(gavel bangs)
-: This meeting of the Public Utility Commission of Texas
will come to order and consider matters
have been duly posted with the Secretary of State of Texas
for November 18th, 2021.
For the record, my name is Peter Lake
and with me today are Will McAdams,
Lori Cobos, and Jimmy Glotfelty.
Mr Jeanette, could you please walk us
through the consent items on today's agenda?
-: Good morning, Commissioners by individual bow falling
items were placed on your Consent Agenda
one, six, seven, nine, 10, 11, and 32.
And I need to announce that Commissioner Cobos
has recused herself from items one and six.
-: Thank you, sir.
Is there a motion to approve
the items just described by Mr. Drew Nay?
-: So moved. -: Second.
-: All in favor, say, aye.
Both: Aye.
-: None opposed, motion passes.
At this time, we will move forward to public comment.
All comments related to a specific agenda item
will be heard when the item is taken up.
This is for general comments only
speakers will be limited to three minutes each.
We do have some folks signed up to speak today.
Mr. Jeanette, if you'll please keep time
for us so we can stay on track
with the very long agenda we have today.
First up we'd ask Emma Paps to approach.
She may be in the overflow room,
so she's making her way here.
We'll accommodate her when she gets here.
Next up we have Misty Quinn.
Did I get that right?
All right.
If either Mr. Image shows up
will of course accommodate them.
In the meantime, we'll move on to Draula Taylor.
Hi, welcome.
Sorry, Emma, come on up, thank you.
-: Thank you.
Good morning.
All: Good morning.
Welcome, I don't know if you heard the speakers,
we limit three minutes each and general comments
only if a testimony on specific items
will be heard at that time.
-: Okay, perfect, thank you.
Peter: Sure.
-: Good morning everybody.
And thank you for having me today.
My name is Emma Paps
and I am a lifetime resident of Texas
and a campaign representative with the Sierra Club.
At the Sierra club, I worked to represent
the interests of thousands of Texans across the state
to be exact, nearly 30,000 dues paying members.
And today I'm here to speak with all of you
about our electric grid,
because while we all know that what happened in February
was certainly horrible,
I want to ensure that those of us sitting in this room today
know what the people of Texas really need.
Well, I was fortunate enough not to lose power
for a 16 duration that week.
Other people like my good friend, Anna,
who lives in Austin, were not as fortunate as me.
In Anna's house, as soon as temperatures started to drop,
her interior temperature started dropping as well.
Anna lived in a complex of condos in downtown Austin
and like many buildings here in Texas,
her building lacked installation.
It probably had a little bit of it,
but not enough to keep the temperatures high up there.
Within a day or two of the freest happening,
the temperature inside of her apartment
was just above 20 degrees.
Her kitchen sink had ice on it
when she went to go and try to wash her dishes.
Her and her roommate had to sit in a tense together
that she uses for backpacking in order to conserve warmth.
Now, I tell the story not to bring us all back
to the reality that was this horrible week,
but to make clear that here in Texas,
in order to really make our electric grid
and our electric system work,
we need changes across the board.
If we keep building homes, that lack insulation,
then the next time, if something
like this ever happens again,
which we know it has happened
even before what happened in February,
those people will still be left
stuck in their homes in temperatures below freezing
with ice, sitting on their kitchen sinks.
We need comprehensive solutions to fix the energy grid,
which include things like energy efficiency,
better insulated homes, better windows in our homes.
We need things like solar on our rooftops.
We need wind energy to keep our air clean.
Peter: You have one minute.
-: We need better programs from our utilities
that encourage us to reduce our power usage
when we're near to peak.
We need utilities to say, hey, turn down your thermostat
it'll help you save money,
we'll take 15 bucks off your bill
and it'll help us conserve.
We need programs that start with the people of Texas
that help us improve our lives
and anticipation of events like this happening
in the future.
But most of all, we need public participation.
When I talk to the normal people in my life,
they do not know what's going on with our electric grid.
And that is because things here
at the Public Utility Commission
have not been transparent enough.
(bell chimes)
They don't hear enough about it
in a public meeting in order to inform
the public about what's going on
and how we can move forward
and let them say their piece would be very appreciated.
Thank you.
Peter: Thank you, Emma.
-: Thank you.
-: As Missy make her way, and there's Missy.
-: I'm gonna apologize that my voice is shaking
I feel like I'm in a fishbowl.
(all laughing)
Yes, my name is Missy O'Quinn.
I'm an organizer and a mom here to give my experience
during Winter Storm Uri,
with the hope that a little encourage you
to adopt grid changes,
that'll ensure that I can cut my lights on
and cook despite severe weather.
Like I said, I'm a mom, I have three kids,
two of which are severely asthmatic.
During that week we spent,
I would say, about 17 to 18 hours
of every day in the cold, with no electricity.
Bundled up, just trying to stay warm house about 45 degrees.
Thankfully, we didn't have ice in our sink,
but we felt like we had ice on our estates.
I want to say about the third day
and my daughter Trinity, then 14 had an asthma attack.
It's usually controlled,
but I couldn't plug her machine in and give her a treatment.
Couldn't call 911 because they couldn't send anybody for us.
Thankfully, my partner is from the Midwest,
so we decided we were going to take our chances
and slide to the emergency room.
We spent four hours in the emergency room
trying to get a breathing treatment for her,
but it still wasn't any better
because they were running on generator power.
So even though the lights were on,
so their machines could run, there was no heat.
And so this shouldn't happen.
This shouldn't happen, there is renewables,
there's battery storage,
there are so many ways to ensure
that this doesn't happen again.
Despite my own personal experience,
once the lights did come back on
and once I could get back on the streets,
we spent weeks doing mutual aid for people
that had busted pipes that didn't bounce right back
when the lights came back on.
So I would like to encourage y'all to not just think about
the bottom line of all the people that are in this room,
but think about my child's lungs.
Think about us being able to just function
and not spend an ungodly amount once it's over on our bills.
So that's all I got, thanks.
-: Thanks mom.
And Draula Taylor, come on up.
-: All right, it's Indiana.
-: Oh, okay. -: It's all right, all right.
So I'm here.
I am an organizer and also
at the time of the Winter Storm,
I was with the Harvest Project,
helping out with the Harvest Project
and we were doing some mutual aid.
I am also here to amplify the word for public transparency,
because I think it's telling
public transparency in this process,
because I think it's telling
that there's more suits in this room
than regular people who were affected
and who basically their families died.
I see some of you shaking in agreement
because some of us were affected by this,
but there needs to be more people in this room
and it's very uncomfortable for me to walk in this room
and see reserved seats and the people that I was helping,
some of those people didn't make it.
At the time, there were people downtown,
our skyline in Dallas was still lit up.
People were dying.
People were still dying.
So for those suits who kept those lights on,
I know we could have kept our lights on as well.
For those people who died in their car
having their stuff on,
our city set up warming stations,
stationary warming stations
with buses that didn't move while the community went out
and fed the homeless,
the Harvest Project went out in effect the house list.
We had warming stations and things like that,
but that's not our responsibility.
It shouldn't have been all to us
'cause we had to fight to feed thousands of people.
And still the same week during that time,
when we were feeding everyone we could,
we were trying to get everybody warm.
A block away, a man died, a block away.
And that's gonna haunt us.
It hurts me that I couldn't reach him in time.
And we took the bus out ourselves,
that's not for us to do, it's for you all,
not to allow this to happen.
It's for this room to be a public utility.
This is not about your interests,
It's about the people
it's about everybody's interest.
And again, I know some of you are shaking,
oh, my lights were out for a week.
My lights were out for this amount of time.
People died in their cars.
Some people died in their houses.
-: You have one minute.
-: And I had a lot of stuff to say,
but it's just walking in here and seeing reserved seats
and to come here and find out that the public
have been cut off from this,
that there has to be a reserved,
you have to get an invite to a certain process
of this thing.
We didn't have to get an invite to die,
dying on the streets.
So, I some of you have the best intentions in this room.
Maybe, I don't know, I don't know any of you,
but this is unacceptable.
And that's all I have to say
'cause I can't remember half this stuff I had to say.
It's not our responsibility.
If you are paid to do this,
it's your responsibility to ask us what the solution is
and for us to be a part of the process.
-: Thank you, Miss Taylor
(bell chimes)
Next up is Cyrus Reed.
-: Thank you for the record,
Cyrus Reed with the Sierra Club.
Commissioners, I'll be very brief,
I've spoken to you before.
I think you heard from some members of the public.
And I have my own personal story
of being without electricity,
but also our church helped a lot of elderly folks
that were in an apartment in East Austin
that literally could see the lights on in downtown.
They had medical conditions
so our church took them in
'cause we happen to have power in our church.
So I have my own story,
but I think that the really the three asks are...
Well, first of all, thank you for what you've done.
I think the weatherization requirements
we saw their cut yesterday that they're moving forward.
That's very important to make sure
this doesn't happen again.
So thank you for what you've already done.
I think the two big asks are,
on any huge changes that you're contemplating
let's have a public hearing
where any member of the public can make comments.
So I'm not talking about ERS or little stuff.
I'm talking about the big stuff
and that you do some sort
of a cost benefit analysis before you go forward.
And I've said it before and whenever it's appropriate,
don't forget the demand side.
At the end of the day, people live in homes
and a lot of our homes are leaking
and are not probably appropriate to live in.
So anything the Commission can do
and I know it's not just PUC is TDHCA, it's federal money.
Anything you can do to help boost the solutions
that people actually can employ in their home
or in their small business,
I think would be of great benefit to the state
and make our system more reliable.
So I'll end it there,
but I don't want to leave the impression
that you guys have done nothing
'cause you've already done quite a bit,
but I think we're asking to include the public more
in the final decision-making and with that I'll end it.
Thank you so much.
-: Thank you, Mr. Reed.
-: Yes sir.
-: We have no other speakers signed up
to address the Commission today.
So at this point, public comment is now closed.
We will not be taking up items 13, 18, 19, 21, 24 and 33.
And before we dive into our agenda,
I know we've got a very full, full program today.
Would it work with y'all,
if we save the item number three,
the SWEPCO right case until the end
so we can get through the rest of it
and these good folks can go home?
-: Yes, sir. -: All right.
Let's start off with Lori.
-: Yes sir, thank you.
-: Let's start off with item number two, Mr. Jeanette.
-: Item two is docket 51023.
It's the application of city of San Antonio
to amended its CCN for a transmission line.
PFT was filed on July 26
after exceptions were revised,
ALJs filed memos with corrections,
Commission had oral argument on this matter
at the October 28th open meeting
and remanded it to allow requested information to be filed.
-: Thank you, sir.
Anytime this Commission considers
a CCN regarding new transmission, that's a big decision.
We heard a lot about that at our last meeting.
However, we also asked CPS to provide
underlying information on the need
to support the need for this line.
And I don't know about y'all,
but I certainly don't consider refiling the same data table
without showing the underlying analysis,
providing information.
I certainly don't consider weblinks updated information.
And most importantly,
we still don't have the underlying calculus
that establishes the need for this line.
So until we get that,
I'm not sure we have much to discuss,
but happy to hear y'all thoughts.
-: Go ahead.
-: So with that, I agree with you, Mr. Chairman.
I believe that the resubmission on requested information
was somewhat rehashed, reorganized
from what we had seen before.
So I'm comfortable with continuing to press for this
because I believe ultimately we're trying
to establish a template,
a precedent for what we expect in these filings.
And so we've got to make one filing look like the rest,
and if we're not satisfied,
we've just got to keep plugging away at this.
And I know time is burning, but ultimately the utility,
it will be in their interest
to eventually get you the data that we need.
-: Yeah, we need to see the calculus that justifies-
-: The need. -: The need
not just the high-level number
that promises that it's there, it needs there.
-: Erie as well.
The company did not comply
with the Commission's remand order.
And in order to remain consistent with the standards
that we have said in prior cases,
I think it's important that we have the company file
the underlying information for the calculations
of those tables and the actual reports
instead of including weblinks.
-: I'd echo that very quickly.
I defer to your thoughts, Mr. Chairman on this
and the other Commissioners on what we need.
I think in the end we need this.
I think this line is needed.
I grew up in San Antonio, this area has massive growth.
It is something that is going to be needed,
whether we decide today or whether we decide in 30 days,
something's going to have to happen.
I'm prepared to announce my decision today,
but I'm happy to defer to the chairman
until we get additional filings from the applicant.
-: I don't think anybody's disputing the rapid growth
and the need for transmission.
This Commission has been very aggressive
on building out transmission.
We just need to make sure we go through the process
and go through the process properly,
validate thoroughly the need before we start
putting towers up and affecting people's lives.
Any questions for us on what's needed?
-: Yes, thank you, Mr. Chairman.
Kirk Rasmussen representing CPS energy.
And I apologize that we didn't bring the Commission,
what you were looking for.
We did bring our load studies forward.
So in response to the request and your order,
we did provide the actual data for 2019, 2020,
which we did know was an abnormal year
because of the COVID shutdown
and then the data year-to-date for 2021.
So we did bring that data forward
demonstrating that our load forecast
and our application had trended actually lower.
Our forecasts were lower than what actuals had shown.
And so we did provide that updated information
with the affidavit of our planner, Mr. Tamez.
So we didn't understand we were rehashing the same data.
We thought we had brought that forward.
Peter: We appreciate the update.
The request is for the underlying calculations,
that gets the data, the results in the data
and the deeper dive into the study.
And the math that gets you to the forecast.
-: My apology.
And I apologize that we did not bring the Commission
what you were looking for.
So we will bring the...
You're looking for the calculations
of how we got to the-
Peter: The knowledge and analysis
of how you got to those forecast, yes, sir.
McAdams: How do we it's real?
-: Okay so, we will endeavor to do a better job.
I apologize that we didn't bring
what you all were looking for.
We do believe this was a necessary project for the area,
and we'll make filing, bringing the Commission
what you're looking for, showing the calculations
for that forecast in a little more detail.
-: I appreciate that, and in the future,
feel free to actually submit actual documents
instead of weblinks.
-: We were trying,
there's some voluminous documents
and so weren't trying to burden the record,
but we'll be happy to present
the underlying documents and-
Peter: Appreciate that.
-: Yeah. -: Thank you.
Would entertain a motion to remand this case back
to docket management to allow CPS to provide the evidence
that was originally requested.
-: So moved. -: Second.
-: All in favor, say, aye.
All: Aye.
-: Motion passes.
Thank you, sir.
We're going to table item three
until the end of our programming today.
Item number four, please, Mr. Jeanette.
-: I'm four is docket 52610,
is the application has stuck to them in their CCN
to build a transmission line.
To Commission, we issued a order request
and briefs on a threshold issue in this case,
focused upon interpreting what the Commission's actions
in its orders where it approved a single circuit,
double circuit capable facilities.
What that meant in regards to the second circuit?
We've gotten briefs back in the matters now
in front of you for decision.
-: Thank you very much, Mr. Jeanette,
this is something that have been discussed before.
It is an important issue.
I have some thoughts, but of course,
want to hear from y'all.
I think it's fairly straight forward
to say that the Commission did not approve
a second circuit in the original CCN,
a big part of that is establishing need.
That was not done at that time.
And we certainly aren't gonna,
I'm certainly not comfortable just assuming
that every single circuit,
CCN approval out there in the state
is valid for a double circuit without further consideration.
Pure requires that we evaluate that need
before authorizing additional capacity.
That being said, one of the benefits of these structures
is that it's an existing right-of-way,
it's an existing structure,
and we of course have been adamant
in advancing transmission projects
to address well articulated need.
I think we should have a second CCN application
for the second circuit,
but it should be in many ways expedited.
We don't need to go through the whole process again,
we certainly need to look at need.
We'd certainly need to look at costs
and the impacts of any additional infrastructure
that that's not accommodated within existing structures
and existing right-of-ways.
But I don't think we need to do
the full environmental assessment
that's already been done on the same piece of turf.
And we certainly don't want to unnecessarily delay
new transmission projects.
Thoughts?
-: Thank you, Mr. Chairman.
I believe that you're on the right track here.
I think CCN is required for a new circuit,
but I do think that there are a few things
you've mentioned them that might make
a process for the second circuit much easier.
And as you said, scope,
there's not a routing component to it.
We know where it would be.
If we do choose to require an environmental assessment,
I might suggest that we consider that that assessment begin
when the first circuit was approved
because we don't need to go any further back than that
because the original environmental assessment
went from that date backwards.
So we would have an entire record
of the environmental impacts of that line.
That would be if we required an environmental assessment
on just hanging a second circuit.
I think the need issue,
it's kind of the cornerstone of what our authority is
to protect right payer, so agree with that.
And I want to be able to give
the transmission owners this ability,
but I just think it's too much discretion at this time
within the framework of the law that we have.
So the last thing that I would say is, I think some
of what they file will determine the scope
of what the CCN will be, since it doesn't include route,
it may not include environmental work,
or it may include a short amount of environmental work.
So, I think we need to be diligent
in how we accept what those CCN applications look like
and ensure that they are narrowly focused
on what that second circuit is
and what the need for that second circuit is, thank you.
-: Thank you, chairman, Lake
and Commissioner Glotfelty.
I generally agree with your comments on this issue.
I think with respect to the stack case,
the facts of the case,
the Commission's order would require
a CCN application to be filed.
As we move forward if a utility files a CCN application
for a single circuit,
and there is a Commission order
approving the single circuit,
the CCN is for the single circuit,
and you must come back for this second circuit.
If a utility files a CCN application
for a double circuit transmission line,
the utility should provide the information
related to load growth
the need for the second circuit
as you all have well articulated
is important from a consumer cost standpoint.
Costs associated with the infrastructure
for the second circuit.
I agree that we need to look
at what we can sort of streamline
and make more efficient with that.
If they do have to come back ultimately
to add the second circuit later,
I think one thing we got to keep in mind
if a utility files a CCN application for two circuits,
but only installs one circuit,
and we'll come back and install the second circuit later,
that based on the specific facts of that case,
we need to determine whether we want
to give them some kind of a timeframe to come back.
Because what I have noticed,
especially in my review of the Rio Grande Valley project,
the San Miguel to Palmetto line is that the utility
that was responsible for the majority of that line,
they hadn't come back for the second circuit
and a lot of activities happen in the interim.
There were wind farms built
and radial lines build out to them
and so adding the second circuit ultimately
is going to be a little more complicated
because of all the activity that has occurred
in the interim.
And so that makes that more costly
for the installation of the second circuit,
and it requires a little bit more of a routing jiggering.
So I think as we look forward to utilities,
that file CCN application for two circuits,
but don't install both circuits at the same time,
we've gotta be cognizant of making sure we understand
when they're projecting that the need
for the second line's gonna come in
and maybe I think Commission staff has noted
that in the past, in some orders,
we've used seven years as a deadline for them to come in
and if they don't come in within that seven years,
for the second circuit, then they have to come back
and follow the CCN application.
I would venture to say that maybe we need to move that up.
I mean, we're growing five years, maybe
so that we're not stuck with having to wait seven years
and then play catch up and then end up
approving the second circuit that ends up being more costly
because of all the activities that went on.
So just want to put that out there for consideration.
-: Let me throw this in there,
the concept right now we have is the seven years
really going to building the transmission line at all.
So really the first circuit,
would you want to have, start thinking about this,
would you want to have different timelines?
I'm putting the first circuit in,
then you do them putting the second circuit in.
So.
-: I mean, I defer to Jimmy
and then you've got a lot of experience in this world.
What are your thoughts?
-: The way that we certificate these, you have to show need.
So I think the seven years on building a project
is probably too long if Oncor has shown need
and that the Commissioner has ruled that we need it.
We need it before seven years.
So I can't imagine that a utility
is going to want to wait seven years
to put a transmission line in.
For a second circuit,
if we are giving an exemption for them,
or some kind of an expedited process for them
to come in for the second circuit within seven years,
that probably makes sense.
The one challenge that I have in my mind
around all of this is,
I don't even know what the universe
of double circuit capable of,
single circuit lines there are out there,
and they may be maybe 10,000 miles.
And if everybody just gets to go build,
I fear what would happen to our transmission rates
without having our check and balance on that.
So the second circuit,
maybe we could look at that,
but I think they've got to build the first project quickly.
-: So would you favor a shot clock on the first circuit
and a longer shot clock on the second,
since, you know-
-: So I think the question would be
how we would phrase it
because I don't know if it's in service.
Sometimes these projects take a long time.
Sometimes they're dependent upon the supply chain,
which obviously we know is an issue right now.
And really transformers many times are the big challenge.
So that would be fine with me.
-: I would just point out to y'all
because this happened before any of you got here,
but when we came up with the seven years,
we had gone out and asked to input from utilities.
I've asked my people to go pull
those filings up and sort of put that together again
and bring that forward to y'all
so you can see what we have.
Now, we may want to go out again,
because this is becoming a little more complicated
when we're talking about two circuits,
and whether we want to go through that routine again,
to figure out these kinds of timelines or stuff.
So I don't have a timeline for you yet
on when we're going to have that pulled together,
but we're starting to work on that to help y'all.
-: It would seem to make sense to see
let's confirm the details of our current default setting.
But in principle, I certainly agree
with Commissioner Cobos that the need
and Mr. Glotfelty, the need means need,
and of course, with accommodation,
for supply chain issues, library issues,
and then the other externalities,
but if the needs there, we need it.
With the consideration to the information
will get from your office, Mr. Jeanette,
we'll take a look at that when it's ready
to see what our current default setting is,
and then move from there.
Otherwise, do you need any other information
or direction from us?
-: The only thing I would throw out,
and I'm sure we're going to talk about it
in the next docket,
is that because we've talked about this
in this briefing, also,
we need to get our orders a little sharper on this point
to make it clear what we're certificating
and what we are not certificating.
And we have plans to do that.
-: And I will also add that at some point,
when we opened up the CCN rule or CC and criteria role
that we may want to consider
sort of setting different standards for that second circuit,
consistent with our discussion
to expedite those CCN amendments,
if already is an established route and assessment.
So just as a place holder.
-: Absolutely.
-: I'd agree with Lori.
-: Excellent.
Do you agree, Mr Jeanette?
-: So what we need for you now,
as I answer to the briefing question,
which I think I heard you say that the Commission orders
single circuit, double circuit capable
mean we only certificated the one circuit.
-: That's correct.
-: Yes sir.
-: Agreed. -: Agreed.
-: Do we need a motion on this?
-: Yes.
-: So moved.
-: Second.
-: All in favor, say aye.
All: Aye.
-: Motion passes.
That'll bring us to item number five.
-: Item five is docket 51568.
It's the application of the CenterPoint
to amend at CCN for a transmission line in Wharton County,
PFD was issued September 1st,
exceptions and replies were filed.
The ALJ filed a memo on November 3rd
with proposed changes and corrections.
After your discussions, I have one more comment
on the PFT that unlocked the night.
-: All right, I think PFT got this right.
We just established that approval of this CCN
would mean that it is for only that single circuit,
despite the use of lattice structures
and other some consideration in modern poles here.
But I think that the cost benefit
and the future value of a double circuit capable
of structure outweighs the implications of monopoles,
but I'd happy to hear your thoughts.
-: Okay, so you would stick with the lattice,
the PFD lattice?
-: Yeah. -: Okay. All right.
I wouldn't heavy one way or another,
I was trying to,
frankly, having watched the Commission for awhile
they always used to default setting
if somebody asked for monopoles they granted monopoles.
But now I hear you.
What do you think?
-: I agree with the PFD, I would adopt the PFD.
I think its monopoles are more expensive.
-: I know.
-: And we're gonna-
-: There was one mile
and so I was kinda trying to balance that.
-: Right, right.
I'm comfortable with the PFD.
-: Okay.
-: I guess if we're looking to the future
and look into growth, we're paying,
if we go with the monopoles there downsides to that,
but in the big picture,
we'd be paying more money for less capability
for double circuit down the road, which.
-: Mr. Chairman, I guess I have a little different view
and that is that if we're impacting a resource
that can potentially be adding megawatts to the system
and I've read this record, quite a bit
to try to see the nuances.
I mean, I know the original tax abatement
was for 300 megawatts for this farm
and then it's grown.
I think that the right thing to do
is to approve the order with a modification
to allow monopoles across the section.
Only that last section of where the solar farm would be.
Monopoles can be double circuited as well.
They don't just have to be lattice structures.
So if that does need to be a double circuit at a later date,
they may need to change out a monopole structure,
but it still can be double circuited.
And I just think in this time, when we need resources,
the delta between a monopole cost
and a lattice structure is not huge
when you're talking about a mile,
if you're talking about tens of miles or hundreds of miles,
it can become substantial.
But the cost, if it's a mile
there may be six or eight structures across this solar farm
and that's it.
I would suggest that we approved the order
with a modification
that CenterPoint look at monopoles across
that last area where the solar farm is,
and then approve it with that modification.
-: Certainly some valid points,
and I know we're scrambling for resources
in all ways, but I also wasn't quite sure
just how much on thousands of acres,
how much did a few extra feet really cost
in terms of megawatts?
-: That's a fair question.
I think, what was in the record said
that you got about another 10 feet of right-of-way
and that's a very legitimate question that-
-: Thousands of acres?
-: Yeah.
There are obviously thousands of acres out there.
We don't know what the universe
of what's under a lease for the solar farm
but anyway, that's a good question.
-: And I guess my question is how much more of a cost
would it be to put monopoles in the mile long stretch,
the extra right-of-way
and also to understand a little bit better,
what stage in the development this solar facility is in.
That was a little unclear,
and maybe you can clarify, Megan,
where this solar facility,
in terms of placing it into service,
we're going to make a change for it.
That we're going to be sure that it's gonna
actually be placed into service
'cause it sounded like there was still some,
at least the ALJ thought
it was sort of a speculative project at this point.
-: Sure, Commissioners, Megan Griffiths
on behalf of Danish Fields Solar.
To answer the first question with respect to the monopoles
by decreasing and using monopoles
that saves an estimated five to 20 megawatts
for the project.
The reason that that route four was better
was because that basically it's on an area
that was constrained by pipelines.
So the route that the ALJ chose was good
because that was not buildable land already for them
and they were aware of that,
but so that it does save an extra 10 feet of right-of-way
to use the monopoles.
And so that's the estimate.
And then with respect to your questions
regarding the stage of the project,
the ALJ did roll that it was ongoing development.
It's in the advanced stages of development,
they have entered into the IAA with CenterPoint.
There are $6.6 million of security that was put down.
We had a highly sensitive number
of how much investment was put on the project already
at the time of the hearing that has increased significantly.
Since then we submitted that number in our exceptions
they've closed on the construction loan.
They've already procured the panels.
There was testimony on that in the record
that said basically the month following the hearing,
they had to stay on project, to meet their COD date,
go ahead and procure.
They have done that
and then onsite construction is slated to begin in December.
So it's in the significant advanced stages of development.
-: Thank you.
You said that the difference of that 10 feet of right-of-way
between the monopole and lattice structure
would reduce total capacity, install capacity
about five to 20 megawatts.
Megan: Correct.
-: Okay, so there's no, I guess,
regulatory or procedural reset by making that change,
that would in some way,
force the project back to the beginning
or another way impeded in the time to implementation
is just a reduction of five to 20 megawatts?
-: It would reduce the size of the project.
-: Okay, but it's not a reset.
It's not going to delay the construction
or other implementation of the project?
-: That's correct.
-: Okay, and what is the total expected installed capacity?
-: The total expected install capacity is 600.
Not sure it's correct or not.
Glotfelty: That's a big fall.
-: Yeah, we liked that.
Now let's hope 10 feet is a 1% impact on capacity.
-: I guess what I would say is,
going through this process as a developer
and as a transmission line citing,
they're both, they're hard.
They're very hard and they have to play off of each other,
but you also have additional landowners out there.
You have other parts of the community
that you have to think about,
this processes is long.
I think what you want to do is you want
to try to accommodate both.
-: Sure.
-: And if you can accommodate both
within the agreement of the right-of-way,
and then you're modifying the structures
I think what we're showing
is that, look, let's accommodate this.
We want the excess megawatts, we need the line.
The solar facility needs the line
and we can modify it and let both projects go forward.
-: Quick, McAdams.
-: Commissioners, Andrea Stover
on behalf of CenterPoint.
CenterPoint is ready to do whatever
the Commission tells us to do and to construct it
as you direct.
I would just note that to the extent that we are required
to narrow the right-of-way
across the Danish Fields property.
There may be certain areas where it's going to be necessary
to have it wider than 90 feet
there's areas where there's turning structures
and that requires wider than 90 feet of right-of-way.
And because at the sort of Southern end of that property,
there are marsh areas and other places in which they'll have
to have a longer sort of distance between the structures
as you do that, it requires the right-of-way to be wider.
Yeah, so to the extent that that the Commission
can allow us some flexibility in those areas
so that we can be sure that we're constructing it safely,
we're happy to do it and narrow that right-of-way
with using monopoles.
-: Yeah, I would never suggest that we do anything
to violate national electrical safety code.
We need heights and we need towers
within the code to make sure that they're safe.
-: You're not trying to work around that one?
-: Not trying to work around that one (chuckles).
-: Okay, if you feel that that's where to go
and I have to defer to your expertise on that
in one way or the other.
-: Yeah, so look, cost is certainly a perspective resource.
I agreed with, and initially coming into this,
I was on the side of, grant the one mile monopole,
but I think the important thing
is we don't take monopoles off the table
for costs every time,
because they have been a valuable tool in the past.
I mean, in terms of these projects,
it has been a time honored tradition of this Commission
to grant monopoles to ease the impacts to landowners.
I mean, it's an easement thing.
And if I don't have to provide 10 more feet
of easement on my land, I'm a happy camper, generally.
What do you think, Commissioner?
-: I was waiting for you to finish.
-: Yeah, I know.
I was after that but, well-
-: Sometimes we require,
we asked that the landowner who's getting
this beneficial monopoles
to grant the right-of-away is reduced
cost of the transition line.
-: Happy to do, if the conditions are right.
-: And Commissioner, just to clarify
in the record, we've indicated that it's a 50% increase
because it will require farther distances.
Well, I'm sorry, shorter distances and more structures.
So for that, we don't actually have in the record
what it would cost to just monopole that area.
Glotfelty: It was the entire length of the line.
-: That's correct.
-: And that is certainly 50%.
-: Yes. Yes.
And for that distance,
the cost would be 50% for whatever it is for that one mile.
So it would be a 50% increase.
-: One comment though, is that it would also decrease
the condemnation award too, with the decrease in feet.
So it's a give and take on both sides.
In the record, we did have an estimate
that it's about a million dollars,
a megawatt of impact.
And so I think that you don't always take
the condemnation side of the proceedings in effect,
but this is a very close call on this one
and I think that decreasing it to use the monopoles
would effectively be a wash.
-: I think the record shows
that there's a difference of opinion
about whether or not it would be a wash
in terms of the cost of the right-of-way.
-: If it's a four mile long so one mile is 25%.
-: Right.
-: Good point, it's a good point.
-: The other thing that I would just say about monopoles
is we naturally just think about a steel monopole structure.
There are other monopole structures out there.
This is in an area where they're prone to hurricanes.
I mean, we have spawn concrete towers,
we got half steel, half concrete.
We've got lots of issues there
that may reduce the cost or have some delta
and the cost that provides a lower rate.
Lattice structures, especially if they're turning structures
are big, heavy, expensive ones,
the same thing with monopoles.
But it had been my experience
that the difference isn't that big in terms of cost,
if you can get the benefit of having both the facilities
and the generation, all the generation,
again, that's where I would fall down
to try to accommodate both.
-: Commissioner Cobos.
-: Well, I think it makes sense to try to accommodate both.
I'm trying to really understand the additional costs.
I know that the impact on the flip side is less megawatts,
and we need more megawatts
and one megawatt is 200 homes, right?
In this hot summer.
-: Right.
-: And so we're looking at range of five to 20 megawatts
of a reduction.
So those are significant megawatts.
But I said, I know it's a shorter line.
It's about a mile.
I think it's just really just balancing out both if we can,
but I would really like to understand the cost impact
of adding, is it one monopole, is it a few monopoles
on one mile?
-: It would be a few monopoles.
I don't have the exact number of structures
that it would require.
That's something that we can get you.
I will say that the longer that this process goes,
the more, it may create issues
for the generator we're trying to interconnect
because they are on a timeline as well.
And so if this process is slowed down,
it may impact our ability to get them interconnected
and get their megawatts online.
But we can go back and get you cost information specifically
for changing that one mile.
-: And their is assigned interconnection agreement?
-: Yes. -: Yes.
-: Yes, and CenterPoint has actually completed
their facilities to interconnect Danish Fields.
-: Sure, so I made this is a 30% increase
on 25% of the project.
So it would give you,
what's the quick and dirty math?
-: 12 and a half.
-: 12.5% increase in the total project costs
to accommodate both the increased transmission
and to ensure those additional megawatts
are brought online and that project is not disrupted.
-: Overall, I'll tell everybody
kind of where I'm defaulting right now.
I think non bypassable transmission costs
are going to be an issue in the future
'cause we're going to be building
a lot of transmission 'cause we're going to need it.
And there's going to be more solar resources out there.
I think we'll get our megawatts on solar.
I think it's coming, so that articulated it.
In this case, if we want to expeditiously move,
I'm like you curious about these overall costs
associated with this short line, but ballpark,
if you're taking 25% of the project
and you're increasing those costs,
I think it's gonna fall somewhere in there.
So I would go with the lattice work
and just move with the PFD.
Get this thing moving along,
make your interconnection date, energize
let's get the megawatts going.
-: Okay.
-: So where's the votes?
-: Yeah. I mean, that's where I started.
-: So you picked me up?
(Commissioners laughing)
Fair enough.
I'm perfectly content to move forward
with lattice structure.
No need to-
-: Okay.
-: I mean, it's a 1% difference in this project at most 3%.
I know it's not ideal,
but I'm certainly happy to move forward with that,
that we got a good sense of where you are.
-: In balance, I think I would lean towards
the lattice towers only
because I think Commissioner McAdams,
you made a strong point.
We are gonna have a lot of solar come into our market.
This is a very large solar facility
and I think it will go a long way
to providing cost efficient,
much needed solar generation for our Texans.
But I think just cutting the sliver off of it,
ultimately it's a wide range, five to 20 megawatts.
I mean, it could ultimately be-
-: Could be on the short side.
-: Could be on the short side
but we got to weigh that with the additional costs
that we are going to be placing on rate payers
through transmission cost of service.
And so that's my basis for landing with the lattice towers.
-: So can I ask you a question of CenterPoint
and that is in this process,
I think I read in the record that you all
had not had a whole lot of communication
with the solar farm early in the process,
is that correct or?
What I'm trying to get at is
if you had had these discussions early on,
would a monopole structure had been considered
earlier in the process rather than just
to total lack of structure.
-: Sure, and when you referenced the solar farm,
you're referring to Danish Fields
'cause we're interconnecting a different solar farm.
-: We did actually have conversations with them.
In the hearing, one of our witnesses discussed
the fact that we talked to Danish Fields
about the need to interconnect another solar facility
to hill G and it would require crossing
the land that they had under option at the time.
I think ultimately the issue is lattice structures
are considerably less expensive for CenterPoint
and the difference in right-of-way
with is not very significant
because of they're in a hurricane prone area
so that sort of increases the costs
that are associated with making sure
that monopoles in particular are hurricane proof.
CenterPoint's analysis was
that it ultimately made the most sense
to stick with the lattice structures.
-: Good point, I think, as we're looking
at this transmission infrastructure,
we also, especially in certain point service territory,
you need to be thinking about
not only reliability, but resiliency.
And so thank you for that additional information.
Commissioner: Absolutely.
-: Any other questions? -: No.
-: I know Mr. Jeanette has some additional comments.
-: Yes, sir.
Ordinarily we would have done this through a memo,
but we missed it and it was brought to me yesterday, late.
I've talked to each of your offices this morning,
but I want this on the record
or in paragraphs 11 and 12
one dealing with deviation more than minor
and the other dealing with deviations
for engineering constraints
or ordering paragraphs that used to be in our orders.
Previous Commissioners have taken
these ordering paragraphs out,
they really should not be in our orders.
And so as our current orders don't have these,
it's my intent to pull these ordering paragraphs out
before we bring this back to you for signature.
-: That works just fine, any opposition to that?
-: I don't think so.
-: All right, at this point,
I think we've got a sense of direction
everybody wants to go.
Is there a motion to adopt the proposal
for the decision with a modification
incorporating Mr. Jeanette's comments
as he just articulated and clarifying
that this would in fact be
only approving a single circuit?
-: So moved.
-: Second.
-: Thank you, Ma'am.
All in favor say, aye.
Commissioners: Aye.
-: All opposed, nay.
-: Nay.
-: Motion passes, thank you all.
-: Thank you.
-: That brings us to item number eight.
-: Item eight is docket 52178.
I's the application the Oncor to adjust this ECRF.
Proposed order was filed on October 29th
and the ALJ filed a correction memo on November 3rd.
I also filed a memo with a change yesterday
or the day before.
-: Proposal wouldn't make sense to me.
Any other thoughts?
-: No. -: All right.
-: I just-
-: Looked down there Jimmy?
-: $30 Million bonuses, a lot of money.
For a $47 million or $48 million,
$49 million in energy efficiency improvements
and a $30 million bonus.
This isn't the right place to have this discussion
but I look forward to when we discussed
the entire energy efficiency program
to figure out how we right-size this
and make it the best energy efficiency program in the US.
-: Well said.
-: I think there's been, just agree on all points.
And I know there's been conversation by this Commission
and the discussion by this Commission about improving
the return on invested capital for our rate payers
and the energy efficiency program,
get the best bang for our buck that we can get.
And I think there's a meeting tomorrow where that could be
an excellent topic of discussion.
To the extent we have ideas on how to do that.
-: Correct.
-: Are you comfortable with the proposed order?
-: I am. -: All right.
Is there a motion to adopt the proposed order
as modified by Commission council November 17th memo?
-: So moved.
-: Second.
-: All in favor, say aye.
All: Aye.
-: None opposed, the motion passes.
Will bring us to item number 12.
-: Item 12 is docket 52689
is the application of CenterPoint.
AEP and TNMP for a load management programs
and agreement was filed on November 9th.
I'd filed a memo requesting attendance of the parties
at the request of office.
So I understand that currently
this is an None opposed agreement.
-: Thank you, sir.
I'm glad that request was made for the parties to be here.
I certainly have some questions at this point,
but certainly want Commission staff to approach.
Is there any particular party we want to call it first
or we can just call all of them?
-: You gotta think there's enough
for all of them, Mr. Chairman.
-: Oh yeah, all right, come on up.
-: Maybe I overshot.
(Chairman laughing)
-: We can work in shifts.
-: We only have one shift.
-: Thank you.
-: While everybody gets settled
we can also rotate in and out.
We don't absolutely have to have everybody at the same time.
I know we've got a long day ahead of us
while everyone gets settled
and consideration of programming today
does it make sense for you all we're at the one hour mark,
do another hour and then break for lunch at 11:30?
Does that work?
-: Sure.
-: All right, good deal.
All right, they're like over being here.
I know we have a lot of questions.
I suspect we can start to my right with the questions.
-: Well, I'll defer.
-: Thank you, Mr. Chairman.
Thank you all for coming.
I'm trying to understand just
the kind of the initial basic premise behind the program.
And I know you can say it's to reduce demand,
but it didn't go through kind of a normal process.
It didn't go through any of the existing programs.
It went through the legislature
and I'm just trying to get an understanding
of what didn't we have that you all required
to go to the legislature to get a program like this?
-: CenterPoint.
-: Good morning Commissioners,
Sam Chang with CenterPoint Energy.
To the extent that you have technical related questions
I do have with me my Energy Efficiency Manager,
Shea Richardson.
But with regard to this interim program
that we'd like to operate for the next 90 days or so,
there is a little bit of a difference
in terms of why it's outside
of our current energy efficiency portfolio.
Some of those reasons have to do with budget caps, right?
In the current energy efficiency rule,
there are certain budget caps,
and that impacts how we could deploy
load management programs.
Another aspect is for the energy
efficiency load management programs,
transmission level customers are not eligible participants,
whereas in the interim programs
that we're seeking approval of,
they would be eligible participants.
And so there's a little bit more flexibility
as far as casting a wide net
for participation and deployment.
-: Can you all, all of you, I guess,
give me an understanding
of why the discrepancy in the program,
not the discrepancy, but the discrepancy in the amounts.
One utility wants 1.5 megawatts,
one wants 10 megawatts,
and the next one wants 100 to 300 megawatts.
It seems like 100 to 300, not necessarily a pilot program,
the others might be.
How do you all come to those numbers
and defend the discrepancy in that wide range?
-: Sure, at a high level, there are differences
with regard to our customer load profile,
as well as our service area.
I'll defer to Mr. Richardson
in terms of how we got to our numbers.
-: Morning Commissioners, Shea Richardson
with CenterPoint Energy.
As Sam mentioned, I'm Energy Efficiency Compliance Manager
for use of electric energy efficiency programs.
In terms of the scale of our program,
we have historically implemented
a commercial load management program
through our energy efficiency portfolio
that's in the 100 megawatt range.
That's about the scale of the program.
So we look to design and implement
this winter load management program,
this interim program, which was something new for us,
we really kind of use that as a base
on what have we done historically in the summer peak
and kind of take that as a starting point
in terms of our goal for that 100 megawatts,
with the idea that we would look to expand that
and increase that number possible
so that we had as much curtailment available
for this winter, as we possibly could.
-: For the record, Stacy Whitehurst on behalf of the TNMP.
So obviously we're one of the smallest utilities,
and we have the 1.5 megawatt goal
in the summer peak period.
For our load management, it's about five megawatts.
And so we are treating this as a pilot program.
It's not that we don't have that much available load
to go out there and procure
so that's why ours is so low.
-: I appreciate the way that it was put together,
where we're obviously looking for a demand reduction.
It's key as we continue to move through this market reform.
To me the demand response is a key component of it.
The way that you all have suggested
or outlined the program with no critical loads
that, 24/7 availability to procure
the numbers of schedule outages and the hours per each,
they're fairly common.
And I think that the only thing that troubles me on this,
I like the direction of it,
it's just that it was filed expeditiously
and we don't know anything about it.
And this program is supposed to start in 12 days
and be for three months as a pilot and-
-: With no budget caps?
-: We had no budget caps,
but it's hard for me to get my head around.
I know the legislature has spoken on it,
but it's just hard for me as a Commissioner to sit here
and just say, well, we're going to approve a program
that starts in 12 days
and not know much beyond that.
-: I don't think the legislature approves anything
with the division that it's unlimited
in its impact to consumers, that's called a tax.
And this is not that.
So I think they have always allowed
the Commission discretion to set reasonable parameters
around the pilot project.
Would you agree with that?
-: I wanna add to that point, Mr. McAdams.
I think SB 3 allows for this program.
It is our duty and our responsibility
to the back end to ensure that we look at it
from a rate payer standpoint as well.
I don't mean to interrupt your flow,
but I did have a question for AEP.
For comparative purposes,
Commissioner Glotfelty, just sort of noted the wide spectrum
of megawatts that the different utilities proposed
in their program.
AEP's goal would be to achieve
10 megawatts in load reduction
for an estimated budget of, I believe, 350,000.
So when you compare that to CenterPoint,
which is 100, between 103 hundred megawatts,
and they're at 650,000 for the estimated budget.
Is that what I'm reading correctly
from your proposed program?
100-300 megawatts with what kind of an estimated budget?
-: Commissioner, we're seeking 100-300 megawatts
and we're pricing it out at $30 a kilowatt.
So on the high end, it would be 9 million
with regard to the estimated budget on the low end,
it would be 3 million.
Commissioner McAdams, we do agree with you in the sense
that the Commission certainly has the regulatory oversight
and review of what it thinks should be the reasonable
and necessary costs.
That's why we made the commitment
with regard to the regulatory asset
that recovery and the reasonableness
and the review of that will happen subsequently.
And so, we are not intending
to have an unlimited amount of money
to use for our load management program.
-: Are the time constraints articulating these plans
in essence, a cap on the amount of money that can be spent?
-: We do appreciate the urgency at which
the Commission has taken up this matter.
And we do apologize for the time crunch
and we don't think it's optimal.
-: No, no, I mean, the time of demand response.
-: I will defer to my tech.
-: Okay, I mean, it varies by program,
but four hours, no more than four hours at a time
and no more than four incidents of request was one of them,
is that in effect they can strain
on total amount of money that can be spent?
I don't know, I'm asking.
-: Commissioner, I would say in terms of the constraint
on the total amount of dollars spent,
one of the features of our program is that we're having,
obviously we're going to have customers and participants
as we sit in our plan, enroll and apply to this program
and effectively what will keep cap spinning
is that we will approve
and our commitment will be to pay up to their qualified,
agreed to curtailment amount
that they provided on that application.
-: So there's a cap per customer,
but not a cap on how many customers?
-: There's not a cap on the number of customers,
but essentially there was a cap on what we commit to pay.
So we will approve at the meter level for every participant,
a certain amount of load that they expect to share.
And in the aggregate, that could be 100,
or it could be 300 megawatts,
but we won't pay based on performance,
anything more than that.
So if we know that we have 100 megawatts
worth of curtailment enrolled in the program,
that's our commitment to pay at that incentive rate.
That's what we would commit to the customer.
But if we over-performed based on that,
we're not going to pay based on that performance.
So that's basically one of the ways
in which the program essentially allows us to go
into any of these curtailment events,
regardless of number of events,
knowing the absolute maximum that we would expect
to pay through the program.
-: Sure, but let me ask hypothetical,
if you expect 100 to 300 megawatts
worth of customers, demand response to enroll
what if you have 800 megawatts
worth of customers enroll?
-: If we did have eight,
again, that would be on the very high end.
I think, and I guess I prefer to say,
I think our expectation the highest, and it would be 300.
I think if we exceed that
and certainly we are constrained on time
so we'd like to push for as much as we could.
If we look like we were going to have more demand
for the program to exceed that 300 megawatts,
I think that's just something that we would communicate
and if there was any budget adjustments need to be made.
-: What has been the customer interest in your programs?
We're in a very expedited timeline here.
I mean, are you hearing from your customers
and your service territories
that they're interested in participating in this program?
-: Yes, we have had many, many customers
and many participants
some that have participated
and some that in our historical program, some that haven't.
So we have had a lot of interests.
We also have had a lot of questions
and certainly due to the timing,
because we are trying to gather this information
and have this set up for December authentication.
So it's a very quick roll out.
So we have had some questions and concerns
on just the timing of it being something new
and what's needed to participate
and is this really gonna happen?
So we've got a lot of good feedback,
but we certainly, haven't got a lot of questions.
It's something new for us
and it's been such kind of a quick turnaround,
quick rollout.
-: 'Cause that's what I'm kind of wondering,
at the end of the day,
how many customers are we gonna really have sign up
for these programs?
I mean, y'all are asking us to approve this very quickly
at the very beginning of the winter
when really the true tread on the winter
is January and February.
I guess the other question I have,
and it seems like with respect to the CenterPoint
and I'd have to flip around and make sure,
but on the other companies,
but the targeted program participants
would be commercial customers,
aggregation groups and reps.
With respect to the commercial customers,
are these larger commercial customers?
Are we going to have some kind of cannibalization
between this pilot program and ERS?
And to some extent,
is there any overlap, I guess is a question.
-: Commissioner, one clarification,
currently reps are not eligible participants,
but we are fine with having reps
as being eligible participants if that's what you want.
I'll defer to Shea with regard to-
Cobos: It's actually in your filing.
So that's where I'm getting all this information,
unless I'm missing something here.
It says-
-: Arms.
Cobos: Arms, okay, all right.
No wonder we got a lot of paper on this case.
Thank you, Kelly, okay.
Thank you for the clarification,
but we'll, we'll get to you in a bit (chuckles).
-: Commissioner, I believe your question
was around just the size and type of customers
we expect in our program.
It's certainly early in that process,
but, I would expect we would have a range
of larger and smaller commercial customers.
We really haven't limited the scope
of the customers we're targeting.
So I don't know that I have a lot of good information
for you right now and exactly what that range is
in terms of the feedback we have or what size customers.
But I do know that it is a broad range
of both larger and smaller.
-: Okay, well, I think depending on how this program goes,
if we continue to have these programs in the future,
that'll be something to consider
in terms of, whether there's any overlap
or crossover cannibalization between the programs.
I think with respect to this winter,
I mean, ERCOT has already issued out their RFP
for the winter procurement for ERS.
So I don't think this would affect any participants
on that end, is kind of what I'm sort of observing
at this time.
But I was just kind of curious
to learn a little bit more about that
especially with CenterPoint,
having a large industrial load that you have out there.
-: And Mr. Chairman,
with regard to your question
about the control over enrollment issues,
we would view that as a question that's really decided
when it comes to cost recovery.
If you think we over enrolled,
or maybe we went past our sweet spot
as to what is cost-effective,
certainly parties and the Commission itself
can raise that question.
-: Thank you, so here's the deal.
This Commission is moving heaven and earth
so that we never have to use your program.
(all laughing)
And so that reasonable test, when we get to it,
we better not have to use your program.
And so the larger it is,
and the framework that it fits in,
is important, especially in the short fuse timeline
that we have to work with here.
Oncor, Oncor, anybody from Oncor?
man: Good morning. Yes.
-: Good morning.
EECRF, can you describe the mechanics
of how this would fit into EECRF
or at least the framework of EECRF?
Should we go down that road?
-: Certainly.
Yes, I am Garry Jones.
I'm the Director of Energy Efficiency for Oncor.
(clears throat) Excuse me.
This program is treated
just like any other program
in the energy efficiency portfolio.
Our intent will manage this
under our current commercial load management program
that we run in the summertime.
So we'll recover it through EECR
just like we would do with any other program.
-: [Jimmy Glotfelty ] So the overlay
is simply to apply it for winter?
-: That's correct.
-: [Jimmy Glotfelty ] Yeah.
And so ERCOT is accustomed to how to account
for that as well, is that accurate?
Garry: That is.
-: And so for the purposes of ERCOT load management,
we have a framework from an operational control perspective
to use it.
-: That's correct, we have a memorandum of understanding
with ERCOT and we do need to modify that
to accommodate for the winter,
but we'll make adjustments to it.
Glotfelt: Okay.
-: Can I ask how you all envision retail providers
being a part of this,
or are they not part of this?
Are you all going directly
to these entities that are in your business
that you don't actually sell electricity
but you provide transmission service
or distribution service to,
and trying to get them to curtail load?
I'm just trying to figure out
because the retail market, we want this to happen
and I would like to see it in the retail market
as a demand function that impacts wholesale rates
across the entire board.
So I get a little fearful when I don't understand
the program, if it's just the transmission owner going,
and again, this is a bigger issue in EECRF
when we talk about that,
but can you all give me an understanding
of how you all envision going
to get this load that you seek to pay to reduce?
-: Stacy Whitehurst for TNMP.
So we do contact the end-use customer
if we have the contact information,
but a lot of it does come from aggregators
that maybe go and have customers
in our service territory, CenterPoints territory,
and AEP surcharge.
So there's a combination of certain customer classes
that we'd be enrolling.
So it's a combination of both outreach of customers
that have participated in our program,
in the past and then aggregators.
-: Build on that, Jimmy, and the interaction
with the wholesale market.
How did y'all decide on the prices you set per kilowatt?
-: Commissioner, for CenterPoint energy,
and just to answer your question
much of our this winter intermodal management program
is based on what has been historically successful
for our summer energy efficiency program.
So everything from the program design
was somebody wants to even the pricing,
which for us is $30 a KW.
We use that same model.
It's been effective for us in that summer program
in garnering participation in to hit our goals
while at the same time being cost-effective.
So we really just use the same.
-: Historic pricing wasn't just correct
not new analysis.
-: We did not modify that for more where we had been recently
with our existing load management activity.
-: Are any of you extrapolated,
I guess, depending on the program,
each of you have different time constraints, is that fair?
Like each customer can only be cartel so many times
for no more than a certain number of hours.
Is that generally accurate?
Have you all looked at the,
or extrapolated the equivalent megawatt per hour price,
if all of those hours were utilized
and essentially to manage load shed,
or demand response by taking load off
of the reducing that demand?
-: Yeah, Commissioner, I don't have that information for you.
So no, we have not.
-: Okay, per Jimmy's point about
how this interacts with the wholesale market
and that impact.
I'm curious what the equivalent megawatt-
-: Value.
-: Value versus somebody who's just participating
in normal demand response in the real-time market.
-: It started at EEA2, correct?
Still, I mean, this is an EEA2 threshold,
so we are at high cap,
no matter what at the threshold.
-: Okay, I mean, so what y'all were doing $30 a kilowatt?
-: At $40.
-: $40, so how many dollars per megawatt?
(Commissioners laughing)
-: As he rose.
-: Yeah, someone do that math for me?
-: Regulatory, guys, come on.
-: It'd be $3,000 a megawatt for us,
I think that's 4,000.
-: Okay, $4,000 a megawatt, 30 times.
Okay.
-: We have 300 times for.
-: 300?
-: Right.
I mean, cause isn't that what they're proposing
a 300 megawatt, correct Kayla?
-: All right. -: So, okay.
So those are expensive megawatts, but at high cap.
Okay, and how many hours?
-: So for our program, we committed to a six curtailments,
two tests curtailments ranging
between one to three hours
and four unscheduled curtailments
ranging between one to four hours.
-: Thank you.
-: So I have a question
'cause I've been curious about these programs
as they are enshrined in SB 3 ,
when the legislature added this provision to SB 3
and I'm assuming they had conversations with the utilities
and I'm wondering why EEA2 was selected.
'Cause we are trying to move all of our tools
out of the emergency toolkit like we have for ERS
and the TDU distribution voltage reduction program.
And this is a conversation for later forum,
but if we were to open up
the TDU energy efficiency load manager program rule
25181, which I have supported doing so
either we'll have the opportunity
to move some of these programs outside of emergency.
But this particular program,
this particular winter program is statutorily tied to EEA2
can someone elaborate for me how we got here?
Or just give me a little bit of background
as to why ultimately, I mean, you didn't pass this bill,
but I'm assuming you had conversations with the legislature.
-: Commissioner, I, myself didn't have conversations
with the legislature.
I don't have much visibility
into the SB 3 sausage making on that.
-: Right, and I wouldn't suspect you would
'cause you're an attorney, you're not a lobbyist,
but I guess I'm trying to understand,
the value of having it at EEA2.
And we're trying to move everything out, obviously.
-: I think that's some statue.
-: Yeah, it's a statue.
-: Is it possible that our TDSP load management program
in substantive rule is that EEA2 right now?
So was it designed to be consistent with that
in terms of the mechanics?
-: I think the current summer load management program
is called by our current EEA2
and so I think that's probably why,
'cause we were trying to keep them
consistent between the two.
Glotfelty: So big rocks of load management on your part?
-: Makes sense.
So we'll have the ability to adjust that in our role,
but this is obviously statutorily and shrine.
I'm just trying to understand it a little bit more
when I saw it in SB 3, I honestly thought it might be
a good positive movement in the right direction
to try to get some winter activity
on the load management program.
But I'm just trying to understand the background on it.
-: Can I ask staff a question?
-: Absolutely.
-: And the question would be,
did you all look into how this played with the EECRF
or did you look at it as just a standalone program
that while authorized by the legislature
it met the statutory construction of that?
-: Okay, well, Oncors is different from the rest
because they're trying to do it within the EECRF.
Tarrus ERS PEC.
So Oncor is different.
It will operate within,
and it will also address some of the issues
that have been raised regarding participation by the reps.
So they're required by the rule,
by the EECRF rule to include reps as far as participants.
So Oncor we'll do that and we'll address that.
We did look at Oncor's program
because it's part of the energy
efficiency cost recovery overall program
and it did fit within a pilot.
And what we did is we sent it out to our EIP listserv
and we also filed it in a project for stakeholder comment.
So we followed the process for an existing program
that is now offering a pilot program.
So the other programs were offered outside
of the utilities load management program.
And they're not doing it according to the EECRF rule,
but it's very similar, is what I would say.
-: Thank you.
-: Questions, comments?
So just a perspective that I'm coming from this.
And I know this, Mr. Chairman, you shared
this viewpoint that whatever we do before this winter,
we want it to be useful
to that command and control capability
of the ERCOT control room
and to know how it's going to interact
and to know what they're going to expect.
And so for your purposes, managing all this,
we don't want the procedures to be necessarily
shoot from the hip.
This needs to be kind of tried and true
performance measures and EECRF is that.
so it's a kin to it.
It seems to be designed very much like it.
So as I view this, I see it as an augmentation to that.
-: Yes, we certainly want more resources this winter.
The big question I've got remaining
is if approval is granted,
what is the time to implementation for staff
because there are a lot of questions today.
And I would certainly default on the side of caution
on something, as you pointed out, Jimmy, that is moving
so, so quickly with big sums of money.
I'd certainly want to default
on the side of caution before we dive in head first,
but we've got to balance that with the need for the winter.
So for all of you,
what is time to implementation if approval is granted?
-: Robert Cavazos with AEP, Texas.
The timeline is still December 1st
through the end of February 28th.
-: So how long, if we tabled this
to get more information and be able
to crunch the numbers a little bit more
until, say, our December 2nd meeting,
would you still be able to implement it and say-
-: A month.
-: 15 days after that, or the 12 days?
-: Would certainly think we could.
-: Okay, so-
-: Well, I mean the thing that, again,
that kind of gets to me is the range of megawatts
we're talking about.
I mean, if this was a one and a half megawatt program
for TNMP, 10 for AEP and 20 for CenterPoint,
it seems like it's pretty reasonable.
It's 100 to 300 megawatts.
That's where I struggle.
Are they going to be able to get it?
I know that they're in an area
that has a lot of large commercial and industrial.
I feel like the cost could be exorbitant
and I what you said is maybe we should defer
this until the December 2nd rule,
we've only given them 12 days now.
So they started at the 15th of December.
They may be able to get those megawatts,
but we would get more information
about how it would impact the EECRF program,
how it would impact the wholesale market and ERCOT,
how the reps might play into this and such.
-: No, I agree.
And I would almost add
that waiting until December 2nd seems prudent
or matter of due diligence,
just so we can further examine this, get more information,
but I mean, as long as this program is up and running
and we ultimately decided to move forward by January 1st,
I think we're going to be okay
because, I mean, the true winter
typically this in January and February.
So I don't want to feel rushed
to get something in place December one,
because that's the first day of winter,
I think we got to do our due diligence
and get the information to feel comfortable.
And I would think January 1, would be just fine.
-: Commissioners, to the extent
that you need additional information or analysis,
we'd be happy to provide it.
And to the extent that you want to push this
to December 2nd, we can make that work.
-: I appreciate that.
I'll build on my previous statement, their question,
we would love from each of y'all analysis
on the megawatt hour equivalent.
So we can see what just normal demand response
in the real-time market that we usually see would be,
and also compare it to other premium
other price points in ERS, or example.
I know we don't have those bids back in,
but that'd be good to be able to see apples to apples
and how it would both on quantity and a price point
and how it would interact
with other demand response programs
and also the real-time market
under these kinds of circumstances.
Any other specific requests for either staff or the parties.
-: Chairman, just briefly, a rusting table
on our behalf staff.
We're happy to go back and try to put some more guardrails
on this and answer those questions
that you all you all raised today.
In the meantime, in that period,
we would like authorization from you all to go ahead
and start working with ERCOT
on how these programs will be dispatched
so that when they are ultimately approved,
if they are, we're ready to go on that day.
Peter: That certainly makes sense to me.
-: Yes, sir.
-: Rebecca is our law square Commission staff.
I think they're not a party to this case,
but ERCOT may have some information on that calculation
comparing these programs
and historic budget they're requesting
to the ERS project and per megawatt per hour calculation,
which I think would be the equivalent,
which varies highly with ERS depending
on the time of day those hours are, and this is more flat.
So they might be able to provide
more information in filing on that.
-: 'Cause at the end of the day,
we do not want ERS cannibalized.
We want people signing up for ERS
'cause we can use that.
-: And that's more valuable to our reliability
with thorough actions we've taken recently earlier.
-: And the economics would have changed
with the changes in the ERS.
-: Exactly.
-: So I think with that, can we ask ERCOT
to file some analysis on that in this docket,
as soon as they're able to do that kind of
quick and dirty math.
And like everybody's comfortable with granting authority
to engage with ERCOT on dispatch mechanics,
any other requests for our parties
or to use for information when to ask
for a proposal for a hard cap
or some sort of way to make sure we have upper end.
-: Yes, sir.
I'd like some side of a type of engage with parties,
you've already been in the discussions,
but what a budget would look like on this,
for our perspective,
as we calculate what this pilot program
is going to look like system wise.
-: Good point, and I think I'm engaging with parties.
I think at least some of the filings
I was thumbing through a while ago, I know Arm
and TCPA came in kind of late in the process
and just to kind of make sure everybody seemed up on that.
I know it was a quick turnaround would be helpful.
-: All right, any questions or clarifying questions
on what Commission needs?
-: Yes, sir.
With regard to Oncor's program under the EECRF,
would you like us to wait until January 1st
to begin implementation of it
or can we go ahead and begin implementation December?
-: Let's wait for the consideration
with the rest of them at the December 2nd meeting
and by no means I think Commissioner Cobos
is saying that the critical part of the winter
doesn't start until January 1st
or I guess the winter season, technically,
usually December 20th, December.
I think her point is that a week or two delay
won't have a significant impact on reliability.
I don't think she intends
to specifically delay it implementation
to January 1st.
I think I'm guessing, yeah.
Generally, if we give her approval
the sooner the better,
but let's wait till the December 2nd meeting
for the Commission to give a yay or nay at that point.
I think all of us, if it is an approval,
we would all encourage implementation as soon as possible.
-: Chairman, just briefly, just for clarification,
you mentioned having a budget.
I think the way the programs are now
there's an estimated budget.
Would you prefer to see a hard cap?
-: I would say I would prefer
to see a consensus driven cap
on what the universe of expensive rate payers.
-: Thank you.
All right, I think that's all we've got for y'all.
I have a couple other parties that would like to approach.
Thank you all very much.
Commission staff can hang out for a minute would be great.
-: Morning, Commissioners,
Andreas Mitrano for Texas competitive power advocates.
We've intervened this case,
I don't want to into technicalities.
This case was very accelerated
and we got it in as soon as we were aware of the issues
that were being discussed here,
and we have some serious concerns about the implementation.
Certainly TCPA is not trying to stand
in the way of any program that could add megawatts
in the winter at all,
simply that we have an energy market.
It's very sensitive,
we've seen that the implications
of that throughout this year from three days in February,
four days in February.
And we want to make sure that any program
is fully incorporated into the market
and operated by ERCOT with market principles
and keeping the market impacts in mind
so that we don't have a piecemeal approach
that uses this program as a band-aid
but then it has a cascading effect
of having a worse impact on disincentivizing investment
in resource adequacy, further down the line.
And our ask is very simple.
We simply are asking
that ERCOT ensure that this program be incorporated
into wholesale price formation
that in all the joint TDUs will provide ERCOT
with the information they need to account for this program
and that this be implemented operationally
in accordance with NPRR 1006, which was approved in 2020,
which directed the TDU load response programs
be incorporated into the ORDC
and the other reserve pricing capacities at ERCOT.
And simply, we just want
to make sure it's accounted for
so that if there are pricing impacts of this,
that it not dis-incentivized generation
or other normal processes through the market.
And I'm a little concerned about
the prices that we're talking about here.
I mean, they're talking about 30 or $40 a kilowatt
that's tremendously above the value of loss load
in the market cap.
And so you're having a vastly disproportionate impact
even though the relatively small number of megawatts,
the proportion of the impact of that could be very great.
And again, we're not trying
to stand in the way of this program.
We just want to make sure it's accounted for
in the wholesale process.
And unfortunately we've had difficulty
getting response from the TDUs
on incorporating this concern,
but it seems like it's not that big of an ask
simply to have this accounted for.
-: Yeah, so as soon as Mr Madrano intervened,
I got on a phone call with him, shot him an email,
sent him some follow up emails, radio silence on his part.
We received TCPA's red lines, Monday 5:44.
We sent a response back to him yesterday in the morning.
So I want to clear that misconception right now.
-: Thank you.
I certainly appreciate your points
about maintaining market operations
and market principles throughout.
And I think that that sentiment has been expressed up here
and between now and our next meeting,
I think all of us will expect all of the related parties
to continue those discussions
and move towards what Commissioner McAdams
nicely said as a consensus agreement
on how best to integrate these demands response programs
with current market operations at ERCOT.
-: Thank you, sir.
-: Rebecca Zara for Commission staff.
I think the issue with the MTRR
Mr. Madrano referenced 1006,
it was approved in 2020 following information
about ERS recall after it was deployed
in the summer of 2019, and that is still in the queue,
and it's not a project that's been started ERCOT.
I don't want to speak for them,
but I think the operational ability for them to implement
that before this program would be available for winter
and 2022 is not a possibility.
-: Thank you.
And I appreciate that clarification.
And as between now and our next meeting,
as the Commission staff also work with the relevant parties
to given those constraints,
come up with the closest we can get
to a viable balance between the demand response
we need for this winter,
while integrating within existing constraints at ERCOT
again, in inconsistency with our market principles.
-: Certainly, just briefly, Rashid Water for staff.
We do think it will be valuable to have ERCOT's input
on this request and how that would impact those things.
So as part of the other information,
that job ordered them to provide,
we think this would be a good addition to that.
-: We'll ask ERCOT to add
that request from south to the report on pricing
and the interrelated market dynamics
between those both on price point
between the ERS
and the existing energy efficiency program.
And this proposal, Commissioner Cobos.
-: And I would add that in ERCOT's feedback to us,
that they address any constraints,
why they're having the constraints
and what potential constraints we may face
with respect to take into consideration
the impact of load programs on price.
These are important matters that we need
to have done out there
and I'd like to better understand
what the constraints are and why.
-: Well put.
-: Yeah, it's just a case of appointments, Mr Chairman,
you've scheduled it well,
all roads lead to December 2nd,
because again, high cap has to be formalized
as of December 2nd as well.
So that'll give us a ballpark figure for Mr. Mcdonald
like what is going to be the value
of power at that point, EEA2.
So at least we'll have that visibility
and it's going to be a bit of a matter
of structuring the workshop versus the open meeting
and when and where all these things come together.
But yeah, December 2nd.
-: Record our food.
-: Yep.
-: Commissioners, Kelly Kayla Brown
for the Alliance for Retail Markets.
And just a couple of clarifications.
And we also intervened
after we saw the additional information filed
by the TDUs in this proceeding
and we had lots of discussions with them,
and I think we've got some general agreement on the items
that we'd like to see added to their programs.
The first one is to allow retailers to providers
to be project sponsors.
We think that's an efficient way,
especially given the speed
with which we would like to get this implemented.
And that's consistent with the Oncor program
that includes retail as providers, as project sponsors.
The second is about a gap that was identified in February,
which is we would like the TDUs
to notify the retail rep of record
when that reps customers enroll
in the TDU load response program,
especially as one of the TDUs pointed out
that this program is a little bit different
than their other EECRF programs,
where transmission level customers
can participate in this one,
it could involve large swings of power
that the reps were responsible
for scheduling being curtailed.
And so if they have a heads up that their customers
are enrolled in this program.
And then working out some sort of
after the fact notification to the reps,
when those customers are curtailed.
And you talked about ERCOT,
there might be a way for ERCOT to provide that information
and we're open to figuring that out.
But talking with my members,
they spent a lot of time kind of tracking that down
after the fact
and if there's just some way to notify the reps
since they are the customer,
they're the interface with the market for those customers.
We definitely appreciate the discussion
about adding a hard cap, a budget.
We think that's important.
And one of the things that we'd identified
was, TNP and AEP, Texas proposed budgets in this proceeding
and we've asked that CenterPoint, do the same thing.
And then the AEP Texas budget as filed was set at $650,000.
I understand that from AEP, Texas,
that that needs to be corrected to $350,000.
And again, lawyer doing math here,
but just wanted to also clarify that the payment amounts
will be somewhere between 30,000
and 40,000 per megawatt hour.
Peter: There's a lot of fuzzy math,
which is why I asked you-
-: Not 3000 to 4,000.
So it is when he said, it's magnitudes
above what the high cap is.
-: That's exactly why I wanted
and asked him to put it on paper.
Like there was a whole sequence of people
that got that math wrong, thank you.
(Commissioners laughing)
Scott: Commissioner.
-: Yes.
-: Didn't mean to interrupt, sorry,
Scott Seamster, with TNMP.
With regard to notice,
I think one of the issues of just
to calibrate from the utility standpoint,
providing notice of enrollment
has typically been considered
proprietary confidential information under 25272.
And the problem being is that it's a choice to the customer
to contract directly with TDU
and therefore, since there's no other interaction
with the rep,
we've kept that information separate.
And I mean, we've been running these programs
for decades and not provided that notice.
I understand that ERCOT,
doesn't provide the subscription list for ERS either.
So that confidential issue would need to be addressed.
As far as curtailment,
we understand that ERCOT does issue directive
when it would draw down and pardon me,
and with regard to our programs,
however, we're allowing ERCOT to make that direction.
And therefore we would think
that it would be able to make a notification,
but having their involvement on that point,
as far as notifying winter curtailment occurred
and getting that to the reps seems
that it would come from ERCOT.
-: Okay, thank you for bringing those issues.
Yes, Ma'am.
-: One response about the rule that Mr. Seamster mentioned.
So 25272 G1 A provides a specific exception
to that proprietary customer formation rule,
where if the PUC puts in an order telling the TDUs
to share that information with the rep of record,
it's consistent with the rule.
-: Okay, well, this is another thing
that I hope y'all will both work with staff
on to either recognize existing precedent
or find a way to accommodate the needs
under this new proposal.
-: I would say, just because it used to be the way
it doesn't mean it's the right way going forward
with the market.
-: Took the words right out of my mouth, Jimmy.
We should all say that three times every day,
(Commissioners laughing)
just because we used to do it that way
doesn't mean that we need to keep doing it that way.
All right, anything else on this item?
All right, we can table it for the next meeting.
Do we need a motion to grant authority?
All right, we'll direct staff to work with ERCOT
on the dispatch mechanics.
Thank you all very much.
-: Thank you.
-: Alright, we've got a couple of minutes left
before our lunch break.
-: I think we can probably get through.
-: Yeah, we're gonna knock out a couple,
item number 14, please sir.
-: So Item 14, we have a report on utility earnings.
-: Appreciate staff work on this.
I don't have any particular comments or thoughts,
but open the floor for comments, if you do.
-: I don't have any comments. -: All right.
-: No comment. -: All right.
I don't think there's any formal action on that.
I don't have anything for items 15 through 21
and 22 Commissioner Cobos,
you have an update on this docket?
-: Yes, I just wanted to know
that pursuant to our order in project number 52682
on October 14th,
the TSPs that we'll be constructing the San Miguel
to Palmetto double-circuit line
in the closed loop facilities,
which include Stack, ETT, AEP Texas, and Cherryland
have filed their first quarterly update on November 1st
and it provided us with the charts
of where they are with their projects at this time.
I know they're incrementally starting their work
with respect to the second circuit
and I know that Cherryland's getting ready
to start working on their CCN
and expects to comply with our order
to file it no later than June 30th.
So things are kind of, bubbling up
and getting going to degree
so far of what I've seen from the progress reports
it doesn't appear to be,
I think at least ETT noted that there could be,
potential supply chain issues,
but I don't think they've actually noted
any specific ones yet and have this deck.
So things are moving along.
I wanted to add this here
because also it kind of correlates
with our discussion in the stack case earlier
with respect to item number four,
where we decided when a CCN application is needed,
just to remind you that we have Stack, ETT and Cherryland
all constructed the first single circuit
from Simon Gilda, Palmetto,
and based on our review of those,
well, first of all, let me backtrack,
in that project, we had asked the parties
that the Stack, ETT and Cherryland
to let us know whether or not they thought
that they needed a CCN amendment
and just to see what their basis was.
And so their basis was that the prior CCN in order
had granted him the second circuit, I believe.
So based on our review of the information
that was submitted by the utilities
at the time in this project
and our decision in the stack case on the threshold issue,
that these companies Stack, ETT and Cherryland
would not have to file a CCN for the second circuit,
but of course, Cherryland hall and AEP Texas
will have to file a CCN
for the new closed loop transmission facilities.
So that's how it dovetails into this project
but I just wanted to note that for you.
And then also the parties in this project requested
that the Commission enter a standard protective order
to protect confidential information,
that they may be required to provide us
as they continue to provide us quarterly updates.
And I have been visiting with Steven
and I think notified docket management.
-: I learned the chief judge yesterday of that request.
And so it should be worked on.
-: Okay.
And that is all I have for this project.
-: Thank you for the update.
That was a major, major initiative and a big step forward.
That brings us to item 23.
-: Yeah before you have proposal
for publication of this rule.
Peter: Is there a standard for your review?
-: Yes, sir.
Peter: Any questions, comments, or a motion
to approve the proposal for publication?
Glotfelty: So moved.
Cobos: Second.
-: All in favor, say aye.
All: Aye.
Peter: None opposed motion passes.
It brings us to item 25.
I know you've got an update here.
Cobos: I do.
I was at the November board meeting
for the Entergy regional state committee.
I was named the vice president of board.
And so I just wanted to let you all know.
Jimmy: Congratulations.
Cobos: See what I'm getting myself into here, but.
-: [Jimmy Glotfelty ] Real easy
and is talking about succeeding so.
Cobos: Well that that's actually been
a topic of conversation here in Texas
so it won't be anything that we haven't heard of before.
So I can, trade some notes with them
and tell them how to serve themselves on that.
But just want to let y'all know,
as I may be bringing you updates in the future on that.
Peter: Look forward to that, congratulations
and thank you because I know how much free time do you have.
So I appreciate you taking that on.
I don't have anything for item 26 through 29.
That'll bring us to the water segment of our program today.
I know you've got a memo on this item.
Is that something I'll you put the memo out on this.
Do you want to move forward with it now?
Or just break for lunch?
Now we can start with water?
-: [Jimmy Glotfelty ] I think it's simple unless
it becomes more in depth so we could label it
and then bring it back up.
But the memo, Mr. Chairman was good.
-: Call it item 30, sir.
Peter: Item 30 please, Mr. Jeanette would lay that out.
-: Item 30 is the dock at 49351,
it's a rate payer appeal
of a bear said, rate changes.
Commission issued an order on September 29th
motion for rehearing was filed on October 22nd.
Then it's noted.
Commissioner McAdams has a memo.
-: As I was about to discuss,
the memo was intended to clean up the order
and allow parties to know
what needed to be refunded and where.
So it's a procedural cleanup, initiative on my part.
I hope it is well taken.
I think it'll do some good standby for any questions.
-: Yeah, but thank you for tackling that very much needed.
Appreciate, pretty sure on that.
I agree with everything you put in there.
And certainly think that we've got a clear direction
to order the re-hearing.
Any other thoughts, comments, questions?
-: I agree with Commissioner McAdam's memo.
-: Yeah, all right?
-: Fabulous memo.
(Commissioners laughing)
-: All right, in that case,
is there a motion to grant the motion for rehearing
to the extent provided in Commissioner guidance memo
and modify the order in accordance importantly
with that memo?
-: So moved.
-: Second,
-: All in favor, say aye.
All: Aye.
-: None opposed, motion passes.
Brings us to item number 31.
I think that should be pretty straight forward.
Mr. Jeanette will lay that out for us.
-: Item 31 is docket 51224.
It's the complaint of John Blaylock
against Mercy Water supply Corp.
There's a PFD issues on September 30th, no exceptions.
I mean, except since the replies were filed,
the ALJ filed a memo with suggesting no changes to the PFD.
I have a memo with proposed changes.
Peter: I think the PFD is pretty straightforward here.
You got to provide evidence to move forward and the other.
Cobos: Agreed.
Peter: All right, is there a motion
to adopt the proposal for decision as modified
by Commission counsel's November 17 memo?
-: [Jimmy Glotfelty ] So moved.
McAdams: Second.
Peter: All in favor, say aye.
All: Aye.
Peter: None opposed, the motion passes.
That moves us onto item 34.
I don't have anything there.
Item 35, Mr. Jeanette, could you lay that out for us?
-: 35 is docket 51790
it's the application of Keegan Monster
to amend its SPCOA certificate.
There is a PFD of dismissal filed on September 30th.
No exceptions or replies were filed.
-: This is another one.
I think that the PFT pretty straight forward got it right.
Go ahead in the fumbling,
but happy to hear other thoughts.
-: Definitely agree. -: Total agreement.
-: Same.
-: All right, is there a motion
to adopt the proposal for decision?
Both: So moved.
-: Second.
-: There we go.
All in favor, say aye.
All: Aye.
-: None opposed, motion passes.
That'll bring us to item number 36
and you know what that seems
we'll get to our telecommunications segment of-
-: I think we'll break there for lunch.
-: Got it.
-: Thank you all, we'll reconvene at 12:15.
All right, thank you.