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Operator: To offer standing by today's conference
all participants are on a listen only mode.
I would now like to turn the call over to President Batjer.
Thank you, you may begin.
-: Thank you very much, (indistinct).
Appreciate that. And hello and hello everyone.
Thank you very much for joining us today
for public briefings from Bare Valley Electric,
from Liberty Utilities and from Pacific Corp
on their readiness for public safety power shutoff
is as this wildfire season.
Today's briefing from the small
and multi-jurisdictional utilities
is the last in a series of four public briefings
we are holding this week, having heard
from San Diego Gas&Electric Company on Monday
Southern California Edison Company
and Pacific Gas&Electric Company yesterday.
I am honored to have joining me today
on the virtual dais representatives
from the California Governor's Office of Emergency Services,
the California Department of Forestry and Fire Protection
and the Office of Energy, Infrastructure, Safe and Safety.
Director Ghilarducci from OES is here with us.
Chief for Lance is here from Cal Fire
and director Caroline Thomas Jacobs is here from OEIS.
As well as my fellow Commissioners, Commissioner Shaaban
Commissioner (indistinct) Commissioner Shiroma
and Commissioner Houck.xx Welcome to all.
In terms of it, of format for today's briefing
following opening remarks from the dais.
We will first hear from Pacific Corp, Allen Berreth,
vice-president transmission and distribution strategy.
Followed by Liberty Utilities, California,
president Chris Alario
and finally, Bear Valley's Electric president Paul Marconi.
Each utilities presentation will be followed
by 15 minutes of questions from the dais.
I will tell everybody that the last two days
we have asked questions along the way.
So please don't take that as an intentional interruption,
but it has been beneficial to ask during your presentation
questions, as we go through your presentation.
After the three presentations and three rounds of Q&A,
we will move to the public comment period of our agenda.
We are scheduled to conclude by 12:00 p.m.
For the public comment portion, which will begin at 11:25,
if you wish to make a public comment,
please dial into 1-800-857-1917,
enter passcode 7218384# and press star one.
You will be placed into a queue
and the operator would take a name and organization.
There may be a delay from the time you press star one
to the time the operator asks for your information.
So please be patient and stay on the line.
You will be called upon to speak when you get,
when we get to the public comment period in today's agenda,
and we will provide two minutes,
we will provide two minutes for each speaker.
You will, I will keep my opening remarks brief
so that the majority of our time today can be used to ensure
the public is able to hear from the utilities
on their state of preparedness.
It says, I am sure and number of people listening today
were not able to join us
for the earlier briefings I mentioned,
I hope you will indulge me as I cover a few important topics
that yes I have covered in the last two days.
With climate change, drought driven weather events
and the drought conditions
we are facing throughout the west.
Our wildfire seasons are starting earlier and ending later,
and they are persistently more severe.
This year there have already been approximately 6,000 fires
that have burned over half a million acres in California.
And it's only the beginning of August.
We are already in what will likely be a long
and very difficult wildfire season.
Oh, we are driving the utilities to plan
for an execute approaches to reduce risk
of utility cause wildfires
through better weather forecasting,
red hardening and vegetation management.
One of the tools that is available to the utilities
is indeed to shut off power to customers.
Unlike other mitigation strategies,
these proactive power shutoff for PSPS events
have very real and direct impacts to customers.
It is trading individual risk to customers
or reducing wildfire risk.
This trade off is why PSPS events must always be.
And we will all underscore this today.
Must always be a measure of last resort.
So utilities have the obligation
to manage their grids responsibly
and they must keep the safety
and well-being of their customers as their highest priority.
Well, PSPS is not sustainable.
It's not a sustainable approach to reducing wildfire risk.
We must ensure that if and when utilities
do decide to shut off power,
they are prepared to execute and communicate
in a way that minimizes impact.
Today, Pacific Corp, Liberty and Bear Valley
has either not used PSPS or used it only rarely.
This lack of experience makes preparation
all the more crucial in case any of the utilities
we will be hearing from today.
Use PSPS of is this welfare season.
In addition, we know that these entities
can be impacted by PSPS events,
call by other entities and utilities.
For example, their valley is a transmission customer
of Southern California Edison.
As with the other utilities today,
I am eager to hear how Pacific Corp, Liberty,
(clears throat) excuse me, and Bear Valley
will mitigate impacts of potential power shutoff
on (clears throat) excuse me.
On people who rely on electricity
to maintain necessary life function,
including or durable medical equipment
and assistive technology.
I also wanna hear how they will conduct outreach
to and notification of all customers
within a particular focus on customers
with access and functional needs.
I also want to hear how these utilities
will coordinate with other utilities
who they receive transmission from.
With that I'm very much looking forward
to getting into the specifics
and having a very thorough dialogue today.
I will now turn to our representatives
from Cal OES, Cal Fire and OEIS,
if you have any opening remarks to share with us today,
first I'll turn to director Ghilarducci.
Mark.
(clears throat)
-: I'm ready.
Good morning, President Batjer, could you hear me okay?
-: Yes.
We hear you fine.
-: Okay. Great.
Well, good morning.
Thanks President Batjer, and members of the Commission,
members of utilities that are joined today.
I'm happy to be with you.
I really feel like today's briefing
with the smaller multi-jurisdictional utilities
really does provide us another opportunity to get together
and continue to discuss how we can continue to refine
and improve our overall efforts
with regards to public safety, power shutoffs,
and fire mitigation around our power infrastructure.
Particularly ensuring that the stage notifications
when they do occur, reflect the highest stage,
which the IOU has entered into its PSPS activity
and in a timely fashion.
It really not the effort of first resort,
but the effort of last resort.
We have been working closely
with the three smaller utilities over the course of 2020.
I will say that we have been able to successfully
identify all the relevant contacts
we've made good coordination points of contact and outreach
and engaged all Pacific Corp, Liberty,
and Bear Valley in PSPS planning events.
These IOUs have been totally now folded
into the (indistinct) continuous refinement
of PSPS events protocol that includes them attending
monthly state agency partner and IOU coordination calls
actively participating in the state operation center
situation sell workshops and focus groups
to improve customer notification procedures
adopting the standardized executive briefing template
to be used during PSPS events
when briefing stage stakeholders
and seeking feedback from us on their PSPS protocols.
This is increased engagement in crucial prevent work
that will ensure that all three utilities PSPS events
go as smoothly as possible, not only for the end customer,
but for state stakeholders as well.
We appreciate all three utilities
putting in their PSPS planning efforts.
One area of improvement that we note
would be to assist in state situational awareness,
as well as their own operations.
That adoption of what we call a rest service.
This is representational state transfer of information.
In essence, this is pulling mapping through GIS data
to be able to provide that situational awareness
up to the state so we can see what is happening
with the impact to customers throughout their jurisdiction,
and be able to work with them
on being able to meet unmet needs as, as they arise.
And this would also allow for real-time data sharing
during PSPS events specifically,
I would say that for Pacific Corp Pacific course first PSPS
was in September of 2020.
The IRU did reach out regularly to OES for feedback
and made sure they were responsive to us.
What we had questions on their notifications.
There were some mishaps as there would be expected
in the first go around,
but they were quickly corrected by Pacific Corp
and the mistakes were not repeated.
Pacific Corp then also launched a new PSPS website
with address lookup for customers
to see if they were located within the PSPS impacted area.
All good positive movements forward.
In the case of Liberty, we did work with them.
Okay, conducted tabletop exercises on May 25th
and a full-scale exercise on June 25th,
we did learn how they did their notifications
and made recommendations on improvements
or notification informed submittal.
And Bear Valley did also conduct a tabletop exercise
on June 21st.
And again, noting what comes out
of these table top exercises gaps.
And we were able to identify areas of improvement
with regards to PSPS notifications in more timely fashion.
I would say overall, there's still work to be done
with all three of these smaller utilities.
And of course, all three have been impacted by wildfire
over the course of the last two years.
In fact, I was up in Alpine County
at the Tamarack fire last week,
and Liberty was very, very actively
working to get power restored.
But there's still work to do with community resource centers
with the AFN community and overall support to the community.
And I do believe that given the resources
available to these utilities and their interest and intent,
they are working in a positive way to try to work with us.
But again, there's continued work to be done
and we continue to look forward to working with them.
So with that President Batjer, back to you. Thank you.
-: Great.
Thank you so much Mark for those remarks.
Now I will turn to Caroline director of OEIS.
Caroline, do you have any opening remarks?
-: Yeah, I'll keep it brief.
Thank you, President Batjer, again,
really appreciate the opportunity to be here with all of you
and get the briefing from the utilities
on their preparations for this coming PSPS season,
or we're already in the midst of.
Certainly re concur with all the comments that both you
and director Ghilarducci have already mentioned
in terms of the severity that we're looking at
and the preparation and the work that needs
to go into being ready to respond
and accurately and effectively implement a PSPS this season,
especially for the smalls.
I do want to just reiterate what you mentioned,
President Batjer in the sense that I know that for Liberty
and Bear Valley, you guys haven't called a PSPS yet.
And certainly what we learned from the larger utilities
is that even with preparation
that the first few times can be a little bit rough
in terms of learning the particulars.
And so I think it's all the more important
for you guys to be pushing and thinking ahead
and preparing and practicing what that would look like.
Because we do have the experience now
you have the lessons learned from the previous utilities,
and I think that there's opportunity
to be able to be better prepared the first go around
then the other utilities as they were initially
ramping up their PSPS programs.
So look forward to hearing the progress
that you've made this year and continue to push on
and appreciate again, the time
and opportunity to chat with the utility today.
-: Thank you, director, appreciate your remarks very much.
Chief Berlin.
Do you have any opening remarks you'd like to make?
-: Sure thank you. Good morning, President Batjer,
and everybody I'll just echo the comments that were made
specifically, President Batjer,
your comments about the conditions
that we're already experiencing this fire season.
It should be noted that nearly 89% of California
is under extreme or exceptional drought conditions.
And we're already seeing the results of those conditions.
We're seeing a significant increase
in the number of wildfires, the size of wildfires
and the severity of wildfires.
And so the 2021 fire season
is without a doubt off to a busy start.
And while I feel like I'm a little bit repeating
what I said last year,
this year, we are definitely seeing more fires
than we did to the same time period the year before.
Today's briefing also very timely.
As many of the counties served (indistinct) companies
are under red flag warning conditions this week.
So we are seeing extreme weather conditions
in two of the companies, territories and fires
in their territories as well.
And so definitely look forward to the updates
on the planning going into PSPS decision making
and even looking forward to some specific updates
on the efforts to avoid PSPS
through infrastructure hardening
and require vegetation management.
So on behalf of Cal Fire,
appreciate the opportunity to be here
and look forward to the presentation.
-: Thank you very much for your remarks Chief.
And now I will turn to my fellow Commissioners
and the way you're all being displayed on my screen.
I can't see you all.
So I can see Darcy any opening remarks
from any of the Commissioners.
-: Yes, yes.
Very briefly,
very much appreciated all of the presentations the last few
days and looking forward to today
and for each of the presenters,
I'll be interested in everything they have to say,
but also want to hear a little more detail
on how they're working
with their community-based organizations
and also for their assets, emotional needs customers.
I see that Bear Valley provides for the transportation
through their mountain aid, but for Pacific Corp
and providing a transportation access
to too many resource centers.
Thank you very much.
Look forward to the presentations and the discussion.
-: Thank you, Commissioner Shiroma.
Any other Commissioners would like to make a comment.
-: President Batjer,
this is Commissioner is mana service here on the phone.
I just wanted to, I really here and I see
that the Pacific Corp we'll be touching on this,
but clearly in our last previous update,
there was a recognition of the need
to really double down on communicating,
improved communication with the tribal nations
in their territory.
So I look forward to hearing on that progress.
Thank you.
-: Thank you. Commissioner (indistinct).
I see Commissioner (mumbles) you have said you're okay.
And I think Commissioner Houck.xx says the same thing.
So we will then thank you Commissioners.
We will proceed then to the first presentation
from Pacific Corp,
we have the president of transmission
and distribution strategy from Pacific Corp here with us
to do the presentation.
Sir, would you like to begin?
-: All right, thank you.
First let me just do a mic check
and make sure everyone can hear me okay.
-: We can hear you fine.
-: All right it looks like it.
And my presentation, would it be displayed?
-: Yes, it is up.
-: Oh, there it is.
Thank you.
All right. Good morning, President Batjer,
Commissioners and other agency officials.
First, let me just say thank you for the opportunity
to review Pacific Corps' Public Safety
Power Shutoff preparedness.
So why don't we go ahead and go to the next slide, please.
So as noted on the slide and for the record,
my name is Allen Berreth and I'm the vice-president
of transmission and distribution operations
for Pacific Corp.
I should note that, well, I'll be giving the presentation.
I am joined on the call by Kurt Mansfield,
our senior vice president of power delivery.
And in case there are any detailed questions
after the presentation,
or sounds like throughout the presentation,
I have Justin, the Cartec,
our director of emergency management available,
and also Melissa Nottingham,
our manager of customer advocacy and tariff policy
are also available to answering questions.
We'll be going through the following topics,
which touch on our preparedness for PSPS
and also the longer term grid hardening
and customer communication,
all the different aspects that we've touched on
in the opening remarks.
So with that, let's go to the next slide, please.
All right.
So before we go into the details,
I'd like to provide a little bit of context for Pacific Corp
in our service territory in California.
So shown here on the image in Northern California,
outlined in black is our service territory.
In purple is the tier two area
and then shown in red is the tier three.
And so in discussions, when it comes to PSPS,
it's that tier three, that subset of our service territory
that has the PSPS planning involved.
We do serve 45,000 customers
in our California service territory.
And as we go to the next slide,
we'll see what subset of that 45,000
or in that tier three or PSPS planning.
So as we zoom in to that red area
that we showed on the previous slide
and look at that tier three area
in the table and lower right, you see the stats.
So these are the areas that have been identified
as extreme risk geographic locations,
either inside that tier three
or we're right next to that tier three.
So we incorporated and electrically connected our system
that affects and impacts that tier three area.
So within that area,
we've subdivided these locations into five discreet zones
that we can take action on independently,
given that conditions might not affect this entire area
all the same at the same time.
So it's subdivided into five zones
as shown in the table there.
And you can see this is a little over 10,000 customers
served from nine substations, 20 distribution circuits,
and about 260 overhead line miles
are in this elevated tier three area.
So while these are the areas
that have been identified for elevated risk
and our PSPS planning,
I do wanna know that we do monitor conditions
across our service territory.
So we don't have blinders on only looking at the PSPS areas.
That's just where additional planning
or asset hardening
would be prioritized first to take action.
Our situational awareness goes,
does go across our entire service territory
so that we are monitoring conditions and can take actions
as needed and dictated by on the ground conditions.
With that let's go to the next slide, please.
All right.
So now let's transition and talk about vegetation
and the threat posed to the electrical system
through either the fallen risk
of that nearby trees in our right away
or outside of our right away
can pose to the electrical system,
or even that blow in risk from vegetation trees
that are nearby that has branches
that either are blown out of the tree
or into that, that can make contact
with the electrical system and create a fault
or a possible ignition condition.
And based on our historical data from 2015 to 2020
vegetation most likely causes around 26%
of our fire risk events and 24% of our fire ignition events,
which basically about 25% of all our risks
and admission events,
which is why it's an important area to focus on
with our wildfire mitigation plan.
And so what are we doing in the short term?
So you see it they're listed on the slide,
which is an increase in vegetation inspections
in these high risk areas, meaning an annual inspection
of what is the condition of vegetation near our lines,
and do any conditions need to be resolved.
And where we've seen an increase
due to the drought conditions and health of these trees
is an increase in a high-risk tree inventory.
And so understanding what trees
and your dead and dying trees need to be removed.
And so doing an inventory of those trees
in an accelerated removal of them,
once they've been identified.
We also a radial pole clearing around the base of our poles,
a 10 foot around equipment poles,
so that as the equipment operates a fuse opens,
we make sure there's no fuel available
at the base of those equipment poles
that could create a situation with fire spreading, right?
And in situation awareness through data collection.
So what that means for us in the vegetation management realm
is well, we don't have a tree inventory
of every tree we have,
we have a tree inventory of the high risk trees
as they're identified,
but there's not a complete inventory of the trees
around our electrical systems.
And so to start a journey toward establishing that
we're piloting programs such as satellite imagery
and the images shown on the screen here,
where we start getting a sense of
what is using the satellite imagery, LIDAR,
where did these trees exist?
What's the density of these trees, density of tree canopy,
so that we can start quantifying
the risk of vegetation management
in subsections of our circuits.
So that can inform our vegetation management program,
prioritized areas where we might have
to do increased trimming, increased frequency.
And so we're pushing for that.
That will also eventually create an inventory
of our veg management risk
and quantify the risk reduction over time.
That's our goal with vegetation management.
Transitioning to the longterm shown in the lower right there
is rebuilding our overhead lines to cupboard conductor.
So that just mitigating that potential interference
of a branch or a tree
making contact with a bare overhead wire.
And so we'll rebuild the lines to cover conductor,
also changing out relays reclosers to newer relay detection,
where we can detect heightened impedance faults
anticipate fault before there's actual ignition event
wave form analysis seeing if we can proactively determined
that there could be a potential tree interference
somewhere out on the line
before it actually creates that ignition or fault, right?
And then that also plays into a system automation
of switching around, sectionalizing,
reducing the customer impact
to these highly dense vegetation areas.
That's our longer-term build out goal
when it comes to vegetation management,
how to mitigate that risk.
Specifically with our 2021 vegetation management progress
in California, we're about 60% through our annual program,
which makes sense, given where we're at in the year,
that is around 11,000 poles have been cleared,
radio pole clearing at the base of it.
We've inspected around 1800 miles of line.
We have cleared 1400 miles of line conducted a tree pruning
and ensuring that clearance exists.
That's resulted in around 22,000 trees have been pruned
2,400 trees have been removed.
So speaking to that hazard tree inventory
and removal process.
So 2,400 so far this year.
Again, those are year to date numbers,
which represent about 60% of our annual program.
So, all right, let's go to the next slide please.
So moving beyond vegetation management
as a mitigation measure, let's go a little longer term
and let's now talk about other actions being taken
to harden the system and reduce the likelihood
or need or scope of a public safety power shutoff.
And so, as I mentioned earlier about cupboard conductor,
that is our mainline mitigate our main mitigation strategy.
Just reducing that exposure for overhead line
and coupled with installation of line reclosers
and substation relays,
to be able to have the system react quicker to the,
if a fault exists, if an interference on our line exists.
And so our mitigation efforts are ramping up in 2021
compared to what we were able to accomplish in 2020,
we are on track for delivering 85 miles of covered conductor
by the end of 2021.
And with the installation of 27 reclosers
relays being installed
out on the line and in our substation.
As an example of how this reduces the scope of PSPS,
the graphic on this slide is just showing
one of those PSPS areas.
When I said, we took our tier three
subdivided it into five zones on the image there,
you're looking at the Mount Shasta zone
and it showing our covered conductor project
that we've completed in that area, in the Mount Shasta area,
which creates a ring fence in the downtown area
that can stay energized and elevated wind events,
allowing more system flexibility
with the goal of reducing
the impact of a PSPS events, right?
So as soon as we put that covered conductor in place,
we can withstand higher winds in that area.
Meaning we don't have to de-energize that core area
under the same conditions as before.
And then we only have to be energized the taps out of town,
wherever the direction of the elevated wind
or fire conditions exist.
So it's just an example.
And then we work out from there in the coming years
and accomplished peppered conductor from those taps,
meaning that we can go through
that system can withstand even higher
elevated fire weather conditions, right?
And so even steps that we're taking
in the first year or two,
even though it is a three, four year plan
each stage mitigates and reduces the likelihood
or the impact of a PSPS event, right?
And as we add reclosers out each of these directions
from the downtown, they to allow us to sectionalize
what areas would be impacted,
which customers would be impacted by a possible PSPS event.
Asset inspections are also a key component of preparedness.
And so in these areas where we go out
and make sure we do an annual visual assurance inspection,
we patrol the line, note any conditions,
and if any conditions are found,
they are corrected on an accelerated timeline.
IR inspections are scheduled for the transmission lines
through the PSPS areas or the FHC eight tier three areas.
We conduct these infrared inspections
when the loading on the transmission line is at peak
to make sure that if there are any issues
that highlights them the most
during those heavier lifted times of the year.
So based on that forecast, that loading of the lines,
and we'd divide that into three flights a year,
April, July in December, just based on the loading.
So the first two that have been accomplished
and in December, we'll accomplish the third IR flight
for the transmission lines in these areas.
All right, next slide please.
Caroline: Allen, can I ask a question?
And it looks like you might be getting into.
This is Caroline from OEIS.
In the vegetation management, as well as the grid hardening.
And if you're gonna get to this later in the slide deck,
you can just say, you're gonna answer it later,
but can you walk us through how those improvements
change the threshold you've referred to a couple of times
that it would change the threshold
of when you would have to call up PSPS
in your decision making.
Are you gonna get to that later?
Or can you speak to that a little bit now?
-: Well, that's a great segue for the, yeah.
The slide I was about to touch on.
So let's go through how those changes
would impact the decision making
for what's leading up to a PSPS.
So yeah, let me go through this
and see if I don't answer that question.
And then if not hold me to it
and let me make sure I answer it.
Because while that grid hardening
is a long-term mitigation strategy in the short term
that public safety power shutoff
is available tool and totally understood
as a measure of last resort
is when it would want to be used
in extreme fire weather conditions.
And the decision-making for public safety power shutoff
has a number of inputs
as the conditions for a geographic area are evaluated
and shown on the slide there in the bottom half
are the difference, fire weather indexes they've been used
across the various utilities.
These are the inputs that we look at
from the Fosberg and KBDI and vapor pressure deficit
as these change in the areas.
And then you couple that dry fuel
kind of drought weather conditions,
and couple that with wind speeds and the wind direction
to decide whether or not as those elevate action
needs to take place.
And it's not just a mathematical formula
of a certain threshold that we use universally
across all our areas.
By looking back at history,
we've been able to see for each of these circuits
and even sections of the circuits under what wind conditions
have outages occurred in the past.
So on some circuits that might be a 35 mile per hour winds
where outages occurred.
And on another circuit, and another section of that circuit,
it might be able to go up to 40, 45 mile per hour winds
before outages occur on the system.
And so by understanding that and getting more granular,
the thresholds is very unique to the individual circuits
in areas on whether or not it's elevating
through this PSPS decision-making framework.
So the question of, so then as we do covered conductor,
then yes, for that area, that circuit, with that in mind,
we would know it can go up higher
than what it previously was able to, right?
So, whereas that circuit, we might say, oh, well,
traditionally we saw outages at 35 miles per hour.
You know, now we know what the cover conductor,
it can go above that.
And so that is uniquely taken into the decision-making
for that circuit, all right?
Also while the environmental inputs are considered
in the wind conditions weather
it is also the condition of the system.
So part of this decision making process is also reaching out
and doing an inspection.
One, when was the last vegetation inspection?
When was the last cycle trimming conducted?
What conditions exist? What is the hazard tree?
What are the known conditions?
That all goes into the decision making as well.
So that we know that that circuit was just inspected.
Vegetation management was just completed.
We have a better feel about what the impacts
under certain weather conditions.
So what should that threshold be,
is all taken into consideration.
It makes it hard then for the decision-making framework
to be expressed as like a formula,
because we're taking all of this information in
very unique to a circuit,
very unique to its specific conditions at that time
and making a decision as we monitor and watch it
through this flow chart as it elevates that.
Also incorporated into this decision-making framework
is reaching out to others beyond specific,
or we reach out to other emergency agencies in the community
and ask, "What are they experiencing right now?"
"What are conditions, from their perspective?"
Which might be an active fire is already being
responded to right now.
And that a PSPS situation could make the community response,
could hamper it, right?
It could make it worse.
And so we need that feedback to make sure we understand
that we are actually reducing risk and not creating risk.
And we only accomplish that by reaching out
as part of the PSPS decision-making framework
in incorporating all that information.
At the end of the day, it is the utility that decides
whether or not a PSPS will occur,
but we don't make that decision in a vacuum.
And so we wanna collaborate with others.
We wanna understand what other agencies are seeing,
let them know what we're seeing
and what action we are taking.
And so that means advanced notifications
to these agencies and our customers.
If we're looking at, if it's elevating up to a PSPS watch,
a PSPS activation is being forecasted.
Then that kicks off the 72 hour notifications,
48 hour notifications,
where we started doing outbound calling to our customers
and personal phone calls to our medical baseline customers,
AFN notifications,
there's a whole time's notification process
as we get closer to an actual PSPS watch or event.
(indistinct)
-: Caroline, is that getting to your question
was guarding the threshold?
-: Well, it sounds like if I understand your Allen correctly,
that it's a circuit by circuit threshold,
so therefore the numbers could vary widely.
Is that correct?
-: Correct.
Because absolutely because in our journey to make sure
that we're not impacting customers unnecessarily
in certain areas of the circuit
that can withstand higher winds,
we wanted to move away from a universal threshold
because certain circuits and conditions
allow us to be more surgical.
-: So, and if you don't have the detail here
in this presentation, we can do it as a follow-up,
but it would be, I would like to understand better
the range of the thresholds and how those are changing
based on the mitigation efforts
that you presented on the other slides.
-: Yeah.
-: To verify other question as well,
of all of the considerations that you have to make,
and you've detailed them here.
How do you...
What kind of consideration do you give
to the health and welfare of the people
and the safety of the people who will be going,
who will be de-energized?
How do you factor that in that, I mean,
obviously the safety of the system and the hardening
and the mitigation plans, but what about the people?
What about the people
who are actually going to be de-energized?
I mean, you've mentioned your, how, how you,
by, by our guidelines,
you must do the notification properly,
but our guidelines also call for consideration of the safety
and the health and welfare of the people
who will be de-energized.
'Cause it is a safety, it's a terrible safety issue.
-: Right.
Yeah, thank you for the question
and that kind of clarification of how we view that.
And we'll get into some of the slides
that look at well identification of vulnerable customers.
So then you know all right,
what a community resource centers are we providing?
What services are we providing for them?
What's the backup generation.
So I'll touch on that
in some of these future slides as well.
And I also view that as part of our reaching out
to local emergency partners
and identification of vulnerable customers ahead of time
and identification
of our critical infrastructure ahead of time
to fully understand that impact
to our customers in these areas.
And that's all part of that tabletop exercise
and that preparedness.
So yes, very much a part of a process.
-: Yeah. Yeah.
Well, I look forward to,
to when we get to that part in the presentation.
Thank you.
-: All right. Thank you.
-: Allen, this is Daniel from Cal Fire.
If I could just ask at this point,
you had mentioned related to some of the hardening work
that you're doing
and you spoke to detecting ground impedance faults.
Can you talk about any additional
or new emerging technologies that you may be looking at,
like distribution fault anticipation technology
that your company might be bringing
into the hardening topic?
-: Yeah, thank you for that question,
because that is an exciting
kind of advancement of technology
in that way form analytics
and almost preemptive identification
of any issues out on the line.
So in our Weed California area,
inside that substation there,
we've actually just in the last couple of months
installed the two of these relays
that do that wave form analytics.
We're able to look at that wave form
and just based on what we can see there,
it can identify different types of interference
and different signatures of the wave form
that can tell us to go look for things out on the line,
even though it didn't create a fault yet, right?
And so that allows us to be very proactive
and not wait for the outage or the ignition event.
And so I think that that is an exciting
advancement in technology.
And we do have those relays
installed you weed substation area.
And so we're looking to learn from that.
Thank you.
-: Right.
I think I heard that it wasn't in the presentation,
but I think I heard you say
that you have hearted 60% of your goal this year.
It just wanted to correct
that that's for your goal this year, the 60% number?
-: 60% was referring to our vegetation management program
is 60% yep through the annual trimming and inspection.
-: And we're already here in August,
as I mentioned at the beginning, you have red flag warnings.
Do you feel like you're gonna be able to accomplish
this year's goal
despite the fact that we're into the peak fire season now?
-: Yeah. Yep.
We are forecasting to be on track
and be able to accomplish our 2021
vegetation management program.
It was prioritized in such a fashion
to make sure we accomplish
like say our tier three vegetation management program
before the tier two and before the non tier
to make sure that if something was at risk,
it would be outside of this
already identified higher elevated fire weather areas.
So.
-: Great. Thanks for expanding on that.
-: Yeah.
All right. Next slide please.
All right.
And if some of those questions brought about
let's talk about the community resource centers.
So in the event that a public safety
power shut off does occur
specific or has identified locations
where community resource centers
or CRC will be opened in those areas.
So you can see on that map there
and visualize the tier three area that was showing earlier
subdivided into those five zones.
And then those stars are where we pre-identified locations,
where we can open up a community resource center preferences
to have a physical established facility
that we can open up a CRC.
So we've identified those
in collaboration with local communities
on where would make the most sense
and making sure that the distance
between the customers being impacted and the CRC
is 10 to 20 miles.
To make sure they're not too far away from the customers
that we're impacting.
So you can see the services there
that are provided at the community resource centers.
And backup locations are identified as well.
Our goal is to have both a primary and backup
in each of these locations.
But in the event that even beyond those locations,
Pacific Corp does have contracts with vendors
that we can deploy and establish a temporary CRC
in any location, even if a fixed facility is not available
for it for any reason.
So we have that capability as well.
And I should touch on that given the pandemic
and COVID protocols can be adhered to as well
as we open up the CRC.
So that planning is in place to make sure that
that would be conducted under current guidelines
as well if a CRC was open.
All right, next slide, please.
Now let's touch on.
-: I'm sorry.
I was asked to ask about the CRC
on any of the tribal lands in this area?
I don't see that.
-: Happy Camp is the closest to the tribal lands there.
And I don't, maybe Justin can correct me.
I don't, let's see it's at the croup wellness centers,
the backup one and Happy Camp.
Sorry, if you go back to two slides.
Sorry.
There we go, in that table.
Let's see the CRC identified the in Happy Camp,
the Karuk Wellness Center as backup area
in Weed Karuk Wellness Center in Yreka.
So it is in conjunction with the tribes
trying to identify good locations as well.
-: Yeah. Okay.
I see that in the smaller and the CRC identified.
Okay.
Thank you.
-: Yeah.
-: I have a quick question.
This is mark on these, on your experience.
I know you you've done, I think one PSPS,
but I mean, how have these CRCs operated?
Have they been successful?
Have you gotten feedback?
What was the uptake at these centers utilized adequately
do you have some sort of metrics on that?
-: Thank you for that question,
because we do not have experience with setting up a CRC.
So this is all pre-planning.
The one PSPS we had was a short duration, eight, 10 hours.
And so just for in within the day,
so a CRC was not established and there was already CRCs
for other active fires that were available
if somebody did actually need one.
So Pacific Corp didn't need to set one up
for the PSPS that we conducted last year.
So we don't have those learnings.
So we would have to be collaboration with other utilities
and others who have set these up to understand
the planning for what it would look like for us.
-: I appreciate that.
I would maybe suggest that would be an area
where you may wanna do a exercise to actually,
maybe do a functional exercise of setting one up
and running through it.
And so that you know,
one thing about planning and talking about it.
Another thing about actually running it to the mill
and then seeing where the gaps and seams are.
So anyway, we'd be happy to certainly work with you
on helping you with that exercise if you're interested.
-: Thank you.
Yes, that would be great.
-: Allen, can I follow up on Mark's question?
Did...
Has Pacific Corp initiated PSPS in Oregon?
In last year or year before, did you set up PSPS there?
-: We have not conducted a PSPS in Oregon
or any other service territory, California.
Yeah.
And the one was the only one we've done to date.
-: I know some other utility did do it in Oregon.
I was just curious if you'd had that experience.
Thank you.
-: Mm-hmm.
-: And Allen, it's generally my question about
in your pre-planning, do you anticipate that
you might have accessing functional need customers
or medical baseline customers,
customers who don't have access to transportation
and may need to help get to the resource center?
-: Yeah.
So why don't we transition to the next slide?
Oh, sorry.
You're on that slide.
I'll move to the next slide.
Because yes,
we are looking to expand our program to address.
It was identified as a gap at our last public meeting
when we were looking at vulnerable customers,
working with them, AFN, what we're doing for battery backup.
And so we're looking to expand that program,
learning from others and expanding our program as well.
Looking for that,
to include for this medical baseline customers
and AFN transportation options as well to the CRC.
So, yes, we are looking to expand that
and be able to provide that offering
in addition to these other areas where we looked.
-: What is the timeframe for that?
Sorry for interrupting, but what is your timeframe?
If you're looking for that expansion and looking,
it says all of this is due in 2021, and it's underdeveloped.
-: The transportation and battery backup
for our medical baseline customers in California.
It's full speed ahead that we would want this
in the next month before it would be needed, right?
That's the timeline
for what we're looking for those options.
The larger battery or generator backup for all AFN customers
or any customer in these areas and the rebate program.
That's a longer-term effort
realizing we can't turn that around in that same timeframe,
but for that smaller subset of medical baseline customers
and expanding our offerings to them,
it's a quick turnaround.
-: I just would say and I don't know if you had
any of your company representatives listening in
yesterday and the day before
with the presentations on the larger IOUs,
but they have quite a bit of experience in this area.
And I would suggest that perhaps you all talk with them
and do some learning from their experience
in not only how they identify the customers
who are in need of battery at how they deploy it
and their information and education of the customers
and how these are used.
So I think it would be very appropriate
for you to contact one of the other IOUs, perhaps PG&E
they're deploying and have for the last couple of years.
They not as much as we would like them to,
but they're deploying thousands of batteries.
-: Right.
(indistinct cross talk)
Yeah. Thank you for that.
Yeah.
We don't wanna create the wheel
we wanna build off of other successes of their programs
and model the same.
So, absolutely.
-: Yeah.
-: All right.
So that's the expansion in the community resilience
and the battery backup generators
for these moldable customers.
I guess also noted on this slide is in the CRC
is also providing the EDB charging capability as well.
So making that available to customers in these areas.
Okay.
Next slide please.
All right.
So a large component of a successful
wildfire mitigation plan is communicating
and educating our customers on what they can expect from us
and what they can do
to be prepared themselves during these conditions.
A customer survey was conducted last year
to help inform our outreach
and communication campaigns regarding wildfire safety.
And so we'll look to continue
for ways to enhance our messaging
to these targeted vulnerable customers,
and to provide them more information about what to expect
and emphasis will be placed on communication
and notification around PSPS events.
Not just timely notifications,
about ways to provide more context
about the potential of moving from watch to PSPS event.
That's a confusing transition of trying to educate customers
that we're watching and the possibility of something,
you know, four days out.
And as that transitions to an event
and an actual forecast of the de-energization,
and how do we make that clear
as was noted in some of the opening remarks,
we have evolved our PSPS website
where customers can go on there, type in their address,
see if they're in one of these PSPS areas, see the status,
the forecast of the next seven days.
If we anticipate a watch or an events
and whether or not it's impacting them.
We're looking to provide even more information
through this website
as customers come to our website to gain information
either how can they be designated, an AFN,
a medical baseline, what can they do to be prepared?
We're also evolving this website
so that as we just talked
about the hardening that's going on over the long-term,
these boundaries of a PSPS are then dynamic.
They're not static.
Currently if you go to the web page,
it's showing you the five kind of static areas
that our planning has identified.
We understand that these will now become dynamic
and that we need to be able to move that boundary,
to really show customers what we're anticipating
the actual subset of those PSPS areas
are what might be impacted.
And so we're evolving that as well
to make sure that we're really providing
the latest information to our customers.
All right, next slide, please.
-: Allen, real quick question.
In your territory there are some areas
that have either very low broadband or no broadband at all.
And so are you communicating, educating, out doing outreach
to those folks who don't have access to the internet?
You have a lot of rural areas
that are probably in that category of lacking
the kind of broadband services
that hopefully we will some someday soon bring to them
mailings and things, the old fashioned way, the US mail.
-: Exactly.
It's that multi-pronged approach.
We don't rely on just one channel to reach our customers.
So yes, there is the emails, there are the social media,
but there are the build inserts and direct mailings to them
to provide information as well.
So, yep. It's on all fronts.
-: Okay.
Thank you.
-: Yeah.
Okay.
And as we discussed,
it's understood that public safety power shutoff
is that tool of last resort
because of its impact to customers
and their safety and the impact of the communities.
And we wanna make sure we understand that impact
and identify our vulnerable customers
as is it an AFN or medical baseline customer.
And so some of what we've already talked about
is like these mailings.
And so even within the care program where we send out forms
and direct mailings to our residential customers
and even master metered accounts,
so that we try to get beyond that master metered
and into the individuals
that live behind that meter information.
So it's this direct mailing, how do they sign up?
Where do they get more information
about identifying in signing up as an AFN
or medical baseline so that they can get into these programs
so they can get these notifications
so that we can reach out to them
and talk about battery backup if they qualify for that.
And so it's all these different outreaches.
Shown in the lower right, is our medical baseline
for a California service territory.
You see about 126 and 28 of those
are in those designated PSPS areas,
just to give you a few of the numbers.
And so this is a personal outreach
to those 28 medical baseline customers.
If whichever one of those 28 are in an impacted PSPS area
to make sure that they are taken care of
and that they are aware of any impacts.
-: So Allen, do you have an estimate
of how many AFN customers you have
in your high wildfire zones?
-: In California, it's this 126,
maybe I didn't quite understand the question.
-: Medical baseline, you've got 126 this year,
but how about when your access and social needs,
and that includes low-income seniors, non-English speakers.
Do you have an estimate of it?
-: We have the number.
I do not have it in front of me, so I apologize for that,
but it is tracked and we have the number.
And so maybe I'll ask Melissa to chime in
if she happens to know that number off hand,
but I apologize, I don't have it in front of me.
-: Okay.
Melissa: Allen, this is Melissa.
If you want me to, just to pipe in real quick,
we do have about 50 customers
that are self identified as AFN
in our tier three high fire risk districts.
-: Thank you, Melissa.
Melissa: Thank you.
-: Okay, next slide please.
So in addition to establishing the vulnerable customers
and our outreach to them,
it's also a coordination with other external agencies
and specifically has expanded
the emergency management department
to increase our collaboration coordination
with these external agencies and communities
that are shown here on the slide.
And so in the upper left, we talked about this already,
but the identification of critical infrastructure,
communication providers and communication
is saying critical infrastructure for the community,
especially during an emergency response event.
And so this is us working with the communication providers
to understand their backup capabilities,
to understand their locations and within these PSPS
or possible PSPS de-energized areas
so that we can coordinate that in the middle there
and was talking about at the last public meeting
is our collaboration with the tribes
and wanting to increase that.
And so now holding twice monthly
and making sure that we have good coordination
and communication about what the plans are
and what their needs might be,
and letting them know our long-term plans system hardening
in those areas and PSPS, the CRC availability as well.
So we've increased that outreach and coordination.
And then in the upper right,
are kind of ongoing engagement
with other public safety partners
and being the tabletop exercises and these counties,
which were completed in May.
Just to make sure we're all on the same page
about what the process is, what is the decision-making,
what's the outreach, what's the notification,
and where are the areas of concern.
Now, it's important that this coordination
with external agencies that create the feedback loop, right?
That informs the planning and preparedness
and where we can improve in Pacific or is open to that.
We're a continuous improvement organization.
We want that feedback.
And so shown at the bottom half of this slide
is what we have noted so far about what's going well
and areas that we wanna watch and are seeking to improve.
And it's things we've touched on already,
whether it's our communication with customers
that might not have the same capabilities as others,
as far as how to receive information,
whether it's backup generation,
these are areas we know we need to continue to push on
and continue to challenge and find ways to expand
and improve our offerings, our communication,
our coordination.
But as noted in even in some of the opening remarks,
we have made progress,
we have opened and improved our communication
and partnership and things have gone well.
And wherever we've received,
feedback that we need to make a change.
We look to address that quickly.
-: Oh, and I would encourage you
to follow what director Ghilarducci suggested and having,
I know you have had the two tabletop exercises,
but I think some actual functional exercise
would really benefit you and your customers,
particularly as he and others have noted
that the CRCs are not easily set up and easily run.
And they're critical to the community
when you do have a PSPS.
-: Yeah. That is great feedback.
And a great idea. So thank you.
-: Allen, is mark again,
just on these external agency coordination engagement,
how have you found the external partners?
Have they engaged with you on these?
Do you have good participation from public safety,
from non-governmental organizations,
faith-based organizations, tribal community,
is everybody coming to the table for these
and how has that whole collaboration going?
-: Yeah.
Thank you for that question.
I'm gonna ask Justin, our director of emergency management
is probably a better place
to provide better color around that and that response.
So Justin, can you respond to that?
Justin: Yep. Thanks Allen.
And thanks for the question.
I would say in short that it's been really successful
and just to reference the two table top exercises
on May 25th, we held one in Siskiyou County
and on the 27th in Del Norte,
and we had really good tribal representation
or state breaths from Cal Fire
and our VOT partners in local emergency management.
So everyone's rallying around the PSPS discussion
and we are getting really, really good, good feedback.
And I will say just on the comment
around setting up kind of a functional exercise
is something we're planning on doing next year.
We actually did set up a TRC
as part of a joint three county tabletop in Southern Oregon,
just a couple of months ago when it was very successful.
We came back a lot of feedback
and we're looking to do the same thing
kind of in concert with our new emergency management staff
coming on board in our California service territory as well.
-: Thank you, Justin.
-: Yeah. Thanks for the feedback on that.
You know, there's a saying in the businesses,
you know, disasters happen while you're planning.
So I'm just thinking that a few of these things
that are directly related to impacts to the community
while you guys are working your tails off
on addressing infrastructure improvements
and building your protocol out,
ultimately we, and I know you don't,
but we cannot forget the end impact.
And that is the customers,
the people who live in the community particularly
people who need extra help.
I would maybe suggest, and again, happy to help you.
If you're gonna do a tabletop
or a functional exercise of a CRC next year,
maybe that's whatever six months away,
we're gonna go through this season,
even maybe going through a tabletop discussion exercise
sometime in the next few weeks
would be beneficial for you all.
Which we again, would be happy to sit if you want,
just so that there's a little clarity on where, when, how,
or that CRC or be set up.
And then maybe you can articulate that out to the community
in a broader way.
So just a thought on that, 'cause just this week,
as you know fire weather
is you're going to write flight condition.
Currently, you're gonna have winds
up through the end of the week.
And my guess is that it's in between now and January one,
we're gonna have a number of potential PSPS events
taking place in Northern California.
So, and with the drought conditions the way they are
and the way these fires are spreading and moving so rapidly,
we wanna just be on top of that.
So anyway, just a thought on that.
And again, happy to help you get there.
-: Appreciate that offer.
Thank you.
-: Allen, this is Caroline.
-: Oh, excuse me.
I think we're gonna need to wrap up
where I've not been a very good timekeeper today.
We're about 15 minutes over time.
So please Caroline, go ahead.
-: Just quick question.
Can you just in 60 seconds,
talk to any individualized notifications
to communication companies.
One of the sort of lessons learned over the last few years
has been that their notification needs
are slightly different
than a typical customer's notification reads
needs due to having multiple sites.
So can you speak to how you guys have,
or are planning on tailoring notification to them?
So they get a consolidated and concise notification.
-: Yeah.
Thank you for that question.
And it was, I think, remarked on earlier,
it's about the GIS sharing information.
So when it comes down to notifying a communication provider
it's about providing GIS information
so that they can truly understand and quickly understand
how we're sharing that information in a standard format,
that they can take that in and know their impacts.
And so it's about doing that pre-planning and explaining,
and being able to provide to them at a time,
this is what you'll get from us, does that work?
So an ATMT is the, our lesson learned on that.
-: Great. Thank you.
-: Mm-hmm.
All right.
And if we move to the next slide, which is the last slide,
so thank you for the time check.
And so in closing, thank you again for the opportunity.
Pacific Corp, obviously we'll continue
to evolve our processes relating to preparing ourselves
and the community for PSPS events.
Our areas of focus, as we walked through that
do include identifying our vulnerable populations,
expanding our programs,
the medical baseline, and AFN customers.
We recognize we have an opportunity to expand
and evolve our current offerings.
So we'll be looking to do that,
continue to push in our improved communications
and how we're providing information through our web pages.
And as we build a better situational awareness internally
with our weather forecasting,
being able to pass that straight through to our customers
through our website so that they can see
that weather forecasting capability as well.
This conversation about the continued collaboration,
our tabletop exercises,
and actually doing functional tests of that.
And can we set these CRCs up
and moving beyond just planning for them,
but actually exercising some of them
absolutely is an area that we'll push on.
And just that ongoing collaboration from that last slide
with all these various agencies and communities
and critical infrastructure, like communication
will be an area of focus as well.
So with that, that ends the presentation.
And we had a lot of good questions throughout,
but happy to field any additional questions at this time.
-: Okay. Thank you very much for you
and your fellow colleagues for the presentation.
Are there any remaining questions
before we move on to the next presentation by Liberty?
-: Yeah. I just have one question President Batjer.
Oh, sorry Commissioner.
-: Yeah, no, go ahead.
Go ahead.
-: Its one real quick question.
Allen, while reviewing your wildfire mitigation plan
it looks like the company was only able
to deploy two out of the 11 weather stations
that you had planned for last year.
Curious what you've done
to get caught up in your weather stations
and what you're doing differently this year
to make sure that you stay on track.
-: Thank you for that question.
'Cause yeah, we are to 20 weather stations
have been installed and 41 across
our Pacific Corp service territory.
And we have ordered like an additional 100,
just to give you a sense of the context of the magnitude
of what we're looking to have installed
across our service territory
before going into the next wildfire season.
So yes, we're on track and implemented
what we wanted for before this fire season,
but looking to push that even further
and more than doubling our our station count.
-: Great. Thank you.
-: Last question, I guess, to accommodate, you know,
yesterday we heard confusion, he added--
-: Commissioner Shiroma, could you speak
a little bit more direct I'm having...
You're kind of fading in and out for me.
-: Sorry, I'll get closer to the (mumbles).
You know, there's been a number of fires
up in newer territory.
I think there are some current fires now.
And so I think we're all feeling
a really strong sense of urgency.
I imagine you are too.
Are any of these fires affecting your infrastructure,
your system up in Northern (indistinct).
-: Right.
And Justin might be able to jump in
and provide a more detailed quick.
Currently yeah, no,
well actually I'll just throw it to you Justin,
'cause I don't wanna misspeak.
Justin: So no problem, man.
Yeah.
Most recently the boot lake fire in Southern Oregon
was the most impactful of our assets.
And currently we're keeping a close eye
on some of in Southern Oregon the animal fire specifically,
and some of the grills.
So we do have a lot of smaller ones right now,
but we all know how quickly they can grow,
especially with some of the winds.
So we're very busy on the operational front right now.
-: Yeah. Okay.
All right.
I just wanted to acknowledge that.
-: Thank you.
-: There...
Thank you.
Are there any other questions of Mr. Berreth?
Okay.
Thank you very much for the presentation from Pacific Corp.
And I think there are quite a few follow-ups
that we have all enumerated today.
And so we look forward to those follow-ups
from you and your company.
So thank you very much.
And we will now turn to the presentation from Liberty
to Mr. Chris Alario,
who is the president of Liberty Utilities.
And I do apologize sir for being, keeping you waiting
and being a little late, but we, as you could tell,
we had quite a few questions to ask at Pacific Corp,
and that will probably be the same for you.
So please don't take it as a rude interruption
when the virtual dais asks you questions
during your presentation,
but that's seems a better way for us to roll.
So with that, please, I turn to you now
for your presentation from Liberty.
-: Okay.
I'll just check and test to make sure everyone can hear me.
-: Yes we can hear you fine.
-: Good morning President Batjer, Commissioners
and other state agency representatives.
My name is Chris Alario,
and I'm president of Liberty Utilities,
California Operations.
Joining me today are Travis Johnson,
our vice president of our Tahoe operations
and Elliot Jones, our senior manager of wildfire prevention.
I would like to just comment real briefly here
that sitting in
and listening to the Pacific Corp presentation
was tremendous for us.
The learning, just the questions that are being asked
and the presentation it's really helpful for us
because this is really new terrain for all of us.
And the more that we can see
what our peer companies are doing
and understanding what they're doing,
there's a lot of opportunity for shared knowledge
and shared learning here.
So this is a great opportunity for us.
We really appreciate the opportunity
to be part of this public meeting.
And I'd also like to note that Mr. Ghilarducci,
offer to meet with the smaller IOUs
to help us improve our customer,
our PSPS preparation mitigation of customer impacts.
We'll be reaching out to you, sir.
And we want to set something up
and take you up on your offer in the near term.
So really appreciate that offer.
Can you please advance to the next slide?
So I thought I'd start by giving you a quick overview
of our operations.
So Liberty serves approximately 49,000 customers
in the greater Lake Tahoe Basin area.
One unique feature of our Lake Tahoe utility
is that it is connected to the Nevada balancing authority,
not Cal ISO.
And we purchased power directly from NV energy.
We also own and operate two solar farms located in Nevada
that generate supply 60 megawatts of renewable energy
to our customers via NV energy's transmission system.
Our local operations comprise 125 employees.
We have increased our staffing by 25%
over the last two years,
adding 25 new positions to underpin our base operations
and lead an execute our wildfire
mitigation programs and activities.
As you can see by the map,
our service territory is quite expansive
while most of our customers live in the Tahoe Basin area
our serious territory does stretch north
as far north to the Town of Portola.
And as far south
to the communities of Markleeville, Coleville/Walker.
One another unique feature of our service territory is,
is that we do have a high percentage of high fire risk areas
with over 90% of Liberty's 1,400 miles of overhead lines
located in high wildfire threat districts.
Climate change and ongoing drought exasperates
the welfare challenges we face in Lake Tahoe.
And if the drought continues into 2022
and the trends continue
for earlier and longer wildfire seasons,
the surrounding forest and the Lake Tahoe area
will be more stressed and prone
for exceptional wildfire conditions and risk.
As you can expect, what is shaping up
to be one of the most and what is shaping up
to be one of the most severe wildfire seasons on record?
Our top priority is keeping customers safe,
minimizing customer impacts
and connecting and supporting AFN populations.
We are doing everything possible to prepare
and be ready to respond to emergency situations
safely and timely.
As I mentioned, we've been increasing our staffing.
We've also been focused on improving resource planning,
logistics, and execution.
I think we've made tremendous progress as you'll see in a,
in a slide later on and improving customer
and external communications.
And that includes both the timing, accuracy,
and effectiveness.
And then one thing I really pride our company on
and our staff.
I think we've gotten better too at being more transparent
with our customers,
with our communities and with our partners.
And this is really critical
because these wildfire situations,
we serve a number of very small, tight knit communities
and our ability to be transparent
and communicate real effective information to them
helps lower their anxiety and gives them the confidence
that their utility provider is doing everything they can
to keep them safe and try to avoid PSPS.
As previously noted,
we have been fortunate so far in being able
to avoid having to execute a PSPS over the last three years,
but we wanna make clear that we see it
just like the Commission does that.
And we view it.
We view PSPS as an option of (indistinct).
And as Travis we'll discuss later on in the presentation,
we are making good progress in hardening our system assets
to mitigate wildfire risk so that we can continue to avoid
or at a minimum, minimize the use of PSPS
and minimize the impacts on our customer during the wild
customers during the wildfire season.
We have learned a lot over the last three years,
and we continue to learn
both from these type of public meetings,
but also in working with our peer companies.
And as Elliott we'll discuss later,
we are applying those lessons, those learnings
to improve our PSPS decision-making.
Including utilizing more real time information
by deploying our linemen to patrol
and monitor conditions on the ground.
As you know and it has already been commented
the wildfire season is already in full swing.
So I would like to conclude my opening comments
with a brief update on Liberty's recent response
to the Tamarack fire.
Which was caused by lightning and fueled by high winds.
And it did spread into Liberty's of service area,
south of Lake Tahoe, the Lake Tahoe Basin and into Nevada.
The fire burned over 60,000, 68,000 acres.
At the high point,
the fire caused the evacuation of one of our communities,
the historic town of Markleeville and surrounding areas,
and has impacted over a thousand Liberty customers
at various times.
Two weeks ago, the fire destroyed six miles
of our main line and laterals
serving Markleeville and the surrounding communities
working closely with incident command,
we organized and deployed over 100 Lyman and contractors
to the fire zone.
Our field crews worked 16 hour shifts to rebuild
our main line laterals, which involve replacing 130 poles
in very challenging and remote terrain
and removing 4,800 fire damaged
or destroyed trees from the right of ways.
At the same time, we were able to mitigate customer impacts
during the two week emergency
by deploying temporary generators and Markleeville,
which allowed us to keep those 350 plus customers in power
while we rebuilt the lines.
We also deployed and we're ready to power up
temporary generators in the Coleville/Walker area
while NB energy made repairs to their fire damaged lines,
that feed power to our 770 customers in that area.
We were fortunate that NB energy
was able to complete the repairs
without cutting power to our customers.
So we did not have to power up the generators,
but I would like to know we were ready.
So by shifting all available resources to Markleeville area
and working around the clock,
we're happy to report as of two days ago,
Liberty completed the rebuild, re-energize the lines
and restored service to all customers
that can receive power in the Markleeville area.
So I also wanna thank all the public agency partners
that we worked with during this emergency
great learning lesson.
We plan to spend a lot of time here
once we finished the cleanup to really debrief
and do a lessons learned
and all this is gonna be hopefully helping us
be better prepared for the next emergency.
So with that, will you please.
-: May I interrupt for just a second
because it's quite extraordinary.
Not only are you dealing with the Tamarack fire,
and what had has occurred there,
but also I would imagine the Beckworth complex fire.
So I'm sure you're gonna talk about that,
but I'm curious with the evacuations
that were done in Markleeville area,
were you all asked at all by the community,
or maybe this will be one of your lessons learned
to set up any kind of community on resource center,
even though it's not that you call the PSPS,
clearly people were evacuated and lost power.
-: Well, we considered that,
but we were fortunate that because of the entire town
and surrounding areas were evacuated,
it gave us time to procure temporary generators.
And our engineers figured out a way
to basically set up the temporary energy generators
that could then power up the lines south of where we were,
where our main line was destroyed.
We were able to effectively power up the whole grid
using temporary generators.
So there was no immediate,
there was no impact on the customers
when they were able to move back into the area
once the evacuation order was lifted.
-: Okay.
-: Yeah.
-: And obviously there a lot of tribal land and area
in that Markleeville
both the Washoe as well as the Paiutes tribes.
And not only have you had to contend with fires,
but you had a tremendous earthquake in Walker.
So I don't know in dealing with your
you're still the facility is it's,
it's shaking quite a bit these days as well.
-: Well, I mean, we are now in a situation
where if we're not preparing and ready
and readying ourselves for the wildfire,
we're in winter storm season, so we're getting very,
we're getting very good and better each year
at responding to emergency situations,
just given the environment in which we operate
and where the system is located.
It sits on the mountain in the middle of the forest.
So we're getting better each year.
-: Okay. Thank you.
-: Chris, this is Daniel.
I have just a quick question on your rebuild.
You know, first I have to acknowledge,
obviously that your team must have worked significantly hard
to restore power and restore the infrastructure
that was destroyed by the fire, but just curious,
were you able to take any opportunities
to replace any of the line with covered line
or any of the infrastructure with hardened items
while you were in this rebuilding process?
-: We looked at that the unfortunately the planning horizon
for a cover conductor, it's a six to eight week process
just to do the design.
It is a special equipment you do.
And so we had to weigh, do we do a cover conductor
that would take a lot more time,
or do we go ahead and rebuild the line
as quickly as possible
to get to keep the customers in power?
And the temporary generators, that's not a long-term fix
and we weren't comfortable running those generators
could be, it could take us anywhere to two to three months
to complete a cover conductor project
with just the planning horizon, ordering the materials.
So we did consider it, but at the end of the day,
we opted to minimize the customer impact
and rebuild the line.
We did upgrade the poles
and I believe we upgraded the wires as well,
but we did not go all the way it's covered conduct.
-: Thank you.
-: All up to that.
You know, one of the things that also is,
and I appreciate the kind of conundrum
about needing to get power back up
and perhaps maybe not missing the opportunity to harden,
but not having that readily available.
And the similar can, the situation tends to exist
with the communications infrastructure.
And in this case, you sound like you're above ground,
still with all the infrastructure,
but was there any communication
with a telecommunication providers in the area
about even attaching together,
making sure the poles were updated to make sure
they could withstand enough
of the communication attachments?
-: Yes.
My understanding is all the polls were designed.
I believe that the original,
that the existing mainline we had there
did actually have telecommunications hardware on it already.
I think we had agreements
with the telecommunication provider
to have those hardware there.
But I'll defer, I'll bring Travis in here.
Travis, do you have any more information
on the telecommunications?
I believe generally what the plan is
we get our poles in place, we get the power up
and then the telecommunication company
comes behind us and then strings are their lines back on.
-: Yeah, that's correct, Chris.
So I think it's frontier that actually serves that region
and all poles calcs were done
to allow for that telecom, you know,
hardware to be restrung on the poles.
So it's certainly designed for it.
-: So this is Mark, and just a quick thing
and I appreciate your briefing.
So I spent quite a bit of time up in Alpine and Markleeville
whether in the fire and afterwards, and I'd say your,
your crews are kicking butt out there and doing a great job
and in restoration and the work that they're doing.
It didn't dawn on me as I was driving by
a number of your crews and watching their operations
about rebuilding and how you're rebuilding,
you know the fire came through there in 84, the acorn fire.
Now we've got a fire again, this year.
Probability is we'll see, fire there again.
And so really from a policy standpoint
from the organization,
how are you thinking about investing
in hardening your infrastructure?
What are your plan there?
I mean, if we build back exactly as we had before,
then we're destined to sort of see the same
sort of outcome in future events.
So just kind of one of the mitigation efforts
you are focusing on and how you're doing them?
-: Now, I'll briefly respond to that.
But I think Travis, in his slide, in two slides from now,
we'll be going more into that.
But our challenge is that over 90% of our overhead lines
are in high wildfire threat districts.
If in a perfect world and we had endless access to capital
and we didn't have to impact rates,
we would be doing a lot more cover conductors
and a lot more undergrounding.
But unfortunately that we have to balance
both the needs of improving the system
and at the same time trying to manage the impacts on rates.
And we take that very seriously.
So what our challenge is really, really focusing on
and having a good criteria around prioritizing the projects.
And I would assume, and Travis might be able to speak to it
that this particular main line to Markleeville
is probably somewhere in our overall planning,
but there are other projects I know there are other projects
ahead of that one that have been ranked a higher priority
based on both our risk-based decision-making framework,
as well as other criteria that we take into account.
And so we're getting better every year at it
but as you can see the system that we operate,
it's very challenging to try to do everything all at once.
It's almost impossible, but we appreciate that feedback.
And when you come visit us,
we could probably spend some more time sharing with you,
how we go about using this criteria to really identify,
evaluate, and select
and prioritize the projects we're gonna do.
-: Great. Thanks.
Appreciate the feedback.
-: Okay.
Can we advance to the next slide?
Okay.
So on publication, public education, outreach improvements.
This is one area that I have taken a particular interest in,
and I do work closely with our customer service groups
and our public outreach people,
as well as our customer communications.
I am happy to report that we are making good progress
in connecting with our customers and local communities
and educating them about the wildfire threats and risks
and our mitigation efforts and programs
aimed at keeping our customers safe
and minimizing as best possible impact on our customers.
We, of course like all the other companies,
we are continue to use traditional communication means
to public meeting formats,
to get the message out to our customers.
So far this year, we've completed 12 public meetings
with counties and community organizations,
14 targeted social media posts on Twitter and Facebook
and for direct mail and email communications
on specific subjects and vegetation management.
We also have several people in our organization
that are active in the local communities.
A number of our employees are part of the local community
and our customers.
And so in addition to what we do here
formally through our communications program,
we do have eyes and ears in the local community
and advancing our messaging and try to get better
at really identifying and meeting with
and getting information out to any and all customers.
We have learned a lot over the last three years,
and we are applying these lessons
to improve our public education and outreach program.
We are getting better at this and notably
we are making good progress in registering
and supporting our medical baseline customers.
I think one thing I'd really like to note here,
and I think this is a testament
of the commitment of our team.
Our customer service team has called visited
all 258 registered medical baseline customers
to update their contact information
so that we've got good contact information
in the event we have an emergency
and also they answer any other questions they may have.
Now we've got a lot of work to do in this space
and we know it.
And I would say our biggest challenge and top priority now
is engaging supporting the needs of our AFN
and Spanish speaking customers.
We are actively working on creating partnerships
with six local CBOs
to assist with our identification outreach
and registration efforts,
to customers with special assistance and notification needs.
We recently engaged with the Washoe tribe,
who are located in the Southern end of our service territory
to update them on our response to outages in their area,
caused by the Tamarack fire
and discuss future collaboration.
We have provided TBOs PSPS toolkits in English and Spanish
detailing what customers can do
to be prepared for PSPS events
and are prepared to provide the toolkit
in other languages upon request.
We were also working on establishing a portal on our website
for customers to self identify as AFN
and expect this to be in service by next month.
And we are, what else are we doing here?
We also are working to identify additional CBOs,
and this is probably the biggest challenge for us
because this is not a readily group
that is easy to identify.
We do not track that in our customer information system.
And so we'd had particular challenges there.
And one response has been of course,
is to reaching out and partnering with CBOs.
But the other thing that we identified and recognizes
that we don't have enough resources
on this particular challenge.
And so we are in the process of hiring two new positions
to focus on deepening, expanding the CBO partnerships.
And we've also are hiring one new bilingual position
to perform outreach
and support our Spanish speaking customers.
We have one of these positions
will be filled a manager of public outreach.
The lady had accepted the position
and we'll be starting in the next couple of weeks.
So finally I wanted to touch upon.
We are also making good progress on building relationships
and coordinating with the major communication
carriers in our service area.
We have established points of contact
with Verizon, AT&T and Frontier all of whom are now engaged
in participating in our PSPS exercise and wildfire safety
to (mumbles) advisory board meetings.
For taking into account the time here,
I would like to advance to the next slide
and have Travis go ahead and I'll turn it over to Travis
to talk about grid hardening.
Unless there's any questions
that you want me to take right now.
Okay.
So Travis, it's I'll turn it over to you.
Travis: All right.
So quick audio check.
I'm assuming everyone can hear me.
Okay.
So I'd like to open if I could.
First of all, President Batjer,
thank you for the opportunity to speak today.
And President Batjer, (giggles)
your comment was not lost upon us.
We do have the backward complex fire,
just adjacent to the Northern portion of our system
that certainly got the blood pressure up.
But thankfully we haven't had any infrastructure damage
from that fire.
We do.
It's interesting that 6.0 earthquake,
the largest one in the Western US,
I think in the last 25 years
you have the center was essentially Walker, California.
It's those folks haven't had enough hardship as of late.
And then the Tamarack fire is currently still active.
And I think it's noteworthy that we almost forget it,
but all of this stuff is going on during a global pandemic,
which I never thought I would have said these words
altogether in a couple of sentences.
So there's certainly a lot going on here.
So some of the system hardening improvements
that we just like to call out,
we are doing quite a bit of covered conductor work as well.
I think we're up to over seven miles
of covered conductor in the air now.
Majority in the Tahoe Basin
with some down on the Walker/Coleville area.
The one of our kind of flagship things
that we're pretty proud of
is the Sagehen Microgrid project.
This is a Microgrid that we installed
that powers the University of Berkeley's
a Sagehen Creek Field Station.
And essentially what this project allows us to do
is de-energize around three miles of distribution line
that goes through some pretty remote
and challenging terrain.
So currently, as of May early May of this year,
we power that lateral down
and we're feeding the campus completely with our solar
array there and battery storage.
And so far we've been doing great,
state of charge has been solid,
and we haven't had to rely on the distribution lateral
to power that campus.
So that's been pretty exciting for us.
One of the details behind our pole replacement program
is I think as most folks on this WebEx know,
we're required to only inspect
about 20% of our poles each year.
Well, we took the initiative last early last year.
We said, that's not good enough for us
in these conditions that we're now the new normal.
So we actually went out and inspected
every single one of our poles in the calendar year of 2020.
So that's five times more inspection work
than we're used to,
which of course would generate a lot more repairs
once you go out looking for issues.
So the pole replacements that we're doing now
are just enormous, five times more than we normally would
on top of a large spin up in CapEx related
spending on covered conductor.
So lots going on here in the Tahoe area
regarding those items.
Fuse replacements I think we all know what those are.
Expulsion fuses in that hot particles when they operate.
So we're working diligently to get those changed out.
Tree attachments may not be totally known
everywhere in California, but up in the Tahoe area,
the prior owner of this utility utilized,
and it was kind of common practice back then
uses threes to run service wire to home.
So we're getting rid of those attachments
'cause trees continue to move and die over time.
And we don't wanna have our service wire hooked up to those.
We're doing quite a bit of a wire upgrade projects as well.
And the things that aren't on here
that I do think are worthy of touching on
is in King's Beach we deCommissioned
very old substation called Brockway Sub
and Commissioner Guzman (indistinct) and team
had the opportunity to tour that.
I believe it was late 2019 or early 2020
before the pandemic.
Very pleased to say that substation
is not only de-energized, it is gone and we've replaced it
with a new metal clad switchgear station,
just up the street at King's Beach Sub.
So that one, I just a huge thanks to the Commission
and partnering with us to get that approved and eliminated.
Let's see here, a couple other things on the list
that I wanted to share
as we were also doing a high impedance,
all detection partnership
with the University of Nevada, Reno.
And so for the non protection engineers on the call
that if you have a high impedance fall,
something like a tree leaning on the line,
but may not be establishing fault current,
those are hard to detect sometimes.
So we're working with UNR there
to improve our ability to see those issues
before we do have some type of ignition start.
We're also working with Texas A&M on a DFA
that's distribution fault anticipation.
We heard Pacific Corp talking about that
with wave form analytics.
So certainly exciting stuff there.
And essentially that's detecting that fault
before the fault current,
before that actual arc burst happens.
So excited to see how that program pans out.
So those are the highlights I wanted to share
on grid and Hardy, excuse me, grid hardening.
And now I'll pass it back over to Chris,
to take the next slide.
Chris: Yeah.
Daniel: It's Daniel, before you move on
it just a quick question.
Thank you for the numbers here on your home
or on your infrastructure hardening,
but do you have any measurable targets
for what you've been able
to actually accomplish here in 2021,
again, acknowledging that you have been redirected
and focused on rebuilding a lot of your line,
but do you have any idea of the percentage of completion
for, for this year's goals?
Travis: Okay, a very good question.
So first I did wanna take an opportunity
to address the earlier question about rebuilding
and the Markleeville area.
So the near term goal is unfortunately
all of the trees adjacent to our burn line were killed.
So we took the opportunity to work with those landowners
to remove any tree that had striked just since,
within strike distance in our line.
So from a fire safety perspective that right away now,
it looks like a transmission corridor
along that distribution feeder.
So that's the short term sort of strategy
we've come in with much higher class poles in most cases,
so stronger poles, but a very, very clear right away
is the short-term strategy.
And then as we move into the latter years,
it will be a covered conductor opportunity.
And as Chris mentioned,
that's just a little bit lower down the priority.
Now that's out right away.
It looks like a transmission corridor.
So regarding being on track and on schedule
for a covered conducted projects,
we still expect to have those completed
by the end of our construction season.
And I think it's worthy to point out
for the team on the phone.
We have a very unique circumstance in Tahoe,
in the basin here
and here we can only build in what we call dig season,
which is May 1st to October 15th.
So we have a very tight window
to actually get projects done.
And that's regarding water clarity for the Tahoe Basin.
We don't wanna have a lot of soil disturbance
and cause a degradation of clarity.
So yes, we are on schedule
for our cover conductor projects in '21,
and we should get those wrapped up.
Daniel: Well, I applaud you again.
That's gotta be tough work
with all the rebuilding that's going on.
So thank you for that.
Appreciate the explanation.
-: Yeah.
I just wanted to add a couple of comments too.
So I actually just checked and we are tracking to complete
our entire capital program for wildfire mitigation.
You can see it.
I think it's $34 million number,
actually, it's higher than that.
We've added some more projects.
We are probably by the end of the year,
we're gonna complete potentially up to $40 million
of capital improvements
targeted specifically at wildfire mitigation.
The other thing I wanted to comment too
is is that we actually received a number of awards
on that Microgrid project up at Sagehen.
And now what we're doing as part of our feasibility analysis
for our cover conductor projects,
we do a alternative analysis
on each and every cover conductor
to see if there is the possibility to utilize a Microgrid,
to either replace the cover conductor
or in some cases shortened to cover conductor link.
And so it was a great learning opportunity
to Sagehen project.
It worked out very well.
And so we're taking that success
and now we're looking to see if we can deploy it elsewhere
in the service area.
Which not only will, help us lower, get more work done.
But the other thing it does too,
is it is a lower cost option in many cases
to and to the coverage conductor.
So we're getting a better bang for the buck as well.
So with that, why don't we go ahead and--
-: Sorry.
Can I ask a clarifying question on that
and why does the source of energy impact
whether or not you should have a covered conductor?
How's the Microgrid as a source of energy impact wires?
-: Well, what it basically allows us to do Commissioner,
it allows us to take that three mile stretch of line
to take it out of service during the wildfire season.
So what we basically do that mile that Microgrid
during the wildfire season supplies 100% of the power
to that Sagehen facility.
And it allows us to take out a service
aligned in a very high fire, okay?
-: Yeah. Thank you.
-: You're welcome.
Should we go ahead and advance to the next slide?
So I talked a lot about AFN and vulnerable customers,
and if there's more questions on that, I can answer them.
But for the balance of the time here,
I really would like to give Travis an opportunity
to share with the group here,
what we're doing with respect to our resiliency program.
And specifically we have a very innovative project
that we're gonna be bringing forward to the Commission here
in short order, probably within the next 30 to 60 days.
But Travis,
why don't you share with them our resiliency program?
Travis: Thank you for that, Chris.
So this is an exciting program where
we're looking to deploy over 300 behind the meter batteries.
And so the target is around 272 batteries
for medical baseline customers.
There would be around 35 for critical facility customers
and then another 20 to 21 batteries,
large battery systems for large customers in that category.
So these would be owned and operated by Liberty,
and we could also deploy them as a virtual power plant
to achieve demand, charge savings from NB energy
to help fund the program.
So what we wanted to do is reach out to our customers
as we were crafting this program
to get a lot of input from them.
So we've received 388 surveys
completed from our customer base on this resiliency program
and including 30 from critical care
or green cross customers on their thoughts.
So what we're essentially gonna do with this information
is package it all together, take that feedback.
And then as Chris said,
we're gonna approach the Commission here
in short order with this program.
Another part of--
-: Can I ask you, sorry to interrupt you.
How does that compare to the universe
of your medical baseline customers 300?
You said you're targeting 300 customers
in 35 critical care facilities.
-: I believe in, and Chris it's helped me from a memory here,
but I think that gets essentially almost 100%
of our green cross customers.
-: Yeah.
Yes, Commissioner
right now we have registered 258 medical baseline customers.
So the program would cover all the, that would,
they would receive first priority of the batteries
our medical baseline customers.
And then the balance of the batteries, then we would,
we would look to deploy,
as Travis said to critical facilities
and then possibly some of our larger customers.
We see this as a very exciting program, actually.
-: Okay. I was--
-: It's also something that helps us in the winter months too
where we have outages the medical medical baseline customers
will be protected
because they will have of these batteries in place.
I excuse me for interrupting you.
-: No, no, that's okay, Chris.
I will, of course look carefully at what you submit to us.
I would just say that some of the backup power,
the batteries that the utilities
other utilities have been providing
to provide backup service.
In some cases they're easily able to be also used
for demand reduction and demand management purposes
and other cases, purposes diverge.
So it's a little bit tricky and we just wanna make,
in this context, we're most interested in seeing them
use to provide the backup power needed to critical times.
I'm sure you've thought a great deal about that,
but I just wanna underscore that.
-: That's a great point Commissioner,
certainly inbound storm dispatching that energy
to take care of the demand charge for the month is not,
is not the way we've planned to do that.
Or certainly with impending PSPS conditions.
Absolutely not.
So a very point well-taken.
I just wanted to point out one other component.
Before I moved to the second tier
of this resiliency program.
For low-income customers
they would actually receive that service,
the medical baseline low-income
they would receive the service for free.
And the way we've designed it
as part of the demand charge savings
would help fund that portion.
So look forward to getting that application together,
to provide much more detail, but we are excited about that.
-: Chris and Travis, I hate to interrupt
'cause we're in a really critical time,
but we are hopelessly behind schedule today,
and it's not your fault.
These have been robust, important discussions that we have
with you as well as with Pacific Corp,
but we're almost an hour behind.
So I hate to do this to you,
but we're gonna need to sort of wrap up
and I know you've got some important things in front of us
in your slide deck,
and I hate to, particularly as your AFN discussions,
because that's critically important to all of us.
Just wanna say one last thing.
It seems like your AFN community I'm from Northern Nevada.
I know your territory extremely well.
I grew up in Carson City, Nevada,
and my family was from Smith Valley.
So I know your backyard really well,
but I can't believe
that you have so few medical baseline folks signed up.
So it just, that seems like a very small number.
I know you're working hard on it,
but it seems like a very, very small number.
-: Yeah, well, hopefully we're gonna get better at this
and we are committed and focused on identification
and registration and the next time we get together,
hopefully we'll have better, better results
and better, better numbers for you as well,
President Batjer.
-: Yeah, I look forward to that
and I know that my fellow Commissioners do as well.
-: Okay.
So we hear you on the time crunch here.
So I'm gonna go ahead and turn it over and to Elliot.
Elliot, can you quickly walk them through
our PSPS decision-making matrix
and then we'll see how much time is left.
I think this is critical for the Commissioners
and our state agency representatives
to understand how we do this.
So we'll go ahead and please advance to the next slide.
Elliot: Thank you, Chris.
And I will do my best to provide the information
as accurately as possible and as abbreviated as possible
if I can here.
So what's we're gonna move into
is our PSPS decision making criteria and modeling
as discussed before we have not activated
at public safety power shutoff,
that we've put a lot of effort into our preparedness
in the event that we do have one.
It really is a last resort.
And so the decision tree that you see here
is sort of our criteria
should note that we've broken down our territory
into 46 PSPS zones
that would each receive an individual forecast,
looking at these factors that you see here on this screen.
The first one, there being energy release component.
And without going into too much detail,
that's a measure of vegetation flammability.
You know, when, when conditions are beyond our threshold,
we're monitoring that.
And then moving into monitoring wind speeds,
where over 40 miles an hour is what our analysis
shows is sort of an exponential increase
in outages beyond 40 miles per hour.
So that's another one of our factors.
And then the other one is mentioned earlier by Pacific Corp
as the (indistinct) fire weather index,
looking at temperature, wind, and relative humidity.
So really we were looking at forecast every six hours
for all of those 46 zones and evaluating these factors.
And we have the ability to make a decision
within any one of those zones around PSPS.
I will go to the next slide now.
So just wanted to note with this one,
that we're always looking for ways
that we can improve our decision-making
and our situational awareness.
And so this is sort of a new decision-making criteria
that we are evaluating right now,
sort of in parallel to our distinct criteria.
And so this one utilizes wind speed and burning indexes.
Our key decision making factors.
Burning index or BI is really a combination of
how fast the fire will spread.
And also the flammability of the vegetation,
which is the energy release component.
So really it's a measure of flame length
and flame lengths above eight feet
can present serious control problems and firefighting effort
that the head of the firewall likely be unsuccessful
from what our analysis has shown in the past.
And so really the idea here is to capture,
extreme wind driven events
that our other criteria may or may not catch
in the same manner sort of in the late season
or maybe even early season.
So like I said, we are evaluating,
this is just one more factor,
one more tool in the tool box that we're looking at
when we are evaluating the extreme fire conditions.
And then also combining that with, as Chris mentioned,
our proactive patrols during elevated weather events,
taking those field observations from our line crew,
the staff that are out there inspecting lines,
and just as a way to continue to learn
from these elevated weather events.
(mumbles) Next slide, please.
Is there a comment?
-: Can I just make a comment?
And this is a comment to the other small I'll use.
I should've made it to Pacific Corp as well.
I don't know, were you able to listen to the presentations
the past couple of days from the larger IOUs?
Elliot: I was able to listen to
the San Diego Gas&Electric.
So I haven't had a chance
to catch up on the other two yesterday.
-: I just wanted to make a point
and we can follow up offline
as I'm sure you will know.
They have increasingly sophisticated
machine learning methodology for evaluating
the potential of admissions spread and so forth.
And I think that I don't think they're proprietary.
I don't know how if you have the capability
to use all of them with the most recent iteration,
but they keep improving them.
And we've heard from PGE about a probabilistic weather
tool that they're now adding to their fire potential index.
I would just urge you in Pacific Corp and Bear Valley
and others to see what you can borrow
from those technologies.
Because as I say, I don't think that
they're all proprietary.
I think they've been sharing those
and you could benefit
from the increasingly sophisticated tools they're using.
-: Thank you for that Commissioner.
Well, definitely something we're monitoring
and we're always looking to learn and improve.
So definitely noted and we will key in
on some of those factors that the large utilities
are looking into.
So thank you.
-: Thank you.
-: I do know, I do know that indeed they will share.
I've asked San Diego's SDG
and you had asked that question specifically of them
they'll even share algorithms
that they've developed, et cetera.
So I think a meeting with them
would be very, very helpful to.
-: Excellent.
-: Yeah. Thank you.
-: Again, I'm watching the clock
it's getting really nervous, everybody. (laughs)
-: You know what, Elliot, I'll wrap up here.
Let me do the vegetation threat real quick for you.
So basically what this slide shows is is that five years ago
we were working about for about 3,500 trees a year,
fast forward to 2020.
We're now working in excess of 13,000 trees a year
by working at is that's either training
or removing a dead dying tree.
So we nip it currently wrapped up
our vegetation management program,
and this is really proving some good results for us.
Last winter season for the first time
we saw a significant decrease in outages,
which we attribute to our vegetation management program
clearing out those dead and dying trees,
which are being loaded with snow and falling on our lines.
And with that Commissioner, we have a couple other slides,
but we'd be more than happy later on to follow up
with the fifth, the Commissioners or staff
for additional questions.
We appreciate the opportunity to be here today
and share with you what we're doing in Lake Tahoe
to keep the customer safe
and try to do our best at mitigating the wildfire risks
that poses to our customers.
Thank you very much.
-: President Batjer might be on mute.
-: Oh gosh. I'm so sorry.
I was on mute.
Thank you, Chris and team very, very much.
The last two slides are extremely important to us,
the information as well as to the public.
So I'm sorry to truncate this.
I have already sent a note to Rachel Peterson,
our executive director,
and talking to her about
how we can do a follow-up meeting with you
to make sure that we complete this presentation
and that the Commissioners and the virtual guys
all get their questions asked and answered,
and that we don't, again,
miss out on any important information that we need to,
you need to impart and we need to hear, so--
-: We'll make ourselves available.
-: Okay. Thank you so much.
And I really appreciate your presentation.
You've got your hands full in your territory with wildfires,
earthquakes and sorry, laptop is a big snow here.(giggles)
-: Thank you everyone.
-: All right. Thank you so much.
Thank you all very much. Thank you, Liberty.
Okay.
We are hopelessly behind. As I have said,
I'm going to ask Liberty, excuse me.
I'm gonna ask Bear Valley to please come on board.
I see that you're here and I'm going to ask again,
just as I said to Liberty, we are hopelessly behind
and I see through your deck
that you've got quite a few slides.
If there's any way that you can somehow summarize,
some of it would be very, very helpful,
and it will, it may mean that we have to do a reschedule,
so we don't miss anything today.
But with that, I would like to have Bear Valley,
go ahead and begin the presentation
by introducing yourself and the team.
-: President Batjer, Commissioners,
and other agency officials.
I'm Paul Marconi president of Bear Valley.
I'll be giving this presentation solo,
but there is quite a team effort behind this.
If we could go to the next slide.
Basically, you're gonna follow the agenda that was provided.
Let me go to the next slide.
We're located in San Bernardino mountains.
We're a small service area, 32 square miles.
We're mostly at or above 7,000 feet.
We're in a dry environment.
We're in the high fire threat district entirely
90% is tier two, 10% is tier one.
As of today, we're actually 805 days accident free.
And we're very proud of that.
And safety is obviously our number one priority.
Go to the next slide.
One of the things that president touched upon this,
we are definitely very much impacted by Southern California
and so the most important takeaway from this slide
is actually the graphic, the red lines show Edison's lines
that come into Bear Valley.
There's two from the north, which is our main supply lines
and the small line from the south,
which that line mates up with one of our lines,
the Radford that's all in tier three area.
Generally we can de-energized
during the high fire threat periods.
Go to the next slide.
This is the third season we've been preparing for PSPS.
We've never involved one, but we've been very much out there
following what everybody else is doing and trying to learn.
And outreach has been probably the most important thing,
trying to prepare our community without scaring them.
And I think we have a very supportive community.
We've worked on the language piece
right now we can do real time in English and Spanish.
We do have co-care materials in all the languages
that Commissioner guidelines require,
but we would like to get to real time in those as well.
We've implemented two way emergency text communications
and our IVR,
and we continue to further improve our communications
and outreach
and we'll get to access and functional needs customers.
We've been working with the county and city.
In fact, yesterday I reached agreement with the city manager
on a confidentiality agreement
so that we can share some of our customer information.
And not just for PSPS, but for emergencies and disasters.
It makes sense.
We are constantly updating critical customer lists
and provide that to our field operations.
There are no questions on this particular slide.
I'd like to go to the next one in the interest of time.
So we have not that's to the PSPS,
so we don't have any direct experience.
So our lessons learned are derived from two PSPS drills.
Now, while the last one was a tabletop,
we did send people out to the field to do inspections.
We did exercise that component.
We did exercise our CRC and actually set it up
and verify it with function.
We did actually deploy people with batteries
to addresses, to simulate.
We were delivering batteries.
So we did try to do as much as we could
because you really never know
until you actually do something, how it's actually gonna go.
We have a PSPS manual that we've updated now once.
And we did go through that and make sure
that we followed everything in our manual.
We have learned a lot from these workshops
prior to this workshop,
this year alone, we're two other workshops.
We've looked at the public surveys
and we've got the feedback
from our community and stakeholder meetings.
And we incorporate our lessons learned
in our manual updates.
We'd go to the next slide.
So we did, these are the,
we have four telecommunications providers
in our service area.
We establish points of contact, primary, secondary tertiary.
We've listed all of their facilities
and we're in the process of validating,
which ones have backup power, which ones don't.
And we do have a schedule brief
at the end of August, early September.
We're scheduling a brief for them,
just specifically to the telecommunications.
They've been invited to all of our partner briefs
and community briefs,
but this time I think we're getting a much better response
from them to make sure they're included
and we can talk to them directly.
Go to the next slide,
unless there are any questions on this one.
Two, we don't have any tribal areas, but we do our,
our main jurisdictions are the county of San Bernardino
and the City of Big Bear Lake.
And then we have the US Forest Service.
We in fact, I briefed the city council
and talked to our district supervisor.
We did do annual PSPS meetings for our stakeholders
and communities.
I personally give those meetings
and we're gonna do another round.
We did them in June and we're gonna do another round
of them in early September as well.
We update our notification channels,
points of contact and so forth.
And we test that out.
One of the challenges,
even if we're not gonna invoke a PSPS,
because we're in the Los Angeles media market,
our customers hear about the Southern California Edison
and PSPS warnings, and often get confused.
And so we do have to do a lot manage that news,
especially with our local government partners
and first responders to make sure they understand
whether or not we're going to be impacted
and how they might be impacted.
So we do quite a bit of that outreach
and that tests the very same channels
that we would use if we were invoking a PSPS.
We closely work with the mountain mutual aid association,
which is a group of utilities, government agencies.
I'm actually the president and a lot of NGOs.
And it's our way that we would respond to any disaster
or emergency in the Valley.
But I also take that opportunity to keep them informed
on how PSPS would work and how that would impact
and how we can work together to mitigate the impact.
One thing I took on this year
is to establish Fire Safe Big Bear Council.
It's a community group that takes up education of wildfire,
works with Cal Fire and the fire departments
and helps the community be involved in fire prevention
or fire wildfire readiness, both of those things.
And so it's a very good nonprofit group.
It's a great way for us to get our message out, I feel.
And so it's something I put suit.
If we could go to the next slide.
So as I said, we're entirely
within the high fire threat district.
It's a reality of our lives here.
By the way, my entire staff has to live in the service area.
It's a requirement.
So we're very much invested in this.
And those shaded areas
are areas that we consider higher risk areas.
And we think they're more likely
if we were to invoke a PSPS.
And so we did early on (indistinct) those areas
have the ability to isolate them
without impacting other customers.
And then we actually have the impact
on how many customers would be impacted by those.
We also have the ability to contact those customers
if we actuate those particular switches
and we would use IVR messaging, text messaging as well.
Is there any questions on that one now go to next.
I don't wanna,
we're doing a lot of the same grid hardening projects
that the other utilities are doing.
So I won't go into detail explaining them,
but I will say that we completed
our weather station installation
we've got 20 weather stations.
That's about 0.6 weather stations per square mile.
Okay.
So we are really learned a lot too
about how we have micro climates up here
and it can have Highlands on one end of the,
of our 10 mile wide area and low winds on the other end.
So it's kind of interesting, but we've done that.
We worked very closely with Dr. Driscoll over it.
You would see installing alert wildfire.
High definition cameras.
We have one more to install.
It's a fun, a local radio station.
And we've got agreement from the radio station owner
to do that.
So really we're just playing coordinator
between UCSD and the radio station.
And then we provide some labor to make that happen.
We, in early when we completed the removal
of all expulsion fuses conventional pieces
from our system over 3000.
So I'm pretty happy about that.
We also implemented enhance this patient
and that has been in place now since March of 2018.
And we've gone through our entire service area
to implement these specs.
We do go above the minimum specifications.
And I think later I have a graphic on best vegetation.
I'll show you the, how, what a positive impact that has had.
We are using technology like LiDAR to survey our system,
and it's extremely useful.
We also hire a third party.
Although we do patrols, we also have hired a third party.
Who's not involved in any other work,
then inspection for us to do a second ground patrol
of our systems so that we get an unbiased view
of how we're doing.
We can go to the next slide.
These are things that are ongoing or in progress
covered wire, replacing bare wire with covered wire.
It's probably the most impactful thing that we can do.
We've last year we got about seven circuit miles.
And so far this year we're over six circuit miles.
We're on track to get 12.9 circuit miles done this year.
And I know there was a question about how would that impact
your TSPs decision making.
And when I get to that, I will explain,
but I think personally it would be unlikely
that we would invoke a PSPS
once we have covered wire in place.
And I'll explain the reasons when I get there.
The Radford line project,
this project is in the permitting process.
It's a line that goes through,
it's a 34,000 volt line that goes through the tier three.
We're working with the fire, the US Forest Service.
It's been a challenge to get it permitted,
but right now we have mitigation in place
that we generally keep it the energize
on high fire threat periods.
We don't really need it
except for during the snow making period,
which for the resorts
and because those are interruptable customers.
And generally we're not, we don't,
I don't think I've ever seen high fire threat day
when we're making snow (laughs) it's it doesn't impact us.
We do have three attachments we've removed about,
I would say almost 50% of them
and we were making good progress.
We have no high voltage tree attachments.
Just be clear on that.
It's service wire, generally service wires down 120 volts.
(coughs) So it's low voltage.
We have other projects that install the high-speed switches,
fall protection equipment, so forth.
We are using this year UADs to inspect our system.
And we are monitoring projects such as solar generation
and batteries to work projects either in planning.
We could go to the next slide,
unless there are any questions on specific grid hardening.
Okay.
This is scenario where we are trying to really improve.
We have medical baseline customers,
but we also have ASN customers in out of 24,600 meters.
If think we'd have more than 14 AFN customers.
So we're pushing that.
I am requiring my customer service now,
anytime someone calls to hire about AFN,
to explain to them about what the program is,
who qualifies as an AFN.
I think even though we've done this via mail,
our website or social media,
I think we just need to be out front and just go after it.
So when you call our customer service now they,
that our customer service are instructed
to make sure we have our folks are understanding of that,
especially also with new applicants obviously.
We are coordinating with CBOs in our area
to identify and educate people on AFN
and self-identification,
and we're working with the City of Big Bear Lake as well.
And as we are looking at the phase three decision
and starting to put together our annual ASN plan
in accordance with safe screening requirements.
Is there any specific questions on that,
like to go to the next slide?
-: Well, Paul, I would agree that that seems
like a very low number given your service territory.
And I do hope you are,
you can do as much as you possibly can do
to really outreach to the community.
And logic would tell you that that is that,
that there must be more people in need
than have an identified to date.
So I would encourage you to continue doing all things,
including what you're doing, plus. (laughs)
-: Yes.
And that'd be support vulnerable customers.
You know, we are, we have a lot,
a fair amount of snow every year.
And so snore snow is more, it's our challenge.
And we've had, since I've been here since 2014,
some major snow storms,
and we've worked very closely
with the city county this year.
So the fire department responding to these outages
and we've always been able to get,
do door to door service for our medical baseline
in those situations.
So I see why I can't do that in the PSPS event.
We use everything. We is phone, IVR, the texting website,
local radio station.
We also go knock on doors, okay?
We're that small that we can knock on doors.
And we have other groups in the community
that were willing to help us knock on doors when we have to.
One of the things that always troubles me on PSPS,
and maybe we can talk about this.
And their decision making is, well, we haven't Santana winds
at 7,000 feet and it's nighttime.
It's about 18 degrees in a Big Bear.
And so that to me is also a safety issue for my customers.
So it's something that I factor in
and we have to have the ability to reach
and go out to our customers if we have to,
if we did invoke the PSPS to get them
the assistance they need,
or get them to a place where they can be warm.
So it's very important that we do that.
We do have a community resource center
that we set up at our main office.
We are, and I'll talk more about those on a slide.
And then once again, horrible batteries,
we do need to learn more about how to deploy these.
We did size the ones we bought
so that you can charge a standard oxygen machine
so that someone who's on oxygen can use that battery
to get their oxygen recharged.
And, and so we wanted to make sure that we didn't bias
'cause there's a lot of batteries out there
that can provide power,
but they provide power the long-term,
but they don't provide that surgeon power
that's needed to actually charge an oxygen machine.
And so we wanted to take a look--
-: Sorry to interrupt.
But as Commissioner, Rick Shaw has said earlier,
I think I'm not sure whether you were able
to listen in on the other presentations by the large IOUs
in the last couple of days,
but I am sure that if you reached out to either San Diego,
Gas&Electric or Edison,
they have quite a bit of experience
with purchasing batteries of all sizes and types,
as well as educating their customers as to how to use them.
So, and we are going to need to wrap up at 11:45,
so about 15 minutes, okay?
-: Okay. Thank you.
And we will reach out, if we could go to the next slide.
So decision-making criteria modeling.
You know, we have many factors,
I'm just a simple minded nuclear engineer.
So I like to keep it simple.
And we looked at the most limiting structures
and then we took the design margin down to zero and said,
found out that the wind
at about 80 miles per hour was limiting.
And then we have a little bit of a cushion in there.
So at 55 miles, it's the speed limit
is when we would probably invoke a PSPS
if we have dry high fire threat conditions, obviously.
And so, and that's for bare wire.
If I had covered wire, when we installed covered wire,
recognize that we go through and also do pole loading.
And so instead of taking my design margin down to zero,
I'm gonna take it down and say 2.67,
that has meaning to those who follow geo 95.
And if we can withstand a hell of a lot more wind.
So I would say, we would evaluate a PSPS
and the 90 to 100 mile per hour winds,
not likely ever going to happen, okay?
Can I say it will never happen? No, (laughs) but not likely.
And if you look at the history of our winds,
the tables below, we just, how in the last six years
just don't experience this high winds.
When we have high risk days.
For some reason,
the way the topography of our mountains are set up,
we're somewhat shielded from the Santana winds
as far as the actual speed of the wind, but we're ready.
We do during the winter do experience winds
over 70 miles per hour, but generally,
you know, we're getting, you know,
tend to inches to 24 inches of snow,
or back on through the fortunes of 2019,
we had over 10 inches of rain.
We just aren't having a wildfire that day.
And so while we are very versed in it
and we do keep this up,
we do believe that we can get our system hardened
where PSPS is really not a likely event in Bear Valley.
More likely that Southern California Edison
will take our power away.
And I didn't put a slide addressing that,
but I can tell you
that we talked to Southern California Edison
at the executive level,
the manager level, and the working level.
And we have a very good and close coordination with them.
We have access to their portal.
We have direct phone lines to their control centers.
I have direct communications with their account manager.
And last year during the potential events,
we were talking just about every four hours
and making sure that we were all on the same page.
And I think each year I see that coordination improving.
I was actually pretty happy
with the way they responded to us.
And I think we worked well together.
That is my top concern as far as the PSPS goes.
Could go to the next.
-: Paul, have you in your close communications with Edison,
have you all ever done any part of
or participated in their exercises?
-: No, but that's a great thing to do.
And we have not, we have to relate here within our staff.
The Edison gives us a call and says, we,
the following line is under consideration
and here's the period of concern
so that we all know their terminology.
And then what we would do,
we have actual switching procedures and so forth
so that when we get these warnings,
the challenge for us
is to get the power plant up and running.
In Bear Valley we have a small pecker.xx plant,
8.4 megawatts,
get that up and running before Edison were drops power to us
because then we would be in a black start scenario.
And if you ever in any utility, that's always a,
it's a huge challenge to start up a power plant
under black star conditions.
-: I do think it would be good to inquire
if you could please be included in their next exercise.
-: On the vegetation.
I mentioned that we back in March of 2018,
following the permissions issue
of a decision on increasing
some of the fire prevention measures in geo 95,
we implemented a new standards and we actually,
we trim out to 12 feet as is done at the time of trim.
But our decision to trimming now is at 72 inches, not 48.
So we go beyond the minimum required
and we do that because of our environment.
And we have seen a notable decrease
in vegetation contacts in lines.
It's early you could say law of small numbers if you want,
but I can tell you that when I first came here
and you hear the wind,
it, no, there'd be a little loud at somewhere.
We don't have that anymore.
This is really, and we have a very supportive community.
I would have thought
with the amount of trimming.xx we are doing
that we would have gotten pushback.
In fact, we actually get praise
from at these community meetings,
from folks that were out there with keeping the lines clear.
I think the general folks are appreciative of that.
A lot of trees we're keeping track of them
and we're putting them in our GIS over 13,000 trees,
we keep track of the species
and we were getting much more surgical
so that we can really get our management teams
on the areas of concern
before any threat weather approaches.
Go to the next.
An area, three resources new for us.
We do have it located at the main facility.
We do have a backup plan as well,
and I do wanna work on some other backup plans,
just so you understand,
I can drive from one end of my service area to the other
in about 20 to 22 minutes
and without violating any speed limits,
we are located right in the center of the service area.
And so we feel that's a great location,
but we want the ability obviously to move it to other areas
if we did.
And so that's what we we've tailored our system to do that,
or our coordination center.
We are improving our CRC.
We have all the standard stuff.
There was, I, you know, I read in the phase three
and it came up in one of the workshops
doing some indoor filtration for smoke.
And that does make sense to me.
And we'll try and get that in place last year
during I know it didn't reach our service area
we had the Eldorado fire,
which was impacting the air quality up in our area.
And it had the, in both the PSPS at the same time,
the Eldorado fire was going on.
It would've been nice to be able to offer an environment
where people can breathe
without being exposed to that kind of atmosphere.
And so we are looking at that
and we did set it up to verify that
we could actually set it up and we had people there
and people know what to do.
I personally liked to play a customer
and go in and test it out
and sometimes be a difficult customer,
but it makes our customer service folks
a lot more responsive.
Go to the next.
I think this is the final one.
We do have a lot of feedback.
We get feedback from our surveys.
It's all stuff that makes sense.
And so we are constantly looking at those surveys
and trying to understand
how we can best serve our communities.
We have a very, one of the biggest challenges we have,
like I said, the door to door services sometimes needed.
We have an elderly community that are not tech savvy.
And then we have a lot of tech savvy people on it.
You know, we have to cater to both.
And we still have people with, rely on land (indistinct)
and then we have others who don't even know what a mine is.
And so even in the small service area, it's challenging,
but we have to continually improve
to make sure we can reach out and talk to all our customers.
And also, and the other thing is, as I mentioned earlier,
we're in this LA media market.
And so we have to educate them about Southern California,
Edison PSPS and their valley PSPS and the differences
and whether or not they wouldn't be impacted.
And every time Edison,
they may be calling away a PSPS in Ventura County.
Well, it's on the local news that we're watching
and I guarantee you, we get phone calls about that.
And so we try to take a leading on those things
and get out in front and make sure our customers
understand what they need to be ready for and when.
Go to the next.
Questions point.
-: Thank you, Mr. Marconi for getting to do your presentation
and helping us with my poor management of time this morning.
So I appreciate that very much.
I will turn now to the virtual dais and ask
if any of my colleagues have any further questions
and those that they have already asked.
I see the chief shaking his head,
and I do want to mention Mark Ghilarducci
did have to depart,
but there are people from OES who are listening in.
So I don't want you to think that they left
in the middle of your presentation.
So any questions?
Yes. Commissioner Houk.
-: I don't have any questions
but I know we're running on time.
I just did wanna note that I appreciated
all of the presentations and I learned a lot today.
So thank you to all of the utilities.
-: Indeed.
Any other questions of Bear Valley?
Okay. Not seeing any or hearing any.
So with that, Mr. Marconi, I want to thank you again
for your presentation.
And I want to thank the representatives from Pacific Corp
for theirs as well as Liberty.
And I would ask if you all are still online with us,
I hope that you are.
Please stay if you can please
and listen to the public comment.
Very important for all of us.
Okay. With that, we will now turn
to the public comment portion of our agenda.
As a reminder, if you wish to make a public comment,
please dial 1-800-857-1917
and enter a pass pass code 7218384#, press star one.
You will be placed into a queue
and the operator will take your name and organization.
There may be a delay from the time you press star one
to the time the operator asks for your information.
So please be patient and stay on the line.
We will provide you two minutes, two minutes to speak.
You will hear a bell sound when your time is up.
So please be mindful of that.
Operator, please bring on the first commenter.
Operator: Thank you.
We have no one in the public comment telephone line
at this time.
But again, if you wish to speak
during the public comment period,
please press star one unmute your phone
and clearly record your name and organization when prompted.
Again, there's star one to make a public comment.
Batjer: So we'll wait a few minutes because we are late
and I'm sure some people had to drop off.
Maybe they'll sign back in.
Operator: And as a reminder,
if you would like to make a public comment,
please press star one unmute your phone
and record your first and last name when prompted.
Batjer: Okay. Operator as anybody joined us?
Operator: In President Batjer,
there are no participants
on a public comment, telephone line.
Batjer: Okay. Thanks (mumbles).
With no more callers on the line or no caller on the line.
The public comment period is now closed.
I do once again, wanna thank you for joining us today
for a really informative briefing and discussion.
I'm sorry that we kind of got lost in our time.
And there were lots of rich questions
being asked along the way
for which I think my fellow Commissioners
and my esteemed colleagues from Cal OES, Cal Fire
and OES for your participation, not only today,
but the last two days.
And I also want to thank our wonderful team
here at the CPEC, Rachel Peterson, Tony Knowles,
Drew Dutton, Shelby Chaste, Cindy Kin, and Briana Mendoza,
in our safety enforcement vision for all of their hard work
in organizing these briefings.
It isn't easy and it takes a lot of coordination and effort.
And I really thank them all.
I want to also thank my own advisor, Nora Hopkins,
for all of her hard work in preparing me
and the rest of the Batjer team for these three days.
So thank you so much.
And thank you today for your participation to the public.
And thank you again to the companies
for their presentations.
This meeting is now adjourned.
Thank you.