(gavel bangs)
-: Good morning.
This meeting of the Public Utility Commission of Texas
will come to order to consider matters
that have been duly posted
with the Secretary of State of Texas
for October 7th, 2021.
For the record my name is Peter Lake
and with me today are Will McAdams,
Lori Cobos and Jimmy Glotfelty.
Mr. Journeay,
could you please walk us through today's Consent Agenda?
-: Good morning, Commissioners.
By individual ballot the following items
were placed on your Consent Agenda.
Six, seven, 22, 23, 25, 30, and 31.
-: Is there a motion to approve the items
just described by Mr.Journeay?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
This time we'll open the floor for public comment.
All comments related to a specific agenda item
will be heard when that item is taken up.
This public comment period is for general comments.
Speakers will be limited to three minutes each.
Do we have anyone from the public signed up to speak?
-: No one signed up on our list, sir.
-: Thank you, Mr.Journeay.
Public comment is now closed.
We will not be taking up item 14 today.
And with that, we will start
with agenda item number one, please.
-: Item one is docket 5 1 2 1 5
it's the application of Entergy
to amended it's CCN for a solar facility in Liberty County.
The Commission considered a proposal for decision
at the September 30th open meeting.
After reading the transcript,
we decided to bring this back to you
because we were unsure exactly what it was
the Commission wanted to do.
-: Apologies for the lack of clarity from the dais.
I know, I think we have a sense of,
I suspect we have a sense of where we want to go,
but just the logistics of conveying that.
No order has been issued yet,
but let's go ahead and clear up the issue.
I know there's a conversation about
if this was the right project to serve that load.
If other mechanisms have been considered,
there's an issue of the structuring of the proposed deal
and an issue of what's confidential
and what's not confidential.
Thoughts, or?
-: I'm recused.
-: Oh. -: Yeah.
-: So, anything -: I think it was
-: Happy to lead off.
So as I reviewed the, well put, Mr. Chairman,
as I reviewed this,
as you condensed down the issues,
the heart of it is the benefit test
for the consumers within the Entergy service territory.
And it gets down to
what benefit metrics are baked into that evaluation.
And that's what many of the arguments were about
before the ALJ,
but still it remains that the net benefit
as computed by the ALJ was 24 million under
the Entergy model that they're proposing for approval
versus under a PPA model,
which would be 72 million benefits,
dollars in benefit to the consumer base.
So as I looked at this,
and that was the posture I was in
going into the last open meeting was,
was agreeing with the PFD
and that we should reject that and approve the PFD.
But again, if we want to drill down
on the specifics of how that net benefit is computed,
is that where you were leaning
in terms of more information?
Because it's all about how you calculate it.
-: Well, first of all,
I agree with you and your comments,
both of you that
I think I was somewhat confused last meeting also,
on where we were going with this and where I,
where I read the docket to be and what the PFD was.
I think that the case has not been proven, quite frankly.
I think that we need to be prudent
and diligent when it comes to rate payer funds.
And there are holes in the data
as the Chairman has highlighted,
there are confidentiality issues,
there associated tax issues and such,
that I find it hard to say that this is totally prudent.
And, therefore,
I would support the order that denies the application.
-: Agreed.
And we want to modify
that order to request more information
about what's confidential, what's not confidential.
-: I think that's important.
Absolutely. -: Yes.
-: All right. So do we,
we have a motion to adopt the proposal for decision
with a modification to the order,
to order the parties
to jointly add exhibits, file exhibits,
indicating which exhibits are confidential,
and which are declassified, is there a motion?
-: So moved.
-: Is there a second?
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
You have everything you need on that Mr. Journeay?
-: Yes, sir.
-: Thank you.
Brings us to item number two.
-: Item two is docket 5 1 4 8 4.
It's a compliance following of AEP Texas
for their rider TC to refund of transition charges.
A proposed order was filed on August 27th
that would approve the refund transition charges,
no corrections or exceptions were filed.
I have a memo with proposed changes to the proposed order.
-: It seems relatively straight forward.
Any thoughts or comments?
-: Yeah, just to recapture the heart of it.
You know, the refund directly to consumers
is consistent with our rationale
and the CenterPoint case a docket number
5 1 5 6 7 that I previously filed and, you know,
I agree with the proposed order.
-: I'm supportive of that.
-: All right.
Is there a motion to approve the proposed order as modified
by Commission Council September 30 memo?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
Item number three.
-: Item three is docket 5 1 8 0 6.
It is a true up compliance filing of Entergy
concerning their scheduled TTC.
The proposed order was filed on August 4th.
That would approve revised rates
for Entergy's transition to competition tariff.
No corrections or exceptions were filed.
I have a memo with proposed changes to the order.
-: Another pretty straightforward issue.
Any questions, comments, thoughts?
-: I do have comments.
This, I see this as two issues.
One of them is the docket is solely
about truing up previous orders previous,
you know, that implement legislative directive
on how to move areas of Texas
that are not in ERCOT to competition.
And obviously respect, you know,
previous decisions of the Commission and think that
ultimately this order needs should go forward.
What troubles me is that we've spent about,
and not we, I haven't spent a dime,
but the rate payers in the Southeast
have spent a couple hundred million dollars
on a transition to competition.
And there's nothing, I believe, to show for it.
And I think originally, you know,
there were some preconditions for competition
such as open access tariffs, you know,
is there, there's a generation limit.
Some of these I believe are,
are sufficed or satisfied under the construct
that Entergy Texas is its own utility,
but it also works under the MISO system.
You know, there are other issues out there.
I haven't been to every one of the proceedings
on transition to competition for Entergy
over the last 25 years, of course.
But, you know, it seems to me that there are,
competition has been good for the rest of the state
and that if we are, you know,
going to finally reimburse Entergy for the,
for the rest of this money,
that some kind of transition ought to be re-looked at,
you know,
is there a process for stakeholders to give information?
Should we have them file here to say, yes,
we want competition in that area.
There are, again,
some of the preconditions of, you know,
open access being handled by MISO.
Anyway, I'm not being too articulate about it,
but what I want is,
I hope that if stakeholders and folks in the Southeast
and retail electric providers and, you know,
consumers want competition in that area
that they ought to tell us,
I don't think that a couple of hundred million dollars
for nothing is a good deal.
And if it moves,
if it moves us towards a competitive market in that area,
I think that would be prudent,
but I'm supportive of the true up,
but just wanted to make the comment that I think we need
to re look at this and stakeholders need to look at it
and tell us, yeah.
Is it time to move forward with competitive choice in,
in the Southeast region?
-: Well put, I think
-: So,
this argument has been,
I would echo your comments, Commissioner,
and I have written down,
I am so glad this is the last year (laughter)
of this true up.
And it just is a twist of fate
that I am one of the Commissioners that has to approve
the last year of this true up.
But that, that fact on taking ERCOT to the Sabine
has been heavily debated for decades.
And, and within the last two years,
10 years at the Legislature, they've discussed it.
The residents go back and forth.
It's a dynamic part of the state of Texas,
Southeast Texas.
It's a heavily industrialized area of the state of Texas.
It's growing fast.
URI has made people evaluate, again,
it swings back and forth,
that maybe it's not such a good thing.
You hear that from their Legislative representatives,
Senator Nichols, Senator Creighton,
that they're glad that they have Entergy.
So it does swing back and forth.
But I agree with you,
it seems like there should be a mechanism or a voice
to where if the consumers and those rate payers want to see
any type of competitive benefit in the future,
that we should provide them a venue at the PUC.
In the interludes between the legislative sessions,
where they can speak in front of
their elected representatives,
but at the end of the day,
for the purposes of this case, this is it.
This is the last, this is the last one.
I'm glad.
-: Well, yes,
that certainly does seem like, I mean,
it's a lot of money, 200 million,
and you all have raised some very important issues
that I think merit a lot of deep consideration
by the Commission that, I mean,
that's a significant change.
And so, you know,
I think my experience has been with Entergy
looking to join different ISO and RTOs,
ERCOT, SPP, MISO, currently in MISO.
And, you know,
I think one of the reasons they wanted to join MISO
was to try to garner some of the benefits
of being in an actual ISO and RTO.
And I think as a Commission, we should continue to,
to review whether that is producing the benefits
that were proffered to us by joining MISO.
And I think there's, you know, ongoing review of that.
And so from my perspective,
I'm open to hearing what you have to say.
I think that merits a lot deeper consideration,
but that is a lot of money to look into joining competition.
200 million.
And I'm happy like you Commissioner McAdams,
if this is the last round of these charges.
So I'm happy to see these going back
and I'm comfortable with the proposed order.
-: Thank you.
I think it's fair to say that this Commission
has been robust in welcoming stakeholder input
since we've been seated.
And so the bottom line is if the folks in Southeast Texas
want to have that conversation, they should let us know.
Fair?
-: Fair. -: Fair.
-: All right.
In the meantime,
we'll need to conclude this piece of business.
Is there a motion to approve the proposed order
as modified by Commission Counsel's September 30 memo?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
Item number four, please Mr. Journeay.
-: Item four is docket 5 2 0 3 4.
It's an agreed NOV concerning AEPs reliability
and continuity of service.
Commission previously considered a proposed order.
Sent it back for further information.
That was provided and the ALJ filed
a revised proposed order on August 25th,
that would approve the administrative penalties of 56,000
and the agreement.
No corrections or exceptions have been filed to that.
-: Thank you, sir.
I know this is an issue, Will,
that you've led on, filed a memo back in May.
And so I'll defer to you.
And of course,
I know Jimmy's got a lot of background in this space too.
-: Yes, sir.
I mean, just for me as a layman,
I'm trying to figure out what right looks like.
I think this is what right looks like
in terms of a file template
that could be used in the future.
It addresses everything that, Mr. Chairman,
you and I discussed in our early days in the Commission.
It's hard to believe it's already been five months,
almost six months since we
first landed here. -: Hell of a year.
-: but it addresses timelines, amounts,
feeder by feeder analysis
on when corrective action could be taken.
So as a policy, I believe, on the whole,
it drives us toward a goal
of improving system-wide reliability.
If you address these in the timeframes established
that we can see,
that the Commission can monitor moving forward,
theoretically, on a law of averages basis,
we're actually gonna make a dent
toward the better for reliability.
And that's very important in these hurricane prone areas.
And I was glad to see this.
-: Well put.
-: I would, I am not an expert on saiety and safety.
I assure you that, but I agree with
Commissioner McAdams thoughts on this,
I hope that, you know,
since we are in hurricane, well,
let me go back and just say,
satiety and safety are obviously
very staple base components of a reliable system.
Many of y'all know, that my background,
I helped lead the investigation of the 2003 blackout,
which was caused by one tree
and then a bunch of issues after that.
But, you know,
satiety and safety is truly important
and it's critical to reliability for every consumer.
And I hope that there's a time that we,
over the next,
after we get market designed done in some, you know,
we can actually look into this a little bit more
and understand it.
There are a lot of issues that deal with segmentation
and other things of critical loads
kind of down at that level that this is interconnected with.
And I just, this is so important in my opinion,
that it should take some Commission focus, but.
-: Absolutely
-: Yeah.
Well, based on the expectations
that have been set forth by Commissioner McAdams,
and you, Chairman Lake, in prior NOV cases,
I think that the company provided the necessary information
to be able to prove up their corrective action
and provide the information
that you both were expecting
in your direction prior to open meeting.
So I'm comfortable with
the question. -: Formally,
could I just take the opportunity
to formally thank AP and
the other TDSPs out there NOEs, everybody,
I mean, if you take the time to file these plans,
remediation plans,
it's a great help to the system as a whole.
And I think right now,
as we're going through redesign
and trying to stabilize ERCOT
and also maintain a reliable service throughout Texas,
these efforts, we shouldn't take them for granted.
We should thank you for that.
That's, you're doing the right thing.
-: Absolutely, job well done.
Is there a motion to approve the proposed order?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
Item number five, please, sir.
-: Item five is docket 5 2 0 7 2.
It's the application of SPS
to adjust it's energy efficiency cost recovery factor.
A proposed order was filed on the 16th.
Some changes and corrections were made thereafter,
and the LJ followed a revise,
a memo revising the proposed order on September 28th.
And I have a memo with proposed changes to the proposal.
-: Thank you, sir.
Seems relatively straightforward.
Any comments or questions?
-: Straight, straight
forward as it stands now. -: There we go.
-: Look forward to looking at these in the future.
(laughter)
-: Is there a motion to approve the proposed order
as modified by Commission counsel in September 30 memo?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
The
next item will be item number eight, nine and 10.
If ya'll are going to take those up I'll step aside.
-: Yes, sir.
-: Mr.Journeay
can you walk us through item number,
we can bring these up together.
Eight, nine, and 10. -: Sure
-: I think we only need to bring up nine.
-: Okay, great.
I'll bring up number nine.
Docket number 5 2 3 2 2.
Application of the Electrical Reliability Council of Texas
for a debt obligation order
under PURA Chapter 39 sub-Chapter N
and a request for good cause exception.
Let me know issue that you would like further clarity on
regarding our discussions last week.
Can you frame that for us?
-: Yeah, so,
so the issue we didn't address
was the one that around when an entity opts out.
Can it maintain that opt-out status or forever,
or are there,
would there be restrictions placed on that entity?
And if it undertook certain actions,
it would lose it's opt-out status.
-: So this goes to the issue of coming in and out.
So once you,
once you,
you know,
fall into the category of not opting out
and so you will avail yourself of securitization,
how hard and fast is that status?
Does that follow you through time?
And my position is, in my belief,
and I welcome. -: Excuse me, committee,
it's really focused on the ones that do opt out
and do not take.
-: Okay, correct
one way or another,
as it applies to the obligation order for entities
and affiliates that opt out, it is my belief you're out.
If you decide to stay in,
then I believe that you should be able
to change your rep classification.
You shouldn't be able to change your rep classification.
So that entity is in,
and that obligation as a part of securitization stays there
and is housed with that entity uplift charges stays there.
Now you can, of course,
in my view, form a new entity
and in the instance where you want to
serve non-affiliated customers, you should be able to,
but again, you form a new entity.
So for the purposes of the entity,
securitization stays with the entity.
What do you think.
-: Similar.
I think if you are a rep option two, and you have opted out,
you remain opted out.
However, if you change your rep certification
to another option of a rep, then,
and start serving unaffiliated customers,
then you should be charged the default charges.
You can't opt out and then turn around
and then change your rep certification and start, you know,
you're opted out and you're providing a different service.
So that's my position.
-: Go ahead, sir.
-: I was just going to say,
I hope this doesn't become an issue,
but I agree with both of you.
I mean, you can't use,
we shouldn't allow entities to get out
And then opt back in just to avoid a system issue
that everybody has born, you know,
in ERCOT and, you know,
believe again hopefully, people,
entities will not do this.
It's the obligation of everybody to work together,
to make the system work.
-: It's a matter of competitive equity I think.
And ERCOT's already looking at, you know,
sort of a broader issue of,
of a company that exits and then comes back in
that they have to be charged default charges.
So I would sort of,
kind of view the issue from that lens of
if you're going to opt out as a rep option two,
you can't later go change your rep certification
and still be considered opt out
and start providing a different business model.
And then that gives you a competitive advantage
over the other reps that are having to assess
these default charges to their customers.
So that's my position.
I think if we move in that direction,
that ERCOT should address this issue
in their protocols as well.
-: So thank you for bringing that up,
because that was going to be my kind of second leg to this,
this discussion NPR 10 67.
I urge us to consider, and I think we're there,
given the conversation,
to be consistent with what we do in this order,
with what 10 67 reflects and just for clarity,
it is my view that we would have an interest in ordering
ERCOT to adopt NPR 10 67.
I mean, just clear up the ambiguity.
Move forward with it,
and consistent with the discussion in this order.
You may not be ready to do that right now,
but I believe for the purposes of consistency and clarity
to the folks out in the audience,
to the market participants, I think it would help.
-: Absolutely.
As we look to stabilize the ERCOT market,
we need to close loopholes
for the future and prevent, you know,
entities from taking advantage of the system
and we need to maintain equity.
And so I am supportive of moving forward
in the position for option two in this case,
and continue to support ERCOT in their efforts
to ensure that companies that leave the market
don't come back in and not be subject to default charges.
-: Okay.
Now I'm going to ask you for the sake of clarity.
Repeat to me what you think you heard.
(laughter)
-: Thank you, sir.
(laughter)
If you are an option two rep, and you opt out
and you want to change your service method
so that you're serving additional customers,
you have to form a new entity,
come back into the market as a new entity
and as a new entity,
you will be assessed uplift charges.
-: I agree with that.
-: I do, too.
-: Ditto.
-: Okay.
Do we need to cover anything else?
Do we need to make a formal vote on this?
Do you have your instructions consistent with the
conversation that just happened?
-: I do,
and then we'll add language into the order
that we're working on daily.
I hope that we can get something out.
My hope is by tomorrow
so that the parties have an opportunity to look at it,
and see what I screwed up
so we can get it fixed for next week.
-: Okay.
The order for the ERCOT little
is likely not to come out tomorrow
because of personnel issues.
Hopefully, first thing Monday,
it will come out and let the parties look at that.
-: That works for me.
All right. Great.
Thank you, Steven.
-: So do you think we need to order to the NPRR?
So the question of procedure,
the Chair has not recused himself
from consideration of that.
Would we welcome him back on any type of consideration NPRR?
And should we do that at the next open meeting
as a formal order?
-: I think it's a directive.
-: I mean, it's ERCOTs heard you
that they like what you're doing.
It's seems a little off kilter to me
to order ERCOT to adopt a protocol
that's in the process and may have revisions to it.
It ultimately will be presented
to the Commission for approval.
-: True.
-: after the board acts on it.
-: So I'm looking at ERCOT and they have heard us.
Our high level policy is understandable,
and the objective is consistency
with the securitization financing order.
So I'm willing to let it stand at that
and let that NPRR proceed at pace.
But I think you've got three out of four
and we're saying it's important.
-: You'd think that I would know the order better
having been (chuckle)
reading it for so many days.
I know there's a provision about ordering them
to adopt protocols.
I know one of those is related
to the uplift charge mechanism.
-: Right.
-: It's not clear in my head right now,
whether there's other languages in there
to deal with protocol,
to adopt protocols related to entities
leaving the market,
a general statement that they should adopt a protocol.
And certainly if that's not in there,
we could add that language.
-: I think that's a good idea.
And we might've touched on it in our prior open meeting
when we discussed this case to just include, you know,
in that order instructions to ERCOT to address that issue
and create new protocols,
which they're already in the process of doing,
just to solidify that we are giving direction on that issue.
As I think I also provided feedback
on the terminated competitive wholesale market participants
that they would still owe ERCOT.
I think this just maintains a consistency with the order
as to what our expectations are
for terminated competitive wholesale market participants,
and also for competitive wholesale market participants
that leave the market and come back in
and what the expectations are.
So I think that just creates consistency in the order
for you to insert that language in there.
-: As currently drafted the,
that language is actually much broader
and just applies to all market participants
that owe money to ERCOT, -: Sure.
-: whether they're in or out, or leave and come back,
or whatever.
You owe money, you owe money.
-: Okay.
-: I like that.
I like it broad. -: Yes
Yes I, yes.
We'll review your order,
but I think that's the right approach.
-: Okay.
Before we mess anything up, I'm going to leave it there.
(laughter)
All right, Mr. Chairman, we're out of this.
-: Did I miss something?
(laughter)
-: We missed your leadership.
(laughter)
We tried to get you back into this thing somehow.
-: We like you, too.
-: All right.
I don't have anything on item 11 or 12.
Do ya'll?
-: No, sir.
-: All right.
That'll bring us to item number 13.
-: Item 13 is project 52 3 0 7.
It's a project to review the rules adopted by ERCOT.
Commission staff filed a memorandum
and a proposed order recommending approval
of two notable operating guide revision requests
and one retail market guide revision request.
-: All right.
Any comments or questions for staff, or are we ready,
happy to approve the proposed order?
-: I would approve, yes sir.
-: Approve.
-: All right.
Is there a motion to approve the proposed order?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
Not taking up item 14 today.
I don't have anything for 15.
You all?
-: No.
-: All right.
Item number 16.
Staff has filed a proposal for publication
related to our scarcity pricing rule.
At this point, we'll call up Mr. Smelter
to provide some background and we'll,
you've taken a lead on this.
So we'll look forward to your
thoughts and comments -: Hello, Commissioners.
-: David Smelter for Commission staff.
I think our instructions
from last meeting were pretty clear.
You wanted us to strike through a nine
and put in a 4.5 and that's what we did.
And that's with regard
to the price of the high system-wide offer cap,
which is the system-wide offer cap
that is in effect most of the time,
it's not been in effect since URI,
but will come back into effect starting January.
We also filed some briefing questions
that were due on the 30th
that provided a little bit of context
on what parties thought about that.
I know that some of you had a chance to look at that.
So the proposal publication is ready to be published,
if that is the will of the Commission.
-: Thank you, sir.
Comments, questions?
-: He accurately captured my request
(laughter)
and I try to be simple about those things.
So I look forward to comments
coming back from stakeholders on this one.
-: Likewise.
I will say,
or I will remind our stakeholders that this is an action
driven by the January 1 reset from low cap to high cap.
And this by no means is the only action that we will take
regarding the ERCOT market design or structure.
This is not happening in a vacuum.
We will be considering,
as we have discussed all summer
throughout multiple work sessions and comments,
we will be considering changes to ORDCE the MCL, et cetera.
So I just want to remind our stakeholders.
This is not the only adjustment.
This is a timeline driven change.
Is there a motion to approve the proposal for publication
for comment?
-: So moved.
-: Second.
-: All in favor, say aye.
Members: Aye.
-: Motion passes.
Thank you, Commissioners.
Thank you, Mr. Smelter.
I don't have anything for 17, 18 or 19.
You all?
-: No, sir.
-: Item 20 is our update from ERCOT.
Got several topics to cover here,
but we'll start with summer update from Kenan,
and a maintenance update from Dan.
Gentlemen, please come on up.
And if you will state your names,
and who you're with for the record.
-: Okay.
I think I'll start.
I'm an Dan Whitman within ERCOT.
I think you can summarize Summer operations
this summer as being cooler than normal,
wetter than normal,
less windy than normal, and more conservative.
And so I'll go through a few slides with you
with more detail than that. -: Well put.
The weather the summer, like I said,
was mild across most of the state,
generally cooler, rainier,
particularly in the first three months of the summer,
the average daily temperatures were one to two degrees
over the kind of,
on the average cooler than normal conditions.
In the graph on the top of the slide one, there,
you can see that there were no periods
with widespread temperatures well above a hundred degrees,
which is what we typically have,
a few of those during the summer.
We did not this summer,
in spite of this lack of typical hot periods,
we did set new monthly peak records
for both June and September.
The annual peak for the year 73,475 megawatts
was well below the forecasted peak for the summer
of 77,000 some odd megawatts because of that lack of,
kind of really hot weather.
On slide two you can see
that it was generally less windy this summer
than any of the last several years.
The graph shows, kind of your wind output
and it's normalized for the amount of capacity.
Cause the amount of capacity has been going up.
As you can see that this year, over most hours,
the wind was actually less than what it had been
the last several years.
Solar generation was higher.
-: Can I ask you a question about that?
-: Yes, sir.
-: Was that in all regions,
or was that specifically driven
by a panhandle, West Texas, or a coastal issue?
-: I don't have that in front of me.
My recollection is it was kind of widespread.
We didn't see on some lot of days,
we didn't see the kind of coastal going up
the way we have in previous summers.
And then it was also low
in kind of the more westward regions.
Solar generation was higher across the whole summer
because pretty much every day,
because we had significantly more
installed capacity upsell.
We did see new wind and solar instantaneous output
records during the course of the summer
with over 23,500 megawatts of wind back in June.
And then solar got up about 7,000 megawatts several times,
but the peak was 7,036 megawatts in first part of August.
Moving to slide three.
Thermal generation outages were generally lower
during the summer when we got up to the highest net load.
So when you had high load and low wind,
the thermal outages were significantly lower,
less than six megawatts.
There were days that they got up higher than that,
but it was usually on a,
either cooler day or a day with more wind.
And so it didn't cause any problems.
-: Can I say something here as well?
-: Sure.
-: I'm sorry to interrupt,
but this was an area that I had spoken with Brad about
the other day, and Christie.
When I was reviewing the thermal generation
unplanned outages,
it seemed like an inordinate number of those outages,
the cause was either unknown or other.
And to me that doesn't give us
a good understanding of what the issue is, you know.
Are there more systemic issues
where certain types of plants?
Are they, and it doesn't,
it doesn't matter what the issue is.
It's just trying to have a better understanding
of what those outages are and why they are happening.
Might give us a better indication of duration
and other things.
So I'd love to have the discussion with you all
in the future about how we re-categorize
or expand the categories
from unknown and other to things that are a bit more
informative to the Commission and to the consumers
and to the market as a whole.
-: Makes sense.
We actually haven't notable protocol revision requests.
That's going to be going in sometime in the next few weeks,
that will among things, allow us to,
There's this particular field that the generators,
when they have an outage,
they enter that data into, it's a dropdown box.
Gonna expand that dropdown box
where there are more options.
And also that dropdown, that data can't be updated
after the original entry of the outages.
There are other fields that
where they can tell us what's going on
in kind of nauseous detail,
but that particular one, you can't update it.
And so, part of that will be doing a project
so that it can be updated
so they can enter the outages early.
And if they don't know what's going on,
they can say that.
But then later,
once they have done more evaluation
and know what's going on,
they can update that field to let us
know the -: I think that's a good thing.
-: and then we can post for public purposes, the right,
the correct reasons.
-: Thank you.
-: Yeah. Just for the layman and the general public,
but the moment it breaks, we don't always know
what broke. -: Correct.
-: And, but you're making the ERCOT is making the adjustment.
And that's why it says unknown at first, later on,
you're making the adjustments.
So once they've gotten under the hood
and figure out what broke,
then they can record it.
-: Absolutely.
And they would be required to come back and do so.
-: Yes, they would be required to report what broke.
Thank you.
-: We've included the graph on the lower left hand corner
of slide three there for the last several years.
And what it does is look at certain key variables,
the load, the wind,
the solar, and the thermal unit outages
at different days of the year,
particularly at the time of the new June peak
at the time of the new September peak
at the time of the annual peak.
And then also kind of that tight day in June that we had,
and you can kind of see the,
how those different variables varied
across those different days
and compare them to the peak peak time last year.
And so I don't really have anything
I specifically want to point out on that graph,
but we're providing it because we have it each year
and it's,
there's some continuity there that's important.
The final thing I want to note this,
for this summer is that we did operate more conservatively,
keeping more resources available in reserve online
and also in making those available
either through additional ancillary service quantities
that we bought or through reliability unit commitments,
basically telling additional units to start up.
You can see from the graph on the upper right,
that we bought a higher amount
of ancillary services in July,
and then incrementally stepped that up in August
to kind of adjust more of that additional capacity
over into the ancillary services
rather than having to do this reliability in commitments.
And the other thing I guess I should note in that graph,
is that those numbers seem very high,
but what that is is kind of the addition
of all the extra megawatts over the course of a typical day.
So the way to think about it
is if we were buying 5,000 extra megawatts each hour,
over 24 hours, that would sum up to about 220,000.
So that's the way to think about that.
-: Point.
You finished on that?
-: Yes, sir.
-: One other quick comment on the thermal outages graph
on the left of that slide.
When you noted the thermal unit, unplanned outages.
Unplanned outages being, it broke, we weren't,
machinery broken in process
that were below 6,000 megawatts
on dates with high net peak demand.
Just for context, 6,000 megawatts is like,
check my math here,
but I think that's less than 10% of the total thermal fleet.
-: Correct.Correct.
-: So on those high net peak demand days
when demand was high, 90% of the fleet was still operating.
-: Correct.
-: Okay.
Just want to make sure we got some context around that.
-: Okay.
And that's all I have on from an operational perspective,
turn it over to Kenan.
-: Good morning on a Kenan Ogelman with ERCOT.
So I have four key things that I wanted to share with you.
First one is that we had a relatively cool summer
and the low cap was in effect.
So on just generally speaking,
prices were relatively low or normal.
There wasn't a lot of spikes in the market.
We also did not have any mass transitions
or anything where customers are moving
to a provider of last resort
or anything like that during the summer,
ERCOT did commit, as Dan pointed out,
more resources through reliability unit commitment
than we have in previous summers
and non-spend, reserve service priced out a lot higher
than we had seen in previous summers.
So as I go through each of those, the first,
the next slide, which is slide six,
it just shows the increase in RUC.
And it also shows you how much of that RUC commitment
was bought back by the resource,
which is in this for this summer, relatively small,
and that's driven by the market clearing prices.
So if there was a opportunity to make better profits
by buying the unit back and letting it be a market unit
entities would do that.
But when they're low prices,
they would rather take the make whole and cover their costs.
So we RUC-ed a lot.
And very few of those reliability unit commitments
were bought back by the market participants.
-: Just to paint the picture, Kenan,
what was,
and you may know off the top of your head,
I won't use 2020,
but 2019 was a hot year, high prices too.
$9,000 was cap.
It was achieved.
What were your RUC hours in June and August
compared to this?
-: In 2019, they were very small in June and August,
much smaller than even 2020.
I don't have a exact number for you,
but in this graph
you can see through -: Less than 100?
-: I'm sorry?
-: Was it less than 100?
-: That sounds correct.
-: Okay.
Go ahead.
-: So would the higher prices in 2019?
It sounds like to me, the higher prices in 2019
would have incented more generation to be available.
So therefore ERCOT wouldn't have had to have RUC-ed as much.
-: That that's correct.
So I think there's two things going on.
First,
is that there's market incentives to commit.
And then secondly,
if even if you did not commit and were RUC-ed,
there's an incentive to buy yourself out of that RUC.
-: Versus this year when prices were lower
and we had the L cap 2,500 in place,
it might've made more economic sense
to be part of the RUC process to at least get made whole.
-: Yes.
And because we're operating more conservatively,
there's more capacity on the system
and less likely to be high adders and things like that
as you get near the peak.
The next slide I was going to spend a little bit more time,
is the real time hub price.
And we tried to show this in two ways
because we traditionally show kind of the whole year
and February really dwarfs the summer months.
So we kinda took that out.
You can see that with the exception of August,
prices were slightly higher in 20, I'm sorry,
in 2021, then 2020,
but 2020 was also a relatively mild summer.
If I were to compare that to 2019,
you would see that those average prices were much higher.
-: Much higher than 2021?
And -: Correct.
-: Okay.
-: And then the next slide is kind of
a reality check that we do for ourselves
in terms of convergence
between the real time and the day ahead.
So,
the market's never going to always get something
that is very different in real time right day ahead,
or they might expect something to happen
day ahead that does not happen in real time.
So there can be daily differences,
but ultimately you do want those markets to converge.
There's usually a premium for the day ahead,
but with kind of daily exceptions,
you want those markets to converge.
And the slide shows that on average,
those markets do converge with some exceptions
that the market wasn't able to foresee
either in real time,
either something happened like a unit went out
or the wind forecast was off.
So that could drive expectations
either for the prices to be higher or lower
than they really turn out to be in real time.
-: So what happened on the range of August 29th through 31st?
Cause that's a real divergence there.
I mean that there is nothing comparable on your chart
to that period.
-: So.
-: Saying day ahead was higher than
real time? -: Yes, sir.
-: At the end of August,
you could also look at early July
where real time was way ahead. -: Yeah, so
-: Yeah, that's true.
-: But as you can see at one point one
goes above the other and then they come back.
So on those days,
I believe both the load forecast was off,
as well as the net load forecast.
So day ahead,
expectations could have been very different
than what we actually needed in real time.
-: Okay.
The next slide I have for you is about the non-spend.
And so when you think about ancillary services,
I think there's two things that drive the price
that it will clear out.
First is,
the sale of energy is your alternative
or your opportunity costs.
So if you go back to the previous year in August,
when the energy prices were high,
you see all the ancillary services being high as well.
So that's one sense of reference,
But what this graph shows is also when you procure more,
it takes both the market some time to adjust
and it moves up the merit order of that stack
and the price goes up.
So you see in the summer months,
ancillary service prices going up
and particularly the price of non-spend
increasing relative to other months,
this is driven by our additional procurement
of the non spin reserve service.
-: Important note about the market responding
to essentially increased demand for non spend reserves
or it's additional margin of safety,
increased demand from ERCOT on the same amount of supply.
I also note for fellow Commissioners and the general public
that the market responds,
and sometimes it responds slowly,
but sometimes it can respond quickly.
I think the, by way of example, the first night,
I think July 12th was the first night
that the new non-spend procurement was formalized.
I think the,
our ending 10:00 PM, 11:00 PM,
something like that,
the first time the additional non-spend was bought
it cleared at like $1,100 a megawatt,
which should never happen in the middle of the night
because all the gas turbines were throttling down
to go overnight.
And we don't want consumers paying that price
in the middle of the night, obviously.
The next night it cleared at $17,
which is exactly what we want
the markets to respond.
People kept the generators onto another couple hours
because they knew there was a market there.
And so I think that's a great example of,
as we go through this redesign process,
exactly how we want to,
we want to put out the results we want
and let the market respond to the most efficiently possible.
-: Right.
-: Glad to see it working that way.
-: And there is one additional step that we're taking
to provide additional liquidity in the non-spend space,
which is to allow additional load participation
that doesn't currently exist.
So that is notable protocol revision request
passed the technical advisory committee
at their last meeting.
And we'll go before the board
and come before the Public Utility Commission.
-: What's the MPRR number on that?
-: It is
-: 2 93.
2 93.
(laughter)
I've heard a lot about it.
So Kenan, can you,
I know it's past tack and it's on its way to the board.
Can you explain a little bit more
what the benefits are
of including that additional load to non spend?
I know ERCOT really wants us in place
by the summer of 2022.
And I would just like to understand a little bit more,
just you don't have to get down into the detail,
but just really what is the goal?
What is the benefit?
-: Well,
I think I'm at a very high level
there's no good reason not to allow load to participate.
So from a
economic efficiency you want all the resources
that can provide value in that space
to provide value in that space.
So I think that is a primary goal,
but secondarily, in terms of a market response,
it adds more liquidity to that market
where it will clear at a value
that reflects both the supply, the load side,
and the generation side in that market.
So those are the two key reasons
why we really wanted to move forward with that.
-: Well, non spend,
as we've seen, is a very valuable tool
to maintain reliability,
I think it's very important
as we move forward with this MPRR,
And I know that there's going to be a workshop
that will address other issues related to this MPRR,
that we delicately, well,
deliberately and thoughtfully look at this issue
because what we don't want are unintended consequences
to our non spend product.
And so we have to be very mindful of that
as we've relied heavily on non spend
this summer in our conservative operations,
that somehow in the middle of tweaking this around
to bring in more load, which I think is,
you know, pragmatic and,
and something that we should look at,
we don't want to end up in a position
where we have unintended consequences
on a very valuable non spend product
as we move forward to, you know,
especially into the winter
and this fall really where I think
we will hear from ERCOT that ERCOT will continue
to use their conservative operations through this Fall
as a result of the maintenance shoulder season.
And so non spend will continue to be very important
in those conservative operations in the winter
and year-round or liability, quite frankly,
especially with conservative operations.
So want to make sure
that whatever is happening with that MPRR,
that there's not any unintended consequences
on that valuable product
and the participants that have been providing that product.
-: They're actually,
some of these items were discussed at TAC
and there is going to be a workshop scheduled
to work through some of those issues, for example,
the deployment order.
And some of those types of things were raised as issues.
And the only thing I would share with you, additionally,
is some of those changes are going to be complex.
So we will have to make trade-off decisions
between getting something in this summer
and letting those other features come in later
versus trying to do it all at once.
-: On that,
what's the no later than to effect the Summer
that we need to have this in place
as an MPRR modification?
Is it before the May auctions for?
-: So non spend is auctioned
on a daily basis. -: That's right
it's on a daily basis.
Yeah.
-: So there isn't
-: What's the optimal market absorption.
I mean, when do participants nominally like to have this?
-: It would probably be nice to have it in place and in May,
but what I would caution you is that
the very resources that would be implementing securitization
on the settlement side, -: Yeah.
-: We'll have to work on that as well.
So, my expectation is,
and I'm sorry to bring bad news,
but I would expect something more like the middle of summer
where we actually are able to get this in play.
-: Okay.
-: We can, we can work on that.
(laughter)
-: And then I have -: What did you say there?
-: We can work on that.
-: Agreed.
-: I do have one last slide,
and this is just to kind of summary
of the credit collateral activity.
In truth, the summer was relatively calm.
You do see one spike in collateral calls.
That is actually a result of true up invoices
that we sent out that had to do with the February storm
and not anything that happened during the summer.
So as we got better meter data
and were able to assign those costs better,
there was a true up that happened in the Summer
that triggered collateral calls
that were what I would describe as a somewhat,
a little bit of a surprise to the stakeholders.
So it took them a little bit of time
to post the collateral associated with that.
-: All right,
thank you, sir.
Yeah, Dan.
-: So I have one more issue I wanted to discuss with you.
In the Fall, in September October timeframe,
typically the demand on the system is lower
because people are neither running their air conditioners
nor their heaters.
And so that's really the time of year
when we see a lot of generating units
that are taking planned outages to get ready for winter.
And this year, we're seeing
a significantly higher number of these plan
generation outages to get ready for winter
that are scheduled during this fall season,
compared to what we saw at the same time last year
And for previous years.
In fact, to the tune of, you know,
I think they were about 10 gigawatts last year,
and it's up to about 18 gigawatts
at the highest time during the course of this Fall.
So although the demand on the system is generally lower
in the Fall,
if we do have days with unseasonably warm
or toward the end of the Fall, cold temperatures,
and we also have low wind
and higher than expected unplanned generation outages
for some reason,
we could also have some tight conditions in the Fall.
As Commissioner Cobos mentioned earlier,
it's kind of a year round problem
because people have to fix their plans.
ERCOT will soon be filing this revision request
that I mentioned earlier to implement
the provisions of SB 3 that provide for ERCOT
to approve or deny all generation outages.
For now,
when we see these tight conditions developing a few days out
we'll issue what's called an advance action notice.
Basically, a notification out to the market
to let the generators have the opportunity
to move those outages around
so that we have enough capacity.
And if that doesn't work,
then we'll use our existing
outage schedule adjustment process
to either delay or cancel some of those generation outages
to make sure that
we've got enough capacity available each day.
But this process also allows those generators
to continue to take the outages.
When we do have milder conditions
in order to get ready for Winter.
In addition, as was mentioned,
we're planning to continue
more conservative operations approach
that was implemented this summer
throughout the Fall and going forward,
so that we'll have enough sufficient generation
available to do that.
Just wanted to add that.
-: Yeah. Important update.
And the bottom line for the public
is one reliability is paramount
and will continue to be paramount.
Second, we need to prepare for winter.
These generators need to do oil changes, tire rotations,
et cetera, just like any other piece of machinery,
which means that it's,
we don't get a free pass this Fall.
It's still going to be tight,
but ERCOT has mechanisms in place
and the authority to cancel an outage,
adjust that maintenance schedule.
If conditions look tight,
they can make sure those thermal generators
will be there if we need them
and they can move maintenance to a later date.
-: Correct.
-: Thank you, sir.
Very important point.
-: And ERCOT will continue
to use their conservative operations tools.
-: Absolutely.
-: Right.
-: In fact,
we're incorporating the need to do that
into this process of making sure
we've got enough generation not on outage.
-: Excellent.
Thank you very much.
Any other comments or questions for the ERCOT team?
All right. Thank you, gentlemen.
-: Thank you.
-: We also have a memo filed from Commissioner Cobos
on this item.
So I will turn it over to her to lay out her memo.
-: All right.
Well,
in a follow-up discussion to our open meeting
on September 23rd and our order
to stack AP slash ATT and Sharyland
to build the second circuit loop of second circuit.
New second circuit line and loop facilities
wanted to file this memo.
I think as a matter of due diligence,
we need to ensure that we
are getting progress reports from the utilities,
with regard to their construction of the second circuit
and the loop facilities.
We, as we discussed last open meeting,
these facilities are intended to serve as a interim measure
while we await a more long-term solution
for the Rio Grande Valley.
And I just don't want this to slip, you know,
behind schedule and not remain a priority
for the companies that are building these facilities.
So I have filed this memo for your consideration
to require at my request,
quarterly progress reports from the utilities
that are responsible for these facilities
to provide us with information
on how things are progressing with those second circuit
and loop facilities being built out
in the Rio Grande Valley.
It's important for liability.
And I just want to make sure that we stay on top of it
since we ordered the construction of these facilities.
-: Absolutely.
Agree with both the spirit
and the technical elements of your memo.
This is a project that is critical for the state,
and it's not something this Commission
is just going to forget about and hope it works out.
And so thank you for ensuring that we'll keep an ongoing,
we will continue to monitor the progress
and do everything we can
to support the relevant stakeholders
while also holding them accountable.
-: Great.
And so, Steve and I asked for staff
to open a new project
for these transmission related matters
that I believe staff has opened.
And that's where I would like
the quarterly progress reports to be filed.
-: Yes, we have filed open
that is Project 5 2 6 8 2.
And I would just ask
because the order directing the building
of those transmission lines has not completed it
through the signing process and whatnot.
Would you like to amend that to include
these progress reports requirements in that order?
Maybe we can pull it back in, add that into it and.
-: Yes.
-: Makes sense.
-: Yes.
And in that order,
that requires those quarterly progress reports
to make the first one being due November 1st.
-: November 1st
-: Did you say 5 2 6 0 2?
-: 5 2 6 8 2.
-: 8 2.
And then we will, now we have this open,
we will transfer all the previous documents.
You'd requested us to put in there.
If we haven't already done it, I'm not sure,
but they will be there.
-: Okay.
And as a second item to this discussion,
I requested that stack ATT slash AEP
and Sharyland also file,
make a filing in with respect to the CCN activities
that would be required as a result of building
the second circuit and the loop facilities.
And I had sort of raised the issue at the last open meeting
about, you know,
whether whether a CCN amendment would be required.
And if it was how quickly the companies can,
would be able to file a CCN amendment
or a CCN application at the Commission.
And at my request, the parties have filed,
made filings in 5 1 6 1 7,
which will be transferred to the new project.
And with respect to stack and ETTs letter,
they have stated that they don't need a CCN amendment.
I just want to put a placeholder here
and I appreciate the company's filing that information
and the facts surrounding their determination.
They don't need a CCN application,
that is because the prior CCN application
that was approved for the Commission
will allow them to not have the CCN amendment
or be required to file one with this.
However, I do want to put a placeholder
because there is a tangential docket
that Commission staff is looking at right now.
It is a docket number 5 26 10.
And in that case stack has requested a determination as to
when a CCN amendment would be required.
And I think to make sure that we are moving
all in a consistent direction
and to, you know, level-set,
I want for Steven to provide us an update
on what's going on with that case,
with respect to requesting briefing
and ultimately getting a Commission determination
when a CCN amendment is required
with regard to a second circuit
on a double circuit capable 3 45 transmission line.
-: Yes ma'am.
We discussed this case early this week, I guess,
Monday and looking at the issue
and also knowing the issue has been discussed
in this arena, decided that this was an issue that
the Commission needed to speak to
and decided to issue a briefing order
to request a threshold brief,
a briefing on threshold issue in this case,
which will have much broader implications, no doubt.
I think the, the orders about done,
we should get it out,
I think given the timeline where we are,
we would be looking at having that issue brought to you
on the November 18th open meeting for resolution
so that we can have the Commission definitively address
when if a CCN is required in these circumstances or not.
-: Okay.
And with respect to Sharyland's filing,
they have reiterated
that their best time estimate is eight months.
And so with respect to that timeline,
I would like to include in the order,
that order's construction,
a directive that Sharyland file
a CCN application in June of 2022.
And if there's any delays in that process to notify us.
-: Makes sense to me.
Y'all?
-: Yup
-: Okay, we'll have that into that order too.
-: All right.
-: Do you want to say June 1st or June 30th?
-: Well, we are at the beginning of October.
And so I'd say by June 30th,
just sometime
within the month of June. -: Sure
-: No later -: June 30th
-: No later. -: No
-: Yes. -: No later than.
-: And certainly we'd accept it earlier.
-: Absolutely.
But, and if there's any delays to please notify us
of that delay -: Absolutely
-: All right.
-: Okay
-: Work for ya'll?
-: Yes, sir. -: Mm hmm.
-: All right.
-: That is all I have on this item.
-: Thank you for your leadership on this.
It's tremendous.
That concludes our business on Item 20.
I don't have anything on Item 21.
Anybody else?
-: No, sir.
-: All right.
Next item will be Item 24,
Mr. Journeay, could you play that out for us?
-: Item 24 is docket 5 1 5 7 2.
It's the appeal of John McGuffey and McFarland farms.
The cost of obtaining service
from the Virginia Hill Water Supply Corporation.
Proposal for decision was filed on August 31st.
It recommends that the Commission deny the appeal.
No party filed corrections or exceptions.
-: Thank you, sir.
Seems straightforward to me,
but would love to hear from y'all.
The tariff is clear.
Any comments, questions?
-: Yeah.
The classification of their tariff that they're in
sort of dictates the outcome here.
So I agree with you Mr. Chairman.
-: All right.
Is there a motion to adopt the proposal for decision?
-: So moved.
-: Second.
-: All in favor, say aye.
Committee: Aye.
-: Motion passes.
Item 25 was consented.
I don't have anything for Items 26 through 29.
-: Y'all?
-: No, sir.
-: That will bring us to 32
with comments on that from staff.
-: Yes, sir.
Thank you, Mr. Chairman,
just a couple items this morning.
First in regards to the Turks selection process,
where you're finalizing that process.
I hope to notify the applicants
who have been selected tomorrow,
and then we'll file a memo
in the docket that we opened for the applications,
letting the public know who we've selected
and also notifying Tetum and Chief Kid
of who we've selected so they can contact them
about future meetings.
-: Excellent.
-: Thank you.
-: Second,
I've given you updates
on our mapping committee work in the past.
One of the things we've talked about
is how to engage the public and stakeholders in that.
We have another meeting tomorrow.
I'm going to discuss,
and I discussed yesterday with executive director Wei Wang
of the Railroad Commission.
Who's the Vice Chair of that committee,
ways that we can engage the public and stakeholders
to give them more information on what's going on.
So I'm going to put a couple ideas out there
tomorrow at our meeting and hope to report back
on our progress on that
at our next open meeting for you all.
And then finally, something that is very important
I think specifically to Commissioner Glotfelty,
I want to thank the Facilities Commission and Mike Novak,
their Executive Director, for working with us
to move up the timeline for constructing
our two new Commissioner suites.
So that Commissioner Glotfelty
and his staff can move into Commissioner's offices.
We are going to start that construction on the 14th,
and we hope, they hope to have it done by
the beginning of the new year,
which is about the same timeline
that we'll get our new dais
to accommodate up to five Commissioners,
to make you all a little more comfortable up there.
(chuckle)
-: Outstanding.
And I will also, in all seriousness,
commend Commissioner Glotfelty
for being such a good sport (chuckle)
and joining this Commission with the lack of space
and resources we've had.
We appreciate you. -: I would
invite you all to come down my hallway,
it's very open and very quiet and very,
it's a joyful place to be so.
(laughter)
-: It gets a little tight in your cubicle, but
(laughter)
-: He may not feel that way once the construction starts,
(laughter)
but that's all I have this morning.
-: In fact, in ya'll need an address for me
to tell you where I am, (laughter)
so y'all can come see me I'll let you know.
(laughter)
-: All right.
I don't have anything on 33 or 34,
unless you all have anything else,
that will bring us to item 35,
Mr. Journeay,
you've circulated a statement regarding our Consent Agenda.
Could you give us a brief summary of that?
-: Yes, sir.
This statement is trying to reflect discussions
that I've had with all of y'all
over the past period of time
to basically expand our use of the Consent Agenda
beyond what we have historically done.
So that if items only have correction memos
from the judges or staff, myself included on that,
those items will be consent able.
There were three proposed orders today
that only had a memo for me on it ,
that in the past we have not consented,
that would be one that would be consented.
And we had a PFD with no correction, memos or all.
And that would be, also now, put on the consent,
be able to be put on the consent list.
It also lays out what it means
when the Commission approves the Consent Agenda,
and that is it approves the latest filed order.
Plus the correction memos
that have been filed prior to that time,
it does not include memos from parties outside staff,
or the judges within that.
And then finally it talks about
how we prepare our Consent Agenda,
which is how we have done it in the past,
but it lays it out and it makes it clear
that if Commissioners are recusing themselves from a matter,
they do not need to be included
on the unanimity of the Commissioners
to put it on the list, to have it put on the list.
So that will resolve some issues we've had recently too,
where things weren't consented.
It will give us a little bit more,
probably save us five minutes on our openings,
(laughter)
Maybe a little bit more. -: I imagine
-: It's always welcome opportunities
to streamline operations here at the PUC.
Thank you for laying that out.
And so just so the public knows
that we will continue to be transparent
in all of our actions here.
The changes you're talking about that now can be consented,
are non-substantive grammatical technical corrections,
any substantive changes of policy
would be still for discussion with the Commission.
-: Well,
I think that's true, with maybe two exceptions,
in that were so a judge that writes a PFD
occasionally could make a substantive correction
in their memos.
And we have dealt with those in the past, always.
And perhaps also in proposed orders to adopt rules
where there's changes to the rules
that could be substantive changes to the rules.
Those would also be included in this process.
Of course,
if the Commissioner wants to discuss them,
they just don't put it on their consent list then.
-: Yeah.
If it's some substantive policy,
if you think we would
would flag that for discussion.
-: Right.
-: All right.
Any comments, questions?
-: I think this strategy,
given the workload that we have,
given the panacea of topics
that we have to take up over the next year,
help provide focus for the public as well as us
and the stakeholders who are active participants here.
So I think the policy is consistent
with both the degree of transparency,
which the PUC has been accustomed to
and the work that staff does behind the scenes.
So again, I agree with that.
-: Well put.
-: So we would take a ask for your approval of
this statement, as it's your policy.
-: Is there a motion to approve
the statement regarding use of
the Commission's Consent Agenda?
-: So moved.
-: Second.
-: All in favor, say aye.
Committee: Aye.
-: Motion passes.
That concludes our agenda for today.
Having convened in a duly noticed open meeting,
the Commission will at 10:47 AM on October 7th,
hold a closed session pursuant to Chapter 501
in Texas government
code sections 5 0 1.0 7 1 5 5 1 0.0 7 4 and 5 1 1 .0 7 6.
We'll be back in a bit.
Closed session is hereby concluded
at 11:44 AM on October 7th, 2021.
And the Commission will resume its public meeting.
No action will be taken by the Commission
regarding matters discussed during closed session.
So there being no further business
to come before the Commission,
this meeting of the Public Utility Commission of Texas is
hereby adjourned.
(gavel bang)