[Federal Register Volume 86, Number 162 (Wednesday, August 25, 2021)]
[Notices]
[Pages 47485-47487]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[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