Amy: Off the list so that we shouldn't have
any potential risks and the need for a PSPS here.
And so I think the PSPS specific plan, hopefully,
kind of guided or could guide you
or give you insight into our thought process there.
I would say on the flip side,
as far as whether or not our grid hardening initiatives
and how far we are along and where we've deployed them
impacts the decision-making.
And I think the goal is to always mitigate
the potential for PSPS as much as possible.
And when we do have, once we've completed
all the different grid hardening activities in an area,
the goal is to not need the PSPS events anymore.
Obviously, as things change and our risk modeling changes,
and climate changes, it doesn't mean it always goes away,
but at least the way we know it now it should go away.
Until you get to that point, until we can make sure
all the boxes are checked, if you will,
and we've mitigated all the different risk drivers
in an area, it's challenging to say you don't need it.
And so that is where we start to rely on our PSPS protocols.
And I think there's a decent amount of information
in the filing and the other filings.
But that's where a lot of those weather thresholds
come into play, is we are kind of looking,
when we evaluate the decision, we are looking at
how far along are we in our hardening activities?
Are we complete? Are we not?
Do risks still exist?
So I'm hoping that kind of answered
your two-fold question, Andie.
Andie: Yeah, that was great.
Thank you so much.
If we could get a response from Liberty,
and also, specifically for Liberty is,
I was wondering how you identified
where to locate resiliency corridors as well.
Dylan: Yeah. Thanks.
Those are good questions.
So I'll address your first two questions first.
Primarily a lot of the initiatives
that we're undertaking are brand new.
We've got a couple of years of experience
under our belt with how these can really affect our system.
What level of resiliency do you really get
and risk prevention do you really get from these initiatives
is still really being evaluated.
So, the PSPS risk isn't necessarily
something that we've quantified yet.
So I'm still speaking at a fairly high level.
However, speaking at a high level,
we do look to increase initiatives that reduce
both the scope and the duration of PSPS events.
For example, adding increased sectionalization,
increased weather stations for situational awareness
of actual weather conditions is
something we're really working on.
But we haven't really quantified
what level of PSPS reduction that
that can actually have yet just because this is so new.
And then conversely, how does grid hardening initiatives
inform our decision-making for PSPS?
And I would kind of echo PacifiCorp's response here,
it's hard to say, without all these initiatives complete,
that you don't need the PSPS.
So, you try and mitigate most effectively
the most risk reduction you can get in an area,
but maybe there's still a piece of hardware
or something that gives you pause about an area.
And without having that full blanket,
entire risk reduction, it's hard to say
how much we can really reduce the PSPS events,
in the near future at least.
And then lastly, on resiliency corridor selection.
So for the first project that we actually proposed
in our 2020 wildfire mitigation plan,
we kind of had a slam dunk project.
We've got 12 megawatts of diesel generation
in our Kings Beach area.
And that, with a short span of covered conductor,
we can get from that diesel generator
to the downtown Kings Beach area.
And we don't like running the diesel generators
all the time, but in a PSPS event,
it's certainly called for.
And so just to have that, islanded microgrid style area
is really, really pretty low risk for us.
So that's the only project we for sure
have going on right now, but we're expanding
some analysis to other areas,
maybe something like battery banks
or smaller mobile generators or something of that sort,
to see if we can do similar projects in,
like our South Lake Tahoe area, for example.
Andie: Thank you so much, Dylan.
And then to move on to Bear Valley with Paul.
Paul: Yeah.
So, in grid hardening,
sectionalization is a quick way
to reduce the impact on PSPS.
And so that's something that we did right away.
So, that doesn't really solve the issue
for those on the downstream end of that switch.
And so projects that are, the covered conductor projects,
the fuse replacement projects, pole hardening,
getting the wood poles replaced that are strengthened,
making sure it all poles meet our requirements.
Those all are grid hardening factors that go into
getting rid of the PSPS or the need to have one.
So those areas are prioritized.
And then the other thing is more of a dynamic thing
that looks at, we look at how many,
for each circuit, we evaluate how many
outstanding level two discrepancies are there per,
as defined in G.O. 95, and that contributes to the risk
for if you do have any, we shouldn't, that's our goal.
We don't want to enter the fire season
with a bunch of level twos.
And we also, you lose, it elevates the risk
if you have level ones, that should always be zero,
since those are immediate fix items.
And they're either fix them or get them
to a point where they're level twos.
But, it is an input to our model so that we have
that dynamic on the actual condition of the circuit.
Andie: Okay. Thank you so much, Paul.
With that, I'm going to move to the stakeholders.
I see that neither Greg nor Zoe,
neither of you have your hand raised.
Did GPI have any questions?
Zoe: Thanks. Sure.
I can go real quick here.
This is Zoe Harrold with Green Power Institute.
So my question is, for the SMJUs,
do they have a sense of kind of a grid hardening threshold
or end goal that needs to be reached
for these different mitigations?
So like covered conductor, say, 80% coverage,
to be able to raise the PSPS threshold,
or a threshold for sectionalizing,
that they kind of have this as an end goal in mind?
Thank you.
Amy: Sure, that's a great question.
I think, as it pertains to the PSPS zones
for covered conductor, realistically what we're trying to do
is within those, I'm gonna say electrically connected areas,
things that we can isolate, the goal is within there,
and by isolate, I mean kind of thinking about
circling the PSPS areas, the high risk areas,
and saying everything in here is really high risk.
The goal there is to have covered conductor everywhere.
But then once you get outside an area
where you can sectionalize, maybe you don't need it.
So I think for PSPS, we're looking
to kind of include the entire thing.
But now that doesn't translate
to the entire service territory.
So that's something very different.
And once you get past, I'll say, the extreme risk area,
if you think about the way we're deploying
our grid hardening initiatives,
once we get past that first extreme risk area,
I don't think we know the answer yet.
I think we're waiting to evolve our risk model
a little bit more to say that,
past that first step do we need it everywhere?
Is it 80%, like you talked about, is it 10%,
is it a combination of different initiatives?
I think that's where it's tough to say
what the future holds.
But for us right now, within those extreme,
extreme risk zones, which are our PSPS zones,
we're looking to include covered conductor
everywhere within there.
Dylan: This is Dylan with Liberty.
That's a good response, Amy.
I'd say, largely our bottom line goal is,
what is the most cost effective and overall effective
mitigation solution for any given area.
To us, the answer may not be covered conductor
all the time in our highest risk areas.
For example, there are some areas
where micro grids might make a lot of sense.
If you can say, for example, we've got
four miles of uncovered distribution line
going through a very high fire threat area,
but you can, the loads at the end of the line,
you can take that four miles out or decommission it
or de-energize it during fire season
and just do a microgrid at the end of that line,
that might end up being cheaper
than covering the conductor of the entire area.
So that's a big feasibility analysis.
we're undergoing at the moment,
with the end goal of just,
we don't want to subject our customers to PSPS.
It's probably a point of diminishing returns.
Like you can get 90% of the mitigation for X dollars,
but you can probably get a 100% for two X dollars.
And what is that threshold that's worth spending?
What return on investment are we getting
for the customers there?
And I think the bottom line here is still
our risk modeling is still in its infancy, definitely.
And as we continue to gather more data, quantify
the effectiveness of these various mitigation numbers,
I think we'll have a much, much better idea
of what a fully baked solution looks like.
Paul: So, I think if,
like, for example, covered conductor would definitely
bring the threshold level to extremely unlikely,
I think I would say, that we'd do a PSPS.
And I think we can tell customers that,
that we'd get covered conductor.
Now we're really only looking at scenarios where
the three second gust threshold
exceeds the design of the system.
And those designs are set in G.O. 95
and our own company standards.
Those are uncontrollable events,
but if we were to get those, those would be extremely rare.
'cause the design margins are set that
we shouldn't really experience those,
but those would be the only cases where
I think we would be deep concerned
if we were expecting that kind of situation.
-: Thanks so much. -: Thank you, everyone.
Andie: So, yeah, did that answer your question, Zoe?
Zoe: It did, thank you.
Andie: I did have one
clarification question for PacifiCorp.
I was wondering when you've mentioned installing
covered conductor on all of it,
when you talk about the threshold for that, is it like,
would you consider a higher wind speeds
before considering a PSPS?
Or is it excluding it from PSPS consideration at all?
Amy: I think that's a good clarification question, Andie.
I think at this time, our expectation is that
it will influence the threshold.
And then, I think as Liberty kind of described it,
we want to get a little experience under our belt
before we say, oh, and now it's gone from higher threshold
to I don't need it at all.
And one thing, and I probably should have clarified this
when I was speaking before, when we're talking about
installing covered conductor,
it's not just the covered conductor,
it's kind of the full suite of the hardening initiatives
and the way they pair together and they stack,
that they match with all of our risk drivers.
So there's that component as well.
So when I'm saying covered conductor,
I'm thinking all the bells and whistles I need
on that circuit to mitigate
all of the different risk drivers.
But I do think it's, there's probably an intermediate step
where we say, hey now we're looking at different thresholds.
Now we're getting more confident
that the results are really coming back
that these risk events are disappearing.
We feel as though it is very low,
and then I think you do move to don't need it.
I don't have the crystal ball on what exactly
that looks like or when, but I do think that has to be
kind of the vision and our eventual target.
Andie: Thanks so much, Amy.
Going into Cal Advocates' question, with Henry Burton.
Henry: Hi, thank you.
So I have a question for all three utilities.
We haven't talked a lot about inspection in this session,
but I wanted to ask, are you doing aerial inspections,
either by drone or helicopter,
for your distribution infrastructure in HFTD areas?
Or do you foresee starting to do aerial inspections?
And just talk a little bit about your thinking
on the relative value of aerial
versus detailed ground inspections.
Thanks.
Amy: Sure. Hi, Henry.
Henry: Just to clarify, I'm talking about distribution.
Amy: Just distribution, okay.
That's helpful.
So for distribution right now,
we don't do any programmatic aerial inspections.
We do on the transmission side,
but not on the distribution side.
I know we've dabbled around in it a bit
and the company does have,
they've set up kind of a drone management program.
We haven't yet thought about it in a programmatic way.
And one of the reasons is, right now,
not to say things can't change,
we tend to see more ground line failures.
We tend to see more conditions and flaws
that can be viewed from the ground.
We don't tend to have a ton of the pole top failures
at this point, not to say that trends can't change,
but there just hasn't been a strong justification
at this time to stand up an aerial inspection.
But obviously we all know the risk landscape is changing,
and as electric companies, we have to change as well.
And so I know that is something we're starting to consider,
is are there drone applications
on a more routine basis that could benefit us.
But I just don't quite have the answer for you yet,
but we are thinking about it.
Dylan: Yeah, Liberty's largely the same.
We've investigated doing some drone level inspections
on distribution level voltages,
but we haven't programmatically deployed anything to date.
We really focused this past year on just improving
our traditional ground-based inspections,
and we feel that we've made great strides in that area.
And additionally, with some of the aerial inspections,
just getting a drone in the right place
with lots of vegetation in the area can be difficult.
So yeah, bottom line is we're exploring it and do not have
an aerial distribution inspection program to date.
Paul: So for Bear Valley, like I said,
we did beef up our ground patrols.
We did implement LiDAR.
We've done now, in 2019 and 2020,
we did complete LiDAR surveys.
Those use both ground mounted LiDAR devices and some drones.
And we just, last week, put out a RFP for a UAV program,
to do an annual UAV survey before the fire season.
We're looking at the HD imagery as well as thermal imaging.
Our team had an opportunity about a year ago
to visit Southern California Edison's, one of their centers,
where they showed us the value of the UAVs.
I do see a lot of value there,
it's just how much we can do at once.
And now we're at the point where we can certainly,
I think, go to that next level with the UAVs.
It gives you a good geo location and it gives you,
it's incredible what you can't see from the ground up,
when you look, compared to what you see from the sky down.
And so we do see a lot of value there
and we're looking forward to doing the aerial surveys.
Henry: Great. Thank you.
That's helpful.
Andie: Okay, so next up we have Will Abrams.
-: Thanks very much.
I had some questions around quality assurance processes,
'cause I didn't see that touched on
too much during the presentation.
So I was hoping you could talk to
what are your current quality assurance processes?
What are the current quality control tools
that you use to ensure your work?
And if you can also talk to sort of
your staffing limitations around that as well
and how that's structured.
Do you have a quality assurance department?
What's the training and what's the level
of the subject matter experts that you have in those areas?
Andie: All right, so before you answer,
Will, I just wanted to clarify, did you want the ATOs
to respond to that as well, or just the SMJUs?
-: I'm open.
I think, to whatever degree folks feel that they have
answers to that question, to the entire group.
Amy: Okay. I'll go ahead and start off for PacifiCorp.
I know we touched on it a little bit in the slide.
It has been a focus area for us this year,
based on some feedback received,
to make sure that we're reporting on
and talking about and presenting on our QA QC processes.
So for our inspections, we've got a couple of different ways
we introduce these controls.
So the first is, we actually have built into
some of the contractor work we do,
that they have a staff person who does quality controls,
QA QC of their inspections, so by the time
the inspection results make it to PacifiCorp,
there's already a decent level
of quality assurance that happens in there.
So then the records make it into our system
and we've got kind of two areas we attack.
One is the physical site auditing,
so where we're going out and trying to understand,
do our inspectors understand?
Are they capturing violations correctly?
Are they categorizing fire threats correctly?
Are we giving them the right priority
to make sure we work the correction correctly?
So there's the physical side.
And then there's, I'm gonna call it the administrative side,
so making sure that when we get records coming in,
that they match policy, that they match,
because we have a way that we categorize findings.
And so we're making sure the categories make sense,
'cause those categories dictate how we plan and do work.
And so where the data comes in wrong
it means that we have the potential
to get off track on how we correct them.
So those are the two fronts we attack
after the kind of pre-qualified inspections come in.
And I think I touched on in the presentation,
the field audits, the physical piece usually sits around 5%.
I think last year we were a little bit higher,
actually 7% is what we were able to audit.
And then the desktop audits combined
with the contractor and internal, we tend to sit around 50%.
There's a third layer that is new
that we've introduced a kind of a weekly tool that we have
that looks for, I'm gonna say data mismatches,
but it looks for a record that doesn't match policy,
or a priority that doesn't make sense.
And that's kind of a third element we've implemented
on a weekly basis to kick records back to the inspectors
to make sure there isn't something deeper going on.
The nice thing about packaging all of this as a program
is we're feeding it into our annual training,
which has been really helpful.
And especially with that weekly report we're able
to actively train throughout the year on our inspectors
to make sure they understand the requirements.
So that's kind of,
it's kind of a couple of different fronts.
I hope that touches on kind of our QA QC processes.
As far as the people involved,
so I think I kinda mentioned we have some that are,
ones that are integrated into our contract.
We also have a team called field inspection support
and we've got strategic folks placed all around
our service territory that do the follow up field audits.
They're experts in electrical code.
They really closely manage those contractors.
And so that's a large function of what that team does.
And then we have a central team,
asset management and work planning,
that do the more kind of desktop work
to make sure corrections get facilitated.
So it's not one specific department which is,
can be challenging for us with these programs.
We don't have a specific QA QC department.
We've got kind of some resources
within all of the different functions that play a part.
Hopefully that answered your question.
-: Thanks very much.
And are those folks that are trained in quality assurance
or are they sort of folks that have
the electrical engineering experience?
-: That one.
-: And sort of executing on the QA,
as opposed to a quality assurance
or risk management professional that would be,
is that how that works?
-: Correct. Yes.
Yeah. We don't have an on-staff,
kind of quality control or risk assessment person.
It's more folks that are trained in electrical components,
electrical code, experience in program management,
things like that.
The expertise tends to be on the technical component side,
if that makes sense.
-: Thank you. -: Yep.
-: So, for Bear Valley, likewise,
we don't have a QA department or QC department.
It depends on the type of work being done.
In the next section,
we're gonna talk about vegetation management.
We do have a formal vegetation QC program
where all supervisors, managers,
including myself and certain other designated people
who understand what they're looking at and are trained,
go out and do, we do six QCs per month.
So it gets everybody out in the field
and keeps our contractor on its toes.
And so to me, that's essential.
So that program, and it has very specific attributes
that they look for in completing that QC.
For T and D type construction,
it's actually part of our invoicing procedure.
So we have a field inspector who goes out
and verifies the work is completed per the work plans.
And the material that was pulled was actually used
per the work order or for the specifications
before that invoice proceeds to the next level.
So, QC sort of happens that way for those types of projects.
And then when you get some more complicated,
like a substation, we do bring in a third party
to do testing and commissioning.
So that it's not the company that constructed it,
but it's an independent testing and commissioning group.
So we get the QC there.
-: Thank you.
-: This is Dylan, with Liberty.
I'll jump in really quick.
So we do have, we're going back through our system inventory
and inspection records with our own internal inspectors
who are qualified, trained linemen,
very familiar with line construction
to make sure that the contractors that we're using
didn't miss anything crucial.
We're not going through every record,
as any audit would not do,
but we are performing a level of QA and QC there.
And so that's done by a qualified and trained workforce.
But we are certainly seeing workforce limitations
within that department and willing to expand
with a set of qualified contractors.
And then secondly, Bear Valley kind of mentioned this,
but we have started implementing a G.O. 95 checklist
for new construction and making sure
that everything is built to the design and built to code.
So, that's another approach we're taking
as far as QA QC within our grid hardening initiatives,
as well as the inspections.
Thank you.
-: Thanks.
And I guess given the limitations around resources,
I'm wondering if folks have explored
the possibility of a mutual assistance agreement
or things like that to sort of help with,
I guess, getting that specific QA subject matter expertise
more in house, have you explored
sort of collaborative ways to fill those gaps?
Sorry, I don't know if that's a follow-up question
that's allowed, but that's throwing it out there.
-: I'm sorry, Will, I may ask you to repeat it a little bit.
So it's around kind of sharing the resource
amongst utilities or having kind of
backup contractors ready to go or?
-: Right. Yeah.
No, I just, I understand, that there are limitations.
You have more resource constraints then the larger IOUs
and therefore don't have sort of a bank of QA professionals
and a lot of structure around that.
And so, I guess I'm just wondering
if there are ways to collaboratively fill that gap,
through like a mutual assistance agreement,
where you have some shared resources
or sort of can build some of that expertise.
And if you've explored ways to do that,
sort of I guess more creatively than actually
just hiring QA professionals which might be
more cost prohibitive than for others.
-: Okay. Yeah, that helps clarify.
I would say at this point I don't know
that we've investigated specifically
what you're talking about.
Where we benefit, at PacifiCorp,
is our California service territory is very small.
But we do have a larger workforce that we can rely on
in times like this where you have significant peaks
and troughs in the requirements.
And I can say specifically in the inspections realm,
we have had to pull resources in
from the other states where we work.
So I think because we have that kind of,
almost a natural built-in pipeline,
we haven't had to do what you're talking about.
Not to say there wouldn't be value
in what you're talking about, in collaborating,
whether it's just throughout the industry
with other utilities to have this extra resource to rely on.
I don't think we've experienced that,
that significant shortage yet,
just because of the unique position we're in.
But that is certainly something we should be thinking about.
-: Thanks.
-: That's a good question.
I don't think Liberty has specifically explored
that as a possibility.
I can certainly see the benefit of sharing resources
where they are constrained,
maybe not with the people in the room
but with neighbors potentially to our east and west.
So we'll take that as a potential follow up
and see if there's merit within that suggestion.
Thank you.
-: Thanks.
-: Yeah. So it sounds like a good idea.
There are challenges to execution.
We're in very different geographic locations.
There would also have to be some very careful
cost allocations, so Liberty's ratepayers
aren't paying for Bear Valley work and vice versa.
So there are some challenges that would need to be resolved.
I'm sure those could be surmounted
if the benefits certainly outweighed the,
all that has to be done.
-: Thank you.
Andie: Did Horizon West or Trans Bay Cable
want to speak to their quality assurance,
quality control programs?
Alona: Hi, this is Alona Sias with Horizon West.
So we don't have quite the same resource constraints,
given our footprint.
So specifically for Horizon West,
for inspections we have dedicated operations
and dedicated highly trained operations personnel
who conduct those inspections.
And then in addition to that, we have
our senior director of operations review
and monitor and audit those inspections results,
just given that we have only one asset.
So we're able to do that, given our scope and our staffing.
Lenneal: And this is Lenneal Gardner for Trans Bay Cable.
Similar to Horizon West, TBC maintains a workforce
of operators and engineers that are skilled
and trained on conducting similar inspections
for our limited footprint of facilities.
And there's an operations director and engineering director
who have that overall QC responsibility.
Andie: Thank you so much.
Yes, it's definitely a lot easier
when you have less facilities.
With that, Ryan, did we have any questions from the chat?
I know I see the one from Leigh.
I'm not sure if you got any others?
Ryan: Yeah. That's it, Andie.
And I'm happy to happy to read it out.
Andie: Sure, yeah, that'd be great.
Ryan: Great.
So again, this is from Leigh Kammerich.
Will Liberty develop or explore an undergrounding program
outside of Rule 20A projects?
Rule 20A primarily focuses on beautification
and is not initiated for safety purposes.
The WMP acknowledges there are RSCs in place,
but undergrounding is not included
as a mitigation initiative or objective goal for the future.
-: Yeah. So I can speak to that.
In general, we don't have one today.
You've read the WMP and you can see that.
So what we found with undergrounding projects
is we run into significant, significant permitting issues
with local agencies in our area,
and it just becomes cost and timeline prohibitive
to the majority of these projects.
The Rule 20A ones we are doing under that Rule 20 program,
but even within those, we have a handful of pending projects
that we have tried to permit for two, three, four years,
and just hit significant roadblocks.
So it's really not something we've explored
at a grand scale because it's so difficult to accomplish.
What we've found is covered conductor is much easier
to implement, reusing existing right away ways
and in some ways, in some cases,
you can reuse existing poles.
It's much more efficient to deploy
and cost-effective as well.
Andie: Okay. Thank you so much, Dylan.
To sign back off with wildfire safety division,
this is again, mostly for the SMJUs.
And I know you touched on this a bit
during your presentations,
but just wanted to get more specifics
on how increased inspections differ
from routine inspections in scope and content?
And also was wondering how you were measuring
the effectiveness of utilizing increased inspections
in comparison to routine inspections?
-: Sure. Another good question, Andie.
I think, so for increased inspections,
maybe I'll clarify, I'm assuming you mean
enhanced inspections or inspections
we weren't historically performing,
not just a volume uptick of standard inspections?
Did I get that right?
Andie: I was looking specifically for anything
outside of the G.O. 165 requirements.
-: Okay.
Okay, great.
Then I think for us our best example,
we probably have a few,
our best example would be the I.R. inspections.
So there was a half slide on, so not very much.
There is a section in the WMP that does provide
a bit more information if folks are looking for
details of the program evolution,
what is the scope, what are the objectives.
A key component for us there is making sure
we set up that program management,
which was a pretty big effort in 2020.
So that now in 2021, we can track things,
like when exactly did we find conditions?
What were the conditions like?
We're assigning them kind of different data fields
in our system so we can extract them.
How many line miles did we fly?
And so what we're able to do now,
which I think is what you're getting at,
is how do I measure effectiveness
or measure if it's working,
is we're at a point where we can say,
how many line miles did I inspect?
How many things did I find that potentially pose risks?
What were the costs?
And we actually look at cost per finding
and cost per mile associated with that program.
And then we can compare to our traditional programs
and at least show, yes, there's value.
If there is value, is it more, is it about the same?
And also kind of tie that value back
to the risk drivers that Heide presented this morning.
So making sure that the things we're finding
are the things that tend to get us in other areas.
And so that's kind of, that's probably my best example
to provide on how we're implementing
these enhanced or additional inspections
and then how we're tracking effectiveness.
-: Thank you for the question.
So as of today, Liberty is not proposing
increased inspection timelines on any of our assets.
However, it is something we are strongly considering.
I would like to point again to the really important strides
we made in 2020 in refining our inspection process.
And we did actually inspect
the entire overhead system within 2020.
So, in some regards there, we actually did
perform inspections with increased frequency,
'cause some of those circuits were just inspected last year.
But I think we're kind of waiting for our risk mapping
and modeling to really identify,
is there increased benefit in inspecting the circuits,
for example, within high or very high fire threat areas
with an increased frequency?
And what does that buy us, exactly?
And then past that, as far as new technologies
we're investigating for inspections,
we are actively investigating both drone
and infrared technology,
integrating that into our G.O. 165 inspections.
Thank you.
-: So, I think inspection is actually low cost
when you compare it to what you're potentially preventing.
For example, for us, a LiDAR or a UAV
or a second ground patrol is probably on the order
of about 100,000.00 per year per type of inspection.
That's fairly low cost to compare to a major failure
or a, God forbid, a wildfire.
So definitely worth doing, worth pursuing.
I think as all the utilities have gone through this process
and we've all sort of matured on the inspection front,
I would say that pretty soon,
the G.O. 165 is probably ripe for a revisit
on what the minimum requirements are.
I think everybody would agree
that if you were just doing what G.O. 165 specifically says,
you're not anywhere close to where you should be.
So there is a lot of value in bringing
all these inspections together and certainly,
it helps avoid issues that you just don't want to develop.
Andie: Thank you.
Just for clarification,
does Bear Valley currently do anything,
outside of the G.O. 165 requirements?
-: Yeah, we do LiDAR.
We do a second ground patrol inspection.
And we're adding UAVs, HD imaging.
We've done thermography.
So we go beyond what's the minimum requirement there.
And now we're looking at also increasing the periodicity
of detailed inspections on higher risk circuits.
Andie: Thanks so much
Back to GCI, it looks like Zoe has another question.
Zoe: Yeah, thanks.
So for the SMJUs, can you talk a little bit about
if and how you're proactively assessing
and replacing aging equipment?
And if that process is informed
by data or risk driven assessments?
-: Sure.
So I would say right now we do mainly,
I'm gonna call it condition-based replacement.
So driven more by field inspections,
on-site work, noticeable changes
in the quality of the power potentially,
due to outage investigations, things like that.
We are exploring ways to do more,
I would say predictive modeling.
So whether it's through some sort of asset health assessment
or a carry over from the wildfire risk modeling efforts
that are ongoing, is there a way to get
ahead of the game a little bit and catch things
before there's noticeable deterioration?
I know that that is certainly something
as a company we want to do.
I just don't think we're quite there yet,
to say that I know exactly when to replace
that widget on that line because data tells me.
But I think we're working on incorporating things
like inspection findings, power quality,
age, manufacturer, applications, how am I operating it?
To try and get us eventually to some sort
of predictive model.
I just don't think we're quite there yet.
Hopefully that answers your question.
Zoe: It did. Thank you.
-: So, yeah, we're largely in the same boat as of today.
All of our asset replacement is done
based on inspections, essentially.
We do have in the past year really started prioritizing that
with our risk mapping and modeling,
all of the condition codes for different failures,
not failures, but issues with equipment,
has an associated fire risk zone as well as HFTD.
And we are prioritizing based on that information.
And then lastly, as far as the asset health evaluation,
with the DFA technology, we are really hoping that
that's kind of at least part of the answer there.
That's pretty tough stuff to evaluate
the condition of every piece of equipment,
based on anything other than a visual inspection.
But, yeah, the distribution fault anticipation technology
should be able to identify some of those incipient failures
and help prioritize that work as well.
Thank you.
-: I think we're condition-based for replacement of assets.
I don't really know of any age based type programs.
I do know that when we do go out
and work on a system or a series of poles,
we may bring that whole system up-to-date,
so that we don't have to keep going back
out to that one particular area.
It's more efficient to do it that way.
But we don't say, oh, we're gonna target these items
because it hits this value in age.
Zoe: Great. Thank you, everyone.
Andie: So we've got around five minutes left.
So I think enough time for one more question.
Henry with Cal Advocates, you had another one.
-: Yeah, that'd be great.
So this question was mainly intended for PacifiCorp.
At PacifiCorp it looks like was not able to install
as many miles of covered conductor
and as many pole replacements in 2020
as had been forecast last year.
Can you discuss how the 2020 fire season
affected your system hardening work
and how you've built that type of issue
into your planning going forward?
How have you accounted for disruption due
to fire season or other kinds of natural disasters
in your wildfire mitigation planning?
-: Sure.
There's kind of, it sounds like there's two components
you're interested in, the pole replacements,
as well as the implementation of covered conductor.
And so first I'll take the pole replacements.
I think in previous years of the plan
we had been a little bit light on a full scoping,
so weren't sure the specific details.
And so a lot of our annual phasings were estimates,
very educated estimates, but estimates.
We have actually made a shift change in that area
where we are targeting pole replacements
coincident to covered conductor programs,
and waiting to phase in the pole replacements
in lower risk areas later, which is kind of why,
if you saw on the slide, you see the pole placements
are kind of light and then they ramp up later.
So that one's a little bit of a program shift,
as well as a little bit more of a program shift,
I would say, and a philosophy shift,
than a lagging of completion.
On the covered conductor, I think, honestly,
I think our main hiccup there is, you are correct,
we have not done as much as we'd hoped for or planned for.
I think for us, we underestimated some of the challenges
and they're the types of challenges Liberty brought up,
the challenges with engineering and designing a new spec,
the challenges with how are we gonna maintain
this new equipment, especially when it's deployed
so regularly throughout.
It's that change management piece.
And what that's done is it's really changed the pipeline
that it takes and the timeline to deliver those projects.
And so that was an unfortunate hurdle, I would say,
we didn't see coming in that way.
Changes that we've made,
I think the big part is recognizing that.
We have brought on more engineering resources
to help with the engineering and the scoping
and the startup efforts to really
get those projects kicked off.
We're requiring, it's a fairly linear process
before we get to where we're actually
procuring materials and constructing.
And I would say the positive is,
I do believe right now we're forecasting
that we can catch up this year.
So while we weren't able to do what we wanted
to do last year, right now, we're planning to play catch up
and trying to deliver just over 80 miles this year.
And that is what we've brought on
those engineering resources for, to play catch up.
So I think for us, it was as much of a,
really fully understanding the process and what it takes
to put these new projects in.
And I think we underestimated that effort, to be honest.
Certainly we had some other disruptions throughout
the year that that made us change some things.
But I think really the core issue
is understanding what it takes.
I think we underestimated that a bit.
-: Okay. Thanks.
And if we have just a moment, real quickly,
it looks like from your plan, the cost per mile
for your covered conductor program
is around 180,000.00 to $230,000.00 per mile,
if I'm looking at the numbers correctly.
Is that correct?
That's much lower than what the larger utilities
are expecting as unit cost for covered conductor.
-: I'd have to pull up the plan that,
it sounds like the right order of magnitude.
I'm not sure of the specifics.
So I might to check with some folks.
It does sound less than what the other utilities put forth.
I'm trying to remember if we've done that full calculation.
It could be slightly different scope though.
So I would want to,
before I commit to this being exactly it,
I would want to do some checking to not lead you astray.
It could be that our covered conductor replacement
doesn't always include full pole replacement,
but then always include
some of the other bells and whistles.
As kind of similar to what Liberty is talking about,
the reason it's a nice technology to deploy quickly is
that sometimes you can use existing structures.
But I'm not sure is if that's driving the difference,
but that could be a driver of the difference in unit cost.
And I think maybe, I think around, for us,
we see about 10 to 15% pole replacements,
where some utilities may require 100% or 80% or 50%.
But that certainly can make an impact.
-: Okay. Yeah.
That could be a factor.
But just the order of magnitude sounds correct to you
that you're talking about something on the order
of like 200, less than half a million dollars per mile?
I do think that seems like the right order of magnitude.
I want to check and make sure.
But less than half a million makes sense.
Yeah, mm hm.
-: Okay. Thank you.
Andie: Okay, and with that,
we'll go ahead and take a break
and catch back up with Vegetation Management after.
Just wanted to give a thank you to all the panelists.
This has been extremely informative.
And also a thank you to stakeholders
and for asking great questions.
So we'll resume at 2:30.
(upbeat music)
-: My name is Colin Lang.
I am the Environmental Scientist
with the Wildfire Safety Division.
I have the pleasure to moderate our discussion
this afternoon, concerning Vegetation Management.
Vegetation management can both reduce
wildfire ignition and consequence risk.
It involves planning for both
the canopy surrounding overhead lines
and the understory in and around the right-of-way.
Landscape structures modified by colonization
and our changing climate have made
vegetation management efforts challenging
and require land managers and utilities
to constantly adjust to the present,
sometimes unprecedented, conditions.
In the past few years, utilities have increased
the scale and scope of their vegetation management programs
to address these issues.
Just like before, in round three,
we'll hear from the PacifiCorp, Liberty, and Bear Valley
about their vegetation management plans.
And then we'll have a short five minute break,
followed by a question and answer panel with our presenters.
So first up is PacifiCorp.
Brian: Hi, this is Brian King with PacifiCorp.
I think the presentation that is showing is different.
It is not the Pacific Power presentation.
There we go. Thank you.
So again, this Brian King
I'm the Director of Vegetation Management
with Pacific Power.
I'll provide a very high level overview
of our vegetation management accomplishments in 2020
with respect to our wildfire mitigation plan,
as well as general vegetation management program,
as well as some areas of opportunity,
areas that we're looking into to implement improvements
and investigate further, including additional technologies.
And Heide Caswell will speak to some of the pilot projects
that we are currently implementing
or have implemented with respect to technology.
Next slide.
In 2020, Pacific Power conducted
what I'm calling readiness patrols.
So these are patrols that are incremental to our inspections
in support of our scheduled routine maintenance work.
We conducted these readiness patrols on over 1,100 miles
of transmission and distribution lines within HFTD
prior to the height of the fire season.
So this is a large effort in addition
to our routine maintenance activities that we completed.
We continue to work on reducing
our high risk tree inventory.
So we continue to identify and address
our high risk trees along our power line corridors.
In 2020, as an area for opportunity,
we started to identify trees that we call cycle busters,
or those are the very fast growing trees
that may not hold for an entire cycle.
And in collecting that information,
which we can utilize in the future for opportunities
or identifying future management opportunities
with respect to cycle busters.
So we just started collecting that information in 2020
and are starting to build that database.
We cleared vegetation around poles,
incremental to our regulatory mandated
pole clearing projects, so over 2,000 additional poles
were cleared within high risk fire areas.
We continue to apply herbicides and tree growth regulators.
So this is an integral part of our vegetation management
to control tall growing and fast growing species,
respectively, as part of
the integrated vegetation management.
And we also, in addition to conducting the inspections,
those readiness patrols, for over 1,100 miles,
we conducted and addressed any correction activities,
so corrected and addressed
those vegetation management conditions
that were identified during the readiness patrols,
in addition to our routine maintenance corrective actions.
And we also conducted post-audits of all work conducted,
as identified in the routine maintenance
detailed inspections, as well as readiness patrols,
to ensure all work was completed to company specification,
and that adequate clearances were achieved.
Areas where we're looking for improvement,
or opportunity areas.
We've implemented, in 2020, the rollout of a new
electronic planning, mapping, record keeping system.
This is so our folks out in the field
can utilize handheld tablets to record information,
the work, identifies the work that needs to be conducted,
and then our tree contractors who perform the work
also can then record work completed utilizing tablets.
And so we have an improved tracking system.
We're continuously fine tuning our system.
As mentioned in 2020, we started identifying
cycle buster trees as well and have the opportunity
to collect different types of data.
So we're continually refining our approach
and how we're using that data and collecting that data
to help inform additional components of our program,
for example, tree growth regulators,
as well as identifying tree cycle busters.
We can then have an inventory
where we can potentially identify
the use of tree growth regulators
on those cycle buster trees to better manage
those fast growing tree species.
We continue to partner with our local agencies
for fuel reduction.
This year, we coordinated with
the Dunsmuir Wildfire Safety Council
to assist on a fuel reduction project
between the I-5 and Dunsmuir.
And we had distribution lines in the project area
and partnered with the community
to safely remove vegetation around
and adjacent to our facilities.
And we continue to look for opportunities
to partner with agencies with respect to fuel reduction.
We're implementing additional means
of identifying how to prioritize our work.
So we are developing, in addition to utilizing
just the HFTD, for example, and using that
as a means to prioritize work,
we're looking at more granularity
to refine within the HFTD other areas,
circuits, or segments of circuits that would be
of higher ignition risk than other areas
or have a higher consequence,
to help us prioritize our work.
And we're utilizing additional technology,
such as remote sensing, LiDAR, and so forth,
and conducting pilot projects
with respect to this technology,
Heide Caswell will give you a high level overview on.
Next slide.
Heide: So this is Heide Caswell.
Just adding in some pieces
to Brian's discussion around vegetation.
We've been using some of the advanced analytics capabilities
to try and bolster our understanding
of the vegetation risks that exist around our facilities.
And doing this through
a couple of different pilot approaches.
They're described in our WMP in, I think, Section 4.1.1,
where we talk about the different pilot activities.
But this, I'll go into some detail here
to try to provide some context.
We have done some remote sensing vegetation pilot work.
and this has been largely focused
on various aspects of LiDAR and using LiDAR,
as Amy spoke previously about.
as an input to equipment failure, modeling,
pole strengths, those sorts of things.
The same datasets were used to try to identify
certain aspect features that are valuable for vegetation.
So trying to leverage the cost of putting
a helicopter up in the air and the amount of post-processing
that goes with it, in order to understand
the environment around the utility equipment.
So you see on the right side,
some of the different graphics that exist there.
Historically what we had focused on
in our vegetation program was
an understanding of every circuit
and how many miles that circuit was,
whether it was overhead or not,
and obviously the overhead being the one
we were working on the clearance for.
And then kind of the run rate associated with paying
for the vegetation work that was delivered there.
So in order to start to develop
a more comprehensive inventory we started looking at
the conventionally available datasets that exist
and used the National Land Cover data
to try to build basically a proxy for an inventory,
which was used in our risk modeling tool
that I spoke about earlier,
where we then come up with a zonal canopy amount.
That is also information that's informative
for the forester, but it isn't as much as they need to have.
So what we piloted was the use of the LiDAR flights
in order to do a certain amount of vegetation segmentation
so that we'd know what was coniferous,
what was deciduous and how many trees of what sort
were within distance of our utility equipment.
We've had several different efforts on that.
And while it is, we've had good results with them,
it is not necessarily something
that is broadly applicable,
just with the large footprint that we cover.
I know that Paul's said several times
that Bear Valley is 32 square miles.
We are 11,000 square miles.
And so getting that kind of LiDAR coverage
for our service territory would come
at an extremely high price.
So instead, what we've been working with
is enhanced satellite data that Salo,
one of the subcontractors to the Pyrogence Project,
has been developing across California.
We've been using that dataset.
And I think that you can see, or hopefully you can see
in the lower, or in the graphics to the right side,
you can see what we're dealing with
in terms of the pixelation that exists there.
On the next slide you actually start to see
some of the features that the enhanced
satellite technology delivers.
And this is a discussion about the,
or the next slide shows you what we're intending
on doing in a two phase pilot.
The first phase is very focused around trees that,
with terrain considered,
and the height of that particular tree,
have a strike potential to our assets.
And that's what's shown with the little red dots
is those trees that have sufficient elevation
that if they were to fall
from whatever their position is today.
So, they could be on the side of a hill or not,
if they would fall into the line, they are a risk,
then that provides information for Brian's team
to go out and validate the health of the falling risk.
Also in that particular pilot, what we're focused on
is understanding the change in the vegetation
from a 2016 kind of benchmark year to 2020 satellite values
in order to start to understand
whether there's some capability in phase two
to do some growth rate calculations,
which then helps to feed into
perspective encroachment modeling.
And again, putting one more tool
in the hands of the forester.
So that is the short term pilot that we're targeted.
And it really is, again, trying to augment
that legacy vegetation management data
that's been, so far, with the handheld tool,
enhanced with the data that we're collecting there.
And this creates just one more,
kind of more comprehensive look at the entire landscape.
And if there are any questions later,
Brian and I will take them, obviously
Brian: Thank you, Heide.
If you'd move to the next slide.
I would believe that would be,
this concludes our high-level overview.
-: Yes. -: Thank you very much.
Colin: All right.
Thank you both so much.
We will move right along to Liberty.
Peter: Hello. My name is Peter Stoltman.
I'm the Manager of Vegetation Management for Liberty.
And I'll be providing a update on progress we've made
since filing our 2020 wildfire mitigation plan.
On the next slide slide we'll show
the programs and initiatives I'm gonna highlight today.
At Liberty, we've maintained
growth in our existing initiatives.
And we've also piloted and implemented new VM initiatives,
which I'm gonna discuss today,
including implementing our first
Forest Resilience Corridors project,
establishment of fuel management
and biomass removal projects,
and new vegetation inspection initiatives,
which are ground patrols of our Tier 3
High Fire Threat District area
and piloting the use of LiDAR for vegetation inspections.
On the next slide I'll discuss
our Forest Resilience Corridors.
What these are are multi-jurisdictional efforts
focused on tree removal and forest health.
We work with large public and private landowners
to remove hazard trees and reduce stand density along
along our utility corridors.
And for that, we established three treatment zones
for the areas surrounding our utility right-of-ways.
And Zone 1 is the area typically about 15 feet
from each side of the power line,
commonly referred to as the wire zone.
And in this area Liberty will remove all vegetation
with the potential to grow into our facilities,
as well as larger shrubs that would
add to the fuel load in the wire zone.
Zone 2 encompasses an area up to 175 feet
outside that immediate wire zone.
And we're focusing on removal of hazard trees
with strike potential and additional thinning
and fuel reduction efforts to reduce the stand density.
And in this area, the work is typically performed
as a joint effort between Liberty and the landowner.
And in Zone 3 is a broader area extending
175 feet up to 1,000 feet on either side
of that right-of-way, where additional thinning
and fuel reduction may be performed by the landowner.
So typically on these projects,
we're looking at Liberty being responsible
primarily for that Zone 1 work,
sharing the workload in Zone 2,
and then Zone 3 work being performed
at the discretion of the landowner.
So in 2020 Liberty worked with the U.S. Forest Service,
Northstar California Resort and Sierra Pacific Industries
to implement the first of these projects
on about 15 miles of the 60 KV transmission line.
And this line is a particularly critical piece
of infrastructure for Liberty because it serves
as a backup feed to our Northern service area.
So if one of our other transmission lines were to go
out of service, this line would pick up those customers.
And the picture on the slide here is one such area
where we did some zone work on our 625 line.
One of the biggest challenges in getting this work
started and kicked off was permitting.
It's very complex and challenging due
to dealing with multiple landowners and agencies
and even sometimes different departments
within a single agency that need to review
and approve our vegetation management work.
So we're working really closely,
specifically with the U.S. Forest Service,
to streamline the permitting process
and to hopefully avoid future project delays
as we continue with our Forest Resilience Corridor projects.
Also in 2020, we were fortunate to work
with the National Forest Foundation,
and they are a congressionally chartered nonprofit
that works specifically on national forests
and national grasslands to perform
and carry out land management projects.
And they had a large scale fuel reduction project
occurring on the Tahoe National Forest
where we have about three miles of transmission line
that crossed their timber harvest area.
So we were able to work with them to inspect
for additional hazard trees in the Zone 2 area.
And then we had our line clearance qualified contractors
go in, remove trees that were adjacent to the lines,
or just that their timber operator may not have been
comfortable with felling due to proximity
to our our high voltage lines.
And that was a big success.
So we're looking at more opportunities to partner
with the National Forest Foundation
on other similar projects within the Lake Tahoe Basin.
On the next slide, we'll talk about
some fuel management projects we have going on.
And so Liberty has kind of four types of projects
focused on fuel reduction and biomass removal.
Our community fuel reduction projects focus on
additional vegetation management activities
after our typical routine
vegetation management work is done.
And so what we'll do after our routine work is done,
we will go back and remove additional trees
under and adjacent to the lines
that could cause future growing issues.
We'll perform brush clearing around all the utility poles,
regardless of whether they're a subject pole or not.
And then we remove all the biomass from that project area.
In 2020, we completed three of these types of projects
and removed over 376 tons of biomass.
And we're looking to greatly expand that program in 2021.
The California Tahoe Conservancy
is a large landowner in the Lake Tahoe Basin.
They do have large properties, but they also have
several small parcels scattered throughout the area.
And with the amount of increase of work that we're doing
from our vegetation management activities,
we're starting to create an increased workload
for the Conservancy crews.
Typically they'd be able to go in
and handle any wood left after our projects.
But, since we have been doing so much more work,
it started to create too much workload for them
and taking away from their larger land management projects.
So, we worked with them to create a scope of work
for treating wood and debris left behind from our projects
and using our own internal resources to treat that wood.
So, we started that in the fourth quarter of 2020
and were able to treat 33 parcels
in that short amount of time.
And again, that is a program that's proved very successful
and we're going to continue with that moving forward.
We also work with local fire protection agencies
to manage wildfire risk on Liberty owned property.
And so we completed defensible space projects
at two of our substations.
And these projects focus on removing hazard trees
with potential to impact our facilities
and then removing small diameter trees,
dead and dying brush and branches
surrounding the substation to maintain the defensible space.
And fourthly, wood hauling projects.
Historically we would remove everything
up to four inches in diameter
and everything greater than four inches in diameter
was left onsite for property owners to handle.
We realized that that's not always feasible.
And sometimes that property owner
doesn't necessarily do anything.
So in order to not contribute to additional fuel loading,
we're working on a more extensive approach
to remove wood from project areas
that may have otherwise been left onsite
to benefit the community and reduce wildfire risk.
And on the next slide, I'll talk about
some new inspection initiatives.
In our 2020 wildfire mitigation plan,
Liberty established annual inspections
of our Tier 3 High Fire Threat District areas,
which equates to about 50 miles
of overhead primary conductor.
And in 2020, we did complete the ground-based inspection
and completed all vegetation management work
that was generated from those inspections.
However, after the filing
of our 2020 wildfire mitigation plan
we received a deficiency due to concerns
about the effectiveness
of our reported vegetation inspection frequencies.
We were using a cycle based approach,
with a three year inspection cycle,
with the exception of those annual inspections
of the Tier 3 High Fire Threat District areas.
And our service territory, I should point out,
is 92% High Fire Threat District.
So we really treat our entire service territory
as High Fire Threat Districts.
We don't really change scope of work for that remaining 8%.
So in last year, Liberty performed a LiDAR inspection
of 330 miles, which is almost half of our service territory.
And the point of that was to explore the use of LiDAR
for increasing our vegetation inspection frequency.
And we compared the ground-based inspections
to the LiDAR inspections to determine what the method
would be for moving from a three year inspection cycle
to an annual inspection cycle.
Ultimately, we selected LiDAR
as the preferred method, for a few reasons.
One is the speed at which those inspections
could be performed.
So, for comparison, that Tier 3 inspection
that was ground-based, it took us two months
to inspect those 50 miles.
The 330 miles that we inspected using LiDAR,
that data was acquired in two days.
And then we received our initial deliverables
of all that data within the first month,
that we can start taking action
on the data that we acquired from the vendor.
Additionally, the LiDAR has extremely high accuracy.
And so, technology isn't always perfect,
but it definitely eliminates
the factor introduced by human error.
And so that was another benefit
that we considered with using LiDAR.
And then we also have the ability
to inspect without access issues.
There's a lot of gates.
Sometimes our locks get cut off or other locks get placed on
and we end up having to chase down access
to get to the property where our lines are at times.
And we also have extremely rugged terrain in areas.
And actually in that picture, that is some
of the point cloud that we received from the LiDAR data.
And in the top right corner you could see
a line of detections going up into the right.
And essentially that's one of our lines
that goes up the side of a mountain,
and that's not uncommon for our service territory.
So although it may not be inaccessible,
it's very challenging to patrol on the ground.
And so again, LiDAR eliminates that issue
that we see from ground-based patrols.
And lastly, with LiDAR, we're able to efficiently
direct resources where needed to maintain clearances.
So, once we get those detections back,
we can know where the worst conditions on our system are.
We can prioritize our work based on
the detections that we receive
and then be much more targeted in our approach
to maintaining clearances throughout the system.
So with that being said,
Liberty is going to expand the use of LiDAR.
We saw a lot of success in this pilot program.
And so we're now going to use LiDAR
for our system-wide annual vegetation inspections
beginning in 2021, so this year.
So generally speaking, I'd say at Liberty,
we're really willing to take a close look
at our historical practices and explore new opportunities
to mitigate wildfire risk in our service area.
I think this shift from a three year cycle
to using LiDAR technology for annual inspections
is one way that really demonstrates that point very clearly.
And thank you for your time.
Colin: And thank you for the presentation
Last and certainly not least, Bear Valley.
-: Okay.
So vegetation management is, I would say,
it's probably the top program today,
the top mitigation to preventing wildfire, in my view.
And therefore it's an incredibly important program.
Can we go to the next page.
Our program consists of preventative vegetation management.
And so it's basically a cycle where
the vegetation management contractor visits,
on a periodic basis, every facility
throughout our service area on a cycle basis.
There's also corrective vegetation clearance
needs or actions that are identified
by inspections, the LiDAR surveys,
or other type of discrepancies are identified.
And then there's emergency vegetation clearance.
So if you have a big storm event,
we do have a lot of vegetation to be cleared.
And after you clear all that, the obvious ones,
because sort of everything shifted due to the storm,
so you've gotta go through the service area
and take a hard look to see
if what you thought was good is now no longer good.
So, those are the three elements of our program.
We have, like I said, we're at 7,000 feet.
Our trees are snow laden.
So over the years those branches become
more susceptible to breaking and falling.
Or the trees themselves become susceptible
to falling and breaking.
And we have icing conditions and so forth.
So we go beyond the minimum clearance standards of G.O. 95
in order to accommodate those more severe conditions.
And then another element, I sort of talked about it
in the Q and A, is quality control checks.
That is a very important aspect of our program.
It gets our supervisors, managers, out in the field
looking at this very critical program.
And I think it's really paid dividends.
It really stresses the importance of vegetation management.
And in a world of constrained resources
there's a lot of things I wouldn't do
before starting to look at vegetation management.
It's just an area you can't cut, pardon that,
but you just can't dial back on vegetation management.
One thing that we are doing now in our program,
and we just, we talked about it in our 2020 plan.
We finally have a forester onsite to provide us,
a contracted forester, to provider us,
kind of a third party, so we're not only relying on
our vegetation management contractors, arborists,
but now we have our own independent expert onsite
to help advise us on our program, help us to target areas,
and come up with special projects and so forth.
On the inspection side, as I mentioned before,
we do the annual G.O. 165 ground patrols.
We do a detailed inspection.
That's done every five years.
We do a second annual G.O. 165 on ground patrol
by a third party, we do the LiDAR.
We also have implemented the Forester program
and now we're doing a,
we'll be doing a UAV fly over and imaging thermal surveys.
Go to the next slide.
LiDAR, we've done this for two years now,
and it really does help quite a bit.
It gives you a great picture of what locations
you need to go have a look at,
get the contractor out to those areas.
It almost gives you good, what I would call
objective quality evidence of how clear your lines are,
which is important.
And it also kind of gives us a good focus
of where to go right before fire season
to make sure we're ready.
And the UAV, like I said, we issued an RFP,
and we hope to get a survey done before the fire season.
And we think that inspection will complement
our vegetation management program.
Go to the...
Final slide, I think that's just questions.
But on the removal of biomass and so forth,
our contractor removes all waste, wood waste.
It doesn't matter what diameter.
That's our contractual requirement with the contractor,
to remove and dispose of it in accordance with
applicable ordinances and laws.
We are looking at, the community does have
some fuels management programs,
primarily run by the Big Bear Fire Department,
so we're looking to partner with them, see how we can help.
We're also looking to reach out
with the U.S. Forestry Service
and see how we can help in their fuels management.
That's all I have.
Colin: Great, thanks so much, Paul.
And thank you to all of our presenters.
I have us coming back from break at 3:40.
So we have quite a bit of time,
but I will see you all at 3:40 for the Q and A.
(upbeat music)
Perhaps go outside and look at some trees.
I want to make sure that everyone is still with us.
But, I...
Can I just get an acknowledgement
from PacifiCorp, Liberty, and Bear Valley that you are here?
Brian: This is Pacific Power.
Peter: Hi, this is Peter with Liberty. I'm here.
Paul: I'm here, Bear Valley.
-: Great. Cool.
Thank you all.
So we will start out just like the other Q and A sessions.
I'll ask a question for WSD
and then we'll move on to the stakeholders
and go in sort of a round robin that way.
So, as my first question...
My first question is in regards to contractors.
All of you, either to a large degree or exclusively,
rely on contractors to do your vegetation management work,
if I'm not mistaken.
And so I just wanted to hear from each utility
about the best practices for oversight of these contractors,
particularly when issues arise, how they are remedied.
And I'd also like a short discussion
about how you ensure contractors are effective bases
for the utilities out in public,
particularly when communicating
with land owners and customers.
As we all know, vegetation is
a very visible part of wildfire mitigation.
So we can start with, why don't we start with PacifiCorp?
Brian: Yes.
So I guess one of the best ways
that we oversee our contractors
is through our internal staff.
So in 2020, over the past couple of years,
2019 into 2020, we hired four additional utility foresters.
and those foresters have the primary responsibility
of conducting post-audits.
So one of the most effective ways
that I mentioned to oversee our contractors
is through our internal staff
and having their presence out in the field
reviewing the work conducted by our contractors.
So they're out as closely behind the contractors
as feasible and efficient to conduct post-audits
of the contractors' work, identify issues that may arise
with respect to the contractors' quality of work, et cetera,
efficiencies, things of that nature.
And then coordinate those findings
with the contractors general foreperson,
to address any issues or build upon what is
working appropriately and working well in those areas.
So post-audit work and being out in the field
and reviewing the work has been
one of the more efficient ways to oversee our contractors.
It does take a lot of resources to do that work,
obviously, to be out in the field that much as well.
And as far as the customer communications and so forth,
it goes hand in hand with what I mentioned previously,
as far as our our foresters being out in the field,
communicating, having that one-on-one conversations,
with our contractors, with the general forepersons,
on how to handle and manage customer interactions,
concerned customers.
And so it does take a bit of that one-on-one
constant communication and a little bit of training
with respect to our contractors on the proper approaches,
proper procedures of coordinating
with our customers appropriately.
And we have a process in place where
if the contractor cannot resolve a customer concern
it's elevated to our foresters and they interject themselves
to work to resolve a customer concern in that manner.
Colin: Can you also speak to
how issues with contractors are remedied?
Brian: Issues with contractors are remedied?
So it's, at first, identifying that issue
in a timely manner, as quickly as possible,
bringing that light to the contractor
and having that open transparent conversation.
I like to view ourselves as a partnership
with our contractors in building that partnership.
And where we have that strong partnership, in many cases,
they'll offer remedies as well to any issues.
We have had leadership issues or concerns
with respect to our contractors.
And they have taken our concerns very heavily
and made leadership changes on their own.
So by having that partnership with the contractors,
I've found that they are becoming
more amenable and responsive to our concerns
and to concerns that we raise with them.
Colin: Right. Thank you so much.
Liberty.
Peter: Yeah.
Our process is quite similar to what PacifiCorp lined out.
We have a group of contract foresters
who go out and do patrolling
and pre-inspection of our lines to generate work orders.
And then we have a separate contractor
that actually performs that tree work.
And our internal arborists audit
a lot of that work after it's inspected
and before it's completed by the tree crews.
And then they'll also do follow-up post-work audit
on the work that's performed by the tree contractors
to, again, make sure that everything's being done
according to our work scope and specifications.
So there's a little bit of checks and balances
we have in place there.
And we're also developing third-party specifications
for auditing to supplement that work
and have additional resources to do
more post-work and post-inspection auditing
of our vegetation management program.
And when it comes to communication with customers,
typically throughout the permitting process,
the contract foresters who are doing the pre-inspection
have a lot of interaction with customers.
We're in very frequent communication with them
if there are issues that come up.
And then when the tree crews are out there performing work,
if there are any customer issues,
we have kind of a chain of command,
where the tree crews will work
with the customers to resolve an issue.
If that doesn't work, they may reach out
to the pre-inspector who permissioned the work.
Maybe there's some clarification that needs to be done.
and then it'll get escalated to our internal arborists,
or myself if needed, to resolve any issues.
And in addition to that, we host monthly meetings
with all of our contractors.
So every month we'll meet with them,
discuss what's currently going on,
if there are any issues that need to be addressed
and kind of just really maintaining
that open line of communication
between Liberty and its contractors
to make sure we're all on the same page.
But, yeah, we have a pretty good working relationship
with our contract resources.
And honestly, if there is a contractor
that's not meeting the needs, most customers aren't shy
about reaching out to us directly to express a concern.
And then that is also another way that identifies issues,
if we need to address them at that point.
Colin: Great. Thanks for that answer.
Bear Valley, Paul.
-: Yeah.
Similar, we provide contractor oversight
through a number of methods.
One is our vegetation management QC,
which we talked about, where managers and supervisors
go out in the field to do at least six per month.
Second area is, we do require our contractor
provide us before and after pictures
of their trimming activities so that we have good evidence.
And then, we also have a forester now
who will report to us and will be out in the field
evaluating the contractors.
Colin: Paul, can you briefly speak to how issues
with the contractor are remedied?
-: Yeah.
So we have a weekly requirement
for a weekly meeting with the contractor.
So, the contractor to talk to us about
where they're gonna be so that we can alert the community
via our website and social media,
where tree trimming's gonna take place.
Also, so we have situational awareness
of where they're trimming trees
in case something happens to a circuit in that area.
We also coordinate any clearances
or covering of wire required for their services.
And then we also coordinate any customer issues.
So there is a regular scheduled coordination meeting.
If there is a discrepancy that we find
we issue a vegetation order
and we monitor the number of vegetation orders being issued.
And we'll talk to the contractor if we're finding
that the number of vegetation orders are increasing.
That could be indicative of them not doing a proper job.
There's also a daily contact with the contractor
just to make sure we are keenly aware
of where they are in the service area.
So then if any customer issues come up,
we prefer to resolve them ourselves
rather than having the contractor speak for us.
The contractors do obviously identify themselves
as working for Bear Valley Electric Service,
but we do most of the interactions ourselves
for the customers.
Colin: That's great. Thank you for that.
Okay, we will move on to the stakeholders.
And for the sake of switching it up,
Henry, I see that your hand is raised.
Henry with Cal Advocates.
-: Hi, thank you.
Okay, so I'll start with a straightforward question.
What is your approach to vegetation clearances?
Obviously there's a minimum in General Orders
of four feet at the time of trim
plus enough growth to keep it at,
enough room to keep it at four feet until the next trim.
But I know some utilities are trimming to 12 feet.
Some are trimming up to the sky above the wires.
So, can you explain, each of you,
what your clearance distances are?
-: Yes, this is-- -: Start with PacifiCorp.
Brian: Sorry. Yes.
So in general, yes, we, Pacific Power,
we trim our trees to maintain that
four minimum clearance distance
and additional needed clearance
so that the tree will hold that clearance through the cycle.
So we conduct our work on a four year cycle
and halfway through that cycle we conduct an interim work
to address any of those fast growing species
that may not hold through an entire four year cycle,
such as a cycle buster.
So we're ensuring we, post-work, post-pruning work,
our post-prune clearances are well beyond
the four feet range, out to 12 feet for side clearance,
13 feet under clearance, and 10 feet overhang,
or for distribution on a fast growth species.
So we categorize our trees from a slow,
moderate, and fast growing species,
and then prune to achieve certain clearance distances
based off of a tree species' growth rate
in order to maintain that four foot clearance.
Peter: Yeah.
At Liberty, we achieve 12 feet minimum clearance
at time of work throughout our system.
And then on transmission we do work to remove all overhangs.
So we have kind of ground to sky clearances on transmission.
We do allow overhang on distribution.
But generally speaking, we're getting
a minimum of 12 feet of clearance at all times
whenever we're performing work.
Brian: This is Brian with Pacific Power.
If I may interject, just to clarify,
I gave the post-work clearances that I had mentioned
are for our interim work that we conduct.
So similar to what was just said, we do post-work,
achieve a 12 foot clearance on a minimum for our cycle work.
Just to clarify. Thanks
-: So, at Bear Valley, we maintain, for the high voltages,
the voltages that we operate at,
we strive to achieve a 72 inch radio clearance zone.
And when we make a decision to trim, in other words,
if we think the limb is within the 72 inches
or is going to be within 72 inches before the next visit,
we would trim it out to at least 12 feet, maybe further,
depending on whether it's a fast growing species or not.
-: Great.
And if I could follow up, PacifiCorp mentioned
rating trees by rate of growth.
What's your basis for categorizing trees?
Who develops that schema?
How do you categorize trees into buckets by rate of growth?
Brian: So that's the pre-inspector,
the person who is identifying the work to be done
based off of their professional judgment and experience,
will identify, bucketize those growth rates by trees.
And so, yeah, to identify whether it's a slow,
moderate, or fast growth species.
-: I see. Okay.
Colin: All right. Thank you for your question, Henry.
I think now we'll move onto GPI.
Zoe: Thanks.
So PacifiCorp mentioned using
herbicides and growth inhibitors.
Are any of the other SMJUs using these treatments?
And then two other parts of that question,
is how often do they have to be applied?
And then is there any other consideration
for long-term solutions, such as replacing
with low growth or native species?
Peter: This is Peter with Liberty.
I'll start on that one.
So we don't use herbicide currently
for our vegetation management program.
And we haven't used tree growth regulators in the past.
However, we have reached out to some contractors
that perform that services and have been
in discussion with using that.
We do have a couple outlying portions of our service areas
where we do see faster growing species
that require more frequent maintenance.
And so, we are considering that use
of tree growth regulators in those instances.
We haven't implemented any of that type of work yet.
Oh, and as the other one, as far as planting
or following up with low growing shrubs
and things like that, that's something where
we're not currently doing.
It's something that we'd consider long-term,
especially on some of our larger projects
where we're really just trying to promote
the lower growing species that would occur naturally,
and managing to remove those incompatible species,
while promoting the naturally occurring compatible species.
Zoe: Thanks.
Maybe a quick follow-up question for Liberty there.
Is the decision to move to herbicides,
is that partly a cost-based decision?
So having to inspect less and do less trimming?
Or is it a wildfire mitigation aspect as well?
Peter: Honestly, it really has to do
with the permissioning.
And in the Lake Tahoe Basin, there's a lot
of additional regulations and restrictions
on what we can do to prevent any pollution
or discharge from activities that may create
ground disturbance going into the lake.
So the Tahoe Regional Planning Agency
has additional rules for permitting.
And so it's just something that we haven't really
pursued due to that reason.
Zoe: Great. Thank you.
Brian: And this is Pacific Power.
So, we are, as you mentioned,
utilizing tree growth regulator herbicides.
We utilize that where we have permission to do so.
So it can be hit and miss in areas.
There could be some prime areas of prime candidacy,
to utilize herbicides or tree growth regulators,
but we don't have permission to do so, so we don't,
due to environmental concerns or landowner concerns,
With respect to tree growth regulators,
it's new in our veg management tool box,
and we've been utilizing it for a couple of years now.
And as far as the reapplication,
it is dependent upon species and so forth
and the efficacy of the product.
But it can be reapplied generally during
either the cycle and or interim maintenance.
So either once every four years
or every two years there may be an application.
But again, tree growth regulator is
something new that we are utilizing
and we have to look into a little bit more
as far as what our overall plan and approach would be
for reapplication on what frequency, based on the tree.
As far as promoting the low growing species,
similar to what was said, we're not actively planting,
proactively doing plantings, but we're utilizing
herbicides and tree growth regulators
to try to target those incompatible species.
And then through integrated vegetation management
to promote those lower growing species
within our rights-of-way.
Zoe: Thanks.
And then Bear Valley, are you using similar techniques?
-: Oh, no.
We're not using any vegetation inhibitors or regulators.
We have similar issues with it that Liberty raised
as far as with what the requirements would be.
And it's not necessarily that practical to our service area.
And as far as replacement, we haven't engaged in that.
We did do some tree removal.
But we really don't encounter a lot of people introducing
species that aren't indigenous to the area.
That isn't a big issue for us.
Zoe: Great. Thanks, everyone.
Colin: As a followup to that,
I apologize, I'm gonna break the cycle a little bit.
PacifiCorp mentioned targeting specific species
based on growth rates, and I was wondering,
and Liberty mentioned that as well,
and I was wondering if this targeting of specific species
kind of went beyond anything qualitative
that the foresters are doing based on experience,
that is, is there data to support,
slow, medium, fast growing species?
And in addition to that, are there any other factors
that the utility uses to target specific species,
like for instance, limb failure rates
or likelihood to fall in storms, et cetera?
Brian: So, this is Pacific Power.
As far as we do, currently, we are relying on
that qualitative information based on experience
and knowledge of our pre-inspectors, our foresters,
and so forth, to help target those areas
where there are faster growth species
or species that may be more susceptible
to failure, as you mentioned.
There is qualitative data out there.
Currently, we are, Pacific Power
is more currently in the state of relying upon
more of that qualitative information.
As I mentioned earlier,
we are modifying the data that we collect,
when we're out in the field conducting our work,
through the tools we have now in place since last year,
such as collecting information on those cycle busters,
those faster growing species, to allow us
to analyze that information at a later date
to help inform our decision making process.
Peter: So yeah, at Liberty, our pre-inspectors,
they're looking at previous years' growth
to help determine future growth rate
of individual trees as they're inspecting them.
And there is a lot of data out there that has been done
to quantify growth rates by species.
And so that's another thing that we use.
And sometimes when treating different species on our system,
we may target more clearance or work with the customer
to try and remove those species
that we know are gonna be fast growers.
But overall, our species composition is pretty predictable.
We don't have a lot of that, other than the outliers.
So we have a pretty good handle, based on experience
and industry research that's been done to help guide us
when determining growth rates of individual species.
But with switching to these LiDAR inspections,
that's one thing that we will be able to quantify more
by using change detection year over year,
to show us exactly where species are growing faster
or at different rates and need increased mitigation
or more frequent pruning at that time.
So, I think it's a combination of looking at
each individual tree's previous growth rate
to determine future growth rate using
industry available research on growth rate by species.
And then integrating that future data
that we're gonna be getting from the LiDAR surveys
to do change detection to see if there are outliers
or those cycle buster trees that maybe
we're not currently targeting.
Colin: Great, thank you.
Does Bear Valley target trees
based on growth rates or other factors?
-: Well, we track the species.
So when we do trim trees, we document in our GIS the species
so that we can keep track of which are fast growers.
Our contractor also keeps track of them too.
So they import that into our system so we can evaluate it.
They also have their own slightly different system.
It's basically just uploading the files
between the two systems, but they also keep track
of fast growers so that they can make sure
the revisit rate is appropriate.
Colin: Thank you.
Okay. I just want to make sure,
Mr. Abrams, do you have a question?
I see your hand isn't raised, but?
Okay.
In light of the silence.
Hey, Ryan, are there any questions
in the chat or in the Q and A?
Ryan: Hey, Colin, nothing coming from the chat.
Colin: No. Okay.
Then I will throw it back to Henry Burton
with Cal Advocates.
-: Okay, thanks.
So, next question is, can each of the utilities
talk about how you do hazard tree assessment and removal?
Do you have a particular tool that you use to assess
whether a tree is hazardous and needs to be removed?
Whose judgment are you relying on for those assessments?
How far out from the wires are you looking
when you're making hazard tree assessments?
Let's start with PacifiCorp I guess.
Brian: Yes, so with respect to hazard tree assessments,
when our pre-inspector goes out
to look at the vegetation along the line,
in general, if you visualize they're walking along
the middle of the corridor underneath the line,
looking off from either side,
to either side of the right-of-way,
and looking for vegetation encroachment or hazard trees.
and with respect to hazard trees, generally,
in accordance with industry standards,
they're conducting a visual assessment,
a level one assessment.
And if there aren't any,
they're looking for visual indicators of tree health,
for example, if there are any defects,
other environmental factors as well.
Is the tree leaning?
Does it appear to, the root,
or erosion around the base of the tree for soil instability?
So they're looking at various factors.
But they're, in general, in order for them
to do, potentially, do conduct any more detailed assessment,
there would need to be some visual indicator
that would draw their eye to that tree,
to indicate that as a hazard tree.
And in general, if there is a visual indication
that it's a hazard tree it's treated as a hazard tree
and identified for removal or pruning or be addressed.
And so that's the general process.
And in general, they do take into account other factors.
Prevailing wind directions.
Has there been, for example, some recent logging activity
in the area, which now opens up area and makes,
and some trees may be susceptible
to windthrow, et cetera, or erosion in that area.
So, they do look at wind patterns, soil structure
to a degree, slope, et cetera, and all that plays into
their visual assessment of identifying hazard trees.
Was there a second point to the question there?
Or did I capture that?
-: I think that's mostly it.
I guess how far away from the wires
are you looking when you make those assessments?
Brian: Well, they're looking
as far as they can see into the tree canopy there,
and for trees that are within strike distance of a line.
So if there's a tree outside of the strike distance
from the line, that won't be looked out,
even if it was a dead, dying tree.
So they're looking at trees within
strike distance of a line, in general.
-: Great, thanks. Liberty.
Peter: Yeah.
So at Liberty we have a couple of different approaches
to hazard tree mitigation.
One of them is a program specifically focused
on dead and dying tree removals.
So we'll have inspectors patrol the lines
and look for any tree that's dead or declining
and is able to strike the facilities.
So, in some instances, on our service territory,
they may be looking at trees 200 feet away
from our power lines, due to the tall trees that we have
in our service territory and the slope that can occur.
So, they're looking pretty far off right away, again,
towards anything that can strike the facilities
and looking for those obvious defects.
So that's kind of, we follow as far as tools.
Typically we follow industry standards.
So there's the ANSI A 300 Part 9 Tree Risk Assessment
Standards that we typically use as a guideline
for performing hazard tree assessments.
So that and dying tree inspection,
typically what would fall into the level one inspection
where you're just patrolling the line
and looking for those obvious defects
or the dead and dying trees from one angle.
We also do detailed inspections of our lines.
And that's where we have tree inspectors,
typically they're inspectors that have
a little bit more experience and they're looking for, again,
obvious defects, dead, dying trees, and things like that.
But they're also looking for green hazard trees
with the capability of striking our facilities.
And if they see something that would draw them to that tree,
like was mentioned before, then they'll perform
what would be considered a level two inspection,
where they're walking completely around that tree
looking for any other defects, the capability of it
to strike the facilities, the likelihood of it,
factoring environmental considerations and things like that.
So, that's typically the tools that we're using.
There's also a Utility Tree Risk Assessment
Best Management Practices publication
that was recently put out, so we incorporate that,
and we recently drafted a hazard tree management plan
that really outlines all this.
And it is alluded to in our WMP.
It's drafted, it's not finalized yet,
but we're really drawing from those resources
provided by the industry to help guide
our hazard tree management plan.
-: So similarly, we're looking at, Bear Valley,
at removal of dead or diseased trees
that could fall into the line,
is basically the distance that we look.
And we also look at trees under the drip line that are just,
it's just it's too hard to manage them.
You're gonna be revisiting them very quick, too often.
And then making those assessments,
there's a couple of processes.
One, the contractors' general foreman
got a sense of experience.
The contractor has an arborist who they leverage.
Our inspector has an enormous amount
of experience in tree-trimming.
And then we also now incorporate
a forester into our process.
As with most tree removals, in our service area at least,
there is a permitting requirement.
So you just don't go chop down a tree.
So there's an outside agency also
that reviews our decisions in making those tree removals.
-: All right, thank you all.
Colin: Great. Thank you, Henry, for that question.
GPI, Zoe Harrold, do you have another question?
Zoe: Sure, I'll ask something.
Do any of the SMJUs have programs
that basically route the VM product or biomass
to different end use applications?
So either, pellet production or particle board production
or firewood for community members, things like that?
(radio beeping)
Man: This is Britt.
Peter: Hi, this is Peter with Liberty.
I'll take the first stab at that question.
Typically we don't direct where the biomass goes.
On those neighborhood or community projects
that I had mentioned, the contractor,
it's up to them where they take it.
We do have one contractor that was hauling all the biomass
to a cogen plant where it's being,
intended use to generate energy from the biomass.
We also had a contractor take it to a similar facility to,
actually it was one of the prisons over here,
over in Nevada that uses biomass to generate power,
and so they brought it there.
So I guess we don't typically dictate
where the biomass goes.
That's historically been up to our contractors.
But we're looking for ways to improve
the utilization of biomass.
When it comes to firewood,
all of the work that we're typically doing
on the California Tahoe Conservancy land is
putting together, is having hand crews go in
after our routine work and bucking up that wood
into firewood and stacking it.
And then the Conservancy has a firewood collection program.
So we'll send that information back to them
so they'll know exactly what parcels we've completed.
And it goes onto a map on their website.
So people who have permits to collect firewood
know where they can go and collect firewood.
So that's a really successful program.
And then we also advertise internally
to employees and things like that,
where there's firewood available to get picked up.
But that's about the extent of the use
I could think of at this point in time.
Zoe: Thanks. That's helpful.
PacifiCorp and Bear Valley.
Brian: Yes. Sorry, this is PacifiCorp.
My phone turned off in the middle of the question,
but based on the answer there it sounds like
we're talking about slash and the end use
of slash and wood chips and programs associated with that.
So Pacific Power, we do similar to Liberty.
We don't dictate the end use per se,
with respect to that material with our contractor.
In general, we do leave a lot of the larger wood
for the landowner that they can use
for firewood and so forth.
On some of our larger projects,
large removal projects that we have on going on,
we have taken a lot of slash to biomass energy producers,
which has been fairly successful there.
It's looking to be somewhat cost neutral
as far as them purchasing the material
to cover our transportation costs.
And in general, we look for ways and encourage
the recycling of our wood chips
in every opportunity that we can.
But our tree contractor in large part
will manage that process.
-: So at Bear Valley, the contractor overall
is responsible per the contract to remove the waste
and dispose of them properly in a legal manner.
That's contractually our main requirement,
and not leave anything behind.
However, the contractor does, is allowed to,
and they do work with customers.
So if it's a tree that belonged to a customer
and the customer wants the wood,
then the customer gets the wood.
We do work with the city and provide them wood chips
and also the water company, if they want them,
we provide them the wood chips, or our contractor does.
We also allow, the county has a program to have wood
for elderly and low-income folks.
And so we do allow the contractor
to provide that supply there too.
Zoe: Great. Thanks everyone.
Colin: I see that we are running short on time,
but I do think we have time for one more question.
Henry, if you have another question,
you are welcome to ask it.
-: Sure. I guess this might be quick,
but do you keep track of the performance of your contractor
in things like how many errors or missed tree
each contractor is responsible for?
Brian: This is Pacific Power.
With the implementation of our new electronic tracking,
planning system that we rolled out last year,
when our foresters conduct audits,
we are tracking exceptions, those audit findings.
And so as of now, yes, we are tracking those moving forward.
And our foresters can, based on those results,
prompt discussions with our contractors,
whether it be positive or negative,
based on the number of findings they're seeing.
So we can course correct and address any issues.
As far as in the past, we were also collecting
that information, but it was more paper-based.
So moving forward, we'll have an electronic database
that we can build on.
-: Great.
And you can link it back to individual contractors
or suppliers? -: Correct.
-: Great.
Peter: Yeah. So at Liberty, previously our audit process
was a little bit more ad hoc.
Last year, we did a more formal audit
of 15% of work that was performed for us.
And so, with that data, we're able to quantify
which contractors were performing well,
and with work orders and everything like that,
we could narrow it down to crew foreman
if we wanted to and get pretty granular,
if we saw a really consistent pattern
of work failures that wasn't meeting our criteria.
And moving forward, we're developing
a more robust quality assurance, quality control plan,
that we'll be rolling out to have
a larger sample size and more data,
more frequent inspections and audits,
and also closer to the time of work being performed,
so that we can continue finding
and fixing any issues that are out there.
And again, with our database, being able to go back
to those work orders and determine do we have
any patterns and that'll help inform future training
for contractors or future work with contractors
to continually improve our program.
Paul: So, Bear Valley typically only has
one contracted company performing the work.
Our veg management program, QC program,
does have the ability and we do track
the number of vegetational orders resulting from QCs.
Back in 2018, at the very beginning,
when we implemented that program
and really had metrics to it,
we discovered our previous contractor was not performing
to the level that we needed.