Daniel
Brooks), 136 (Letha Tawney).
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6. Panelists at the technical conference suggested that current
requirements for system performance under extreme weather scenarios may
need to evolve.\7\ Should the transmission planning requirements
established under North American Electric Reliability Corporation
(NERC) reliability standard TPL-001-4/5 be modified to better assess
and mitigate the risk of extreme weather events and associated common
mode failures? Should any additional changes be considered to the NERC
Reliability Standards to address the risk of extreme weather events?
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\7\ June 1 Tr. at 138-40 (Mark Lauby).
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7. Multiple panelists at the conference emphasized the need to
establish a requirement for interregional transmission planning and
improve existing interregional cost allocation methods to prepare for
extreme weather events.\8\ How can the existing requirement to have an
interregional transmission coordination (not planning) and cost
allocation process be modified to better account for the benefits that
interregional transmission facilities provide during extreme weather
events? Would defining a set of uniform transmission benefit metrics
that can be used across regions in the interregional transmission
coordination and cost allocation processes help interregional
transmission projects come to fruition? If so, please propose such
metrics in as much detail as possible.
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\8\ June 2 Tr. at 64-66 (Renuka Chatterjee), 147 (Patricia
Hoffman), 153 (Dan Scripps).
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8. Would having a target level of interregional transfer capacity
help facilitate more effective development of interregional
transmission projects?
[[Page 47487]]
Should minimum amounts of interregional transmission transfer
capability be required or encouraged as a way to improve the resilience
of the power system? \9\ If so, how should such minimums be determined
(e.g., a stated MW or percentage of load basis), and how specifically
should such minimum requirements be implemented (e.g., NERC reliability
standards or new tariff requirements)?
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\9\ June 2 Tr. at 64-66 (Renuka Chatterjee).
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9. Multiple panelists at the conference suggested that the current
reliance on the 1 day in 10-year Loss of Load Expectation is
outmoded.\10\ Are there alternative resource adequacy planning
approaches that could be more robust alternatives to the use of the 1
day in 10-year Loss of Load Expectation standard? Please describe such
alternatives, including describing whether such alternatives have been
used either in the United States or elsewhere.
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\10\ See June 1 Tr. at 85 (Judy Chang), 119 (Richard Tabors),
122-123 (Alison Silverstein), 125 (Devin Hartman), 127 (Mark Lauby).
Dated: August 19, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021-18259 Filed 8-24-21; 8:45 am]
BILLING CODE 6717-01-P
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