-: 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 September 23, 2021.
For the record, my name is Peter Lake
and with me today are Will McAdams, Lori Cobos,
and Jimmy Glotfelty.
Before we dive in,
I think Jimmy has an introduction he'd like to make.
-: Thank you, Mr. Chairman.
For everybody in the room and those online I'm filling
out my staff and I wanted to introduce VA Stevens,
who will be my chief of staff.
And she's been around these parts,
not necessarily the PUC, for a long time.
But she's been at the Capitol and the TNRCC
and then with me to streamline permitting
at the federal level.
And obviously, if you talk to her, you talk to me
so welcome her.
Thank you.
(participants applauding)
-: Yes, sir.
All right, Mr. Journeay,
could you please walk us through today's Consent Agenda?
-: Good morning, Commissioner.
By individual ballot, the following items were placed
on your Consent Agenda.
Six, nine, and 25.
That's all.
-: Is there a motion to approve the items just described
by Mr. Journeay?
-: So moved. -: Second.
-: All in favor, say aye.
-: Aye. -: Aye.
Motion passes.
At this time, we will open for public comment.
All comments related to a specific agenda item
will be heard when that item is taken up.
This is for general comments from the public only.
Speakers will be limited to three minutes.
Mr. Journeay, do we have anyone signed up
from the public to speak?
Stephen: No, sir.
No one's signed up.
-: Thank you.
All right, we will not be taking up item number 27.
That brings us to our normal agenda.
I don't think I have anything on item one.
That'll take us to item number two.
Please lay that out for us, Mr. Journeay.
-: Item two is docket 51215.
It's the application of Entergy for a CCN amendment
for a solar facility in Liberty County.
The PFD was issued on July 19th.
Exceptions and replies were filed.
The ALJ filed a memo on September 14th, making no changes.
I have a memo with proposed changes to the PFD
and Commissioner Cobos has recused herself from this matter.
-: Thank you, sir.
I know this is a big project and would be a good
diversification of generating resources for that area.
But there seems to be a lot of problems
with the application and last minute additional
of financial promises without any clarity
on mechanisms to deliver that.
Thoughts.
-: I agree.
You said the words exactly.
Financial guarantees that don't have any backup.
I think they're a tax equity partner
that we don't know who they are.
There are a whole host of things that I think it's hard
to make a decision on and prove beyond a reasonable doubt
that this is in the public interest.
-: Well said on both counts.
I agree with all of it.
-: I appreciate OPUC's intervening in this
and their concern.
We're not at that point yet
and we'll trust that they'll be there
to ensure the project costs are in line
with the public interest.
Is there a motion to adopt the proposal for a decision
with a modification or the parties
to jointly file this with exhibits,
indicating which exhibits are confidential and declassified,
which was another issue?
-: So moved.
-: Excuse me, sir. -: Sure.
Stephen: Your motion was to adopt the PFD.
-: Approve the PFD-
-: As modified. -: As modified.
-: Okay. -: Is that to,
I think we want to agree with it.
-: We wanna remand it. -: Yeah, we wanna remand it.
-: I wanna remand it.
-: Oh, okay, I apologize.
Remand to remand the docket to OPDM or so.
-: So it would fill out the record
to ensure that we have more information
about the financial dealings
about the proposed solar facility
and the financial understanding of the other parties
before it comes back to us.
-: I withdrawal my motion.
-: All right.
We'll take Jimmy's motion commentary as a motion.
You second that? -: Second.
-: All right, we've got a motion and a second
to remand the solar for more clarification.
All in favor, say aye. -: Aye.
-: Motion passes.
Item number three, Mr. Journeay.
-: Item three is the docket 51556.
It's the application of Greenville Electric
to change wholesale transmission rates.
Proposed order was filed on August 2nd.
I have a memo with proposed changes to that order.
-: Seems to be a reasonable settlement.
Any thoughts on approving that proposed order?
-: Increases rates by the 900,000.
Staff, parties agreed.
I'm good with it.
And would move to, yeah.
-: I'm good.
I'm good with this one.
-: And would move to adopt the proposed order, as modified.
-: Is there a second? -: Second.
-: All in favor, say aye. -: Aye.
-: Motion passes.
Item number four, please sir.
-: Item four is docket 51959.
It's the application of TNMP to amend their DCRF factor.
Proposed order was filed on September 3rd.
The ALJ filed a correction memo on September 23rd.
-: This is another settlement.
Any thoughts, concerns?
-: Yeah, I mean pending Commissioner Cobos
but I just wanted to make sure what we have here
conforms to previous precedent that we establish
our rate case expenses.
That is the case, even with the revised filing by ALJ.
Or it's not the case, even with the revised filing by ALJ.
-: It's not the case- -: That's what I wanna confirm
and that's what I wanna ask for.
I believe the Commission should modify this order,
as it's presented,
to recover only the rate case expenses
for which there's proper evidence
and accordingly modify the rate case expenses rider.
We sort of crossed that bridge in a previous proceeding
on Cherryland and I just wanna make sure we're consistent
moving forward.
-: Well, more than one, that's a good standard to set.
-: I agree.
Based on my prior experience,
there have been settlement agreements reached
where trailing expenses are capped at a certain amount
to take in account potential rate case expenses
that would occur at the tail end of the case
to settle the case.
However, I don't disagree with the approach
that's been established by the Commission
to just cut it off at a certain point
and let the parties recover their rate case expenses
in a future proceeding.
So I agree with the approach
and would support approving the order
with the modifications regarding the rate case expenses
and the changes proposed by TNMP and their exceptions.
-: Agreed.
Can we consider that a motion?
-: You can consider it amotion.
-: Is there a second? -: I second.
-: All in favor, say aye. -: Aye.
-: Aye.
-: Motion passes.
Item number five please, sir.
-: Item five is docket 51972.
It's an agreed NLV-related to Centerpoint.
Second revised proposed order was filed on September 15th.
The ALJ filed a memo on September 16th
accepting changes proposed by Centerpoint.
-: Got another settlement.
Thoughts, concerns?
-: I hate to open,
I appreciate when parties make the effort
to try to settle.
I think that's in the best interest
of all parties involved.
I struggle with this one a little bit
because SAIDI and SAIFI are so important,
especially in regions along the Gulf Coast.
Especially when we don't really have
a full record of when every customer was reconnected.
Especially when I read the filings,
I'm not sure that the request for information
has been totally fulfilled.
And I think that these are really, really
important treatise.
SAIDI, SAiFI, how we make sure that these individual Texans
have their electricity and when it's cut off
and when it's not cut off are really,
really important issues.
I know Centerpoint's gonna come back
with the report here in a few months
documenting a lot of vegetation management things,
which I'm really, really eager to see, and other things.
But I don't know, this one,
it kind of scares me that it's not in the best interest
right now and we need more information
in order to make a more informed decision.
-: Yeah, and I would dovetail on that.
We tried to establish again,
since the Commission was formed,
with its current composition,
we're trying to be consistent in asking
for remediation plans so that we can gauge success here.
And again, this is in a hurricane,
it's in a vegetation-prone area of Texas
so it keeps happening.
So we need to see, what are you gonna do
to ultimately fix this?
Fines are fine but that's not how I gauge success.
I gauge success as I don't ever wanna hear
about this feeder again.
And so-
-: And the feeder is not in a rural area.
It's in a very populated area so it does impact customers,
a significant amount of customers.
And I agree with your statement
on the administrative penalties in that a $10,000 penalty,
sometimes these penalties are basically
just the cost of doing business and folks will pay out
and keep going.
But we wanna see remediation, correction, mitigation,
so that issues are actually addressed and fixed.
-: I think the one other thing that I would add
is it is clear, it is a hurricane-prone area,
high winds.
I think they, CenterPoint, has done a good job
in a lot of their system.
If there are problem lines like this,
we have to focus on these problem lines.
As a business, you can't let one problem line
skew your SAIDI and SAIFI of your whole system.
You can't let that happen, guys.
And I just, I recognize that they would be under
or they would be in compliance with most
of their SAIDI and SAIFI if it weren't for these storms
and that's great.
But we've gotta get these small ones cleared up
because it means customers.
Customers are inconvenienced.
-: Or at least get us the plans
so that we can gauge the costs on the system, or whatever.
Just give us a plan.
And right now that's,
I think we're all singing the same sheet of music.
That's what we're missing right now.
-: With respect to the other violation
and the 1102 customers and disconnection
of those customers,
the company had agreed to a $200,000 administrative penalty
and also contributing to a charitable cause
for low-income customers so I am comfortable
with that path forward.
It is the SAIDI and SAIFI violations
that I think are the issue here,
where we don't have enough information.
-: Agreed.
-: It sounds like there might be a motion to remand.
-: I move to remand it
for more information on the-
-: Remediation plan.
-: The remediation plan.
-: Is there a second? -: Second.
-: All in favor, say aye. -: Aye.
-: Aye, motion passes.
And I appreciate very much the focus
that all of y'all have put on this issue.
This is a problem we can solve
before it becomes a problem.
Item number six was consented.
If item number seven and eight,
are y'all gonna take those up?
-: I would just say a couple of words on those
and explain the path forward.
-: I'll excuse myself.
-: It'll be quick, sir.
-: I was recused.
-: So Chair takes up item 5232,
can I take these up together- -: Yes sir.
-: Okay, I'm gonna take up 52321 and 52322.
And just for clarity for stakeholders, participants,
and the broader public, on securitization,
we now have a partial settlement filed
in the docket on 52322.
We also have the bones of what securitization
might look like for 52321.
I believe a bit,
and again, that partial settlement came in this week.
It seems prudent to have a little bit more time
for staff to address the fine points and issues
that were not covered, for the purposes of 52322
in the partial settlement outline that was filed.
And also, for the purposes of 52321,
the $800 million securitization, we also have
some outstanding refinements that could be made
before a final order could be presented
for our consideration.
So with that, we have posted for a open meeting
next week, September 30th. -: Yes, sir.
-: And we could take this up at that time.
-: In addition, sir, we were discussing posting
additional open meetings on October 5th and 6th,
just as a- -: Placeholders for, yes sir.
-: In case they're needed.
-: Yeah, we will not let the timeline slip on this,
that's the ultimate goal.
We wanna make sure the legislature
and parties understand that.
We just wanna get this right at the first cut.
-: Absolutely and I support adding
the extra open meetings to give staff
more time to evaluate the bare bones,
as Commissioner McAdams has talked about,
in 52321, Subchapter M, securitization case
and make sure that we have everything we need
to make a decision on that case.
And then with respect to 52322, Subchapter N,
as you noted, we do have a partial settlement
and we do need to give staff more time
to evaluate the settlement.
But we also need a weight on the supporting testimony
that supports the settlement so that we have
more information on the settlement
to allow us to make a well-informed, holistic,
robust decision.
-: Yes, sir. -: I would say,
I'd like more time to understand it as well,
not just staff.
It's complicated, it's confusing-
-: You can just say that, I'll take more time too.
-: We gotta get it right and it's important.
We have to do it quickly, obviously,
for the good of the market.
But we gotta understand what we're voting on.
-: It would be nice.
-: And really, I mean, I do wanna say
I appreciate the parties working towards a settlement.
We asked them to do that
and to all of you that were part of that,
it's important.
We appreciate you heeding that call
and working towards the settlement.
-: I would just like to say that one thing
that has disrupted our timeline
is it is taking more time than anyone might expect
to figure out what issues have not been settled.
-: And that's why, as parties file additional comments,
again, trying to solve those issues
that are not addressed in that partial settlement.
I get it, those were the big ticket items
but there are functional areas that we've gotta make sure
we get right here. -: Yes, sir.
I just baited the water.
I don't think I'm gonna take my hook out.
-: Yeah, I just added some to it.
So if everybody's in agreement,
we'll set aside items number seven and eight
until next week.
-: Agreed. -: Agreed.
-: Mr. Chairman, I'll hand it back to you.
-: All I heard was Journeay talking about baiting the water.
That's enough for concern. -: That's his favorite pastime.
-: You got your reel with you?
-: All right.
That brings us to item nine, which was consented.
And have y'all taken up 10
or you're not gonna take up 10?
-: We did not take it up. -: We did not.
We are not gonna take that up.
-: Okay.
Item 11 and 12, I don't have anything on those.
Do y'all?
-: No sir. -: Nope.
-: That brings us to 13, regarding market performance
this summer.
I filed a memo on this earlier this summer,
related to generator outage reporting.
Jimmy hadn't joined us at that point
but we directed ERCOT to make an outage
and dereg reports available to the public
within three days, instead of the standard 60 days,
due to issues related to the June event.
That order expires on September 30th
and ERCOT is currently working through NPRRs
to fulfill the order that we issued.
But those won't be completed by September 30th.
So I would proposed extending that June order
to ensure that the public continues
to have the same transparency
on generator outages and deregs that have
so far this summer.
I think that transparency is important to the public.
And while we have come through the summer months,
as y'all know, the fall shoulder months
still have their own unique challenges.
And I know the public will still have
a keen interest in that transparency.
I'll open it up for thoughts or comments on that.
Go ahead. -: Thank you, Chairman.
I think that's a great point.
With respect to the report,
as we enter into the shoulder months,
there will be generation down to get, maintain
for the winter, to go through the maintenance outages.
So in the report, would that include
just D rates and plants that are forced out or both?
-: It would be the exact same order as in June
of just forced outages and deregs.
It would just change the timeline.
I think ERCOT's got, they already have a pretty robust
planned outage program.
We've made changes to that
and ERCOT has not, since the winter,
ERCOT has more control over those planned outages
and adjusting those to ensure reliability.
So this would just be focused on forced outages,
simply changing the dates
from having that order expire on September 30th.
And this would just make that same exact order
effective from October 1st through May 31st of 2022.
-: Just to correct, Chairman,
the order does speak to maintenance level outages.
-: Oh, it does, as well.
Oh, well, there you go.
Sorry.
-: I'm sorry, it speaks to?
-: Maintenance level outage information.
-: I think this is a good vote, a good yes.
It's pretty big market information,
especially when we're so short on capacity.
And I think it's important to get it out there quickly,
as opposed to 60 days later.
A lot of things can happen in 60 days with generating units
and we oughta make sure that the public
and the market knows what's happening as quick as possible.
I applaud ERCOT for trying to make the changes
as quick as they can and this order
is kind of a stop-gap measure to make sure
that we have a continuity of service in what we're doing.
-: Indeed.
-: To dovetail on that, I believe it is consistent,
this approach as a stop-gap, a bridge,
to what may be considered market design,
as we have that conversation in October.
So this is widely considered by the public,
by policymakers to be, as of right now,
a successful policy.
Stakeholders will be able to,
once we outline a blueprint.
And if it does touch on this,
we'll be able to speak to an overarching policy
moving forward.
But for the time being, as we again bridge through shoulder,
which is always tense, at least from my standpoint,
this helps in terms of transparency
and pressure on those resources again
and shareholders to do the right thing.
So I would support it.
-: And yes, I absolutely support the continued transparency
going forward.
I think it is important for the public,
for the policymakers, for us, as we work
through market design.
And I do believe it is important that ERCOT.
I'm glad to hear that ERCOT is introduced NPRRs
to set a more permanent framework
to provide that transparency to the public.
-: All right, thank you all for the comments.
At this point, I'd entertain a motion
to issue a new order.
ERCOT making the order
in paragraphs one, two, and four
of our June 30th order.
And this docket effective from October 1, 2021
through May 31, 2022. -: So moved.
-: Second. -: All in favor, say aye.
-: Aye. -: Aye.
Motion passes.
That will bring us to item number 14,
regarding the Texas Entergy Reliability Council
and its membership.
I know our executive director filed a memo
on this project.
Mr. Gleeson, would you and your staff
like to provide some background on your memo?
-: Sure, thank you, Mr. Chairman, Commissioners.
So we, in this project, filed instructions
for those interested in being a part of TURK.
To apply, what we're asking for is a letter of intent,
for a resume, and for a letter of recommendation.
This closely mirrors what we do in our RFP process
and that's the example we use to set this.
The only thing I would add is we want
to work on an expedited timeline
so I'd ask if they're interested,
file their application by next Friday.
And my goal would be to have a selection
for all of the eight spots,
by the end of the following week.
-: Like so many things around here,
a very aggressive timeline. -: Yes, sir.
Appreciate the expediency
with which you're undertaking this.
Any comments, questions for Mr. Gleeson?
-: No, sir.
-: All right.
Is there a motion to approve
the order filed with Mr. Gleeson, September 16th.
Memo authorizing a delegation of authority
to the executive director takes necessary action
to make appointments to the Texas Energy Liability Council?
-: So moved. -: Second.
All in favor, say aye.
-: Aye.
Motion passes.
Thank you.
Don't have anything on item 15, do y'all?
-: No sir. -: All right.
-: Nope. -: Good.
That will bring us to item number 16, project 52373,
regarding wholesale electric market design.
Commissioner McAdams filed a memo, two memos on this.
Before I'd ask you to address those,
I'd offer some comments and thoughts
to our broader stakeholder community
that I think reflects the general sentiment
of this Commission.
We have been, and you all have been,
part of an extraordinary stakeholder process to date,
throughout the summer, and will continue to be.
So we as a Commission are very grateful, and the staff,
for all the effort and resources that have been expended
on that.
We got a lot of good feedback.
We've had a lot of good discussions
in these work sessions and it's been a lot
of work for everybody involved, including our staff
and our Commissioners and their staffs.
We've got a lot of good input and insight
on new ancillary services products,
the scarcity pricing at ORDC, MCL, et cetera.
And all of which this Commission will consider
and I suspect will take action on some,
if not all of the above, once we get to our final blueprint
in December.
But I would ask our stakeholder community
to not stop there.
If we stop there, I think we run the risk
of putting band-aids on bullet holes.
Senate Bill three asks us to not only address
ancillary services and look at additional products
that could be used to enhance reliability
in the ERCOT marketplace
but it also asks us to ensure broader reliability
in the ERCOT marketplace, in addition to above
and beyond just those ancillary services
and similar type products.
So I would ask our stakeholder community
to think about the substantial changes
to the normal functioning of the ERCOT market
in a normal day and a normal course of business
that will ensure that the revenues and the economics
of the ERCOT model go to generating resources
that provide reliable power of any form or fashion.
And so that companies and entities
that reliably provide power to Texas
can run a reasonably profitable business
under normal conditions.
They don't need a scarcity event
or a crisis to generate reasonable returns
for their investors.
Right now, the current market framework
seems to put reliability risks in the ERCOT control room.
If a unit trips or weather conditions change,
the folks in the ERCOT control room
are responsible for continuing to serve load.
As part of the normal functioning of the ERCOT market,
I think we'd like to see that risk
moved out into the marketplace.
That has the financial tools and risk management
capabilities to better handle that kind of risk
and where the rewards for mitigating that risk
are available.
That could be on the gen side, the load side,
some combination thereof.
We've already seen a lot of suggestions that address that.
So this is just a reminder to our stakeholders
that as you move, from now until the submissions
outlined in Connie's memo, I think September 30th-
-: Yes, sir.
-: Please, please think big.
Please think about wholesale changes
that will provide revenues to reliable power
and normal market function without requiring
a crisis, without requiring scarcity.
So that's simply my ask of our stakeholders
as they move towards that September 30th deadline.
Commissioner McAdams, I know you've filed some memos
on this so I'll turn it over to you at this point.
-: Thank you, sir.
And let me start off by saying that the memos
were filed with an interest of not only market certainty
but to assuage consumer concerns
as we head into the winter of 2022.
And to set in place a system of safeguards
that both the market participants can count on
but the consumers, the residential consumers
that are gonna receive bills.
Uri was traumatizing, we recognize that.
The next winter after Uri will be remembered
by consumers of all classes.
And so my memos were limited in scope
and as I said in my memo,
this isn't market redesign, this is market design.
These are aspects of our market design
that are sitting there that everyone in this room
is accustomed to seeing and debating change to.
But with that, one of the components is clearly
in our rule.
A lot of things hinge on the value of lost load,
the high cap that is in TAC 25.505.
In order to address ORDC substantively,
which is the basis of, I think it's fair to say
hundreds of comments.
If you screen several dockets that we've opened,
consistently, stakeholders have said
that the high cap should change.
That $9000 was almost universally critiqued
as being high, given the depth of the load shed
and the length of the duration of the period of Uri.
And so I would pare my memo back and what I'm asking for
in the interest of a fast-moving rulemaking
to where we could lower the high cap
for the purposes of 2022.
And again, that would dovetail naturally
into the proceedings that we are taking up
as a part of the redesigned blueprint,
which this Commission will consider.
Again, lowering the high cap is not,
in and of itself, the answer and will not be
the only thing to be imposed for 2021.
But for the purposes of our rules,
we must change that in order
to substantively effect everything else.
And so I propose that we open this rulemaking
to only change that $9000 number and,
if appropriate,
so that again, having conferred with staff,
the way rulemaking should proceed is staff
would file a redline.
And again, then we would adopt that redline
to go out for comment.
So in order to match that up with our schedule
to enact these changes quickly,
conforming to the comment requirements,
we only have a couple of dates on the schedule.
September 30th would not be in time
because frankly, I need to propose a number here
that can then go into redline.
And I'm looking at Connie and Thomas
to make sure all this jives,
that we can then vote on to move forward in the process
so that stakeholder comment can be received.
So just as a kind of whiteboard in words here,
I would propose a number at 4500 right now
to supplement the 9000 as a placeholder-
-: To reduce from 9000.
-: Reduce from 9000 down to 4500, cut it in half,
and then let stakeholders tell us why I am wrong.
And then let's see-
-: Do you think you'll get comments?
-: I think I'm gonna get comments.
-: I don't think so.
I'll bet you won't.
-: We could adopt that at the October 7th open meeting
with an abbreviated comment period for,
and again, everybody's filed comments on this,
I mean, everybody's done studies,
for October 14th, which lines up very well,
Mr. Chairman, with the redesign effort
and those decisions that would
move forward concurrent to that on ORDC or anything else.
-: When would you ask stakeholders to have their,
I guess, final, final comments on high cap
into the Commission for consideration?
-: Well, I'd look to Connie on that.
My non-negotiable is to get this in place
for January 1.
-: Would it sync with this?
I mean, they've got comments coming in
on September 30th anyway-
-: I know, on the study.
-: On the market reliability.
-: The reason I didn't line it up
with September 30th is because I have
to get staff to put out that redline
and then we come back and adopt it.
We have to vote on that portion,
which starts the clock.
-: So that would be-
-: The October 7th.
-: So would it be manageable
to having stated, what I think,
is a reasonable starting point
for a revised high cap of 4500,
would it be manageable to let stakeholders provide feedback
if, I mean we can have that discussion
on what that number looks like,
provide feedback on that number
before we start the clock running on a proposed rule,
get their feedback by September 30th
and then we can do the redline after we see
what they've said?
-: I think we have to do the redline
in order to get this thing moving.
I don't know. -: We could proceed
in either path.
Y'all could agree on a starting point number today-
-: I'll do that. -: And we could bring a redline
to you before the October 7th open meeting.
Alternatively, you could give a few days,
a week between now and then, for input into what
that number should be.
-: So input between now and then could just be
filed under one of the projects,
a project open per Will's memo?
-: Yes. -: And that satisfies
the legal requirement for comment as we move forward.
I just don't want it to get delayed
so that we don't have implementation uncertainty
for consumers by January.
-: Anything that happens prior to us,
prior to y'all voting on a redline
is entirely discretionary.
-: Okay. -: That's right.
And I thank you, Will, for the leadership on that issue.
Having been representing the residential consumers
through this winter storm Uri,
it was a very traumatizing event to actually work
firsthand with the residential consumers
throughout that storm.
And there are a number of issues that I think need
to be addressed before the storm,
before the anniversary and this is one of 'em,
the price cap.
Although it doesn't translate directly
to residential bills, and it won't
because HB16 was passed and it bans
the wholesale price index plans
that were provided to residential and small commercial
consumers during the storm.
But it's still important to lower that cap,
for a variety of other reasons
and I support doing that in the most efficient manner
but also to get the feedback that we need
from the stakeholders on 4500.
Which we have hd a lot of stakeholders file
comments supporting 4500,
but I just wanna make sure that we get that feedback.
And I'm good with either way,
whether we get the feedback up front.
We could get it submitted in 52373.
We could get it submitted in a new project
that Commissioner McAdams wants to open
on ORDC specifically and get information
and then get the redline going,
because the clock doesn't start until the PFP,
the redline, we vote on the PFP.
So either way is good with me.
I think we're gonna meet the by the end of the year,
January deadline with either approach.
-: So let me make sure I've got the context
of what you're laying out,
and especially for the public.
Since the winter event Uri,
the high cap in the ERCOT market was moved
from 9000 to 2000. -: That's correct, sir.
-: So throughout the summer,
the high cap price in the ERCOT market
has been 2000, based on existing rules.
Those rules that will, based on the existing rules,
that $2000 mark will move back up to 9000 on January 1st,
which I think is, from my understanding-
-: That's why it's so pressing to address it in my mind.
-: Agreed.
And so the driving focus of your initiative here is to,
and part of your concern with the,
obviously protecting the Texas consumers,
both businesses and residential customers,
this initiative is to make sure that by January 1st,
instead of going back to the 9000,
which we've generally heard from the public
and our stakeholders is too high,
this project will be an accelerated version
of moving that high cap down through our Rule 25.505,
a very narrow scope of that. -: Yes, sir.
-: So that we can ensure Texans won't be charged $9000
in the event of another scarcity-
-: Event. -: Crisis.
We don't know what the number will be.
You're proposing a 4500, a 50% reduction
from the old high cap for consumers.
So that's a substantial reduction in potential liability
for Texas consumers.
And as part of that, from what I understand,
you're making a narrow focus in an accelerated rulemaking
so that it syncs with our broader market redesign blueprint,
so that those can go,
that we can open and close 25.505, have the rule in place,
have the new high cap in place before January 1st
and still have that rule available to us
for the broader blueprint.
-: Yes, sir.
-: Okay, yep.
I just wanna make sure to lay it out,
I got everything.
-: Can I ask one clarifying question
or make one clarification point?
So in our rule, there's the high cap,
there's the systemwide upper cap,
and there's the value of lost load.
-: Right.
-: So when you say changing the high cap,
will that change to the high cap also result,
are we still going to have the same number
for the systemwide upper cap and the value of lost load
because the value of lost load is what's included
in ORDC.
-: Go ahead.
-: I was just gonna say, that's my understanding.
Until we do the studies to determine
what the best value of lost load is, which-
-: Well, thankfully, lots of stakeholders
are doing studies for us- -: That's for sure.
-: To accommodate our accelerated timeline.
-: As per the rule, Commissioner Cobos,
two numbers are specified in relation to high cap.
And again, that's $9000 twice.
And so, and again, right now value of lost load,
that's kind of why I asked that question,
should we specify VOLL in rule?
-: I don't think so because my initial thought is no
because the whole action that we were able
to take with ORDC and being nimble with making those changes
would now require a rule change if we put VOLL in rule.
-: Right. -: But I do wanna point out
that in 25.505, subsection G, 6e,
it says the value of lost load will equal
to the value of the systemwide upper cap in effect.
-: Exactly, yes, yes.
-: Okay, so- -: Which one's setting which?
-: Well, that's why that 9000 specification is so important.
Everything moves off of that.
-: Okay, so we're going to get comment
on the HCAP and the systemwide upper cap.
We're thinking of them as the same figure?
-: Yes. -: Okay.
-: As of right now. -: Okay.
I just wanted to make sure I understood that
because of the ruling-
-: It's gonna be a real simple redline.
I expect 4500 to replace 9000 in those two spots.
-: Okay, great.
Thank you.
-: So do we want to,
if we wanna have it done,
and just by you mentioning this in terms
of the timing for proper rulemaking,
given the extraordinary circumstances
since the storm that we're all in,
this Commission has already moved forward
with critical rulemakings and an accelerated process.
I think we had a 10-day comment period
for the Phase 1 weatherization rule.
And I would certainly be comfortable
using a similarly accelerated timeline
for an issue as critical as this.
Of course, considering that we've already had months
of public comment on this included
in our many other elements of feedback for market redesign.
I guess it takes us back to,
do we want to pick a number from the dias,
starting with 4500, I'm fine with,
get with the stakeholders, evaluate that,
include that feedback in the comments due September 30th,
then work with staff to issue a redline?
And then October 7th, we've got a week
to process their comments.
October 7th, we can issue a proposed rule
using the same 10-day comment period we did
with weatherization.
That would get us to the 17th.
And from there we would, depending on how many comments
we get back from the public
during that official public comment period,
staff will respond, per the process.
And then I don't know the next open meeting after that.
-: The 27th, I think.
-: So the 27th of October, we could be adopting
a new VOLL high cap number that will,
and that would still leave November, December.
Yes, Ms. Speltzer, feel free to come up.
-: The 28th is the open meeting.
-: The 28th. -: The 28th?
-: So just for your context,
any proposal that you determine to publish
at the October 7th open meeting will appear
in the Texas Register on October 22nd.
It takes a little time to work its way
through the process.
But even so, I believe we could get comments
back and have it free at the November 4th open meeting
for adoption.
Peter: That would still leave essentially two months
for that rule change to be operationalized at ERCOT.
-: Correct.
Lori: Is it a requirement to wait to be published
in the Texas Register?
Because I believe we went through this discussion
with Barksdale with the weatherization rule.
Man: It is not but if we simply started counting
the 10 days from the 7th, the comments would be due
before it ever appeared in the Register.
So I would recommend at least allowing
a couple days after it's been in the Register,
which is considered our official notice.
-: Are you, I heard something about a series
of open meetings regarding securitization.
-: Yeah, so the 30th and the 8th.
-: The 30th of September and the 5th and 6th of October.
They're earlier than your focus here.
Peter: Is the Texas Register timeline,
is that by publication date or just by 14-day process
at the Register?
-: That's by publication date.
-: When's the next previous publication date?
-: Do you mean when's the publication date
before the 22nd? -: Yes.
-: There's a publication date on October 15th.
The submission date for that is October 4th.
-: Yes, so that's the problem.
Remember, the 30th open meeting has already been posted
and it's a limited agenda.
So it would have to be modified.
It's only covering those dockets related to securitization,
that's the problem. -: All right.
Stephen: You can post the meeting for the 4th.
-: Post the meeting for the 4th.
Woman: I mean, I think we're gonna be able
to get there with the PFP adoption on the-
-: And November 4th for adoption.
-: Yes. -: Okay.
-: And especially, I know it's a very narrow scope but-
-: It's very volatile. (everyone laughing)
-: Yes, sir.
And so that way we can get feedback.
Let's make sure we got your thinking right.
We're asking stakeholders in concurrence
with if there are market redesign comments
due to the Commission on the 30th.
We would also ask that they file comments
related to this very specific high cap
and VOLL component of the 25.505
by the 30th to the Commission.
You include that with the,
or do you want to open a separate project for that?
-: No.
Well, I don't wanna make life that much-
-: I would recommend opening a separate project.
-: You would, okay? -: Yes.
-: I didn't wanna step in there.
-: And then we'll proceed with your proposed rule
in that same new project.
-: Okay. -: That makes sense for you?
Lori: Makes sense for me.
-: Just that we'll open the new project
just on the very narrow component of 25.505
regarding VOLL and high cap.
September comments come back September 30th.
We will have a redline ready October 5th.
-: The 7th. -: Yes.
-: The 7th, sorry.
And with the goal of publishing that
in the Texas Register on the 22nd, Ms. Speltzer.
-: Yes. -: Okay.
And then with an appropriate 10-day public comment period.
Seven day? -: Seven day.
-: Seven-day public comment period,
which would be the 13th opportunity for the public
to comment on this since June.
Seven-day formal, official public comment period
from October 22nd to the 29th.
Staff will respond to those comments submitted
by the public and be prepared for the Commission
to formally adopt the rule at our October 4th open meeting.
-: November 4th. -: November 4th.
Woman: - November 4th.
-: I look forward to seeing this in the transcript.
That's a great plan. (everyone laughing)
Woman: Janice is the best.
-: I'm good with that, yes.
-: That'll work? -: Jimmy?
-: Yes.
-: And the only thing I wanted to say
with respect to your request for the proposals
and your encouragement of stakeholders submitting proposals
on the 30th, it would be really helpful
to get very specific stakeholder solutions
with an implementation path going forward,
whether that requires PUC rule change
and/or ERCOT protocol changes, system changes.
What is our implementation path going forward
to implement their recommended proposals?
And to the extent that stakeholders can get together
and jointly file proposals, that would be very helpful
because I feel like I've heard a variety of proposals
that have different elements of similarity.
If the stakeholders could get together
and agree to joint proposals,
that would also be very helpful for our evaluation
of those proposals.
-: Very good point.
Implementation is gonna be a key part of this.
And another thing in addition to that
is please also keep in mind the general context
of the proposals.
In the universe we're working in,
I suspect that my colleagues are not going
to be very excited about any new ancillary service product
that contains 70,000 megawatts over peak,
given that would be a capacity market or anything like that.
Also, please, please keep the real-life implementation
in context, in consideration, when you submit these.
All right, does staff have any other questions
or need any other action from us?
-: If I could just walk it back to confirm?
Today, we'll be opening a new project
to look at 25.505 for the very limited purpose
that you have outlined here today
and we will file a request for comments
on that very limited issue.
Given that it is such a limited issue,
the comments will be limited in page number.
Peter: Yes.
-: Can we limit the number of lines?
(everyone laughing)
-: What were you thinking about in terms of page numbers?
-: Five.
Five pages.
We're talking about a number and one issue
about VOLL and high caps.
Peter: That's a narrow scope.
Two?
What are you feeling here?
-: Five, because again, you want the back cast analysis
to describe how it will increase pressure
on generators, you name it.
-: Okay, good? -: That's good.
-: All right, and for our stakeholder community,
the tentative proposal starting point
from Commissioner McAdams is 4500,
50% reduction from current high cap.
Any thoughts on- -: The number?
-: Makes sense?
-: That makes sense to me.
I'm comfortable with starting at 4500.
-: Absolutely. -: All right.
-: And I'll just add to Commissioner Cobos' comment
about the filings in 52373,
the market design recommendations,
staff's been having informal conversations
with market participants and asking them to work,
once all the filings are in,
to review one another's and come prepared
to the October 14th workshop,
to discuss comparison and contrast among the proposals,
their own and other parties'.
-: Yeah, so there's value in seeing what everybody,
or a large segment of people, agree on.
But there's also value in seeing,
which is your point, let's see where the consensus is
but that's also, that doesn't mean to discard other ideas.
So we can see whether there's consensus,
which is one universe, but also see other ideas
that may be worth learning about
and certainly I don't think any of us
will be afraid to pick and choose
and take components from any or all of these.
-: What about Brattle?
I think that's important as well.
So we will have Brattle at the October 14th work session?
Woman: Yes.
-: Yes, ERCOT has retained the Brattle Group
as the in-house consulting firm to help
both ERCOT and the Commission
as we move through this process.
And they have been working and will be working
with ERCOT staff and PUC staff
and will be available at that open work session
on October 14th.
Good point.
Thank you for reminding me. -: Absolutely.
-: All right.
-: Thanks, Mr. Chairman.
-: Thank you.
That's a big move critical to that January 1st timeline.
That is a major consumer protection item.
That will bring us to item 17,
related to energy regional state committee.
Staff has filed a memo on this.
Come on up.
We'll call up Warner Roth and Justin Atkins
from Commission staff.
-: Warner Roth on behalf of Commission staff.
The memo I filed in the SVP
and MISO dockets is related to FERC docket RM21-17,
related to the advanced notice of proposed rulemaking
on building for the future through electric
regional transmission planning, cost allocation,
and generation interconnection.
This is a broad advance of a rulemaking.
A broad docket opened up to review a more,
to take a more holistic view
of FERC's transmission planning processes,
transmission cost allocation processes,
and the generation interconnection processes
for FERC jurisdiction RTOs.
This could potentially have significant ramifications
on shifting costs, changing how transmission planning
is done in FERC jurisdictions.
So in any of the non-ERCOT areas,
I know that the SVP Regional State Committee
and the Organization of MISO States
are both considering making comments in this docket,
both in the initial phase and in response
to other commenters later on.
I am making a recommendation for the Commission
to file an intervention in this docket
so that we may engage with our outside counsel
in making sure our interests are protected in this docket.
-: Fair enough, thank you.
Any thoughts, comments, concerns?
-: Just having watched the interstate traffic on this
and by that I mean filing traffic,
I think it's consistent that Texas start
to stake out our own position
and I like Warner's recommendation.
-: Absolutely.
I know MISO was looking at some long-term
transmission planning issues and cost allocation.
I think it's really important that we get involved
in these issues at the federal level
and also at the MISO level.
-: So I would, I agree that we should have this intervention
in this way.
I hope that in the future, we can put more meat
on the bone when we have an intervention
and talk about really what our issues are,
especially in light of the winter storm.
We've got parts of Texas that are in both
of these regions and transmission planning,
use of emergency power, all of the issues
that are wrapped up into this issue
could be valuable to our citizens
that live in those non-ERCOT areas.
And I feel it's incumbent upon us
to be participating in those process.
I think as it stands now, I may be wrong
but MISO South doesn't even have any transmission
proposed right now.
And that's a challenge.
I think that area was hit just as hard
as many other regions during winter storm Uri.
And if there are things that we need
for our consumers in Texas, we have to use this process.
We've gotta get in there and we've gotta roll our sleeves up
and do it and participate.
-: Agreed, we do need transmission to ensure reliability
in the areas of the state that are not within ERCOT.
Those are very important areas of our state as well.
And also to make sure that those ratepayers
are not being allocated costs for other parts
of those other ISO RTOs that they are not getting
the benefit for.
-: And one other thing that I wanna say
is these committees and regions, MISO, SPP,
even PJM and others,
they're not easy games to play in.
They're established players there.
They have relationships.
Commissions change and right when you get
to know some Commissioners,
they change on the RSCs and stuff.
And us getting in there and building relationships
and having them understand what we want
and what we need is as important as anything.
So I think that again, us being involved in these
is really important.
And I know it takes staff time,
I know it takes Commissioner time
but it's a part of the state that we can't ignore.
They represent a lot of Texans.
-: I'd agree with you, Commissioner.
The trend for the rest of the country, MISO, SVP,
they've been, similar to ERCOT,
so many issues have been at log jams and logger heads
for so long.
I think FERC is starting to press a little bit
to break some log jams.
And that will necessitate Texas being very well-acquainted
with those processes and engaged
because even with the slivers that we do have
in those ISOs, we are a big part of their load
and must be engaged.
-: Well, we do have one other market that's not covered
right now by Commissioner McAdams and I
and that's WAC, the western part of the grid
where El Paso is.
So that might be something that,
I'm not giving an assignment
but since I've had my fair share-
-: Do I hear a fifth Commissioner coming?
I'm kidding.
-: Item up for discussion, absolutely.
-: Yeah, any interest in taking on that charge?
-: Perhaps.
-: All right.
Look forward to exploring that opportunity.
All right, Mr. Roth, thank you for laying that out.
Is there a motion to authorize the PUC
to file a dockless intervention
in the FERC docket number RM-21-17,
directing staff and an outside counsel
to monitor this FERC proceeding?
-: So moved. -: Second.
-: All in favor, say aye. -: Aye.
-: Motion passes.
Thank you, sir.
We are not, well I guess 18 and 19 were covered
under the previous item.
And that will bring us to item 20,
regarding transmission and its relation to reliability.
We've had several entities file material
on this in response to Commissioner Cobos' memo.
And I suspect Commissioner Cobos
has some thoughts and suggestions.
-: Thank you, Chairman Lake.
Just for background purposes,
this is a follow-up on our discussion
from the September 2nd open meeting
and in response to Chairman Lake's action items,
during that open meeting,
I requested that ERCOT file additional information
regarding long-term and other interim transmission
improvements to help ensure reliability in the
Rio Grande Valley.
Also information related to the boundary threshold used
by ERCOT in transmission planning for reliability purposes,
and to also provide us an update on ERCOT's ability
to implement the new consumer benefits test
that is required by Senate Bill 1281.
Woody Rickerson is here today to discuss their filing.
And while Woody makes his way up here,
I will also say that on September 14th,
I filed a memo requesting that the transmission service
providers that would be responsible
for building the interim transmission improvements
that we had ERCOT and those companies evaluate,
which included a second circuit
from San Miguel to Palmito
and a new transmission facility to close the loop
from Palmito to Edinburgh.
I requested that those transmission service providers
follow their estimated timelines and costs
to build their respective portions of those facilities
and they filed them on September 20th.
And I requested that representatives of Stack,
AUP/ETT and Cherryland be here today,
in case we have any questions,
after we walk through ERCOT's filing.
-: Where would you like me to start?
-: Just at the top with Rio Grande Valley.
-: So my name is Woody Rickerson.
I'm the Vice President of Grid Planning
and Operations at ERCOT.
So we'll start with the Rio Grande Valley.
Most of the demand of the Rio Grande Valley
is in Cameron, Hidalgo Starr, and Woolsey Counties,
which is further south.
The summer peak demand in that area
is projected to reach 3200 megawatts in 2026.
Using our established planning criteria,
the existing system, if you don't have any major outages,
can reliably serve load up through that point
and then system changes will be needed in 2027.
That's the kind of status of where we are right now.
Peter: System changes will need to have been
completed by 2027.
Jimmy: Required.
-: And why?
Is that a reliability need that arises in 2027?
-: That's a reliability need.
The existing system will no longer
be able to reliably serve, without having overloads,
physical overloads of the system,
the load that's in that area in 2027.
-: So they can serve, just in layman's terms,
right now the existing transmission can serve 3200 megawatts
of load, based on projections.
After 2026, it will not be able to serve-
Woody: That's right.
-: Any increased load beyond that.
Woody: Right.
-: So we don't need to start in 2026,
we need to start sooner.
-: Absolutely, yeah.
So yes.
Just a little more background on that area,
it's primarily connected to the rest of ERCOT
through three 345 kb lines.
Those are long lines.
They're series compensated, which has its own
stability issues.
Two of those lines run parallel to the coast
and make them susceptible to hurricane damage,
which is a constant concern that we have.
But not something that is directly accounted
for in planning standards.
-: Woody, do you know when those three circuits
were put in place, were placed into service, what year?
And I did ask the TSPs as well
but just for context, if you can at this time?
-: So the 345 line coming from Laredo
was put in place in 2016.
So that westernmost line runs parallel to the Rio Grande
was 2016.
Lori: All of it?
From San Miguel to Palmito?
-: From, you might have to get some of the TSPs
up here to help me on that.
But from Laredo down to the lower Rio Grande Valley,
that was completed in 2016.
The other two lines, I don't know for sure
when those were put in place.
It was prior to the year 2000 though.
-: Yeah, so in terms of the western leg,
the San Miguel-
Peter: State your name and who you're with.
-: Piece was put in place, energized in 2010.
Lori: Can you please state your name and who you're with?
-: I'm sorry.
Wayman Smith with American Electric Power Service Corp,
here for AUP Texas and ETT.
Lori: Okay, and please continue, what year?
-: 2010 for the San Miguel to Lobo portion.
And then, as Woody indicated, from Lobo to Palmito, 2016.
And then, as he alluded to, the two 345s
on the east side of the valley have been in place for awhile
but those were actually reconductored
in that 2016 timeframe as well.
Peter: So continuing on,
just a little bit more background information.
-: Can I ask you one question?
You said that the two easternmost lines
that are hurricane susceptible are not,
that's not modeled into our transmission planning standards?
-: Well, the fact that they are vulnerable
because they're on the coast,
doesn't give them any special treatment
in our planning standards.
-: But is there any, should there be?
I guess that's the question.
-: Well, I think- -: Since there are
three lines that go to the valley
and two of them are susceptible to hurricanes.
-: I think that's an integral part
of what our recommendation is today actually.
-: Okay.
-: There is also limited conventional generation capacity
in the Rio Grande Valley and there's no new planned
conventional generation down there either.
There's also a, we may have as much
as seven gigawatts of our wind and solar generation
there as well.
So there's a lot of that that's coming on.
Will: Coming on or is it there, Woody?
-: A lot of it's there but there's a lot of growth there too.
So we could still have seven gigawatts of wind and solar.
-: The implication being that if the wind's blowing
and the sun's shining there,
there's more power supply than is needed
at the current time and with transmission constraints,
it can't get to the rest of Texas?
-: Transmission definitely has constraints there, yeah.
-: And it's Gulf Coast wind?
-: Some of it's Gulf Coast wind
and some of it is along the Rio Grande Valley
or along the Rio Grande, there's a lot in that area too,
which has a little bit different characteristic
than the Gulf wind does.
-: And that Gulf Coast wind is more
of a non-peak wind resource?
-: That's correct, the Gulf Coast wind
has a higher on-peak capacity factor than the non
or wind that's located in other areas.
And finally, the other thing I'd point out
is that we currently have
16 generic transmission constraints
that have to do with stability limits
in the entire ERCOT grid.
Seven of those are in the Rio Grande Valley.
And that has to do with the amount of invertebrate
generation that's there and also the fact
that Rio Grande Valley is on the edge of the system
and somewhat isolated from the rest of the grid.
So all these factors that we're talking about,
the relative isolation of the Rio Grande Valley
being on the edge of our system,
being a long ways from a lot of the rest of the system,
the susceptibility to hurricane damage,
load growth, it's a growing area,
the number of GTCs and the stability concerns
we have there, the penetration level of the wind and solar,
the fact that we have outage coordination issues there.
If someone wants to take a plant out of service,
it's very difficult for them to do that.
If someone wants to take a 345 line out for service,
it's very difficult to coordinate those outages as well.
Those outages can't occur right now
during anything near a peak condition.
They have to occur during off-peak conditions.
And when you have competing entities
wanting to take those same outages,
it becomes very difficult too to coordinate outages.
And that's for both transmission and generation.
And also the three lines that are coming in
are series compensated, which causes stability concerns
and it also causes sub-synchronous residence issues
with generators.
That's the price you pay for putting the series compensation
in on those lines.
But all of those factors,
we have those factors in other places in the grid as well.
But I think the Rio Grande Valley may be the only place
where all of those factors are part of the story.
And so that combination of all of those factors
makes the Rio Grande Valley unique
and it also stretches our planning criteria
that we currently have.
So in order to-
Jimmy: What do you mean stretches the planning criteria?
-: It puts us right on the edge
of having to rely on the system all the time.
We're just in time with improvements.
Jimmy: So more transmission would probably be better.
-: More transmission would be better.
-: Getting more transmission causes reliability issues,
which prevents getting more transmission.
-: So in order to address that combination of factors,
we looked at, along with the TSPs,
we've looked at multiple transmission solutions down there
and there was a short list that was filed with you
of two long-term improvement options
for the Rio Grande Valley.
Those two options have some things in common.
They involve a 345 line that comes from San Miguel
and goes into the Rio Grande Valley.
It also involves another 345 line
that cuts across from the Laredo area
to about halfway between Corpus and the Rio Grande Valley,
so it's kind of a cross.
And there's two different versions of that.
Of those two versions, option two is the plan
that ERCOT recommends to ensure that the grid
continues to serve the load.
So if you compare the two options
that's on slide seven for you,
the two options are pretty similar
in the estimated 345 kb right-of-way that they require.
The estimated cost is similar.
But option two is significantly better
because of stability constraints, SSR mitigation.
It's further from the coast so it reduces
the impact of potential hurricane damage.
And so we recommend that the option two
is the preferred option.
It's a tier one project.
A CCN will be required.
We've presented this to the Regional Planning Group
on September 15th and we're collecting comments now.
Unless directed otherwise, we plan on seeking
TAC review and board enforcement money
into the year for that option two.
-: Woody, is that option two, the 345 kb
is double-circuit capable?
Is it gonna include two circuits or one circuit?
-: It will be two circuits.
-: When it's built? -: Yes.
-: Okay.
-: So Woody, on costs, sorry, I gotta look at that.
That's a lot.
-: Big numbers. -: Those are big numbers.
Those are CREZ type numbers, ballpark ish.
But what we get out of that is you use latest technology,
you kind of have a hardened system,
it's interior, and I'm trying to frame this
for the hew and cry that's sure to come up.
-: Well, it would supply the needs of the Valley
from a low-growth perspective through 2040.
Will: Through 2040, yep, all right, got it.
-: So the reliability need that would present itself
in 2027 would be moved back to 2040?
-: Yes. -: At least.
-: That would be greater than 2040.
Our load forecasting gets a little hazy
when you get out that many years.
But up until at least 2040,
we don't see any more reliability issues
serving load in the Valley.
-: And what were the alternatives that you,
I'm sure there were a handful of them.
You don't have to go through every single one of them.
But obviously, building a $1.2 billion line,
requiring likely 100% new right away
through the center part of the Rio Grande Valley is hard.
I know that's hard work.
I know siting transmission, working with landowners,
it's a hard thing.
So what were the comparison points
that made you all say oh,
this is 100% worth it and the other ones aren't?
-: The main option we compared against
was very similar in nature.
It required very similar lines,
the endpoints were a little bit different,
it was not quite as good an option
because of outage coordination issues
and also because it doesn't help as much
with the SSR issues that the other line did.
So as far as cost goes, it's was a very similar cost.
As far as right-of-way goes,
it's very similar in right-of-way.
The option two thought definitely had some advantages
in outage coordination, in SSR reduction.
A little bit further from the coast
so it's a little less likely to have hurricane damage
and things like that.
Now, there are some other options there.
There are some existing,
those existing 345 lines, there is an option
on the one that comes down the Rio Grande there,
you could add a second circuit there
and that's not as costly.
However, it is not what we recommend
as a reliability project.
It would be continuing to do what we've done
in the past, which is just one step ahead.
Someone described that as you've got
the tachometer on your car is in the yellow.
It's not in the red yet, it's in the yellow.
That second circuit would mean keeping that tachometer
in the yellow.
Building this takes us back out
so we have a little more margin.
-: I just wanna provide a point of clarification
because I've had filings specifically made to me,
and I'm not the only one making the decision here
on the Rio Grande Valley.
I think my peers and I are extremely interested
in ensuring reliability in the Rio Grande Valley.
So I'm responding to the letters that were provided,
and that is there's a lot of confusion out there
that I hear in the ERCOT stakeholder process
and concerns with the second circuit.
And the concern being that the second circuit shouldn't be
a replacement for the new option two long-term project.
And I just wanna be very clear that
at no time did I ever say that it was an either/or
or versus project.
But somehow the messaging has gotten confused
and there's been a lot of pushback
on the second circuit saying,
it's not an option for replacing the new project
or deferring it.
And I just wanna be very clear that that has
never been the case.
We're looking at both of them.
It's an and, not an either/or.
And so I just want to level set there and be very clear.
Okay.
And when you say it's not gonna
to provide a reliability benefit,
in your presentation today,
you say that it pushes back the reliability need
from 2027 to 2033.
How long is it gonna take to build a new project?
What's your best cost estimate?
-: Option two estimate is that it will be completed in 2027.
Lori: Option two in four years.
Okay, what's your best estimate for completing that project?
-: No, we think that option two,
we could complete that in five years.
So we're sitting here today, if you start in 2022,
that'd be '26.
-: Right when you were about to hit the red.
Okay, so then on the second circuit,
and I know you're gonna cover it in a minute,
but I just wanna make sure that this is clear too,
is that in the filings I've received,
most of the line that's owned by AUP/EDT is 34 months,
if you do it hot.
And so if you're looking at it as an second circuit
and new 345 kb project, you are,
most likely the construction it appears,
and please clarify me if I'm wrong,
that if we decided to add a second circuit,
then that second circuit would be put in place
maybe a year or two, maybe even three,
before the new project.
So then you'd have a staggered,
sort of phased implementation of new infrastructure
that would both provide reliability to the Valley.
So Woody, in your opinion, would both of those options
provide a reliability benefit together to the Valley?
-: The second circuit definitely has a reliability benefit
to the Valley.
It does push that need out as well.
Yes.
And option two definitely has,
I mean, that's the fix for the Valley.
That is the ERCOT recommendation.
The second circuit also has a reliability benefit,
but we just don't wanna see that ultimate fix
get pushed back.
-: Right, and again, it's not an either/or or versus,
it's an and that I'm looking at.
-: When the original lines were built,
the Laredo to Rio Grande Valley and such,
and I'm assuming here this is, and correct me if I'm wrong,
that they were all single circuits
and they were put on double-circuit towers.
Is that right?
If everybody's pushing back saying we shouldn't
put another circuit there,
then why did we go and use double-circuit towers
and put that in rate-based,
if that was never gonna be a opportunity
to double-circuit those structures?
-: Yeah, if I could maybe, maybe add a little bit of clarity.
I think that the concern was maybe in the way
this was maybe packaged a little bit in the PowerPoints
because it says, well, if you string second circuits,
that pushes out the reliability need until 2033,
which might lead you to the conclusion,
oh, well, we don't need anything 'til 2033.
Let's just kick the can down the road
on a long-term option two solution.
And I think that was the concern.
Peter: I just heard a recommendation not
to build the second circuit.
-: Well, I- -: And I would appreciate
the concerns being brought to my office
instead of being voiced at RPG
against the Commission suggestion.
And maybe coming to my office before you decide
to write me letters.
-: Understood.
But just to be clear, from AUP, Texas ETT perspective,
does the second circuit have value?
Absolutely.
It has value.
It improves the load serving capability.
As a short-term, interim solution,
until we can get that long-term solution in place,
does that make sense?
It absolutely provides a value.
But I just, in my mind I would be concerned
that not to let that overshadow our need
for that for a source.
-: Okay, 'cause I mean, I guess I've been a little confused
with the filings I got on Monday the 20th
versus the letter I got last night
with respect to how AUP/ETT feels about the second circuit.
Because in my meetings directly with Mr. Fox
and there was a lot of interest in, you know,
there seemed to be no issues, no reliability risk
with the second circuit, y'all can do it hot,
you can get it done, get it done quickly,
get it done quicker than ERCOT says.
And then all of a sudden I'm getting a letter last night
saying, well, you know,
it might get more complicated and no mention
of the hot work.
And again, trying to combine the two projects
as competing projects.
So that's what I'm concerned about
is that I've gotten mixed messages.
The last thing we wanna do is disturb existing reliability
in the Valley.
That's the last thing we wanna do.
We want to bring additional reliability to the Valley.
So if we were to order the second circuit,
we would want that done in the best way possible
to maintain existing reliability in the Valley.
Woody: Absolutely, understood.
-: And I have been assured by your company, ETT,
that you can do it hot, you can do it reliably.
ERCOT has to approve and coordinate outages.
But I want to make sure we're going
to order that line, that it's going to done,
that that second circuit is gonna be built reliably.
So we're not gonna put the Valley at risk,
although having one line there for so long,
that's built for two lines, double-circuit capable
for so long, for at least 11 years part of it,
has put us in a bind now,
because now we have infrastructure there that we want
to add another line.
And so now there's this reliability coordinating outage.
I mean, it should have just been built
with the two circuits that from the beginning,
it sounds like.
I would like to understand why it wasn't.
If it was approved, if a CCN was approved
for a 345 double-circuit capable transmission line
and the ratepayers are paying for extra infrastructure
for a second line, why wasn't the second line added?
-: Yeah, the short answer is adding
the second circuit adds cost.
And if we can not,
at the time those decisions were made,
if we cannot definitively show, based on ERCOT
planning criteria, that there's a need
for that additional capacity associated
with the second circuit, it doesn't get endorsed.
-: Have you brought it forward since
for ERCOT to review in the last five, 10 years?
Because the Valley has exploded in population
and economic growth, and I'm surprised to hear
that there's just no need.
-: No, we have, AUP has made two RPG filings
since that line was put in service in 2016,
we have made two RPG filings.
In both of those RPG filings, we looked at alternatives
that included the new bringing a fourth source
in as well as stringing the second circuits.
And in neither case, did we get endorsement
because we said, well, the need date is further out
so we're gonna, put a band-aid on it
and we're going to put additional dynamic reactive
in the Valley, we're gonna push it out a little bit more.
And so far that has been the decision.
But we have brought that forward.
We have brought forward both a new source
as well as stringing the second circuit.
-: Okay.
Well, the band-aid seems to be the reason
why we're always playing catch up in the Valley.
-: 100% agree.
-: And no other dispatchable resource
to any degree is moving into the valley
and that's this catch-up problem.
ID generation, to help levelize this.
And we can't have it islanded.
And at the end of the day,
that's a policy decision for the State of Texas
and certainly us.
That's what's coming in here
and if option two is one of those right choices,
and I appreciate this briefing because it helps frame it
at 1.28 billion.
And then the other options,
which redundancy is helpful in a disaster-prone area,
that is currently islanded-
-: And the most western line. -: Yes, ma'am.
400 to 450 million.
Look, we've gotta envision it as a whole.
That happens to be the cost of a combined cycle gas plant,
somewhere in the valley, if it was ever to deploy.
-: I will say, and I wanna be clear,
that I do think that the new long-term project
has a lot of value and ERCOT supports it.
It has a plethora of value for the Valley.
And two, with respect to your cost concerns,
in no way will we be making a cost of determination
with our discussions or any actions that we make.
Woody: Right, understood.
-: Today. -: Today.
It is not a blank check.
As Chairman Lake has said in prior open meeting,
it is not a blank check.
The utilities would still be expected to meet
rate making principles and standards
that comply with PURA and the Commission's rules.
So whatever actions, if we take any actions on this
from our dias ordering construction,
that it's no determination on costs.
-: Sure. -: We will still expect staff
to review those costs, as they would review all other
transmission-related and other costs in a rate case.
-: I would want to chime in on the cost issue.
And that is I've scratched my head a little bit
to figure out where $450 million comes
from on a second circuit on existing structures
and existing rights of way.
I know there are three new substations,
but adding a second circuit.
So I struggle with that.
So I'd love to have some more input
on why a second circuit costs so much
on an existing structure.
And I would assume, again, I could be very, very wrong,
but when you built the first structure
and the single circuit,
you probably built the substations
in such that that could be added to,
if you were gonna add a second circuit.
So it begs my question of why would you need
three more substations?
So if you can just kind of fill me in
on a little bit of that, that'd be great.
-: I will and I'll try.
I have a hard time doing it sometimes
without drawing on a board.
But the short answer is the existing structures
are double-circuit capable, but the arms
are not on the structures. -: Okay.
-: So, they're set up, they're drilled and tapped
to add the other arm, but the other arm's not there.
So there's a lot of costs involved there, number one.
And then the second issue is when you make turns,
you can't make those turns,
we refer to them as heavy angles.
The really severe turns,
you can't make those with circuits
on both sides of the towers.
And so what happens is when you get to one of those turns,
you have a single structure that each circuit will hit
in order to make the bend.
And so every place, there's a turn,
we have to go put a structure there, it's not there today.
So it's the combination of,
from a material and engineering and design perspective,
it's one adding that second arm to the existing structures,
and then two, setting all of the structures
that are needed to make those turns.
And when you look at those estimates, in particular,
between the Lobo to North Ed section versus
North Ed to Palmito, there's a significant difference
in costs for stringing the second circuit
on those two sections.
And it gets back to what I just said.
The section from North Ed to Palmito,
there are a bunch of turns,
twists and turns as you traverse that circuit.
So you have to set a bunch of additional structures
in order to make all those turns.
-: Those three new substations.
I mean, substations are expensive
and in some cases are needed.
And in your filing on September 20th,
you say that three substations are needed
for three wind farms. -: Correct.
-: Can you clarify, why?
-: Yeah, so, so, so what happened is
in order to connect those wind farms,
we built circuits, radial if you will,
out of existing stations,
utilizing portions of the open second circuit.
And it's hard to see without a picture,
but basically you have, for example,
a line coming out of the Del Sol station.
Utilizing that second circuit open position for say,
15, 20 miles, and then going back
and then going back to the wind farm.
And so what happens when we string the second circuit,
at the point where that line going to the wind farm
comes in and hits the existing structure,
we have to put a station there.
And those are the three stations that we're talking about.
-: So to come to this conclusion,
did you run power flow models?
-: I'm sorry. -: Power flow models.
-: Oh, I'm asking him, sorry.
I just happened to look at you.
-: I'm sorry, I didn't.
-: In coming up with the determination
that you need those three wind farms,
did you just run power flow models
or has actual modeling work been done
to support that conclusion?
-: Well, those are just requests by the generators
to interconnect our system.
So we have an obligation to connect them
and that was the lowest cost way
to connect those generators.
-: So you're combining two things.
You're combining an interconnection issue
with a reconductoring issue and trying
to optimize that to figure out the best way
to solve both, is that right?
In that cost bundle, in that cost structure?
-: Yeah, so we got a request for interconnections
from these generators and we said okay,
what's the most economical way to connect them.
Well, we've got an open circuit
on an existing line.
Let's use what's there, as much as we can.
And so we strung some of that second circuit
when we connected them.
And so that's, there's roughly 70 miles
along that line that already has the conductor
hanging on the second circuit, already has the arms.
So that works to our benefit.
But where the line directly coming
from the generator comes in and hits
the existing line, we have to put a station there
to terminate it.
-: I think that makes sense.
I'm not gonna sit up here and argue against the engineering.
But I think, from my standpoint,
the papers that have been submitted
were kind of lump sums saying a double circuit
with three new substations costs 400
and something million dollars.
And a little bit more understanding
of the components of that cost would be hugely valuable
for me and I think everybody.
I hope, quite frankly, that we look
at this solution of adding second circuits
to towers that are double-circuit capable
as a first alternative to building some more transmission
in the state.
-: Yeah, and just to dovetail on that,
I'm not opposed to any of this.
Even if you lump sum it,
I put this in the context of look,
we've got $1.4 billion a year going out the door
on transmission congestion costs.
So anything that helps to offset that
and you're in one of those prone areas
of the state that helps you operate more efficiently,
and again, load growth is coming in that area.
So no, I wouldn't slam the door closed
on any of this.
It's just a question of how to most efficiently do it
and hit your targets.
-: So I think one of the,
and please correct me if I'm wrong,
but it sounds like to me that when you build
a 345 kb double-circuit capable line,
as you did, and part of it was in I guess 2010
and the other part of it was in 2016,
it seems like the longer you wait,
the more the system changes.
And you end up dropping a radial line
to some wind farms and some lines
and it makes it harder to add the second circuit later on.
Depending on what region of the state you're in
and what the factors are, it just seems to get complicated.
-: Yeah, I would say, if the second circuit were there,
what we would do to connect those generators
would be the same as where we're gonna end up.
We would still have to build a station
on that second circuit and then run a radial line
out to the generator.
So what we end up with will be the same
as if the second circuit had been there,
we're just doing it in a little different order.
-: So, and you might have already answered,
Commissioner Glotfelty,
but how much would those substations cost?
A ballpark figure.
-: Those are in the 15, $16 million range.
So you're talking about 45, 50 million
for those three stations
and then you've also got station expansions
at the other intermediate stations along the way,
just to terminate the new circuit.
So we have to add terminals at the other stations
just for adding the second circuit.
Just those three stations lone
is in the 45, $50 million range.
-: Okay, so thank you.
And Woody, do you have any more to add
on that slide that covers the interim options?
With respect to the loop,
can you give me some background on that
and what are ERCOT's ultimate recommendations
on the second, on the little close the loop project?
-: On the closing the loop project?
It's not part of our reliability recommendation.
It has benefit.
You can serve more load with the loop closed.
It gives you more operational flexibility.
But our reliability recommendation is that option two,
building a new line down from San Miguel
in the crosspiece as well.
Peter: But not the double circuit?
-: No, that's not part of our recommendation.
Lori: Part of your recommendation
for long-term reliability.
-: Right.
-: But we're doing both, provide more reliability benefits
together?
-: Closing the loop, adding the second circuit
definitely that has benefit to the Rio Grande Valley
in terms of reliability.
There is benefit there.
Our recommendation is the option two
and we just don't wanna see anything delay that
because that is the fix that we need
to get out of this just-in-time,
having things ready just in time for the next piece
of load growth.
Peter: Like option two.
-: Option two would be a-
Peter: Just-in-time.
-: It would be a step change in what we've done in the past.
For example, what we've done in the past is
if we were gonna build a double-circuit capable line
into the valley, we would look at it
and we would say one circuit is adequate
to serve the load for the next five years.
So let's just fund one circuit.
That will get us through the next five years.
And then we look and say well load growth is up now
so we need to add the second circuit.
But what this is is kind of a kickstart
all the way to 2040 and it gets you above
that just-in-time mentality.
And the reason that just-in-time mentality is a problem
in the Rio Grande Valley is because
of all those reasons I listed before.
It's isolated, hurricane, limited generation,
lots of RR being built there.
So all those factors add up there to make,
I mentioned before, it stretches our planning criteria.
So if our planning criteria has some flaws in it
or some holes in it, the Rio Grande Valley exposes those.
That's what makes that unique.
And we've seen this a little bit before
in Far West Texas.
Once again, fast load growth, on the edge of the system-
-: At the end of the line. -: Needs big changes
to catch up with and we were in the same kind
of situation in serving that area as well,
struggling between just-in-time fixes,
small, incremental fixes versus large step changes.
And I think you see that on the edges of our system.
You see it in places where load growth
is exceptionally high or higher than what we normally see.
-: So what I'm hearing you say, Woody,
is that if ERCOT wanted us to pick a path going forward,
it would be the long-term, option two solution.
-: Right. -: But if the Commission wanted
to move forward with two projects,
one being the long-term and one being the second circuit,
that together would provide reliability.
-: That's right, my control room,
my outage coordinators, my planners,
they all would prefer both
from a operating the system standpoint.
-: Okay, would your operators, planners,
control room have reliability concerns
with adding the second circuit
if it was done appropriately in coordination with ERCOT's
processes and even if it was done hot?
We don't want to present a risk to existing reliability
in the Valley and I need to hear it clear and now.
-: Okay, so here's as clear as I can state it.
Strictly speaking with our planning criteria,
it would not be an issue there
because we should be fine through 2026
and the second circuit can be added before then.
However, we are one bad hurricane away
from losing the 345 line.
The thermal generation that's in the Valley
is getting older.
A six-month overhaul of one of those units
that occurs over the summer would put us
in a really bad place.
And our planning criteria doesn't compensate for that.
So if we continue business as usual
and we don't have those kinds of bad outages,
then I think that would be fine.
However, we're right there in the yellow zone.
We're one bad thing away from losing
one of those key pieces that serves load down there.
We got the three lines and four big units
or three big units.
-: Are the eastern lines, are they double-circuited
or are they single circuits?
-: They're double circuits.
-: Okay.
But the hurricane pole lines are double circuit?
-: I'm gonna have questions.
You'll like it.
So put it another way,
second circuit on the western edge
in the near-term provides a near-term level
of redundancy sooner than you have
to guard against hurricane disruption,
generator outages, because what we're learning
is that it's happening,
and any type of unforeseen event in the near-term.
It gets you there quicker but ultimately
the path down the middle of south Texas,
again, option two, gets us that long-term breathing room
to where we can absorb any potential scenarios
of load growth well into the future.
-: That's right.
-: You go back to my tachometer analogy,
four years from now, we're gonna be sitting here
and we're still gonna be in the yellow.
Will: Yeah, I hear you.
-: Adding a second circuit doesn't add another pathway
into the Valley.
You have three now, you'll have three then.
Will: Right, but it gives you a crutch to lean on
if something bad happens. -: It gives you a crutch
to lean on, that's right.
But it doesn't-
-: Or if God forbid, the option two construction
isn't completed exactly in time,
precisely on the date in 2026.
I know that's never happened before.
Woody: That is some insurance of that as well.
-: Right, okay, so to kind of sum this up,
we can wrap up this part of the presentation.
It sounds like with respect to the long-erm project,
option two, we all agree that it's important
for the Rio Grande Valley and we want
to see that project continue to go forward at ERCOT.
I would recommend that we request from ERCOT
that we have that project endorsed by the end of the year.
-: Okay. -: Okay,
so by the end of the year.
-: Through the standard, current process.
The normal process. -: Through the normal process
and for ERCOT to deem it critical for liability
so that when we get the CCN we can process it
in six months.
And then I would like to hear
from the companies and their counsel
how quickly they can put together a CCN application
because we wanna wrap up this long-term project
as fast as we can.
So if we don't have a timeline estimate here today,
file one and let us know.
And I would also say, as you get ready to file a CCN,
because we're basically saying right now today
that we support ERCOT and their option two.
So that's enough guidance to start preparing your CCN
and I would also say that when you file that CCN,
prepare to file your direct testimony at the same time
so that we can save time.
And then we'll look to see what
other procedural efficiencies we can squeeze out
within that six month timeframe.
That would be my recommendation for the long-term project.
-: Can I ask a couple of things?
First of all, Woody, you kind of hit a nerve with me
with something that I don't like
about reliability assessments that come from NERC or any RTO
is they go, we're gonna be great for the winter except
or however.
It's always the contingency.
If one big generator trips or
if one big transmission line fails.
And that's what we found ourselves in.
And I know that's planning criteria across the US
but we have to be more diligent about it than that.
And I hope we could get,
and obviously there's a cost here,
but we could get to the place where it's,
even if we have one of those circuits in the Valley go down,
we are still gonna be okay in the Rio Grande Valley.
If we do have a hurricane.
And that's where we need to think about this
from a reliability perspective.
Obviously, the cost of reliability goes up
the more reliable you want the system.
But to me, just in time's not getting it.
I said a couple of open meetings ago,
the fact that quote/unquote, we gold-plated the system
or people were accused of gold-plating the system
when we built coal and nuclear plants, thank God.
Guess what?
We're using all of that capacity today and it's needed.
So I want you all to think ahead.
I want you all to think about these towers
that you can add a second circuit.
I want you to think about these big time reliability
projects that are necessary for 2040.
We're not gonna get too many bites at the apple,
I don't believe.
And I'm not saying that all transmission,
this isn't a run to the PUC to put every bit
of transmission we can in the rate base,
I don't believe that.
But there are projects that are needed
that I hope we can use our authority.
I think the legislature has been clear,
the Governor has been clear and other leaders,
let's get it done.
And we want to take advantage of that
and make sure that Texans are protected
and Texans are served by more reliable systems.
And a lot of that, in my belief,
is that the generation costs continues to go down.
We may be putting a little bit more in transmission
but generation keeps coming down
and we're gonna have other issues we've gotta deal with
with inverter-based generation and storage
and all those things.
But it's all dependent upon a robust transmission system.
So the one other thing that I wanted to ask is,
when you think about the option two or option B,
did you only look at 345?
I continue to struggle with the fact
that we're one of the only regions that have
the upper limit of our transmission stops at 345.
And I know some of it is because of underbuild issues
and the requirement that you put in a 500 line.
We may have a lot more underbuild to do as well
but have you looked at the scenario?
I know you all advocate for 765
but has ERCOT or AUP thought about using that?
And would that provide any more reliability
or value to the Rio Grande Valley
if you went with a higher voltage?
-: Yeah, we have considered that
in a number of, obviously during the CREZ process,
it's something that was considered.
And kind of to your point,
the way I think about 765 is it's not a onesy twosy,
for the reasons you just said,
if you have one 765 kb line or two.
The problem is, when you lose that line, what happens?
And so in my mind, it's something you have
to kind of make that commitment to and work
towards building out at least some sort
of a backbone at that voltage
in order to then have that to organically grow from
and make it work.
And so in this particular case
when you're looking at building one new line
to the Valley, does it make sense to do it at 765?
Probably not, right, for the reasons I just said.
It's more expensive and then obviously you have the issues
to deal with if you lose it, what happens?
-: But if you lose it, you still have three others
that might be able to be the contingency on that.
I guess what I would say, I'd love for y'all to look at it.
I'd love for y'all to think higher.
Think not 2022 but 2032.
-: Yeah, just let me clarify your statement there.
The concern with building 500 or 760 kb
is that it is so good at delivering high amounts
of power and high volumes of supply of power,
it's so good at its job
that if you lost it for a little while,
it's not worth building it at all.
-: Uh, no. -: Fill in the gaps
for me there. (spectators laughing)
Woody: I'm sorry.
-: I just don't understand why you wouldn't want
to build something that is extremely good at its job
because you might not be able to use it
a couple of days a year.
-: Well, it's just, when it goes out,
then you have a significant amount of power that-
-: Okay, sure, if you said, I don't want to build a 760 kb
because it's a single point of failure
for more people than a 345 is.
And so instead of that, I'm gonna build
two separate 345s that provide offsetting risks
to each other in different areas
and one's on the coast, one's not.
And so therefore I've reduced my risk
of a single point of failure.
If you said that, that would make sense.
But what I'm hearing is,
we're only gonna build the one line and option two.
And instead of building a really big one that delivers
a lot of power to ensure reliability for a really long time,
we're not building more to reduce risks,
we're just gonna build a smaller one.
Help me fill in, I mean, somebody help me here.
-: Yeah, I think it has to do.
I mean, really this is a reliability issue.
And that is when you talk underbuilds,
you talk about if that 500 kb line trips
or that 765, where is that power going?
The generators are still generating.
-: Sure.
-: The load is still there.
So the rest of the system has to pick that up
or you're gonna have potentially outages.
Lines are gonna trip generators are gonna trip.
So the question is, I think, the cost of a 345,
knowing that you don't have do any underbuilds
or the cost of a 500 and a 765,
knowing that that's a higher cost structure,
but then you're gonna have to do additional work
to ensure that that contingency, if a contingency happens,
that that fails.
-: Okay. -: And I kind of wonder
is does the second circuit on the western line
help that contingency.
-: Help defray just loading a-
-: That's right, a single circuit 345.
What worries me about this entire conversation,
two part, is that under this framework of thinking,
we're never having a 760 line in Texas, ever.
You're not even headed to saying we're never having
a 760 line.
-: I think if you want to move to 765,
you've gotta build an entire 765 system.
You can't just build one line. -: That's right.
-: I realize that- -: That's the step change
we're talking about.
And so instead of $1.3 billion, we're talking
about 20 or $30 billion.
I mean it's a lot- -: Not for that line
but for a system. -: For a system.
I mean, it's a huge step change.
-: But other regions have it.
Did they do it in 30 billion chunks too?
-: I don't know.
AUP, they're really the premier 765 builders
across the US.
But 500s are used in lots of different regions as well
and I'd put it out there for food for thought
that thinking positively in the future
about these higher voltage.
Maybe now is the time, maybe now is not the time.
I don't know.
But I'm saying now is the time-
-: Well, a blanket no is not the answer.
A blanket no is not the answer.
-: Yeah, a blanket no is not the answer
and no, I don't even wanna look at it right now
is not the answer.
-: Absolutely.
And this kind of circular logic of no,
we can't do it right now.
And I understand, y'all are constrained
by the current process.
But the circular logic both applying
to no, we're not gonna do 500.
We're not gonna do 700 now because it doesn't fit
and we're not gonna do it,
just like we're not gonna do a second circuit band-aid
because we don't like band-aids,
we wanna do the billion dollars first.
The band-aid didn't get done anyway
because band-aids just leave you
in a just-in-time danger zone.
Well, not doing the band-aid got us
in a Just-in-time danger zone anyway.
And it's this circular framework across the board
in this process that is very, very concerning.
And I'm immensely grateful that you're sorting through this
because I'm starting to see why we haven't gotten
a lot of projects done that we've needed in the state.
-: And it has been a ride. (spectators laughing)
So it was much more complicated than you would ever think
evaluating the second circuit.
So to just frame up the conversation,
and you made a really good point,
Commissioner Glotfelty, earlier,
the reason we're having this conversation here today
is because the legislature and the Governor
want us to ensure reliability.
And one component of that is looking
at the acceleration of transmission development.
And we, as a Commission, we as a Commission,
are looking at that together.
And although the Chairman has assigned me
this very important project that I have worked
very hard on over the last several weeks,
we as a Commission are making a decision,
we as a Commission are evaluating these issues.
I just wanna make that real clear
because it seems that there might be some thinking
that I'm the only one interested
in looking at these options.
So I just wanna be real clear and on the record on that.
And secondly, I wanna go back to again,
trying to summarize this conversation
to the long-term project.
And as we stated here today,
we want ERCOT to endorse the project
by the end of the year and to deem it critical
for reliability.
If you don't have it done by the end of the year,
then you need to give us an update-
Woody: Okay, we will.
-: Because we'll order it if we have to.
Right? -: Yeah.
-: And so it's gonna get done and we want the endorsement
through the regular process.
This is $1.2 billion so we want it to be vetted
but we want it endorsed by the end of the year.
And we want it deemed critical for reliability
and we want the party or parties that are responsible
for filing a CCN application at the Commission
to provide us with their best case,
most efficient timeline for how long it's gonna take
to file the CCN.
To file it in a project that Stephen will be talking
about to us at the end of this long conversation.
To file it with their direct testimony supporting
their application to help expedite the CCN process
once that project comes over here for our CCN review.
Now we'll also say,
well, I'll leave it to my next topic
on the second circuit.
Is I had conveyed last open meeting
and we had broad statutory power
to order the construction of transmission
for safe and reliable to provide safety
and reliability in the state.
And so what I would like to understand
from you all, if there's additional information
y'all would want on the second circuit
to be able to make a determination
on whether we want to pull the trigger
and use that authority or if you're comfortable
making that decision here today.
But before we take action,
I really wanna make sure that we go back
to Woody's statement that he abundantly made clear
to us today that ERCOT would ensure
that that second line would be put in place
in a reliability manner where we would not create
a reliability risk for the citizens of the Rio Grande Valley
when we add that second circuit.
-: We can do that with outage coordination, yes.
-: And you can manage the outage risk.
-: Right.
-: That may delay the project but we'd rather
manage the outage risk.
-: We're not gonna approve outages
that jeopardize our liability.
-: Okay.
And I also want to make clear again from you
that you said together these two projects,
the second circuit, from San Miguel to Palmito
and the long-term project together provide
significant reliability benefits
for the Rio Grande Valley.
Peter: That's true, yes.
I'm not, yeah, keep going.
-: Okay, so based on this feedback
that I think is critical to our evaluation here today,
I would like to understand from y'all
if y'all are ready to order the construction
of that second circuit,
based on our broad statutory authority
under 35.005, subsection B, 39.203, subsection E.
-: I take it you're ready.
Just a guess.
-: Well, I just wanna hear from y'all.
-: Okay. -: I'm waiting to hear.
-: Wheen are we expected to have this thing energized
if we order this today?
When is it gonna be ready?
When does it help out the Valley?
What's your forecast?
-: We were indicating about 34 months
for our portion,
and I think the other TSPs were within that as well.
-: Okay, so we're looking at,
okay, six years for the long-term fix.
Yep.
Three years of hurricane season.
Okay, that's my question.
What do you think?
-: So, I'm trying not to surprise the court here
but we actually have some fairly new information
to bring to the group.
-: Please state your name for the record and continue with-
-: I'm sorry.
Michael Quinn on behalf of the Cherryland Utilities.
So, since we've had our original project
approximately a month ago, we've had a large load
come and approach us about siting in the Valley.
And today we at 2021,
we have 2800 megawatts worth of capacity.
2027 is what he said
we have 3200 megawatts worth of capacity.
And so the second circuit buys us
approximately 300 megawatts of additional capacity,
based on the extrapolation from what ERCOT brought.
So over the last month, we've had a load approach us,
a very meaningful load.
And if you'll allow me to be a little bit vague,
it's not public information as to who and the size.
But the way I would describe it is
they are on a very aggressive timeline.
I don't have a signed FEA today,
that's the Facilities Extension Agreement.
But we have vetted them enough
and actually brought it to ERCOT within the last week,
that's it's in the tune of 600 megawatts.
Jimmy: And it's a highly controllable load,
I would assume.
-: Yes. (everyone laughing)
-: I've only been chairman one day.
Don't get me fired.
Will: A bit more information on that, please.
-: This is wild stuff.
-: And so I'm not trying to surprise anybody.
We brought it to ERCOT, like I said,
in the last week.
And we believe the load is very credible.
They have another facility in Texas
that another utility is building out to
so we believe the load is real.
So absent the second circuit and the closed loop,
I suggest that there's near-term risk.
-: Yeah, so,
oh yeah, go please.
-: I'm sorry.
Mr. Quinn, let me ask you a question.
So you just got this new information
and you believe-
-: Over the last month and specific we brought
it to ERCOT over the last week.
-: And you're saying that,
are you saying that it justifies closing the loop?
-: So I'm happy to talk about closing the loop
but I believe that in ERCOT's presentation,
they suggested closing the loop
plus the second circuit is what gets us
to 310 megawatts of capacity.
Now, I don't wanna put words in ERCOT's mouth,
if they have a different number than that.
-: So in other words,
that 2026 projection for new capacity
might be moving up.
-: Yes, that's exactly what we're suggesting.
-: So the band-aid might actually be more critical
than previously thought.
-: So the second circuit and closing the loop
gives us a little bit of headroom.
Not substantial, in my opinion,
but it does allow us to serve that load
safely and reliably.
Now that's a conversation specific to Cherryland.
I don't know what other conversations,
Stack or AUP, is having with other loads.
We see the,
Commissioner, we're very much in your camp
from the standpoint of, we see the near-term project
and the long-term project as both.
We see them as two sides of the same reliability coin.
We see there's near-term needs
and we're trying to address those with
these quicker projects.
We absolutely believe the right thing to do
is to go forward with the Greenville Project as well.
-: Woody, do you have any feedback
on this new load or have y'all looked at it?
-: We have the information they've provided us
but nothing further.
We don't know anymore about it than they do.
-: Okay.
-: I can tell you from AUP's perspective,
we've also talked to several large loads as well.
Don't have any commitments at this time
but there is a lot of interest there.
-: And so the proposal that Cherryland has provided
for closing the loop includes both construction
by Cherryland and AUP.
Do you support this closing the loop?
-: I do, yeah.
And I agree with what was said here.
Our analysis indicates that stringing
that second circuit all the way
from San Miguel to Palmito, closing the loop,
gets us about 300 megawatts.
That's consistent with our analysis as well.
And by the way, I sincerely apologize
for any confusion that we have caused on this issue.
We do see value in that second circuit.
And so I would confirm what ERCOT has said
and what Cherryland has indicated
regarding the improvement in capability associated with it.
And we will stand by our 34-month timeline
for getting that done, energized,
so we can do that reliably.
-: So I just want to make sure that it's properly framed
for everybody, 'cause I know that the normal stakeholders
who are very sensitive to transmission costs
will come knocking.
But we get near-term reliability solutions by 2024
with a long-term reliability solution by 2027
for the tune of this-
-: We actually think we can probably do better than that.
So possibly even by 2026, we could get the long-term.
-: The other way to think about it is,
I know we'll incur new costs and a significant cost
but what is the cost of inaction?
-: Exactly.
-: So the way I think I envision it is
if we move forward with ordering these interim options,
which is the second circuit and the closing of the loop
to provide more near-term reliability
and load growth, load serving capability in the valley,
those facilities would be in place about 2026,
which is right before the reliability need arises,
based on our cost modeling in 2027.
And then followed by the new project that would be built
after the reliability need.
So we would have sort of a phased-in
infrastructure build out to address the reliability needs
of the Valley and maintain the reliability
for those citizens down there.
-: I know you've got an extensive background in this.
-: I'm ready to go.
-: I'm good to go, based on your work
and your expertise on those two, as you just laid out.
-: Okay, so do you want me to make a motion or do you want-
-: Do you want to cover that or just those two?
-: Do you want me to make a motion?
-: If you have a motion ready, that'd be fantastic.
-: Okay, is everybody comfortable with that?
-: Yes. -: Okay,
I just wanna make sure.
Okay, so pursuant to PURA 35.005, subsection B and 39.23 E,
I moved to order Stack, ETT/AUP and Cherryland
to construct a new second circuit
on the existing double-circuit capable 345 kb line
that runs from the San Miguel station
to the Palmito station and to close the loop
from Palmito to North Edinburg
to help ensure reliability in the Rio Grande Valley.
-: We've got a motion.
Is there a second?
-: Second.
-: All in favor, say aye. -: Aye.
-: Okay, and before we move on,
I will also say that if a CCN amendment is needed
to build these facilities,
and I don't think it will be needed
for closing the loop, but if it's needed
for the second circuit, that EDT and Cherryland said,
it would take about eight months to prepare the CCN
for submission to the PUC,
if a CCN application is needed, a CNN amendment.
So I would like to understand if that can be done faster.
By the end of the year.
Because if we are approving these projects
under our statutory authority,
we will be processing the CCN within 180 days,
so that's about six months.
So we would like to get this going as soon as possible.
-: Yeah and to be clear,
from our review of our existing CCN, we don't see,
it's already certificated for double-circuit
so we think we're good to go.
So we don't see that as an issue.
-: And our initial review indicates the same.
If the Commission has other perspectives
in Cherryland's part of the project,
we specifically have said, we can do it in 30 months.
If we have to go through the CCN process,
obviously routing's not a issue for the second circuit,
we're prepared as soon as we start that CCN process
to go ahead and put dollars at work,
from an engineering and procurement standpoint,
recognizing the urgency of the project.
And I feel comfortable that we'll hit 30 months.
-: We don't have a contrary opinion on the CCN.
Good to hear.
Thank you.
-: So you don't need,
your position is you don't need a CCN
for the closing the loop facilities?
-: I'm sorry.
For closing the loop, yes, we absolutely will
because it's brand new.
Right away for the second circuit.
I'm sorry I was not clear.
-: Okay, so will that take eight months to prepare?
-: Our past histories has indicated yes,
eight months is appropriate.
I'll commit that we will leave no stone unturned
to try and improve upon that eight-month period.
-: Okay, so can you go back and visit
with your counsel and see if you can get it done faster?
And also- -: Why yes, I will.
(everyone laughing)
-: There we go.
Yes, sir.
-: My name is Corey Allen.
I'm the power delivery manager for South Texas Electric Coop
and, like Wayman said, we've got the rights
to the double-circuit on that 42 miles
that we have from San Miguel going towards the Lobo.
And we do have the easement rights in place
so don't think we'll have a regulatory time.
Peter: Excellent.
Cherryland, back to Cherryland.
-: Good morning, Commissioners.
John Zerwas with Cherryland.
We can certainly go back and see if we can improve
on the eight months.
There's probably a few things we could expedite
and try to cut it a little bit shorter.
But we'll come back and stay in contact
with you all about that.
-: Okay and as I directed, and for the other project,
if you can file your direct testimony
with your CCN application to cut time,
I think that would be very helpful.
John: Absolutely.
-: Excellent.
All right.
-: I think we can leave the Rio Grande Valley.
-: All right.
I'll just remind everyone that before the direction was
given to move forward with closing the loop
and the second circuit,
there was also a very clear directive
from this Commission to ERCOT to continue
to accelerate the option to long-term
transmission project under,
would you like to codify that in motion or?
-: Sure.
-: I think she did, didn't she?
-: I did. -: Oh, I'm sorry.
Janice: We can, if you'd like.
-: No, no.
We're good, right?
-: Well, before we leave this topic,
actually, I do have a very important statement
that I'd like to make.
I think it's, as we've said,
it's extremely important to maintain reliability
in the Rio Grande Valley.
But I do want to say I can't leave this topic
with again reiterating that very importantly,
that we need to be clear that we're not making a
determination on cost.
I know I asked for cost estimates
in the filings that were made this past Monday.
And although the Commission is ordering the construction
of these transmission lines and facilities
to improve the reliability in the Valley,
we are in no way giving the companies a blank check
to build the facilities being ordered today.
All costs associated with the construction
of these facilities, pursuant to the Commission's order,
must still meet the rate making standard set forth
in PURA and the Commission rules
in a future rate making proceeding,
which will require that rates are just and reasonable.
It is my expectation, and I think our expectation,
that staff will review all costs that the companies seek
to recover for the order transmission
with the same level of scrutiny that they would use
in a rate case proceeding that does not involve
the Commission order to construct to help ensure
that the rate payers pay rates that comply
with PURA and the Commission's rule standards.
-: Well put. -: I second that.
-: Thank you.
-: So Commissioner Cobos, just to follow
with the less important,
we're gonna open a project as a storage house,
a place to file Commission orders that direct
to building of the transmission so that these orders
will be easy to find.
Lori: And can you move my memos and the TSP's filings
that have been filed to date from 51617
into that new project?
-: I'll file those in that when we open it up.
-: Thank you.
I think that's a great idea.
-: Excellent. -: That's a good idea.
-: Okay.
-: Good deal.
Thank you all.
-: Thank you. -: Thank you.
-: That wraps up business on-
-: Can I?
I just have one statement that I wanna make.
It's not pertaining to the Rio Grande Valley,
but I've had some discussions
with Brad Jones at ERCOT about potential,
if we run into a major reliability outage,
like we did during winter storm Uri,
and if our system went down,
obviously we have black star plans
and we have black star plants around ERCOT
that would help us bring the system back up.
That's still not an easy process to manage,
bringing up generation and load in a way that is
well, there's a process for that.
And thank God we have operators that test this
and work towards it.
There have been a couple of discussions
about what might happen if we could build
an AC interconnection to SPP
or to the Midwest ISO South, Entergy South,
and keep that circuit open all the time.
And I'm not talking about FERC jurisdiction here,
but this would never happen if there
was a jurisdictional issue.
But keep it open unless there was the absolute emergency
that leaning on another system would help us bring up the
ERCOT system in the event of a major catastrophe.
We've got a handful of facilities that might be utilized
for that and I know ERCOT has been working
with a university here in Texas on a study
that should be done in 2022.
But to me it seems like it's a really good issue
to consider for the economy of our state.
We don't want an outage for 30 days.
We don't want an outage for a week,
if we can lean on something else.
We've done things similar where we've block loaded,
as it's called, loads into SVP and loads into MISO.
This would be a little different,
but it could provide us some valuable black start frequency
support if we needed it.
And we don't have the answer yet,
but to me, it's a good educational tool.
It's a good research project to see if this is something
that would benefit all Texans
in the event of a major catastrophic outage.
-: That's a great idea.
And I know you've taken a special interest
and initiated some special projects
related to vegetation management,
a more granular load shed.
Would this be something you'd be willing to take on
and lead the charge on?
-: I thought I already did.
-: I did too.
I did too, just what's the next step?
-: Thank you, thank you, sir.
I think, I don't know what the next step is.
I think we need data from the study.
Obviously, we'll have conversations with FERC
and the pink building.
We don't want, this is not anything to do
If there's a jurisdictional problem-
-: With partial application, in other words.
-: This would be totally emergency application period.
-: As with the other issues that you're taking the lead on,
please identify ways to accelerate, streamline processes
and move as quickly as we can to an actionable solution.
-: Okay, thank you.
-: Woody, back to you for the remainder of your presentation.
Woody: All right.
You guys ready to move on
to load forecast boundary threshold?
-: Yes, sir. -: Yes sir, quickly.
Okay, quickly.
So when ERCOT prepares future planning fixes,
we put a load forecasting and it's kind
of a top-down forecast.
We use economics and Moody's forecast.
And we say, this is how much load is gonna be
in certain areas.
That's our forecast.
And this forecast goes into 2022 cases,
'23, '24, '25, '26,
those future planning cases have our forecasts in 'em.
Now TSPs, working more from the field up,
taking customer information,
bring their forecast in and compare it to ours.
If their forecast currently,
if their forecast is greater than ours
but less than 5% more, then we accept their forecast
and put that into the planning case.
If their forecast is, let's say 8% more than ours,
then we cap it at 5%.
And that's true for all the weather zones,
except for the Far West,
which has a seven and a half percent.
So what we're talking about today is
a move to increasing that boundary threshold.
Instead of having 5% for the weather zone,
moving it up to seven and a half percent
in all the weather zones.
I think that's a reasonable initial step
to better account for the changing needs and load growth.
And it may actually help alleviate some
of the just-in-time planning that we have to do,
having that power load in there.
So the request here is that you give us instructions
that you want that boundary threshold moved
from 5% to seven and a half percent
in all the weather zones.
And then the process is we can go back to TAC.
We ask for a TAC recommendation.
We take the TAC recommendation to the board
and the board approves it and then it's done at that point.
Peter: That makes sense to me.
-: And then does it have to come back to us?
Woody: No, we can implement it.
-: Okay, good.
-: Thank you, Woody, for your recommendation.
I think it's important to recognize
that our state is growing and it's been growing.
We have a tremendous amount of population
and economic growth throughout the state.
I know that the rest of the state is in 5%.
Liz Jones, do you have anything you'd like to add?
-: If I may. -: Please.
-: Liz Jones for Encore.
I'd like to make sure one thing's clear,
which is that the percentage increment is
on a weather zone basis.
And so depending on the weather zone,
that's a few megawatts or that's a lot of megawatts.
So if you talk about the North Central weather zone,
which includes the DFW area,
seven and a half percent is a significant amount.
If you talk about the Far West weather zone,
it is a much smaller amount.
And wasn't familiar with our cuts intentions
until you all provided your slides.
Would like for you all to think about
whether there needs to be some relationship
to the base size of the forecast
when you're thinking about what the percentage increment
of adjustments should be.
And that is how the Far West moved
from five to seven and a half.
I'm not suggesting that there's a basis
to move from seven and a half to 10,
but I do want to make you aware that the,
particularly in fast growing areas like the Valley,
like the Permian, that can be less useful
just because of the base number.
And so I think, as Woody explained,
this is something that is managed through the ERCOT board
and so it doesn't necessarily have to come back through you.
But it would be helpful if you offered guidance
on treating this issue.
-: Do you have a suggestion on what a revised number
for a fast-growing area like DFW should look like?
-: Well, my suggestion is that because the base number
in North Central is so large and we're now talking
about the seven and a half percent ban,
I think we, at Encore, are much more comfortable
with what those numbers look like for North Central
than we are for what those numbers look like in the Permian.
And so if you could afford ERCOT
and Woody the discretion to bump that number up
for the smaller weather zones, if they deem appropriate,
I think it would be beneficial for us.
-: Fair enough. -: Woody, is there
any information that you can maybe bring back to us
that would help paint a little bit more
of a picture for us on exactly what-
Peter: Yeah, maybe an impact of-
-: Low thresholds, you know.
-: We can look at,
I mean, this has been going on for years
and so you can go back and look at what actually happened
in 2020 versus what the ERCOT load forecast
said was gonna happen in 2020.
Jimmy: That's a good point.
-: You can do that for 2019
'cause 2020 was kind of a strange year
because of COVID.
So there is information like that.
This is a stretch though right now.
And seven and a half percent,
we thought long and hard about the seven and a half percent.
That was a stretch, that's a big change.
-: Well it seems like the impact
of whatever that 5% to x is
can greatly vary, depending on the load serve
to that particular area.
Would it be productive as an intermediate step
to look at a data table of expected impact
in each of the seven weather zones for-
-: I can tell you that this year,
this year six of the eight weather zones,
the TSP predictions forecast were above
what we had in our economic forecast.
Six out of the eight weather zones.
-: More than 5%?
-: More than 5%, correct.
And I can also tell you that,
let me get my number here.
We did think about this a little bit beforehand.
That, for example, I'm not gonna use 2020
but in 2019, if you think about 2019,
we made a forecast in 2016 of what 2019
was gonna look like.
And the actual numbers that came in
were below our forecast in 2019
in every weather zone, except for the Far West,
which is partly what led to us increasing that
to seven and a half percent.
So this year, six out of eight forecasts
are above our forecasts.
In the past, the actuals, when they've come in,
have been below the 5% boundary that we have.
So what does the future hold?
Strong economic growth still, it appears.
Peter: The bottom line is forecasting is hard.
-: No matter what you say,
you will surely be wrong, it's just a question of how.
And so again, I'm not up here asking
for a blank check, by any means.
But what I am asking you all to think
about is seven and a half is a guidepost
and not a cap because circumstances
in different weather zones may necessitate
a different result.
-: Fair enough.
I appreciate the point.
Maybe you could coordinate with ERCOT
on evaluating what a scenario would look like
between with different metrics for different weather zones.
Would that make sense?
-: Well, I think so,
but it sounds like what you're asking
for is sort of a policy change
of how we apply the threshold.
-: Well, so let me, I'm sorry,
brief history lesson.
Part of the reason that the 5% came into effect
in the planning guide was as a consequence
of concern that transmission and distribution providers
were padding their forecasts to maximize their bill.
And Encore supported this change and we're standing by it.
What we're suggesting is that in the past
that has been applied as such a hard cap,
from a forecasting perspective,
that it has been difficult to bring forward projects,
particularly in fast growing areas,
that we think are merited,
not because it's within the 5% dead band,
if you will,
but because there are particular circumstances in the area,
and I believe Senate Bill 1281 actually codifies
that kind of point of view so that there is
some more flexibility there than what has historically
been provided by the 5% or the seven and a half percent cap.
-: Okay, so as a utility on the ground,
in your service territory,
you're able to see the growth better
or in some ways are able to have,
you're providing information to ERCOT
because you're on the ground.
You're much closer to the actual load growth.
They have their forecasting methodologies.
And so it sounds like to me,
and again, please clarify if I'm not exactly
capturing what you're saying is that,
even if we went to seven and a half percent,
and we asked ERCOT to go and change it
for all the weather zones.
Because it sounds like, from what you're saying, Woody,
that the 5% in six weather zones is constraining.
It's actually constraining how much load growth
is probably happening 'cause we have rebounded
from COVID and our economy has been strong,
it's gonna stay strong.
And so if we go to seven and a half percent,
to not have that be a hard cap
but to be a guide and maybe if you see something higher
than what ERCOT is seeing,
you can provide supporting documentation
and work with ERCOT to prove your case?
-: Yes, and again, historically that has been
in the nature of signed agreements
that are securitized by the new customers.
That's a just-in-time standard
because customers don't wanna make commitments
and disclose their business plans
earlier than they have to.
So we're looking for the ability to use a range
of evidence and we bear the burden of proof,
absolutely, as utilities, that additional infrastructure
is needed.
-: Okay, so as an interim step,
something to consider is perhaps having Woody
and ERCOT go ahead and increase to seven and a half,
as an interim step.
And then for this proposal that you've provided us today,
to continue exploring how we can get that
into the planning guides so that we have more transparency
in the process going forward.
Does that makes sense? -: Yes.
-: So this would not be a permanent order
in terms of system change for ERCOT.
This would just be almost a pilot moving forward
for their evaluation guidelines?
-: I think that if we were comfortable today,
if we were comfortable and if you're not,
then you can think about it.
But if you were comfortable today,
as an interim step, as ERCOT recommended,
we can ask them to raise the 5% boundary threshold
to seven and a half because it sounds like,
at least for six weather zones in the last year,
the low forecasts are seen from the TSPs
are being constrained by the 5%.
In other words, they're higher
and they're being constrained.
So as an interim step,
we increase it from 5% to seven and a half percent
to take into account that growth that-
-: So we know we're growing,
so let's paint with a broad brush first
and then in the meantime we can put a finer point
on particular areas.
-: Have ERCOT explore this concept.
Work with Encore and the TDUs to explore that concept
of having the boundary threshold serve
as a guiding post and what additional information
a utility or TSP can provide
when they exceed the seven and a half percent
that's something beyond just a signed agreement,
that would still provide the proof that you need,
as ERCOT, and we want to see too
because we don't want to have projects justified
if the growth isn't there.
-: Absolutely. -: Right.
-: But proof that would help solidify
the utility's case for why it exceeded
seven and a half percent.
In addition, not just a signed contract
but other forms of proof.
-: Yes, Commissioner, we believe that would be very helpful.
-: So I think the five to seven and a half percent
is direction from you, we take it to TAC,
and we get board approval,
and that becomes part of our process at that point.
So that could happen fully over the year.
-: October. -: Potentially.
-: Let's hold up for today.
Let's propose to make the move from 5%
to seven and a half percent
and we'll direct that to be implemented.
And then as the next step we can-
-: The next step is a planning guide revision,
at the very least. -: Yup.
And there's gonna be a lot of that going on,
so we don't need to solve it all today.
-: Can I just ask one question
about the practical effect of this is kind of
over projecting, potentially over projecting
the load growth in a region, correct?
-: So that could mean more transmission
as opposed to less transmission.
-: Yeah. -: Could be.
It could also mean the second circuit
of some lines get approved. -: Oh, wow.
Man, what a great thought.
-: I'm trying to figure out
if the checkbook is open right now
because I'll just write a check.
But the question really that I have
is do, you need this,
you need this change when?
When are you using the five versus seven and a half percent?
Is it for,
do you need it by December for a next transmission plan?
Do you need it by March?
That's what I'm trying to figure out.
-: Those load forecasts will go into planning cases.
We have a set of planning cases every year
that we use for evaluation.
Those planning cases either have a ERCOT forecast,
they have a 5% bounded forecast
or they might have a seven and a half percent
bounded forecast in those weather zones.
And the more loads you have in the planning cases,
the more needs will show up in the transmission perspective.
-: And those base cases are for reliability projects?
-: Those are for reliability projects, yes.
-: And, sorry.
And those forecasts are also used
when ERCOT evaluates large transmission projects
or transmission projects that are not radial
that require a CCN.
So I would suggest to you
that they are your first screen for whether
a project is needed.
But you all and your staff provide the second screen.
So this is not a blank check.
-: I think the big picture is it was abundantly clear
earlier today that the planning process
for transmission needs to be improved.
In the meantime, this change would help us
defer towards the side of load growth
rather than constrains.
-: I understand that but I'm still confused on one thing.
You all, you have your load,
you all have your transmission planning models
that you all use.
And I'm assuming that utilities and ERCOT
have the same model and this is...
Do I have something wrong?
I guess what I'm trying to figure out is
changing this from five to seven and a half percent
in September 23rd versus January 1, 2022,
what's the practical impact of that?
Is it that every study of every project
that gets studied between now and the end of the year
uses a lower threshold?
Or, I'm just trying to understand
when a utility proposes a reliability project
or ERCOT says, we believe that this project needs to happen,
what's the timeframe for that?
-: Those planning cases are built once a year.
-: Once a year, okay.
-: And the load, in those planning cases,
is distributed according to that load forecast.
It's agreed upon. -: Okay.
And when are the planning cases?
-: They're built at the first of the year so-
-: That's what I wanted to know,
that's what I wanted to know.
-: And they're updated three times yearly.
-: Okay.
-: And we have the luxury of a smaller surface area
than ERCOT and so we are continuously updating
our transmission plan and thinking
about what forecasting should go into it
for particular regions and particular projects.
ERCOT has the challenge of mapping
and accounting for the entire grid
and therefore their updates are less frequent than ours.
-: Okay.
That answered my question.
-: Where does that leave you
in terms of is this something that's productive
to do now?
-: I'm fine upgrading it now
and then having another look later or,
not making this a blank check,
but I think we have load growth in the state
and I think it's pretty common
that it's growing, pretty common knowledge.
But I just don't want it to be a blank check.
-: Yeah, agreed. -: And more this was juts
a trying to understand when the planning model.
-: Yeah, and it's moving it from five,
it's still a cap at seven and a half percent.
And then you can, per your comments,
we can look at whether if we need
to fine tune that in the future.
-: Right and agreed
and I wanna stress this as well.
And I think this is down in the planning models
and like Liz said, it's the first screen
to see whether or not a project is even needed.
So there's a lot of steps that still need to occur.
But I still want to,
before it gets to us in terms of a CCN approval, et cetera.
But I do wanna stress again
that obviously not a blank check
and no determination on whether projects are needed or not.
This is just a percentage change
to account for the fast-growing population
and economic growth that we have in our state,
in all areas of our state in one form or fashion.
So but that's it.
I think I'm comfortable moving
from five to seven and a half percent.
And with respect to your long-term process
that you've proposed, Liz,
I think that's either a planning guide revision request
that you can work with with ERCOT on submitting.
Or, we as a Commission, could include something
in our rule whenever we-
-: Well, I'd welcome a suggestion from
and encourage you to continue exploring this
and come back with a suggestion.
But I think for today,
we've got a pretty good line of sight
on what action we can take,
if you've got a motion you'd like to propose.
-: Well, with that, I would just say
that we can direct ERCOT to increase the boundary threshold
from 5% to seven and a half percent
in the remaining seven weather zones
to help accelerate the development of transmission
for reliability in the state.
-: Okay.
All right.
-: Thank you, Chairman, Commissioners.
-: Thank you.
-: Mr. Chairman. -: Yes, sir.
-: Before we move to the water issues,
may I suggest that we go to closed session?
We're about to run out of time with our Attorney General
sitting here.
-: All right, we will recess after completing
item number 20 and move to closed session,
pursuant to Chapter 551 of the Texas Government Code,
sections 551.071, 551.074, and 551.076.
We will be back to pick up our agenda on item number 21.
-: Woody has one last set on the economic criteria.
-: I can be fast.
I can be really fast.
-: We gotta recess. -: Sorry, Woody.
-: When we come back.