Andy: Lucy Morgans.
Thank you, ma'am, you may begin?
Lucy: Thanks very much.
Good morning, everyone.
On behalf of Caroline Thomas Jacobs,
Director of the Wildfire Safety Division,
thank you for joining us today for our technical workshops
on the 2021 Wildfire Mitigation Plan updates.
My name is Lucy Morgans and I'm the acting program manager
in the mitigation branch, which has it's a team of experts
and to taking a review of the utility 2021
Wildfire Mitigation Plan Update.
Our team, along with the team from Cal Fire, is responsible
for evaluating the 2021 Wildfire Mitigation Plan updates
and support for final decision of approval
or denial of each wildfire mitigation plan.
The goal of today's workshop is
to allow PacifiCorp, Bear Valley Electrical Service,
Liberty Utilities, Horizon West, and Trans Bay Cable
to present and explain their 2021 WMP Plan Update focusing
on specific areas and allowing stakeholders
in general public to ask questions of the utility.
As opposed to last year, where we had each utility present
their plans, this year in an effort
to streamline our process and emancipation
of the challenges of conducting a workshop
in a remote environment, we thought
to have the utilities hone in their presentations
on three key areas.
These are risk assessment mapping
and resource allocation methodology
with design and system hardening,
including inspections and mitigation choices,
and lastly, vegetation management,
includes an inspection, strategy, and pilot.
So a quick notes about, say the review
of the Wildfire Mitigation Plans pursuant
to Assembly Bill 1054 happens
outside the formal Commission proceeding.
However, the Commission will take actions
to ratify not the Wildfire Safety Divisions actions
on the Wildfire Mitigation Plans.
Please be informed of all communication practices involved
in discussion with Commissioners or other decision-makers.
Before we discuss the agenda for today,
I wanted to take a moment to go over a brief safety message.
So if we could just have slide one, please.
Right.
In these virtual times, we are all in different locations.
Please be aware of your surroundings
and have two evacuation routes out from your location.
If you're alone and you feel comfortable doing so,
please make sure someone is aware of your location
in the events of an emergency.
These workshops are all day and require us
to sit in front of a computer.
We have built in breaks,
but please be sure to move around throughout the day.
We also recognize the challenge of living the lives
we are living, please, be sure to do what is needed
to take care of your mental health as well,
including taking breaks as needed.
Please practice public health guidance regarding COVID-19
if you were around the people.
And finally, if you feel something, say something,
if you need immediate assistance
in addition to someone knowing your location,
you're welcome to say so in the chat function.
We will be monitoring the chat function throughout the day.
So moving on to slide two
I'll take a moment to go over the schedule for today.
The general cadence of the workshop is
to allow periods of time for each utility to present
on the design and to present on the designated topic,
then take a break, and then answering
to a question and answer session.
First step today is risk assessment, mapping,
and resource allocation methodology.
After a break, we will begin our Q&A session on that topic.
Next will be lunch, followed by utility presentations
on vegetation management.
We will then take another break
and then into our Q&A on that topic.
We will end the day with a brief wrap-up and next steps.
Just moving on to the third slide.
In framing our discussion over the next two days,
sorry, in framing our discussion today,
the Wildfire Safety Division asks you
to focus on each of the four questions listed below.
So firstly, what progress have you achieved
over the past year and how does
that progress impact anticipated work in 2021 and 2022?
How do you understand your best and
how does risk factor into decision-making?
Here we want to emphasize that each
of the mitigation initiatives should be prioritized
based on their reduction of wildfire ignition
and the energization event.
It's imperative that the utilities moved towards a model
where mitigation activities are justified
and risk reduction can be modeled and quantified.
Thirdly, what's your priority mitigation activities
in the next year
and where are these activities being targeted?
Is this based on risk modeling?
What is the anticipated reduction in risk
as a result of these actions?
And this last question, sentence around PSPS
or the energization events.
So how will initiatives reduce the risk of ignition,
wildfire spread, and impact to the decision to use PSPS?
This last question is embedded
in the previous three questions
and is not discussed as a separate item here.
Before I hand it over to our moderator
to the first portion of the workshop,
I'll go over a few meeting logistics.
So just switched to the next slide.
Thanks.
So most participants are in listen only mode.
That means you cannot speak, but you are still welcome
to interact and ask questions using the chat feature.
Do you do not use the Q&A feature.
The chat and the Q&A tools are
in the lower right-hand corner of the WebEx screen.
Again, only use the chat feature
to ask technical questions.
It designated WebEx host is a technical resource
and is not a member of the Wildfire Safety Division.
Please only direct the chat message
to the host to resolve the technical issue.
If you wish to ask questions,
please select all panelists in the chat function.
And one from the Wildfire Safety Division
will be monitoring posts.
Again, please don't use the Q&A feature.
We will not be monitoring that.
We will route questions as appropriate to panelists.
Finally, we have asked several stakeholder organizations
to serve as panelists.
They will be given an opportunity
to ask questions directly to the utility.
You can just click to the next slide.
As an example, in the Q&A during the risk assessment
and mapping section, stakeholders designates
that panelists may use the raise hand function
in order to ask questions.
The moderator will coordinate those questions.
Everyone else, please use the chat function
as described earlier.
Depending on the number of questions received,
we may not be able to cover all of them,
but we'll do our best, right?
And with that, I'll hand it over to Alan Wu
to moderate our third portion of today's workshop.
Alan.
-: Hi, thank you for the introduction, Lucy.
Hi, everyone.
Good morning.
My name is Alan Wu, and I'm a wildfire safety analyst
with the mitigation branch of the Wildfire Safety Division.
I'll be your moderator for the upcoming session.
Wildfires continue to be a big threat to the environmental,
social, and economical well-being
for the State of California and wildfire risks
or wildfire risk models will play an important part
of the battle by being the thread
that holds the WMP together.
Risk models should show the utilities
where their risks lie now, where the risks will be
in the future, and also act as a guiding compass
to pinpoint where resources should be distributed.
For the next 45 minutes, we will focus on risk assessment,
mapping, and resource allocation methodology.
The three SMJU utility companies will describe
their risk modeling efforts, but more specifically
how the models have progressed since the 2020 WMP
and how the utility company incorporates risk models
with decision-making.
We will present in the order
of PacifiCorp Liberty and Bear Valley.
Members of the panel, please reserve all questions
for the Q&A session and members of the audience feel free
to submit questions via chat throughout the presentation
and Coco Tumasyan, our chat moderator,
will read them during the Q&A session.
All right, PacifiCorp, we'll start with you.
Thank you.
-: Good morning.
This is Heidi Caswell.
I don't know if you're going to bring up the slide deck.
Can we bring up the slide deck?
-: Yeah.
What's the name of it?
-: PacifiCorp.
It's the one with risk at the end of the title.
Thank you.
So good morning.
My name is Heidi Caswell.
I'm the Director of T&D Asset Performance
and Wildfire Mitigation at PacifiCorp.
And I'd like to discuss
how we have moved forward with our risk assessment process.
I'll try to tie it to the specifics
around the risk mapping activity
as well as locational identification of risks,
as well as then tying it to the specific initiative
that reduce that risk.
There's some kind of feedback going on with my phone.
So I don't-- -: That was me.
I'm going on mute.
I apologize.
-: Thank you.
So next slide.
So PacifiCorp has made substantial progress
in our risk assessment methodology
as pointed out in our 2020 feedback,
the feedback received from 2020 WMP.
We were fairly focused on the use
of the high fire threat district and the various tiers
and we're inspired to really advance
how we looked at locational risk, like many peer utilities,
especially those that discuss their processes
through the large three investor owned utilities.
We've been using a lot of data science, machine learning,
and other kind of more advanced techniques
to try and model the risk
with data sets that we have,
incorporate datasets that previously we haven't incorporated
and then try to extend that into kind of the what if
to be able to then serve against
as an input to selecting mitigation initiatives
and prioritizing around those.
Again, previously, we were applying the designation
of the high fire threat district
as a indicator of should this circuit
or these customer served by the circuit be part of elevated
and more highly prioritized activities or not.
And with this update, we've made some substantial strides
to advance beyond that.
We also previously looked at seasonal impact
of ignition probability
and had less focus on risk event drivers.
In other words, we looked at unplanned outages
of very similar risks and with this update have tried
to really align more specifically against specific types
of risk events and understand the why, the when,
the how, the where kind of aspect
to working against them.
As one of the large elements incorporated
into our risk assessment, we look at the vegetation canopy
as well at a zonal level and we quantify
what we call utility risk,
which is the result of those unplanned outages,
vegetation exposure, recorded history,
and then a probabilistic arc energy calculation.
In the future, we anticipate looking at elements
such as equipment types, some specific components
that may be more prone to that catastrophic failure mode,
as well as aspects around asset health
and getting better precision and granularity
about some of the other inputs like vegetation.
Next slide.
This graphic is trying to illustrate for you the concept
that's behind our risk assessment model,
which we've called the localized risk assessment model,
LRAM, in our WMT.
And you can see, I've tried to make sure
that you can link the different graphics back to the WMP
so that there's good reference.
Some of these are I-tests and I apologize for that.
This graphic is showing you
that what we take is the basic service territory maps,
so terrain and land basis behind it.
We overlay on top of that, our circuit topology,
we consider the historic fire
weather risk fire spread risks.
So that would be as expressed in the past development
of the HFTD, the integrated utility threat index.
We overlay our tree canopy risk modeling results
from arc energy calculations done through our sign modeling,
utility ignition fault risks,
so those are the unplanned outages, and utility fires
and equipment that comes from the fire database
and then fire weather risk,
which is a more contemporary view
around fire weather.
So the last four years at a more tightly gritted value.
So that forms for us both a long-term view and a recent view
with the topology and with the characteristics
and performance that have recently been experienced
within each of those circuits of segments.
And a zone of protection, that core that we're considering,
the modelable core, is from an isolation point
like a fuse or breaker recloser,
that kind of device to the next downstream.
So all of the conductor and the equipment elements that are
within that protective zone are considered when ZOP
for modeling purposes and that's how we are then quantifying
and calculating various aspects
along that segment.
Within the state, we have, if my memory serves right, 2,700
or so zones of protection, where we have 70 some circuits.
So just to help you understand the segmentation
that's going on.
The next graphic actually depicts the model results
as of our most recent model run and
this is for illustrative purposes,
it's really is a model output.
If you look at this graphic,
the combined fire risk is expressed by the width
and the intensity, the darkness of the blue.
So if you see certain areas
where there are very lightly revealed blue
and not very thick,
that would be the lower combined fire risk area
and the corollary to that is the areas that are thicker
and darker are the ones that are the higher fire risk.
And again, this is the combination
of what we call the utility risk blended
with the climate impact.
So it has that consideration of vegetation,
outage performance, arc energy,
and then the climatology in the area.
The next graphic
or next slide if you wouldn't mind.
I wanted to actually walk through the process
that we went through so that that map maybe starts
to make a little bit more sense of that model,
output makes a little more sense.
And it really is a five step process.
We look at our outage data and analyze it,
categorize it to look at that risk event driver.
We then look at risk events by the probability
and we also then look at fire records
against the risk event drivers.
Then the next step is to look at the initiatives
that target against specific risk event drivers
and then prioritize those mitigation efforts using a variety
of measures, including customers impacted combined risk,
utility risk, and so it's kind of
like a multi-dimensional view that happens at the very end.
So this first graphic shows you
how we map our outage cause code data
and some of the data mining that we have to do
within those records in order to align them
against the risk events and the drivers.
So we've got contact from object,
we've got equipment failure, we've got some unknown,
some human errors, all of those.
And we basically repurpose what would be traditional
categorization of our outage causes
in order to align against the risk events
that are relative to fire risks.
And the next slide, we then look at
on the number two shows you
where we analyze it by cause category.
And you can see that 42% of the risk events during the 2015
through 2020 fire season time period are the result
of equipment failure, and 22%
of the total is associated with contact from object.
It's important for me to note that sometimes
in equipment failure, it's actually a contact
from an object that causes an equipment failure
like a tree branch breaks something.
And so we attempt to separate that,
but recognize there can be a little bit of fuzziness
within that big blue wedge of the pie.
In the pie chart that's designated number three,
we take the fire utility fire database
and go backwards with that and see that 47% of the fires,
and it is a sparse dataset, but 40% of the fires
that we've record of are associated with equipment failure
while 41% of them are associated with contact from objects.
So those two continue to kind of stand out as the areas
to be responsive to and while not part of our WMP,
we were asked to actually score the risk events.
And so that's actually on the right side we identify
during fire season and non-fire season the high,
medium high, medium, medium low, and low values
for each of those risk event drivers
versus the fire risk expectations.
On the next slide, we try to align again,
back against the risk event driver,
the different mitigations that are part
of our thought process when we're looking at them.
And this is actually in the WMT, it shows up
as three separate tables just to make it readable
in the documents and the first series are focused
around the arc energy conductor damage,
and then the equipment failure piece,
and then the asset hardening piece,
and, sorry, equipment failure and vegetation management.
So what you can see is that hopefully,
if there's an X in the box, it indicates
that that mitigation measure can be effective
against that risk event driver.
So when you would look at, as an example,
the animal contact has several ways
that animal contact can be mitigated against.
It can be improved by coordinating protective equipment
by additional protective equipment,
by a variety of hardening activities
that are over on the right side of the table and such.
But that's really to try and identify for individuals
that we don't have a one size fits all solution
for how you might mitigate
and it really is very targeted against the specific.
So there's, as you can see here, animal guarding,
spreading the construction,
enhancing the installation,
covering conductor, all of those are possible
for animals contact, which again is contact from object
under the risk event driver.
So that's how we look at the initiative
in order to understand what kind
of solutions might resolve that specific driver.
On the next slide,
the focus here is on prioritization.
So once we understand that there is a risk
and what the elements of risk are,
so when we see the zone of protection,
we can understand is it a vegetation contact issue,
is it history around a specific type of outages,
what is the probability of any kind of arc energy issue
if a fault event were to occur?
We then are given the ability to see the zones
of protection within each of the circuits.
And in that case, in the upper left chart, which is shown
on page 75 in our WMP the figure 45-14.
This actually shows you in kind of a histogram sort of view
against the combined score, which is the expression
of the combination of utility and climate risk,
each of the zones of protection performance
for every circuit.
So you can see that there are a couple of circuits
that have kind of some outliers zones of protection,
which then would mean that in order to improve fire risk
as well as possible, you would attack those specific ones.
You can also see that there are certain circuits
that have very similar characteristics for the zones
of protection, which then would suggest that
since they are at perhaps an elevated level,
all of that particular circuit is worthy of quick reaction
from the mitigation perspective.
The next chart to the right looks at the fire weather score.
So this is really the climatology and the combined score.
So that helps us understand those areas
where it's not the utility risk
that maybe is driving the situation,
it's actually the location.
So that helps us understand what about it is the where.
And you can see that we had circuits
that had projects that were prioritized and certain circuits
that previously had not yet been prioritized
for some of the mitigation measures,
which were revealed with this view of the data
as opposed to the expression of the HFTD and our PSPS plan.
So it gives us another way to validate
and modify the prioritization of our work
now that we see it in this, through this lens.
In the upper, right, we can use that view
to help us understand the combined score risk
across the bottom against the impact to customers.
And what I failed to note is that the size
of the bubble is the circuit length
or indicates the circuit length.
So a small bubble is a short circuit,
short in length circuit, whereas a larger bubble is one
that has more circuit mileage to be dealt with.
And so we can start to understand both the customer piece
as well as then by the big or little circles
how exhaustive our efforts would need
to be versus the risk that we would be buying down
essentially with the mitigation efforts.
So there were a variety of other ways that we also look
at kind of the alignment of our mitigation measures
against the sections of circuits
within our service territory.
And those are also expressed further in the section 4.5 0.1
in the WMP, but this was just to try
and help work you through that thought process.
And later on, we'll talk a little bit,
or other panelists will talk about how we apply this
to the asset mitigation and vegetation management activities
that are also important parts of delivering the WMP.
Alan: And Heidi, this is Alan,
we do have to be aware of the time.
So two minute warning here.
Heidi: I'm actually, if you go to the next slide,
I can say thank you and give you back two minutes.
Sorry, I just talk fast.
Alan: Thank you so much, Heidi.
And so next, we're going to have Liberty Utilities present.
Thank you.
Greg: All right, do a short introduction here.
My name's Greg Campbell, and I'm a senior analyst
in our regulatory affairs division, and I'm here to talk
about Liberty's risk assessment, mapping,
and resource allocation methodology.
Okay, next slide.
So our progress from the 2020 WMP toward 2021 WMP
of Liberty has made some significant strides
and coming into 2021 Liberty was the only utility
who had not filed a risk-based decision-making framework
as part of its GRC filing
and this includes how Liberty evaluates wildfire risks.
So our first generation wildfire risk models
were completed February 20 of 21.
So and this is adopted the same approach
as what the larger IOU used in their MAVF
in MARS risk assessment methodology.
And so we used this approach
and this approach replaced our old approach,
which mainly consisted of qualitative scoring
and using heat maps.
So these were some techniques
that the Commission expressed some preference
to move away from
and to incorporate more quantitative analysis
and that's what Liberty has done.
So the company we've established a risk mapping capabilities
through our partnership with Reax Engineering.
And what we've been able to do is combine that analysis
that we worked with Reax with tools like Hexagon
and Power BI to complete Liberty's analysis.
Okay, next slide.
So prior to Liberty having this risk mapping capability,
a lot of our decisions were made
on whether something was cyclical
or whether something was compliance-based.
And another feature of the strides that we've made is that
if you look in our maturity survey from the 2020 WMP,
a lot of our answers referred to our projections being able
to look at risk at the regional level.
And so what we've been able to do is the work
that we've made between 2020 and 2021,
we're now able to look at risk at the circuit level
and in many cases also at the segment or the span level.
So one of the other strives that Liberty made is
we've also upgraded our outage management system responder.
And what this is able to do now is
to produce a specific report
that's going to capture a lot of the data points
that the Commission has asked Liberty
to collect with respect to wildfire risk.
And again, even with some of the advancements
that Liberty's made from 2020 to 2021,
there still is a lot of work to be done.
Again, this is just our first crank of our models,
our first results of our models,
and we do plan to dedicate more resources
towards our risk-based decision making framework initiative.
Okay, next slide.
As we can see on this slide, in quarter one of 2020
in the six step risk-based decision-making framework
process, we were at the beginning
of the risk analysis stage.
So this involved us collecting data,
looking at certain data points whether it was coming
from our outage management system,
whether it was coming from our inspection reports,
we really hadn't organized anything to be set into models
and to be looked at and really analyze.
So now in quarter 2021, we've completed steps three
and four and we are now at the beginning of step five,
which now allows Liberty to look at some
of the model's outputs in the form of the risk
and inefficiencies and start to incorporate this
into discussions in terms of what capital investment
or operating and maintenance program decisions are going
to look like forward-looking.
Next slide.
Well, as I mentioned earlier,
as part of Liberty's risk mapping efforts,
Liberty Commissioned Reax Engineering
and they conducted a detailed wildfire risk analysis
over our entire service territory.
And as part of this analysis that Reax conducted,
they looked at a fire spread, they looked at the number
of structures that would be impacted in the form of houses
or in the form of businesses, they looked at
what the cost would be to suppress the fire.
And als the number of people or the populations impacted
for 33 distinct areas within the Liberty service territory.
Looking at these factors is very important because as we see
in some slides that we'll see coming up,
this will feed in directly as the data points
to model the consequences of the outcomes
that Liberty's used
in its risk-based decision-making framework bow-ties.
So we'll see a slide where we'll see the four outcomes
and how those consequence modeling fits into that.
Next slide.
So here we see a visual
and this is an example of the areas
for which Reax looked in our service territory
and how they've segmented it off here.
This is our South Lake Tahoe region
and you can see that there's four different colors
in this graphic right here.
So we have the red region
and this is going to represent very high wildfire risk.
We have the pink region,
this is going to represent high wildfire risk.
We look at the yellow region,
this is going to represent moderate wildfire risk.
And then if we look at this light blue region,
this is going to represent low wildfire risk.
And these green lines here,
these are our primary overhead distribution lines.
And a lot of these lines are going to criss-cross
into different segmented areas and these segment areas
all have different wildfire risk profiles.
So this will be important to keep in mind
in the following slide when I talk about how we look at
what the wildfire risk rating for individual circuits are.
And lastly, it's important to note here
that this dark red the region, if you look off
to the Eastern section of this dark red
very high wildfire risk region, this is currently
what our HFPD three region is.
So this very high wildfire risk rating that Reax has found
for this section in our service territory aligns
with our current HFTD three region.
Next slide.
So the next step, Liberty recombined
our outage management system data
along with our vegetation management inspections,
as well as our detailed system survey inspections
and looked at all of this data in those segmented areas
that Reax had looked at in terms of
what is wildfire risk scoring was.
So what we were able to do is integrate
all Liberty's internal data with the ratings
that Reax looked at
and in which they segmented our service territory.
So why this is important is that as I explained earlier,
a lot of our circuits will be located across two, three,
sometimes four different wildfire risk areas.
So some of our circuits could criss-cross
into the very high, the high, and the moderate.
And what Liberty was able to do is take all
of these different risks that you see on the slide,
our vegetation risk, our performance risk,
and our asset condition risk.
Look at each of those segments on the circuit
and then roll that off into an overall wildfire risk rating
for that circuit, looking at each of the different segments
on that particular circuit.
So in the WMP when we had to score
and rank each of those circuits,
that's the methodology that Liberty has used.
We looked at the span risk on a particular circuit
and then rolled that up to the circuit level.
Okay, next slide.
Well, as I mentioned earlier,
Liberty adopted the same MAVF MARS approach
that the larger IOU have used
in their risk-based decision making framework.
And here is a bow-tie and this should look pretty familiar
to everybody, where you have your wildfire risk drivers
off the left-hand side, you have the actual risk event,
in this case, it's a utility cause wildfire
if you're not in the bow-tie.
And then off to the right, you have your outcomes.
And in this case, Liberty worked with Reax
to come up with four distinct outcomes and each
of these outcomes has three consequences attached to them.
So those consequences were safety consequences,
financial consequences, and reliability consequences.
And this should all be pretty familiar with anyone
who's worked closely with the S-MAP and RAMP proceedings.
So what we looked at was
when we looked at those risk factors,
when I mentioned the structures impacted the numbers
of population affected, all of this was modeled
in these consequences of the four outcomes
that you see on this slide right here.
So the technique was the same that we've seen
with the larger areas and that's the methodology
that Liberty adopted to calculate its RSEs.
And Liberty's RSEs with some of its scores
for its first-generation wildfire models along with each
of those individual circuit risk ratings can be found
in attachment C in the 2021 WFP.
All right, and that should conclude our discussion.
So thank you.
-: Great.
Thank you, Greg, for that presentation.
Next up, we're going to have Bear Valley Utilities
and we're going to have Paul present.
Thank you.
-: Yeah, good morning.
If you could put my brief up.
Okay.
One second.
So a brief introduction.
I'm Paul Marconi.
I'm the President Bear Valley Electric Service Incorporated
and I'll actually be the analyst
for all three presentations.
Can you go to the next slide?
Before I get into the risk assessment, just a brief,
if you've had a chance to go through our plan,
some of the key areas of our planet aims
to tailor our actions to our community.
It's a small area, 32 square miles.
It's up in the mountains.
As you can see from the pictures, lots of trees,
the trees get snow laid in, so they get weak,
and then when the winds pick up in September,
there's a potential for branches to come off
and make contact with lines.
So and because we're in a generally a dry environment
during that time of the year,
we're in the high fire threat district.
For those, with eagle eyes that people
on the chairlift, that's pre pandemic, okay?
Substantially, we mitigate the risk of wildfire,
that's what our planning to do.
There's emergency response for restoration
in wildfire events and so forth.
One of the big things that I take away from,
I think this is my third technical workshop after filing
our plan, is the incorporate industry best practices.
We always were in quite a bit from each other's plans
as we look at them as well.
Can you go onto the next slide, please?
So on the risk assessment, mapping,
and resource allocation methodology,
Bear Valley follows the small multi-jurisdictional utilities
process that was provided
in a CPC decisions back in April of 2019.
You can go to the next slide.
This is basically a seven by seven matrix,
frequency versus consequence
or likelihood versus consequence logarithmic.
Has the six step process similar to what Liberty discussed.
And you look at their various risks, you look at mitigations
and the output is a risk spend ratio and risk reduction.
This chart sort of demonstrates what comes out of that.
So on the X axis are all the mitigations
and there we have alternatives too.
So you'll have installing covered wire,
you'll have undergrounding, and then you can make a choice
on which provides the best risk spend ratio.
As you know, we've had this model
in place since 2017, actually, and
the X axis is just seems to grow
because we add mitigation and look at alternatives.
So it gets a little complicated, but it does give
us a good sense of how much risk do you reduce
for the cost.
You can go to the next slide.
Okay, so that method
that I discussed is a little less satisfying
because it doesn't have that bow-tie,
it doesn't show
how different mitigations interact with each other.
And so that's probably the least satisfying part
of that model.
And so as an interim measure, we developed
what we call the fire safety matrix, circuit matrix.
And basically you're not expected
to actually read the lines in that spreadsheet.
That's just showing you the model,
but what the model does is it lists for each circuit,
it takes into account what are those things
that make a circuit high-risk for wildfires?
And then what are those things that would mitigate the risk?
And so those are those colored boxes off to the right.
And then finally, and this is tracked in the matrix,
but you don't get a score for these items.
It's one of those things
that lessen the impact of a wildfire, okay?
For example, evacuation route hardening.
It doesn't reduce the risk
of the utility causing a wildfire, seeing any points for it,
but it's important to the community.
So we wanna track it here.
And this is the model where we tracked it and so,
we incorporate some of these items
that are important to just wildfires in general.
So the way we apply this model is we take the output
from the previous model, the risk spend ratios,
and we decide, okay, if we want to apply this mitigation,
which circuits should we apply to this mitigation to?
And so that's where this allows us
to get that granularity down to the circuit level.
And we would like, in the future,
we wanna look to get even more granular,
but we also tamper that with the fact that, like I said,
we're 32 square miles, so circuits really aren't that long.
And in general, many circuits,
you're as granular as you're gonna get.
But we wanna take a look at that
as we develop our processes.
You can go to the next one.
So one of the things I really like about this model is
when we decide to do different mitigations,
we can then fast forward and plug them in the model and say,
okay, if we apply that mitigation,
what will the risk value of that circuit be?
And if we look at our plan holistically
and step through it at the three-year point,
what's our system gonna look like?
And then at the ten year point,
what are we gonna look like?
And you can see how there's that progression.
You can also win, which is really neat,
is you can play with the mitigation
and we say, well, if I only, if I install covered wire
but I only need to install a certain amount
on this particular circuit
I already get it down to the green.
So those are ways that we can prioritize
or get circuits down to medium or moderate risk
and then focus on getting those other reds down to moderate
and then go onto the green.
So those are some items that the model allows us to do,
allows the decision-makers determine
where we're gonna put our resources.
Point to note, what the algorithm does,
it's really heavily weighted towards bare wire,
overhead bare wire.
Okay, so one of the things that we also did
in the model,
we rely a lot on subject matter experts, right?
So in the early days, subject matter expert we would say,
hey, that's an area of high winds and
heavy vegetation density.
Now, we've quantified those things.
For example, with the weather stations dispersed
throughout our service area, we can say,
okay, we know what the winds are
at different points on our circuits.
And so, and we have history now,
so we can say if the winds are less,
if the highest wind are less than 20 miles per hour
on dry days,
then the wind intensity is low.
And we can quantify these so that we're no longer relying
on an SME to tell us, that's a windy area.
And before this effort,
you need to understand the only weather station
in Big Bear Lake was at the airport.
Now, we have a bunch throughout the service area,
So we get very granular.
The other thing is also in vegetation,
same thing with the advent of putting
all the trees in our GIS,
we're able to quantify the vegetation density.
So for example, if on average a span has less than 10 trees,
that might be classified as low
and I'm just picking some arbitrary numbers here,
10 to 20 trees would be medium
and then more than 20 trees, it's high density.
So those are ways that we get around
not relying so much on someone's judgment in particular,
but being quantified across the Board
and providing some reasonableness to our assessments.
So onto the next one.
So we're a small utility and one of the important pieces
in resource allocation staff.
And we did a lot of things recently,
one, we rewrote a lot of the job descriptions for people,
even for people who are there to really emphasize their role
in the wildfire mitigation plans.
I believe in section one, we identify who's who
and what they do in this wildfire mitigation plan.
So we wanna make sure that works with their job description
'cause personal accountability
to me is absolutely essential
in addition to the risk assessments and so forth.
It's also that personnel side,
making sure there's true accountability
by the individuals involved in the plan.
In our job drivers get from roles,
we have a utility engineer
and wildfire mitigation supervisor,
that just used to be the engineering supervisor.
Now, very specific role in wildfire mitigation,
we added a wildfire mitigation
and reliability engineer who runs all these programs
and gets the data.
We brought on a dedicated project coordinator 'cause
like any utility you have two functions going
on at the same time,
you have execution and you have planning.
And in the past,
Bear Valley Electric was doing both
with the same group of people.
And we found that we really had to break that piece up
and then we've contracted a forester
to provide us a third-party support in our vegetation
and risk assessments in that area.
And then the other area that is really bringing our GIS
and data management up to speed 'cause the data really
and really drives our decisions
and shows us the results of where we're making difference,
where we're maybe not making a difference,
and where we ought to be heading.
So it's really important we allocate resources to that piece
and that's where we're moving.
So the big thing that we're our next step is to transition
to admission, calculating admission probabilities
at different points, and also bringing on transitioning
to a bow-tie style of risk assessment model.
And our goal is to have that in operation
sometime mid 2022, we'll be kicking off
pretty soon a project to take us to that next level
in the risk assessment modeling
and bring us on to that granularity
of different ignition points in our service area.
And that's it for this session for me.
-: Great, thank you for the presentation, Paul.
And now, we're going to enter into a short break.
We are all going to come back with the question
and answer segments of today's workshop
for our risk assessment mapping and resource allocation.
So we will all meet back here at 10:40
and members of the audiences this a great time
to submit your questions via chat.
So yeah, everyone, let's take a short break
and we'll all be back at 10:40.
Thank you.
We're in session.
So one thing I wanted to note here is we're going
to ask questions in order of the different parties.
So we have WSB here represented by me,
and then we also have the Green Power Institute.
We also have the Public Advocate's Office
and we also have Mr. Abrams,
and then we'll also have Coco Tumasyan
to read out the chat questions.
So at this point here let's have
all these stakeholder parties use the raise hand feature
in the in the WebEx, and we won't leave the hand raised.
And then what I'll do is I'll start the cycles through
and ask all the questions.
And for all the panelists, when asking questions,
let's ask one question at a time.
Totally fine if the question has multi parts,
but we will go with water.
And what we'll do here is if a question is addressed
to all three utilities, we'll have the utilities answer
in the order of PacifiCorp, Liberty, and then Bear Valley
just like how we went through the presentations.
So great, the first question here is going to be from WSD.
And this is the question for all utilities.
Please describe at a high level
the mitigation initiative selection process
and pinpoint where the outputs from the risk models.
And this could be RSEs, this could be identification
of high risk segments and more are used
in the decision-making process.
-: So this is Heidi Caswell from PacifiCorp,
and hopefully some of the graphics that were
in presentation help make it a little bit tied
to the question well.
So we use again that combined fire risk,
which is the model output of the climate
and fire climatology history
to help identify areas that
due to their location
and environmental conditions, et cetera, are
where a utility ignition could result
in fire spread.
So then on top of that,
we lay that the utility ignition piece
and the output is signaling to us at that zonal level
what the absolute value is for that particular circuit zone.
With that, we then look to see what the drivers
for that specific risk are.
So is it something to do
with how the arc energy manifests itself,
what the vegetation history is,
what the historic outages might be,
and all of those help us then understand
what particular symptom that segment experiences
then to the mapping that was identified
where we outline what the cause history is
that helps us get into an understanding of
what kind of events
that particular area would be susceptible to.
And then we look to see whether fault response,
inspection and maintenance programs, vegetation management,
or asset hardening would be the best way to mitigate
for that particular risk event driver.
And with that, then we start to look
at how much any one of those measures
potentially buys down our risk.
One of the areas that we have worked to do is quantifying
that risk spend efficiency, that is kind of the next target
that we're striving for is
some of the incorporating the effectiveness measures
to identify how much that risk is improved
at a quantitative level instead of the qualitative level
that we've used in the past.
But that's generally the approach that we've been taking
and then in terms of its impact, the probability
and the impact of the event,
it helps identify them the prioritization
for that particular zone being advanced further.
-: Great, thank you, Heidi, and next up we have Liberty.
-: All right, yes, so Liberty the approach
that we use is looking at those RSEs
and as part of those RSE calculations,
there are a lot of factors that go into that.
So during the presentation,
I mentioned that we do look in many cases
at the segments span level of our particular circuits.
And at that particular segment in span level,
there were three different risks that we looked at
in addition to the factors that react scored
for us at that particular segment or span.
But those three risks were vegetation risk,
our asset condition risk, and our performance risk.
And that was in the form of what was the type of driver
that caused a forced outage.
So a lot of the factors we saw in the WMP are like,
if an animal chews our circuit
or if a tree branch cuts our wire,
anything that we can attach to a risk driver.
What we try to do is look
at our outage management system output,
trace that to the location and record those details.
So next, when we looked at particular mitigations
that addressed certain risk drivers,
we can look at the statistics in terms of the number
of forced outages by type and also the number
of those force outages.
And we can look at if these mitigations reduce
these risk drivers from occurring,
and if they, then that that is what factors
into our RSE calculations.
So that is the main basis.
We recently just completed our modeling to reach those RSEs.
And again, this is in the same form as the MAVS
in the MARS methodology
that the larger IOUs have completed previously.
So we really haven't had much time
to incorporate the RSE values into our decision-making
in terms of wildfire risk,
but certainly what we've already started to discuss
in terms of how we will be factoring that in.
And then of course, there are other factors
that you look at in addition to RSE.
So this also has to do with timing, costs,
resource constraints, for example,
a lot of times permitting is an issue of doing a lot
of work in the Tahoe area.
So there are other considerations that we do take
into consideration when selecting a particular mitigation,
but now, that we do have the tool to produce those RFEs,
we're going to incorporate
that into our forward-looking capital investment
in operating and maintenance decision-making
-: Great, thank you for that answer, Greg.
And lastly, Bear Valley.
-: Yeah, I'll be brief here
and what I'll do is walk you through an example.
We were looking at an evacuation hardening
and there are a number of alternatives,
obviously, you could underground,
you could put a fire resistant composite,
lightweight steel poles, replace the wood poles,
or you can also install what's called a wire mesh wraps
that wraps around the base of the pole
and goes up a certain height.
And those are all good alternatives.
Probably, the least satisfying is a wire mesh,
but it does do the job, okay.
At $950 a pole that's RSE goes up quite high.
Whereas when compared to replacing the pole
or even undergrounding,
those are much more expensive options.
And so get an immediate grip on the problem and solve it.
We have over 800 poles on our evacuation routes,
output drove us to, hey, let's get the wrap on the poles
in the next two years
and then implement a policy that whenever we replace a pole
for whatever reason, we'll replace it with lightweight steel
or fire resistant composite pole.
And so you can get that balance achieved
for the risk reduction in a very efficient
and cost effective manner.
And then in the long run, as you replace poles
for other reasons or development and so forth
you can use that RFC to drive your policy in the future.
-: Great, thank you for that, Paul.
And then next let's go the panelist
for Green Power Institute.
Zoe: Great, so Zoe Harrold
with the Green Power Institute,
thank you for all of these presentations.
My question is related to essentially dataset size,
so compared to the IOUs,
the SMG used have much smaller risks event outage
and ignition dataset, and this can really make
essentially the predictive modeling approach very difficult.
So I was hoping you could each talk a bit about
how you actually overcame this modeling limitation.
Thank you.
-: So this is Heidi Caswell from PacifiCorp
and great observation.
We actually ran into this issue
as a fairly substantial one when you try to create
some kind of risk event to ignition relationship.
And that is actually the reason that we didn't try
to do anything mathematically in those two pie charts
other than to draw the correlations about the observation
and not not try to turn it into a number of essentially.
The hope that we have over the next
kind of model development is to try to extend our reach
in terms of application of the ignition probability
for specific fire risks or for risk events
so that we become more quantitative with that.
And that might be by reaching out
to the large IOUs to determine whether there's
any kind of extensible data that exists
within their datasets that we could kind of attempt
to leverage or by continuing to just work
with a smaller data set that we have extended into other,
we have other service territory apart.
So perhaps there's some opportunity
for outside of California informing
some of the relationships.
Hopefully that's helpful.
Zoe: Very helpful, thank you.
And then Liberty and Bear Valley.
-: Yeah, that was an excellent question.
I'm glad you asked that.
So that is absolutely a challenge for Liberty,
perhaps applying most of the Liberty
because we are such a new utility in this space.
So one example, that challenge that it did present to us
in addition to the lack
of real depth of history of our datasets
that we did try to use a neural network approach
that the larger IOUs and I believe also a Heidi mentioned
that PacifiCorp was using, the problem that we ran
into is once we were utilizing that approach,
we found that we really didn't have enough history
of data points to make it that reliable compared
to using a more standard approach,
which would basically be weighting each outage type
equally in the prediction of a wildfire risk event.
So in a neural network, there's a lot of feedback
in terms of if this occurs then in a lot of information is
basically looped for each observation.
But unfortunately, we weren't able to look
at those results as reliable as a standard approach.
So we did go with a standard approach
to come up with our RFEs.
In terms of looking outside of our own datasets,
that's something that we are definitely exploring.
So we've talked with Bear Valley
about doing that too last summer,
how are ways that we can help help each other?
I think we're still in the discussion phase
of just what that looks like,
but it's definitely on our radar,
and it's something that Liberty it looks forward to doing.
-: Yeah, it's a great question.
It reminds me of my statistic professor,
figures lie and liars figure statement.
So you do have to look at what you're doing in statistics,
you can quantify the amount of error, right?
Based on the amount of data you have.
So when you do look at the numbers, see you do look at them
with eyes wide open and caution that.
We have the benefit, however small
of having a database that goes back now about 20 years.
So we look back further in the past
to sorta glean and increase our database.
The other thing I would just say that, you know
as much as a heavy list that is at least
for small utilities to be these quarterly data reports
and so forth, they do give us a glimpse at what all the data
from other utilities and so those pay off
and increasing our ability to assess
and look at a broader picture.
And then once again,
collaborating between the utilities would be beneficial
in resolving that issue.
Zoe: Great, thanks, everyone.
-: All right, thank you for that question, Zoe.
Next, let's move on to the Public Advocate's Office.
-: Okay, this is Henry Burton, can you hear me okay?
-: Yep.
-: Okay, great, so I'll start with PacifiCorp.
A question for PacifiCorp,
you mentioned using a Cal-Adapt tool to
estimate or model climate change trends over time,
can you elaborate a bit on that
and how you used it for your risk analysis?
-: Yeah, so in the model, there was the expression
or the the demonstration, I think of the different layers
that are incorporated
as additional inputs for the calculation process.
And with the Cal-Adapt data what we did was looked at,
I think, four different scenarios
for the climate change out to 2030 at this point.
And basically, we're looking to see the variation
that occurs for the contemporary climate aspect of the model
with regard to the fire weather indices and the dryness.
So it was specifically focused on what would we expect
at the zonal level that we've been talking about
with the change in local dryness
during the extreme periods of the year,
and then at the same time,
how are the models suggesting
that fire weather indices would change?
And so those are around temperature extremes
and wind extremes as well, so gas specifically.
And with that, we then were able to identify the zones
that had the most substantial impact
as far as the ramping up their combined fires
or combined scores.
So that was the output, there's actually,
it's a little tough to tell the specific
because it's really best viewed in the model way,
but there's a graphic that demonstrates
that distribution of climate variation as a function of time
at the zonal level in our fire risk assessments
or in the risk modeling in 4.5.1 in our WMP.
And we anticipate refreshing
that as Cal-Adapters future climate change models
are produced and we have begun some conversation,
I think it's mentioned in the document as well with the
climate work stream that's part of the Pyrogens project.
-: Great, and for the other two utilities,
did you use Cal-Adapt or a similar tool
for the same purpose?
-: Henry, could you repeat that question one more time?
I think I just want to make sure
I can answer it fully, yeah
-: Sure, so the question was, did you use the Cal-Adapt tool
to understand climate trends over the coming decade
or two and or do you use a similar tool
and could you describe a little bit how you looked
at kind of trends?
-: Sure, that's a good question, thanks Henry.
So as part of looking at our climate trends
and anything that would be related to climate change
and how it does affect our wildfire risks,
that would be part of the Reax analysis that we use.
So whatever trends that they identified
or whatever input variables are related to climate change
that was part of their fire propagation models
that we incorporated into our analysis
that's where that would be captured.
-: Yeah, for Bear Valley,
I don't think we use the Cal-Adapt,
but we did look at climate change studies.
Our area is very small, so it's almost a pixel
in the picture, but what we did look at, for example,
right now, due to the winds during dry periods are
typically pretty historically are not high for us to a point
where we would act initiate PSPS.
But we did look at, hey, if we did nothing
to harden some of our systems,
and you look at the climate change occurring,
we would in the future be in PSPS scenarios,
and therefore taking a lead angle on this problem,
we did use that kind of information as we planned mitigation
and so forth looking towards the future.
-: Okay, thank you.
-: All right, thank you, Henry, for the question.
Next, we're gonna move on to Mr. Abrams.
Participant: And Mr. Abrams,
can you be sure to unmute your phone?
Let's give it a few more seconds here.
If not, we can move on to the chat questions if we have any
and then we can circle back to Mr. Abrams.
Coco: Hey, Alan, this is Coco while we're waiting
for Mr. Abrams audio just wanted to let you know
we have not received any questions yet
in the chat so you can circle back.
-: Great, thank you so much, Coco.
Well, let's go into the next question for WSD
and Mr. Abrams when you're able to get the audio working,
go ahead and let us know
and we'll put you up next for questions.
So this next question here is targeted towards PacifiCorp,
but I would also like to hear Liberty
and Bear Valley's approaches as well.
So PacifiCorp, in the 2021 WMP update,
we have figure 4.2-3, which is the breakdown
of annual distribution of risk events by cause categories.
And from 2015 to 2020 even though the amount
of risk events fluctuates,
the category of unknown is staying proportional
and it's one of the higher brackets.
So I'm wondering what is the utility doing
to better understand the unknown category?
-: That is a super question,
so for us unknown is the natural response
to that unknown would be to give guidance to people
to help them decide how to code it.
But we did not want to corrupt the data that we have.
So it's important for us to make sure that we build
the investigative competency
so that we actually are able to turn an unknown
into certain known.
So
oftentimes, what ends up happening is
whatever the evidence would have been about what's a fault
or the risk event was his bound
by the time patrolmen gets there
or it was a transient sort of event.
And didn't actually leave any indications.
With the eye, you wouldn't necessarily be able
to detect what that was.
As we are moving forward with the deployment
of many of the relay replacements that are part of our plan
as well as then recloser control
technology, we'll be in a better position
to actually diagnose the specific locations
and have better targeted inspection
of those particular areas
so that those unknowns can be made known
but not necessarily by the immediate responders.
But it'll be on the follow-up action
as opposed to on the outage restoration that we're able
to determine what the known is.
And we do that actually
through some post-processing that happens
or we will be doing that some through post processing
that happens with
mining, that outage history and triggering notifications
to people that conduct those analysis.
-: Got it, thank you, Heidi, Liberty and Bear Valley.
-: Yes, that's a great question.
So as I referenced earlier in the presentation,
we have upgraded our outage management system.
And as part of that upgrade, it will do a couple of things.
The first thing is that it does produce a report
that contains a lot more details in terms and data points
in terms of what the Commission was looking for.
And some of those data points were
if it was energized equipment,
how many splices that were there?
What type of equipment was the fault on, the location?
So some of those data points are now features
as part of this new report that we have.
A couple other things that the company is doing.
And that's part of creating this new report,
there were more options
or the communication between our dispatch
and our trouble men to log in our outage management system.
So what we did was we retrained
and went over of these new options with our dispatch teams
as well is our field workers
in order to properly capture those data points
and have those data points be accurate in the report
because that will eventually feed into our risk models.
So I think that that's going to have some improvement
over a lot of these data points that got listed as unknown.
So we'll have to see going forward what that looks like,
what is our expectation
that the unknown category will decrease
with these new options
and with us producing this report and retraining our staff.
-: Great, thank you, Greg.
-: I don't think our unknown is that large a number,
but we do have, and we've been doing
this now for about four years,
a very detailed prescriptive report that the patrolman use.
So they don't have a lot of options,
they have to check the most appropriate.
And then the next day there's follow up
and if we have questions,
we sit down with the patrolman, get pictures.
So being on top of the data gathering is important
and making sure it's done real time
rather than at the end of the quarter,
you're trying to do your quarterly upload.
And now, you're trying to reach back a couple
of months and figure out what happened that night.
So that's important.
There are genuinely events that are unknown,
I mean, sometimes, an OCD will will open,
you'll patrol it, you'll patrol it again.
Okay, we test it, it's fine.
We patrol it again just to see if we missed something
and you don't, you it's not there.
So there are a few that are gonna be
in that unknown category and just the fact of life.
-: Can I add to my answer, please?
It kind of precipitated by what Paul just mentioned,
which is historically
and I think Zoe's question really tip this one off is
that we have long history of outage records
and those systems may have changed over time.
The goal of the outage was to solve and restore power.
Now, what we're doing is we're using that outage
as a proxy for risk events.
And so we're in the past and unknown
as long as you had the power restored was
kind of I looked for everything, everything looked fine.
I couldn't actually detect what it was.
It was an acceptable outcome to leave it at that point.
Now, it's less acceptable,
and so we have to build different processes
in order to actually go deeper into that investigation
and that's what we're really trying to recognize
in our tool sets and move forward with
so that we have better answers
for those that can be made known if we have more data
to inform what probably happened
or what maybe conclusively happened when you have
some of that electronic data.
-: Great, thank you for all the answers.
At this point here, I'm just sure.
Abrams, are you able to patch through with audio?
Abrams: I believe so, can you hear me?
-: Yes, loud and clear, thank you.
Abrams: Great, thanks.
I'm glad I was able to fix that.
So I appreciated the presentation
and really just had some questions
around sort of the transparency
of the information and the degree to which collaboration
particularly with local agencies contributes
to how this information is used.
So PacifiCorp talked about, you talked about
how there's this circuit prioritization map.
And so just wanted to understand
how much of that information is transparent.
And so if I lived as an example in an area
where there was one of those red dots,
might that I'd be able to sort of contribute
towards solutions to sort of reducing the risk
around that circuit.
And how does that type
of collaboration go back and forth?
And similarly, sort of around the sectionalization devices
that are within your grid,
how much of that information is shared specifically
about what types of sectionalization devices are
in what areas?
And so does that also then empower emergency managers
or other folks to be able to help
when there might be de-energization
or there might be decisions
around how to mitigate that they're able to contribute
in a way because they have this information?
Thank you.
-: So good questions there, Mr. Abrams.
First off to this point,
we haven't made the zonal quantification of risk.
Part of our conversation, we started
with the sharing of our mitigation plans
with the PSPS impact
that we're really reliant on the HFTD designation
and attempted to be very transparent
with customers and public safety partners in that regard.
In terms of that sexualization question that you're asking,
we went the other direction.
And it's interesting to hear your approach to it,
with us, what we did was we used the identification
of where critical customers
or medically vulnerable customers were
at that section level, had the conversations
with our emergency or with the public safety partners,
and then went backwards to try to determine both mitigation
and sectionalization opportunities.
We've never identified, I guess,
at a facility point level to our public safety partners
where each of those kinds of control points
and maybe that's worthy of a conversation with them.
What we tried to do was to use that whole PSPS impact
and risk impact as a conversation.
I don't know that we have yet figured out
how to make the model usable
if you don't have some of the GIS data behind it,
but certainly, it will have some of those conversations
with public safety partners,
hopefully through our Wildfire Safety Advisors Board.
-: I think community engagement is really important
and we're a small enough area, but there's always
why is that street getting covered wire
or when am I getting covered wire on my street,
small town issue.
And so what we did was we briefed the city manager
for Big Bear Lake in a very detailed on
how we arrived at the mitigation we selected
and then how we were prioritizing them.
And a good number of them fall outside the area
in the unincorporated areas.
he really cares about the incorporated areas,
but he understands why we're doing
those areas first and how it's all linked.
The other area that I use,
I'm not sure if you're familiar
with fire safe councils throughout California,
but I briefed those personally,
take our plan slides and briefed the fire safe councils
'cause those are individuals,
and if you're willing to join a fire safe council,
you're definitely a concerned person
in your community about fire safety and wildfires.
And so those are people that I like to reach out to
because they spread the word around the community as well.
-: And for Liberty, we were still
in the planning phase on that,
but we do have emergency plan as well
as a PSPS of protocols that we follow.
So that's about the stage where we're at right now.
Abrams: Thanks very much, I appreciate the answers.
Really,
my question, which I think was addressed is
really to sort of have more collaboration
around decision-making in terms of the mitigation measures
that are put forward so that public officials are empowered
to be able to say, "Well
if you move this sectionalization device here
and we're able to gate in this way,
we can protect this telecommunications infrastructure
or limit the effects in this way,"
or, "I know the landowners that are around
this circuit where you've identified that there's a risk,
I can work with you to address it."
So I guess just I really appreciate the answers,
I guess I just would say that it sounds
like that's an area for further development,
so that these partners in the public can really be active
in terms of working with you in mitigation is going forward.
But thank you very much.
-: Thank you for that question, Mr. Abrams.
And we about five minutes left here.
So Henry, go ahead and take it away,
and this will likely be the last question
that we'll have with this Q&A session.
-: Great,, okay, thank you.
So I have a question mainly intended for Liberty,
Liberty if yours is relying on react
for risk assessment and modeling,
and so I have a couple of questions on that.
One is how did you develop the polygon
that you used to do risk analysis
of different parts of your service territory?
I'm just trying to understand how you drew the polygons
to identify discrete regions.
And then secondly,
how did you validate the results that Reax provided
in terms of risk modeling?
How did
route it or test it in the field to make sure
that that risk modeling was providing a reliable output?
-: Yeah, thank you for that.
Thank you for that question, Henry.
So as part of how they segmented off those areas,
if you remember those green lines,
some of those areas would follow
where those circuits are located.
So that was part of it.
Another part of it is an elevation change,
what type of vegetation of ground fuels that were out there.
So these are a lot of factors that go
into their fire propagation models
and what they were able to do
as part of that modeling look at areas
where if a significant wildfire themes.
So for example, if we start moving closer to Lake Tahoe,
the fire spread would end
because there's no vegetation, there's no wood.
There's nothing that's going to have the fire,
let's say if there was a forest there in would carry,
so that's one example.
Another example too is that if we looked
in areas that were heavily commercialized, a lot of times
these buildings aren't necessarily great conductors
of a wildfire, so the spread isn't going
to escape containment
as it was as easy as it would,
say in a very heavily forest area,
particularly with vegetation or ground fuels that can
really be conducive to wildfire spread.
So there's a lot of things that are taken
into consideration how to area those often segmented off,
but those were some of the different risks
that they looked at and that we talked
about how to change from one category to the next
and where one border would start and the other would end.
In terms of valid, validating out in the field
or what their outputs were.
I think we're still in the collection,
we're still sort of in the beginning stages of that.
I'm not sure we really have a long enough history
in terms of really validating.
I think anytime you do something like that,
you need to have a reliable sample size to look backwards on
and say, "Okay, yeah, this is where we think it is."
Maybe this needs to change, so I think as time goes on,
we're gonna be able to do that validation
like you just mentioned.
The analysis that they completed for us wrapped up in Q3.
So really we haven't really had
that much time to really let what the scoring
and rating that they've identified,
then looking backwards to any types of changes
whether we need to say something's more risky or less risky,
but this is something that we do have our eye on
and this is something that we know is gonna happen.
We know that our first-generation models
in the information that feeds
into these first-generation models will change,
and we know not everything will be static.
And so we do plan to keep an eye
on that in the jobs as we see of the data come
and test it like you mentioned.
-: Thank you.
-: Great, thank you for that question, Henry.
At this point, we have reached the end
of the time block for our question and answer session.
To all three of the presenters,
thank you so much for presenting your guys's risk assessment
and mapping and resource allocation.
We will now take a short break here.
We are going to resume at 11:35.
The next section will be moderated
by my colleague, Andy Biggs, and is...
Andy: As part of properly assessing risk,
it's vital that the utilities have frequent
and thorough inspections to understand asset health
and accurately identify where to conduct repairs
replacements, and system hardening projects.
Utilities need to demonstrate
how they are identifying advancements to the traditional
from the ground and visual inspections
whether it be through drones, LiDAR, infra-red
in order to augment inspections and properly catch issues
and field before they lead to an ignition.
Integrating and understanding
of equipment and asset health utility should be vetting
various mitigation measures to implement
to reduce the risks posed
by their systems, including PSPS risk.
One of the higher bill options
for mitigation will be digging
into deeper the session grid hardening,
which includes cover conductor undergrounding
and microgrid development.
Given the largely rural nature from much
of the SNG's customer basis.
With climate change
and weather conditions worsening over the past few years,
utilities should be building their systems
to be able to withstand known local conditions
to ensure systems won't fail or lead to an ignition event
at high wind speeds
and focus on maintaining a reliable system
that minimizes PSPS events and keeps power
and lights on for customers.
With that I'll turn it over to the utilities
with 10 minutes each starting off with the same order
as earlier with PacifiCorp starting off,
then Liberty, then Bear Valley.
We'll also include the
two independent transmission operators this session,
being Verizon West and Trans Bay Cable,
even though they have a much smaller footprint,
they've still undergone the work to understand
and mitigate loss higher risk along their systems.
As a reminder, if you have any questions,
please enter them into the chat
for a moderator our Ryan Arbor to go through,
and we'll have them answered
during the Q&A session this afternoon.
Amy: Okay, great.
Can everyone hear me okay?
Yep.
Hello.
Participant: Yep, you're coming in loud and clear.
-: Yep, okay, (laughs loudly)
Sorry, I'm so paranoid about that, thank you.
So thanks for that, Andy.
I assume you want me to go ahead
and kick it off with PacifiCorp?
Andy: Yes, please, go ahead.
-: Yep, okay, great, thank you.
So my name is Amy McCluskey,
I'm the Director of Asset Management at PacifiCorp.
And today I will be presenting to you on three key elements
of our wildfire mitigation plans.
These are grid hardening inspections
and emerging technology.
Next slide, please.
And here they are again with a few images
to give a little color.
Specifically grid hardening, this is the area
where we're talking about changing our grid.
A huge portion of that is implementation
of covered conductor grid.
Inspections, we're gonna focus
on both standard as well as enhanced inspections.
And then the last, the emerging technology.
And we've added this in because this is an area
where we're testing out some new things
and trying out some new things.
And there's a high potential
that what comes out of this area can strongly influence how
or what we do in grid hardening and inspections.
Throughout the presentation,
I may refer to these as pilot projects or research projects,
and you may have seen them in the WMP also referred
to as different names, but here we're gonna talk
about them as emerging technologies.
Next slide, please.
So before we dive in, I did wanna provide a quick refresher
into our plan objectives.
The walk through this it's not meant to,
I would say replace the detailed work that Heidi walked
you through this morning on risk modeling.
It's really here to just provide a simplified view
of what our plan hopes to accomplish
and how our initiatives are designed
to meet those objectives
with an overall eye on reducing wildfire
through the implementation of our WMP.
So if you take a look here,
we've got four objectives on the slide.
So greater resilience or fewer fault events,
rapid fault response, facilitate situational awareness,
and operational readiness and consider and mitigate impacts
to customers and communities.
And when I think about why certain mitigation activities,
it really boiled down to meeting these objectives
and reducing risk by observing the risk drivers
that Heidi talked about this morning
and trying to really change the way our system operates.
What I'd like you to take away
from this slide is each of our initiatives is designed
around meeting a plan objective, and therefore can
either reduce risk or enable the reduction of risk.
And while each individual component can be very effective
where we really start to see benefit is
when we combine initiatives
or layer them on in these high risk areas.
And as an example, I'll just walk through one,
when I think about that first plan objective,
greater resilience through fewer fault events.
Do you remember from this morning, Heidi walked through
our fire risk event data
that tells us we've got two fairly large categories,
one is contact with objects
and another is equipment failure.
But I think about grid hardening,
and I think about trying to reduce those fault events,
it certainly checks that first box of reducing the impact
of contact, but it doesn't necessarily check the box
of reducing risks due to equipment failure.
However, that's where our asset inspections can really come
into play and handle that second risk reduction.
So when you're in areas
where you have multiple risk drivers,
you need multiple initiatives.
The last row there, emerging technology,
certainly, we're still in test phase
with a lot of our different pilot projects.
So they're all kind of under construction,
but I did wanna point out that when we do develop
these pilot projects, we're thinking
about how these projects can meet these objectives
and how these projects can inform other initiatives
'cause that's what it's all about is is sticking
with our vision and our plan.
Next slide, please.
Now, that I've covered a little bit of the why,
I did want to touch on the wheres just in case
there are those who may not be particularly familiar
with our service territory, got a map here on the left,
just a few of the general stats.
We provide electricity to approximately 45,000 customers
via 63 substations, just over 2,500 miles
of distribution and about 800 miles of transmission.
And our service territory spans around 11,000 square miles.
So it's a fairly low customer density as compared
to some of the other California utilities.
Specific to the HPD or higher risk assets,
we have the stats here on the right hand of the slide,
approximately 1200 miles, or just over 1/3
of our overhead lines are within the HFTD,
850 of those distribution and 350 transmission.
So this will become a little bit important
when I'll get to later slides to talk about where we deploy
our different initiatives, what we look for,
certainly these HFTD high risk areas
as well as the one Heidi talked about this morning become
very, very critical to the deployment.
Next slide, please.
All right, so we've talked about the why and the where.
And so now, we'll start to get into the what.
This slide here, it's all about our grid design
and system hardening initiative.
As I put her on the slides
about four main areas where we focused on system hardening,
bursting installation of coverage conductor,
second proactive replacement of poles,
installation of system equipment,
and replacement of small diameter conductor.
I've also included in this view the installation
of weather stations.
It's not strictly a grid design system hardening initiative
but it's such an important part of how we deploy,
how we manage the work that we have included it here
because it's such a critical component
of the overall program.
However, if you were to dig into the WMP,
you would see it under situational awareness.
I did just want to note that in case you're trying to follow
along with the document, it's just not gonna follow
in order with the other components here.
When I think about the the initiatives here and why,
why covered conductor, why replacing a pole?
The first one that touched on earlier covered conductor is
really around limiting the impact of contact.
So it's preventing the event altogether.
The other three on here focus on a few different things.
So they focus more on controlling the event
or making sure the event doesn't get worse.
So they mitigate risks slightly differently.
For example, the proactive replacement of poles.
For that program PacifiCorp is targeting high risk locations
that might be susceptible to a brush fire
where we think we could use
some additional structural resilience to make sure
that restoration can be faster to support egress.
So it's not really a program that prevents an event,
but it helps control it and make sure
that it can be recovered from quickly.
The last year of installation
with system automation equipment and replacement
of small diameter conductors,
they have a similar goal in mind,
which is our ability to implement advanced protection
and control schemes.
So system automation equipment, that's all your widgets,
your relays, your reclosers, your circuit breakers,
your advanced communication equipment
that allow us to identify a fault faster, see smarter,
isolate quicker and really reduce the potential energy
that can be released.
Replacement a small diameter conductor is an enabler
to that program, so we have a few areas
where we need additional capabilities.
And in order to do that,
we have to upgrade the small diameter conductor first.
I've included some numbers on here,
total program targets as well as annual program targets
as opposed to going through those 'cause sometimes,
it can be challenging to figure out what they need
and if they're good, I've included a qualitative phasing
and deployment graph on the right.
And I just wanna point out just a few things.
There are no units for this qualitative
and along the x-axis are the years
and then the colors do correspond to the programs.
And you can kind of see in 2019,
we started focusing on weather stations
and system automation and plan development.
In 2020, again to shift efforts
and ramp up our covered conductor program,
focused on design, and engineering, and scope.
And now, we're pretty much fully ramped up
and focusing on high-risk PSPS mitigation,
which includes pairing different initiatives
in a specific location,
which I'll walk you through in the next slide.
Our plan is to continue with that,
but I did wanna point out, sorry.
Can you go back one slide, please?
Toward the very right, you see, it says risk shifts.
To date, we've been focused on PSPS locations,
but as Heidi walked you through the risk modeling
this morning, as that evolves and we get more granular
with our risk and exactly where our high risks are
and what locations specific drivers are,
there is the potential that we may change
how we target programs and where,
but right now you can kind of see where we are in the graph.
We're really focused on PSPS mitigation.
Okay, next slide.
This is just a quick snapshot of what that looks like.
I don't expect you to read everything on the left here,
but I'm gonna point out a couple of things.
So this is an example of focusing
in on the high-risk PSPS location,
and there is some color coding that is important.
The color coding on the circuitry kind of describes
how we might bucket the different work.
So where we have isolation
or where things are electrically connected.
And what we do is we look color by color
and say, "What are the things we can do here
to mitigate risk?"
I'm up with an implementation plan, which is what you see
on the left, which is kind of a color section
by color section, how we're attacking that portion
or that circuit.
And it is once you complete your constructions,
then you would have mitigated the PSPS risk
in this location.
So as opposed to looking at all the places
you might have covered conductor or all the places
you might have reclosers, we're looking at what lists,
what menu items of our system hardening do I need
in this PSPS location to mitigate the PSPS risk.
Next slide, please.
Now, we'll shift gears a little bit.
So moving from a grid design and system hardening
to inspection, that here, when I talked
to you through our standard inspection programs
as well as our enhanced inspection program.
On the last, in 2021,
our goal is to complete 63,000 cyclical inspections.
These are typically driven by compliance requirements.
So for us, it's just a around 3,000 intrusive inspections
where we also typically perform a detail at the same time.
So it's kind of a double inspection,
10,000 additional detail and around 50,000 visual assurance
versus the inspection.
In addition to just performing the body of the work,
our goal is to complete the tier two
and tier three inspections prior to fire season,
making sure we focus on those high risk areas.
Additionally, identify fire threat conditions
and accelerate corrections.
If 2021 is anything like 2020,
we think we will be finding around 8,800 conditions,
800 of which will be fire threats
that we need to accelerate correction for.
So that's what we're planning on.
We'll see how the numbers shake out when it's all done.
And finally, another goal we have is to bring
you a fresh focus to our QA/QC of inspections.
This is an area we received feedback
on and think like we could,
it was important that we really focus on this area.
So for us, that means incorporate fire risk identification
into annual training, prioritize the tier three
and tier two locations, complete desktop reviews.
We're planning for around 6,500 of those this year
as well as around just under 700 field inspection audits
as well, so that's their standard program.
When I move over to enhanced program here,
for us right now, that means our infra-red inspections have
overhead transmission lines.
This was something we kicked off in 2019,
has evolved in 2020, and it's now a full program in 2021.
I believe to date, we've found seven different hotspots
on our transmission lines.
At first it was one or two
and I think we learned a lot over the years
that we really need to target the inspections
when the lines are more heavily loaded, peak,
or near peak loading,
so that gives us the best possible diagnosis
or the best possible chance to see that extra hotspot.
An example of one of those is tear on this slide
that was abnormal heating on a jumper on a 69 KV structured.
And one of the big things in 2021
that we've introduced the new program management processes
and procedures, so we have better tracking
to describe program effectiveness, program costs
'cause we do see this as something that is supplemental
and in addition to our standard programs,
we wanna make sure we're measuring the effectiveness
as we go.
Next slide.
So this is the last topic I'll cover today,
and I know a lot on the slide.
So I'll kinda touch on a few things,
this is emerging technology or our pilot projects,
you will find a lot more detailed information
in the 2021 WMP, specifically section 4.4.1.
I picked the six tier to just draw on the slide
and talk through a little bit.
With each, we've got the name, very very brief description,
the application, which is really how I see
this pilot project influencing something else,
the plan objectives, so does it align
with one of our plan objectives I walked you through?
And then the status.
The first one distributed fault anticipation
in wave form analysis.
This is a partnership with Texas A&M
to install new devices on circuits
and see if we can get smarter about predicting faults.
So obviously, if you think about the plan objectives,
it's predicting faults and ensuring rapid full response.
The LiDAR or pole loading assessment program,
we've got two LiDAR programs on up here.
One focuses on assets, the other one focuses on vegetation
'cause the first one is really around leveraging data to see
if we can improve how we model circuits,
how we understand risk,
and how we identify equipment for replacement.
The LiDAR vegetation, which I believe will be touched
on a little bit later this afternoon is
around informing risk mapping
and potential threats that exist on the system.
The fourth pilot here, radio-frequency and infra-red
for line patrolman, it takes a lot
of the positive things we've learned
from our existing in Hampton session program
and explores whether or not we can incorporate
those elements into our standard inspection programs.
Certainly still in the early stages there, but hoping
that we can take a lot of already existing lessons learned
and apply them.
The arc energy fault modeling project,
this has been really critical
as the company has advanced the risk modeling efforts.
So being able to simulate
and calculate the potential arc energy
certainly helped us understand where our risks are.
And then finally,
the advanced weather station modeling project,
which is about comparing different types
of weather stations.
So the company is certainly adamant
about deploying weather stations for situational awareness.
We're just not sure exactly which one yet.
And so with all of these,
we're trying to keep a close eye
on how they inform other programs,
how they change our risk modeling,
and how they meet the different plan objectives.
One more slide, and so what that does is say, thank you,
and I appreciate the attention and thanks for listening.
Andy: Yeah, thank you so much, Amy.
Up next we have Liberty
Dylan: This is Dylan Harris with Liberty.
Could you bring the slide deck up, please?
Great, thank you.
And I believe it is halfway roughly through
this presentation is where my piece starts after this,
right there, perfect.
Hello, everyone, thanks for being here today.
My name is Dylan Harris, I'm an electrical engineer
with the operations department here at Liberty.
I'm here today to discuss
with you Liberty's grid design, system hardening,
inspections, and mitigation choices
within the 2021 WMP update.
Obviously, that's a mouthful and just a lot of topics
to cover a pretty wide breadth of information here.
So I'm just gonna try and hit on the key points
of each of these.
We really have a wide array of approaches
for grid design and system hardening.
Everything from coverage conductors to micro grid projects.
We just started this year
as well as some substation hardening efforts.
And then we've also made great strides
in improving our inspections in 2021.
Next slide, please.
So in 2020, we completed our first cover conductor projects.
We now have seven miles of covered conductor
roughly installed within our service territory.
The majority of that is this ACS
or aerial conductors system type,
construction that you see here
where the conductor is sort of bundled together
and supported by a messenger wire.
In future years, we plan to use risk mapping and modeling
to drive where we really want to implement covered conductor
and other grid hardening initiatives.
So far some challenges we've faced
with the coverage conductive program are permitting issues,
visual impact, and initially we had
some unfamiliar maintenance practices
and tools due to it just being a new construction type
within our company, we've since held some trainings
and gotten the right tools.
And we've largely bridge that gap
of the big question is how do we,
if a tree totally falls through this and breaks everything,
how do we address that type of catastrophic style of outage?
Another area where we're targeting
with the use of cover conductor is creation
of resiliency corridors.
So the idea here is we have some existing generation
assets specifically within our North Lake Tahoe
service territory that in the event of a PSPS,
we can create this resiliency corridor
with covered conductor, shut down portions of the grid
that we need to, but have confidence that a key area
of the service territory is going to have power
during these PSPS events and give the community a place
to be during one of these events
and have critical services available.
And conductor is a good technology,
but we were continuing to evaluate alternatives.
Next slide, please.
So among those alternatives is as microgrids 2020,
we were successful in constructing
and Commissioning our first microgrid solution
to a remote mountain research station.
It is the Sagehen Creek Field Station,
kind of Northwest of Truckee
if you're familiar with the area.
These projects save have customers over $2 million
by replacing high fire risk distribution line
with a containerized solar plus battery storage microgrid,
the line is it's still physically in place
but we have the ability to totally deenergized
it during fire season.
Additionally, we're undergoing feasibility studies
for microgrids and other locations,
we have planned covered conductor projects
that we're looking, taking a step back and saying,
it doesn't make more sense to do a microgrid here,
what is the feasibility from a cost perspective
and what does that bias in terms of resiliency
and value for the customer?
-: Next slide, please.
So in 2020, we did a system wide inventory
of all our overhead assets.
This kind of serves the baseline of our system condition
and we can use this to develop programs
to proactively replace infrastructure.
So this system inventory really allows us
rather than just having a time-based maintenance program
to evaluate the condition today of every piece
of equipment in our overhead inventory
and kind of create a
more condition-based maintenance program,
which is it's something that's really exciting for us.
And go ahead, go to the next slide.
So another outcome of the system inventory was
also application-based inspection.
So believe it or not,
in 2019 Liberty was using paper-based GO165 inspection forms
and that just doesn't have the granularity
and quality of data that you need
from what the Commission is asking for,
so we drastically improved that in 2020
and also completed inspections
on the entire overhead system.
So this improved inspection practice,
like I was mentioning in the previous slide provides
prioritization for mitigation of at-risk structures.
So when you take this asset condition combining
with the risk mapping and modeling effort
that Greg spoke about this morning,
you really get a really solid way to prioritize
system maintenance.
And then future years, we're looking
at expanding our inspection program
to include infra-red imagery in and seeing the applications
that that can have for us.
Next slide, please.
So a couple of emerging technologies
that we wanna talk about today,
PacifiCorp mentioned distribution fall anticipation.
And so the idea here is you look at high fidelity,
current and voltage wave forms,
and Texas A&M has developed algorithms
that can reliably detect, this nuance looks
like it might be a branch hitting the tree
or it might be a failed connector or something days
or weeks before an actual outage or failure occurs,
which obviously has really big impacts.
So we don't have this deployed yet
within our service territory within 2021,
we'll have approximately 20% of the feeders covered.
And this is starting in our very high wildfire risk areas.
So we're using that at risk mapping to prioritize this work
and kind of in, since we don't have
this technology deployed, yet, we sort of have to look
at at other resources for, hey, how effective is this?
And so we've looked at FTE's wildfire mitigation plan
and they've deemed it successful enough
to drastically expand this program.
And so that's something we're looking
at as an indication that is a promising technology.
Additionally, the initial risk analysis is favorable
and cost-effective based on the fact that it is relatively
easy to install, hardware wise, just a single piece
of equipment for each feeder.
And so we're looking to expand
that as a cost effective mitigation solution.
Next slide, please.
Lastly, I'll touch
quickly on our distribution automation program
that we target the designed to be complete within this year.
Again, we're targeting theaters
and the very high fire risk areas.
And in terms of reducing the risk of,
and scope of PSPS events as part of this,
we're adding a lot of sectionalizing options
to really limit that scope as much as we can combine
with data from our weather stations and circuit monitoring,
we can really make the most informed decision possible
to try and limit the scope of those events.
And distribution automation,
like I mentioned is gonna leverage
some new technology as well as existing reclosers
and isolation devices that we have in the field.
And it also is a great improvement
to the system reliability.
And with that, that is all I have today, thank you.
Andy: Thank you so much.
Up next is Scott, Bear Valley presentation.
Scott: Okay,
most of my slides will talk
about the grid hardening aspects.
I'll talk about inspections, although a lot
of slides are in the next section
where I can explain those further.
And then on emerging technology,
they'll talk about that as well at the end.
Go to the next slide.
When you look at grid design and hardening,
it's important to understand the environment.
It's a small area, 32 square miles,
it's about 7,000 feet is where most of the facilities are.
So it's
in the heavy loading district.
For those of you familiar
with geo 95 constructional requirements.
And then it's also all within the high fire threat district,
mostly about 90% tier two, about a 10% tier three.
And key jurisdictions, it's really three principle ones,
the County of San Bernandino, City of Big Bear Lake
and US Forest Reserves.
Most of our voltages are either sub-transmission
or distribution sub-transmission at 34,500 volts,
distribution 4kV.
You go to the next slide.
I'm gonna highlight some of the projects
we've embarked on, covered wire conductor installation is
something we've embraced.
We did pilot the program last year
and selected two vendors Priority Wire
and the South Wire products, we tested others
and our decision was to go with these two
as the principle solutions.
And we do have a pretty ambitious program.
We got about eight circuit miles last year and
we plan on doing about 13 circuit miles
per year going forward.
And that's split between 4.3 circuit miles per year
on the subtransmission side
and 8.6 circuit miles distribution.
And this is all targeted on a prioritized list using
that fire safety matrix,
so to decide where to go, where to do it.
So that's how that's driven.
You can go to the next slide.
Just one comment.
The covered conductor is a long-term project,
but as we target those high risk areas,
obviously, we start getting starting early payoffs.
Fuse replacement program, this project started in 2019.
The objective was to remove conventional expulsion fuses.
As you can see, fuse events are spark producing events
that could potentially result in fire or wildfire.
And the nice thing about, this is an early win, I think.
We had a little over 3200 fuses in our system.
We came up with a strategy to use current limiting fuses
and TripSavers
and a strategy on where to put each.
As of 31 December, we had 901 remaining to replace
and our goals to have a system by June, 2021.
And one of the things like, for example, last year
we had, I think, 22
fuse events
and because of the progress we had made in this project,
I think only three of those events were conventional fuses.
So just shows we've reduced that risk
by getting this done and getting it done quickly.
So that to me has been a good project and reasonable costs.
You can go to the next slide.
As you can see, evacuation hardening,
I talked a little bit
when I asked one of the questions last panel.
In picture, there's basically three ways
off the mountain on paved roads.
And so it's very important
that we keep the poles from falling into the road,
and obviously there's different ways of handling that.
So we piloted to make sure we were familiar and understood.
What's involved with the different solutions
on different types of poles.
Obviously, we were underground before.
In fact, a good portions coincided with an evacuation route.
We evaluate what's the cost of relocating infrastructure
and then we've looked at this wire mesh cladding wrap
and we looked at what other utilities are doing.
And once we saw that they had adopted certain solutions,
we went out and tried them ourselves
or talk to them to make sure we understood
so that we could get the benefit of what they had learned.
So, as I mentioned, our plan is
to harden the three main evacuation routes over two years
and using the wire mesh wraps
that quickly gets a handle on the problem.
And then we develop a policy to replace the wood poles.
When they're being replaced for any other reason,
we do it with something that's fire resistant and so forth.
This is anecdotal, but I think it's key to understand.
If you did have a wildfire in Big Bear Lake,
any region, generally you'll find at least one
of the evacuation routes is closed down due to the fire.
Just if you look at the geography
that's the fact that's generally true.
And most fires that have threatened us
in recent years have threatened
at least one evacuation route.
Last summer, there was a fire.
They were inner dark territory, but it shut down Highway 38
and a number of the scenarios
that the
Cal Fire and the District Commander ran
if the fire had spread up the backside of the mountains
up to Big Bear Lake, it would have taken away
the area near the dam over to the left
on that chart Highway 18 over there.
So we would have been left with one route down to return.
So it's very important that we focus
on these evacuation routes and understand
the weaknesses that they cause
that we contribute positively to making them safe.
You can go to the next slide.
So obviously, we use our risk modeling
to develop our prioritize list of mitigations.
But at a higher level, like I said,
we're mostly tier two, a small portion tier three.
So we sorta have to prioritize.
Unlike the larger utilities, we have to get
even more granular than the high fire threat districts.
And so we're a little more surgical,
we've identified high risk circuits
and we consider these things as we develop our plans.
One of the things that, I don't have it up here on the slide
because we've already sectionalized our high risk areas
and so from a PSPS perspective,
we've already got that in place.
The next level is automating those particular switches,
which is what we're doing.
We have a grid automation project,
which is in progress right now.
They're installing a fiber network
that'll allow us to do that.
But once again, 32 square mile area, it's not hard
for our crews during the high-risk fire weather
to be out in the field and get those switches.
We haven't had to do that.
We do exercise having the mountain fields
in order to do that,
but we are fully sectionalized
to where we wanna be right now.
On the inspection, we, first of all, do the,
obviously, the geo 165 required periodicities.
Due to our location, we do annual ground patrols,
we do five-year detailed inspection,
we do the intrusive pole inspections.
We also, in addition to the ground patrol,
we do a second annual ground patrol by a third-party.
So this is another contractor independent
of our field inspector and we make sure
that contractor has no construction work with us.
So they're completely focused on inspection and
that's a good check and it helps us get that outside view.
Then we also use LiDAR.
We've now completed two LiDAR surveys
and we're trying to do the LiDAR per year.
And I think that's a very good effective program.
We did do tomography route
our entire area using Brown mounted two years ago
and it didn't yield a whole lot,
so we have increased the periodicity on that.
And right now we're looking where we've got an RFP out
to contract out a UAV where we will get
some high definition imagery and
thermal imaging as well.
So we're excited about using that inspection technique
to help identify areas for improvement.
Likewise, we're in the process
of implementing a inspection app for patrol
our field inspector so that we get
highly accurate
and automate the process of identifying deficiencies
in getting into our GIS system.
One of the things too, that it's not
in our wildfire mitigation plan this time round
but it's something we're talking about and considering,
detailed inspections by Geo165 are required every five years
on all circuits.
It doesn't matter if they're underground,
overhead, bare conductor, overhead, covered conductor,
it's a five-year inspection.
So we split it up each year we do a certain number.
Having worked in other communities
such as the nuclear field and petrochemical field,
those areas they do, what's called risk=based inspection.
So we might adopt a plan
where you more frequently inspect the higher,
the bare wire, and high-risk areas,
and so forth.
So you develop a periodicity based on that.
So that's something we're trying to focus on
so that treating underground systems,
which are fairly stable and reliable, the same
as a bare wire and tier three area is
probably not the correct answer on detailed inspections.
And so that's something we're gonna address in the future.
Regarding emerging technologies,
we pilot programs that have already shown promise
at other utilities.
Being a small train, the technology risk
for our customer base is a lot.
And so we don't wanna buy into something
that's gonna turn out to not work.
So we tend to leverage work with the big utilities
and then apply it tomorrow unique circumstances.
And we think that's a very cost effective way
of getting these new technologies into our system
in a fairly responsible and yet decision fast manner.
We also are open to folks who wanna do research
on our environment and our systems.
We certainly are open to collaboration in those areas.
That's all I have.
Andy: Great, thank you so much, Scott.
I'm gonna transition over into the ICU
starting off with Horizon West.
Alona: Thank you, Andy.
This is all I see on this Horizon West to me.
Can you hear me?
Andy: Yeah, I can you hear me?
Alona: Okay, great.
So I know we're running short on time,
so I'll be pretty brief here.
But like I said, my name is Alona Sias,
I'm Director of Strategy and Business Development
and I represent Horizon West Transmission.
So we can go on to the next page.
In terms of the agenda for today,
so before we get into the wildfire mitigation strategies
and measures and section, TNN said
we are employing at Horizon West transmission,
I wanted to spend just a few minutes to give an overview
of Horizon West Transmission, given that
we're very new independent transmission owner in California
and I wanted to give an understanding of our footprint
and our current scope of operations in the state.
And then after that, we're gonna talk
through the specific measures we're taking
that we detailed in our 2021 WMP
before the harden and the assets that we have in space.
Let's go to the next page.
So like I said, we were a very new utility.
We were transmission only utility
and we were the first non-incumbents to be awarded
to competitive transmission project
by the kites bill back in 2015.
And those two projects are the Suncrest SVC project,
which is in Southern California
interconnecting as the SDG&E.
And then the second project is
the Estrella substation projects interconnecting
SDG&E in Northern California.
So both of these projects were awarded to us
as part of FERC Order 1000 process.
And both of these are very contained substations,
so they're limited transmission lines
and no distribution line.
Next page, please.
So like I said, the only projects we currently have
in operation is the Suncrest project,
which is in Southern California and is located
in tier three wildfire area, it's interconnected with SDG&E
and it's about 40 miles East of San Diego,
and of course, in San Diego County near the Town of Alpine.
It's a very new asset.
It's a little bit over a year old.
So we energized that early last year
and we have not had any utility-caused ignitions,
near misses, or PSPS events
at the Suncrest SVC project to date.
And the project was selected
to provide reactive power support
and increase, enabled more renewables being transmitted
from Imperial Valley into the rest of the system.
And let's go to the next page.
And then once again, this is the location of the project
and relation to the high fire threat district area.
So you can see it's in a higher fire district area
secure three, and we've had a history
of fostering wildfires, especially last year,
there was the valley fire being very close to RS at
as close as four miles away.
Next page, please.
I want to spend a ton of time here.
This is just another deep dive into the project location.
Let's get to the next slide.
Okay, so on this slide,
you can see exactly the project overview here.
So on the right hand side, this is the project location,
sorry, it looks like the font is a little blurry,
but that's specifically, thank you,
that's the project location itself.
The blue line that you can see from
that project location is the underground spot one mile line
and gone into as the SDG&E substation.
And then the tiny green line is a very short span
of overhead wire transmission lines
that we're currently working on undergrounding.
So, like I said, this is just
to give you sort of an understanding of the scope
of operations that we have
and we're making sure that our wildfire mitigation plan is
really tailored to our current scope
and footprint of operations in California.
Thank you for that, and then.
I think we can go to the next page.
And then in terms of to give you a visual of
what the project looks like,
this has been main SPC facilities static are compensated.
This is a substation itself
like that is being connected to SDG&E
through the about one mile underground transmission line.
And as you can see, there's really no vegetation
around the substation and make sure
that the original design was hardscaped taking
into account the high risk of wildfire
in the area where we have the assets.
So we're really done a great job of just thinking
through the original design and making sure
that we make those modifications early on
to minimize any contact with education
that we have to minimize any risk of ignition.
So let's go to the next page.
Okay, great, so
now that everybody has a better understanding
of our scope and operations in California,
wanted to talk through our approach to identifying
for their harding measures and making sure
that we are still keeping wildfire risk top of mind
and making sure that we are protecting the infrastructure
as best as possible.
So we primarily employ a failure modes and effects analysis,
FMEA methodology to inform appropriate wildfire hardening.
This methodology was pioneered by NASA
to identify potential failure modes
and proactively address them.
And really what we do, we use this five step methodology
to understand what is the underlying risk,
quantify the risk, and then based on that quantification,
identify modification that we should be implementing
and implement those.
So based on that,
what we do is the first step is the risk identification.
So for each major component of the equipment that we have
whether it's being the underground transmission line
or the substation site itself or transformer,
we go through every single element trying to identify
what are all the potential ways
in which that equipment components may fail.
And then based on that, we brainstorm
what could be potential drivers of the failure
of that components, whether it's concept of education
or just equipment failure or seismic events trying
to be very holistic in our assessments.
And then based on that, we prioritize,
we assign a score in this third step, risk prioritization.
We think through how likely that event occur,
what would be the impact of that event occurrence
to the severity of that pack,
and then what measures or capabilities do we have
in place to detect that event in case it does occur.
So we can respond to very drastically and quickly.
And then based on that, we calculate a risk clarity number.
And after we've done that exercise for each element,
we go through the risk mitigation.
So for any element that has starting
with the highest risk clarity number, we tried
to brainstorm what potential mitigation measures
we should be deploying to minimize the risk
of that elements failing
and potentially creating a utility cost ignition.
And after we go through that entire exercise
for the entire scope of our asset, we do the risk assessment
of reprioritization, sort of going back and asking ourselves
based on our mitigation measure that we're going
to implement, what is the resulting risk priority number
and do we need to do anything further
to further reduce the risk?
So that is the primary methodology that we deploy
to identify the right initiatives for grid hardening.
So let's go to the next page.
And I think because we're running a little short of time,
I'll probably skip this one.
Let's go to the following one where we go
through the actual initiatives we have identified for this.
Thank you.
So through that, like I said, because after this new,
we've had the benefit of learning some best practices
from all the other utilities who've been doing the work
on wildfire mitigation for much longer than we have.
We really took a lot of these mitigation measures
and implemented them in their original facility design.
So we thought through the original design made sure
that we are, for example, under we undergrounded the line
because tier three, we gonna sure
that we have fuel free vegetation setbacks
and there's no vegetation within the site itself.
If the project is located on land
that has been previously discharged.
So there's really very little vegetation
and you did lean to the surrounding area of the project.
We also contracted fire support
to the have on site during construction.
So anytime you have a spark or hot work,
you really minimize risk of ignition.
And then in terms of the hardening measures themselves
that were implemented, as you saw from the picture,
we erected a concrete perimeter wall
to minimize any ignitions or any arcs
from the substation itself leading the site
and igniting vegetation offsite.
We're also implementing transformer gas monitoring
and containment hardening to make sure that we have
that real-time visibility to the health of our transformers
as potential oil leaks if they were to occur also
because the project is in a seismically active area
with transformer seismic pads.
And then similar to a lot of other utilities,
we're installing a weather station
to just further enhance our real time situational awareness
of the site and cameras as well.
So we can go to the next page.
I have a couple more pages,
but I think I'll end on this page.
In terms of inspections and maintenance,
we have the site is remotely monitored 24/7
by qualified personnel
through those all the sensors that I talked about,
but also the overhead cameras.
In addition to that, we do a detailed inspection
of the sites on a monthly basis
and that includes all sort of equipment,
all fuel modification areas,
just to make sure that everything's in top shape.
And then we also have regular education as a tool
to make sure that there's enough education
that's encroaching on the site
and can cause concept with energized equipment.
And then in terms of operational practices,
we have the rest of my 40 protocol
where we really don't do
any non critical construction activities
during red flag warning days given
that those are much higher risk.
We have hot work safety program where any hot work
that involves grading or bark on the site is improvised.
And then we have five safety training
for all personnel including contractors on site.
You can go to the next page, please.
And lastly, I'll briefly touch on these.
Like I said, in terms of condition awareness,
we have 24/7 monitoring.
We have equipment health sensors
that help us really be more proactive
about understanding the health of our critical pieces
of equipment and rather than reactive as problems come up.
We have individualized inspections that I talked about.
And then in terms of response and recovery,
we provided specific tailored training
to local fire agencies.
They're very familiar with the site,
they know how to respond to those electrical fires
that were to happen there.
We have an emergency response plan in place
and we have all of our key personnel trained on that.
And in addition to that, we have a private fire brigade
that's dedicated to the Suncrest project
in case there were ignition at a site
to make sure that we have dedicated access
to fire suppression resources that are trained
on electrical fires and are familiar
with the layout of sites.
And then, like I said, because we are transmission only,
we do not have MD's customers.
We do not foresee ever deployed PSDS,
but we do have a protocol to communicate
with the stakeholders like CAISO, like SDG&E
and in case we do have a need
for a emergency communication procedure.
So that's all I have for Horizon West.
Thank you again for the time
and thank you for all the input.
Andy: Thank you so much, Alona.
I know we're running a little bit over
but we just have one more presentation
with Trans Bay Cable and then we'll break for lunch.
Michael: Hello, this is Michael.
Can you hear me?
Andy: Yes, we can hear you, Michael.
Michael: Hi.
Well, thank you for having us here.
So I'll be doing a quick intro to Trans Bay Cable
and then I'll hand it off to the Lenneal Gardner,
who's our regulatory and business manager,
who's gonna talk about some
of our hardening and risk mitigation strategies.
You could go to the next slide.
I'll try to keep this short
'cause we're running a little bit late on time.
But basically Trans Bay Cable is an HVDC converter station
which operates in the San Francisco Bay Area.
Next slide, please.
We have 53 miles of submarine cable
and two converter stations,
which are interconnected with PG&E.
So both of these interconnections
with the PG&E substations are using a underground cable.
So we're capable of providing 400 megawatts
of real power transmission into the City of San Francisco
and each station can also provide a significant amount
of reactive power support to support the network
out in Contra Costa County and in San Francisco.
Next slide, please.
Here's a picture showing our cable route through the Bay
and generally speaking,
our converter stations located at each.
Next slide.
So our converter station in San Francisco,
it's the Potrero converter station.
We're primarily located
in a urban city environment in the city.
And you go to the next slide.
We have our Pittsburgh Converter Station.
Pittsburgh Converter Station is located right
on the edge of the Delta, right where the San Joaquin
and Sacramento Rivers intersect.
You can go to the next slide, please.
So I wanna talk briefly about some
of our wildfire mitigation strategies and measures here.
So next slide.
So as you can see, we've identified our proximity
to the forest areas for the wildfires in California
and our Pittsburgh Converter Station is located closer
or closest to some of these fire risk zones.
So approximate to the tier two high fire threat districts.
We're still not located in any Wildlands.
So next slide.
But we are located close
to some proximate vegetative fields,
the marshlands located behind us
and to our West.
On the next slide, we have a more zoomed out view
which shows our proximity to those vegetative fields
and then also the nearby residential communities.
Next slide.
We're also taking into consideration our location
in the Bay Area in our proximity to seismic fault lines.
We're located near several faults that run
through the Bay Area with the San Andres fault being out
in the San Francisco Peninsula,
but the Hayward, Diablo, and Greenville Fault.
And so although unlikely,
we do wanna take into consideration
that seismic activity could be a precursor event
that causes an ignition.
Next slide.
I think here, I'll turn it over to Lenneal
for our overview of our FMLA process, which is similar
to the one used by Horizons West.
Lenneal: Thank you, Michael.
And just for realizing that I'm standing
between everyone and lunch, I will skip over this slide.
As Michael stated, it's very similar to the process
that Horizon West utilizes for risk assessment
of risk assessment and prioritization
of the wildfire risks and drivers in mitigation measures.
So I'll skip to the next slide and discuss
briefly TBCs overall wildfire risk management overview.
As Michael described earlier,
TBC has a very limited footprint
and as a result of the assessed wildfire risk
as part of our overall fire prevention program
and operational risk reduction.
And stated here,
we've developed a site-specific fire prevention plans
and these plans are reviewed annually
by a local fire departments.
And let's move to the next slide.
I'll kind of discuss some
of our facility design construction, et cetera.
So just to highlight here, TBC's cables are all underground
or submerged beneath the Bay waters.
All of the above ground infrastructure is fully contained
within our converter station sites.
They're surrounded by 12 foot concrete walls with inward
and outward facing, security cameras inside those walls,
there's a fire lanes of matter approved
by the local department and Knox boxes.
TBC our buildings meet California Building Code.
In addition to California building
for seismic resiliency,
some of the inner infrastructure is actually designed
to meet IEEE seismic resiliency,
which is a higher than the California building code.
The electric system employs controls
which implement protective blocking
which can shut the system down within microseconds.
And so if there is a fault on the system,
the system will trigger an immediate shutdown.
Below that, you see there's a list of some
of the incremental hardening projects
that we've undertaken upcoming years.
So that's transformers, seismic pads,
we're increasing the resiliency of our transformers.
We've got eight transformers at each sites.
We are adding some fire suppression capability
to some of the auxiliary buildings that we have on site
in Pittsburgh, including additional thermal barriers
for auxiliary rooms.
Next slide, please.
Thank you.
In this slide, you see a description
of our maintenance practices.
We conduct weekly and monthly inspections
of our facilities.
This includes sidewalks, inspecting cable vaults.
And we also, on the next page, I'll discuss
we have real-time monitoring of our cable,
which includes the ability to monitor and pass dig notices.
So we've got 24 seven real-time monitoring of our cable
and of the system through our human machine interface.
Operational practices, there's a number
of our fire prevention and emergency policies
or hot work fire safety program and all operators
and engineers receive training on all of these procedures.
Next slide, please.
Thank you.
I kind of hit earlier on some of the situational
and conditional awareness capabilities that TBC has.
And last week, just the response and recovery,
one of the things that I like to highlight,
this year, we purchased class B foam trailers,
which are designed to fight
and suppress transformer oil fires.
So that's a capability
that local fire departments did not have
and so TBC purchased two trailers.
There's both at our Esrello and our Pittsburgh site.
So those are on onsite for depression
in case a situation arises.
And other than that,
I think kinda high hit all the highlights I'd like to.
So thank you much for this opportunity to present
and that's all for us.
Thank you.
Michael: Yes, thank you.
Andy: Great, thank you so much, Lenneal and Michael,
and thank you also to all of our presenters
that we've had so far as to fit a lot of material
within 10 minutes, it's understandable over.
With that, we'll meet back here at 1:30 to go
into the Q&A session.
And apologies for eating a little bit into your lunchtime.