AD21-13, Transcript of Conference on 6/2/2021

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FERC-1004, One-Time Reports on Extreme Weather Vulnerability Assessments (NOPR in RM22-16 & AD21-13)

AD21-13, Transcript of Conference on 6/2/2021

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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
I

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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9

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.

25

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.

3

thinking about dynamic reserves for renewables, but why

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can't we then also do that for weather and temperature.

5

Folks have been

And so including specific weather events or just

6

temperature itself and forecasting dynamic reserves might be

7

something that we can look into in the future, and we're

8

doing preliminary studies, but of course not necessarily

9

implemented.

10
11

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:

13

is a privilege to be here.

14

just what Sunrun is for those of you who may not know.

15

Sunrun is a distributed solar and battery company, and I

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really appreciate the opportunity to join the panel today

17

because so far I haven't heard much mention of distributed

18

resources.

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I want to just take a minute and

And I'm not sure there was a lot of discussion

20

yesterday either.

21

today is don't forget the distributed resources.

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going to play a critical role, and have played a critical

23

role in the past year in dealing where we have had very

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serious outages.

25

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

2

Commission here to ask if we could get our customers to

3

participate.

4

charge.

5

compensated for it.

As if we could get our customers not to

Ask customers to share their power, but we weren't

6

And so we had been working very hard with CAISO

7

and with the California PUC to explain that you have all of

8

these resources that are available, that can be available to

9

help not just the individual but the system at large.

10

in fact there was something close to 3,000 batteries

11

available last August, about 150 megawatts, and those

12

batteries -- I mean there were more than that available, but

13

those actually voluntarily participated and helped to

14

prevent the outages that everyone was very concerned about.

15

But the capacity was actually much greater than

16

that.

17

that time there are thousands and thousands of more

18

batteries that individuals, companies, schools have

19

installed.

20

account as we do our planning.

21

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

22

just recently entered the market.

But we had hundreds of

23

customers who were able to not only back up their own house,

24

keep their solar operating, but actually have their

25

neighbors and others participate.

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So that's my main message.

You're going to hear

2

it again later in the questions.

3

FERC is fortunately we do have the Order 2222, which is

4

going to play a tremendous role we believe in ensuring that

5

these resources actually are able to participate in the

6

markets, can be compensated fairly for that, and can really

7

be part of this resiliency discussion and reliability

8

discussion.

9

We have some concerns.

But the other point for

We are very optimistic

10

about New England ISO and PJM, who we think are very sincere

11

in their efforts to try to work with distributed resource

12

providers to make sure we can get the right plans in place

13

to make this work, but we're concerned about other ISOs and

14

RTOs who are saying they think they've already done what

15

they need to do.

16

The fact is it's not done.

Except for New

17

England ISO, we are not compensated for any capacity in the

18

RTOs and ISOs, so we look forward to working with FERC,

19

working with other stakeholders, and all I would say is that

20

these are resources that individuals are investing in that

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are available to make our system more reliable and resilient

22

and we just can't forget that thank you.

23

MR. WHITMAN:

Thank you.

We also have a question

24

later on oriented more towards flexibility demand which

25

might incorporate these questions in the comments that you

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have.

If there's no other, are there any other questions,

2

comments, just starting on this particular on our first

3

question?

4

next, we'll start with our next question thank you.

5

If there is no one else then we'll go with our

MS. TOPPING:

Great.

For our next question what

6

current practices exist with respect to recalling or

7

cancelling non-critical generation and transmission

8

maintenance outages during a reliability event?

9

practices sufficient to ensure that all possible resources

Are these

10

and infrastructure needed to address an extreme weather

11

event are available when such events happen unexpectedly?

12
13

And I'm looking for raised hands.

I see Anne's

hand up.

14

MS. HOSKINS:

Apologize, I just forgot to take my

16

MS. TOPPING:

Okay.

17

MR. YEOMANS:

Yeah thank you.

15

hand down.
Let's go to Wes.
Yeah the New York

18

State during extreme heatwaves and in the winter is a very

19

tight, transmission electric system.

20

the load is in downstate, southeastern New York, Long

21

Island, New York City, a lot of generation capacity in

22

upstate in what I would call limited transmission.

23

The great majority of

So it is very important in predicted tight

24

conditions, or unexpected conditions that we can get

25

transmission.

I recall there may be more important don't

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1

let it out in the first place for ordinary scheduled

2

maintenance, you know, forced outage is unavoidable, but if

3

there's the ability to move scheduled outages to other low

4

level time periods or less stress conditions we always

5

strive to do that.

6

We do have the authority to direct transmission

7

owners to recall transmission lines as need per ISO TO

8

agreement that we executed in 1999.

9

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

82

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

83

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

84

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

85

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

86

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

87

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

88

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

89

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

90

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.

91

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

93

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.

94

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

95

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

96

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

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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

102

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

104

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

106

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

107

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

109

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

110

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

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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

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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

123

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.

131

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

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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

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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

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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.

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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

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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,

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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

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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.

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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

143

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

146

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

147

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

148

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

151

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.

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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

161

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

162

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

163

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

164

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

165

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

166

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

167

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

168

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

169

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.)

171

1

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.

22
23
24

Larry Flowers

25

Official Reporter


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