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Host: This is the electric investor owned
utility safety briefing
to the California Public Utilities Commission
and the Office of Energy Infrastructure Safety meeting.
Thank you, Carolina Contreras, you may begin.
-: Hello everyone,
and welcome to Bear Valley Electric Service
and Pacific Gas and Electric Safety update briefing
to the California Public Utilities Commission
and the Office of Energy Infrastructure Safety.
My name is Carolina Contreras,
I staff at the safety policy division,
and I will be your facilitator today.
At today's briefing,
members of the board of directors of Bear Valley
and PG&E will present and answer questions
from the CPUC and Energy Safety regarding updates
on their electric safety related efforts.
Due to the coronavirus pandemic
and the shelter in place order,
we are conducting today's meeting online
and by remote participation.
The meeting is live-streamed on the CPUC's website.
You can view the meeting at www.adminmonitor.com/ca/cpuc/.
Closed captioning is available in English and Spanish
through the webcast.
You can click on the green button to select
your language of choice.
Joining us on the virtual dais today
are CPUC President Batjer and her fellow Commissioners,
Shiroma and Houck,
as well as the Director of the Office
of Energy Infrastructure Safety, Caroline Thomas Jacob.
Unfortunately, Commissioner Recshouen
and Commissioner Gusmanasevas are unable to join us today.
In terms of a format for today's briefing,
we will hold a morning session for Bear Valley Electric
and an afternoon session for PG&E,
which is scheduled to start at 1:00 PM.
After opening remarks from the dais this morning,
we will begin Bear Valley's session with public comments.
We will then move on to a 25 minute presentation
by Bear Valley Electric representatives
on their safety update, followed by a discussion and Q&A
from the Commissioners and Energy Safety director.
We are scheduled to break for lunch at 12:00 PM
and we'll reconvene at 1:00 PM for PG&E's portion.
The afternoon will commence with public comments
for PG&E's session.
We will then move on to a 45 minute presentation
by PG&E representatives,
followed by discussion and Q&A
from the Commissioners and Energy Safety director.
We are scheduled to conclude today at 3:00 PM.
We will have an opportunity for public comment
at the beginning of each of today's two sessions.
Bear Valley's public comment session will come first
and will begin around 10:15 AM.
PG&E's public comment session will take place
in the afternoon, and is estimated to begin at 1:00 PM.
If you wish to make a public comment,
dial 800-857-1917 and enter passcode 1767567
and press *1.
You will be placed into a queue
and the operator will take your name and information.
You will be called upon to speak
when we get to the public comment period in today's agenda.
We will provide two minutes to each speaker,
so please be mindful of the time.
You will hear a bell sound when your time is up.
Please be mindful to other callers in the queue
and stay within your allotted time.
We also have Spanish interpretation available.
Dial 800-857-1917 and enter passcode 3799627#
to be connected to the Spanish line.
I ask that today's speakers remain mindful
and speak clearly.
We will now repeat public comment information
in Spanish.
(speaking in Spanish)
I will now turn it over to President Batjer
for opening remarks.
-: Thank you so much, Carolina.
And I want to say good morning to everyone.
I'd like to, of course, welcome my fellow Commissioners
and Director Thomas Jacob
from the Office of Energy Infrastructure and Safety.
Today's meeting with Bear Valley and PG&E
is the second in a series of meetings
we have put in place to hear annually
from representatives of the utilities boards of directors
on a comprehensive set of electric safety related issues.
The first meeting in this series was held in August
with SCE Edison and SDG&E.
While this meeting is a new initiative,
it is part of the CPUC and Energy Safety's
ongoing effort to hold public meetings
with utility leadership across a range of safety issues
including wildfire mitigation, public safety power shutoff,
and represents our continued commitment
to transparency and accountability
around important public safety issues.
Presentations like the ones we will hear today
are critical to ensuring we are kept informed
by the utilities around their responsibility
for continuing to improve their safety performance
including the development and maturation
of their organizational safety cultures.
A stern safety culture is essential for strong
and effective safety performance, and that culture
is set by utility leadership.
So a venue such as this,
where utility leadership can present their view
of their own company's safety performance
and hear from the public and regulators,
is a very valuable feedback loop.
We also believe that a public meeting
with board members is a reasonable and effective way
for the utilities to demonstrate they have met one
of the statutory criteria for obtaining safety certificates
which requires the electrical corporation
to establish board of directors-level reporting
to this Commission on safety issues.
While public briefings enhance transparency,
I also want to recognize that we have many staff
at the CPUC who focus exclusively on safety oversight
and enforcement work which happens outside
of the public view.
Also we have been working for years
to enhance the level of engagement in assessing the risk
the utilities face and determine a more quantifiable basis
for assessing safety performance
in our safety model assessment proceedings,
and our risk assessment and mitigation proceedings.
Today's meetings further enhance our oversight work
by providing the public a venue to hear
the presentation of the board,
and for getting a better public understanding
of the priorities and actions of the board
and the executive leadership.
Monday marked three years since PG&E infrastructure
ignited the deadly campfire.
I wanted to recognize this occurrence
and that of the 84 lives that were lost.
This anniversary is a grim and anguishing reminder
of the need for sustained and ongoing actions
by PG&E and other utilities to operate their systems safely,
and to put the care and wellbeing of their customers
in every business choice they make.
Oftentimes in regulation,
one can get consumed in statistics and metrics.
How is a utility doing this year compared to last year?
And month over month?
But in this work and in today's meeting,
I want to hold center that it is real people
we are talking about.
Real people's lives who were lost
because of a neglect to uphold the responsibility
to operate safely,
and real people whose lives were upended.
It is the real people that guide my
and my fellow Commissioner's unwavering commitment
to exercising every level we have
to continue to push utilities to forefront the customer
and forefront their safety.
With that in mind, I am very much looking forward
to hearing from Bear Valley and PG&E leadership
on their key priorities and efforts to improve safety,
and to hear about the board-level accountability
for the utility leadership related
to the company's safety performance.
So I want to thank very much
the Safety Policy Division,
the Office of the Commission,
and the Office of Energy Infrastructure Safety
for organizing this very important briefing today.
With that, Carolina, I will turn it back to you.
Thank you.
-: Thank you, President Batjer.
Commissioner Shiroma?
-: Ah yes, thank you, Carolina.
I very much appreciate the efforts today
to provide the updates.
These are of the highest importance
in establishing accountability at the highest levels
of the organizations.
The governing boards set the tone.
They set the expectations.
And we will learn today
about the board of director's efforts in development
of governance structures to ensure that both
the Bear Valley and PG&E teams are effective and efficient
in implementing safety efforts.
The commemoration of the campfire and those lives lost
are an important reminder
of the governing board's responsibilities
and the influence that they have
on the entire organization.
And though the two utilities are different in size
and geography and customer base,
the principles apply the same, again,
in terms of the accountability of the governing boards,
the accountability that they hold over their teams,
and I look forward to a robust and detailed discussion.
Thank you.
-: Thank you, Commissioner Shiroma.
Director Thomas Jacob.
-: Good morning, and thank you, President Batjer
and Commissioner Shiroma.
I just want to say I definitely concur
with all of what you guys just said.
President Batjer, very eloquently described
the severity and importance of this effort.
I think it's important to root today's discussion
in the fact that the landscape
in which each of the utilities build, operate,
and maintain their grid, and the risk calculus
for doing so, has fundamentally changed.
As the impact of climate change continues to worsen
and California experiences (indistinct)
that increase the risk of wildfire,
the importance of building and maintaining
a culture of safety and wildfire resilience
for employees, customers, and the general public
becomes ever more critical.
With over 8,300 fires
and more than 3 million acres
burned this year in California,
the numbers, more importantly the impact of those fires
on the residents, communities, and our environment
are staggering.
Year over year, the threat is only continuing to escalate.
Safety and climate resilience must be considered
and prioritized in every decision that utility makes
to ensure every opportunity is maximized
to improve worker safety and reduce or eliminate
the likelihood of an ignition from an electrical line.
Building a culture of safety,
where safety's not just what you do,
but it's who you are, is not easy,
nor does it happen overnight.
It takes hard work, universal buy in,
and a strong commitment to leadership.
It means developing a culture based on safety
and risk management, not just focused solely
on compliance, but a culture that reduces risk
across how you build, operate,
and maintain your infrastructure.
Through the safety culture assessments
our team conducted this year,
I know PG&E and Bear Valley's governance work,
I also know that there's still much you need to do
to ensure that the entire organization,
from the board down to the frontline worker
including employees and contractors,
prioritize safety in every decision, in every action,
to improve safety outcomes for your workforce,
for your customers,
and the communities in which you operate.
As we're coming to the end of the calendar year
and the compliance period
for the 2021 wildfire mitigation plan,
I'm particularly interested in hearing
from both PG&E and Bear Valley
about the specific safety improvements
implemented this year,
and how each of you plan to address
the commitments you've made
for which you're currently behind schedule.
I'll leave it at that for now
as I'm sure I'll have questions after the presentations.
With that again, thank you for the opportunity
here today and I appreciate the Commission
organizing the briefing.
Back to you, Carolina.
-: Thank you, Director Thomas Jacob.
Commissioner Houck?
-: Thank you, Carolina.
I want to thank you
and all of the Safety Policy Division staff
for organizing today's public meeting,
as well as Energy Safety for their continued partnership
with the CPUC on wildfire safety matters.
I concur with the comments that were made
by my fellow Commissioners,
particularly President Batjer's comments
regarding the need to prioritize safety
and how what the utilities are doing impact people's lives.
I'm looking forward to learning more about the progress
that both Bear Valley and PG&E have made
in improving the safety of their systems
and their goals for future implementation
of safety measures.
I had the opportunity last week,
along with Turn, SCD, and Energy Safety,
to visit some of the sites
where PG&E is currently conducting
it's wildfire mitigation work.
This provided an opportunity for all of us to see
what was happening on the ground,
and have PG&E address some of the questions raised
by the public including implementation
of fast trip settings,
which I believe they'll be talking about
in today's presentation.
So I appreciate PG&E engaging in dialogue
with all of us regarding its recent safety work
and the progress they've made to date.
There's still a lot of work to be done
and I just want to reiterate what's been said already
that we intend to hold the utilities accountable
for providing safe and reliable electricity
to their customers, and I'm looking forward
to hearing more from both utilities today
in their briefings on how they're going to be implementing
safety measure and what they've done to date.
So thank you.
-: Thank you, Commissioners and director Thomas Jacobs.
We will now turn to the public comments portion
of Bear Valley's session in today's agenda.
We want to make a clarification,
the passcode that we let you know about earlier
needs to be corrected.
So I will correct it in my following statement.
As a reminder, if you wish to make a public comment,
dial into 800-857-1917 and enter passcode 5180519
for the English line.
Again, that has been corrected
and I'll repeat the corrected passcode.
5180519 for the English line.
And the passcode for the Spanish line is 379929627.
Excuse me, I'll repeat the passcode for the Spanish line.
That is 3799627 for the Spanish line.
Unmute your phone and press *1,
you will be placed into a queue
and the operator will take your name and information.
You will be called upon to speak in the order
your call was received.
You will have two minutes to speak.
You will hear a bell sound when your time is up.
Please be mindful of other speakers in the queue
and keep to your allotted time.
I will now turn it to the operator
to open the public comment telephone line.
Operator: Thank you.
The public comment telephone line is now open.
Again, if you wish to speak
during the public comment period please press *1,
unmute your phone,
and clearly record your name when prompted
so I may introduce you.
Again, that is *1 to ask us questions.
It may take a few moments for comments to come though,
please stand by.
-: So it sounds like we have no current speakers
on the queue.
We will then move on with no more comments on the line.
The public comment period for Bear Valley is now closed.
Thank you to all who would like to call later.
There will be another public comment session for PG&E.
To provide written comments,
please send them to carolina.contreras@cpuc.ca.gov.
We will now hear from Bear Valley Electric Services
representative, Paul Marconi
Paul Marconi is president, treasurer,
secretary, and safety and operations committee chairman
for Bear Valley Services.
Welcome, Mr. Marconi,
you are scheduled for 30 minutes.
I am turning it over to you now.
-: Thank you.
Are you gonna display the slides?
Yes, okay.
Good morning, President Batjer, Commissioner Shiroma,
Commissioner Houck, Director Thomas Jacobs,
staff, and members of the public.
Thank you for inviting me to provide
Bear Valley Electric Service Inc.'s
board-level update.
Bear Valley is committed to ensure safety of the public,
our customers, and stakeholders that are exposed
to our facilities and operations.
We are committed to continually implementing
and executing initiatives to reduce the risk of wildfire,
and we are also committed to providing a safe,
healthful workplace for all of our employees,
on-site contractors, vendors, and other visitors
to our facilities.
We can go onto the next slide, please.
During this briefing, I'll brief the topics
that were requested in that order.
So we can go to the next slide.
Bear Valley is small.
32 square miles, if you want to subtract the lake,
you can take another four and a half
to five square miles out depending on lake level.
Most of our facilities are at 7,000 feet.
We're in the San Bernardino Mountains
where you have an alpine environment.
That means heavy tree, pine-type vegetation.
Mostly dry environment, about 8% a year.
Entire service area is in the high fire threat district.
90% is tier 2, about 10% is tier 3,
that Southern red area is our tier 3 area.
Our jurisdiction's pretty simple.
County of San Bernardino, City of Big Bear Lake,
US Forest Service.
We have 24,623 customers.
We have a permanent resident population
of about 22,000 residents.
About 30% permanent residents and 70% second home owners
in Bear Valley.
Our population can swell to over 200,000
generally between Christmas and New Years,
and just as a data point,
last year, we had over six million visitors to Bear Valley.
So our normal power supplies
comes from Southern California Edison lines.
Next slide, please.
The framework of our key priorities and efforts
are organized along the guidelines provided
in the wildfire mitigation planning,
and while some of these categories of initiatives
are mostly on a tactical level, they spill into both,
but I would say the board and senior management
operate mostly in the strategic level,
reaching out to the tactical to inspect
and see how we're doing.
And the frontline managers and supervisors operate
more in the tactical level.
We can go to the next slide.
So we've got 86 initiatives in progress.
I'm just gonna highlight some
of what I think are the more compelling
towards achieving a safe grid.
One is a covered wire project.
We did some pilot testing
and also worked with the other utilities
and we selected the priority wires as our primary product.
It has a fire retardant in its insulation layers,
and we have a program to replace
approximately 4.3 circuit miles
on the sub-transmission system,
and 8.6 miles on the distribution system per year.
To date, we've replaced approximately
9 circuit miles on sub-transmission
and 10 circuit miles on the distribution.
When we replace the bare wire with covered wire,
those poles are completely hardened,
they're wind loaded, tested with spider calc,
they're tested for their structural integrity,
the hardware on the pole is changed out
so that we have a completely hardened system
when we're done with that.
The risk assessment and mapping is a project
that we focused on this year.
In the past, Bear Valley follows what the small,
multi-jurisdictional utilities used
for risk-based decision making,
but this is going beyond that.
We hired a consultant to develop
specific risk modeling to include risk maps
that show the overall ignition probability,
and then the estimated wildfire consequence
along our electric lines.
And this project, we've had previews of the results,
this project will be completed by December.
The results of this project will be included
in our 2022 WNP update,
as well as in our next rate case.
And honestly, most of the results are consistent
with what we had discovered with our own internal models.
The biggest thing that this project does
is it uses much more sophisticated weather
and wildfire spread databases.
It also uses ignition probability databases
that we didn't have access to.
So I'm pretty excited about this project
being completed this year.
This year, we also implemented drones
to conduct imaging and thermography inspections
on our facilities, and we just completed
our first one in September.
And we also have a project that's ongoing
to go and assess the structural integrity
of about 8,000 poles.
To date, we've tested 3,024 poles.
We've replaced 773 poles as a result of that,
and we remediated 110 poles.
When we do the load assessments,
we do a 3D stress analysis using spider calc.
Some of the other utilities use ohcount,
those are all acceptable.
We also check for the internal deterioration
of the poles, and we also look for uncorrectable
geo95 deficiencies when we do these assessments.
We can go to the next slide.
Another initiative that we have ongoing now
is the evacuation hardening route project.
We did a pilot to look at different solutions.
We evaluated our evacuation routes with the sheriff
and local fire departments,
and we have three main evacuation routes.
Some of the facilities along those evacuation routes
are already underground
or were fire resistant composite poles.
We identified 812 poles with holds along those routes,
and so we targeted them for hardening.
The method that we chose was to install a wire mesh wrap
on those poles.
400 this year have been installed,
and 412 next year.
That was, by far, the most effective, rapid,
and economical approach to achieve 100% hardening
along our evacuation routes in a two year period.
We also have implemented a policy
that any time we replace a wood pole
on the evacuation route, we will replace it with steel
or fire resistant composite poles.
We have a grid automation project
and installed a fiber network in our service area.
Basically mimics our sub-transmission system
and connects all of our substations.
The fiber network is about 90% complete.
We also developed a SCADA software system,
and next year we will actually begin
connecting substations and field devices.
And this will set the backbone for newer technologies
in years to come.
For example, fast acting switches connected to sensors.
We also have a project that installs,
it's called the fault localization
isolation system restoration,
or as in the business, FLISR,
and basically, if you think of our sub-transmission system,
it's a circle that connects all of our substations
and our power supplies.
By installing nine IntelliRuptor pulse closers,
these devices talk to each other
and whenever a fault occurs on a 34 KB system,
it's immediately isolated by two of the switches
and the rest of the system is restored.
So it enhances our fire safety by quickly isolating faults,
minimizes the number of customers to no more than 2,000
can be out of power, and it allows the crews
to know exactly between which switches the fault is
so they can get there quickly
and quickly assess what's going on.
Probably our most ambitious project
is the Radford line replacement.
If you recall on the map that was on the third slide,
there was a line coming up from the South,
that goes right through the forest service area.
It's the high fire threat tier 3 district.
It replaces the 34,000 volt line and all the poles,
about 67, with covered wire and fire resistant poles
using a distressed iron product.
Right now, that project is in full evaluation
by the US Forestry Service for permitting
and we expect to begin construction
at the end of the Winter weather in April of 2022,
and should be completed before October 2022.
Most of those poles will have to be replaced
using helicopters due to the steepness of the slope
and lack of roads.
The final project that I wanted to mention
of the initiatives in progress
is the tree attachment removal project.
When we started this project,
there was 1,207 tree attachments.
To date, we've removed 493
and we have installed 286 new poles.
As you can imagine, when you use tree attachments,
you have to follow the trees.
When you use poles, you can use a more economical
and effective geometry that uses less poles.
And yes, the tree attachment in that picture is gone,
it was the first one gone.
Next.
We've enjoyed a pretty good safety record.
In fact today, this brief was as of 29 October,
we were at 904 days accident free
and very thankful for that.
However, I fear complacency and so we have to work every day
to ensure complacency doesn't set in,
especially when the record is so strong.
Every day without incident is a win to us,
but the next day is a completely new play,
and so we're pushing our managers, supervisors,
to be engaged in the field
'cause in my mind that's where the rubber meets the road,
and that's where we have to maintain our high standards,
out in the field.
We can go to the next slide.
The table on the right shows the risk reduction to date
based on our fire safety matrix.
It's about a 14% reduction in risk.
It's based on a model that's not perfect,
but it does allow us to track the relative progress
over time, and I would love to a risk reduction meter
in my office that was updated every hour,
but short of that, I get this.
And the nice thing about the model is one,
whenever we make changes to the model,
we go back and plug in the original data
so that we have apples to apples comparisons,
and it allows us to evaluate each circuit
and then the totality of circuits.
It also allows us to say hey, if I do 2.5 circuit miles
of covered wire on the bulbon circuits,
what's the impact on risk reduction?
So we're able to put our detailed work plans for 2022
and estimate what we think we're gonna achieve
that year in risk reduction.
And I think what we're seeing is we are improving risk,
and our goal is to get rid of our high risk circuits,
and then once we are in the medium risk field,
bring us down to low risk.
This algorithm that we use takes about 20 inputs
and it includes everything, even just for example,
if we complete our ground patrol
and find a number of deficiencies, risk will go up
when we plug that in the model.
So it's dynamic as well,
it's not just looking at hardening issues.
You can go to the next slide.
We did implement enhanced vegetation management
back in the Spring of 2018.
I was following the Commission's decision
in 2017, in December, which introduced
more vegetation requirements,
and we took that on and we also increased
some of our standards.
For example, a little bit of the sub-transmission
we have a blue sky requirement.
We increased our minimum line clearance
from 48 inches to 72 inches.
So by geo95, you have to start trimming
when it gets to 48 inches,
we start trimming at 72 inches
and then we trim out 12 feet minimum.
We also have a program to eliminate trees
that pose a risk to our lines,
and that's not just trees that are in the clearance zone,
it could be a tree across the street that is dead
or diseased and could fall into our lines.
So that's another key element of our vegetation program.
We have a contracted forester on staff who's not associated
with our vegetation clearance contractor,
who advises us out in the field on how we're doing.
And then finally, all the managers and supervisors
and certain subject matter experts including myself,
we go out and we do vegetation management QCs.
In the last three months, we were all doing it weekly,
and we divide the work by the contractor.
As you can see by the numbers of vegetation contact
on lines has gone down significantly since we implemented
these enhanced vegetation management measures.
And the other benefit of this, honestly,
is improved reliability in the Winter
when we have a lot of snow storms
where vegetation will hit the lines.
May not be a fire threat at that point
because of all the snow, a wildfire threat,
but it's a reliability issue,
we don't get as many outages now due to vegetation,
and so people don't lose their heat in the cold weather.
We can go to the next slide.
These are some of the initiatives we've completed.
Similar to what San Diego Gas Electric did,
we installed the Pulse Conditioned IntelliRupters
on our re-closers.
Those are the ones that when they automatically cycle
on a fault, they only test with 10% of the previous power.
So the amount of energy sent down the line to test
is reduced, reducing the likelihood of putting high energy
into a fault that may still exist,
thereby reducing the likelihood of a fire.
However, on these high risk states,
we put our re-closers set to manual anyways.
We've partnered with UCSD, Dr. Neil Driscoll,
and the ski resort, and Big Bear Fire Department,
Cal Fire, and San Bernardino Fire Department,
and we installed 15 cameras at seven sites
and we have excellent coverage of our service area
with the ALERTWildfire cameras.
In fact, two of the cameras are on one of our poles
at Dead Man's Ridge, and I think I talked about Cal Fire
and Big Bear Fire Department,
they were very satisfied with the coverage
that we've achieved.
I'm not sure if the brief is still visible.
Brendan: This is Brendan with IT.
It should be still visible.
-: Okay.
It disappeared from my screen,
but if everyone can see it, fine.
We also sectionalized our system
the high risk areas that,
if we were to have a PSPS,
these could be the most likely areas,
such that we wouldn't affect customers
that weren't at risk in a PSPS scenario.
We also have been doing LIDAR.
The Light Detection and Ranging surveys,
and this year we completed our third one.
This has become an annual routine for us,
and a very useful tool.
The other thing we've completed
is our third party ground patrol.
So this is the third year that we've completed this.
In addition to us conducting geo165 ground patrols
each year, we have an independent, third party contractor
come in who doesn't do any construction work for us,
do a QC on our system.
Another project we've completed is weather stations.
We've installed 20 weather stations
throughout the service area.
Divide 20 by 32, we probably have the highest density
per square mile of weather stations,
but we do have some micro-climates here
and these provide us excellent weather data
especially on wind, wind gust data, average gust data,
and also there's a historian that collects weather
at each of these stations,
so as we go forward in the future,
we'll have better forecasting capabilities.
And the final one, which I think was our early win,
was we had the fuse upgrade program
where we eliminated all expulsion (conventional) fuses
from the system.
3,114 expulsion fuses were replaced
by 2,578 current limiting fuses
and 536 electronic fuses.
And you can see in the picture,
what an expulsion fuse does when it blows,
it shoots out metal slag which has the potential
to cause sparks, which could cause ignitions, fire,
and therefore, potentially wildfire.
We could go to the next.
I don't think our challenges are unlike the other utilities.
I will say though, staff is a challenge here in Bear Valley.
We're kind of like an island,
it's about 50 minutes to an hour to get off
or up the mountain.
Even longer in bad weather,
and we require our staff to live in the service area.
We do have a turnover rate
of somewhere around 20-25% per year.
So it's like starting a football season.
Having a fairly new members of the team every year,
and having to get them trained up
and get them into our safety culture
and get them up to speed on our standards.
But Big Bear Lake does have some very positive attributes,
so our challenge is to find staff that's aligned
with those attributes and I think as we focus on that
when we make our hires, we should be able to retain staff
at a higher rate.
Same issue with power line construction,
contractors is a high (indistinct) in the state.
The big utilities have big projects,
Bear Valley has relatively small projects for them,
and they also have to mobilize their crews up here
because there are no power line companies
in Big Bear Lake.
However, we've been successful at finding
a number of contractors that are willing to come up here.
In fact at this point, we have three major
power line construction contractors
that are engaged in work with us,
and three different, so that's good news
so that we're able to go out to the market
and get competitive bids.
Supply chain is a challenge, obviously.
I think initially when we started implementing
wildfire mitigation efforts in 2018 and 2019
there were some significant supply challenges
in getting covered wire, the fire-resistant poles,
and those materials, but we've done a couple of things.
One, we've built up a supply on the mountain
to meet our future project needs.
We also established a vendor alliance
with the main vendor for Southern California Edison,
and we looked at what Southern California Edison uses
in its grid hardening and tried to align where possible
our specs to theirs so that those items are in stock locally
in the same area.
So we have enough material now in the market
so that if we were to have a wildfire up here
for any reason and we had to rebuild a circuit,
we don't have to build that circuit in like time.
For example, if it was a whip pole circuit with bare wire,
we would rebuild it with steel poles and covered wire,
and then we just have to get more materials
for the mitigation projects.
So it's important to keep material on the mountain,
especially when you have storms
that shut down the roads and so forth.
And then the other challenge is permitting.
With forestry services is a lengthy process,
and we also have challenges getting permits
to clear vegetation in the Caltran right of ways,
but when we do see some stuff
that we really need to get to now,
we find them to be responsive and so we work through those.
The final challenge is COVID-19,
I think it's a challenge to everybody, obviously,
but there's less person to person engagement
and that challenges work site leadership,
monitoring, mentoring, and teaching staff,
and so that's always been a big challenge.
It's important to me to be out
and engaged with our staff,
that's the way you teach them and mentor them.
If we could go to the next slides.
We have established a three year safety culture plan.
We're working on all of these initiatives,
although some are due later
that we want to be at the maturity level.
We also engage the EHS consulting firm, BSI America,
to perform a gap analysis and assist us
with resolving gaps in implementing
our safety culture plans.
This will be a three year effort.
Additionally, we're using the results
of our safety culture assessments
at the Office of Energy Infrastructure Safety
conducted through it's contractor NECRA
to guide us and make course corrections.
You could go to the next slide.
We did receive our safety culture assessment report
for 2021.
We found it to be a very useful tool.
The report provided an excellent description
on opportunity for improvement.
It also provided results of the employee surveys
in several formats that really allowed Bear Valley
to analyze the various worker demographics
and see where additional improvement and work
should be directed.
The assessment noted the following:
One, embedded leadership skills into engaged management,
12 month objective to improve the Bear Valley
safety culture.
That is we need to give the leadership skills
to be engaged.
Get out how to do a job hazard analysis,
when you go out in the field,
what are you looking at when you see a line crew
up on a pole or something?
And then in collaboration
with our vegetation management contractor,
develop and implement an action plan
to address safety culture issues,
in particular, regarding the flow of information
about wildfire hazard mitigation.
This is our contractors did the survey as well,
and they had some issues with employees do not feel
that they are empowered to bring issues up
with their supervisors, and so that's something
that we need to take on.
And we did formally agree to implement
all of the findings and recommendations for improvement
in our 2021 safety culture assessment.
We could go to the next.
I think we skipped one, just go back one.
Yeah.
So there's two areas which we can capitalize on
that were good news.
Bear Valley's safety culture
emphasizes identifying wildfire hazards
and protecting the community.
Employees feel a strong personal responsibility
for their own and other's safety.
However, we have a high turnover rate,
so I have to keep that going.
That's a great snapshot for then,
but we get new employees
and we need to get them up to the team's standards.
The were gaps, and while in the safety
and wildfire categories, the average scores were good,
in the culture categories they were a little lower,
and that was mainly in the customer service
and accounting areas.
So we need to take a look at what issues
are going on there.
I already talked to you about
the vegetation management contractor has some issues
with field employees that we need to work with them
to resolve.
And I think that I accurately pointed out
that we have these objectives,
there needs to be a little more detail
on how the progress can be monitored and sustained,
so we take that on board.
We could go to the next.
The safety and operations committee
reports to the board of directors.
It is responsible for overseeing
the wildfire mitigation plan
and assessment of compliance with the plan.
It is responsible for other activities
including identify wildfire risks
and other safety risks, steps taken to reduce such risks,
and then other matters directed by the board.
The committee shall and does have unrestricted access
to members of management and all information relevant
to its responsibilities.
I would say that when we meet as a board,
the safety committee meets first,
and the safety committee meetings are generally longer
than the board meetings.
There's a lot of detail that's placed there.
We could go to the next slide.
Bear Valley Electric's executive officers performance
is accountable to and subject to control of the board,
and the executive officer is given not only responsibility
but the authority to execute those responsibilities
and therefore, should be held accountable in totality.
The executive compensation plan is designed
to promote public safety and financial stability.
Safety is a priority, ensuring public safety,
it ensures financial stability of the utility,
it utilizes performance metrics that are measurable
and enforceable.
There's no discretionary component
so that, let's say, safety metrics aren't met,
the board can't say well,
you didn't meet your safety metrics,
but we're still gonna give you a discretionary bonus.
Not in our plan.
And the plan allocates the primary portion
of the compensation based on achievement
of performance metrics that are measurable and enforceable.
That concludes my brief, next slide.
-: Thank you, Mr. Marconi.
I will open it now to questions from the virtual dais.
Go ahead, President Batjer.
-: Thank you very much, Carolina,
and thank you Mr. Marconi for your presentation,
it was extremely helpful.
How long have you been chair
of the safety and operations committee?
-: I was chair in this Summer
when we did our annual reappointing
of the safety and operations committee.
So for history, Bear Valley Inc. was formed
in July 1st of 2020,
and so our board of directors formed then
and also our safety and operations committee formed then.
And then each year,
we reappoint members of the safety committee and the chair.
-: And how many members of the board of directors
are on the safety committee?
-: There's three total.
-: And you said that you meet on the same time
in conjunction with the board meeting.
Does the safety and operations committee
ever meet additionally from that?
-: We haven't had occasion to do that.
We have had occasions to meet in special session
for a safety committee.
For example, to pass a resolution
that then needed board approval.
So the driver for the board meeting
was also a safety committee meeting, a safety issue,
and so the safety committee met, discussed the issue,
approved the resolution, and then turned around
and then the board met and the board had to approve
the recommendation of the safety committee,
or had to discuss it
and decide whether or not to approve it.
So we've done that a couple of times.
-: Okay.
Has the safety committee been involved
in some of the recommendations?
For example, sorry if you're hearing
a bunch of blowing going on (laughs) bad timing on my part.
A little concerned about how it would sound
that you all needed to further empower your line people
to feel empowered to raise safety issues
up the chain of command,
and just wondering, you talked about how important it is
to get out in the field.
First of all, I think you use the words
we're going to take that up.
I'd like to know how active you are
in correcting that right now,
and how active is the safety and operations
committee members in making sure that those line people
are indeed empowered?
-: Okay, just to make sure for accuracy,
the line people that we're talking about
is the vegetation management contractor,
not the Bear Valley line crews.
In fact, the Bear Valley line crews
do feel very empowered to stop work
according to the safety culture assessment,
and we are engaging with our contractor-
-: That was my error.
So thank you for correcting that.
-: But we are engaging with our contractor
to address this issue and make sure that we resolve it.
As far as getting out in the field,
I'm obviously out in the field quite a bit
at least weekly.
I've had one of the other board members now,
he's been up here in the last four months
or five months twice, out in the field,
and the third board member,
we're just trying to schedule him to come out.
He used to be a former employee director
when Bear Valley was a division
of Bear Valley Electric,
and is very familiar with our system,
but we want to get him out in the field
so he can see some of the differences
that have occurred since he's been gone.
-: Sounds like a good idea.
So you said that your employees
are required to live in the service area,
what about the board of directors?
-: No, they are not.
-: They're not required
and they don't live in the service area?
-: Only myself.
The other two don't, no.
The board of directors are more at the strategic level.
The reason why the staff needs to live there
is it's 50 minutes, in storm a lot longer,
to get up the mountain.
When we have a problem, we want people to be up here
ready to do what we need to do.
It also gives us a personal stake in the game here.
We don't want wildfires either, believe me.
It can be pretty scary up here whenever we have fires.
-: Indeed it can be, for everyone.
So thank you, I have more questions,
but I'm gonna save time for my fellow Commissioners
and for the director.
So thank you, sir.
-: Go ahead, Director Thomas Jacobs.
-: Thanks.
One quick follow on and then I have a couple others,
but that was really interesting
in terms of the board members,
I get that they aren't required
and don't live up there, do you guys have a current
cadence in which they're, not to say required,
but that they're coming up to be in the field?
Even at the strategic level, just to have an awareness
of what your needs are.
-: So we will be having our board meetings up here.
Right now, we have them via web-based
due to COVID protocols.
We are still not in a ...
But we will be going to in person meetings here,
we hope, in January,
and we will hold all our meetings up here.
And part of the meeting cadence associated
with coming up here will be getting out in the field.
We do meetings at least quarterly.
-: Great.
So my question, a lot of what you talked about
was challenges with supply chain,
challenges with contractors, challenges with turnover.
As you articulated in our safety culture assessment,
one of the general issues we identified
was quality in the wildfire mitigation plans
and compliance work that we do.
It's great that work is getting done,
but it's really important
that even if the inspection's complete,
that you're confident in the quality of the inspection.
So can you speak a little bit more
about what quality assurance programs or efforts
you guys have underway?
I think you mentioned in your briefing
that the management team goes out
and does some of the QAQC, but what is the level of rigor
and standardization around that QAQC
to ensure the work that is happening
is being done at the quality you guys would expect?
-: So the engineering and planning group
reviews all the designs and work packages
before they go out,
and they must approve them
before they give a contractor notice to proceed.
Then they go to the field inspector
and he's the actual line person that delivers it
to the contractor,
and they set up a work in progress QC protocol
of every day I want to meet with your team
or I want to see what you've done,
when you hang that transformer,
I want us to be called and be there when you do it,
and we do a lot of work in progress QC.
Upon work complete, the contractor will return
the work package to us with as built.
In other words, they're making modifications
to the work package, and then the field inspector
verifies all the work that was reported to be done
was done, and the materials that the contractor
said they used were used.
And then we tell the contractor that they're authorized
to send us an invoice.
When they send us an invoice,
it goes to the project coordinator,
who audits the work package against the invoice,
and then it finally then goes through for approval.
So there are several levels of QA,
looking at the work packages and all that,
and then there's QC out in the field
looking at what was actually done.
-: Thank you.
And a question on the EVM implementation.
So on that slide, I think if I remember correctly,
on the briefing you said the enhanced
vegetation management was implemented in 2018,
when you started the work,
and ultimately you got it across your entire grid by 2020.
Looking at the drops in veg management,
the biggest drop was from 2016 to 2017,
and then there was a continued slow ramp down.
What was the driver between 2016 and 2017
for that biggest drop?
It sounds like you hadn't implemented
the enhanced vegetation management yet.
-: We hit the highest risk areas first
where we thought we had issues,
and it looks like we found them.
You drive around,
you can see where you have thick vegetation,
and so I wanted the contractors there first.
We said we're starting the plan over today,
we're not just continuing on our routine,
and I want to get these risk areas done now.
I'm not sleeping well, so I want them done now.
-: That was in 2018 though, correct?
-: Yes.
-: So the biggest drop there was between 2016 and 2017,
so that (indistinct).
-: Yep, 2016 we had some major storms
in January and February.
So that large number was just due to Winter storms.
They probably weren't wildfire threats,
but in 2017, we didn't have as many storms.
I think January 6th through the 9th of 2016,
we had a very major storm up here.
I remember that one pretty well
'cause we had many outages.
-: And then last question,
you reported that the third party ground control
was an important addition to your wildfire mitigation plans.
For the third quarter quarterly notifications,
that particular initiative is off track.
Can you speak to what the current status is of that,
and what you guys are doing to get it back on track?
-: Yeah.
So even though the patrol had been completed,
we had not received the results,
and when I'd heard we had not received the results
by September 30th which is the cutoff for the QDR/QIUs,
I said well, we can't call it complete
because what good is an inspection without results?
So yes, we reported it off track
and we have results and we're fixing them.
-: Great.
So basically the work was actually done,
you're just saying you didn't have the results
so you didn't want to claim the credit for that.
-: Right.
(indistinct).
-: Great, thank you.
That's it for me for now, thanks.
-: Please go ahead, Commissioner Houck.
-: Yes, I'm just wondering about,
I believe you said that you had significant turnover rate,
I think up to 25%, and part of that being
the remote location, but I guess the concern
with recruiting and retaining skilled staff
is obviously really important
to making sure the safety measures
are being implemented on the ground.
So can you talk a little bit more
about how the board is addressing those challenges
to ensure that you've got sufficient staff
to make sure these measures are being implemented?
-: So that's a great question.
I did make a presentation to the board
about this issue last year,
when we renegotiated our contract with the IBW,
we did authorize some improvements in their pay
beyond what we've done historically to address that issue,
and the other thing is we are working with
our human capital management group,
we have an exit interview process now
so that we can begin to understand why people are leaving.
These are done by a third party,
and take those on and try to address those issues.
It's challenging,
people think they like to live up in Big Bear,
and then after a year or two of not being next
to whatever their favorite store is, it can be challenging.
Honestly, like I said,
it's 50 minutes to an hour to get on and off the mountain.
During the peak season, if you want to go to the store,
it could take you, even though we're small,
it could take you two hours with the traffic.
We have 200,000 visitors up here,
it can get very challenging for the local residents.
It can be challenging for them in their way of life.
-: Thank you,
and I look forward to seeing how that progresses
and the information you learn from those surveys,
and how you're hopefully increasing
to make sure you've got the correct staff in place.
So thank you for the response.
-: Commissioner Shiroma.
-: Yes, thank you.
Thank you for the thorough presentation.
For your safety committee, Mr. Marconi,
is there a charter?
I was looking at your website and I didn't see
any reference to your safety committee or-
-: There's a charter.
I'm not sure if it's on our website.
I think the safety cert went to OEIS,
and so when we do that, we provide it in that package,
but I can send it to you.
-: Okay, sure.
And then on your slide 13, let's see ...
Actually, it's slide 14, the last bullet,
Bear Valley's safety culture objectives
do not provide details on how progress will be monitored
and sustained.
And then back on your slide 12,
you've got your initiatives, the summaries,
and some dates.
So the transparency and open communication,
it says December 31st 2023,
and the initiative was targeted,
management frequently conduct safety briefs
and encourages employees to periodically lead them.
Safety committee meeting minutes
and safety performance measures are shared with employees.
Employees are motivated to report hazards,
encouraged to make recommendations,
employees have buy in in all aspects of safety.
So I want to reconcile that with this date
of December 31st 2023, which is two years from now.
-: Yeah.
As I mentioned, while we have dates
on where we want to achieve the full maturity level
on that initiative, we are working on that initiative today.
We're working on all of these initiatives,
we're not oh, we're gonna start doing that.
That's an important one,
and that one takes a long time to fully achieve,
but we have to start today.
We've already started on it to get there,
and that's an ongoing process,
and so like I said, we're not just holding back
and waiting.
-: Good, good.
Are you sharing your meeting minutes
and safety performance metrics now with employees?
-: No.
We just hired a safety consultant
who will be at our next meeting next week.
I've talked to them, so my goals
and what I want to achieve,
and I think within the next month or two,
we will be doing that.
-: I'm a firm believer that things need to be written down,
ratified, and easily accessible,
and so in terms of these safety performance metrics,
the expectations of use, the other board of directors,
are these things written down and accessible
to your employees?
-: So as far as the metrics go,
the only metric that we display
besides the required OSHA (indistinct) forms,
we do display on a marquee the number of days
accident free to all our employees
in very visible locations.
We have a weekly management meeting
where we go through our safety metrics
with supervisors and managers and other key people,
but we don't put that out to all employees yet.
We're working with our consultant
to come up with some weekly communications,
and part of that will be the safety record and metrics
so that employees can feel ...
And I think right now, employees feel very strongly
about the number of days we've been accident free.
In fact, sometimes I fear
that someone might not report an injury,
but they don't want to be the one who broke our record.
So I emphasize to supervisors tell your guys and gals
that don't take anything for granted, be open with us.
I told a lineman personally,
you go out to a job site and you forget something,
it's okay, we'll drive back to the yard
and get what we need, or we'll drive up the mountain
and get what we need.
There's nothing that they are doing
that is worth risking anybody's life
or going home injured.
Absolutely nothing.
-: Yeah.
I can see through you that you are really looking
to embody the soul of the utility,
of the priorities, and that you live up there.
It's very important
that you're out in the trenches frequently.
Really, my query is that are you confident
that everything that you are living, eating, breathing,
in terms of the safety culture as a top executive,
how are you going to assure that those values
are chronicled, adopted, communicated,
and in terms of meeting these deadlines ...
One person can make a difference absolutely,
but how do you infuse your verve
into the organization so that it is there for longevity?
Are you confident that you're going to be able to do that
with these various steps and plans that you've outlined?
-: So that is challenging.
I will say that my field operations,
he's up here for the long run.
He shares these values,
he believes in what I call intrusive leadership.
It's very involved in everything,
and I won't say he's a micromanager,
I will just say he's just engaged
where he has to be engaged.
He's a key element of my team.
I have some newer supervisors that I have to work
and mentor and train to make sure
that they also understand,
and like you say, it's a challenge.
I have to make sure even my accounting supervisor
understands that when we need a part,
we need that part, not something else,
because they're in charge of procurement.
It's a team effort,
and when we receipt materials or we assign contracts,
we need to make sure all that stuff is right too
because it adds to everything.
And we also need to make sure
that when that customer service rep takes the phone call
and says someone's reporting arcing and sparking,
that that phone call doesn't get parked somewhere
and not get addressed.
It has to get right to the duty team
so that they can quickly be energized and get out there.
-: I think your initiatives outlined on your slide 12,
the targets, which is gonna be important
to have those communicated well and frequently,
and that the work is underway,
and that if you can actually beat those deadlines,
that that would be important.
All right, thank you.
Thank you.
-: Thank you, Commissioner Shiroma.
Please go ahead, Director Thomas Jacobs.
-: Thank you.
So just wanted to reiterate on a couple things
that you said, Paul, I think they're really important.
One, really appreciate that you called out
that your concern now is that people would be hesitant
to report something because of the length of time
in terms of going without an injury or an ignition too,
so want to just reinforce that.
I think that's a healthy concern to have.
I think it's fundamental to building a safety culture
to develop a open communication.
If you don't know about it, you can't fix it.
So I think it will be important across the organization,
especially with the turnover
that it sounds like you guys struggle with
just because of the dynamics that you have
in your particular organization and location,
to constantly be reinforcing that.
As well as with the contractors,
reiterating again what you've already called out,
that there is a difference between the workers
that live in your area and are rooted in your organization,
and the contractors that are coming in and out
of that organization, and yet they play a vital role.
We find that across all of the utilities,
they are playing a vital role
in executing these wildfire mitigations, but more broadly,
safety activities that the utilities
are currently implementing across their systems.
So just want to call out again,
the importance of developing a culture around that,
of open communication where identification of issues
is encouraged and supported and responded to
in such a way that it breeds further communication,
as opposed to shutting anybody down.
So if you can speak to me a little bit more
about specific actions you guys are taking
to breed that within your organization,
I would appreciate hearing that.
-: Yeah.
I think we need to have more direct communications
with our employees.
COVID has caused me to speak less directly
to our employees than I had in the past.
I used to have monthly everybody get in the conference room
early in the morning and we'd talk,
and that part is missing,
and it's been challenging to get around that,
but I've talked to my supervisors
and then asked them to have that conversation
with their employees and that's been working,
but maybe I personally also will need to get out,
make a rotation and go to their briefs
and emphasize that from me,
that they know no one's gonna be thrown under the bus
if they say hey,
we forgot one of the many grounding cables we need,
and they don't make a decision to just not install
that grounding cable, go back and get one.
That they understand that, no one's gonna be mad.
I'm a believer that there's only one way to do something
and that's the proper and safe way.
I don't believe in safety first or things like that
'cause that implies there's another way of doing it.
So the only way you should do it
is by the procedure, the proper way we do it,
to our standards.
And so that's important,
and that's a message that has to be discussed
over and over and over again.
I do engage with the union rep,
we meet quarterly and we talk about safety,
and he gathers with the union employees afterwards,
and we communicate our concerns
and he communicates his concerns
and we address those,
and I've found the IBW local 47
to be extremely safety oriented
and committed to holding their members to a high standard,
and I appreciate that.
They feel very empowered,
feel very much that the workers they provide
have to meet high standards,
and they're committed to holding them to high standards.
So when I bring issues up with them, they take care of them,
and so I think that's been a very good relationship.
-: Thank you.
If there are no further questions,
I think we are ready for our break.
We are somewhat ahead of schedule,
so we will be reconvening at 1:00 PM.
Again, that will be 1:00 PM to reconvene
for PG&E's afternoon session.
So thank you, Commissioners,
Energy Safety Director, and presenters,
we will reconvene at 1:00 PM.
-: Thank you.
Announcer: At this time, there will be a lunch break
and the call will resume at 1:00 PM Pacific time.
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Host: Good afternoon, and thank you all for standing by.
Today's conference has resumed.
I would now like to turn the call
back to Carolina Contreras.
Thank you, you may begin.
-: Good afternoon, everyone,
and welcome back to Bear Valley Electric Service
and Pacific Gas and Electric safety update briefing
to the California Public Utilities Commission
and the Office of Energy Infrastructure Safety.
In this afternoon session,
members of the board of directors of PG&E
will present and answer questions from the CPUC
and Energy Safety regarding updates
on their electric safety related efforts.
Serving us on the virtual dais are CPUC President Batjer
and her fellow Commissioners Shiroma, Gusmanasevas,
and Houck,
Director of the Office of Energy Infrastructure Safety,
Caroline Thomas Jacobs,
and executive director, oh excuse me,
she will not be joining us right now.
In terms of format,
this afternoon's portion of the briefing will focus on PG&E.
We will first hold public comments
followed by a 45 minute presentation by PG&E representatives
on their safety update.
We will then move onto a discussion
and Q&A from Commissioners and Energy Safety director.
We are scheduled to conclude today at 3:00 PM.
Before we move on to public comments,
I'd like to ask if there are any brief statements
from the virtual dais.
If no statements, we will now-
Oh, please go ahead, President Batjer.
-: Oh no, no, thank you, Carolina.
I said I have none for this afternoon, thank you.
I made mine this morning.
-: No problem.
Thank you.
If no statements,
we will now turn to the public comments portion
of today's agenda.
As a reminder, if you wish to make a public comment,
dial into 800-857-1917 and enter passcode 5180519
for the English line,
and passcode 3799627 for the Spanish line.
Unmute your phone and press *1,
you will be placed into a queue
and the operator will take your name and information.
You will be called upon to speak
in the order your call was received.
You will have two minutes to speak.
You will hear a bell sound when your time is up.
Please be mindful of other speakers in the queue
and keep to your allotted time.
I will now turn to the operator
to open the public comment telephone line.
Operator: The public comment line is now open.
If you wish to speak during this,
press *1, unmute your phone,
and clearly record your name
and organization when prompted.
Again, press *1.
One moment, as we wait for any public comments.
There are currently no public comments.
-: Thank you, operator.
With no comments on the line,
the public comment period is closed.
Moving on.
We will now hear from PG&E representatives,
Ms. Cheryl Campbell, Floor Director
and Chair of the Safety and Nuclear Oversight Committee,
Mr. Sameet Singh, Senior Vice President
and Chief Risk Officer,
and Mr. Adam Wright, Executive Vice President Operations,
Chief Operating Officer, and board director.
Ms. Campbell, welcome,
you are scheduled for 45 minutes
and I will now turn it to you.
-: Thank you.
Good afternoon, President Batjer,
respected Commissioners, Director Thomas Jacobs,
and CPUC and Energy Safety staff.
We appreciate the opportunity to speak with you today
about our focus on safety at PG&E,
but first on behalf of the board of directors of PG&E,
I'd also like to acknowledge the anniversary
of the campfire, the resulting deaths,
and the horrible impact it had on the community.
The board recognizes the oversight role it plays
in setting the tone and priorities for the company
as it works to improve public safety.
We take the role very seriously,
and we work diligently with the leadership team
on this important effort.
I think we can move to the next slide, please.
Thank you.
We have prepared the following presentation
to address the topics that you have outlined
for the meeting, and we'll cover these topics shown,
and we're happy to answer any questions you have
at any time during the presentation.
Let's go to the next slide.
Let's start with governance
and our safety and nuclear oversight committee,
or SNO committee as we call it within the company.
The committee was formed to advise and assist the board
with respect to the oversight and review of policies,
practices, goals, issues, risks, and compliance
related to public and workforce safety.
The committee operates under a charter
which is posted and available
on our investor relations website,
and was updated and refreshed by the board
as recently as May of this year.
There are currently six members, all independent directors,
and all have, in one or more areas,
deep and demonstrated expertise
in one or more areas shown below.
The six directors are myself as the chair,
Jessica Denecore, Admiral Mark Ferguson,
Craig Fugate, Mike Nigley, and Belle Smith.
The committee meets formally at least six times a year,
including periodically joint meetings
with the (indistinct) committee.
At those meetings, we meet with management,
including the chief risk officer
and the chief safety officer, and others as needed.
We receive reports, we discuss policies and performance,
and we provide feedback to the management team.
The formal meetings are supplemented
by informal meetings, and go to see field visits.
Committee members interact with employees
at all level of the company at these field visits,
and I'll just give you a couple of examples
of where we've been recently.
We've been on vegetation management jobs,
we've been on locate and mark jobs,
last week, Admiral Ferguson and I were at Diablo Canyon,
and we have also been at the wildfire command center
and the lean operations command center
in August of this year.
The committee also periodically observes
the company's wildfire command center
during it's weekly operating review,
and meets with operational staff and senior management
after that meeting concludes.
I also want to point out that the feedback loop
is not just internal,
SNO members meet periodically separately
with external observers and parties
to get insight and feedback on the company's performance.
These parties include the federal monitor,
the operational observer, and North Star.
And underlying all of this,
is the board's commitment to promote a speak up culture
both within the company
and amongst the board members themselves.
I also want to point out that the committee's charter
includes significant operational performance
and compliance issues related to all of PG&E's operations
and facilities, which include nuclear, generation,
gas and electric transmission,
and gas and electric distribution,
as well as the risk management policies and practices
related to those operations and facilities,
including cybersecurity.
I'd like to provide you with a couple of quick examples
of the tie between our oversight rule
and how it impacts the company.
As you can see from the materials,
one of our roles is to oversee
the utilities wildfire mitigation plan and the PSPS program.
So we review the performance against the plan
with the chief risk officer on a regular basis,
and we have been providing feedback.
We did express some concerns about the risk modeling
as well as the active identification.
As a result, management updated the risk models
to address those concerns
about how the work was prioritized,
and they've also implemented asset registry improvements,
which will have an impact
on the asset management programs overall.
We also generate reports of the board
on a quarterly basis that updates the company's progress
on these important programs.
Another way that we have impacted the company
is we review the appointment
of the chief safety officer of the company,
as well as other key officers
who have significant safety focus
as part of their responsibilities.
And the third example I'd like to provide
is we collaborate closely with the people
in compensation committee to develop safety
and operational metrics
to which executive compensation is tied,
and we then meet with the same committee
and review those results.
I think we can go to the next slide if we could.
So let's take a look at the board beyond the SNO committee.
One of the areas that the company focused on
in the wake of the recent safety incidents
and as it emerged from bankruptcy,
was to restructure the board of directors
with a focus on bringing in new directors
with extensive experience in safety and risk management.
The board's currently comprised of 13 individuals
with a wide range of experience and skills.
Their knowledge and experience are used to improve
and inform workforce safety throughout PG&E
as well as public safety.
And what you see on this slide are the areas of expertise
that are found within our board of directors.
You'll find more information
about how we select our board members
in our proxy information on the PG&E website.
With that, that concludes my comments
about the governance and I'd like to turn our attention
to the wildfire mitigation efforts
which are driven by real time learnings
from our fire incident investigation of observation
of prior behavior in California this year.
So I'd like to hand that over to Sameet Singh
to take it from here.
-: Thank you, Cheryl.
Good afternoon,
and thank you for the opportunity to engage
in this forum today.
I have the privilege of being PG&E's chief risk officer,
and as Cheryl highlighted, the SNO committee is responsible
for oversight of all the company's top risks,
but we will focus today on what's on top of mind
for everyone which is wildfire safety.
Our focus on wildfire safety
is not just to make our system resilient
with the climate risk that we are facing now,
but the climate risk that we are going to be facing
in the future.
Years of drought and increasing temperatures
have dramatically changed the environment
in which we operate,
as also highlighted by Director Thomas Jacobs
in her opening remarks.
More than half of PG&E service area as of 2018,
is considered high fire risk.
This represents more than 3x increase
over a six year time period since 2012,
where 15% of our service area was considered in high risk.
And even a larger portion of our service area today
is considered to be in a drought.
2021 has been the eighth driest year
over the last 125 years in California.
33% of California is in extreme drought.
The recent rains have helped
and are a welcomed relief, but have not been enough
to ease the severe drought conditions.
So if we can go to the next slide, please.
Thank you.
The dramatic shift in the environment conditions
that changed and have changed widely accepted
electrical equipment standards,
meaning that we have to rethink
the way we deliver energy safely to our customers
and our communities that we are privileged to serve.
In California, our service area covers 65%
of the state's high fire threat areas,
creating a unique risk profile given the scale.
Additionally since 2018,
we have identified approximately 500 additional miles,
both transmission and distribution combined,
where wildfire safety work needs to be undertaken
based on an analysis of our service area
using advanced technology, 600+ years of fire expertise
with former fire services professionals
that are part of our team,
to identify the high fire risk areas in addition
to the CPUC's 2018 high fire threat district map.
So what that results in is about 31,000 line miles
in high fire risk areas,
which makes up approximately 32%
of all of our overhead line miles.
A large majority of that 31,000 is distribution,
with 25,500, and the balance of 5,550 miles is transmission.
If we can go to the next slide, please.
Great, thank you.
We have expanded our wildfire safety capabilities
significantly to address this challenge
as we have an unwavering focus to ensure
catastrophic wildfires shall stop.
In 2018, we launched a comprehensive program
to address the growing wildfire threat in our state.
Since it's launch, we have continued to add,
as you can see in the slide,
new layers of safety to our system.
The technology we use and the tools we have available to us,
and our co-workers and our contract partners.
The foundation for our capabilities has been informed
by extensive benchmarking
with our peer utilities in California,
as well as practices implemented in Australia,
and the capabilities have really focused on several areas.
First, is advancing our risk management approach
based on artificial intelligence,
machine learning practices, to identify and target
the highest risk areas of our system.
Implementation of situational awareness
and intelligence with a focus on sharing
the collected information publicly with first responders,
agencies, and our customers.
Enhanced maintenance practices such as system inspections
and enhanced vegetation management,
and fundamental redesign and construction
of our electric grid to make our system resilient
to the climate risk.
And lastly, adjusting grid operations
to operate safely during adverse fire weather conditions
such as EPSS,
which is the Enhanced Powerline Safety Setting
or fast trip, as well as a measure of last resort
which is PSPS, and I will discuss EPSS
in a lot more detail shortly.
Before they're improved,
our planning and execution of wildfire safety work,
going into 2021 we implemented two significant
systematic changes.
The first is we stood up the wildfire risk
governance (indistinct) committee, which I chair,
not only to approve the methodology and work plans
for each of our programs,
but to review the progress and discuss and approve changes
to those plans so we're continuing to reduce the risk
of catastrophic wildfires for our customers
and our communities.
And the second is that we have implemented
a lean operating system, which we discussed in detail
during our Monday session with this dais,
regarding the enhanced vegetation management
collective action plan.
This system provides radical transparency
to all aspects of our execution
against the risk informed plans,
and it improves the ability of our teams
to safely execute work and to raise issues
through the daily operating reviews.
With these significant changes,
we are still not satisfied because we know
we have more work to do,
and we also know that when it comes to safety,
our work is never done.
If we can go to the next slide, please.
Over the past four years,
we have made progress in making our systems safer.
This year, we completed our goal
of installing a cumulative 1,300 new
advanced weather stations that equates
to approximately one weather station
for every 20 miles of overhead line that we have
in the high fire threat district.
By next year, we will complete the installation
of 600 high definition cameras
where we'll be able to cover more than 90%
of our high fire threat districts in our service area
through the situational awareness capability.
At the same time, we know that public safety
cannot come at the trade off of reliability
for our customers as it did
through our initial implementation of EPSS.
That is why reducing the impact,
not only for EPSS but also PSPS events
for our customers, using six correlation devices,
enhanced weather forecasting is so important.
I'm gonna first touch on the improvements from PSPS
and then later I will touch on the work we've done
related to EPSS.
We have more than quadrupled the number
of sectionalization devices which help us separate
and segment the electric grid into smaller parts,
in turn, allowing us to be much more targeted
for deactivation during severe weather and fire conditions.
Between 2019 and 2020,
based on all of the infrastructure improvements
as well as the advancements we've made
on the meteorological and numerical modeling side,
we have been able to reduce the scope of PSPS events
by more than 50% for similar weather conditions
without taking on additional wildfire risk.
We are also hardening our electric system
with stronger poles, covered power lines,
and under grounding in high fire threat areas.
Since 2018, we have hardened more than 650 line miles,
and since nearly 1/3 of our electric lines
traverse the high fire threat districts,
we are focusing our enhance vegetation management efforts
in the communities with the highest risk.
Again, we have discussed in quite a bit of detail,
and since we launched our EVM program,
we have addressed more than 5,500 line miles of vegetation.
It's the combination of the safety programs
that is helping our customers stay safer,
and reducing the risk of catastrophic wildfires,
but we know we must continue to improve
as we keep up with the ever changing climate risk.
With regards to the specific 2021 wildfire mitigation
plan commitment progress as requested
by Director Thomas Jacobs at the beginning of the call,
of the 53 commitments, 30 are complete,
15 are on track with our original schedule,
5 are off track from our original schedule
but we have clear line of sight to complete
by mid December or sooner,
which is prior to the end of the year commitment.
We are tracking our progress for all of these commitments
on a daily basis using our lean operating system.
The last three are also on track to be completed
prior to end of the year,
but will be completed late from the target date
that we had included in the 2021 wildfire mitigation plan.
Hopefully, Director Thomas Jacobs, that's helpful
to provide an update in regards to how we're tracking
on those commitments.
If we can go to the next slide, please.
Let me touch a little bit on one of the major decisions
and announcements that we made earlier this year,
which is to commit to place a significant portion
of our overhead distribution system underground
in the high fire threat districts.
Since 2019, we have underground over 85 line miles,
and will complete another 45 by the end of the year.
And in 2022 and in the coming years,
we will see a significant ramp up
in our execution of the underground miles.
The work that we've done and are doing today
related to under grounding in Paradise,
has provided us with innovative construction methods
and techniques to reduce the cost to perform this work,
and enable a significant risk reduction per dollar spend
when we consider the full active lifecycle cost
for certain parts of our system
in the high fire threat districts.
Under grounding not only improves the safety outcomes,
but also eliminates PSPS impact and outages
that may be experienced during Winter storm conditions,
thereby also improving reliability.
This program is the largest program of its kind
ever to be undertaken at the wildfire risk reduction effort,
and we understand the challenge that is ahead of us,
and we are continuing to collaborate
with many external partners through our established
underground advisory council to shape our approach,
plans, and execution, and the council is co-chaired
by one of our executive leaders, Carla Peterman,
as well as by the President
of the California Professional Firefighters Union,
Brian Rice.
This major effort is getting underway now,
and we are engaging with local communities
to understand their local priorities
and potential concerns and developing an implementation plan
that we will outline in the 2022 wildfire mitigation plan
that will be submitted in February of next year.
We can go to the next slide, please.
Was not planning on covering this topic-
-: (indistinct).
Can we go back to ...
What is the process that you're using
to engage local communities?
Is there a role that your regional vice presidents
are playing in determining the locations
that you're gonna be including in your 2022 plan?
-: Thank you, Commissioner.
Absolutely.
So our five regional vice presidents
are engaged as part of this effort.
We are also including the output of our data
from the wildfire distribution risk model,
which has informed many of our mitigation plans
and programs for this year.
We have also engaged our former fire services professionals
which are public safety specialists,
to give us the boots on the ground assessment
of communities that have an ingress/egress challenge.
So that input's being considered.
In addition to that, we are also looking at areas
and portions of the circuit
that have been significantly impacted
by repeat PSPS events since 2020 and 2019.
So those are all the different factors
that are going into helping inform a overall
execution work plan that the teams are pulling together
with that engagement and support from the RVPs.
-: Okay, and those are excellent risk state factors,
but what is the engagement with the local governments
and communities on selection of these lines?
-: Thank you, Commissioner, for that follow up.
The specific engagement is in regards to understanding
what are those local challenges,
and potential execution impediments
around areas that could be difficult
or could be long lead from a permitting perspective,
could be sensitive from an endangered species standpoint,
so we have that coordination occurring
both with the agencies at the state level,
as well as things like fish and wildlife services,
as well as their local district offices.
Engagement with entities like CalTrans
to also understand
what are some of their design requirements
as part of the work that we're gonna be conducting.
So that's really the level of engagement
that is occurring,
and we're also working with the country leadership
to understand if we have a major thoroughfare
for some of the communities,
what would be the potential implications
from a traffic standpoint
when we do have to shut down a certain lane
to do the under grounding work,
are there work hour restrictions as well.
So those are all the different execution feasibility
elements that go into the prioritization
of informing when we can do work,
how much work we can do,
and which part of the respective community.
-: Thank you.
-: My pleasure.
Go, Commissioner.
-: So you indicated that you have an effort
led by a Carla Peterman and Brian Rice, I'm sorry,
would you mind repeating what is that effort
and who else is involved?
-: Yeah.
Thank you, Commissioner, again,
that effort is what we call
our underground advisory council,
and the council also includes respective leaders
from different state agencies,
and really the intent of that effort
is to create a cross-functional advisory council
that can help provide strategic guidance
as we start pulling together our under grounding plan,
what are some of those specific types of challenges,
impediments, long lead permits,
that we're gonna have to consider
and are there ways for us to further streamline
the type of information that we need to be submitting
to respective state agencies
so that we can help accelerate the review and approval
at the project level some of the under grounding plans
that we're going to be implementing.
So it's really helping to work through streamlining
many of those processes because we're well aware
that this kind of undertaking and an effort
can't be done alone by ourselves,
but can only be effective with that engagement
of the multitude of external partners
that we're gonna need support and engagement from.
-: Two more quick questions.
Are you (indistinct),
in these efforts (indistinct)?
-: Yes, so Commissioner, that's part of the process.
The environmental permitting, again,
understanding those specific areas
that could require that type of a permitting effort.
So those are some of the things
that go into that decision making process.
I can't speak to the specific project
and the (indistinct) implications perse,
but those are all the different factors
that are considered,
including the state environmental agencies
which are engaged as part of this.
-: Okay, and then my other question
is are you looking at how you true up this effort
with the requirements of the 2022 wildfire mitigation plan
and also the ongoing (indistinct) applications
we've got with the CPUC?
-: Yes, Commissioner,
that's part of our current planning process,
because as we filed for the 2023 GRC,
the four year GRC as you all know,
we have a significant program that we have included
as part of system hardening,
and when we consider under grounding,
that's part of our broader system hardening portfolio,
because in addition to under grounding,
we also look at are there areas where overhead hardening
may be a more risk bent efficient solution,
or is there a remote grid opportunity
like the one we recently implemented in Briceburg
coming out of the 2019 Briceburg fire that occurred.
A small system that's renewable with solar battery backup
that's providing service to five customers,
obviously didn't make sense to underground that line
or do overhead hardening, we moved the line
and created a small micro-grid type of a setup.
So these are all the different tools that we have
within our broader system hardening program
and under grounding is a key component of that.
-: And keep in mind that all these efforts that you're doing
with the other state agencies, at the end of the day,
if you're gonna need approval from the GPSE and OEIS
on these, I'm sure you're looking at
as to how you're integrating and bringing them
all of us up to speed on all of these things.
In the end, the customers are the ones
who are gonna have to pay.
-: Yep, absolutely, Commissioner,
that's going to be front and center
as part of our 2022 wildfire mitigation plan filing.
Absolutely.
Any other questions before I ...
Good, Commissioner Houck, (indistinct) question.
-: On your 2022 wildfire mitigation plan,
are you gonna be including the 10,000 miles
as long term planning
or how are you going to look at the long term
versus what you're planning for 2022?
-: Thank you, Commissioner.
Typically the WMP process,
and Director Thomas Jacobs can correct if I'm wrong,
it's a three year look ahead,
which includes the in year 2022
as well as two years subsequent to that, 2023 and 2024.
So that's the level of information
that we're gonna be providing,
and at the same time, there's a significant amount of work
that's being done to stand up a fairly significant PMO
to be able to help establish the long term plan,
as well as the oversight of all of the work
that would need to happen from scoping to engineering
to permitting to safe execution in the field
and construction, and ensuring the work is done
to the highest level of quality.
So all of that infrastructure from a process
and oversight perspective, is also currently in the process
of being stood up with the intent and the focus
of the 2022 WMP would be a three year type of focus.
-: And just last (indistinct),
do you see any potential difficulties
with the fact that the WMPs are three years
and then the GRCs are four years
and whether they're aligned in a way
that is going to make it easier and more efficient
for all of us to understand what's going on
in the crossover between the safety measures and the cost?
-: Commissioner, to the extent feasible we are aligning
both the GRC submissions as well as are including
in the WMPs, and obviously, the WMP themselves
are improving year over year.
This will be the fourth year of the WMP filing,
'cause if you look at what was submitted 2019,
it was really a baseline,
there was a very significant overhaul that was done in 2022,
and that was further evolved in 2021 and 2022,
but with the three and the four year time difference,
many of the plans that we have for the end year
tend to be very specific and more granular
in terms of where are we gonna do
that specific two, three, four mile project,
and then for years two, three, and four,
they tend to be more at the programmatic level.
We're gonna be doing x miles of system hardening,
1,800 miles of enhanced vegetation management as an example,
and then as we get to that end year planning
or typically starts to happen t-minus six months
before we get to end year,
to start outlining those specific levels of detail.
So from a programmatic perspective,
even if you look at the slides that I discussed about,
all the additional safety programs that we layered,
we're at a point where many of those programs
are fairly steady state,
and they will carry over into year four as well.
So from our perspective,
that does not cause a significant amount of disruption
of year three versus year four.
Now, the big change, obviously,
going into the 2022 WMP is the fairly significant addition
of under grounding, which we're also considering
and working through from both a GRC perspective
as well as a WMP perspective.
-: Thank you.
-: My pleasure.
All right, if there's no other questions
I will continue on the slide.
Thank you for that engaging Q&A.
Wasn't planning on spending a lot of time here,
we spent about four hours together on Monday
on this topic in regards to the enhanced vegetation
management corrective action plan.
Our process continues to improve.
Our planning is addressing the highest risk
and the gaps that were identified in the 2020 work,
because of our co-workers and contract partners,
we've made essential progress towards
our 2021 EVM program goals.
We exceeded the two milestones that we had included
in the May 6th corrective action plan
for both June 1st and September 1st,
and we have clear line of sight towards
our December 31st goal of 1,800 miles.
I know we submitted on November 4th,
progress report for data as of September 30th,
I will share the work that we have completed
as of yesterday for our enhanced vegetation management,
and we're at more than 1,560 miles that have been completed,
and we've got the line of sight to meet or exceed
the 1,800 miles by end of the year,
and most importantly,
97% of that work that's been completed,
which is the 1,560 miles as of yesterday,
has been completed in the highest 20%
of the risk ranked circuits.
So that's really the big focus for us.
And then lastly, on the 2022 EVM scope of work,
we are much further along than where we were
at this time last year.
We did not finalize this year's plan until April,
and for 2022, we have already issued a preliminary plan
for our execution teams to review for planning purposes
that we also discussed on Monday.
That's a quick update on our EVM corrective action plan.
Commissioner, you have a question, go ahead.
-: Yes.
I meant to ask you this question on Monday.
-: Sure.
-: From 2019 to now, at various workshops we heard
about certain kinds of plant species and trees
that will grow back quickly.
In your efforts, have you gone back
to let's say the 2019 vegetation management ...
Are you tracking where you've been, where you are,
and whether or not any of the previous work
needed to be revisited?
You have any kind of plant species
that may be growing back quickly?
-: Commissioner, the short answer is yes.
So if you think about EVM
which includes two additional aspects of the scope
that goes beyond the routine
or compliance vegetation management program,
which is to clear the overhang
as well as assess the health of the strike potential trees
that are tall enough and not far enough from our lines.
So to maintain that overhang clearance,
to your point because that clearance is gonna grow back,
we are folding that into what we call
our routine vegetation management program going forward,
so that when our teams are where
we have already been for EVM,
they'll not only do the manual clearance,
which they do to maintain compliance with the GO
and the public resource code of requirements,
but also ensure that we're maintaining
what we did for EVM for overhang.
In addition to that, we are further introducing more rigor
going into next year in our routine program
so that our tree inspectors and arborist
that are on the routine program itself
are doing a 360 hazard assessment of trees
that are tall enough and not far enough
for exactly that reason,
and also the reason that given the exceptional
and extreme drought conditions,
one of the adverse impacts it does have on trees
is it accelerates tree mortality.
So those are the elements that we are folding in
from our EVM program into the routine program
and operationalizing that going into 2022.
-: Can I ask a follow on question on that?
I just wanted to make sure I understood you.
So you're folding in ongoing maintenance of EVM
into your routine, can you just be really clear
on has that been folded in or are you folding it in
in the future?
When does that start?
So which EVM maybe hasn't been getting caught
in the routine yet?
-: Yeah, so what happened in getting caught,
Director Thomas Jacobs, thank you for that clarification,
is the work that was already completed in 2019 and 2020.
So it's gonna get folded in as of January of 2022.
So that's where the work we did in '19, '20, '21,
we're gonna maintain the overhang
as well as implement the additional 360 degree walk around
to assess the hazard of the tree.
So that gets fully baked going into 2022.
Any other questions before I continue?
Okay.
We can go to the next slide, please.
So given our drought conditions that we've discussed
and the subsequent increase of the wildfire risk,
we've experienced, outside of the typical wind-driven events
that really have been our experience in the past,
and on non red flag warning conditions,
we did a number of enhancements
to our wildfire prevention efforts this year.
One of our most impactful changes we have made
is to adjust the sensitivity of our equipment
to automatically turn off power faster
if the system detects a problem,
and these settings are known
as the Enhanced Power Line Safety Settings,
I think Mr. Houck had referenced them as fast trip.
They're two of the same.
The EPSS was implemented in late July
as it became very clear because of the extreme conditions
of the drought and the exceptional drought conditions
that we were experiencing in our service area
a lot more fuels driven and terrain driven fires
as compared to wind driven.
It was a significant shift from what we have seen
in the last five years.
We implemented this capability for 11,500 miles
of our distribution circuits.
We're about 45% of the lines in the high fire risk areas.
With a specific focus on circuits that could lead to
a fuels and terrain driven fire under load
to still wind conditions.
So these changes have prevented potential wildfires,
and we made the decision leading with our true north,
that everyone and everything's always safe.
Now that said, we fully acknowledge
that with our initial implementation
we could have done much better in our execution
given the significant reliability impact
on some of our communities and our customers,
and we needed to be far more effective
in our communications with our customers.
I'm gonna touch on both of these in detail shortly.
Since the initial implementation,
we have made significant improvements
for the EPSS enabled circuits,
to address the reliability concerns
both on the frequency of outages
and the duration of outages,
and we have also conducted focused webinars
with our customers across our communities
that were impacted by EPSS,
which again, I'll discuss in detail shortly.
We have also fine-tuned the settings
in the locations where we have experienced the storms,
and we have actually disabled the EPSS settings now
given the minimal fire spread risk.
So today, we have the ability
to be able to enable and disable the 11,500 miles
associated with the circuits,
and we are able to do that in a remote setting
from our control center,
and we can actually enable and disable this capability now
based on the potential fire risk.
And given the low fire spread risk
for most of our service territory,
the EPSS capabilities have been disabled
within our service area.
When these settings are enabled
and settings are enabled next year,
we will have additional improvements in place
that will improve customer reliability
without compromising safety.
Let me shift to PSPS and I'll come back to EPSS.
We have made some ...
I'll pause, go ahead.
I'm sorry.
-: Sorry.
You said you've stopped it for now,
but you're gonna resume it in another fashion next year.
Obviously, the lack of notice and preparation to customers
is at a direct conflict with this type of use of technology,
and you need to secure that before restarting it.
And so maybe you could speak more directly to ...
From my perspective, this is a PSPS
and all those protocols need to apply.
Even customer knowledge to say
I don't know what the cure is right now,
well, the cure is they should receive
the same type of notifications as a PSPS,
but what do you mean by it's gonna come back next year?
-: So Commissioner, we'll probably draw a distinction
as to why EPSS is very different from PSPS.
The reason why it's different is in PSPS
we are able to forecast the adverse wind conditions
for five days in advance.
That gives us the ability, from a meteorological perspective
and operational perspective,
to stand up our emergency operations center
and get into that posture to notify the customers
on t-minus 48 hours, t-minus 24, t-minus 12,
and imminent notification because we're seeing
that weather event materialize.
With EPSS, a key distinction is that the circuit
does not de-energize until there's some level
of disturbance that's detected already.
So meaning that there's a level of an outage,
a tree limb or branch that may come in contact with a line,
a squirrel or a bird that comes in contact with a line,
all of these instances that could lead
to a potential ignition, result in that disturbance,
and what occurs with EPSS is the devices
are much more sensitive and faster reacting.
So as soon it detects it, it de-energizes,
and it reduces the amount of energy that's produced
to create a potential ignition.
Now, the initial implementation of our EPSS
is what created the significant reliability impact,
and I'll honestly go to that now
just to touch on it.
So if you go to slide 15, this starts to,
Commissioner, get to be responsive to your question
about the cure for this.
I'm sorry, two more please.
Great, thank you.
So one of the things that we experienced,
Commissioner, was when we did the intimal implementation,
we did it at a very, very rapid pace.
So what that resulted in was when there was an outage
that occurred, there was multiple devices
that actually opened.
So it was very difficult for our teams in the field
to identify and pinpoint and target
exactly where the trouble was,
but since then, we have gone in
and done an engineering evaluation
for every single one of those circuits,
which is 170 of them that we had implemented EPSS on,
and coordinated the settings in the field,
so made changes to all the other devices
so all the devices don't trip at one time,
so that there's only one device that trips
and it really targets where that disturbance or trouble is
so we can much more rapidly pinpoint, safely patrol,
and restore service to our customers.
And what we've seen is
from an average outage duration perspective,
we are back to the similar level of performance
that we had pre-EPSS when we took that second step.
So that's what you see under the progress
of an increase in 12% (indistinct),
that was subsequently dropped as we implemented
what we called these coordinated settings.
So that's a key improvement that has already been made,
and when we make a reference to that,
we implement this going into next year,
we're gonna implement it
with these coordinated engineered settings,
and what our engineers do is they study
the low profile for every single circuit.
When there's a shift of demand on that circuit,
it creates a potential disturbance as well,
but we don't want to trip the circuit
or de-energize it at those levels,
we only want to trip it when there's some kind of impact,
whether it's a tree that comes in contact or animals,
and that's a fine tune of the threshold
that our teams have done now for 170 circuits.
That's a key improvement from a reliability perspective.
-: Is 170 circuits the universe
of where the technology's being applied?
-: This is where we applied it this year, Commissioner,
which is the 11,500-
-: But it's gonna effect all your circuits?
-: Yeah.
So going forward, what we are setting up
is doing the engineer settings
and basically creating two operating configurations
for our circuits in the high fire threat districts.
One's what we call a normal configuration,
which is what you see today.
When there's low to minimal fire spread risk.
Second configuration is the EPSS
which will be coordinated so that our customers
are not gonna experience the extended outages
that they did with the initial implementation,
and we would enable and disable those settings
when there's a high fire risk concern
from a spread perspective.
So that capability of EPSS is not gonna be enabled
for the duration of the fire season.
We will have the ability to toggle it on and off.
That's circuit specific and geographic location specific.
-: Okay, just a couple of follow ups here.
So the duration's gonna be decreased by 12%,
is that what you're saying?
-: This takeaway, Commissioner, I would share with you
is that when you look at the pre-EPSS levels,
the step one of the implementation that we did,
we saw a 12% increase in outage duration for our customers.
After we took step two,
we brought the duration impact back to pre-EPSS levels.
So with EPSS or non-EPSS,
our customers should not be experiencing
any adverse impact on outage duration
as we implement this capability going to 2022.
That's the key takeaway.
-: See, I have a follow up to your follow up, Martha,
a follow up to this very question,
if I may interrupt you.
So you're talking about percentage of duration,
and you well know that the CEO and I have had an exchange,
a lengthy letter, which you all had responded to.
So I'm asking some questions
that are gonna be repetitive,
but not everyone has obviously seen the letter
nor the response.
So the concern was you have an average outage,
on this chart, of seven hours
and your average impacted customers 1,000.
So if indeed you're going to decrease that by 12%
with those greater technologies that you've brought on,
more sensitivity that you've brought on,
that's, to me, only one piece of it,
and I'd rather talk about actual hours
because people being without electricity,
1,000 people which is an average,
and the seven hours is just an average as you know,
we said this before,
that we had customers complain to us that had outages,
and this is up in the El Dorado County area
and out in the Santa Cruz mountain area
that lasted between 24 and 36 hours.
Now, that was perhaps anecdotal,
but that's an awful lot of time
when you've had literally no notice,
and I know the essence of fast trip is no notice,
that's the essence of it,
because if a squirrel hits a line,
how in the heck are you gonna know that?
But to me, that's only half of it,
because one of the things I was concerned about
is your safety patrol and re-energizing.
You might drop the percentage by 12%,
which is five hours maybe?
But you're not going to be able to re-energize
until you get that patrol out there,
and that's boots on the ground, that's people,
that's more people, that's contractors?
I don't know how you guys are gonna do it,
but to me, that's another thing that was a big hiccup
when you all first implemented this
is you, I don't think, had enough, again,
excuse me if I'm making a presumption I shouldn't,
but I don't think you had enough boots on the ground
to go out and patrol fast enough to re-energize that line,
'cause as I understand it, you still are under the protocol
that the line is not re-energized
until it's been patrolled and found safe.
-: So President Batjer, thank you for your remarks
and your sentiments, we completely understand
the concern and the frustrations,
and what I can show with you
is that the initial implementation
resulted in a lot of the outcomes that you talked about.
So since we have implemented and did implement
the coordination of the settings,
we do not have to patrol the entire circuit.
That's the big change,
because instead of having multiple devices
that trip on that circuit,
one example is (indistinct) meetings
in which really helped paint the picture
is when you have a device in your house
you also have additional fuses
for each of the respective homes.
What was happening before is
when there was a outage that occurred,
it was the outage and the trip that impacted
the entire home.
Given the additional adjustments that we made
to the settings, we can be much more targeted
so the impact is only to a bathroom
as compared to the entire home.
So now, when that trip occurs,
we don't have to patrol every single electrical line
in the home, it's only the electrical line
that's associated with that bathroom as an example,
if we use that analogy.
So that's the way that the configuration
of the system works, and that's how we've been able
to now reduce the impact of duration.
In addition to that, we did step up
the additional resources.
We'll see that in the response
to the letter we provided on November 8th.
We stepped up by more than 40%
and now we're back down to about 20% higher
than our baseline staffing,
because we have seen that additional benefit
of the targeted outage response.
In addition to that, we pre-staged helicopters
to be able to get eyes on the patrolling
in a much faster way, as well as leveraging drones
on some of the hard and difficult to access
and challenging locations.
All of those improvements have really brought
the average outage duration back to the pre-EPSS levels.
So when we see an outage now on EPSS,
it would be the same as any other outage that may occur
let's say on a potential gray sky day or a storm day.
So that's the place where we are now with EPSS
from a duration standpoint.
So pause there and Adam,
I don't know if you want to add anything to that.
-: Yeah, sure, I'd be happy to.
And again, thank you for the push.
Really appreciate it.
And the letter even, we always appreciate the challenge
for us to think through how we can get better.
We do recognize that this was rolled out
in a sledgehammer type of fashion.
It wasn't targeted specifically
because of the dire conditions that we were facing,
and the proactive safety steps that we took
came with the reliability impact and quite frankly,
we didn't realize it would be this many
and for this long.
We really didn't.
We didn't think we'd have this many trips
on similar circuits for as long as we did.
And so having realized that,
and again, our main operating system really helped us
highlight that daily that we were seeing
this high frequency, long duration outages
on common circuits, helped us formulate
a more refined approach.
Helped us develop the community webinars
to show folks exactly what we were finding
and why this is a necessary safety measure at this time,
but it is not lost on us
that we have to get better in this area.
More proactively communicating as we get into next year
that this safety setting has been established,
what to expect, how we can respond,
what we plan to do to make this as painless as possible
for our customers.
We have to get better, that is not lost on us,
but I just wanted to try to reground us very quickly
in the fact that we had to do something.
We had a million acre fire on a normal day,
and those conditions were not conducive for the safety
of our communities and our co-workers,
and so very important that we took this measure.
Clearly we need to refine it.
I think we've demonstrated we are taking
very proactive steps and being diligent to do so,
and we have to make sure going into next year
we have those things in place before we re-implement
this safety procedure.
But it's not lost on us at all, we have to be better.
-: Go ahead, President Batjer.
-: Yeah, just real quickly, Caroline,
'cause something you said, Adam, just reminded me,
Sameet had mentioned earlier the webinars,
you just mentioned them again.
Are you counting how many people ...
There were thousands of people that were impacted,
and my concern is folks just don't hear about these things
in terms of the awareness that you're having them,
that they can be informed about it.
So just wondering how many people
are attending these webinars?
Or attended the webinars.
-: I don't have that number.
I can get it and follow up pretty quickly.
I'll actually send a fax right now (indistinct).
-: Yeah.
Well, you get the point though.
That oftentimes a webinar, something that is transmitted
electronically or even in social media,
it does not get the broad broadcast, if you will,
of notification of thousands of people
that were impacted this Summer and into the Fall.
And I'm sorry because I interrupted
my fellow Commissioner, Caroline.
I wanted to follow up on Martha's,
but I could get one more question before, Caroline, you go.
Martha, did you have one more question?
-: Well, thank you.
By the way, I think it was 560,000 customers impacted,
and I appreciate the clarification
on the improvement on the circuit refinement.
What is the improvement on giving those customers
an opportunity to prepare?
Yes, we do have to do better.
Adam, you have to do better here.
It's not okay to just say
we're just gonna implement this again,
although it's better,
without giving customers the ability to prepare.
What are the criteria you're using
to effectuate this next year?
What month are you starting?
What day are you starting?
Which counties do you anticipate?
Do you anticipate the same 6-7 counties
to be greatly impacted?
What are you doing to prepare
helping customers be prepared?
-: I can touch on a couple of things,
and then maybe Adam if you want to add onto that,
please feel free to do so, and President Batjer,
we're getting the numbers.
We've done, to date, 14 webinars,
and we have those specific dates and locations
that we included in the November 8th letter,
the response that we submitted.
We had a fairly good attendance on the Santa Cruz
and the El Dorado, which were the areas
that were the most impacted,
and then they started to thin out a little bit from there.
But our intent, going to your question, Commissioner,
is really around using the same protocols
from a customer support perspective
that we have for PSPS.
So what do I mean by that?
So as an example, we have about 30,000
medical baseline customers
in the high fire threat districts.
When you look at the number of medical baseline customers
that were impacted by EPSS outage
in a high fire threat district or two or more PSPS events,
it was about 38%.
So round number's about 11,000 medical baseline customers.
So this month, we are sending them additional details
on all of the customer resiliency programs that we offer.
Portable batteries,
the rebates on the backup generator programs,
the ability to leverage the community-based
organizations like the California Foundation
of Independent Living Centers.
So all of those specific details
and the support efforts that we provide
for typical PSPS events, we are further educating
our customer base on.
At the same time, we are engaging with the agencies
of those local counties, the first responders,
as well as all the critical infrastructure entities.
Things like hospitals, things like wastewater facilities,
telecom entities, to identify are there backup
generation capabilities that are needed,
and actually, for some of the most impacted hospitals,
even as we enable the EPSS this year,
we provided backup generation working with them.
So those are the types of areas of support
that we are bringing to bear,
and then as part of a broader communication effort
that we do every year
as part of all the community wildfire safety programs
that we're gonna be implementing,
EPSS is gonna be a key part of that communication strategy.
Now, to your specific question on which month
are we gonna start, we're actually gonna be looking at
the conditions.
If the conditions warrant a spread risk
does not increase until June or July,
that's a timeline where we would look at,
and we're not going to do broad brush
across the entire service area
within the high fire threat district.
And I was mentioning that one of the measures we have
is something called a fire potential index,
which is if an ignition occurs,
what's the likelihood that ignition
becomes catastrophic in nature?
We measure that on an hourly basis,
forecast it on an hourly basis on a rolling
three day forecast at each circuit level.
So that's the level of granularity that we're gonna use
to enable or disable this capability
So it's very surgical, very targeted,
and condition dependent.
These aren't the capabilities we had in place
as we implemented it this year to Adam's point.
-: I think the only thing I would add to that,
and we did have relative to the number of customers
who experienced an outage and does not make it better,
Commissioner Guzman, but the 500,000,
some of those are repeat so the pure number
who experienced an EPSS outage is less than that,
but still too many.
1,169 attended the webinars, so a low number
relative to the customers experiencing an outage.
The thing I would just, again,
free to continue the dialogue,
but you have our commitment that we recognize this
as a critical area for improvement
for our customers and for our performance.
We are committed to doing the things we need to
to make this experience better for our customers,
so that this can continue to be
an effective mitigation against wildfire.
We recognize it, understand it,
and we'll put the weight of the organization behind it.
-: And the last piece I'll add is,
to the question President Batjer asked specifically,
we had 1,169 attendees across those 14 webinars.
Just wanted to make sure we close that out with you.
-: One more question on this from me.
Okay, 11,000 miles, 170 trip units,
am I saying that right?
You've been doing a lot of contextualizing
smaller, it's really regionalized as opposed
to a wide swathe of shutoffs.
Are you looking to do that here?
And also, are you adding more to the 11,000 miles next year?
-: Yes, Commissioner.
So again, the capability that we're looking to enable,
because it's one of the things that we've realized
is part of, and also what Adam highlighted
and Director Thomas Jacobs highlighted
in her opening remarks, that the fundamental way
that we design, construct, maintain, and operate our grid
has completely changed given the conditions
that we're talking about.
So really what we're talking about here
is the operational of that grid and that system
within the high fire threat district.
So we have a total of 800 distribution circuits
that correlate to the 25,500 miles,
maybe doing the math 170 relates to 11,500.
Each circuit mile is not the same as we know,
and some of these circuits tend to vary in length
fairly significantly, but the capability
that we're looking to enable is for all of the circuits
within the high fire threat districts.
Now, it doesn't mean, again, just to reinforce,
that all of them are gonna be enabled 100% of the time,
all the time.
It's really gonna be condition warranted
when the fire risk is elevated.
-: (distinct) your vegetation management,
the covered conductors, and then your (indistinct)
of under grounding in this whole rubric, right?
-: Absolutely, Commissioner.
So where we are, under grounding,
that obviously mitigates the need to enable EPSS
because we have mitigated that risk,
so that obviously improves the reliability
as well as where we have done overhead hardening.
And I was remiss to not answer the first part
of your question on your prior question,
that are we also looking to install
additional specialization devices.
We are absolutely looking at that
from a circuit perspective as well.
Not just the ability to install additional
specialization devices, but also additional remote
and automation capabilities that have the ability
to be able to disable and enable EPSS
in a remote manner through our control center.
So those are all the elements
from a reliability improvement perspective
associated with this program that are gonna be key
as part of our 2022 effort before we start
to get into this patchwork enabling these circuits.
-: And again, the communication in advance,
there were ring announcements, (indistinct) announcements
on PSPS over and over again.
Big, the whole page, as the newspapers,
to familiarize people with PSPS's.
Here, again, it happens instantaneously,
but (indistinct) as really educating folks in these areas.
That decision also is another part
of the wildfire mitigation to be aware of,
and what will you do if such a thing should occur?
-: Yes, all great takeaways for us to build upon
as we move towards this for next year.
But you'll see this in the letter
that we responded to as well, President Batjer
and the rest of the Commissioners.
(indistinct) with the idea
that it was just the webinars for outreach.
Again, it wasn't.
They should have been on the front end,
but we gotta correct it.
But we did email notices out plus postcards were sent
to all customers.
We had our Sprinter mobile command vehicle on site
when outages happened in select locations.
We had social media postings that targeted
the highly impacted communities.
Letters were sent to customers, again,
on highly impacted circuits.
We did engage the (indistinct) the local officials,
hospitals, schools, water agencies, telecom customers
and providers.
Automated calls were sent out supporting the fact
that we were patrolling these lines to give information
so customers didn't come out and slow down our patrol crews.
And then several other actions that were completed
to help notify and keep customers informed.
So there was a suite of activity,
the webinars, I felt, were more comprehensive
and provided the full basis for the reasons why
in a live format with dialogue and Q&A,
but there were other channels of communication
to help keep our customers aware of what was going on.
Again, need to do better, we have our commitment.
the organization is focused on it,
and it will be an improved experience for 2022.
-: So I have a question.
I want to take us back to a little bit of what,
Adam and Sameet, you started with.
Adam you said it was sort of a blunt force approach
to a new risk that you identified,
which is, I would call it, a heightened fire risk
but it doesn't have the wind threshold
or other parameters that would potentially forecast
a use of a PSPS.
So you guys used an existing protocol
that you could jump to
that was an extreme safety sensitivity setting
that then exposed this reliability issue.
When you guys are, this is the part
I want to get to understand better,
when you went to refining it with a more surgical approach,
I'll call it the custom configurations of sensitivities,
how are you maintaining that same level
of safety risk reduction that you originally intended
with the blunt force?
-: Yeah.
So thank you, Director Thomas Jacobs for that.
So basically, what we did is when we went
to that blunt force, we over rotated,
because when you look at the two different types
of outages that we were experiencing,
one was where we actually were able to identify
what the cause was of the outage.
And in many of the instances,
initially when we implemented this,
we were seeing up to almost 80% for some of the circuits
an unknown cause, because when patrol was happening,
there was no obvious damage that was identified.
It could have been a momentary,
whether it was a branch that came into contact
in an intermittent way, but a substantial portion
of those were occurring on what we call load current.
So when there was load that turned on and off
on the system, it takes a few seconds
to be able to stabilize, but that few seconds
of electrical disturbance was enough
to be able to create the de-energization of that device.
So when we went to this custom setting,
our reliability engineers looked at the low profile
to look at the amount of current that's generated
when that loading configuration changes,
and set the threshold so that we are catching
all of the fault current,
which would be indicative of when you have
a animal contact or vegetation, but not impacting
and tripping on load current.
So that's the distinction that occurred.
And then the other distinction was that each of the devices,
when we coordinated the settings,
they were offset by .02 seconds,
meaning that if you have a device that's closest
to the disturbance, that gets tripped,
not necessarily a downstream device
or the upstream device that's even further away from it.
So it checks to see if the prior device
that's right next to me has tripped
because of a disturbance that I don't have to trip.
So that's the additional slight time delay
that was added to maintain the safety benefits
of an impact without adversely continuing to see
the reliability impact that we're seeing.
-: So simply put, in a non-engineering framework,
-: Sorry.
-: It's okay.
Is these refined settings, you feel like
and correct me if this is not what you meant,
you're still tracking the same potential ignitions
that you would have with the blunt force,
but now you've reduced reliability impact?
-: That's correct.
And you can actually see that if you go to slide 14,
if we can pull that up, please.
In regards to what we've seen from a CPUC
reportable ignitions perspective.
So it's one slide before this, please.
Thank you.
One after this. (laughs)
Thank you.
So if you look at the reductions that we are showing there,
Director Thomas Jacobs, since we implemented this
on July 28th, we have seen a 46% reduction in total
to the CPUC reportable ignitions
in a high fire threat district,
and if we just look at the performance
of those 170 circuits over the last three years
in terms of the ignitions versus post-EPSS,
it's almost an 80% reduction that we have seen.
And in those 20% where ignition has occurred,
they have been fairly small in nature,
and that is intuitive actually,
because the settings, what they do is they reduce
the amount of energy that's released.
So even if there is an ignition,
there isn't that significant amount of sparks
to create that larger type of ignition scenario.
So that's proof in the pudding to the point you're making.
-: Thank you.
-: Sure.
I'm sorry, can we just keep the slide back up?
Let me just touch on the right hand side of this.
Before I do that,
I'll just make sure there's no other questions on EPSS.
Really appreciate the feedback, the candor,
the passion around this because we feel the same.
Frankly, the level of communication,
the notifications, and the reliability impact
is unacceptable.
We are gonna do better, we're committed to do better,
and you can absolutely hold us accountable to that.
-: Sorry, Sameet, I just have to say one more thing.
-: No, sure.
-: This is so important.
I think it's important.
Not withstanding on that, which is so true
and you have our full commitment.
I am proud of this company for prioritizing safety.
This is something that the company has desperately needed
is for leaders to step up and put safety first,
and we did that and mistakes and do betters
and all of that, but to make the decision
knowing there was the potential for this,
to anticipate it as widespread,
but we erred on the side of making it safe
and making it right, and I'm proud of this company
for doing it.
However this all plays out, I'm very proud of the fact
that we were able to make that decision,
act upon it quickly, have the capability to implement it,
and then the wherewithal to make it better.
So I just wanted to put that out there,
might not be worth much but just had to say it.
-: Adam, if I may just follow up with your comment.
I appreciate the fact that the company
has put, and some of it has been frankly regulated to do,
put safety first.
However, as I have been a broken record,
as have my fellow Commissioners been,
safety of not having as many ignitions, very important,
absolutely, but the side of the fence
that you missed initially in PSPS
and you missed as you have attested to today
and you did earlier in the week and you have in the letter,
that you really blew is the safety of your customers
that are there without energy for hours,
and fast trip, by nature, is not gonna notice anybody,
that's the definition of it.
So these are people without energy for hours
with no notice and that is a huge, huge safety risk.
So that can't, I know you guys get this now
because I've said it and said it,
as have my fellow Commissioners,
that cannot be ignored and cannot be not factored in
to your safety risk.
The people's lives over here who are trying
to get through life without any electricity
is a huge public safety situation.
So okay, that's in reaction to what you said, Adam.
-: I appreciate it, thank you.
-: Thank you, President Batjer.
Thank you, Adam.
Let me wrap up on this slide
and then I'll see if there's any questions
on the wildfire topics and then move to a separate section.
But if you look at the right hand section of this slide,
what it's basically showing is a cumulative basis
for 2019 and 2020.
PSPS is proven to be an effective measure of last resort
in preventing wildfires and obviously,
one of the things that we do as part of PSPS
is evaluate the damage and hazards that have taken place
in our system.
And consistent with the Commission study that was done
by the safety enforcement division in 2019,
we followed the same protocols
that having not de-energized and the damage occurred
and a subsequent ignition occurred under those conditions,
what could the impact have been
in terms of acres burned and potential structures impacted
using the (indistinct) fire simulation capability.
In total, more than 4 million additional acres
and nearly 500,000 structures could have been impacted
had PSPS measure of last resort not been used.
And as you can see between '19 and '20,
and furthermore into 2021, we'll continue to reduce
the impact for our customers.
Specifically in '19 and '20,
all the infrastructure investments
and the targeted meteorological capabilities
that we put into place
were the significant enabler for that.
One last piece I will share is that the back testing
that we've done with our 2021 PSPS protocols
show that we would have prevented 96%
of the buildings that were impacted from equipment caused
and wind driven fires between 2012 and 2020.
So we have the ability to be able to, in essence,
simulate, through our protocols today,
go back in time historically and identify
would those protocols have mitigated and prevented
some of the most catastrophic fires that have occurred
in the state caused by our equipment.
So that's an overview and in detail discussion
on the wildfire topic.
The next slide we already covered,
which was on the reliability impacts for EPSS,
but I just want to pause here again for a moment
before I start to discuss the safety management system
and safety culture to see if there's any questions,
comments, on anything I've covered on wildfire related
or that Adam opined on as well.
-: Your staff that goes out and checks the lines
before re-energization under this fast trip.
I'm sorry, did you say that within the regions,
as you enter the season, that you have those swat teams
ready to go?
They can check the lines, lower these hours folks are out.
I think you mentioned it but I didn't quite catch that.
-: Yes, we do, Commissioner.
The short answer.
In addition to that, they are supported by helicopters
and drones.
And again, most of our system, of the 170 circuits,
there's only two circuits that are remaining,
one in the most populous area and one in current area,
that are still EPSS enabled.
168 are back to normal configuration
given the low fire risk.
-: All right, thank you.
-: My pleasure.
Okay, so let me now transition.
If we can go to one more slide ahead, please.
Great, thank you.
To our approach regarding the broader implementation
of our safety management system.
So we're taking a page out of our playbook
from gas operations where we implemented the API 1173.
Some of you may be familiar with that,
it's our pipeline safety management system
that was issued for the industry back in 2015,
and it's really a safety management system
that's modeled after the aviation and nuclear industries.
API 1173 provides a systematic framework
to manage and coordinate actions that address multiple
dynamic activities and circumstances
that are focused on operating a safe system,
and continually improving the safety performance.
And the foundational framework that it's based on
is a concept of plan, do, check out.
So starting with plan, the focus is to establish
the objectives and processes that are necessary
to deliver the results in accordance with the goals
of ensuring that everyone and everything's always safe.
The do aspect is a focus on execution of the plan
to ensure there's no daylight
with how the plan is getting executed in the field.
Third is the check aspect,
which is a validation of the results,
comparing that to the plan and the established objectives
to ensure that the results match the intended outcomes.
And then the act is to take actions
based on the gaps that are identified between those results,
and identify the root cause of a gap
and improve that process performance.
So it's a never ending loop of plan, do, check, act,
and it's very consistent with the fact
that when it comes to safety, our work is never done.
To further mature our planning process,
one of the international standards and framework
that we look to was ISO 55001,
and it's really a framework of how we operate our assets.
It's an international standard that specifies
the requirements for establishing, implementing,
maintaining, and improving an asset management system.
So both our gas and electric operations have received
this certification, and it allows us to manage
the wholistic lifecycle of our equipment
more effectively including design, construction,
maintenance, and operations.
The certification process is done
through a third party assessment, Lloyd's Register,
of our asset management practices,
and then Lloyd's Register does a six month validation
on our progress of the plans
after the initial certification,
and a full re-certification process occurs very three years.
And one thing I'll highlight is that the certification
does not signify that we are the finish line,
but a confirmation that we have a structured framework,
a structured process, to assess and improve
our asset management practices.
And this framework really enables a focus
on the understanding of the assets,
the risk associated with our assets,
and the lifecycle of the assets
so that we are proactively managing them
as compared to a run, do, failure approach
which is all too common in the utility space.
The framework that we implemented,
which is still in place in gas operations
post the tragic San Bruno transmission pipeline incident
that occurred in 2010,
we've seen some significant improvements
not only in asset management
but our process safety capabilities and also safety culture,
and this is evident based on examples
like our dig in rate reduction
occurred between 2010 and 2021.
We went from fourth quartile, to first quartile,
and dig ins for second parties are one of the prominent
risk drivers for the gas distribution aspects.
Our gas emergency response, which is the average time
for response when a customer calls in
when they smell a potential gas leak,
to be able to get to their premises and a safe place,
again, from 2010 to 2021, we went from fourth quartile
to first quartile performance.
It's proven in our gas operations part of the organization
and that the same safety management system and principles
that we scaling across the enterprise,
and with electric operations, obtaining the recent
ISO 550001 certification that signifies a right step
in this process.
We go to the next slide.
-: (indistinct) follow up on the certification,
particularly the ISO 550001.
What were some of the top weaknesses
that were identified in that review?
-: Yes, so thank you, Commissioner.
When the review happens, there's 28 specific clauses
within the ISO standard, and then there's a characterization
known as a major non-conformance,
a minor non-conformance, and a scope for improvement.
So we did not have any major non-conformances
because you cannot get the certification
if you have any major non-conformances.
We had several minor non-conformances.
One example I'll share with you is to have
a more effective management of change process.
So what that means is, for example,
when we introduce a new tool or a change to a standard,
ensuring that we think through all of the dominoes
associated with that.
So it's not just a standard that changes,
and let's just use a new tool that gets introduced
into how work method needs to get conducted,
there's calibration requirements for those tools,
there's the training and qualifications
of the individuals that have to use those tools
in the field, there has to be the continued validation
and feedback loop.
If there's any continuous improvement processes
and recommendations that those individuals
closest to the work, that are using that tool,
can provide so that we get into this plan,
do, check, act, continuous improvement loop.
So that's one example of ensuring
we have a more rigorous process
by which we make an evaluation,
and a more rigorous and effective implementation
of that management of change.
So that's one example, Commissioner.
-: And so you can follow up with a full list.
So you said sample, does that mean two
or does that mean 10?
-: So I don't have the exact number off the top of my head,
but I can follow up with you on that,
but it's a handful, it's not 10,
I can tell you that.
What Lloyd's Register also looks at
is when they come in and do the validation every six months,
for each of these improvement areas
we have improvement plans,
and that's really what they're evaluating,
that are we continuing to make improvements
based on the gaps identified, and the progress towards that.
So we're happy to share additional details
if there's a report that gets issued by Lloyd's Register
that, obviously, accompanies the initial certification.
So I'm happy to provide some of that information
if you'd like.
-: Thank you, yes.
-: Sure.
President Batjer?
-: Yes.
Do you know if the other IOUs in California
are so certified?
-: I am not aware of other IOUs being certified.
I don't know, President Batjer, if they're pursuing it,
but both our electric and gas operations
businesses are, and both our power generation
and our IT organizations are also using
some of the framework for asset management.
So this is something that we adopted
as a consistent enterprise-wide standard.
-: Thank you.
-: My pleasure.
Okay, if there's no other questions
I'll cover the next section related to safety culture.
Thank you.
So as you mentioned, President Batjer,
in the opening remarks, a positive safety culture
is essential to an organization's safety performance.
Maintaining a positive safety culture
requires continual diligence at every level
within the organization, and embedding a speak up,
listen up, follow up approach into the DNA
and every fabric and every part of the organization.
A key enabler for us on our speak up, listen up,
and follow up, has been the implementation
of our collective action program.
This was adopted by gas operations in 2013,
and it's really modeled after Diablo Canyon,
and it's part of the nuclear industry.
If you look at any airline entity,
the aviation industry, any nuclear plant,
each and every one of them has a form
of a collective action program which is a key enabler
for their safety management system.
And subsequent to the implementation in gas operations,
we deployed the collective action program
on a system wide basis, which enables our co-workers
and contractors across the organization to identify
safety and process issues, as well as submit ideas
for continuous improvement.
We have made good progress in its implementation,
but we are continuing to focus on improving
its effectiveness every day.
One of the methods that we have used
to asses our safety culture
is through a safety perception survey
by the National Safety Council, or NSC,
and this was performed in late 2020,
and subsequent to this,
actually Energy Safety's consultant DEKRA services
completed its first safety culture assessment
of personnel and wildfire safety for electrical corporations
wildfire teams as is required by EB10544 earlier this year.
The safety culture assessment for us
included our co-workers, contractors,
and electric operations that support wildfire efforts,
as well as our dedicated wildfire risk teams.
The survey included three categories.
Wildfire, personal safety, and culture,
and we ranked 90th percentile in the categories
of both wildfire and personal safety,
and 75th percentile in culture.
The results from both surveys were fairly consistent.
Some of the strengths that were identified
included the self assessments that our teams are making
which describe that an organization is open and honest
about the current state of the safety culture maturity
and the development that's needed to advance safety.
And also a recognition that safety systems
are continuing to advance,
and evidence that we have increased emphasis
on both personal and wildfire safety over recent years.
Some of the opportunities include
more effective communication and engagement
with our frontline teams and this is consistent feedback
that, frankly, I've personally heard President Batjer
from yourself and respective Commissioners,
improving the recognition of some of the wildfire
and personal safety exposures,
and creating a positive learning environment.
So the insights that we have gained
from both of these assessments are continuing to inform
our path forward to shape our safety culture,
and a key area of focus, as an example,
of improving communications with our frontline teams
is through the implementation of our lean operating system,
which I know we discussed in quite a bit of length
in our Monday focus on our enhanced vegetation management
part of the organization,
but this is how we are implementing
and managing the business across the enterprise.
The lean operating system enables both issue escalation
and communication flow to each level of the organization
on a daily basis, and as of today,
we have approximately 1,300 daily operating reviews
that take place across the enterprise,
and as part of this implementation,
our leaders go out and see where the work is taking place
to engage with the teams closest to the work
to understand their challenges,
support the safety connections,
and reduce the human struggle.
I know I'm out in the field quite often,
at least three times if not more a month.
I know Adam's out there every week, if not more,
really getting that pulse from our teams
closest to the work.
Something I'll share with that
is although we've made progress on safety culture,
we have a lot more work to do,
and there is a continued focus on engaging
with the hearts and minds of not just our co-workers,
but our contract partners,
so that we can enroll them to embrace our safety values.
I'll pause there before I turn it over to Adam
to cover our safety performance.
-: I was just going to, if I may,
since you talked about the importance
of getting out in the field.
And Cheryl, you mentioned in your opening remarks
that the safety committee is having field visits
and you listed some of them, I guess they're field visits
but I don't consider them in the field
like visiting the ops center and things like that.
So I guess my question really is as a safety committee,
as a board, which we give great importance to
here at the Commission, and how engaged and involved
you are deep in the organization in terms of not only
communicating the importance of safety
from the board's perspective, but listening
to the line of people, particularly those below
your middle management, of what they are seeing,
and sensing, and hearing.
I'm sure your survey, Sameet, that you just spoke about
will give a lot of information hopefully to the company
and to the board, to senior leadership,
but in terms of getting out and really seeing
both impact of wildfire, as well as some of the communities
that have been particularly impacted by disaster,
like the Santa Cruz mountains as Adam was talking about
where you held the webinars, and the Dixie fire.
Have you in the safety committee, have you been out
and visited some of the nearly million acres
that was burned in California in the Dixie fire alone?
Just wondering what field visits you really are making.
In the field, on the ground, out in California.
-: Appreciate the question, President Batjer,
and obviously, when COVID started, that slowed us down,
but I personally, and other members of the safety committee,
have been out in the field.
Not only on locate and mark,
but on some of the vegetation management,
I've been to Paradise.
Not all of our new board members have, again,
because of some of the protocols that have been placed
since COVID began.
I have not had the opportunity to go the Dixie fire,
it's on my list.
I try to get out into the field I'd say
just about every time we have a board meeting
I try to get out.
Now to your comment about talking to the employees,
we interact with the frontline employees
at every opportunity and I will say that the leadership team
is actually very good about essentially stepping back
and allowing the board members to interact openly
and freely with the employees that are performing the work,
and I think both Adam and Sameet would tell you
that we provide very (indistinct)
and forthright feedback on what we're hearing
and what our concerns are.
-: Good.
I know there are restrictions still,
but I would encourage particularly the safety committee
to do as much in the field as possible.
I think it's really important
to see some of these communities and to feel their impact.
A lot of these folks that are in the high fire danger
are low income, lots of folks on fixed incomes,
lots of folks with disabilities not only due to aging
but just disabilities in general,
and I don't think you see that without actually being there
and being with them and listening to those communities
and listening to the people, your people,
who work on the lines and live in those communities.
So I appreciate that you are, I think you're doing
far more than your predecessors ever did,
but never can be enough in terms of touching
the communities.
It's one of the reason the regionalization
was part of the restructuring that was so important
to this Commission and remains to be
very much important to each Commissioner.
So our encouragement there, if I may.
-: I appreciate your perspective and your comments,
and I think we will be out in the field more
going forward now that protocols are relaxing
and it's a lot easier to interact
with different communities and people.
-: Good, good.
Thank you.
-: Thank you, President Batjer, for that.
If there's no other questions in my section,
I'll turn it over to Adam to cover the safety performance.
Thank you, Adam.
-: Thank you, Sameet, really appreciate it.
-: Sorry, Adam.
Just a quick follow up on your statement.
I know that we've learned from SG&E
that they have board member representation
on their county emergency response efforts
and they meet monthly with two counties that they serve,
(indistinct) and I wonder if that is a model
that, Cheryl, you are all considering
for board members to be directly involved,
particularly with the emergency response
local government leads in each county?
A direct involvement at that level
from one of your sister utilities,
and you can take that back but it's a model
I certainly am interested in exploring
in our regionalization discussion
and more direct engagement of the board.
-: I appreciate your thoughts and your comments on that,
Commissioner, and we will absolutely take that back
and see what makes sense for us.
It's an interesting idea to get that direct feedback.
-: Okay, President Batjer.
I'm just gonna do a time check,
I think you mentioned 3:00 when we started.
I don't think my comments will go much more
than five to eight minutes, but just wanted to see
if that was hard and fast
and if I needed to shorten anything for Q&A.
-: I have time to stay,
but I don't know if my fellow Commissioners do.
I think we should wrap up as close to 3:00.
As we've been doing a lot of questioning along the way
and commenting along the way, so I'm not sure
what the run of show showed that we were leaving
time for closing statements, but I think,
for the most part, everybody's probably
made their statements.
So let's try and wrap up as close to 3:00 as possible.
-: Okay, I appreciate that.
I do want to start off by saying thank you.
I wouldn't say that if it weren't true.
We truly do value your oversight of us
and your engagement with us, it makes us better,
and so I truly look forward to these opportunities
to spend with you and the rest of the Commissioners
and with Director Thomas Jacobs,
and just look forward to your feedback
as I touch a little bit on our safety performance
from our workforce, public safety, operational performance,
and then sort of what we're looking at going forward.
So if you flip to the next slide,
I just wanted to cover a little bit about
the improvements that we're making
in our workforce safety.
And the first thing I want to say
is that this is a leadership challenge.
Workforce safety is a leadership issue.
Obviously, our co-workers out in the field
have to make choices every day to put themselves
in the best position to be safe, but as leaders,
we create the environment, the standards,
the expectations, the safety systems,
much that Sameet has touched on,
and this is something that had me the most excited
when I talked with Cheryl before taking this opportunity,
because I know that the way, again arguably,
and it is applicable in many ways in my life,
the way you do one thing is the way you do all things,
and so if we can nail our workforce safety
and make the drastic improvements that are needed here
to keep our co-workers safe, I know we'll do everything else
with the similar care, concern, and attention to detail
it takes to run a successful operation.
So if you look at our DART performance,
it is drastically improved from really going
as far back as the graph shows to this year.
And the thing that is interesting about our DART performance
is that nearly four out of five of our injuries
are related to ergonomics.
These are strains, a strain from lifting or twisting,
a lot of them are office related.
For example, we had one come in yesterday
that was related to someone's finger,
was bothering them either from mousing
or doing other work, and so that is included in that number.
So while there's days away restricted time,
a significant number of those are really based
on how we position our bodies to do our work daily
in the field and in the office,
and our team is acutely focused
on doing ergonomic assessments to make sure
that we are removing risk from the daily tasks
that our co-workers perform.
Just one example of that is we go out
and we actually film our co-workers doing the work,
and we take that video and we overlay it
with technology that shows body position,
and where the points of strain and pain might occur,
and one of the things we were doing
is we were going out on our poles and were using a nail
and a hammer and we were putting up signage
on our poles.
So that body position was putting strain
on people's elbows, similar to tennis elbow
and other things you get in your forearm and wrist,
and a simple change to procedure,
to use a power drill and a screw,
took that completely away.
So paying attention to those little things
will drastically improve our DART performance even further.
If we look at a 5% improvement in ergonomic performance,
we would drop below 1.0 for our DART performance.
So we're on the right tack, we're on the right trend.
I will say that our contractor safety
is equally important to us.
We consider our contractors co-workers,
they're an extension of our 25,000 PG&E co-workers,
bringing our total body to around 40,000 folks
that are serving our customers daily,
and we are focused on improving their performance
by enrolling them into our safety stand
that everyone, everything is always safe.
We've spent a considerable amount of time
doing safety observations of their work.
We do about 400 of those a day,
identifying at risk and high risk behaviors,
correcting and coaching, and then obviously,
following up with standardization process,
communication broadly, to make sure
anything we see gets corrected.
Unfortunately this year, we've had three
contractor fatalities.
All of them were preventable.
Breaks my heart that families sent their people
to our job site to complete work for our customers
and we didn't send them home,
and we are focused and engaged to make sure
that they live up to our standards and expectations
on how we perform our work.
I do appreciate your opening comments,
President Batjer, you mentioned behind every number
is a face, and I could not agree more with you.
I would just pile on to that a little bit
and say as we think about our stand
that everyone and everything is always safe,
that even goes beyond the person,
and gets into the environment that we create.
I share this story openly with our co-workers
and our contractors that when I was a kid
my father passed away.
When I was eight, my mother dated a guy
and that relationship became abusive,
and there were days where there were physical signs
of that abuse and there were days
when there were no physical signs,
but at no point, even the absence of signs
of physical abuse, was my mother safe.
She wasn't safe because the environment wasn't safe.
And so as we look at our culture,
and we look at our environment that we are creating,
it goes beyond numbers, it goes beyond the people,
and it goes to the environment,
and everything will be safe,
and so we're committed to that
and we're making dramatic improvement,
but that's a leadership challenge
and it's one that we embrace and accept
and plan to make sure we deliver upon.
You can go to the next slide.
I'll quickly cover the public safety performance
that we're seeing.
Our metrics are improved when we look at
some of the critical ones.
Our large overpressure evasion of our gas pipeline,
that continues to improve and show benefits for safety
of the public.
I will highlight this one area,
it's our wires down performance.
We've had a significant number of what we call gray sky days
which are just normal bad weather days,
but they don't qualify for a major event day,
and we've had a significant number of storm days,
about 130% increase this year.
That has contributed to a higher frequency
of wires down, so I'll be very candid with you,
our work plan this year was not sufficient
to complete the work that we thought we needed to do
in a timely and robust fashion,
and I think breaking out our engineering planning
and strategy organization from operations
will help us get a work plan that is much easier for us
to execute upon, and designing safety into our work,
and to make sure that the things that we need to complete
to improve asset health and the safety of our co-workers
is improved.
So wires down will continue to be a focus for us
as we look to keep the public safe.
You can tell that there is improvement
really across the majority of those areas,
even though that are sort of stagnant (indistinct)
within the first quartile,
particularly on the customer emergency response,
and then the DCPP reliability and safety factor.
That's really driven by not a safety issue,
but by reliability of unit two which has had three outages.
So that team continues to perform very well
in the areas of safety, but reliability unit
has pulled that down for this year.
So I'll go to the last slide and then, yes, please.
-: Sorry.
First of all, thank you for sharing your story.
Thank you.
-: Yup.
-: My question is how are you doing
compared to the other IOUs?
It's not (indistinct) to compare ourself to PG&E
and others (indistinct)?
And also are you tracking your workers compensation
premiums?
Another indicator of how you're doing on worker injury
and support.
-: Yes, we do track those.
I don't have those statistics in front of me.
I would say that our DART rate puts us toward
the last quartile when it comes to safety.
We can't do this technically, but if you were to pull out
the ones that are considered ergonomic, office related,
not significant in the field with the rolled ankles
and the smashed fingers and those things,
we would be performing much closer to the upper quartiles,
but right now, we're in the lower band.
-: Thank you.
-: Okay?
Thank you for the question, I appreciate it.
And if you need me to follow up with any information,
happy to take that back.
Okay, last slide.
Just wanted to highlight that I mentioned
this is a leadership challenge,
and our leadership team is fully engaged.
We have a weekly operating review
where we review our safety performance in the prior week.
Everyone on the executive officer team,
our senior vice presidents,
several of the other vice presidents and directors,
are in the room, and we go over what happened last week,
how have our co-workers performed from a safety standpoint,
what new and innovative standards, procedures, tools,
are we trying to implement to reduce safety issues.
I'll give you an example,
during one of our WRs, we presented on the harnesses
of our tree trimmers being accidentally cut,
and that was the result of using a lightweight chainsaw
that you can use with one arm and kind of swing it,
and so we changed that policy and standard
to use a heavier chainsaw that requires two hands
that prevents cutting your harness more often.
So fully engaged, we're looking at the numbers,
we're asking very difficult and detailed questions,
and then taking action when we need to.
So that concludes how we're performing
from public safety, co-worker safety,
and how we're engaging the leadership team,
and happy to take questions the last minute or so
that we have.
-: Just before we hop into questions,
thank you Mr. Wright.
I just want to make a notification
that due to an issue earlier with the phone line
at the public comments, we will need to redo the session,
and we will be taking public comments
after Commissioner questions.
So with that in mind, I just want to make sure
all panelists are mindful of the time
seeing that we will need to hold a session shortly.
-: Sorry (indistinct), I have a question,
it didn't come up in the natural flow
of the presentation, but I think it's important.
So building a culture of safety ultimately
is about an open communication.
If you don't know about these things,
you can't fix the issue.
So to that end, I know PG&E has identified
and committed a number of self reports
over the past year.
Many on missed inspections.
All of these self reports in some way lead back
to poor record keeping or poor data management.
Knowing what equipment you have,
where you have it, and what condition it is
is fundamental to knowing where the risk is,
where you hold it in the systems.
Can you speak a little bit about what PG&E is doing
to quickly address the record keeping,
data management deficiencies?
-: Yes, and thank you for that question,
and Sameet can chime in as well.
He's been helping lead this effort for a while,
but we've moved over Christine Calcert
to put a vice president leader over rebuilding
our assets registry, and we've pulled together
some information and at various times
have shared that information,
but we have an asset registry, we do.
In some ways it's very detailed,
where we can spot things that most utilities cannot spot.
Like we can tell you the lean of a tree
out of eight million of them.
So in some ways it's highly sophisticated,
but in some basic areas such as processes
to bringing our adbuilt data, matching our SAP system
to our GIS system of records to make sure
that if the asset's really there,
it's located in both places.
One from a physical location,
but also from a records standpoint.
Getting those things from a conflation standpoint
to line up is a big part of rebuilding that,
and so we have a detailed roadmap
that we shared with the board,
that we staffed appropriately,
and we plan to communicate on a very frequent basis
with your office to make sure we stay accountable
to delivering that.
So there is a significant amount of work taking place there,
and we do know it's very critical to being able to deliver
on our compliance commitments,
but also keeping our system safe.
Sameet, anything additional?
-: I think, Adam, you covered that well.
The last piece I would add is
in addition to GIS and SAP,
Director Thomas Jacobs,
we are also taking the lidar information that we captured
for the high fire threat districts
for the overhead distribution lines
and realigning our GIS system to that,
because that helps ground to what assets we have
in the field, their geospatial location,
which obviously ends up being a material input
to how we think about the potential risk of fires
and the consequence associated with those
if they started from our equipment.
So those are all the elements that the team is focused on,
and as Adam mentioned, Christine is uniquely positioned
to help lead this.
Both her and I lived through this post San Bruno
on the gas side and have built a very robust
asset registry that has the single version of the truth,
the system of record, and the right controls to ensure
as field work gets done, that that information
gets reflected in our system of record.
And that's the same playbook that's being applied
here on the electric side.
-: Thank you.
-: I just want to, and I too thank you, Adam,
for sharing your very personal family story.
It's heartbreaking, but thank you.
And I also would like to please ask
each of the representatives from the PG&E
to please, we're sorry we have this phone line issue,
and were surprised with no public comments
because we always have public comments about PG&E.
So I hope you will be able to stay.
I know everybody's schedule is going to be impacted,
but it's extremely important for you all to hear,
if public calls in, what they have to say.
So thank you.
-: Thank you, President Batjer, for the reminder.
We have any other follow up questions?
-: I'm looking forward to the public Q&A.
-: Thank you, everybody, for being mindful of the time,
and the phone line issue.
As a reminder, if you wish to make a public comment,
dial into 800-857-1917 and enter passcode 5180519
for the English line,
and passcode 3799627 for the Spanish line.
Unmute your phone and press *1.
You will be placed into a queue
and the operator will take your name and information.
You will be called upon to speak in the order
your call was received.
You will have two minutes to speak.
You will hear a bell sound when your time is up.
Please be mindful of other speakers in the queue,
and keep to your allotted time.
I will now turn to the operator
to open the public comment telephone line.
Operator: Thank you.
The public comment telephone line is now open.
Again, if you like to make a comment,
please unmute your phone, press *1,
and record your name clearly when prompted.
Our first comment comes from Will Abrams,
so you may go ahead.
Will: Thanks very much.
Thanks very much, President Batjer, Commissioners.
Appreciated the presentation from PG&E.
I also attended the (indistinct) webinar,
and just wanted to make two points from attending that
important community meeting.
One was Mark Quinlan had presented part of that,
and one of the things that came across
was a lack of an awareness regarding the community wildfire
protection plans.
These plans stretch up and down and throughout
PG&E territory, that really are the go-to plans
for vegetation management and wildfire mitigation,
and it's critically important that individuals
within PG&E are aware of these plans,
that they integrate with these plans,
and I just wanted to make sure
that PG&E was aware of the plans
and working to make sure that they are integrated
as best as possible 'cause certainly,
vegetation management is something that doesn't exist
in a vacuum.
The other point that I wanted to make
that also came across within that meeting,
was that the sectionalization devices
and location of the sectionalization devices
are not being actively shared with local agencies.
This is also critically important as we think about
power shutoffs, as we think about how to gate
the effects of power shutoffs.
That local governments are actively engaged
in those decisions about where and how to shut off power,
and obviously, the balance between power shutoffs
and wildfires, particularly given that we've seen
some recent wildfires that occur at the same time
as we have power shutoffs.
So these issues are very critically important
to make sure that they're addressed,
and make sure that they are being addressed
at the community level, within the communities,
through these discussions.
So I just wanted to bring those issues to your attention.
Thanks very much for having this important meeting.
-: Thank you, Mr. Abrams.
Operator, next caller, please.
Operator: And we have no additional parties
in the public comments line at this time.
But again, if you would like to make a comment,
please press *1, unmute your phone,
and record your name when prompted so I may introduce you.
-: I think we'll give just a few moments for callers.
Operator, are you able to confirm
that there are no more callers?
Operator: Correct, we have no callers
in the public comment telephone line at this time.
-: Thank you.
With no more comments on the line,
public comment period is closed.
Thank you to Mr. Abrams for his comments.
Since we have had issues with the line,
I want to make sure that anybody else
who has a comment, they are able to provide
written comments.
So please do send them to carolina.contreras@cpuc.ca.gov,
thank you.
Thank you, Commissioners, directors, and PG&E presenters.
I will turn it over to President Batjer
and the original dais for closing remarks.
President Batjer, I think you're on mute.
-: I am, sorry.
Thank you, Carolina.
Just want to thank everyone.
My fellow Commissioners and the director,
this has been a long day, but very important,
in-depth information was imparted to us.
It gave us the opportunity to have a good dialogue
with both Bear Valley and PG&E.
I appreciate the amount of time that you all have devoted
to briefing us today.
I appreciate also that you listened in
on the Bear Valley presentation this morning.
Appreciate the value of your time,
and I think we've underscored some important things
that the Commission holds dear,
and we will continue to speak to you about them
and hold you accountable for them.
So I do appreciate it again,
and I want to thank you all very much
for also the response to my letter.
It's being shared with all of the Commissioners,
and more to come, but we look forward
to a great deal of improvement,
which you have pledged to do so today with fast trip.
I'm never gonna call it ESPP,
too many other alphabet soup running around.
It's enough to have PSPS.
So anyway with that, I thank you on behalf
of my fellow Commissioners.
Have a wonderful afternoon,
and Thanksgiving is coming up upon us very quickly,
I won't see or hear from probably most of you before then,
so I wish you and your family and friends
a most delightful and giving thanksgiving.
Thank you all.
-: Thank you.
Likewise.
-: Thank you.
-: Thank you, President Batjer.
Is there any other closing remarks from the dais?
Thank you, President Batjer, Commissioners,
Director Thomas Jacobs,
and thank you to Bear Valley Electric and PG&E
for your presentations and your time.
This meeting is now adjourned.