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UNITED STATES OF AMERICA
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FEDERAL ENERGY REGULATORY COMMISSION
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Technical Conference
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to Discuss Climate Change,
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Extreme Weather, & Electric
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System Reliability
Docket No: AD21-13-000
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TECHNICAL VIDEO CONFERENCE
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Federal Energy Regulatory Commission
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888 1st Street NE
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Washington, DC 20426
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Wednesday, June 2, 2021
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1:00 p.m.
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Opening Remarks
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Panel 3:
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and Extreme Weather
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David Patton,
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Amanda Frazier, Senior Vice President of Regulatory Policy,
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Vistra Corp
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Robin Broder Hytowitz, Senior Engineer, Electric Power
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Research Institute.
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Renuka Chatterjee, Executive Director of Systems Operations,
Operating Practices for Addressing Climate Change
President, Potomac Economics
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Midcontinent ISO
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Wesley Yeomans, Vice President of Operations, New York ISO
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Anne Hoskins, Chief Policy Officer, Sunrun, Inc.
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Mads Ronne Almassalkhi, Assistant Professor at the
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University of Vermont, and Chief Scientist at PNNL and
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Co-founder of Packetized Energy.
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Panel 4:
Recovery and Restoration
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Kevin Geraghty, Senior Vice President of Electric
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Operations, San Diego Gas and Electric
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Daniel Brooks, Vice President Integrated Grid and Energy
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Systems
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Charles Long, Vice President of Transmission Planning and
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Strategy, Entergy
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Michael Bryson, Senior Vice President of Operations, PJM
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Interconnection
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Brian Slocum, Vice President of Operations, ITC Holding
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Jodi Moskowitz, Deputy General Counsel and RTO Strategy
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Officer at PSEG.
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Panel 5:
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Karen Wayland, Chief Executive Officer, GridWise Alliance
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Randy Howard, General Manager, Northern California Power
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Agency
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Dan Scripps, Chairman, Michigan Public Service commission
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Letha Tawney, Commissioner, Oregon Public Utilities
Coordination
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Commission
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Carolyn Barbash, Vice President of Transmission and
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Development Policy, NV Energy
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Patricia A. Hoffman, Acting Assistant Secretary, Principal
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Deputy Assistant Secretary, Office of Electricity, U.S.
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Department of Energy
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P R O C E E D I N G S
Opening Remarks
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MR. AMERKHAIL:
Good afternoon everyone and
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welcome back to the Federal Energy Regulatory Commission's
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Technical Conference on Climate Change and Extreme Weather
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and Electric System Reliability.
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and I'm with the Commission's Office of Energy Policy and
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Innovation.
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My name is Rahim Amerkhail
The purpose of this conference is to discuss
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issues surrounding the threat to electric system
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reliability posed by climate change and extreme weather
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events.
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any current or contested proceedings before the Commission
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whether listed on the supplemental notice issued on May 27th
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or not.
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We do not intend to discuss the specific details of
And we'd ask that all participants similar
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refrain from such discretion.
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kinds of discussions my colleague, Michael Haddad from the
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Office of General Counsel will interrupt the discussion to
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ask the speaker to avoid that topic.
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If anyone engages in these
For those of you tuning in for the first time
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today, I want to cover some logistics for the conference.
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We will have three panels this afternoon.
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break in between panels.
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and small group of Commission staff will have the ability to
We will also a
Only the Commissioners, panelists
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speak today.
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This conference is being webcast and transcribed.
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With those reminders out of the way let's get started with
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the third panel entitled,
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Addressing Climate Change and Extreme Weather."
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it over to our moderators thank you.
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Panel 3:
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and Extreme Weather
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"Operating Practices for
I'll turn
Operating Practices for Addressing Climate Change
MR. WHITMAN:
Thank you.
I'm Peter Whitman from
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the Office of Energy Policy and Innovation, and along with
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my colleague Elizabeth Topping, also from the Policy Office,
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I'll be serving as moderator.
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This panel will explore the ways in which
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existing operating practices, including but not limited to
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those pertaining to seasonal assessments, outage planning,
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and coordination, reserve procurement and the insight
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management unit commitment of dispatch, short-term asset
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management and emergency operating procedures and they
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necessitate updated techniques and approaches in light of
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increasing instances of extreme weather and longer term
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threats posed by climate change.
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We will be foregoing opening remarks for this
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panel and will move directly into a question and answer
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session.
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break.
Following this panel we will have a 20 minute
I'd like to start by introducing our panel three
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panelists.
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We have David Patton, President of Potomac
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Economics; Amanda Frazier, Senior Vice President of
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Regulatory Policy at Vistra Corporation; Robin Broder
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Hytowitz, Senior Engineer, Electric Power Research
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Institute;
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Systems Operations, Midcontinent ISO; Wesley Yeomans, Vice
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President of Operations, New York ISO; Anne Hoskins, Chief
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Policy Officer, Sunrun, Inc. and Mads Ronne Almassalkhi,
Renuka Chatterjee, Executive Director and
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Assistant Professor at the University of Vermont, and Chief
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Scientist at PNNL and Co-founder of Packetized Energy.
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Thank you.
Welcome panelists.
As we begin I'd
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like to remind all participants to refrain from any
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discussion on any contested proceedings.
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in these kinds of discussions my colleague Michael Haddad
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from the Office of General Counsel will interrupt the
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discussion to ask the speaker to avoid that topic.
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If anyone engages
We will now begin with a question and answer
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session.
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please use the Webex raise hand function.
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you are having issues with raise hand please turn on your
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microphone and indicate that you would like to respond.
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will call on panelists that indicate they would like to
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answer in turn.
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If a panelist would like to answer a question
Alternatively, if
We
Once we do so, please turn on your microphone and
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respond to the question.
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answer, please turn off your microphone and also lower your
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virtual hand so we don't think that you have a follow-up.
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With that I'll turn it over my colleague Elizabeth Topping.
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MS. TOPPING:
When you have completed your
Thank you Peter.
Good afternoon
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everyone.
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broad one and that is how can market structures or rules be
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reformed to give generators and other resources stronger
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incentive to be prepared for the challenge of climate change
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For our first question we'd like to start with a
or extreme weather that they may face?
Can new market products, for example, seasonal
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products, or enhancements to existing market structures be
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designed based on defined reliability for resilience needs
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in order to address the challenges of climate change and
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extreme weather?
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Okay let's see.
Please raise your hand if you
would like to answer and let's go to Amanda first.
MS. FRAZIER:
Thank you very much Elizabeth and
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Pete, and thank you for allowing me to participate on the
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panel this afternoon.
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Commissioners for hosting this technical conference.
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think it's an important discussion.
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low-hanging fruit on how do you incorporate into the market,
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ways to address both climate change and reliability is to
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incorporate carbon pricing into the market.
I'm appreciative also to FERC
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You know I think the
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There are a number of different ways to do that,
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and the Commission recently finalized a policy statement on
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carbon pricing in the market which Vistra fully supports.
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And then once you have carbon as an optimization tool inside
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the markets, then you will be able to attract the right
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collection of resources, both to address decarbonization
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goals along with reliability needs.
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I think other ideas that you know some RTOs and
ISOs have considered, and for example ISO New England has
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implemented they're called inventory energy programs.
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know I think that's an interesting way to ensure that you
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are attracting fuel secure resources for winter seasons in
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particular, or for seasons where you expect to need
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additional incentives to make sure that you have fuel
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security for resources to perform as needed.
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You
I know that you know ISO New England also had
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considered and submitted a proposal called Energy Security
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Initiative, and I think that's something that will continue
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to evolve in the northeast as well.
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programs I think are an interesting way, and a good way, and
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a market-based way to address getting the right resources in
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for events such as winter, winter events.
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But those types of
MR. WHITMAN:
Thank you.
Next we'll go on to
MR. YEOMANS:
Good afternoon, and again thanks
Wes.
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for inviting the New York ISO to this panel.
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of our extreme weather concerns at this point in time, at
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least the last five or 10 years have been extreme cold
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weather.
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and we expect to have more of those.
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The majority
We certainly can have heatwaves in New York City,
We experienced the severe Hurricane Sandy which
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hit New York City and Long Island, New Jersey and
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Connecticut back in the late 2012, ice storm in the late
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90's, but for this question from a market structure and
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rules perspective, I'll really be talking about things that
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we've done to better prepare for the very cold weather
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operation with limited pipeline capability.
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If we had unlimited pipeline capability I don't
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believe we'd have a problem with extreme cold weather but
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that's not the case.
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recently really since the polar vortex of January 2014 is as
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everyone knows single cost recovery certainly is a large
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aspect of ensuring reliability.
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One of the first things we've done
We've enhanced the capability to allow generators
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to provide expected costs for day ahead market reference
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level developments and enhanced our consultation process
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such that generators can get cost recovery for their
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legitimate tool cost to assist with reliability during cold
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weather operations, and all situations, and all other types
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of tight operating conditions where we have substantial
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reliability issues.
Moving on to reserves.
Up until the polar vortex
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we just happened -- the result of our market with a lot of
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latent, excess reserves, but really starting at about the
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time of the polar vortex and even continuing since then so
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many resources had switched the gas, the fuel of choice
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because it's inexpensive natural gas, and again the limited
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pipeline supply that we thought it prudent to increase the
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amount of operating reserves that we schedule and purchase
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and pay for in both the day ahead and the real time.
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by increase, I mean above the minimum operating requirement.
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And
So we had a long time period where we had a
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smaller large contingent with an energy redispatch where
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markets on our borders could only use rescheduled energy,
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and recreate the operating reserves, but starting about 2014
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that became more challenging, so we did the right thing and
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just increased the quantity, and we scheduled it and we paid
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for it and that works well.
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Since January '14, I think around 2015 we
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modified reserve shortage pricing, which modified means
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increased the pricing for reserve shortages with our closed,
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and that better values the reliability benefits of operating
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reserves, hence the same generator to secure more fuel in
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week ahead schedules.
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In the world of regulation service we've
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proactively done studies, maybe not so much for climate
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change and extreme weather, but really to prepare for more
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renewables, whether it's more wind or more solar.
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done studies ahead of time to say at certain high levels of
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renewables what additional regulation will we need, and we
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put some of those higher numbers in place in our market
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systems.
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We've
Moving forward I won't list all the things that
we have going on, but we've written a significant white
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paper on what we need to do to incorporate large volumes of
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solar and wind over the next five to 10 years.
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white paper.
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written for extreme weather, but those market enhancements
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and reliability rule enhancements that we need for very
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large volumes of wind and solar are consistent for the types
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of product we're going to need for extreme weather and
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climate change.
I won't list all that.
We have a
That's not necessarily
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And then from a reliability rules perspective
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different than market enhancements, we have improved our
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weekly dual monitoring capability, testing every six months
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to make sure the dual field units can start annual generator
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visits to make sure they're ready for hot and cold weather
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operations and extreme weather, improved our communications
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with the gas industry, emergency procedure for the gas
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industry, and we've always even before polar vortex at our
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oil burn rules that require a certain number of generators
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to have dual fuel capability.
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We had to switch to oil at certain high load
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thresholds such that we had the resiliency in the event of a
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pipeline break.
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So again, that's my response.
MR. WHITMAN:
Fantastic thank you.
David you're
next.
MR. PATTON:
Hi.
Thanks to the Commission for
the invitation to speak at this Conference.
I think this is
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a really interesting set of topics, and I think we monitor
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New York and New England and MISO and ERCOT, all of which
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have very different market structures and rules that put
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them in either a better position or a worse position to
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address these sort of extreme conditions.
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So most of my comments won't be specific about a
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particular RTO.
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about more generally how the markets in all these areas are
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prepared to address these more extreme events.
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foremost I would say 90-95 percent of the objectives should
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be to get shortage pricing correct in all of the RTOs.
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Some of them might be, but really talking
First and
Shortage pricing is incredibly important because
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it not only allows you, allows the RTOs to price and send
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efficient incentives for things you might foresee coming
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with some degree of probability, but also maybe even more
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importantly it helps you price and send incentives to deal
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with situations that are highly unlikely that you don't see
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coming, and extreme weather events definitely fall into that
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category.
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They're not events that would make sense to plan
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for.
In other words to have planning criteria to address
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because they are so specific and many of them are so low
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probability that that would be enormously costly to have
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mandates to try to address them.
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provided by shortage pricing will provide correct
But the incentives
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incentives for and people respond to naturally who own
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assets, or who serve load.
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And by way of comparison I would say New England
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has by far the strongest shortage pricing.
It's embedded in
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their pay for performance, but people often don't understand
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that that's really just shortage pricing that is packaged
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and settled outside the energy market.
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downsides of doing that, but nonetheless it is by far the
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strongest in the country.
There are some
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ERCOT perhaps is next, and I would say New York
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and MISO are kind of woefully inadequate, so bringing them
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up to a standard that would reflect the value of the loss
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load that you might experience during these extreme events
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will help provide much better incentives in those two
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markets to prepare for extreme events.
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would start.
So that's where I
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I don't think seasonal products or other types of
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products are very helpful because you have to get the spot
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price that tell you at every moment what energy is worth
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correct?
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settle against that spot price, but having a seasonable
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product by itself I think is not very helpful.
And then you can have seasonal products that
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MR. WHITMAN:
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MS. CHATTERJEE:
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Interesting, thank you.
Renuka?
Thank you and good afternoon.
Thank you to the Commission to having MISO at this technical
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conference.
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outcome of many years of preparation and planning as you
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approach the extreme event, they are the weather.
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I would like to start by saying that the
As many have suggested prior to me the generation
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performance is critical, not just during extreme weather
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events.
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doesn't show up at the required commitment, that obligation
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at the required time, we quickly get into actions that are
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less talked about in terms of using operating reserves,
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reserves that will be needed to maintain supply and demand
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values.
It's critical at all times.
If the generation
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Specifically with regards to market structures,
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forward looking actions to improve generation performance,
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MISO certainly thinks that winterization is a critical
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element.
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the north, and extreme heat in the south, so we do face both
MISO's footprint we have you know extreme cold in
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those extreme situations.
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weather events, again we could put in mechanisms such as
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scarcity pricing that we talked about, or seasonal
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constructs amortization, but when you get into the actual
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event we must recognize that you have what you have and try
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to maintain the liability at that point.
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Specifically for extreme
So it's good to have multiple options.
So as I
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reflect upon the February arctic event, it's not that we
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didn't have enough generation.
We couldn't get it to where
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it needed to go.
So again we can think about having locally
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sufficient generation, but at the same time you need
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transmission.
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All of this is a market for the compounder that
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the more uncertainty that's coming forward, so the MISO is
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looking to implement products like the shut-down reserves
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that should give us uncertainty management tools, including
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seasonal and pricing mechanisms that will improve
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availability, but at the end of the day when you are talking
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specifically about extreme weather events, we have to look
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at multiple options.
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The biggest lesson learned for us from the arctic
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weather event was that MISO is well situated and right in
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the middle of the country along with its neighbors that
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allowed us to import power.
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self-sufficient if it's within your FERC -- if it isn't you
Again you want to first be
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want to look instead of the footprint, not outside the
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footprint to import energy.
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So it's about having multiple options given the
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extreme weather events.
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extreme weather events and what you don't anticipate will
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happen during extreme weather events.
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MR. WHITMAN:
The risks generally compound during
Thank you.
Next is Robin.
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that EPRI has done a lot of work in sketching out the
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problem for this.
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MS. HYTOWITZ:
I note
Thank you very much Pete, and
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thank you for welcoming EPRI to this panel and it's an honor
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to be able to speak with my fellow panelists here on this
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topic.
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work on this topic, but first I wanted to just kind of think
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more generally about incentives right.
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So as you mentioned EPRI has done quite a bit of
When we think about incentives, we also think
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about prices.
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giving a high level look at what are prices -- energy prices
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during these events.
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different events.
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two major storms, and the average LMP for NYISO during super
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storm Sandy was around $32.00 a megawatt hour.
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And some of the work we've done and just
And so we took a look at four
Super storm Sandy and Hurricane Harvey as
And Hurricane Harvey the average price was for
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two different zones was $23.00 and $37.00 a megawatt hour.
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And then we contrast that with polar vortex in winter storm
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events.
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were $180.00 a megawatt hour approximately, and then of
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course we know this past February with Winter Storm Uri
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prices were extraordinary high in ERCOT, over $6,500.00 a
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megawatt hour.
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And so during the 2014 polar vortex NYISO prices
And so contrasting these two types of events we
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see very different outcomes right?
So this queue, the polar
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vortex, the cold winter events have high prices right?
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saw a shortage of supply in those cases.
We
Whereas the two,
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the super storm and the Hurricane Harvey we saw T and D
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outages and so often times our demand is just cut off from
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supply, whether or not we have fuel shortages.
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And so I think it's important to recognize, and I
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think like my panelists have that different events have very
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different outcomes in our markets, and coming up with
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different products and methods are going to be very specific
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to the type of extreme event that we're looking at.
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So something that might work for extreme cold
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might not necessarily work in the case of hurricanes or
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super storms.
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brought up that I very much agree with is the importance of
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shortage pricing, and getting shortage pricing right, and of
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course the different ISO's and they can speak more
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specifically to products.
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And something that many of my panelists
But something that we've been looking at at EPRI
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is thinking about how we can almost forecast reserves, and
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the importance of using dynamic reserves.
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thinking about dynamic reserves for renewables, but why
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can't we then also do that for weather and temperature.
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Folks have been
And so including specific weather events or just
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temperature itself and forecasting dynamic reserves might be
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something that we can look into in the future, and we're
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doing preliminary studies, but of course not necessarily
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implemented.
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Thank you.
MR. WHITMAN:
Thank you.
Next and last we have
Thank you.
Hello everyone, and it
so far it is Anne.
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MS. HOSKINS:
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is a privilege to be here.
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just what Sunrun is for those of you who may not know.
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Sunrun is a distributed solar and battery company, and I
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really appreciate the opportunity to join the panel today
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because so far I haven't heard much mention of distributed
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resources.
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I want to just take a minute and
And I'm not sure there was a lot of discussion
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yesterday either.
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today is don't forget the distributed resources.
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going to play a critical role, and have played a critical
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role in the past year in dealing where we have had very
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serious outages.
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And my main message for my participation
We are
Last summer, excuse me, in California we were
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called personally by the Commission -- the Public Service
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Commission here to ask if we could get our customers to
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participate.
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charge.
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compensated for it.
As if we could get our customers not to
Ask customers to share their power, but we weren't
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And so we had been working very hard with CAISO
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and with the California PUC to explain that you have all of
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these resources that are available, that can be available to
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help not just the individual but the system at large.
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in fact there was something close to 3,000 batteries
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available last August, about 150 megawatts, and those
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batteries -- I mean there were more than that available, but
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those actually voluntarily participated and helped to
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prevent the outages that everyone was very concerned about.
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But the capacity was actually much greater than
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that.
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that time there are thousands and thousands of more
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batteries that individuals, companies, schools have
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installed.
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account as we do our planning.
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And
There was an estimated 530,000 megawatts.
And since
So we absolutely need to have this taken into
The same situation happened in Texas where we had
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just recently entered the market.
But we had hundreds of
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customers who were able to not only back up their own house,
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keep their solar operating, but actually have their
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neighbors and others participate.
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So that's my main message.
You're going to hear
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it again later in the questions.
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FERC is fortunately we do have the Order 2222, which is
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going to play a tremendous role we believe in ensuring that
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these resources actually are able to participate in the
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markets, can be compensated fairly for that, and can really
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be part of this resiliency discussion and reliability
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discussion.
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We have some concerns.
But the other point for
We are very optimistic
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about New England ISO and PJM, who we think are very sincere
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in their efforts to try to work with distributed resource
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providers to make sure we can get the right plans in place
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to make this work, but we're concerned about other ISOs and
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RTOs who are saying they think they've already done what
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they need to do.
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The fact is it's not done.
Except for New
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England ISO, we are not compensated for any capacity in the
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RTOs and ISOs, so we look forward to working with FERC,
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working with other stakeholders, and all I would say is that
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these are resources that individuals are investing in that
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are available to make our system more reliable and resilient
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and we just can't forget that thank you.
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MR. WHITMAN:
Thank you.
We also have a question
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later on oriented more towards flexibility demand which
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might incorporate these questions in the comments that you
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have.
If there's no other, are there any other questions,
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comments, just starting on this particular on our first
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question?
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next, we'll start with our next question thank you.
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If there is no one else then we'll go with our
MS. TOPPING:
Great.
For our next question what
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current practices exist with respect to recalling or
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cancelling non-critical generation and transmission
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maintenance outages during a reliability event?
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practices sufficient to ensure that all possible resources
Are these
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and infrastructure needed to address an extreme weather
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event are available when such events happen unexpectedly?
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And I'm looking for raised hands.
I see Anne's
hand up.
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MS. HOSKINS:
Apologize, I just forgot to take my
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MS. TOPPING:
Okay.
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MR. YEOMANS:
Yeah thank you.
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hand down.
Let's go to Wes.
Yeah the New York
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State during extreme heatwaves and in the winter is a very
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tight, transmission electric system.
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the load is in downstate, southeastern New York, Long
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Island, New York City, a lot of generation capacity in
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upstate in what I would call limited transmission.
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The great majority of
So it is very important in predicted tight
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conditions, or unexpected conditions that we can get
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transmission.
I recall there may be more important don't
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let it out in the first place for ordinary scheduled
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maintenance, you know, forced outage is unavoidable, but if
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there's the ability to move scheduled outages to other low
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level time periods or less stress conditions we always
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strive to do that.
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We do have the authority to direct transmission
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owners to recall transmission lines as need per ISO TO
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agreement that we executed in 1999.
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the authorities abilities, we take that very seriously.
The agreement grants
At
10
the highest level we just generally do not allow any
11
long-term transmission outages in the summer months, or even
12
December and January if they do not have recall time.
13
So in a world of transmission infrastructure we
14
can recall it and get it back.
And so if we work with the
15
transmission owner and they say they can get it back in 6,
16
10 to 12 hours, or maybe even 20 hours they we can allow
17
some longer term outages, or we'll watch the weather
18
carefully, and we think we have confidence out about two or
19
three days.
20
So if we have a recall time less than two days
21
then we can allow some significant mission maintenance to
22
work.
23
no reason a transmission owner can't get some work done, but
24
we actually require a fast recall time if conditions change,
25
or if the weather forecast change.
I mean if it's 75 degrees in July for a week there's
23
1
Now of course, that results in a lot of
2
maintenance being pushed out in the spring and the fall.
3
But anyway, we will allow short outages.
4
longer outages with recall times, and then of course we try
5
to move this outage work into the spring and the fall and
6
stay out of December, January.
7
We will allow
And then a lot of that is true with the
8
generation capacity.
We have a process where we evaluated
9
what our predicted capacity excess margins are, and if a
10
generator/asset owner wants to take maintenance, and we do
11
support maintenance, it's the maintenance of the generators
12
and transmission to help avoid forced outages, or very
13
supportive of getting scheduled maintenance completed.
14
It helps.
We have a process on the generation
15
side to look at capacity margins, and if we have sufficient
16
capacity margins we'll let a generator take a long outage to
17
make repairs.
18
generally in the summertime we won't allow long-term
19
outages.
And we always support that, allow that, but
20
We will grant a short outage if it's in a two or
21
three day time period, we need to forecast weather and wait
22
for that peak load, so.
23
MR. WHITMAN:
24
25
Thank you.
I think our next
speaker is Renuka.
MS. CHATTERJEE:
Thank you.
Pretty similar to
24
1
what Wes mentioned, MISO has the authority to reschedule
2
transmission outages and cancel the generation outages as
3
necessary again.
4
responsibility because ultimately when you defer maintenance
5
you could be perpetuating generation performance problems,
6
so we don't want to necessarily move maintenance down the
7
road all the time.
8
The authority that comes will all the
But that said it is becoming more increasingly
9
every day, summer like spring and fall days, and winter like
10
spring and fall days are putting pressure on the maintenance
11
seasons, our traditional maintenance seasons.
12
looking at how do we make you know outage planning and more
13
continuous activity, and opportunistically take outages?
14
So we are
And for those of you who have looked at MISO's
15
recent history I mean aside extreme weather events most of
16
our emergency actions are actually in the shorter months or
17
the maintenance months.
18
achieve access at demand response which we'll get to in a
19
later question, the point being our shorter months seem to
20
represent the highest amount of risk because that represents
21
the highest number of vulnerability in terms of generation
22
resources following availability et cetera.
23
So in terms of is it sufficient?
Primarily because we are trying to
I don't think
24
it's sufficient.
We're trying to do additional things like
25
maximize transmission line ratings, or look at switching
25
1
options to kind of minimize that risk that we are seeing in
2
the shorter months.
3
seasonal construct other places will allow us to make that
4
risk more transparent so we can actually adequately plan you
5
know.
6
We think again moving to some of that
Again different maintenances are our goal.
We do
7
want to get the maintenance complete, so we have the
8
generation available for the highest risk times, but that is
9
putting a lot of pressure in our shorter months for MISO.
10
MR. WHITMAN:
Great thank you.
11
MS. FRAZIER:
Thank you.
Next is Amanda.
So to Renuka's point I
12
agree with her that you know you don't want to defer
13
generation outages if you don't have to because deferred
14
maintenance outages quickly become forced outages if the
15
problem is not addressed.
16
really important.
17
Patton was talking about shortage pricing, and the
18
importance of having pricing that creates the right
19
incentives for generators to be online.
20
And so this coordination is
And going back to the question one Dr.
And part of that is that all traditional
21
generation tends to take it's not maintenance outages at the
22
same time which is either in the spring or in the fall when
23
there's less opportunity for a pricing event.
24
have seen that create is concerns actually happen most often
25
in the shoulder months because that's when an unexpected
And what we
26
1
weather event can really create a concern.
2
In ERCOT in April of this year the ISO actually
3
announced conservation -- requesting conservation on a day
4
where it was unusually hot for April.
5
hot for Texas standards, but for April it was, but because
6
there was so much generation on outage they were concerned
7
about potential shortages.
It wasn't unusually
8
That said, a lot of work has been done in many of
9
the ISO's on coordinating commission and generation outages.
10
Something that has not had as much focus is coordinating
11
electric outages with gas outages, gas pipeline outages,
12
maintenance outages, and that was an issue that actually
13
occurred in again in ERCOT in 2019, and what's interesting
14
is that gas pipelines because their high-demand system is in
15
the winter months, they typically do take their outages in
16
the summer months when their demand is the lowest, but of
17
course the power side demand is high in the summer months.
18
And so more coordination.
I know we're going to
19
talk about this again on the next question, but more
20
coordination from an outage perspective between the power
21
industry and the gas industry is also something that the
22
Commission should look at.
23
24
25
MR. WHITMAN:
Thank you.
Our next speaker is
Anne Hoskins.
MS. HOSKINS:
Hello again.
So I do want to
27
1
mention that one of the drivers for why people are
2
installing batteries with their solar system, particularly
3
in California, but also in Puerto Rico is when transmission
4
systems haven't been working.
5
the forced outage, or required outages, intentional outages
6
by PG&E in particular where we are having days, you know, it
7
went for a few days a few years ago, now they're shortening
8
it.
9
You know when there have been
And so what the incentive has been for customers
10
to go out, invest in their own batteries so they can
11
continue to generate their own power.
12
you know we are getting this large, you know, large amount
13
of solar and battery systems across California and across
14
other states where we've had these kind of reliability
15
issues.
16
And because of that
So you know once again I think what we should be
17
thinking about is if we know first of all that unfortunately
18
this seems to be -- will be a common occurrence in
19
California, but as we see these issues and we have the
20
issues in terms of just having to plan to do outages, is to
21
start bringing this into the planning process, and to
22
realize that there are going to be increasing amounts of
23
solar and batteries.
24
25
And as long as we can figure out how to
compensate those for what they're offering and which I do
28
1
believe can be seasonally adjusted, it's just something we
2
have to keep into account.
3
studies of how that the increase in batteries and storage
4
have resulted in some reductions in the need for
5
transmission build in parts of the country.
6
We have certainly seem some
But I think it's particularly helpful in this
7
context to think about how they can be considered a resource
8
for when you have to have outages to maintain some of these
9
systems which are quite old and we need to make sure they
10
11
have time for their maintenance.
MR. WHITMAN:
Thank you.
Actually Anne I'd like
12
to ask a follow-up on that.
13
the DERs in California were actually called in an emergency.
14
Related to the interconnection and metering were they
15
connected in such a way that they were responsive to the
16
bulk power system?
17
You had mentioned that some of
Is there anything interesting or inciteful about
18
the interconnection process for these resources that would
19
be going forward?
20
MS. HOSKINS:
Well when I say called I mean
21
physically a phone call to all of us from the CPUC which is
22
the biggest challenge right?
23
the system set up yet to either call or to compensate.
24
mean we do have some -- the DER program and others through
25
CAISO, but there's just a tremendous amount of work that has
I mean we actually don't have
I
29
1
to be done and my understanding is that there are some
2
interconnection challenges along with that.
3
But if you looked at this as a resource that
4
really was available to come by capacity which we believe it
5
is, and found a way to compensate it, then there's no reason
6
particularly with the aggregators that are now available,
7
that this could not be something that could be called just
8
like any other type of generation resource.
9
But it was really a situation which was very
10
dire, and I think that policy and regulators were trying to
11
figure out what do we do to you now prevent you know this
12
tremendous outage across California.
13
calling distributed resource providers to ask us to
14
voluntarily take action which of course we did, and we do
15
view ourselves you know as having a very important societal
16
role to play.
17
And so they started
But I think we're at the point now where we see
18
that these are not one off occurrences, that they're
19
happening repeatedly.
20
this is a resource that does provide capacity, that is
21
available quickly, which is the other benefit, and to be
22
brought into this process in a more significant way.
23
MR. WHITMAN:
That it's just time to realize that
Thank you.
Next I think it would
24
be useful as David has pointed out because he has
25
responsibilities across multiple RTOs, maybe a comparison
30
1
across the RTOs?
2
MR. PATTON:
Yeah thanks Peter.
Yeah so I think
3
it would be useful for the Commission to recognize that the
4
authority to coordinate outages is significantly different
5
RTO to RTO, so New England I think has a pretty good tariff
6
authority to coordinate outages because they can deny
7
outages based on their estimated economic impact on the
8
system.
9
So if it looks like for example that a generator
10
wants to take an outage when there's a line outage into an
11
area and it's going to cause congestion, and on that basis
12
they can deny the outage.
13
for years we've been recommending that MISO upgrade its
14
authority under its tariff because MISO can only deny
15
outages when it finds a reliability concern.
16
That's not the case in MISO, and
And the problem with that is that you're first
17
going to see an economic issue before you see any
18
reliability issue and by the time the reliability issue
19
happens you're scrambling.
20
a major line into a load pocket is out at the same time a
21
major generator in the load pocket is out and you end up
22
with severe congestion.
23
So we've seen number cases where
That's a case where MISO technically can't deny
24
the outage because it's purely an economic impact, but it's
25
also a case where the system is vulnerable to reliability
31
1
problems.
2
there's some weather events that creates an additional
3
outage, so I think improved authority would be good across
4
the board.
5
more thing.
6
If another unit has an outage in that pocket, or
But on the incentive side I did want to say one
How incentives connect to this -- that shortage
7
pricing definitely provides very good incentives for
8
generators to schedule to coordinate their outages and it
9
brings their incentives into alignment with the RTOs, so
10
when they're asked to move an outage it will generally be in
11
their economic interest if shortage pricing is good.
12
But one thing you have to realize is that in
13
markets with capacity markets we deliver a lot of the
14
revenues to generators in the form of SE payments that would
15
normally come in the form of shortage pricing revenues in an
16
energy only market.
17
the capacity markets is we don't hang generators based on
18
the fact that they are there during tight conditions, but
19
they are contributing to reliability.
20
So the one thing we don't do well in
So we've been recommending in New England, New
21
York and MISO that they all approve their accreditation, and
22
have it be based in large part on generators being there.
23
And that would help on outage scheduling because if you know
24
you're going to lose capacity revenues because you're on
25
outage during tight conditions, then it brings your
32
1
incentives into alignment again with the RTO on outage
2
scheduling.
3
And the last thing I would say is the one thing
4
you should know in all of these discussions is that there's
5
one key class of participant that doesn't have good
6
incentives, and that's the transmission owners.
7
have outages occurring that create problems, create
8
tightness or create outages, they're not harmed financially.
9
If they
And it's the same problem that we have trying to
10
get them to submit higher ratings so we can better utilize
11
the transmission.
12
market incentives that generators and other respond to.
13
in that regard thinking about how we can get better
14
incentives to the transmission owners is really valuable.
They just are almost immune from the
So
15
New York is the only one that does something in
16
this regard in that they allocate some of the transmission
17
right shortfalls associated with outages back to the
18
transmission owners, kicking the outages.
19
great for everybody to do.
That would be
Thank you.
20
MR. WHITMAN:
Thank you.
Good insights.
Wes?
21
MR. YEOMANS:
Yes thank you, this is my second
22
round.
I failed to mention something in the area of
23
transmission for extreme weather of course it makes sense to
24
recall transmission outages, and don't even schedule them in
25
the first place if there's a chance of extreme weather.
33
1
But even different than that something that might
2
be unique to New York or maybe not, is if we are predicting
3
severe thunderstorms, we had some transmission contingency
4
cases we put into our market system referred to as the
5
transmission service cases.
6
minus zero to normal ratings, N minus 1 to LTP emergency
7
ratings, we actually operate for some additional
8
contingencies assumed already out as part of our market
9
dispatch.
And rather than our ordinary N
10
So quite frankly from a practical perspective
11
that backs off the power flows on the transmission, even
12
though it's in service and it has not incurred that first
13
contingency yet, but it's in anticipation or preparation of
14
what might be sort of lightening strikes.
15
being prepared on the front end rather than loading the
16
lines to their full capability and then having to redispatch
17
on that after the first contingency because you might have
18
second, third, or fourth one shortly after that.
19
And we did.
And it's just
I was in 10th grade but in 1977 we
20
had a negative event in New York where some thunderstorms
21
passed by southeastern New York, and knocked out several
22
transmission lines in New York City, and unfortunately New
23
York City became unsynchronized, and we had a blackout.
24
Okay I wanted to offer that, thanks.
25
MR. WHITMAN:
Thank you.
Finally Anne do you
34
1
have a follow-up, or is your hand up?
2
3
MS. HOSKINS:
I'll fix it.
4
5
Sorry I'm not following the rules,
MR. WHITMAN:
Thank you.
Then let's go on to the
next question.
6
MS. TOPPING:
Our next question -- given the
7
dependence of electric system reliability on other systems,
8
on gas, water, et cetera, what situational information
9
related to those other systems is critical to electric
10
system operator awareness during extreme weather events?
11
Should electric system operators consider
12
modifications to their control rooms, or to software to
13
enhance their situational awareness related to these other
14
systems?
15
with Amanda.
16
I'm look for raised lands, let's see.
MS. FRAZIER:
Thank you.
Let's start
So you know we
17
experienced the power outages in ERCOT this past February,
18
and one of the things that was unique in this event compared
19
with for instance in 2011, was the significant disruption in
20
the gas pipeline system.
21
And you know as the country decarbonizes, it will
22
become more reliant, at least in the short and medium terms,
23
on reliability gas supply for that flexible you know,
24
flexible generation to balance out the renewables that are
25
coming online.
And those gas generators that will be needed
35
1
will have lower capacity factors, so that's going to create
2
you know some real misalignment of incentives in terms of
3
contracting for gas supply as generators are more reliant on
4
reliable gas, but also need more flexibility for when that
5
gas is provided.
6
And so you know we are very interested in a lot
7
more focus being paid to the gas pipeline systems, both the
8
interstate and the intrastate that falls within FERC's
9
jurisdiction through Section 311 and the Hinshaw Pipelines
10
and creating that additional transparency that's needed to
11
have that coordination.
12
intrastate pipelines, slightly regulates those intrastate
13
pipelines, but it has full jurisdiction to regulate further
14
you know if it finds that there are reliability issues being
15
created, and/or if it finds that issues on those pipelines
16
are affecting its regulation of interstate pipelines.
You know FERC regulates those
17
So currently the light-handed regulations are
18
that they require that rates must be fair and equitable,
19
that they must provide open access and be non-discriminate.
20
They have to have a statement of operating conditions.
21
have to offer firm, or interruptible service, and there are
22
some reporting requirements.
23
They
But what's not required on those Hinshaw in 311
24
pipelines are standards of conduct that separate the
25
transmission and marketing functions, transparency is not
36
1
required, so there's no electronic bulletin board similar to
2
the ones that are required for interstate pipelines.
3
And so and there's never been any enforcement
4
actions that we're aware of on pipeline operators under
5
Section 311 or the Hinshaw Pipelines.
6
in the February event was that coordination was very
7
difficult just because information was not available, and so
8
that lack of transparency -- and that includes both the
9
availability of capacity and pricing transparency, really
And so our experience
10
created concerns that we think will only continue as we
11
encounter additional extreme weather events going forward.
12
13
MR. WHITMAN:
Thank you.
I'd like to --
Commissioner Christie has a follow-up question.
14
COMMISSIONER CHRISTIE:
15
for Dr. Patton if I could go to Dr. Patton.
16
your last comments you talked about the importance of
17
scarcity pricing in the energy market, and then you also
18
talked about the importance accurately of accrediting
19
capacity in the capacity market for reliability.
20
Yeah.
I have a question
Dr. Patton in
At the very end of your comment you said we also
21
need to extent the principle to transmission.
Would you
22
elaborate on that?
23
said, just tell us more about your idea about extending that
24
principle to transmission please.
25
DR. PATTON:
I didn't quite get it all from what you
Yeah, so unfortunately almost none
37
1
of the compensation that transmission owners get is
2
market-based, it's all embedded cost recovery through
3
regulated rates.
4
things to increase the transfer capability on a constraint,
5
they don't benefit from doing that.
And so if transmission owners can do
6
If conversely, on the other side of the coin if
7
they take outages at very bad times, and it creates severe
8
congestion, there's no real harm to them doing that.
9
there will be market effects for instance, the RTOs all sell
Now
10
financial transmission rights.
11
things in different markets.
12
FTRs in a lot of other markets.
13
transmission owner reduces the capability by taking outages
14
is large here and woe them, potentially fail to be able to
15
collect enough congestion to pay the transmission rights.
16
They're called different
They're TCC's in New York and
And what happens when a
So you may find on a particular path that the RTO
17
is 5 million dollars short of what they would need to pay
18
those transmission rights because they can't honor them
19
because the transmission owner took an outage.
20
York some of that 5 million would be allocated back to the
21
transmission owner who took the outage.
22
So in New
So that's an example of one small way that
23
transmission owners in one location are being exposed to
24
market incentives.
25
brainstorm how to potentially give them access to some
But I think you know we could definitely
38
1
market incentives because even when we talk about for
2
instance your transmission incentive ideas and policies and
3
MOPR and so forth, it's all sort of characterized as should
4
we increase or decrease the rate of return that transmission
5
owners receive, which is all back in the sort of embedded
6
costs mindset.
7
There's no real discussion that we tend to put
8
these on our comments of finding ways of delivering
9
market-based revenues to transmission owners to try to start
10
to give them better incentives.
11
So make's sense.
COMMISSIONER CHRISTIE:
Well I think it's the
12
start of a discussion.
I've love to hear more from you if
13
you want to follow-up on that after this, and scope out an
14
actual proposal and
15
interesting concept.
flush that out.
16
DR. PATTON:
17
MR. WHITMAN:
18
COMMISSIONER CHRISTIE:
19
MR. WHITMAN:
Yeah sounds good.
Thank you.
Thank you.
Getting back to going back to our
20
questions on situational information.
21
Wes.
22
Renuka's.
23
I think it's a very
If you have a comment?
MS. CHATTERJEE:
The next person is
Okay let's move on to
Thank you.
Fuel availability
24
is one I think that has a lot of attention as it is under
25
the electric gas coordination.
As of now MISO conducts an
39
1
annual winter fuel survey assessment that allows us to
2
collect some information on you know fuel availability,
3
specifically with regards to actual gas availability.
4
And honestly I mean, thinking about fuel
5
availability for gas and coal is no different than how you
6
think about the emphasis on wind and sunshine, for wind and
7
solar resources.
8
who should ensure fuel availability.
9
That said, you know how do we think about
Today all we see as an RPO is to the market
10
offers, so if the generator tells us it's available at a
11
certain cost then we know that they have fuel behind it.
12
assume they have fuel behind it, but if we learn something
13
from the arctic event and prior cold weather events we will
14
work with members one on one to make sure that we would
15
issue them starts so they can procure gas.
16
I
Many years ago the Commission led the charge on
17
aligning the electric and gas coordination timelines that I
18
think is paying off now.
19
in the more forward looking we get, two day ahead, three day
20
ahead timeframe to think about how do we improve the fuel
21
availability, fuel certainty so we can count on the
22
resources appropriately?
23
We probably need more coordination
Again you know it's not to say that the RTO
24
should have their own forward manager and fuel
25
availabilities.
They keep talking about how do you ensure.
40
1
Lastly, on that particular one that increasing renewable
2
resources, you know if you put in a requirement for a
3
forward fuel transport, and the gas unit is only going to
4
run a few times a year, then it's not the cost effective
5
way.
6
So I think there's a lot of debate and discussion
7
to be had around how do you ensure efficient fuel
8
availability for the times when you need.
9
for discussion in the investment.
10
MR. WHITMAN:
11
12
Thank you.
I think that's up
David do you have
additional comments?
DR. PATTON:
Yes.
So I echo a lot of the
13
comments that have been made, especially Amanda I thought
14
made some really good points on transparency and the need
15
for transparency.
16
the gas procurement and trading that takes place is I think
17
okay to get non-stressed days, but it lacks the amount of
18
coordination you need when participants when gas starts to
19
become scarce and participants are trying to acquire it and
20
allocate it, the gas trading that currently takes place is
21
really not very good.
22
dramatic spikes in gas prices, and then when the psychology
23
changes, and the concern over gas availability goes down gas
24
prices tend to drop like a stem.
25
I think a couple things I would say is
And it is the reason why you see
So that signals that we could do a lot better at
41
1
coordinating gas and particularly pipeline capability.
2
Although it doesn't require the same degree of coordination
3
that the delivery of electricity does because the physical
4
characteristics of delivering electricity are far more
5
complicated and rigid than gas.
6
control over gas delivery.
7
You have a little more
But still I think it would be very useful to
8
think about can we improve how we coordinate gas trading and
9
the dispatch of gas around the system.
The idea of a gas
10
RTO function would deliver huge benefits in the sort of
11
tight gas conditions, and I know the pipelines probably
12
would not be crazy about that, but nonetheless it would be
13
extremely valuable.
14
And one final comment just in terms of like
15
short-term improvements.
16
over weekends is -- well surprising.
17
inflammatory words, but it is surprising to me.
18
at the arctic event it happened over a weekend, a holiday
19
weekend, so participants were in the position of having to
20
procure and buy themselves gas on Friday that extended all
21
the way until Tuesday which was made the whole management of
22
the gas suppliers you know far more difficult than it needed
23
to be.
24
25
The idea that you don't trade gas
I could use more
If you look
Because it's really hard to figure out I think
when you're trading on Friday what you're going to need
42
1
three days later. Okay, that's all my comments.
2
MR. WHITMAN:
3
MS. BRODER:
Great, thank you.
Thank you.
Robin?
I think my fellow
4
panelists have done a great job of talking about the
5
difficulties with the gas interface and the continued
6
challenges there.
7
of the question and talk about some work we're doing in
8
EPRI, the control center of the future, and focusing more on
9
that end on what that control center will look like.
But I wanted to address the second half
10
And so one of my colleagues has been looking at
11
increased situational awareness in the control center, and
12
especially to do with alarms, standards and philosophy.
13
especially as more information is going to be coming due to
14
renewables and DERs on the grid, improving the way that
15
operators are able to see this information on any amount of
16
information available to them.
17
And
In the opening remarks that I submitted I
18
encouraged people to go look at some of the information we
19
have there in some of the reports that are available to
20
anyone.
21
are looking at you know is increasing the amount of weather
22
information.
23
electric utilities operations, an so having some simple
24
information available and especially the interchange
25
between transmission distribution, customers, distribution,
And basically, some of the focus that my colleagues
This has really been at the core of you know
43
1
transmission and gas and transmission.
2
And we're encouraged with what's coming up with
3
FERC Order 2222 in this regard.
4
that we're also doing here is looking, developing a tool, a
5
system resiliency evaluation methodology and tool, and
6
basically helping system operators evaluate how at-risk
7
their systems are for these extreme events, and the
8
potential to really expand this across different domains.
9
I'm think about cascading events, or N minus X events.
10
And so one of the things
And this is in early stages of research at the
11
moment, but we're encouraged to move forward, especially as
12
you know, the different resources on the grid and improved
13
DER.
14
remarks that I submitted for more information on our
15
controls of our future work, thank you.
16
And so this is again I encourage you to look at the
MR. WHITMAN:
Thank you Robin.
Wes, do you --
17
you had your hand up earlier on our question related to
18
control rooms and situational awareness?
19
MR. YEOMANS:
Yeah thanks.
I apologize.
I don't
20
know how I dropped off, and actually I lost a little time
21
because I thought the problem was the same.
22
it may yeah, just coming back to what I believe is question
23
three regarding critical gas electric loads and we're all
24
paying attention closely to what happened in ERCOT, what we
25
can learn from that.
But be that as
But quite frankly, in the last five or
44
1
ten years we have gone to the New York gas company really
2
focused in our states more than once, a couple times, to
3
talk to them about their compressors and motor generated,
4
motor driven compressors versus gas turbine driven
5
compressors.
6
And gone back to the electric utilities to make
7
certain that those large important interstate gas pipeline
8
compressors are not on the utility load shed scripts, or
9
lists I should say.
So we're pretty confident on that.
But
10
to be quite frank I think there's an opportunity for us to
11
go back and ask more questions, first of all not just the
12
electric motor driven compressors, but the gas turbine
13
driven, and other auxiliary type equipment that if their
14
start up generators needs start that they rely on utility,
15
and let's make sure they're not on the load's shared script.
16
And maybe even other stations, taps, or just
17
other types of gas stations.
18
electric industry to really again ask for a comprehensive
19
list of critical loads, and then go back to the utilities
20
and make sure those account, and those services are not on
21
the load shed script, so that's very important, so yeah
22
thanks, I just wanted to offer that.
23
So we're going back to the
MR. WHITMAN: Thank you.
If there are no other
24
comments I want to ask if the Commissioners have any
25
questions at this time that they would like to ask.
If not,
45
1
we'll go on to our next question.
2
CHAIRMAN GLICK:
Peter this is Chairman Glick.
3
appreciate the opportunity here, and I noticed that the
4
questions here -- there's many questions and they're all
5
really good.
6
interest of time maybe we can make sure.
7
in the last question in particular, and if it's okay with
8
you to jump to.
9
I was wondering if it's possible just in the
I was interested
And more specifically demand response.
You know
10
I think we saw in the California situation last August
11
during extreme temperatures that demand respond played a
12
very significant role in keeping the lights on, and for
13
those days of rolling blackouts to eliminate the impacts.
14
I
I'm curious if the panelists have some
15
suggestions about what we might need to either from a FERC
16
policy perspective, or at least from RTOs and the way they
17
operate the markets.
18
encourage to facilitate their response during extreme
19
weather conditions.
There's more that needs to be done to
20
MR. WHITMAN:
Okay let's start with Anne then.
21
MS. HOSKINS:
Sure and hello Chairman.
Nice to
22
see you.
So I spoke earlier about the California situation.
23
I don't know if you were on at that time, but you know
24
clearly that was something I'm calling in from California,
25
so something you know very much on our minds right now as
46
1
we're now in fire season again.
2
And you know I do think as I mentioned earlier
3
you know, demand response or just calling on demand side
4
resources.
5
figure out some compensation for it, but you know, and I
6
know there's efforts underway, but it really needs I think
7
additional attention, and you know perhaps support from FERC
8
would be helpful on that front.
9
There is more work that needs to be done to
But I've also heard going forward in terms of how
10
this is all going to work is that there are some metering
11
and telemetry issues that you know we can turn some
12
information in on that you know as we start to look at how
13
you really are -- particularly if you're going to be able to
14
compensate these resources.
15
You know making sure, you know in our situation
16
right we have individual homeowners, and we are able to
17
aggregate those systems and serve as a third party
18
aggregator.
19
lot of you know complicated interconnection roles that are
20
impeding this as well as extra metering requirements when we
21
believe that there are many opportunities for submetering
22
that could really make sure that the flexible resources that
23
are there can be utilized.
24
25
But we want to make sure that there aren't a
So you know I'd be happy to you know send some
additional information in on that, but that's what I
47
1
understand is the combination of just a lack of compensation
2
mechanism as well as some sort of technical metering issues
3
that if we could work those out could really make a big
4
difference, and it is going to be critical again this summer
5
we're sure.
6
Everything we're hearing about is that you know
7
we have very dry conditions, and you know a lot of concern
8
about what's going to happen with the wildfires as we go
9
into the summer.
So thanks for asking.
10
MR. WHITMAN:
Thank you.
Next Amanda please?
11
MS. FRAZIER:
Thank you Chairman for the
12
question.
13
And one of the things that I know is most important and from
14
my perspective is making sure there's a pathway to get the
15
incentives all the way from the wholesale market to the
16
retail customer.
17
I think it's an important one and a good one.
And I think this Commission has done a nice job
18
in promoting demand response and creating orders that
19
facilitate additional demand response.
20
needs to be coordinated also, and I'm sure that there are
21
state utility commissioners listening as well, that needs to
22
be coordinated from the state's perspective to make sure
23
that there are products that can be developed that get the
24
benefit to the customers.
25
But you know that
So for instance, you need to have as a retail
48
1
supplier, you need to have the ability to get access to the
2
customer's information in relative near real time, so that
3
you can understand their usage pattern.
4
product that is cost-effective to the retail supplier, but
5
also beneficial to the end use consumer.
6
You can design a
And then once you have that type of information
7
you can structure a product that will pass those incentives
8
down to the customer.
9
know retail businesses here where we do have demand,
As an example, in Texas we have you
10
voluntary demand response offerings that we give to the
11
retail customers, and they can get paid to curtail, you
12
know, at our request.
13
We can offer additional you know benefits for
14
compensation if they choose to respond to a voluntary
15
curtailment, and a lot of times customers will actually
16
respond on their own just as a good citizens.
17
the information that they need about when conservation is
18
required, and why it would be helpful.
19
If they have
Because it's you know there are more
20
complications in getting that information to the retail
21
customer, I think you see in the development of demand
22
response really proliferate in kind of the industrial space
23
because they have access to the wholesale market, so they
24
can get those benefits directly, and they can participate
25
directly with the wholesale market.
49
1
As connecting back to the last question, another
2
issue that we saw pop up in the February event in ERCOT that
3
is something that probably all RTOs need to consider going
4
forward was there was actually demand response from critical
5
infrastructure, so critical gas infrastructure was committed
6
to provide demand response product through the wholesale
7
market, either in the form of an ancillary service or a
8
reliability service.
9
And because of that they were incentivized --
10
required really, obligated, to curtain their load in
11
response to the call for conservation, and it created this
12
new loop effect where they weren't able to you know produce
13
gas and put it on to the system.
14
So there should be some oversight from the RTOs
15
and ISOs to make sure that we're not creating a situation
16
where demand response is cannibalizing a critical fuel
17
support of infrastructure needed to deliver power reliably.
18
MR. WHITMAN:
Great thank you.
I think that's
19
actually a really good point that we hope to get back to
20
later on.
21
Next is David, and then following Ms. Renuka.
DR. PATTON:
All right.
I'm going to shock you
22
all by telling you how important shortage pricing is in this
23
regard.
24
roads lead back to shortage pricing.
25
Now I don't want to beat a dead horse, but and most
If we intend to properly compensate a lot of the
50
1
responses either to intermittent resource output dropping
2
off unexpectedly, or extreme events, or other factors that
3
can threaten reliability, the price we set during the event
4
in real time becomes a critical component of the incentives
5
that you give folks to make the kind of decisions that you
6
want them to make.
7
And in this case we're talking about demand
8
response, which I think is incredibly valuable, and if we
9
can get most of the incentive for demand response embedded
10
in the energy price, rather than the capacity market I think
11
we'll be far ahead in terms of providing good incentive for
12
flexible demand response.
13
What happens when you try to pay them in the
14
capacity market is they accept an obligation.
15
really want to curtail, and it turns out that at least in
16
MISO and some other places, the ability to utility demand
17
response is significantly reduced because often they
18
indicate they need a relatively long amount of time -- of
19
lead time, to be told that they're going to be needed to
20
curtail.
21
They don't
And often times the extreme events, or the
22
emergencies happen with only an hour or two notice, or even
23
less than that sometimes.
24
cases we've looked in MISO and the amount of the demand
25
response that they purchased in the capacity market versus
So then you know in a lot of
51
1
the amount they've been able to utilize have been very, very
2
different.
3
And they're making some changes to improve that,
4
but I think there's an inherent problem in relying on
5
compensation in the capacity market, rather than through the
6
energy market where they get paid when they help, and they
7
don't get paid when they don't help.
8
9
I do think to the maximum extent possible
treating, trying to get them settled on the demand side is a
10
big improvement over settling them as if they're a supply
11
resource.
12
all demand response as a market monitor we're continuing to
13
see problems with trying to establish baselines and seeing
14
cases where the demand response resources are establishing
15
baselines that don't reflect the amount of load they're
16
actually going to be able to cut when you get to the point
17
of calling them.
18
19
I don't think we can completely do that, but for
So having them be on the demand side eliminates
that particular issue.
So those are my comments.
20
MS. HOSKINS:
Can I follow-up to that, or?
21
MR. WHITMAN:
Sure.
22
MS. HOSKINS:
Oh great, thanks.
Yeah, and there
23
are a few things there that I feel like I have to respond to
24
from the demand side.
25
working with solar and batteries and aggregating them, which
One is that you know when you're
52
1
is what we're dealing through virtual power plants, and even
2
through the bid that we made that was accepted in New
3
England ISO a few years ago, is one of the benefits is it's
4
not like typical demand response because we are able to work
5
through the thousand or so units that we've aggregated
6
together, and customers can continue to have access to
7
power.
8
9
It's not an either/or choice.
It's not as though
they have to agree that they're not going to have their air
10
conditioning and give up their power.
And I know as a
11
former regulator that was a concern after a few times right.
12
You might get you know customers getting a little concerned
13
the third or fourth time they were called.
14
But that's not the situation here.
15
the analytics now that we are able to optimize, make sure
16
that there's enough left in the battery for the customer,
17
and then you're able to share the other power.
18
a firm capacity resource, and I think it's really important
19
that people understand that, but this is not your typical
20
demand response.
21
And we've got
And so it is
So that's number one.
And secondly, I don't think this is something
22
that has to be kept on the demand side, and we've certainly
23
seen in New England ISO they are counting this as a capacity
24
resource.
25
telemetry and the metering is that we do have the ability.
But also one of the reasons that I mentioned the
53
1
We agree, we should not be using baselines.
You
2
know we think that that's really kind of old school.
3
we have the technology now.
4
inverter how much power is being shared, when it's being
5
shared, and so I think that we just need to move beyond that
6
and recognize that we have the technology, we have the
7
customers that want to participate in this.
8
9
That
We can meter exactly from the
There's a very important role for aggregators to
make sure that there is the ability to respond to signals,
10
and you know I certainly am hopeful that you know during the
11
2022 process and otherwise that you know people can learn
12
about the opportunities that are out there now with this
13
technology, and we can find a way to make sure that it's
14
really brought into the markets, thanks.
15
MR. WHITMAN:
Thank you.
16
MS. CHATTERJEE:
Next Renuka?
Thank you.
I would build upon
17
what Anne and David have said.
18
response I think about it as the last step before you're
19
going to control load shed right, so it's really important.
20
And it's best to think about demand response in three
21
different categories.
22
demand response.
23
When I think about demand
The first one being very sensitive
So much to Anne's point you know you could design
24
this product for you know it could respond to parties, it
25
could have specific performance expectations and it's a
54
1
known quantity you get in a known amount of time, so 30
2
minutes, two hours, the entire time.
3
The second category being demand response behind
4
emergency declarations.
5
responses behind emergency declarations and somewhere
6
between 12 to 14 gigawatts to be precise.
7
quantity of demand response, but the trick is forecasting
8
emergencies 12 hours, 24 hours in advance, and calling upon
9
these and actually making sure that it's available, that
10
11
So much of my system demand
So it's a large
it's actually running so the demand can be used.
And the last category of demand response tends to
12
be this voluntary you know load reduction of public appeals
13
and most processes, all of the RTO processes I'm familiar
14
with it's too late in the process.
15
minutes before load sharing we're going out and asking for
16
public appeals, we are relying on the public to reduce the
17
demand, you know, in short time.
18
You know just before, 30
Most of the public may not be even paying
19
attention to some of these announcements.
So this gets to
20
be the most variable or unknown quantity.
You could get a
21
lot, or you could get nothing.
22
that perspective.
23
It's pretty subjective from
So pushing more demand response into that price
24
sensitive category with the distributed energy resources
25
type products I think is one way.
We also should look at
55
1
how do you improve the demand response that's only available
2
and under emergency condition.
3
Some of it will still be available just because of how the
4
industry works.
5
You can't eliminate it.
How do you improve its performance, and lastly
6
how do we leverage public appeals.
7
through a number of emergencies of MISO's it too late in the
8
process, and there's not enough time for the consumers to
9
react and the market to respond before you go to load shed.
10
11
12
MR. WHITMAN:
Thank you.
My experience sitting
Let's go to Mads and
then Amanda.
MR. ALMASSALKHI:
Thank you for the invitation.
13
And I know I've jumped in a little bit late, but that's
14
basically -- I appreciate the comments so far, which in my
15
mind have really focused on the fact that you know through
16
the first three questions we've really been focusing on the
17
need for being more dynamic, be more responsive.
18
And I spent the last 10 years or so looking at
19
distributed energy resources.
20
of misconceptions.
21
electricity industry, that somehow demand response has to be
22
this big hammer when actually today through analytics,
23
optimization and advanced control technology, it's really
24
becoming acceptable.
25
It sounds like there's a lot
Unfortunately still rummaging around the
And what we're looking at today is you know
56
1
terawatts of renewable generation will require gigawatts of
2
flexible energy, or flexible demand.
3
demand can really help us respond to certain limited
4
capacity on the transmission system, because distributed
5
energy resources are everywhere.
6
And that flexible
And so you can have distributed energy resources
7
responding in certain regions as storms come in, which means
8
we can use these control algorithms that manage thousands of
9
millions of devices to prioritize critical loads, by
10
deprioritizing non-critical loads.
11
dynamically.
12
we have sufficient submetering available to us through very
13
cheap sensors over the last 10 years.
14
And we can do this
we can do it in real time.
And in most cases
So really go beyond baselining and really talk
15
about how do we provide firm resources up front that can
16
help during the short bursts -- I think let me just see the
17
name, apologies, so this is David's shortage pricing which
18
is you know DERs are well-bred for this purpose.
19
And I also want to point out that the comment
20
around DR, dynamic demand response today you know, this is
21
not your parent's DR anymore.
22
flexible and nimble resources, which is why I'm super
23
excited to represent you know not just the University of
24
Vermont.
25
National Lab, you know, which has been the first place of
We're really talking about
I'm not just representing Pacific Northwest
57
1
transactive energy, but I'm also representing a small
2
startup company in Vermont called Packetized Energy which
3
has a platform for DERs called Nimble, which is really
4
illustrating that DERs today are not the hammer of
5
yesterday.
6
It's really a scalpel that can provide localized,
7
specific, and very fast services based on the needs of the
8
grid for the markets.
9
MR. WHITMAN:
Okay thank you.
10
MS. TOPPING:
All of this feedback has been
11
really helpful.
12
question because I believe we've gotten a lot of looking
13
back to some, but not to the later part of the question as
14
much, so I'll read that right now.
15
I'd just like to read the entirety of the
What are the most effective means of engaging
16
flexible demand to mitigate emergency conditions?
17
methods to improve the use of flexible demand in addition to
18
the solicitation of voluntary load reductions through mass
19
communications during extreme weather?
20
Are there
Do existing interoperability and communications
21
standards
enable robust participation of flexible DR to
22
address climate change and extreme weather challenges, or is
23
it more consensus-based standards development work needed by
24
the relevant stakeholders?
25
like to speak next?
And let's see David would you
58
1
DR. PATTON:
Sure.
Okay so a couple things,
2
there are a couple other responses to my comments, and I
3
think I don't disagree with either of the responses by Anne
4
Hoskins or Mads.
5
those look an awful lot like supply resources to me, even
6
though they're DERs.
7
I think in the case of solar and batteries
I think not mixing up controllable supply that
8
happens to be distributed, versus true demand responses is
9
pretty important.
But even with the demand response,
10
whether you're talking about supply, or to demand response
11
in the kind of optimizable very controllable demand response
12
that Mads was talking about.
13
I think in both cases something that we're going
14
to need to see to be able to improve on is recognizing
15
locationally where it is and delivering locational price
16
signals that would compensate those resources accurately
17
depending on where they're located.
18
compensation would be the same regardless of whether
19
located if we're having a market-wide shortage.
20
Sometimes that
More often it's going to be the case that we have
21
very specific locations where we're having reliability
22
problems, and congestion that the ability to access those
23
resources will, I agree with you, be extremely valuable, but
24
we're not quite there yet in terms of having enough
25
visibility on where they're located in order to settle with
59
1
them accurately, which I think is in the best interest of
2
the DERs, and the RTOs.
3
And with regard to shortage pricing I think the
4
reason I keep bringing that up and I think Mads sort of
5
referred to this is that very predictably when we're headed
6
into an emergency, and we're running short of reserves like
7
demand response is not a cheap way to get energy or
8
reserves.
9
But when we start to go short it can be far
10
cheaper than the marginal value of our reserves.
So if our
11
prices for example predictably are going to rise from 500 to
12
1,000 to 2,000 to 8,000 dollars, and you have because you
13
can control the DR very specifically and rotate it, you have
14
customers that are willing to respond at let's say 200
15
dollars a megawatt hour, or 300 dollars a megawatt hour.
16
They can receive very strong incentives to
17
contribute to reducing the shortage if we in fact our
18
pricing shortage is efficiently.
19
we're in a shortage, but we're pricing it at 80 dollars,
20
then that severely limits the ability to provide good
21
incentives to the DERs to help us in those circumstances
22
which is why emergency pricing and shortage pricing are so
23
important in the near term.
24
25
If on the other hand,
And as we head towards a system with more and
more intermittent resources and more uncertainty around
60
1
their output.
2
MR. WHITMAN:
3
MS. BRODER:
Thank you.
Robin?
I think this has been a very
4
interesting discussion, especially thinking about the
5
uncertainty of output of these resources, and thinking of
6
that I wanted to mention that there is an RB program that's
7
looking to address some of these issues.
8
program called perform and which is really looking to how
9
can we as you know the power industry address uncertainty
10
11
RB put out a
and delivery risk.
And that especially is focused on many aspects of
12
the demand side and DERs.
13
ourselves are part of one of these teams and there's 11
14
other teams that are really looking at developing
15
algorithms, software, even hardware that's aimed at trying
16
to assess the uncertainty risk of sometimes it's assets,
17
sometimes it's clusters of assets, and being able to give
18
those kind of algorithms to aggregators, to potential BSO's
19
or even to the ISO's in order to help manage that risk.
20
It so happens that Packetized and
And so of course this is in the early stages,
21
research stage not yet in development.
The teams have been
22
working this year, and for the next two years on how can we
23
solve these issues.
24
really bringing in concepts from the finance and insurance
25
industry into the power industry, and looking at how we can
One of our proposals is
61
1
assign risk scores, so that either aggregators or other
2
people who are looking at these different resources can say
3
well I know with some certainty that this resource can
4
provide me what they want, or they would need to be
5
discounted a certain amount.
6
And so I think this is an area of ongoing
7
research, and there's many different aspects and dynamics
8
that go into that, but many teams, and I know many of the
9
ISOs are involved in different teams, and so I'm looking
10
forward to this research.
It should be pretty interesting
11
in how we can incorporate the concept of risk in order to
12
firm up the uncertainty that some DERs can provide, thanks.
13
MR. WHITMAN:
Thank you.
Anne next please.
14
MS. HOSKINS:
Thank you.
So I just wanted to
15
mention that you know there are programs now on the state
16
level that are actually trying to give incentives
17
locationally, and so some of those are really happening up
18
in New England.
19
where not only is there sort of an upfront incentive for
20
customers to get a battery, then there's an incentive when
21
they show up, when they're called, but then there's an extra
22
incentive if it's in a particular area that has a
23
constraint.
24
25
I know that Green Mountain Power has one
So I you know, have people take a look at that.
But there are also programs in Massachusetts.
There's a
62
1
clean peak program now as well as just the smart incentive.
2
So certainly there have been efforts I think on the part of
3
some states to try to see how can they not only incentivize
4
customers to invest in batteries, but also to make sure that
5
they have asked to participate when needed, but that an
6
additional incentive, or a focus incentive based on location
7
or time.
8
9
So I do think there's some good examples out
there that we can learn from.
10
MR. WHITMAN:
Thank you.
I think we'll move away
11
from this topic temporarily to Commissioner Clements has
12
some questions.
13
COMMISSIONER CLEMENTS:
Thank you Peter.
That
14
was a really interesting dialogue, so I appreciate all those
15
inputs.
16
conference on just that question.
17
way from the smallest, cheapest resources up to the biggest
18
most expensive, and talk about interregional transmission.
19
We could probably hold a whole other technical
I'm going to go all the
Mr. Patton mentioned a few things about
20
misalignment of market of the incentives for transmission to
21
participate more dynamically, and I also share Commissioner
22
Christie's enthusiasm for learning more about that.
23
Yesterday there was some conversation about the value of
24
increasing transfer capability across interregional
25
transmission, and Ms. Chatterjee, in your pre-comments for
63
1
this technical conference talked about the value of RTOs as
2
a resilience platform, and the opportunity for improving
3
seams, redispatch and other coordination in a manner that
4
helps to improve reliability and resilience.
5
So I'm curious if you could say a little bit more
6
about that and also talk about -- let me make sure that I
7
got everything that I wanted to ask.
8
that might be involved in coordination at the seams with a
9
neighboring RTO versus a neighboring non-RTO balancing
10
And the differences
authority.
11
MS. CHATTERJEE:
Sure.
Thank you for the
12
question Commissioner.
13
RTO's, particularly MISO.
14
be noted in our post-February event presentation was how the
15
RTO was able to enable flows from the west to east, the
16
typical you know, sorry from east to west.
17
With regards to the you know the
One of the things that needs to
Given the south and west portion it was like this
18
drain hold from power, a lot of power needed to get there
19
because of the cold weather.
20
had not seen in 14 months, and I say 14 months only because
21
we didn't look beyond that.
22
And we had observed flows we
The transmission system was carrying 40 percent
23
more loading than we had seen, which means the system was
24
capable.
25
we addressed during the February arctic event, but the
We did have a handful of transmission events that
64
1
transmission really supported a lot of power flows going
2
across the system.
3
So again as I mentioned earlier, certainly you
4
could have local generation, but you want to have options to
5
the situations to transfer power.
6
from 10,000 megawatts to 14,000 megawatts, not just to
7
support MISO, but to support to the rest of the MISO.
8
9
PJM was sending anywhere
So there was a lot of power transfer that was
occurring, and all of this is in large part due to the
10
transmission that was available in between to make those
11
transfers feasible.
12
renewable integration and portfolio evolution.
13
looking at a pretty aggressive transmission plan that we put
14
out there, and again that goes to support -- that's not the
15
primary driver, the best way to think about it is when
16
you're building transmission, when you're thinking about
17
what are the business uses on reliability and efficiency in
18
extreme arctic weather events, or extreme weather events.
19
Now fast forward as we look into more
We are
All transmission and all generation is supporting
20
reliability.
21
was trying to have their own personal economic gains.
22
Everyone was trying to support the availability of power
23
where it was needed most.
24
25
It's not about you know no one in the event
With regards to you know ISOs an RTOs are market
sources non-markets.
I'll make a couple of points.
First
65
1
when we are trying to negotiate seams agreements between
2
ISOs and RTOs I think the Commission led the charge many,
3
many years ago I believe in 2004 and 2005 timeframe, that
4
has led to what I would call state of the art coordination
5
between the markets, between PJM, MISO and SPP we have a
6
really advanced mechanism for economic congestion
7
management and support for each other.
8
9
So you know again those were significant steps
forward in ensuring that the benefits of interconnection
10
outweigh the pain of interconnection.
11
about market to non-market seams, the negotiations go much
12
slower, and if you think about those the RTOs and ISOs are
13
optimizing policy across multiple members so the diversity
14
of the footprint within each ISO/RTO allows us to come up
15
with a little bit of a flexibility in how you negotiate.
16
Now when you think
When you are negotiating with a non-market entity
17
which is actually the entity itself is its own policy, so
18
it's harder to find a compromise.
19
sort of you know David and I were talking earlier today.
20
said performance, but some basic mechanisms or standards for
21
seams coordination of the operational timeframe would be
22
helpful.
23
So going forward some
We
Otherwise we are trying to negotiate you know the
24
negotiations to achieve reliability cannot be done without
25
discussions on efficiency and liquidity, and those
66
1
discussions are taking a really long time.
2
flow visualization effort that was led by NERC is finally
3
going to give us more transparency to some of the flows on
4
the interregional flows.
5
The parallel
But again that itself took almost 10 to 12 years.
6
You know I was an engineer when that project started many,
7
many years ago.
8
velocity because the change with which -- or the force with
9
which the variables and the DERs are coming forward, we
So anyway, jokes aside, it's hardly
10
can't afford to take 10 years to get those seams implements
11
in place.
12
13
14
MR. WHITMAN:
Thank you.
David you had some
comments?
DR. PATTON:
Sure.
Yeah, I think this is a great
15
question because given the configuration of the RTOs and
16
non-RTO areas, there are, especially during emergencies, but
17
even not during emergencies there are significant affects
18
that the systems have on each other.
19
And Renuka is right that PJM, SPP and MISO have
20
implemented market to market coordination that you know
21
frankly without it I don't know how they could dispatch
22
their systems very efficiently because they cause so many
23
flows on each other's systems, but with non-market areas we
24
haven't been very successful as an industry of getting
25
agreements in place to coordinate the dispatch of generation
67
1
2
to where we're affecting each other's systems.
So for example, ACI, TCI, TDA, both of these are
3
areas that non-market areas, even Southern Company, that
4
create significant flows on MISO's system where we incur
5
much higher costs because there's not a good way to
6
coordinate adjustments to the dispatch of those non-market
7
generators to efficiently manage congestion.
8
9
And again, as I said earlier, things that raise
economic costs during normal conditions raise reliability
10
issues during more extreme conditions.
So we're impact
11
reliability, and so we've been recommending those sorts of
12
seams agreements for maybe a decade, and I think Renuka's
13
right, it's very hard to bring them to fruition.
14
But I think one thing the Commission could really
15
do that would be helpful is require seams agreements between
16
all of these areas, and we'll need some minimal standards.
17
And those minimum standards would include coordinating the
18
relief of congestion.
19
in the FERC limit tariffs required redispatch service to
20
allow transmission service to continue to be supported, but
21
personally I'm unaware in non-market areas of any
22
redispatch that's actually being provided in order to supply
23
transmission service.
24
25
You have in some places required, or
So maybe making that a mandatory requirement, and
so that would be one element of a seams agreement is joint
68
1
congestion management.
2
and exports between neighboring RTOs or non-RTO areas.
3
That's one area where I think there's a disturbing lack of
4
coordination.
5
The second would be managing imports
I mean the operators tend to get on the phone and
6
talk to each other and try to figure out what to do, but at
7
the end of the day we sometimes see very bad decisions being
8
made unilaterally by RTOs that have bigger effects on the
9
other side of their seam than they do in helping them.
10
So I won't name any RTOs in this regard, but I
11
would say all of the RTOs we monitor could do a better job
12
of explicitly coordinating imports and exports to try to
13
maximize the reliability of the interconnect.
14
those sorts of agreements won't come about unless they're
15
required by the Commission.
16
MR. WHITMAN:
Thank you David.
17
MS. FRAZIER:
Thank you.
But I think
Amanda?
And just to connect the
18
dots.
19
that the Commission has in front of it on dynamic
20
transmission line ratings.
21
transmission operators coordinate those dynamic line ratings
22
at the seams could be an easy and cheap way to make sure
23
that you're optimizing transfer capability between the
24
regions as well.
25
The dots between this question and open rule making
MR. WHITMAN:
You know I think having the
Thank you.
Commissioner Clements
69
1
do you have additional comments or questions?
2
COMMISSIONER CLEMENTS:
Thank you for those
3
answers.
4
hold it if other Commissioners want to jump in.
5
last question is two parts.
6
lot of market participants took on risk exposure and then
7
they, excuse me, they suffered financial losses.
8
9
I have one more question Peter, but I'm happy to
Okay.
The
In Texas we saw that you know a
And the market incentives therefore were not
sufficient to incent kind of their range of actions that
10
were after the fact identified as contributing to what took
11
place there in February.
12
are within the Commission's jurisdiction, and for that part
13
I'm wondering if you all have a perspective on how we
14
approach the choice between market incentives and standards,
15
and standards/requirements I guess to arrive at an optimal
16
mix.
17
So some subset of those actions
Appreciating we probably need some amount of
18
both.
19
not within the Commission's jurisdiction like the lack of
20
weatherization, or issues on gas production practices that
21
don't account for extreme weather.
22
And then there's a second subset of issues that are
And so in those cases, and in our limited
23
jurisdictional reach, are there ways the Commission can
24
nevertheless encourage or incentivize those players to get
25
at some of these concerns?
And I would like to hear from
70
1
market participants as well as others.
2
MR. WHITMAN:
3
MS. FRAZIER:
Okay.
I'll start because my company
4
incurred about 1.6 billion dollars loss as a result of the
5
February event.
6
we were fully hedged for our gas supply going into the
7
February week.
8
power plant's operation, but also to some cold handling, but
9
the majority of the problems that we saw were related to our
10
We are the largest generator in ERCOT, and
We had some weatherization issues related to
gas supply issues.
11
And so, you know I appreciate your question on
12
how do you balance the market incentives with the
13
requirements, and I think that it's important to have
14
requirements on both weatherization and preparation for
15
events.
16
reliability.
17
That's part of you know FERC's role in ensuring
That said there is no better incentive to be
18
prepared for a storm than very high shortage prices, and
19
exposure to those prices.
20
was that most of the weather issues that we experienced in
21
2021 were not the same weather events -- or weather issues
22
that we experienced in 2011.
23
And in fact what we experienced
Why?
Because we took you know a lot of actions to make
24
sure that we had address those things that were exposed by
25
our experience in 2011.
I expect that you will see us, and
71
1
others respond to what we learned through the 2021 storm and
2
make changes going forward.
3
That said, the second part of your question is
4
the one that keeps me up at night, and that is that there
5
were so many things outside of our control that impacted us
6
you know significantly in the event, and the largest one of
7
that is the gas supply issue.
8
don't have jurisdiction over gas and production, but you do
9
have jurisdiction over a lot of the pipeline issues, and
I agree with you that you
10
that's where you know many of the problems that we saw
11
occurred.
12
So I hope that FERC will take that opportunity to
13
review its jurisdiction seriously, and consider what changes
14
need to be made to ensure that we do have reliable fuel
15
supply going into the future events.
16
most important things and I think low hanging fruit from my
17
perspective is something that I discussed a little bit
18
earlier, and that's just transparency from the gas side.
19
You know one of the
If we know where the capacity on a pipeline is,
20
and we know you know what the prices are then there's the
21
ability to make a market.
22
important point around the gas trading limitations there.
23
It is insufficient to have to purchase gas for four days
24
going into a major winter event, and in fact we had you
25
know, we saw curtailment to our power plant even on some
I think Dr. Patton brought up an
72
1
contracts that we have days before the winter storm even
2
occurred because the gas wasn't going to be available to
3
trade with us during the middle of the storm anyway.
4
So those are all things that I think either you
5
do have jurisdiction that you can exercise, or you certainly
6
have influence that you can exercise in coordinating with
7
other agencies to address those problems and from our
8
perspective, from Vistra's perspective, that is vital,
9
especially going into a future of potentially more of these
10
types of extreme events, so thanks for the question.
11
12
MR. WHITMAN:
Thank
you.
Before we go to
Commissioner Christie, David do you have a response?
13
DR. PATTON:
Yeah sure.
I think it's a great
14
question.
15
that face market incentives if you price shortages
16
efficiently, and as I said earlier that's probably not the
17
case in most RTOs, but I think you'll get the responses from
18
those entities that you're looking for.
19
I think I agree with Amanda that the participants
I think the only -- I certainly don't think what
20
happened in ERCOT was an indictment of the market there.
21
think it's difficult when an event is that far out on the
22
tail of the probability to plan for it, or to respond to it.
23
So I think there were some companies that didn't adequately
24
prepare for that sort of outcome.
25
I
I think we saw a much bigger problem with public
73
1
entities than we did with either the competitive retail
2
loads, or the competitive generators.
3
rely to the maximum extent on market incentives, then
4
identify the entities that don't have good market
5
incentives.
6
as being a set of participants you should be concerned
7
about.
8
9
But so I would say
So I mentioned transmission owners a minute ago
Gas pipelines are another set of participants
that you should be concerned about.
I think in almost all
10
cases gas shortages are not shortages of supply, they're
11
shortages of pipeline capacity, delivery capacity to certain
12
areas, or the inability to fully utilize the capacity.
13
so that's why some form of improved coordination in how gas
14
is scheduled and delivered would be extraordinarily
15
valuable, whether it's a gas RTO model.
16
And
I know there would be tons of pushback because
17
when the gas pipeline system is not constrained it would be
18
hard for pipelines to charge much for delivering gas.
19
it is the one way that you would be able to ensure that
20
you're maximizing the throughput of the pipeline, and
21
minimizing the sort of fuel supply problems that Amanda was
22
talking about.
23
24
25
MR. WHITMAN:
Thank you.
But
Getting close to the
time, can we go to Commissioner Christie?
COMMISSIONER CHRISTIE:
Sure.
Dr. Patton I'd
74
1
like to ask you to follow-up a little bit and expand on you
2
said FERC should require RTOs to have seams agreements, and
3
the seams agreement should cover several topics.
4
down congestion and more efficient management imports and
5
exports.
6
criteria that you thought should be in the seams agreements?
7
And I got
Would you elaborate on I think you have some other
DR. PATTON:
Actually those are the two biggest
8
because they govern two things.
One is coordinating the
9
power flows where you have two neighboring entities that are
10
causing flows on each other's constraints, and then the
11
second is the broader movement of power from one region to
12
another, which may or may not.
13
They can sort of cross over because when you get
14
a lot of imports that could cause constraints that you're
15
going to have to work together to manage, so they're not
16
completely independent of one another.
17
thing I had mentioned was like if the power is coming from a
18
non-market area like the southeast for instance, if they hit
19
a constraint in the southeast then that power won't be able
20
to flow and actually make it to out let's say MISO.
21
But the only other
So some form of required redispatch for non-RTO
22
areas would be a third thing that would be extremely
23
valuable.
24
it's more about facilitating participant's ability to get
25
power out of the non-market RTO area.
So that's not as much about coordinating, but
75
1
When somebody schedules at a PJM or MISO, like
2
MISO and PJM will just naturally move the generators they
3
need to move for the power to escape their system.
4
pertains with non-market areas.
5
COMMISSIONER CHRISTIE:
6
DR. PATTON:
7
MR. WHITMAN:
That
Thank you.
Uh-huh.
Thank you Commissioner Christie.
8
We're going to go on to just because we have just a couple
9
minutes to briefly talk about question 5.
10
MS. TOPPING:
What best practices exist in the
11
use of innovative mitigation strategies such as controlled
12
sectionalization, microgrids in operations to reduce loss of
13
load and improve resilience during extreme weather events?
14
And let's see.
15
then Mads.
16
I see Anne's hand up.
MS. HOSKINS:
Terrific.
Let's go to Anne and
Thank you and thanks
17
again.
18
some developments that I think are really critical and very
19
much related to the potential for microgrids going forward.
20
I know we're about to close out here.
So we do have
You know in our view having a solar battery on
21
someone's house is essentially creating what you might
22
consider a nano grid right?
23
electrification, this is going to really increase both the
24
need for that source of power, that really local source of
25
power, but also the potential as we're able to start
And as we get greater
76
1
connecting these together, as we're starting to see you know
2
the multigrade chargers, other kind of electrification in
3
the home.
4
So we sort of look at that as the sort of
5
individual nano grid.
6
mentioned earlier is to connect those in the form of virtual
7
power plants.
8
works around the country with many more in the pipeline to
9
come.
10
But then what we're able to do as I
And we have about 12 of those already in the
Where we are working with utilities you know who
11
are making you know billions of dollars a year in upgrades
12
and investments in the distribution system to be a part of
13
that right?
14
a virtual power plant instead of you know developing new
15
plant, or in preparation for closing one down.
16
To be a solution where you might be able to use
And so I think that development where I know
17
other providers are also getting more engaged in that is
18
something to keep an eye out for.
19
interesting kind of approach which it's really much more in
20
early developing, but I think is really critical to be able
21
to work with, with utilities, is this idea of a neighborhood
22
grid.
23
And then the other
And you know I heard I think it was Mads earlier
24
talk a little bit about transactive energy and some of those
25
ideas, but really what the idea here would be is you have
77
1
you know a subset of the homes and businesses in a
2
neighborhood which could actually be fully disconnected from
3
the grid you know, linked to a substation where you would be
4
able to disconnect, not just at the home which we're able to
5
do now in this nano grid, but actually to disconnect a
6
segment of the grid.
7
And that's something that we haven't tried yet,
8
but we are working on it I think is an opportunity for any
9
state commissions that are listening to think about some of
10
the restrictions that get in the way of that where we're
11
restricted to be able to you know have power over different
12
geographies.
13
know, as we get into some of these larger reliability
14
issues.
But also potentially for FERC as well you
15
So in my view it's a really exciting opportunity
16
that we have now to really start to rethink as we're trying
17
to create a more resilient and reliable grid of how we can
18
really aggregate the investments and the resources that
19
people and businesses are putting on the network, thanks.
20
MR. WHITMAN:
21
and close out with Wes.
22
Thank you.
We'll have Mads next,
Mads?
MR. ALMASSALKHI:
Thank you Peter.
And thank you
23
Anne for raising really good points around DERs.
We are
24
ourselves a very small company, but I think when we go back
25
in Texas we saw some of the practices in place around the
78
1
rolling blackouts of how to manage certain extreme events.
2
If we were to pursue intelligent electrification
3
as an infrastructure, I think what we'll see is that these
4
rolling blackouts could not exist anymore because we could
5
manage electric demand in an intelligent manner and
6
therefore avoid, or smooth out what appear like rolling
7
outages, but are really just flexible demand at work.
8
9
And so with Packetized energy what we've been
able to and lucky enough to work with is Stanford National
10
Lab, and there it's shown that really through you know
11
advanced control mechanisms, we've been able to prioritize
12
high-priority loads during these extreme events, and how to
13
ensure the hospitals and schools for example, are
14
prioritized over certain residential demand side loads.
15
And when you do that at scale, or at the size of
16
part of the city you can really help ensure that part of
17
society, the backbone of society is really able to function
18
as well as possible during these extreme events.
19
one other brief comment to make is that we've talked about
20
DERs.
21
And just
NERC has been really flexible recently in
22
thinking about DERs beyond solar and batteries.
And really
23
thinking about demand side loads as also being aggregated
24
and being part of distributed energy resources, which we
25
think that Packetized is a really important step forward and
79
1
we look forward to seeing that DERs taking a more inclusive
2
term, beyond just batteries and solar.
3
4
5
MR. WHITMAN:
Thank you.
Thank you Peter.
Maybe we can have Wes
pretty much close us out.
MS. YEOMANS:
Yeah.
I think I'm into your break
6
now, but I'll talk fast.
So I do agree with what Mads and
7
Anne just talked about.
8
voltage transmission operator.
9
really the tremendous development of additional PM new
I'll take it up a level as a high
Since the 2003 blackout, and
10
phaser measurement internet technologies, we have spent a
11
lot of time looking at controlled subsidization at the
12
transmission level.
13
So I'm moving this up to a higher voltage
14
transmission, and first of all controlled sectionalization
15
can mean a lot of things.
16
York -- and I'm just speaking about New York, we are far
17
more stable, well connected with transmission lines rather
18
than trying to mitigate an event by disconnecting or opening
19
transmission.
20
But anyway we do the math, New
We receive a lot of stability by being connected
21
to the eastern interconnection.
Having said that, we really
22
think the opportunities are to the extent that we can use
23
PN, or if we think there's extreme weather coming and our
24
neighbors are having disturbances, or extreme weather,
25
there's actually a tremendous amount of benefit again to
80
1
re-dispatching the electric system to back down the power
2
pole, similar to what we do with thunderstorm alert.
3
And then if you're operating to 99 percent of a
4
voltage collapse or a stability limit, and then you had
5
extreme weather or contingencies, you're in kind of a bad
6
spot.
7
flows maybe down to 60 percent of limit, now you have a lot
8
of headroom for disturbances and flow.
9
offer that at a higher voltage.
If you're going to redispatch and get your actual
10
11
MR. WHITMAN:
So I just wanted to
Thank you.
Thank you.
I think we've reached
the end of our time, Elizabeth?
12
MS. TOPPING:
Sure.
So I'd like to conclude by
13
thanking our panelists again.
14
time to speak this afternoon and all the insight and
15
feedback you've provided.
16
break and reconvene at 3:20.
17
We appreciate you taking the
We will now take a 20 minute
Panel 3 panelists you may sign out of the Webex
18
meeting.
19
you can use the public webcast link on the conference event
20
page at FERC.gov.
21
over the break.
22
go on the break please mute your microphone and turn off
23
your camera until we resume.
24
in about 18 minutes.
25
If you'd like to continue watching the conference
Panel 4 panelists please stay with us
Commissioners stay signed in and when you
(Break.)
Thank you everyone and see you
81
1
Panel 4:
Recovery and Restoration
2
MR. AMERKHAIL:
All right welcome back everyone.
3
Let's get started with our fourth panel today entitled,
4
"Recovery and Restoration."
5
moderators, thank you.
6
MR. HENSLEY:
I'll turn it over to my
Thanks Rahim.
I'm Jesse Hensley
7
from the Office of Energy Policy and Innovation.
And with
8
me I have Pat Shob also from the Office of Energy Policy and
9
Innovation and we'll be serving as co-moderators.
As Rahim
10
mentioned this panel will focus on the recovery period
11
following an extreme weather event, including but not
12
limited to topics such as restoration practices and
13
prioritization, mutual assistance agreements, spare parts
14
inventory and sharing.
15
Six panelists and six questions.
We're going to
16
forego opening remarks and move directly into a question and
17
answer session.
18
panelists.
19
Senior Vice President Electric Operations from San Diego Gas
20
and Electric;
21
I'd like to start by introducing our
We have Kevin Geraghty, Chief Safety Officer and
Daniel Brooks, Vice President of Integrated Grid
22
and Energy Systems; and Charles Long, Vice President of
23
Transmission Planning and Strategy, at Entergy;
24
Bryson, Senior Vice President of Operations at PJM, Brian
25
Slocum, Vice President of Operations from ITC Holdings, and
Michael
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1
Jodi Moskowitz, Deputy General Counsel and RTO Strategy
2
Officer at PSEG.
3
Thank you to all the panelists for being here
4
this afternoon.
5
everyone to refrain from any discussion of pending contested
6
proceedings.
7
line, and he's going to throw the flag if we get into any
8
contested proceedings that might raise ex parte issues.
9
I really appreciate it.
I want to remind
We also have our lawyer, Michael Haddad on the
So we're now going to go right into the question
10
and answer session.
11
sorry, please use the Webex raise hand function.
12
you're having any issues with the raise hand function please
13
just turn on your microphone and indicate that you'd like to
14
respond.
15
want to respond.
16
If you'd like to answer a question,
And if
I will call on anyone that indicates that they
Like I said maybe not every panelist will respond
17
to every questions, with only an hour, but we'll do our
18
best.
19
off your microphone, and if you used the raised hand
20
function please lower your hand.
21
to jump right into question one and I think by virtue of who
22
emailed me first, I'll start with Jodi Moskowitz.
23
So when you have completed your answer please turn
Okay with that I'm going
And question one is what are best practices for
24
restoration, including for determining appropriate
25
prioritization of load restoration, mutual assistance
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1
agreements, and spare parts inventory and sharing?
2
how should these best practices evolve given the increasing
3
frequency of extreme weather?
4
MS. MOSKOWITZ:
And then
So Jodi all yours.
Sure.
Okay.
Good afternoon
5
everyone.
6
including me and inviting me to participate in this
7
conference today.
8
Jersey has become a poster child for extreme weather and the
9
impacts of climate change.
10
Thanks Jesse and I want to thank FERC for
I think I'll start by saying that New
Over the past 11 years PSEG has seen the worst
11
storms in its almost 120 year history.
12
include going back to March 2010.
13
we lost about 450,000 customers.
14
August 2011 we had Hurricane Irene hit.
15
that we had a record breaking wet snowstorm which caused
16
extensive damage to our system and to our customers.
17
Some of these storms
We had a nor'easter where
Then the following year
Two months after
A year after that, October 2012, we experienced
18
super storm Sandy and at the height of that storm we lost
19
about 1.8 million customers over 90 percent of our customer
20
base lost power.
21
impacted, and 51 of our transmission lines were impacted.
22
We had 110 of our substations that were
And then I'll fast-forward until August of last
23
year, August of 2020 where Tropical Storm Isaias hit our
24
service territory.
25
storm.
We lost about 575,000 customers in that
It was a very quick-moving powerful storm, however
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1
within 72 hours 98 percent of our customers had been
2
restored.
3
So when we look back over those 10 to 11 years we
4
learned significant lessons, and I wanted to kind of share a
5
few of those lessons with you.
6
bucket those lessons into four, three potentially, four
7
categories.
8
9
I think I would sort of
The first is the need to invest in
infrastructure.
You know so that's not so much what do we
10
do in the restoration process, but what have we done to
11
harden our facilities, make them more resilient so that we
12
are reducing the frequency and duration of outages.
13
And from PSE&G's vantage point over the last
14
several years we've made significant investments in our
15
infrastructure.
16
backbone projects.
17
particularly in the year since super storm Sandy, and in
18
Isaias those facilities held up extremely well.
19
We have put in service several large
We've constructed over the past decade,
We actually had only four momentary outages on
20
our bulk transmission system which occurred due to fly in to
21
break.
22
transmission facilities.
23
sub-transmission we've actually made investments to convert
24
our old, less resilient 2600 kv system to a 69 kv system
25
where we have newer poles, stronger poles, stronger
And we had no extended customer outages on our
Similarly, for our 69 kv
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1
circuits.
2
And as a result all of our 69 kv facilities that
3
were impacted in Isaias were restored in day one of the
4
storm.
5
actually worked again in 2014 and we raised 32 of our
6
substations, so they're all at FEMA level plus one foot, and
7
as a result we did not have flooding in those sub-stations
8
as we've had in previous storms.
We've hardened and raised our substations.
9
We've
We've also upgraded our state systems, our
10
station relays so we can remotely operate our system, so
11
workers can get in and safety do what they need to do to
12
restore the system.
13
actually making the investments I the system so that we
14
don't have these lengthy outages.
15
So that's kind of the first category is
Second category would be the mutual aid front.
16
And you know we found that proactively reaching out to
17
mutual aid crews, making sure that we have all of our
18
critical materials in place prior to the storm is very
19
important.
20
Atlantic mutual assistance group, which is a way for us to
21
get mutual aid quickly from utilities that run from the
22
Mid-Atlantic region up to Canada.
PSE&G actually participates in the North
23
We also use a tool called ramp up, which enables
24
us to get mutual aid quickly from even outside that region,
25
so we put that in place.
That's been helpful.
And then
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1
third major buck will be communication.
2
all utilities have seen this over the past decade.
3
to how to put in place a multi-dimensional communication and
4
stakeholder engagement plan.
5
And I think that
The need
So we have daily media advisory updates during
6
storms now.
We have daily calls with our local, state and
7
federal officials.
We have liaisons to our local offices of
8
energy management.
We proactively reach out to our life
9
support customers, so all of that is very important and
10
enables us to kind of get a pulse of what's going on in our
11
system which you know leads to helps us in our restoration
12
efforts.
13
I think the other thing that I would just mention
14
-- I'm assuming that Mike from PJM is also going to hit
15
this, but we work closely with PJM in business continuity
16
planning.
17
participate in.
18
which is not so much on severe weather, but more in making
19
sure that we're prepared for cyber and physical security
20
attacks.
21
PJM holds yearly restoration drills which we
We participate in NERC grid-X exercises,
So all of that in terms of preparation -- prior
22
preparation, helps us in our storm, in our restoration
23
efforts.
24
25
MR. HENSLEY:
Thank you for that response.
That's a perfect segue because the next hand to go up was
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1
Michael Bryson.
2
MR. BRYSON:
Thanks Jesse and again thanks for
3
the invite on the panel.
4
points really briefly to kind of complement what Jodi talked
5
about.
6
kind of storm restoration are really two different concepts,
7
but use a lot of the same things.
8
about black start in a little bit more.
9
I think I just want to make two
One is this concept that black start, and you know
And we're going to talk
But that black start system restoration when I
10
think about PSEG in New Jersey the past couple of years and
11
Charles might talk about with Entergy.
12
of extreme event restoration of customers, but I know in PJM
13
we haven't fired up a black start unit because we needed it
14
in 25 years.
15
They've done a lot
I mean so it's kind of a different concept, but
16
that idea that you're going to use some of these spare parts
17
and mutual aid really kind of reinforces the need in both of
18
those.
19
think about PJM has over 150 black start units on our
20
system, and from a best practice perspective I would take
21
one tie line with an outside system over any black start
22
units in my system.
23
The second one is this idea that you know when I
And they're great, but we really having an
24
interconnective system with MISO in New York and Va-Car and
25
TBA, I mean that's really what we're going to lean on in
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1
terms of trying to restore the system, and so those are kind
2
of two best practices making sure you're tightly coordinated
3
with your neighbors.
4
5
MR. HENSLEY:
Thank you.
The next hand I saw up
was Brian Slocum.
6
MR. SLOCUM:
Yeah thanks, and thanks for the
7
invite today.
Other than the fact that I feel like you got
8
invited to this because you withstood some sort of event on
9
your system for the last 12 months other than the COVID
10
situation we've gone through.
11
today.
12
But I'm happy to be here
For us it was last August.
We had devasting
13
Derecho that moved across our transmission system in Iowa.
14
And I know Charles has got me beat as far as if we're
15
comparing who went through the most last year as far as
16
severe weather in Louisiana there, but our damage was
17
likened to that.
18
We called it a 40 mile wide tornado that was on
19
the ground for a 200 mile stretch.
And another way we
20
talked about it was having a category four hurricane hit the
21
corn fields of the Midwest.
22
I think it really brings home the point that we're talking
23
about here in this conference, or in this technical
24
conference here where these extreme events seem to be kept
25
happening more often, and then also hitting areas in ways
Just a crazy event for us, and
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1
2
that we've never really seen before.
Adam Smith talked about it yesterday too.
We had
3
11 billion dollars in damages that were caused not only in
4
our service territory, but our partners in the area as well
5
were part of that damage.
6
from that and other events that we've had in the past.
7
And so we certainly learned a lot
I'd say the good thing is that us as a utility
8
industry, I think we're really good at this restoration
9
process and all the things that were mentioned Jesse in the
10
question that you have there.
11
possible, working together with those mutual assistance
12
agreement, I'll focus on the inventory for us.
13
Restoring load as quickly as
I think we had two primary lessons learned
14
regarding inventory through our experience in the storm in
15
the Derecho.
16
that we've been working on as we've grown from an
17
independent transmission company in just Michigan, and
18
widening our footprint to include Midwest and down in Kansas
19
and Oklahoma as well.
20
First was standardization which is something
Is making sure we had that standardization so
21
that we can help ourselves out from our other adjacent
22
service territories, and that's exactly what we had to do is
23
take inventory that we had in Michigan, as well as resources
24
from Michigan, and help out there in Iowa.
25
the other thing is on the supply chain side, we're trying to
And so I think
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1
effectively manage our inventory to make sure that we're
2
able to respond to events like this, but also balance the
3
cost of that inventory.
4
And so I think that's something for FERC to keep
5
in mind is you know that's part of what we need to do to run
6
our operations is to keep an inventory.
7
through an analysis back a couple years ago to plan for just
8
this type of resiliency type event where we would come up
9
with storm equipment, storm inventory to make sure that we
10
had what we needed to respond to an event based on what we
11
thought that impact would look like on our system.
12
We also went
And so that helped us to prepare for the events.
13
And so you know I think another thing is just working
14
together with our partners that we have in our supply chain.
15
We have a lot of agreements with them where we can call upon
16
them.
17
need to evolve these practices, I think what we've learned
18
more recently is we have agreements, as I'm sure many other
19
entities have agreements as well.
20
I'd say the only thing you know as far as how do we
And if we have a more widespread event, we're all
21
going to be picking up the phone calling similar partners.
22
And that's where I think we might need to work on figuring
23
out well how do we figure out those priorities in response,
24
which also goes to prioritization of the load restoration as
25
well.
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1
I'll stop there just to give Charles a chance to
2
one up me with his experiences down in Louisiana, so thanks
3
Jesse.
4
5
6
MR. HENSLEY:
go in order.
Thank you.
With that I'm trying to
I will turn to Kevin Geraghty next please.
MR. GERAGHTY:
Yeah thank you Jesse.
I'll just
7
try to differentiate a little bit, but echo a few of the
8
other comments that I heard.
9
Electric a little bit different situation for us.
10
11
First at San Diego Gas and
We
operate in a very extreme high fire threat environment.
Our high fire threat district space is extreme
12
and growing risks really into wildfires here in California.
13
And we can impact our communities by either A -- being a
14
source of that ignition, causing a major wildfire, so we
15
focus on preventing those, but then also our systems can be
16
impacted by those wildfires.
17
So we are operating at an elevated fire risk,
18
and/or hardening our system year round.
19
risk is so high that we just cannot risk our assets becoming
20
an emission risk, and we'll actually de-energize portions of
21
our system for safety.
22
or public safety power shutoffs or PSPS.
23
And at times that
And these are called power safety --
And while we look to do that as a last resort, we
24
do look to restore those customers as quickly as possible,
25
and I think we've got some best practices that kind of help
92
1
with that.
2
And a few you've heard about.
3
the new challenge they face.
4
Can't wait for end of life.
5
And I think about it really being three things.
Now alter the assets to meet
You can't wait for retirement.
If your assets can't operate within the increased
6
threat environment we need to replace them, rebuild them
7
now.
8
possible, and that is moving from just broad awareness of
9
your system to really granular awareness.
You have to have the greatest of situational awareness
10
And the one that I would also point to is you
11
have to have world class emergency operations and community
12
engagement.
13
quite a bit.
14
meteorological system, so we have more than 20, 220 weather
15
stations across our high fire threat district that provides
16
24/7 real time information on the surroundings our assets
17
are operating in.
18
When I think about what differentiates STG&E
We have a first of its kind utility
And because what we have learned is that a
19
general weather model is not good enough.
Our Santa Ana
20
winds can vary incredibly to where a region may see
21
completely different conditions, or a town may see different
22
conditions within the length of one circuit.
23
staff of meteorologists, and we couple those with those
24
weather stations, 100 cameras and satellites to always be
25
assessing our current fuel conditions our wildfire weather
We have a
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1
and then spot fires quickly.
2
All of that is really coordinated through our
3
emergency operations center.
4
community stakeholders via the internet command structure.
5
It's a passion here at STG&E.
6
We work intensely with our
We make all of our resources available to our
7
community, so we have two firefighting helicopters, other
8
patrol helicopters that we make available to our communities
9
because it really just doesn't matter whether we're the
10
ignition source, a fire anywhere in our community impacts
11
our community, impacts their resiliency.
12
And so we train and drill thoroughly with our
13
first responders all year round.
And as part of a unique
14
thing that we are faced with that we have to work with, we
15
work in this high fire threat all the time.
16
know modify our system, improve our system every year.
We have to you
17
And so you will find our crews are out working in
18
the high fire threat district to actually have contract fire
19
resources right with them.
20
that our work actually becomes part of the ignition.
21
would just emphasize what I think I heard in the other
22
responses.
23
Because we can't run the risk
This risk is growing.
It's evolving.
And I
The
24
investment is required.
We put already 322 billion into
25
fire risk mitigations since 2007, but the results pay off.
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1
Our communities are more resilient, and safe and reliable
2
today, and we just have to continue to have the kind of
3
priorities and investment that really address this growing
4
threat, and thank you.
5
MR. HENSLEY:
6
New Jersey to California.
7
back to Louisiana.
8
question one?
9
Yeah thank you.
We've gone from
I think now, and I'd like to come
Charles Long would you like to speak to
MR. LONG:
Sure.
I too appreciate the invite,
10
and the discussion, and I certainly agree with a lot of
11
what's been said already.
12
Entergy on extreme weather, but we certainly do get our fair
13
share, especially along the Gulf Coast in Louisiana and
14
Texas.
15
And we don't corner the market in
But we have been doing this a long time, and
16
we've done restorations -- major restorations for a long
17
time, and I do think we have some best practices that you
18
know that the industry can adopt.
19
a lot of planning in advance.
20
threatened to start the planning, it's too late.
21
And for one of them we do
If you wait until you're
A lot of processes and questions can be
22
predetermined through those plans so that you're not having
23
to make those decisions in the heat of the bottle.
24
like prioritization for example, just with broad strokes of
25
prioritization can largely be done in advance.
Things
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1
We too reorganize into a dedicated response
2
organization, an incident command structure that's
3
singularly focused on the restoration, so I think that's
4
really important.
5
and the way we've learned to do that is just to bring in --
6
we have representatives for all of our customers,
7
government liaisons, you know all of the stakeholders that
8
would be interested in restoration are in the room and help
9
with the prioritization.
10
Prioritization is also really important
It just works better to have that stakeholder
11
process right there in the command center.
12
things would evolve, or should evolve as things continue to
13
I think get more challenging.
14
people to drill, and drill on more extreme scenarios that
15
maybe you faced in the past, so that you can always practice
16
them hard and making the games easy.
17
As far as how
I think I would encourage
And then the other thing I would say is it's
18
prioritization is going to have to evolve a lot.
19
think about how many dependencies are growing with the
20
electricity sector.
21
based on more than just the electric service.
22
kinds of other services that should factor into how you
23
prioritize.
24
25
I mean
You just have to be able to prioritize
There are all
If getting the lights on isn't the top, isn't
going to solve the problem, then maybe that's not the top
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1
priority.
2
change in the future, transportation, information,
3
communication, all of those infrastructure sectors are just
4
going to be increasingly dependent on electricity.
5
But if you think about how things are going to
And if you think about an electric vehicle world
6
where evacuations are dependent on being able to charge your
7
electric vehicles on the way out of town, there's just new
8
aspects of how we should think about prioritization and how
9
we should develop systems in the future as those other
10
infrastructures evolve.
11
MR. HENSLEY:
12
13
Okay thank you sir.
I think the
last hand I saw for question one was Daniel Brooks.
MR. BROOKS:
Yeah thanks Jesse.
And the short
14
answer to that question which of these things don't belong.
15
So we've heard from five utility staff, so like as staff and
16
the consultants when you're going through an actual
17
restoration process, so I won't get into the best practices.
18
These guys and ladies have covered that well.
19
I'll talk about the research that we do in many of these
20
organizations that are here, utilities as well as others
21
throughout the country and the world to look at what
22
emerging capabilities and processes and tools may be helpful
23
as we go forward.
24
25
And obviously, doing work to look at how you
minimize power to repair the physical damage to the system
97
1
and I'll save that for the next question that's more focused
2
on that.
3
to electrically restore service as we get into prioritizing
4
those critical loads, all of those different things.
But looking at how you actually minimize the time
5
I'll offer just a couple comments.
One around
6
black starts.
Michael said you would much rather energize a
7
system from you know still ties to other systems if you have
8
the option to do that, but should you need, God forbid if it
9
ever comes that we have to actually black start from a
10
completely dark system, you know, you want to make sure that
11
you have the capability to determine the optimal number,
12
location and capacity of those black start resources to
13
minimize the restoration time.
14
And that changes over time as the system changes
15
right?
16
you now units are tied, new units, new technology is coming
17
in.
18
forward?
19
and capabilities to be able to optimally make those
20
decisions.
21
And with all the changes that we see going on with
How does that black start optimal change as you go
I think that's critical that you have the tools
We've certainly been working with a lot of the
22
utilities and RTO/ISOs on over the last few years and have
23
tools that are being used for that capability.
24
have those black start units, how do you then not determine
25
necessarily the load priorities, but how do you make sure
Once you
98
1
that you are optimally cranking through sequences that get
2
to minimum restoration times for those priority loads?
3
As you start to establish that supply and
4
delivery backbone, and the critical modes being energized as
5
you go along from that, how do you make those decisions of
6
what's the next best cranking sequence, the next best
7
optimization path you could get to as you're going up
8
multi-hours that you would then think across the system.
9
You know it's all said, you have a plan to do that, and
10
those plans are very useful.
11
But you also have to have tools that will allow
12
you to adjust those plans in real time.
You don't
13
physically hear Mike Tyson quoting one of these types of
14
conferences.
15
plan until you get punched in the mouth.
You know Mike Tyson was -- everybody has a
16
These types of significant high impact load
17
frequency events, they create operating scenarios that
18
aren't necessary what we expected when we were actually
19
going through our training exercises right?
20
that allow you to optimally adjust and figure out more.
21
Having tools
These facilities are out, these black start maybe
22
it's not available.
These non-black start units aren't
23
available.
24
sequence to hit the critical loads established, and the
25
backbone established?
Now given my priorities what's the next best
Have the ability to do that maybe
99
1
something that's really important.
2
And the last thing I'll mention is being able to
3
leverage and utilize emerging resources, distributed energy
4
resources, even all system connected renewables.
5
when you think about restoration processes the operators
6
that are on the panel and others that are listening say hey,
7
you get those guys offline, and you keep them offline until
8
you can get things established.
9
I know
But there are capabilities that those resources
10
have you know, DR, there's an opportunity to have community
11
resilience that's already been mentioned.
12
opportunity to actually plan for and have critical loads
13
that are served and energized and kept up from
14
pre-determined plans of how you would actually the system to
15
a question we'll have later and be able to keep those loads
16
up.
There's even the
17
You know from bulk system connected renewables,
18
there's a lot of renewable capability that's available for
19
those plants that you could take advantage of that may be
20
very helpful in the restoration process.
21
even from active power support if you have a high certainty
22
based on forecasting, what you can do is that.
23
And potentially
So that capability and understanding how to
24
leverage those emerging resources into the restoration plans
25
I think would be very important as we go forward and as our
100
1
resource mix changes.
2
other things on mutual assistance that maybe we'll get to
3
later if there's opportunity.
4
And I'll stop there.
MR. HENSLEY:
Okay thank you.
I have some
Yeah I think
5
you've successfully worked in our first Mike Tyson quote so,
6
of the whole tech conference.
7
had a chance to respond to question one, so we're going to
8
move on to question two now in the interest of time.
9
It think all six of you have
And question two is how can asset management
10
practices and facility design requirements be leveraged to
11
reduce restoration times following a severe weather event?
12
I think we touched on this a little bit, but I'll look for
13
hands.
14
I think I saw Kevin Geraghty please go ahead.
MR. GERAGHTY:
Thank you Jesse.
You know when I
15
thought about this question you know first of all I think
16
that we're recognizing STG&E is one of the best mitigations
17
for this, but the threats we face are incredible.
18
And you can't remove all threats instantaneously.
19
So we used very intense risk informed models to prioritize
20
our strategies, whether that's traditional hardening,
21
whether that's covered conductor, or strategic
22
undergrounding.
23
that wherever we place that investment that we're addressing
24
the greatest chance of ignition, and also creating the
25
greatest impacts on reliability and resiliency for the
And we're just trying to assure ourselves
101
1
communities.
2
Additionally, when I think about those things you
3
can't yet replace, the State of California has established
4
minimum patrol and inspection programs at the CPUC, enforced
5
its compliance with on a continuing basis.
6
go far above and beyond those requirements.
7
of our high fire threat districts before and after any one
8
of these fire weather events.
9
And STG&E would
We patrol all
We use drones to get incredibly detailed
10
assessments, and that information, all that data, the video,
11
et cetera is available to someone like me during an
12
emergency operation that's got to make a decision on whether
13
or not to de-energize.
14
much more intensely into knowing real time condition
15
assessments, and so we're looking very intensely at parcel
16
discharge to actually determine segments of lines that were
17
failing long before they actually have a failure, and we're
18
also looking at falling conductors as one of those ways to
19
actually de-energize our system long before it causes a
20
problem.
21
But as we move forward we're really
But I will tell you way above and beyond the
22
obvious assets whether it's the structures and the wires,
23
there's so much more to gathering this data, whether it's
24
weather data, camera data, condition data, the satellite
25
information, and we're actually building our own private
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1
network to bring all of that data back to our teams to be
2
able to make informed decisions because it's no longer about
3
skating, know the condition and operations of your system,
4
you have to have complete awareness of the environment that
5
it's operating in.
6
And I can't stress enough the importance of
7
education management, and obviously that would apply across
8
the board.
9
back east, or fires here, the vegetation management, fuel
I think utilities whether you're facing storms
10
mitigation efforts are key, and the science and data around
11
that is getting to be incredible between cameras, satellite
12
centers and other really risk informed models that allow us
13
as a utility to get to the most critical thing now.
14
And so as we think of evolving into you know fire
15
safe 4.0 we call it, it's much more about getting even more
16
real time data and more condition-based data of the assets.
17
MR. HENSLEY:
Okay thank you.
I just want to
18
note we're already halfway through our hour, it's hard to
19
believe.
20
responses as tight as possible.
21
three and six because they kind of both touch on dual fuel.
22
But the next hand I saw I believe was Ms. Moskowitz.
23
you please go ahead.
24
question 2?
25
I'll just ask everyone if you can keep your
I hope to combine questions
Could
Sorry Jodi did you want to respond to
MS. MOSKOWITZ:
It would help if I took myself
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1
off of mute.
Okay.
Here I am.
I wanted to just kind of
2
quickly double back to a point that I touched on in response
3
to question one as it pertains to how we're designing our
4
substations.
5
conditions that we found ourselves in during super storm
6
Sandy.
And I mentioned the extreme flooding
7
So what we did beginning in 2013 was to design
8
and implement a wide-scale transmission hardening program
9
that basically leverage FEMA flood elevation data, and
10
incorporated them into our facility design requirements.
11
we were raising -- we raised our stations in flood prone
12
areas one foot above the FEMA flood levels, and incorporated
13
our designs to shield our equipment from the damaging
14
effects of wind and debris.
15
And that has really paid dividends for us.
So
We've
16
determined that if another storm as powerful as super storm
17
Sandy were to hit us again, we would lose about 500,000
18
fewer of our customers, and those who did lose power would
19
be restored more quickly.
20
significant tropical storm in May 2018, one of our
21
substations that was impacted by Sandy we had raised that.
22
We've also seen we had a
And if we had not raised it, we have 5,700
23
customers directly connected to that substation and all of
24
those customers would have lost power and none of them did
25
because of the way that we hardened the substation.
So I
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1
want to give that as an example of how we sort of
2
proactively incorporated these flood, FEMA design
3
requirements into our stations and that has reaped benefits
4
for our customers.
5
MR. HENSLEY:
If I could just really quick
6
respond, was FEMA plus one a voluntary effort, was it part
7
of your company?
8
MS. MOSKOWITZ:
9
MR. HENSLEY: Okay.
10
MS. MOSKOWITZ:
11
MR. HENSLEY:
12
response.
13
Entergy.
14
Yes, yes.
It was.
Thank you.
Thank you for that
The next I saw was I believe Charles Long from
MR. LONG:
Yeah just a couple things and I'll try
15
to be quick.
I think from an AM, an asset management
16
perspective one of the things that I think is really
17
valuable is to make sure that when you're doing inspections
18
that you don't just inspect the equipment, you also inspect
19
things like drainage, and erosion control, and heaters.
20
some of the things that can lead to you know failures that
21
are really not related to the equipment.
And
22
Another thing is to make sure you have
23
pre-determined evacuation plans for employees, equipment and
24
materials that are going to be critical to the restoration.
25
You know having your employees or equipment impacted by the
105
1
events such that they can't engage in the restoration is
2
obviously not somewhere you want to be, so pre-plan that, so
3
you know where you're going to evacuate those people and
4
materials to.
5
On the design side you definitely need to
6
continue to look at criteria and standards that reflect the
7
weather such that we see.
8
design, ice loading design can obviously pay dividends.
9
Someone mentioned elevating critical substation equipment
Increasing the wind loading
10
that can be very, very effective
11
one of the longest to recover from.
12
many ways, but it just take a long time, it's very
13
intricate work to recover a control house.
14
Flooding can actually be
It's worse than wind in
Geographic diversity you know think about how you
15
can get power into the area from multiple locations, fuel
16
diversity for generation I think is another thing.
17
talked about it later in black start and I'll talk more
18
about it, but yeah I think that's also a very helpful thing
19
to have multiple fuel type scenarios that are going to be
20
impacted.
21
We
And then Mr. Bryson talked about the value of
22
that one tie on and I completely agree.
The first lights
23
that were on at Lake Charles after Laura were actually lit
24
from a tie line.
25
generator.
They weren't lit from a black start
And even for Laura where we saw winds on the
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1
coast of Louisiana at 150 miles an hour, our newest designs
2
and transmission lines didn't survive.
3
So they were undamaged, and it was you know part
4
of the first things restored in the Lake Charles area, so
5
those higher designs and new criteria do pay dividends and
6
you should continue to evaluate those with evolving weather
7
threats.
8
9
10
MR. HENSLEY:
Thank you.
Brian Slocum I saw your
hand up next.
MR. SLOCUM: Yeah just quickly, I'll piggyback off
11
of what Kevin was talking about vegetation management.
His
12
issues in California are different than mine in the Midwest,
13
but I would just offer up you know we have stick in place
14
right now with FAC003 with respect to vegetation management.
15
Perhaps there's a carrot that can be put out
16
there with respect to sustainable vegetation management
17
programs and practices that utilities will put in place that
18
FERC could look at and incentivize, whether that's allowing
19
capitalization of certain activities, or providing
20
incentives around that.
21
So you have both the carrot and the stick with
22
respect to vegetation management issues.
So I'll put that
23
on the table for consideration.
24
interesting that a lot of what we're talking about here,
25
you're hearing things that are above and beyond.
And I think it's
You know
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1
Jesse asked a question, was that voluntary that you did
2
that.
3
And I think there's a lot of things here that are
4
unique to the service territory, unique to the conditions
5
that each of us are operating in where we are going above
6
and beyond what the minimum design requirements are.
7
that's sort of contrary to other things that we're talking
8
about within the industry with respect to competition and
9
getting the lowest cost.
10
And
And so there are competing priorities here and
11
I'm just really glad we're talking about this as an operator
12
today because for me operating the system it's really
13
important that we have the ability to go above and beyond
14
and to make sure that we have designs in our system that can
15
withstand the type of weather that we are seeing, frankly.
16
MR. HENSLEY:
Yeah thank you. I think that's a
17
really important point.
I'd be remiss if I didn't ask I
18
think we have a couple of Commissioners at least on the
19
line, if Commissioners have any questions they'd like to
20
weigh in with.
21
CHAIRMAN GLICK:
Jesse I understand that you're
22
asking, but I don't have any questions.
But I wanted to
23
tell you that I want to thank all the panelists for
24
participating today, very helpful.
25
MR. HENSLEY:
Thank you Mr. Chairman.
I think in
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1
the interest of complements I think there's a lot of
2
interest in three and six, I'm going to turn to those.
3
Question three is should restoration capabilities be
4
improved by encouraging planners, governmental authorities
5
and utilities to require dual fuel capability in all black
6
start units?
7
And if you can find a way to maybe double up and
8
work in some question which is about cost recovery concerns,
9
or regulatory barriers to the implementation of practices
10
that would ensure the timeliness of system restoration, that
11
also gets into the maintenance of the dual seam capability
12
of black start units.
13
And just personally I'll say there was a Wall
14
Street Journal article about black start on the cover of the
15
paper a few days ago that I thought was quite interesting
16
related to black start.
17
black start on the cover of the Wall Street Journal.
18
And it's not often that you see
So who would like to go first here?
19
Charles Long I see your hand up.
20
MR. LONG:
I see
please go ahead.
Yeah I think black start is an
21
interesting topic and I really think you should think about
22
fuel and generation just much more broadly than black start.
23
Certainly, fuel diversity is valuable in any kind of event.
24
Dual fuel, or even if it's not a single unit with dual fuel,
25
dual fuel in an area that might be impacted can be very
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1
valuable.
2
And so I think you should really think about
3
that, in a system planning aspect where you know maybe if
4
you have a gas generator next to a nuclear generator, next
5
to a solar generator, you know those types of things, energy
6
proximity can be just as valuable as dual fuel.
7
And then I think you know black start is
8
certainly critical and if we ever you know knock on wood,
9
have a large eastern interconnection type event we're going
10
to have to have those.
But I think it's important to
11
realize that most of these extreme weather events it's
12
really transmission restoration that gets the ball rolling.
13
So I think there are ways to think about it more
14
broadly.
15
about what areas at least will be key to the restoration
16
after an event.
17
advance and get a feel for that.
18
I think you can also do some analysis in advance
You can do some of those analyses in
And I think there are some other things that can
19
be done, you know, besides just dual fuel, just to help with
20
the restoration over all there are just many more effective,
21
and with hardening transmission and distribution can
22
certainly pay a lot of dividends.
23
Fuel delivery infrastructure can be improved
24
probably you know more efficiently in some cases to where
25
the infrastructure to deliver the fuel is just more
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1
reliable.
2
very, very valuable is onsite fuel storage.
3
And then one of the things that we found to be
And so if you know you can get some natural gas
4
stored at the generator location that independent of
5
pipelines or other infrastructure they you know you've got a
6
lot available to you, and you can have several days of local
7
fuel there that can get you started so that's my thoughts on
8
black start.
9
MR. HENSLEY:
Thank you very much for that.
10
believe I saw Michael Bryson up next.
11
give me a holler if I miss anyone's hand up.
12
MR. BRYSON:
Thanks Jesse.
I
Again just weigh in,
Thank you.
And it's interesting
13
you referenced the Wall Street Journal article.
14
kind of a timely, I think that came out the day before our
15
comments were due, but my wife who's way smarter than I am,
16
had the opportunity to read the article and my testimony,
17
and one of the comments that she made was boy, it seems like
18
if there's ever something the federal government should help
19
with it's this issue.
20
That was
And I thought that that was kind of an
21
interesting observation.
We have an effort in PJM, and
22
we're not calling it dual fuel, but we're calling it fuel
23
security, so there's a lot of definitions.
24
fuel.
25
couple different ways we define it.
It's onsite
It might be dual pipelines, you know, there's a
111
1
But even given that loose definition of those 150
2
units I talked about, we have about 50 percent that I call
3
fuel secure.
4
100 percent fuel security is about 150 million dollars for
5
the system.
6
TO zone is fuel secure is about 20 million.
The interesting thing is the hurdle to get to
And the hurdle to get to just making sure every
7
But having said that, jumping down to question
8
six, the pushback that we got is you know it's such a low
9
probability event, why do we need to make that investment?
10
And so I think there needs to be some level of a minimum
11
threshold you know from the regulatory perspective to help
12
with that that might help with that hurtle, because when you
13
hear the numbers we've been throwing around for the last few
14
days in this technical conference, the dual fuel, or fuel
15
security investments are pretty low numbers, thanks.
16
MR. HENSLEY:
Yeah thank you.
I think we both
17
have wives it sounds like, that are far smarter than
18
ourselves.
19
saw your hand next.
20
With that I'll turn to Jodi Moskowitz, I think I
MS. MOSKOWITZ:
Yes.
Just wanted to kind of echo
21
the point about fuel security and fuel diversity in terms of
22
emphasizing the need for example of having sufficient
23
nuclear capability on the system.
24
is a very secure fuel.
25
We all know that nuclear
It is not subject to the same type of extreme
112
1
cold weather variables as other types of generation, where
2
gas supplies can freeze, or coal supplies can freeze, and it
3
also has the benefits of promoting the clean energy future
4
that we all want.
5
about resilience and fuel security, the important role, the
6
critical role that nuclear is going to play going forward.
But I did want to emphasize we're talking
7
With respect to black start specifically I think
8
one point I wanted to make was just the need for regulatory
9
certainty in terms of compensation.
That's an issue that
10
we've been dealing with a little bit in PJM and making sure
11
that you know there's an expectation that generators are
12
going to offer black start service if there is certainty
13
about how they're going to get paid in the same way that you
14
know you often hear transmission owners you know being very
15
concerned about fluctuations let's say in ROE policy et
16
cetera, and the need for regulatory certainty.
17
The same would apply for black start.
And I
18
think the final point that I would make is I think we all
19
need to think about what does the future of black start look
20
like when we're talking about increased penetration of
21
renewable resources.
22
units going to come from, and what is that going to look
23
like in 20 to 30 years, and something we should really start
24
thinking about now.
25
And you now where are the black start
MR. HENSLEY:
Okay thank you.
Kevin Geraghty I
113
1
believe you're next.
2
MR. GERAGHTY:
Yeah just real quick.
I want to
3
build upon Brian's comment earlier about the carrot for
4
investment, and when I think about California last year it's
5
well-known about the load curtailment right and that the
6
supply issue.
7
August and early September there was so many transmission
8
lines passed, impacted by wildfires that there are other
9
equally precarious hours of that year -- that operating
10
But in and around those days so many hours in
window.
11
And I could not emphasize more what's better is a
12
very strong interconnected, reliable and resilient
13
transmission system, and investing and reinvesting in that
14
is incredibly important as we look to be the most reliable
15
operators that we can be.
16
MR. HENSLEY:
Thank you.
I think with that I
17
don't see anymore hands raised about questions three or six.
18
I think I will turn to question four.
19
minutes left here it looks like.
20
We have about 15
Question four is do the states and other
21
stakeholders make decisions that impact restoration priority
22
or techniques need to engage in greater coordination to
23
establish a consistent means to determine restoration
24
priorities.
25
Slocum?
Anyone like to weigh in on that?
I think Brian
114
1
MR. SLOCUM: Yeah I can take a first stab at this.
2
And my general thought process on this is that we do a good
3
job of this.
4
structure in our Derecho experience.
5
in the state emergency headquarters coordinating not only
6
with the state, but also with our customers and we're
7
transmission only.
8
9
It was mentioned you know incident command
I mean we had somebody
So this is a little bit unique for us in that
we're arm's lengths from those restoration priorities.
So
10
perhaps it's a lesson learned for others that are vertically
11
integrated and maybe even for us it's a unique situation
12
maybe a little more difficult.
13
And it shows where to Charles's point that he
14
made, I think what we learned is we can do a better job of
15
this up front.
16
and figuring out within the eight day period where we were
17
in restoration from the Derecho that we should be able to
18
know that at a distribution level this transmission circuit
19
that's out of service is impacting the City of Aims and
20
their water supply.
21
There's a lot of things that we are doing
And we should be able to highlight that red right
22
on our sheet of outages right away without even having to
23
get that input or phone call from that city.
24
say that that was a lesson learned from us that the thing
25
that we can do better is doing it more upfront.
And so I would
115
1
And I think Charles made a very good point that
2
as these loads change, we also need to make sure we're
3
updating that viewpoint on those restoration priorities, and
4
then we can save ourselves at least a little bit of trouble
5
when we do get punched by Mike Tyson and we can figure out
6
how exactly we want to respond and prioritize given the
7
situation that's ahead.
8
MR. HENSLEY:
9
Thank you.
Kevin Geraghty please
go ahead.
10
MR. GERAGHTY:
Yes.
Just building on Brian's
11
comment that you know here in California because of the
12
wildfire risk it is a continuing plan to check active better
13
processes, and so monthly operational calls are held here
14
with the California Office of Emergency Services, the CPUC,
15
the Department of Forestry and Fire Protection, Cal Fire,
16
every month regardless of the threats.
17
We also have monthly briefings with our fire
18
chiefs.
And I will tell you one of our most important ones
19
when you think about the community, and whether the
20
curtailments restorations is our quarterly collaborations
21
with our local emergency managers, and our community
22
leaders.
23
our county to talk about you know their emphasis in what
24
helps us determine where we may roll out micro grids to
25
improve resiliency.
We meet quarterly with over 40 stakeholders in
116
1
But I could not stress enough how critical it is
2
to set up one of those advisory councils and just listen and
3
make sure you're in tune with the county, the things that
4
Brian mentioned up knowing before the community needs to
5
tell you where there's a problem.
6
rapidly and you can create quick GIS layers and whatever
7
tools you're using such that you know the response and you
8
know what the community's response is going to be, and
9
you're going to know their priorities far better.
You'll benefit from that
10
And then it leads to great solutions.
11
have a customer based app engaging with 2-1-1, the creation
12
of community resource centers.
13
there, if you intensely work on the collaborations with the
14
community stakeholders, thank you.
15
MR. HENSLEY:
16
is from Charles Long.
17
Like we
But you can only get to
Yes thank you.
The last hand I see
Please go ahead.
MR. LONG: Yeah I know we're running out of time
18
I'll be really quick.
19
prioritization process is extraordinarily complicated.
20
There are many, many aspects to it and optimizing that
21
restoration prioritization is a very demanding activity, so
22
make sure in your incident claims you resource that
23
appropriately and give them tools and information they need
24
to do that.
25
I think just keep in mind the
And then obviously, as it evolves, the
117
1
restoration priority evolves as you learn more information
2
about damages and such that you just continuously changing,
3
you know, so it takes a lot of effort.
4
And then the last thing I'd say is one of the
5
things that I think to be helpful is you know more and more
6
aerial imagery available, either from a satellite or other
7
sources that are non-utility governmental agencies, the
8
ability to quickly access that and integrate that into GIS
9
systems could also be very helpful.
10
And I think the hardest part of prioritization is
11
damage assessment.
12
you know, how long it's going to take and what type of
13
resources it's going to take to restore all the facilities
14
you can make a pretty good plan.
15
damages in a very detailed way, it's very difficult to do a
16
good prioritization, so I think that would help.
17
If you have a good damage assessment,
MR. HENSLEY:
If you don't know the
Thank you.
That's a great point.
18
I think I did see Michael Bryson if you would like to be the
19
last one to weigh in on this question four, then we'll have
20
10 minutes left for our question five, thank you.
21
MR. BRYSON:
Yeah thanks Jesse.
Just really
22
quick.
You know Brian talked about that you know kind of
23
getting feedback from stakeholders and education.
24
managing that expectation with stakeholders and states up
25
front is important, particularly because when you look again
I think
118
1
at that difference between a black start system restoration
2
and an extreme weather event system restoration because
3
those expectations are going to change, and so putting some
4
time in the up front work is really important.
5
6
MR. HENSLEY:
Thank you.
Unless I missed anyone
I think I'm going to turn to question five.
7
DR. BROOKS:
Hey Jesse just one comment quickly.
8
MR. HENSLEY: Oh sure.
9
DR. BROOKS:
A regulatory one, although not for
10
the Commissioners here, more outside the AA, that
11
situational awareness that Chuck was talking about that's
12
really important for assessing damage and for prioritization
13
you know, drones are obviously being used more and more for
14
that.
15
working to help characterize the capabilities.
16
A lot of good work being done there.
We've been
But the next day hurdle is getting regulatory
17
ability to do beyond visual modified, to be able to increase
18
the capabilities there.
19
Commission here can help with, but it is something that
20
would improve our ability to actually prioritize and have
21
that situation awareness, probably worth mentioning.
22
MR. HENSLEY:
It's not something that the
Thank you.
My apologies for
23
missing your hand there.
Last question is question five and
24
it looks like we have about eight minutes to answer it.
25
Question five is can innovative mitigation strategies such
119
1
as controlled sectionalized or islanding employed during the
2
operating day to improve resilience and reduce the loss of
3
the load, also help to ensure more timely restoration of
4
services to loads that are lost in an extreme weather event?
5
Give me one second.
It looks like Brian Slocum I
6
think is the first hand I see up.
7
MR. SLOCUM:
All right finally I won the Family
8
Feud contest.
I hit the button first.
I think the question
9
I agree with yes, but my only issue is you know deployed
10
during the operating day break, but it goes back to what we
11
heard yesterday, and it has to be planned into the system
12
such that it can be available for the operators to deploy,
13
and/or for the people in the field to deploy.
14
I think back to a situation that we had in the
15
Derecho where we had a very large transmission structure and
16
on it were two feeds that both were down and basically
17
impacted our ability to provide service to a town.
18
I'll leave their name out of it, but anyhow if we
19
could have put into place and would have done this analysis
20
you know a better way to feed a diverse path to bring to
21
that town, then we could have relied upon that
22
sectionalizing scheme to basically you know get that load
23
restored more quickly.
24
25
The thing that we run into oftentimes when we
take projects in through the RTL planning process is the TPL
120
1
standards are seen as this is what you're to plan to.
2
when we bring a project that says we want to pull a line
3
from a different location, a backup line for resiliency, or
4
even in a routing.
5
And
If you want to route a transmission line in a
6
diverse path that's not on the path of an existing
7
transmission structure is already on.
8
shot down in that planning process because it's either more
9
costly, or the permitting is more difficult and I think
10
that's where we can be given some amount of help to make
11
sure that these resilience issues in designing and planning
12
the system can be considered, and should be considered when
13
we're doing the design and planning of the system.
14
MR. HENSLEY:
15
Charles Long please.
16
MR. LONG:
Thank you.
A lot of times we get
I'll turn next to
Yeah I think Brian's words were spot
17
on.
You definitely have to have, it has to be predetermined
18
and it has to be designed you know years in advance, and I
19
think if you think about operating scenarios that you would
20
have to plan to implement it would just be very, very
21
complicated, complex to deliver.
22
Kind of a system that could sort of try to
23
self-heal.
But I do think there's a lot to be gained from
24
just decreasing the dependencies that are on the system.
25
You know, the geographic dependencies or same voltage, or
121
1
2
you may have transformer dependencies.
I think there are lots of things you can do from
3
a resiliency standpoint that even if it's not an automated
4
system, your operators can take advantage of and
5
dramatically quicken the restoration.
6
have part of the plan for an event like you do for
7
hurricanes, you know you can do a lot of things just on the
8
days leading up to that.
9
And I think if you
If you have planned out a design generators, or
10
planned out transmission lines, or substation transformers,
11
there can be a return to serve and you can certainly
12
increase you know your resiliency, and just by doing those
13
types of activities before the event, but that's without a
14
preplanned system that's designed to take advantage of those
15
capabilities, I think it would be really tough to do.
16
MR HENSLEY:
Okay thank you.
We have about four
17
minutes left, and I see Daniel Brooks and Kevin Geraghty
18
before we have to wrap it up, thank you.
19
DR. BROOKS:
Yeah I'll make it quick.
So I agree
20
completely with Brian and Charles that it has to be planned.
21
And it is complicated.
22
opportunity and a need as we start to transition the grid
23
and the resources on the grid through the decarbonization
24
clean/energy transition.
25
to be able to identify, maybe not large islands, but to be
But I do think there's a real
There's a real opportunity for us
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1
able to identify those critical loads.
2
It might be the best critical loads, whether it
3
be the final critical loads that we could plan and we could
4
operationally in real time based on what the actual event
5
has happened and the operating condition.
6
to operate islands that would be able to provide resiliency
7
to those critical loads that we would need up to support
8
getting the rest of the system up for the support of society
9
and you know just people being able to live in the middle of
10
We could be able
some of those events.
11
So there's tools and capabilities that are being
12
developed to do that that we should be looking at that are
13
going to be demonstrated and tested.
14
15
16
MR. HENSLEY:
there.
Thank you I appreciate the speed
Kevin Geraghty please go ahead.
MR. GERAGHTY:
Yeah.
Well not all that
17
innovative, I can tell you when I think about a picture from
18
last year we had the valley fire tear up a large part of San
19
Diego County, in fact it impacted a bunch of our customers.
20
And when all that fire ravage was done to go out
21
there and see the steel structures still standing, but then
22
also seeing wood structures that had really great vegetation
23
management at their base, also having avoided fire damage,
24
you can make a restoration much quicker by the way the
25
system is designed and the way you manage that asset, and
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1
especially veg management, thank you.
2
3
MR. HENSLEY:
Thanks so much.
I see Jodi
Moskowitz please.
4
MS. MOSKOWITZ:
Yes I'll be quick.
I just wanted
5
to double back on the comment that was just made about
6
islanding.
7
circumstances.
8
it as not a substitute for the macro investments that need
9
to be made on the grid, and that we have made, and that we
10
11
And islanding perhaps can work in certain
It's very complex, and I think we would view
have seen customers have significantly benefited from.
So it may be a tool in the overall tool kit, but
12
I don't want to lose sight of the fact that you know we have
13
the reality, and you can hear it from the discussion on this
14
panel of extreme weather occurring throughout the country.
15
It manifests itself in different ways, but the need for
16
resilience, the need for redundant supply for customers that
17
require 24/7 energy and so we really need to focus on what
18
are those macro type proactive investments?
19
20
21
Brian talked about planning, design, that is
really critical going forward.
MR. HENSLEY:
Thanks so much.
22
close to our time limit.
23
otherwise we will probably end it here.
24
25
DR. BROOKS:
I think we're
Anyone like to add a final word,
I'll jump in Brian and just say that
I agree completely with Jodi.
And my comment wasn't
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1
intended to say that we need to be looking at how we can you
2
know intentionally island an entire system during a
3
restoration event.
4
to increase the resilience of critical loads even with the
5
more macro investments that are required, and that was my
6
comment.
7
I think there's targeted opportunities
MR. HENSLEY:
Thanks again.
8
I see that we're about at the 4:20.
9
place to stop.
At least on my clock
It seems like a good
I want to really thank all of the panel four
10
people for participating today.
We're going to take about a
11
20 minute break and then reconvene at 4:40 with panel five.
12
So thank you all again and have a good afternoon.
13
Oh you can I think you're going to be logged out if you're a
14
panelist and you can join the FERC webcast if you would like
15
to continue watching the conference.
16
17
(Break.)
Panel 5:
18
Coordination
MR. AMERKHAIL:
19
everyone.
20
entitled, "Coordination."
21
moderators, thank you.
22
Okay here we are.
Welcome back
Let's get started with our fifth and final panel
MS. MOYER:
I'll turn it over to our
Hi I'm Alyssa Moyer from the FERC
23
Office of Energy Policy and Innovation, and along with my
24
colleague Lodie White from the Office of Electric
25
Reliability, I'll be your final moderator for the day.
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1
This panel looks toward the role that
2
coordination and cooperation across jurisdictions, including
3
but not limited to coordination with retail regulators
4
including states, municipalities and cooperatives utilities
5
and other federal agencies could play in long-term planning,
6
operations and their covered practices to address climate
7
change and extreme weather events.
8
9
We will be foregoing opening comments and
directly to question and answer session.
move
Following this
10
panel we'll have closing remarks and adjourn the conference.
11
I'd like to first start by introducing our final set of
12
panelists.
13
at GridWise Alliance.
14
We have Karen Wayland, Chief Executive Officer
Randy Howard, General Manager of the Northern
15
California Power Agency;
16
Public Service Commission, Letha Tawney, Commissioner, at
17
the Oregon Public Utilities Commission; David Terry,
18
Executive Director of the National Association of State
19
Energy Officials.
20
Dan Scripps, Chair of the Michigan
Carolyn Barbash, Vice President of Transmission
21
and Development of Policy for NV Energy; and Patricia
22
Hoffman, Acting Assistant Secretary, Principal Deputy
23
Assistant Secretary, Office of Electricity at the U.S.
24
Department of Energy.
25
Welcome panelists.
As we begin I'd like to
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1
remind you to refrain from any discussion of pending or
2
contested proceedings.
3
discussions my colleague, Michael Haddad from the Office of
4
the General Counsel will interrupt to ask the speaker to
5
avoid that topic.
6
MS. WHITE:
If anyone engages in these types of
Good afternoon panelists.
7
rejoining us.
8
session.
9
please use the Webex raise hand function.
Thanks for
We'll now begin the question and answer
If a panelist would like to answer a question
Alternatively, if
10
you're having issues with the raise hand function, please
11
turn on your microphone and indicate that you'd like to
12
respond.
13
I will call on panelists that indicate that they
14
would like to answer in turn.
15
your microphone and respond to the question.
16
completed your answer please turn off your microphone and
17
lower your virtual hand in Webex.
18
Once I do so, please turn on
When you have
Let's get started.
The first question is should the Commission
19
consider pursuing ongoing formal or informal means of
20
coordination with retail regulators on matters related to
21
climate change and extreme weather challenges addressed in
22
this proceeding?
23
coordination?
24
you can just give an answer.
25
Wayland.
If so, what should the goals be with this
I'll just go down the list of panelists and
First we'll start with Ms.
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1
MS. WAYLAND:
Well thank you very much.
I have
2
long advocated that the administration set up a formal or
3
informal body that brings together state regulators and
4
federal regulators to come up with a whole suite of issues
5
that are blurring jurisdictional lines between the state and
6
federal authorities.
7
Both many of the things that could be tackled, we
8
original came up with this recommendation in the first
9
forward energy review, and in fact I worked very closely
10
with FERC staff to develop a recommendation called
11
"Coordinating Goals Across Jurisdictions."
12
originally thinking that this would be about the kinds of
13
blurring of jurisdictional lines that emergent technologies
14
are creating, but actually, the multi-faced nature of
15
climate and extreme weather makes it perfect for such a
16
standing
We were
by.
17
MS. MEYER:
18
MR. SCRIPPS:
Chair Scripps I see your hand up.
Excellent.
Yeah I totally agree as
19
well and as FERC indicated in question 17 of the
20
supplemental notice the Section 2.09 of the Federal Power
21
Act provides a forum and a framework for this sort of state
22
and federal cooperation, and I would say and partnership.
23
I'd also highlight in some of the myriads of
24
comments that they submitted that this really sort of comes
25
out of Congress's desire to acknowledge the dual roles that
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1
both the states and FERC have and as they noted there may
2
not be a better example of issues that should be addressed
3
by a multi-jurisdictional, multi-pronged collaborative
4
approach than those related to climate change and extreme
5
weather events that have an impact on local and general
6
electric systems.
7
So I think this is well teed up for that sort of
8
thing.
I guess in structuring it I would focus -- I mean
9
obviously this is a big topic right?
It's climate change,
10
it's extreme weather, it's electric system reliability.
11
focus on tangible opportunities, really drill down to where
12
the rubber hits the road on things like forecasting and
13
transmission and response.
14
The things that sort of you could come up with
15
action plans around as opposed to just another forum for
16
discussion.
17
think should be the goal.
18
opportunity to take advantage of state activities in this
19
area.
20
So
But something that leads to concrete action I
And I also think it's an
In Michigan for example, in 2019 following the
21
polar vortex you know it was ultimately a success story.
22
The heat stayed on, the lights stayed on, but we were close.
23
And our Governor, Gretchen Whitmer asked us to complete a
24
statewide energy assessment.
25
I know other states, you know, with a host of
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1
recommendations across electric and natural gas coordination
2
of the two and propane and cyber and physical security and
3
emergency response, I know other states Mississippi is in
4
the process of doing something after the February event, and
5
other states have done similar things.
6
Allowing an opportunity to learn from those deep
7
dives that states have taken, and then sort of how do you
8
zoom out and connect the dots between states' specific
9
recommendations in something that addresses broader system
10
grid reliability I think is an ideal opportunity for this
11
sort of cooperative approach.
12
13
MS. WHITE:
Thank you.
Mr. Howard would you like
to respond?
14
MR. HOWARD:
Yes thank you very much.
So I would
15
agree with the Chairman's comments, but we are specifically
16
in California, that a great example of where coordinated
17
activity you know would have been very beneficial with the
18
Department of Safety power shutoff.
19
a couple years ago and for transmission dependent utilities
20
were cut off entirely because transmission systems were shut
21
off.
22
It was quite devastating.
You know it took place
And the ability to
23
coordinate and put boundaries and activities around how you
24
communicate those PSTS events and how long the durations and
25
the advanced edification as we see PSTS events now expanding
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1
throughout the west as a potential tool to address wildfire
2
risk in some of these climate change activities, so it would
3
just be one example of several that I think having FERC in a
4
coordinated role with state-type regulations would be very
5
beneficial.
6
MS. WHITE:
7
MS. TAWNEY:
Thank you.
Commissioner Tawney?
Oh thank you and I want to
8
appreciate FERC taking this issue on very transparently and
9
urgently.
10
11
It is critical in Oregon and across the west, but
as we've heard the last two days across the country.
To put some color on Chair Scripps very excellent
12
comments, I would ask FERC to think of the state regulators
13
in our role, in our states as sort of the face of
14
electricity and natural gas.
15
the Governor's office when there's restoration conversations
16
alongside the utilities.
17
We are the ones who end up in
We often play emergency support functions in our
18
state governments.
19
set out temporary rules for public safety power shutoffs at
20
the distribution level, and we ask the utilities to tell us
21
if they have a protocol for PSTS in the bulk system.
22
And so for example, we in Oregon, is we
But of course we can't help them with that.
23
can't tell them what we would prefer.
24
need to look to you, and the federal level to set those
25
expectations.
We
For notification we
And we need that situational awareness as Mr.
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1
Howard just pointed out.
2
event is unfolding, and we don't have good visibility into
3
how the bulk system is going to respond.
4
It's not really critical when the
And often the impacts of these events will be at
5
some distance from our load centers in the left.
6
may have
7
know, 100 miles from the population center that's going to
8
be impacted in the west, and that creates real downstream
9
impacts.
10
Often you
smoke column across the transmission line, you
And without good visibility into how the
11
transmission system is adopting to these risks of how you
12
are setting out to be under some expectations, that we've
13
got in a difficult position with our local stakeholders who
14
want to argue that local is better, that long line
15
transmission is not really the way to decarbonize and so on.
16
And it leaves us really struggling to answer how
17
the whole system will be resilient when our stakeholders ask
18
us and expect us to have an answer as the face of the
19
regulator at the local level.
20
could really focus on that transparency and collaboration.
So I think that partnership
21
MS. WHITE:
Thank you.
Mr. Terry?
22
MR. TERRY:
Thank you.
I also want to commend
23
FERC for raising these issues and the topics today and I
24
think Chair Scripps has said it well.
25
additional items I would add.
A couple of
I think the visibility issue
132
1
that was just raised is an important one across multi-state
2
jurisdictions, and really the changing nature of the grid
3
generally.
4
I know our own coordination with the Department
5
of Energy and FERC to an extent
has helped in emergency
6
response and crisis.
7
members, I think is why I add whether it's a subset, or
8
somehow integrated, or a parallel kind of integration to
9
FERC to address some of the critical infrastructure
The Governor's energy directors are
10
interdependencies around these issues would also be a useful
11
add to that conversation and dialogue.
12
Whether it's at least emerging issues which are
13
still not very high priorities I suppose, such as vehicle,
14
transportation electrification, and needs at the local
15
levels and how those are served by broader reliability is
16
one small example.
17
DERs, et cetera.
18
There's certainly others, increased
But I think that would be helpful and would
19
encourage broader state engagement as well to get some of
20
this policy and perhaps non-regulatory elements as well.
21
MS. WHITE:
22
MS. BARBASH:
Thank you.
Ms. Barbash?
Thank you.
You know I'll tag on
23
with my other western counterparts on the panel here.
24
think there's several ways without repeating my written
25
comments that were filed in this.
I
133
1
Several areas where more coordination could be
2
beneficial, I mean with the shared jurisdiction of
3
transmission I think informal coordination and collaboration
4
can only help.
5
Up here in the west you know, NV Energy who I
6
work for, operates within a lot of states.
So we have one
7
state regulator to work with, and it's been relatively easy
8
to get the state on one page regarding the transmission
9
investments that are going to be necessary, the natural
10
disaster plans, to only for grid hardening but for proactive
11
outage management and restoration, as well as you know the
12
markets that need to be developed.
13
And I think you know our states can all get on
14
one page, but we can't do it all within one state.
Markets
15
will take regional coordination.
16
pathways of getting there, but nobody wants to increase the
17
carbon output.
18
all headed in the same direction maybe with different
19
policies.
We all have different
No one has the goal of doing that, so we're
20
And you know if FERC could facilitate any way to
21
maintain that, those state preferences for the path that we
22
get there, but how the markets can improve.
23
the natural disaster recovery that we're all embarking on to
24
deal with climate change is also new to all of us.
25
How you know,
And I think you know, any coordination or best
134
1
practices in cost recovery of grid hardening, and recovery
2
of such plans could be helpful.
3
know helping with regional transmission expansion which
4
we're going to need for resiliency as we've seen in Texas,
5
to respond to these climate change events.
6
You know and then again you
Any help that we can get to help coordinate and
7
prioritizing federal permitting agencies and across
8
different states would be helpful in order to increase the
9
resiliency to us so that we can respond to climate change
10
and natural disasters.
11
MS. WHITE:
12
MS. HOFFMAN:
Thank you and Secretary Hoffman?
Thank you very much.
I will just
13
re-emphasize the points that we all recognize that we have
14
an interconnected system, blurring of the lines between the
15
transmission and distribution as Karen brought up.
16
including that this raw introduction of distributed energy
17
resources, and what David Terry brought up of the dependency
18
issues as recognized the interdependency with natural gas.
But
19
I guess what I wanted to emphasize is really what
20
should be the goals and focus of the coordination as part of
21
the question.
22
risk-based approach with investing and building blocks which
23
was already discussed, the visibility, the data, and the
24
transparency so that we actually could have a coordinated
25
conversation of what infrastructure investments are required
And I think we really have to take a
135
1
to mitigate climate change and security risks facing our
2
nations.
3
Specifically, the goal I would say is to do some
4
sort of regional stress test, you know, whether it's every
5
year, every other year with building blocks so that we learn
6
from prior analysis in the work that the regions have done,
7
and then really be able to prioritize mitigation efforts
8
that will allow for competitive solutions to be developed,
9
it would put the risks on the table and what the priorities
10
are that we collectively want to address.
11
And then we can also build off of some of the
12
work that the Department of Energy has done for the
13
organizations with the state energy assurance assessment,
14
risk assessment, resilience, maturity models, and add all
15
that into the conversation.
16
MS. WHITE:
Thank you.
Thank you.
I just wanted to check if
17
the Commissioners wanted to ask any questions, or I can
18
continue in the interim.
19
Commissioners have a question.
20
I'll continue until the
Now on question two Ms. Barbash touched with
21
this, and it's given that climate change impacts will not be
22
limited to a single jurisdiction, how can industry standards
23
best evolve on a coordinated basis?
24
respond?
25
MS. MEYER:
Would anyone like to
Commissioner Tawney I see your hand.
136
1
MS. TAWNEY:
Thank you.
I think this is a
2
challenging issue as we've heard for the last two days.
3
There's clearly a great deal of evolution that needs to
4
happen on operating standards, and design standards, and
5
construction standards, and on and on.
6
challenge is both geographically we face different risks in
7
the west, the topography of the west makes us very
8
transmission dependent, with the various communities sort of
9
at the end of very long lines, and that's just a reality of
10
our landscape, not because we've sort of over optimized our
11
system.
12
I think the
And so solutions that work here, outcomes that
13
work here might not be effective elsewhere.
14
and maybe even more important point the risk that we're
15
trying to adapt to here is constantly changing and evolving.
16
So we're a compliance based model of meet the standard and
17
you're done worked in the past.
18
not going to be sufficient going forward.
19
In a related --
It's really clear that's
We need standards that could be taking in the
20
near data, the new reality on the ground, and evolving
21
rapidly.
22
standards, or taking actions that really try to encourage
23
that iteration, that encourage that continuous learning,
24
maturity model approaches, and really drive after the
25
outcome as opposed to the particular pathway to that
So I would look for FERC to be setting out
137
1
outcome.
2
And throughout all of that as a state regulator,
3
I would love to see a really deep focus on the
4
cost-effective risk reduction.
5
I don't mean further discussion from yesterday about sort of
6
how much reliability will customers be willing to pay for.
7
When a community needs to pump water to fight a
It's a critical metric.
And
8
fire, the electricity is at that point priceless.
It's much
9
more I think a question that we have limited time, we have
10
limited resources.
11
risks.
12
investments across our customers.
13
what those no regrets investments are that were mentioned
14
yesterday.
15
needed, and what is going to really reduce risk, and what is
16
sort of nice to have and would be an interesting option,
17
but.
18
We're already behind on some of these
We have a very small population to spread these
We really need to know
And we need some help sifting out what is
And I think that's an important challenge for us
19
as state regulators.
We don't have a lot of data to base
20
those decisions on.
21
conservatively.
22
and that leaves us in a really difficult position, but I
23
think FERC could help us find our way through with the
24
practices and standards and guidance and cooperation with
25
the labs as well.
We don't want to say no too
We don't want to say yes too aggressively,
138
1
MS. WHITE:
2
MS. BARBASH:
Ms. Barbash?
Yeah and I agree with Letha that it
3
is a difficult issue because we are -- we all have different
4
natural disaster scenarios as well, climate change scenarios
5
from hurricanes in the southeast to wildfire in the west.
6
And so we're all dealing with different types, and that
7
requires different investments, and it requires different
8
response and different restoration.
9
So it is hard to set standards.
It would be
10
easier to do on a regional basis than a national basis
11
perhaps.
12
practices, and customizing those plans towards what each
13
area is actually going to be dealing with, and what it
14
should be planning for.
But again, collaboration can't hurt on best
15
MS. WHITE:
Chair Scripps?
16
MR. SCRIPPS:
I agree with what both Carolyn and
17
Letha, but I also think that that sort of to the Chairman's
18
last point, there's enough opportunity for learning here as
19
well, in addition to standard setting.
20
you know the west is going to have a whole lot more
21
experience with wildfires that we are in Michigan, but we do
22
have them, but probably not enough for us to develop our own
23
sort of expertise.
24
25
So unfortunately,
But being able to then rely on what's been done
in the west when we have those events.
We're taking the
139
1
vast and unfortunate expertise that we have with winter
2
weather in Michigan, for when those events strike in Texas
3
and the south where maybe they don't have those, you know,
4
but in terms of how we approach weatherization of lines in
5
the generation assets and the like.
6
I think you know diversity is a strength and in
7
this area too, and I think being able to learn from others
8
who experience these extreme events more often than we do I
9
think provides an opportunity.
10
11
I also think you know to
Letha's point about sort of compliance-based standards.
I think one of the most challenging pieces in
12
this is that sort of naturally, and certainly for historic
13
reasons, we continue to plan based on the realities of the
14
past, and I think as we get into sort of extreme weather
15
happening more often and in more extreme ways, we're going
16
to require whole new disciplines to be brought into our
17
forecasting and planning that we've never really used
18
before, and that sort of gets to the question of how you
19
coordinate with other federal agencies or others that it
20
will impact later on.
21
But I think sort of thinking ahead to that there
22
is -- we're going to need people who have never been
23
involved in electricity planning to be pretty actively
24
involved here in order to sort of anticipate what's coming
25
and not just plan for the systems that needs to happen.
140
1
MS. WHITE:
Thank you.
Mr. Terry?
2
MR. TERRY:
Yeah, I certainly agree with the
3
comments.
4
regional or subregional risks and the uniqueness that's out
5
there in what we're experiencing in different parts of the
6
country is the one we've been thinking about most.
7
also -- I know this is
8
set aside cybersecurity risks as a part of this where we
9
might see an overlay of extreme weather and cyber.
10
I want to come back to though I think the
And we
not the topic, but we can't really
And I was thinking what Acting Secretary Hoffman
11
mentioned about risks, stress tests if you will.
12
that might be an interesting way to go at the new kinds of
13
weather events we're having frankly, that we're just not
14
prepared for looking in that historical lens.
15
I think
I guess lastly in this area, I think there's an
16
opportunity to think more about the cost benefit pieces and
17
what some of the alternatives there are from ranging from
18
grid hardening to changes on the end use side of the
19
equation where we had mission critical actions, which may
20
fall outside of critical infrastructure.
21
the fuel sector, they could be in the processing for that
22
matter as we've seen this week as maybe an odd example, but
23
nevertheless it's real.
24
25
They could be in
So I do think we have to approach risk in a
different way, and I guess quickly, one thing we've learned
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1
on emergency preparedness and response with the energy
2
offices over the last several decades to state the obvious,
3
those states that have experienced a lot of hurricanes or
4
wildfires I think have a much better feel for how to address
5
and work with this issue across borders within their own
6
states.
7
If they haven't experienced these kinds of
8
events, it's much more challenging, and I think we have to
9
find a way to share just as Chair Scripps was saying, what
10
we know across states and conveying the importance of
11
thinking a little bit different about this than we have in
12
the past, and a federal DOE coordinated activity in the
13
states right along with the private sector.
14
MS. WHITE:
Thank you.
15
MS. WAYLAND:
Ms. Wayland?
Yeah I concur with the remarks that
16
everyone has made about the difficulty of having industry
17
standards given the range of threats that are you know, that
18
confront you based on your geography.
19
And I'll say that another issue with focusing in
20
too much on industry standards is that it puts the onus for
21
resilience for planning to be prepared for disaster response
22
on the industry, and not on society as a whole, and
23
resilience cannot just be the purview of the utility, and so
24
there are a lot of stakeholders that are going to be needed
25
to be involved in these discussions that are not necessarily
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1
within the FERC jurisdiction.
2
3
And so standards alone will not get you to the
resilience that we're looking for.
4
MS. WHITE:
5
MS. HOFFMAN:
Secretary Hoffman?
Karen Wayland hit some of the
6
points that I was going to make, but I'm going to just
7
re-emphasize that standards are just the center performance
8
expectations, and it is really retrospective.
9
we're really talking about,
10
And so if
think we have to use the right
mechanism to grab what outcomes we want to achieve.
11
And so if we're really talking about on a minimum
12
level of performance, we're looking at something
13
retrospective in the past, how do we mitigate from a lessons
14
learned?
15
standards are challenging when you want to really look
16
towards the future, or you want to really mitigate impacts
17
that may be coming our way, and I think you have to figure
18
out what is the appropriate mechanism to really drive some
19
of those future investments, and I think there's a balance
20
in them.
You can really go after the standards.
21
MS. WHITE:
22
MR. HOWARD:
The
Mr. Howard?
Yeah I want to echo other people's
23
comments.
I concur with many of those.
What I find is
24
industry in the electric sector is very good at sharing.
25
share lessons learned quite often, whether they're publicly
We
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1
on the utility, an investor on the utility, or a rural
2
electric, I mean we don't seem to have a lot of boundaries
3
there in sharing information through a lot of our different
4
professional organizations.
5
And so I think that is already built really well.
6
Where we seem to be having a lot of problems I've been
7
dealing with wildfires now for six years straight impacting
8
our facilities, our communities, and we seem to be having to
9
deal with more challenges in standards and regulations when
10
it comes to the recovery and the rebuilding evidence, and
11
trying to rebuild in a new way to maybe not run into the
12
same issues that you have previously become more and more
13
difficult.
14
And example would be you know we had a number of
15
wildfires, and this takes place along the whole west coast,
16
where you know when you have wildfires and they burn through
17
these watersheds, and then you hit that winter season and
18
all of a sudden you have the rainfalls, the heavy rainfalls,
19
and all the hillsides come down in and fill up our
20
reservoirs and our hydroelectric bands are filled up with
21
assignments.
22
You know you have the standards under which we
23
can remove it outside and we're built for these types of
24
activities.
25
that are in place today become bigger barriers for us to
And so what we find is more of the standards
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1
recover quickly and move on to prepare for the future, and
2
so yeah I'm just challenged sometimes with historical
3
standards that are used, and how we're moving in some of
4
those events in the current climate we are working in.
5
MS. WHITE:
6
MS. TAWNEY:
Thank you.
Commissioner Tawney?
I just wanted to very quickly, build
7
on Secretary Hoffman's point around finding the right
8
metric, the right incentive.
9
with some performance based ratemaking around the vegetation
10
We're experimenting in Oregon
management and wells hardening for exactly that reason.
11
And I think it's a conversation we need to have
12
more broadly about how do we really set out the end goal
13
that we want to have these facilities deliver on, and then
14
give them space to go figure out how to do that because we
15
can't -- we will not be able to dictate the right answer,
16
the right balance, for the OEM capital prospectively, so I
17
look forward to all the research we can get for doing that,
18
all your research programs on how we can deepen our metrics
19
for performance-based ratemaking on some of these fronts.
20
MS. WHITE:
Okay great.
We'll go on to the next
21
question.
22
collaboration by regions be pursued in order to focus on
23
region-specific climate change and extreme weather needs?
24
Would anyone like to tackle that one?
25
Should some type of formal or informal
MR. SCRIPPS:
Chair Scripps?
I guess in the interest of getting
145
1
the conversation started on this.
2
say one of the things that we learned coming out of 2019 was
3
and it's been mentioned already, but the interdependence
4
between the electric and the gas sectors.
5
necessarily a region-specific thing, but I'll say in
6
Michigan and across a lot of the northern Midwest gas is our
7
primary heating tool.
8
9
I mean yes, and I will
And that's not
In Michigan it's 25 percent of homes use gas as
their primary heating tool.
You know RTOs are by definition
10
electricity focused, and they have a responsibility that
11
they take very seriously, and they should, to maintain the
12
reliability of the electric grid.
13
But as a greater percentage of both PJM and
14
MISO's fleet is gas-fired, what do you have -- what do you
15
do in a situation like we had in January of 2019 where you
16
have gas constraints as a result of the inaccessibility of
17
some of the underground storage in Michigan caused by a fire
18
at a compressor station where the gas system is in real
19
jeopardy of not being able to continue to deliver heat.
20
And at the same time MISO has called a max gen
21
event and needs all resources online.
And I think that's a
22
place where regionally, and with federal partnership again,
23
we need to understand the priority stack.
24
same gas flowing for two different purposes, which one wins
25
out?
When you need the
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1
And I know how I would answer that in Michigan,
2
just given the difficulty of reconnecting people if we had a
3
guest on a disruption.
4
forgiveness after the fact.
5
the person that gets to answer the question.
6
real clarity ahead of time, and that's probably regional
7
among states that share certain attributes, but we had
8
scheduled partnerships again so that we know going in to
9
that sot of emergency situation exactly how we're going to
But that's sort of asking for
And I'm not even sure that I'm
And so I think
10
respond, and that we're going to be backed up at the end of
11
the day.
12
I think that's going to be really important.
The
13
other one that I'd say is probably also of interest is you
14
know folks don't really care why their electricity goes out
15
-- if it's a transmission failure, or a distribution
16
failure.
17
resilience on the distribution grid, and I will say I know
18
I'm from Michigan, but the Ford announcement, and the number
19
three selling point of their new electric truck is it can
20
power your house for three days, or 10 days if you're
21
rationing.
22
And if there are opportunities to look at
And so starting to think about how those new
23
technology applications provide resilience on the
24
distribution grid, you know, that's not FERC jurisdictional,
25
but it certainly gets into the issue of if transmission
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1
which is -- and again, that probably goes back to question
2
one, overlap and the need for dialogue on these cross
3
jurisdictional issues.
4
MS. WHITE:
Thank you.
Secretary Hoffman?
5
MS. HOFFMAN:
6
little bit blunt on this question.
7
realize that we are transferring a great amount of risk to
8
consumers as we talk about this dialogue, and so therefore,
9
I mean regional insight is extremely important.
So I'm probably going to be a
And I think we have to
And I think
10
we recognize that there are challenges out there, and we
11
look at the lack of investment and capacity.
12
We look at resource adequacy issues, we look at
13
lack of hardening.
We look at the inability to set
14
priorities as we want to mitigate contingencies.
15
think we have to think about this that our investments need
16
to be on behalf of consumers and customers, and you know,
17
the ratepayers as we move forward.
But I
18
So we have to keep in mind the affordability as
19
we look at how we want to provide signals, market signals,
20
but visibility and awareness to consumers for their decision
21
whether it comes to distributed energy resources.
22
as some of the discussions that were talked about earlier
23
with respect to emergency pricing and scarcity pricing, we
24
have to really think about the promise of what we were
25
looking at as we look at markets.
You know
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1
But how do we really ensure affordability to
2
consumers who it's for?
3
that's available will allow for educated decisions by
4
consumers, but also affect of emergency response and
5
investment decisions moving forward, thank you.
6
MS. WHITE:
7
MS. TAWNEY:
So to me having that information
Thank you, Commissioner Tawney.
Those are approaches, really
8
excellent points raised by my colleagues.
I think I would
9
add a more mundane, or more foundational point which is I
10
think at a regional level we, or at least I as a
11
decision-making, and I think as our utilities work through
12
their integrated resource planning and begin to try to think
13
about what a mid-century climate, or even within our IRP
14
horizon what that climate looks like, we struggle with sort
15
of the downscaling and application of climate models.
16
What is it we're planning to?
And especially as
17
we way -- we have a long-lived asset at the distribution
18
level, but also the costs of transmission upgrades and
19
transmission hardening coming through rates, how long will
20
those last?
21
transmission siting about whether lines are designed for
22
mid-century fire regime.
23
We are already getting questions in
And I don't have necessarily good answers for
24
that.
The utility has made their design efforts, they have
25
hired their experts, and I think regionally when I think
149
1
about the west there is a way in which this climate impact
2
is going to unfold across the west through the Rockies and
3
the Great Basin, and we need to be talking to each other and
4
tapping national level resources to understand what it is
5
we're even planning to.
6
And we need some help with that.
I think we have
7
great local institutions here in Oregon.
We have Oregon
8
State University that can give us downscale climate impact,
9
but applying that to the electricity sector is not their
10
skillset.
And we need some help with making that bridge so
11
that we really have a sense that we're putting steel in the
12
ground that's going to be useful in 10 or 15 years, and not
13
creating a new resilience problem.
14
And I think we need to do that in a regional
15
conversation because we're all experiencing the climate
16
change in a similar way and can find some economy to scale
17
in that dialogue.
18
MS. WHITE:
19
MR. HOWARD:
Thank you.
Mr. Howard?
Yes thank you.
I'm going to touch
20
on this from a little different perspective from regional
21
collaboration just a need that require.
22
have touched on it regarding mutual aid and the ability to
23
support one another when things get very difficult.
24
25
Some of the panels
And using wildfires we had a situation where five
of our employees lost their homes, and many more families
150
1
were evacuated from their homes due to wildfires coming
2
through the areas, and really at that point you can't really
3
on that staff.
4
needs of their own family in getting their family to a safe
5
location.
6
That staff needs to address the critical
But what we really need more of is just that
7
collaboration on a regional basis.
We can support staffing
8
needs and resource needs and we found this as well when many
9
of our members were looking to support Texas when they had
10
their issues with transformers and equipment to support
11
them, so they could do their restoration efforts, and then
12
the wildfires came, and we had a need and didn't have
13
sufficient transformers.
14
But those types of regional collaborations become
15
quite critical.
And if you're in the middle of a crisis
16
we'll recover in that crisis, and that regional
17
collaboration is just so important for us to be better
18
prepared for these type of activities.
19
MS. WHITE:
Thank you.
Mr. Terry?
20
MR. TERRY:
I think just two areas I would add,
21
and I certainly the answer is yes on regional coordination.
22
I would emphasize again I think there's something to be said
23
for subregional if you will, the unique characteristics we
24
see emerging in some markets.
25
Florida is a great example.
The last major
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1
hurricane event they had the end I think, the hotwash of the
2
situation the state decided they needed to reduce the
3
evacuations by about half.
4
transference of risk, but also puts them in a very unique
5
position of how they need to address their electric sector,
6
which I think they're well on the way to doing, but that's
7
very different than some of the predictable interdependence
8
we see from hurricane events in the southeast that result in
9
fuel interdependencies.
10
That is another kind of
Colonial Pipeline fuel interdependencies as an
11
example.
In the northeast we have a number of states that
12
are pursuing very aggressively electrification policies in
13
the residential sector where gas limitations of the types
14
Chair Scripps mentioned are a very serious problem.
15
And we're transferring fuel risk if you will from
16
delivered fuels to electricity in a way that even around the
17
margins will have a very big impact.
18
another layer here that is very specific that is a near
19
term.
20
to be action, and I think we need to move more quickly.
21
to me that says we probably need to go beyond the regions to
22
hit some high priority risk areas just by nature of either
23
the weather risks they have, or the system and policy risks
24
that are being baked into the future.
25
So I think there's
I think there's an urgency to this issue that needs
MS. WHITE:
Thank you.
and Ms. Barbash?
And
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1
MS. BARBASH:
Thank you.
You know I think I
2
overlapped a little bit on the last question about you know
3
regional coordination being necessary because of the
4
similarity and the differences in the types of the climate
5
change initiated natural disasters.
6
But you know I think it spans across all
7
timeframes for a real time when you're in an event, you
8
know, our reliability coordinators have more situational
9
awareness than a piecemeal by piecemeal, you know, this is
10
how things are affecting me, so this is what I'm going to
11
do.
12
And that's really their role.
And more
13
coordination on these new efforts.
14
all of us, all of this.
15
know are there regional projects that can provide more
16
redundancy than a local project?
17
coordination on that.
18
You know this is new to
And then in the planning stages you
So we need regional
And then we need regional standards on you know
19
whatever kind of climate change disasters you may be facing
20
in your region, whether it be wildfire, earthquakes,
21
hurricanes, the type of grid hardening investments that are
22
best practices to kind of repeat what Commissioner Tawney
23
said.
24
25
And then lastly, how is it all being paid for?
You know again, it's a multi-jurisdictional asset.
We are
153
1
hardening the distribution grid and the transmission grid,
2
and to the extent that there's multi-beneficiaries, what's
3
the best process for recovery of this?
4
5
So there's different time horizons, and
collaboration, that's all I know.
6
MS. WHITE:
7
MS. SCRIPPS:
Thank you and Chair Scripps?
Yeah I know I have already spoken
8
to this, and I know that the question is on regional
9
collaboration, but I didn't want to leave this without also
10
just underpinning the need for interregional collaboration.
11
When you look at the transmission planning it's hard enough
12
within a RTO, but with the process of transmission planning
13
between RTOs and across is next to impossible.
14
And you know, and so I think we all know why.
I
15
mean we can answer why we're in the system and it makes
16
sense on its face, but as we sort of move into a future
17
that's more unpredictable and where transmission can help
18
address some of those things, you know it's not going to be
19
enough that we know that power flows between markets and
20
then we can deal with it in the settlement process.
21
We've got to find a way to break through that
22
sort of siloing between RTOs, and find ways that we can get
23
projects done that sort of cross those jurisdictional
24
boundaries.
25
MS. WHITE:
Okay.
Oh sorry.
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1
MS. MEYERS:
We'd like to switch gears slightly,
2
with just that Commissioner Clements is traveling.
3
listening in to the panel and she sent us a question, so I
4
will convey it to you.
5
standards alone aren't sufficient.
6
standards should the Commission put in place to mitigate
7
future impacts?
8
9
10
MS. WHITE:
She's asking we've heard that the
What mechanisms beyond
Ms. Barbash would you like to answer
that question, or was that hand up from the previous
question?
11
12
She's
MS. BARBASH:
You know that hand was up from the
last question, but can you repeat that question I'm sorry.
13
MS. MEYERS:
Absolutely.
The question is we have
14
heard that standards alone aren't sufficient.
What
15
mechanisms beyond standards should the Commission put in
16
place to mitigate future impacts?
17
MS. BARBASH:
Well since I accidentally had my
18
hand up, I will just say that I don't know that we're ready
19
for national standards.
20
unique.
21
collaboration before we start with any hard and fast one
22
size fits all standards.
Each region is so unique that we need to start with
23
MS. WHITE:
24
MS. TAWNEY:
25
Again, I think each case is so
Commissioner Tawney?
Well thank you for the question, and
I appreciate that you're listening even as you're on the
155
1
road.
We're all stretched so unbelievably thin as we tackle
2
all these challenges.
3
that you have, that FERC staff faces in grappling with all
4
of this.
5
So I really appreciate the challenge
We're grappling exactly with this question when
6
we are trying to write rules on wildfire mitigation planning
7
right?
8
review their plans for completeness, for safety, for
9
reasonableness.
We don't manage the utility, but we need to somehow
We'll do a purview review after they've
10
made the investments, but what standards will we hold them
11
to?
12
And I think we keep coming back to what are the
13
outcomes we want to have and what can we measure right?
14
ignitions, smaller PSPS, fewer customers impacted for
15
shorter amounts of time when you do have to do a PSPS for
16
example.
17
Few
But also how are they accessing the best
18
risk-based analysis?
19
analysis into their decision-making so that the choices that
20
they do make whether it's design standards, or operational
21
practices, really meet the risk where it is and where it's
22
going to be in five years.
23
How are they bringing evolving risk
If it take you four years and you're on a four
24
term cycle for your vegetation plan, you've got to determine
25
for where vegetation is going to be, you know, I'm already
156
1
having a wildfire challenge, you know it can't take four
2
years to absorb a change in what needs to be trimmed, or to
3
adapt to changing tree mortality for example.
4
So I think that I don't have an answer, but I
5
will say as a state regulator we're grappling with the same
6
question at distribution level and we're feeling -- I am
7
feeling very hungry for more data to try to base the
8
decisions on and to set out the incentives for those kinds
9
of choices.
10
And I think incentives are important because we
11
actually don't know quite which technical solution is going
12
to work or be best, and so I couldn't define you must use a
13
steel pole there.
14
here, but a non-explosive fuse there.
15
ridiculous for me to try to do that.
16
to emerge as the best solution.
17
You must use these kind of reclosures
It would be
Who knows what's going
How do we get our arms around the data, so that
18
we're making good choices?
19
investments?
20
across a range of disasters?
21
ever seen on Labor Day here in Oregon, to an ice storm that
22
brought two inches of ice to a part of our system that had
23
been engineered for a half inch because we have never
24
historically seen anything more than that.
25
And what are the no regrets
What are the ones that are just applicable
We went from fires unlikely
And we have some of the largest, longest duration
157
1
of largest outages in February that we've had in our
2
history.
3
It's quite a bit to absorb, so I'll leave it there, but I'd
4
love an answer as well.
And that's you know in less than six months swing.
5
MS. WHITE:
6
MR. HOWARD:
Thank you.
Mr. Howard?
Thanks for the question
7
Commissioner.
I think there's a place for universal
8
standards, and we've already heard that universal doesn't
9
necessarily work for every region, but as a utility
10
operator, cold based guidelines, so out of FERC maybe
11
guidelines that are more concerned or related to
12
performance, or advisory positions at FERC are very useful
13
for the utility sector versus just rigid requirements.
14
Those are just some of the things that I would
15
suggest as we're walking through a transition, and not
16
knowing exactly where that place is going to be, and so I
17
would recommend more along the guideline approach.
18
MR. WHITE:
Chair Scripps?
19
MR. SCRIPPS:
I agree with a lot of what
20
Commissioner Tawney said, not surprisingly, but I want to
21
sort of expand on two of the points and then add one.
22
totally agree.
23
sort of that would be the answer.
24
provide some space for experimentation and innovation, and I
25
think that incentives can play a role in that to figure out
I
I think if we knew the answer here we would
And so we've got to
158
1
what are the right technological fixes that rises to the
2
top when different approaches are tried.
3
But that's based for experimentation backed by
4
some of incentives to sort of encourage utilities to go in
5
places that they might not otherwise I think is a really
6
important piece of figuring this out when you don't have
7
experience.
8
9
The second piece that she mentioned was some of
those no regrets.
I would say I know Alison yesterday was
10
talking in one of the panels, Alison Silverstein, on some of
11
those things.
12
with this.
13
efficiency can play a role in this, so it just helps the
14
system overall.
15
So we know that more flexible load can help
We know even though it's not sexy, that energy
There's a certain amount of transmission build
16
out and we can argue about what that is, but it is least
17
regrets, or no regrets, and I think that just prioritizing
18
these things as we continue to sort of figure out some of
19
the pieces.
20
sort of cybersecurity, not the topic today, but some of the
21
ways that we're addressing challenges that we can't figure
22
out yet that continue to evolve faster than the regulatory
23
process I think have a place here.
24
25
And then the last is I know David mentioned
By the time we impose a rule on our utilities,
you know, that cyberthreat is six generations in the past,
159
1
and so instead we've used things like DOE C2MT
2
self-assessment tools, and just keep asking questions.
3
that sort of process based approach as opposed to a
4
standards based approach, particularly in sort of
5
fast-evolving areas I think has you now applicability here
6
to.
7
MS. WHITE:
8
MS. WAYLAND:
9
Thank you.
Yeah.
And
Ms. Wayland?
I mean we've been talking
about investments that utilities would need to make perhaps
10
system-wide, but you know Commissioner Clements you're
11
asking what else can FERC do other than standards?
12
think a lot of the focus when it comes to climate and FERC
13
has been on emissions.
14
And I
And how you might use the Federal Power Act and
15
other authorities at your disposal to deal with emissions
16
associated with such projects.
17
question about whether you need to use statutory authority
18
to look at the climate risks of new infrastructure -- what
19
kinds of risk ought we need to be addressing when a project
20
is being constructed.
21
But I think there's also a
So I don't have the answer, but I think it's
22
worth you know, those who are legal experts at FERC's
23
authorities to look at to what extent you have authority
24
within project approval processes to deal with the climate
25
risks.
160
1
MS. WHITE:
Thank you.
2
MS. BARBASH:
Ms. Barbash?
Thank you and I'm going to lower my
3
hand.
You know I had some more time to think about this
4
question, so Commissioner Clements.
5
standards, but maybe some evolution of some ancillary
6
services that FERC already has jurisdiction over, already
7
has in place.
So really not new
For instance, you know the operating reserve.
8
Maybe we need more flexible ramping capability to
9
deal with intermittent resources that we're trying to put in
10
place to combat climate change, and to deal with some of the
11
natural disasters.
12
service required as an ancillary service.
13
In Order 888 we didn't have a back stop
And today when we're replacing these load serving
14
entities can get their deliveries and their resources in,
15
you know, we really need to think about do we shed load, or
16
do we try to serve them if we can as a transmission provider
17
that does have resources.
18
service may be helpful at this time, where it wasn't in the
19
past.
And some sort of back stop
20
MS. WHITE:
Thanks and Mr. Terry?
21
MR. TERRY:
I think it is obviously a great
22
question.
I agree with what's been said.
I think one of
23
the elements that might be helpful in parallel to this,
24
obviously no regrets items that need to occur on an
25
expedited basis, but I think there's also an educational
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1
component for the non-energy state and local leaders,
2
non-energy business community leaders.
3
I'm not sure that it necessarily is a public
4
issue, but about the cost and expectations of some of the
5
risk management, some of the risk that needs to occur.
6
I think about how much time and frankly federal tax dollars,
7
state tax dollars we've spent in dealing with the aftermath
8
of the cold snap in the south central part of the country
9
for ratepayers and others.
10
Obviously, that needed to occur.
When
That's an
11
extreme event.
12
education about the cost benefit if you will from the
13
non-energy community, and I think that would be another
14
helpful piece that would help at least make these actions
15
more possible from a political perspective, and from a
16
willingness to act perspective at the state level.
17
But I also think there's some level of
MS. WHITE:
Thanks everyone and we'll go onto the
18
last question.
19
coordinate with other federal agencies on climate change and
20
extreme weather? Ms. Wayland?
21
Are there opportunities to beneficially
MS. WAYLAND:
Yes there are lots of
22
opportunities, but it turns out not to be so easy to do that
23
kind of cross agency coordination.
24
different agencies that have some oversight into the energy
25
system and even if we just look at the electricity sector
There are at least 20
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1
it's a large number, you know, everything from Bureau of Rec
2
and how much water do they have in their reservoirs, to the
3
permitting processes that happen across the agencies, the
4
data that's available at NOAA for forecasting and the
5
National Labs.
6
It is critical to do coordination across
7
agencies, but when you know in my experience, when you have
8
a large number of agencies in a very large issue area like
9
climate change, it's far better and I think somebody
10
mentioned it early on, to have specific questions that you
11
want to tackle so that you can actually narrow the number of
12
stakeholders that you want to bring together around to six,
13
but it is critical.
14
And I think that the states would love -- and
15
David could speak to this, would love to have better
16
coordination at a federal level for the delivery of
17
different services that we can offer in this area.
18
MS. WHITE:
19
MR. HOWARD:
Thanks Mr. Howard?
Yes.
I'll just touch on one of
20
those types of activities that I think has been successful.
21
I co-chair a wildfire working group in the electricity
22
subsector coordinating council, and I co-chair with a CEO
23
from the investment and the utility and a CEO from the rural
24
electric, and we directly meet with federal agencies to talk
25
about mitigation activities on the front end on how we could
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1
mitigate wildfire risk and what parts of the measures need
2
to be changed from the vegetation management to other
3
things, to what do we do when we're in the midst of a
4
wildfire and the coordination or distinction of that fire as
5
quickly as possible to the recovery and the rebuilding at
6
the back end.
7
And I think it's been a really good example of
8
how it can be handled when you get to these emergencies, and
9
these types of climate issues.
So I would close out with a
10
good model, and one that could continue to be expanded on.
11
We certainly need more participation from other folks in
12
federal agencies, but it's been good so far to get things
13
accomplished.
14
MS. WHITE:
Thank you.
15
MR. SCRIPPS:
Yeah.
Chair Scripps?
So I agree with Karen.
I
16
think you know the Biden administration I think is to be
17
commended for taking you know part of what we've talked
18
about is this whole government approach.
19
pieces that are really critical to that are one
20
coordination, and I think you know the role that Gina
21
McCarthy and her office plays, even the way it's
22
coordinating across agencies tend to be understated in this,
23
in terms of making it work and that everything is happening
24
together.
25
I think the two
And then sort of relatedly, it needs to be
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1
focused on execution.
2
take on specific tasks and not just sort of falls under its
3
own weight.
4
coordination function sort of is there at the back end too.
5
The one piece that I would add that may not actually get
6
covered in here is where this shows up in terms of the
7
emergency response.
8
So how do you get into the weeds and
And again, without being silent, so that
And so involving groups like FEMA that may be
9
left out of this conversation otherwise, but are absolutely
10
critical you know when things go back in getting things back
11
up.
12
you know, any number of instances where we're going to need
13
greater coordination.
You know we've seen it in Puerto Rico, we've seen it in
14
And then from the state role where that shows up
15
is you know our state emergency operations center is housed
16
within our state police.
17
government and the states, and then within the states also
18
making sure that we know who are partners are, making sure
19
that those relationships are strong before an emergency, so
20
you're not asking you know who this person is, and who that
21
person is sort of as the emergency is unfolding.
22
So both between the federal
You know we've learned some lessons both through
23
the 2019 polar vortex, but candidly also through COVID and
24
COVID response that hopefully we can sort of build on and
25
leverage to make sure that we're better prepared on a going
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1
forward basis.
2
MS. WHITE:
Thank you.
3
MS. BARBASH:
Thank you.
Ms. Barbash?
You know I would start
4
by saying that at the risk of sounding very na ve, or maybe
5
the first thing we should start with is figuring out why it
6
has to be so hard for federal agencies to coordinate.
7
then secondly, I would say that there's a lot of opportunity
8
there.
9
And
You know, the obvious thing in the west, and I
10
keep going back to that because that's where I have the most
11
experience.
12
we have, and the multiple agencies that have jurisdiction
13
over permitting on federal lands.
But it is in the amount of federal lands that
14
And it's really helpful to have one agency take
15
over a project, and run the NEPA process from beginning to
16
end, coordinating with all other federal agencies, whether
17
VLN, or Forest Service, one of them taking charge and
18
coordinating with the other as well as all the counties,
19
cities and local jurisdictions in order to get the
20
permitting done.
21
It's also very important to have a consistent
22
method for these NEPA processes, so they can't be questioned
23
later -- an expedited process for it in the world we're
24
dealing with now.
25
then take 10 years to build it.
We can't decide we need transmission and
That's just not an option
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1
right now when we're trying to get reliable dispatch of
2
renewables, access to renewables, it can't take that long.
3
And you know and then just maybe where FERC can
4
be involved because it knows the projects which should be a
5
priority for resiliency redundancy, accessing renewables for
6
climate change, and maybe some prioritization of those
7
projects.
8
contact when managing resources and budget for these
9
projects as well, and you know those are my suggestions.
And even from a federal standpoint, one point of
10
MS. WHITE:
11
MS. TAWNEY:
Commissioner Tawney?
Thank you.
There's been a lot of
12
great suggestions, and the federal lands issue is really
13
important in the west.
14
that the electricity subsector council has done on fire.
15
I have really appreciated the work
I think they've really smoothed the path for
16
education management on federal lands, although there is
17
just the task is enormous around the infrastructure
18
rights-of-way, but they are at least having the
19
conversations, and we have seen movement out here in Oregon,
20
for example with the federal agencies on getting better
21
access and so on.
22
But I think to raise a really narrow specific
23
issue you know the FCC has you know deregulated the
24
communications sector, and you know we carry the emergency
25
support function for communications and energy in our
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1
Commission, and we find over and over again that this
2
conversation that we're having here about resilience around
3
a critical service isn't happening in the same way in
4
broadband and cell, and other areas of communications.
5
And where that lacks with meeting to do, for
6
example, public safety power shutoffs because it is simply
7
too unsafe to run the electricity system in some weather
8
conditions, and their response is to ask ratepayers to
9
harden the lines out to the cell tower.
And I think we have
10
a real challenge here around who's job is it?
11
pocketbook should the resilience investment come out of?
12
Who's
And someone earlier had raised just as a societal
13
issue, and this is just this FCC question is a very narrow
14
expression about that larger societal issue.
15
ratepayers cannot make the whole societal infrastructure
16
resilient.
17
really deep engagement or urgent conversation at least with
18
some of the other critical services sectors about what
19
they're doing to be ready.
20
Utility
We can do our pieces, but there needs to be
Because as much as we want to you know educate
21
that there is going to be a cost benefit to these
22
investments, we're not going to get better reliability than
23
we've had in the past.
24
reliability than we would have if we hadn't adapted to
25
climate change.
We're going to get better
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1
We're going to see it at least in the west for
2
some time reduce your liability at a higher cost as we try
3
to absorb the impact of climate change, and that is going to
4
be difficult for customers to understand if we have to also
5
then, trying to build out resilience for the whole essential
6
services sector, because they didn't make the investments,
7
we'll be really, really stuck.
8
9
And so at the federal level having those hard
conversations would be really welcome from a state regulator
10
perspective, so they're not conversations that I can
11
necessarily move the ball on, but are coming home to roost
12
when the cell tower that supports the first responders in a
13
county goes down, and they can't talk from one side of the
14
county to the other, they sort of end up in my office and I
15
can't help, and that's very frustrating.
16
that specific example on the table as something that would
17
be great to work on.
18
MS. WHITE:
And Mr. Terry?
19
MR. TERRY:
Thank you.
So I'll end with
I think this is one of
20
the more important questions I thought from a state energy
21
office perspective.
22
federal coordination to build on with the Department of
23
Energy, your office and also some electricity in the
24
emergency response, and to an extent mitigation space to
25
build from, the collaboration there across agencies and fuel
We have I think a great foundation of
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1
types have been I think having seen it go from very limited
2
two decades ago to what we have now, maybe that perspective
3
that the bar seems maybe better than people think.
4
I think we have a lot to build on there, though
5
whether that's a resilience council of some kind of not, but
6
I think that's a great starting place.
7
Wayland said that really resonated with me.
8
to pick some actionable high priority areas and then focus
9
in on those, and use that sort of existing foundation that
10
Something Karen
I think we need
we have in those two sectors.
11
And one maybe small sliver of that that I think
12
would be a great example, the FEMA brick program which
13
really has an important energy element, and I think in DOE's
14
help with the energy offices and the Commission's, to help
15
utilize those funds that are in the billions of dollars each
16
year now as a result of the Disaster Recovery Reform Act.
17
That's a very ripe opportunity, and certainly
18
FERC engagement in that process would be welcome and
19
certainly very useful.
20
specific actions that we would call out.
21
MS. WHITE:
So I think those are a couple of
Alrighty thank you.
Very interesting
22
discussions, and we thank everyone for participating in both
23
the conference and this panel, Alyssa?
24
25
MS. MEYERS:
panel.
We have reached the end of our
So yes, and thanks as well and we'll now turn to
170
1
closing remarks.
2
MR. AMERKHAIL:
Thank you Alyssa and Lodi.
Thank
3
you to all of our panelists on both days, and to the rest of
4
the FERC team that put this conference together which
5
includes Jesse Hensley, Alyssa Meyer, Patricia Shab, and
6
Peter Whitman from the Office of Energy Policy and
7
Innovation.
8
9
Sam Hile and Dianna Mobely from the Office of
Energy Market Regulation, Michael Haddad, and Norman
10
Yokodonovat from the Office of General Counsel.
11
Netter and Lodi White from the Office of Electric
12
Reliability and Sarah McKinley, Ester Burdenlee, Masume
13
Malda, Phisa McNearn, Ricky Hernandez, Troy Miller, Niam
14
Majad and Karen Williams from the Office of the Ranking
15
Director.
16
climate change and extreme weather.
17
attended, and we are adjourned.
18
19
20
21
22
23
24
25
Ena, Louise
That concludes this technical conference on
Thanks to everyone who
(Whereupon the conference adjourned at 5:50 p.m.)
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CERTIFICATE OF OFFICIAL REPORTER
2
3
This is to certify that the attached proceeding
4
before the FEDERAL ENERGY REGULATORY COMMISSION in the
5
Matter of:
6
Name of Proceeding:
7
Technical Conference to Discuss Climate Change,
8
Extreme Weather and Electric
System Reliability
9
10
11
12
13
14
15
Docket No.:
AD21-13-000
16
Place:
Washington, DC
17
Date:
Wednesday, June 2, 2021
18
were held as herein appears, and that this is the original
19
transcript thereof for the file of the Federal Energy
20
Regulatory Commission, and is a full correct transcription
21
of the proceedings.
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24
Larry Flowers
25
Official Reporter
| File Type | application/pdf |
| Author | Mark Jagan |
| File Modified | 2021-06-08 |
| File Created | 2021-06-08 |