-: Good morning.
This meeting of the Public Utility Commission of Texas will
come to order to consider matters that have been duly posted
with the secretary of state for Texas for June 16th, 2022.
For the record, my name is Peter Lake
and with me today are Will McAdams,
Lori Cobos and Jimmy Glotfelty.
Mr. Journeay could you please walk us
through the consent items on today's agenda?
-: Good morning, Commissioners.
by individual ballot the following items
were placed on your Consent Agenda.
4, 7, 9 through 14,
16, 19 23, 26 and 44.
-: Thank you, sir.
Do we have a motion to approve the items just described
by Mr. Journeay.
-: So moved. -: Second.
-: All in favor, say aye.
All: Aye.
-: None opposed, motion passes.
We will not be taking up item 22 today and due to the nature
of the items in the agenda, we will be taking up item 25
before we take up item 24.
Brings us to our formal agenda.
First item is public comment.
I'll ask all the speakers,
remember that oral comments related
to a specific agenda item will be heard
when that item is taken up.
This public comment segment is for general comments only.
When we do get to oral comments on specific items,
stakeholders should not approach the table
unless oral argument has been previously granted,
or they have been invited by a Commissioner.
As always, speakers will be limited to three minutes each.
Mr. Journeay do we have anyone from the public
signed up to speak today?
-: We have one person this morning, sir.
Mr. Cyrus Reed.
-: Good morning, Commissioners. Welcome back.
Man: Thank you.
-: I went through the same thing.
Glad to be over it.
Cyrus Reed here with Sierra Club Lone Star Chapter,
here to talk to you about my favorite subject,
energy efficiency.
Prices are all up over ERCOT, even in the (indistinct).
The cheapest, quickest and cleanest way
to help consumers more directly is energy efficiency.
The legislature, as you know, set broad goals in 2011,
we, previous Commissioners, set rules.
We haven't really revisited those rules since.
They gave you the overall goals,
but the details, performance bonuses,
cost caps, energy saving targets are left to you guys,
not the legislature.
There are things you can do.
You said, and not trying to make this personal.
I'm just trying to make my point.
You said in December 21 in the blueprint,
we're gonna look at those programs.
We haven't looked at 'em yet.
In the meantime, those eight utilities,
and they're all good people doing their jobs,
following the rules, have set forth
their proposed 2023 plans
and EECRFs, which is how we collect the money
to run those programs.
They're basically saying we're gonna do the same in 2023,
as we did in 2022, as we did in '21,
get to about 530 megawatts of peak demand reduction
and 700,000 megawatt hours of reduction,
all of which are well beyond the goals and good,
but you have a choice: open up a rulemaking
and look at this, get comments from stakeholders,
look at some of these issues, or you will be individually
approving eight different utility plans
in the next few months as those come to you.
I've looked at those plans.
We've filed comments and several of them.
I'm just gonna mention a few things.
CenterPoint 53677-
-: You have one minute, sir. -: Okay.
36% of their proposed budget is for a performance bonus.
They're following the rules.
Encore 536071, Encore has some great programs.
We appreciate their new programs on commercial winter peak.
Great programs, 28 million, 33%,
28 million of their budget is for a performance bonus,
33% of the total budget that all ratepayers make.
Entergy 53571, 37% of their budget,
4.5 million is for performance bonus.
53540, SPS, 34% of their budget,
2.1 million is a performance bonus.
They're not doing anything wrong.
They're following the rules,
but we need to re-look at those rules.
You guys can look at higher savings goals,
specific winter peak programs, what to do about caps,
and the fact is they all could be doing a lot more,
even under the caps we have.
So with that, I'm encouraging you
to please open up some stakeholder comments
on energy efficiency programs,
so you're not to force to approve all these plans
in a few months without taking a good look at them.
Thank you very much. -: Thank you, Mr. Reed.
Anyone else signed up for public comment?
Stephen: No, sir.
-: All right.
At this point, public comment is now closed.
Next item on the agenda, please, sir.
-: Item two is docket 52341, it's the application
of Mark Patterson for temporary rates
for nonfunctioning utility.
Proposed order was filed on March 8th
and on June 3rd, the judges filed...
Well, I filed a memo recommending that Commission
take official notice of six monthly reports.
Filed that by the temporary manager.
Commissioner McAdams has a memo on this item
and the subsequent item.
-: Thank you, sir.
I know you obviously filed a memo.
Would you carry the tee us off?
-: Yes sir. It was a lengthy memo.
I'll try to boil it down.
In these two dockets,
we are attempting to address a number of issues and try
to get a potential solution in front of us.
And that was the purpose behind the memo.
That was the purpose behind the length and description
of the mechanics.
As I set out, I recommended modifying the proposed order
to accomplish two things.
First, addressing the temporary manager compensation issue
raised by Commission staff,
and ultimately approve the temporary rates
in the petition.
As to the first,
I believe that the proposed temporary rates allow
the utility to maintain the annual revenue
that the temporary rates are designed to recover.
I would however, deny the effective date
of the recombined effective rate
until the completion of the sale transfer merger.
I would make a motion to accomplish this,
but certainly welcome any feedback.
Again, it was a heavy memo.
-: Thoughts, comments?
-: I agree with Commissioner McAdams' proposed actions
for this case and the next case,
with respect to the first case,
from my perspective, I think we need to go ahead
and approve temporary rates to get
this nonfunctioning utility going.
But upon the Commission's issuance of a final order
approving the STM,
those temporary rates would be in effect
and the temporary managers fee needs to be zeroed out
because that would be subsumed into the rate.
I think once we look at the STM case
and I know, Commissioner McAdams,
you have some proposed steps there that you've laid out,
I'll let you do that. -: Yeah.
-: And then I'll chime in after that.
-: So thank you, Commissioner. So as to that.
-: Before we do that, we should probably call that item up.
-: Okay, do we need to? Yeah.
-: You're gonna talk about zeroing out the temporary
(indistinct) -: Exactly, yes sir.
Which was articulated in the memo.
So I believe the mechanics, if we were
to adopt anything that that is reflected
in the conditions of the memorandum.
So Stephen, with that, you want us to call it up?
-: So item three is docket 50085,
is the application of Castle Water Incorporated
doing business, Horseshoe Bend Water Systems
and Horseshoe Bend Water Company
for the sale transfer or merging of facilities
and certificate rights.
-: I'll keep going, Mr. Chairman,
if you want me to. -: Yeah, keep going.
Whatever you have left.
Okay. -: Keep rolling.
-: Okay.
As the sale and transfer of Castle Water
is nearing its conclusion,
I believe there is an opportunity for the Commission
to provide clarification and guidance on key issues
that the Commission has not yet addressed in the rulemaking
or the sale transfer merger docket
for nonfunctioning utilities.
Most importantly and consistent with my memo,
I recommend that the reconciliation review
of temporary rates approved for the utility
in docket number 49759 be completed
in this docket, number 50085,
before the Commission issues a final order.
For the amended temporary rates
that may be approved in the pending temporary rate
case of docket 52341.
It makes sense in that case to require
the reconciliation review of these temporary rates
in the utility's next base rate case,
because after sale transfer merger,
it's logical that that may occur.
So with that, Mr. Chairman, pending any type of feedback,
discussion or modification, I would make a motion
to direct OPDM to file an interim order consistent
with my memo.
-: Thoughts, comments?
-: Okay, so with respect to this case,
I am in agreement.
Ultimately the order that comes out from the Commission
needs to terminate the temporary manager's appointment
and compensation fee.
I agree with the reconciliation in the base rate case,
'cause that is consistent with the Commission's practice-
-: Precipice. -: In reconciling interim rates
in the electric utility industry.
And I think that's the appropriate place to reconcile
those temporary rates.
I do think that we need to set
a period as to when those temporary rates will be in place
and then give a date certain after, you know,
I think the utility will come in
after the temporary rates expire,
but if we wanna set a date certain as to when they would
come in after the temporary rate period expires,
I think I'm good with that as well.
So my only question is,
so your position is the Commission issue out
an interim order in this case,
in the STM case, laying out our expectations?
-: That's correct. -: Okay.
Stephen, is that the appropriate mechanical, procedural way
to approach this?
Or are the expectations...
I mean, how do you...
I mean, I'm just curious to think about that.
-: We thought it would be good
to memorialize this discussion
going forward to make sure that it's clear
to the parties and the judge and STM what's expected.
Lori: Okay.
-: Makes sense to me. Anything to?
-: I'm just happy Commissioner McAdams put forth this memo.
It's a little convoluted here and he spent the late nights
this week doing it, not me.
-: Also very appreciative of that.
-: Very appreciative of it. -: Staff was brilliant.
So it helped. -: Brilliant staff. Absolutely.
But nonetheless, it's your name on it,
so it's brilliant. -: Thanks.
-: I'm in agreement.
You know, I think this is a complicated case,
and the goal is to get this across the finish line,
and you've laid out a very formidable path to do so.
So I'm in support of that.
-: Agreed on all points.
So we've got a proposed order to consider and then
a proposed order for reconciliation review.
-: That's correct.
-: Let's tackle that proposed order first.
-: Okay. -: Do we
have a motion to approve the proposal for item number two?
Approve the proposed order as modified
by Commissioner McAdams' memo.
-: So moved -: We have a second?
-: Second. -: Second.
The only piece is I think, Stephen,
do we need to modify the proposed orders,
ordering paragraphs to make them consistent
with the prior temporary rates order?
-: So I think this order, which is basically
amending those would approve the transfer
that the $8 into the rates of the utility,
but make that effective upon the issuance of the final order
in the STM case.
-: Okay, I just wanna make sure that's straightened out.
-: It's released as the temporary measure.
-: Okay. -: Okay, so-
-: Motion stands.
-: Motion stands? Doesn't need to be amended?
All right, motion stands. We have a second.
All in favor, say aye. -: Aye.
-: None opposed, motion passes.
That brings us to back to item three with a proposal
for reconciliation review.
-: Yep.
-: So we have a motion to direct OPDM to issue an order
consistent with Commissioner McAdams' memo
and the discussion at the dias?
-: So moved. -: Second.
-: All in favor, say aye. -: Aye.
-: None opposed, motion passes.
Thank you, again, Mr. McAdams' staff, McAdam's office.
Lot of work goes into that.
Next item please, sir.
-: Item five is docket 50788, the ratepayers' appeal
of the decision by Windermere Oaks Water Supply Corporation
to change water and sewer rates.
A proposal for decision was filed on March 31st,
exceptions and replies were filed,
and the ALJs filed a memo on June 6th,
in which they only recommended adopting the correction
proposed by Windermere.
-: Thank you, sir.
There seemed to be two big elements.
In this case, the question of non-discriminatory,
but also the question of just and reasonable.
I don't know that...
I don't think either one of those were necessarily
satisfied, but would love to hear thoughts and comments.
-: Yeah, so based on my review of the case,
I think the SOAH ALJs
applied the incorrect legal standard,
they only applied one of the, I guess,
prongs that are to be reviewed
under the Texas Water Code 13.043J.
Under that provision of the water code,
the appeal rates must be reviewed
to see if they are unjust and unreasonable,
preferential, prejudicial
or discriminatory or insufficient
and equitable or inconsistent
with the application to each class of the customers.
And so the, SOAH ALJ only looked at whether the rates
were unreasonable- -: Discriminatory.
-: I'm sorry, preferential prejudicial or discriminatory.
And they did that,
I think, based on our conclusion of law
and the Bear Creek Spud case, they only zeroed in
on conclusion of law number eight,
but didn't apply the entire requirements for review
of appealed rates in this case.
So I think they applied the incorrect legal standard.
And I think as a matter
of just sending it back to SOAH,
remanding it back to SOAH
so that SOAH can issue a PFD to address all
of the requirements of the water code 13.043J,
but also to zero in on the $171,000
in legal fees that comprise some of those rates.
I think as you look at the entire request,
I think they're requesting about over 500,000,
and 171,000 of that is our legal fees,
so we need them to scrub that down and apply
the correct legal standard and all their requirements
in the Texas Water Code in their review of the appeal rate.
-: So what I'm hearing is that they need to,
you think this needs to go back to SOAH to not only address
the non-discriminatory, non-preferential,
but in addition to the rest of that section of code,
just and reasonable, and on top of that,
take a closer look on the validity
of the $171,000 in legal fees?
Is that correct? -: Yes. Correct.
-: Okay. That makes a lot of sense to me.
Other thoughts, comments?
-: Yeah. -: I'm in complete agreement.
Those are the issues that I had and I support that.
-: The only thing I would add is that I don't want
to just, not that you did this,
but I don't want SOAH it to get the impression
that we're checking the box on non-discriminatory,
non-preferential just because there's one rate class.
-: Right. -: Right.
-: There's a lot of different types of water users
and just one rate class does not solve
the non-discriminatory issue.
So just want to put that out there.
All right, I think we're in good shape for a motion
to remand to SOAH with instructions to address
the issues Commissioner Cobos raised, specifically
whether or not the rates are just and reasonable,
and the validity of the $171,000 in legal fees.
Anybody care to make that motion?
-: And the issue you raised, sir.
-: And the non-discriminatory issue.
-: So moved.
-: Second. -: Second.
-: We got a motion and a second.
All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
Next item please, sir.
-: Item six is docket 512333.
It's the complaint of John Soules Foods
against the Southern Utilities Company.
Commission considered this docket
at the last open meeting and Commissioner McAdams
has filed a memo.
-: Mr. Chairman, before you begin,
I'm not gonna sign whatever order we have
on this because I wasn't here for the last meeting.
So I'm gonna let you three make the decision on this,
if that's appropriate.
-: Fair enough.
We'll consider you recused.
Per your memo, Commissioner McAdams.
-: Yes, sir. Take, thank you, sir.
-: Lay it out for us.
-: The memo resulted after a conference with staff
and in undertaking further review of the matter,
i believe that certain items needed to be clarified
in the order, remanding the proceeding.
As detailed in the memo,
I believe there are issues with the escrow agreement.
The nature of the conservation charge and the source
of the funds to pay the complainant
that should be addressed on remand.
And so therefore pending any discussion,
I'd move that the Commission adopts the order,
remanding the proceeding consistent with the memo.
-: Makes sense to me. Commissioner Cobos?
-: Yes, I agree with the recommendations
you made in your memo,
and thank you for your leadership on this issue.
-: Oh, well, I look forward to not being a leader
on these issues. (laughs)
-: (laughs) You're doing great.
You're got the curse of confidence there.
-: Thank you, sir. -: It'll keep you going.
Do you have a motion?
-: I believe I moved.
-: Pardon me. -: Move to adopt his order.
-: We have a motion to adopt the order.
Is there second? -: Second
-: All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
-: Great. -: Thank you, sir.
-: Next item please, sir.
-: Next item is item eight, docket 52384.
It's the application of Samuel Sledge to cancel
an exempt utility registration, and an application
of Sharon Peach to obtain an exempt utility registration.
Proposal for decision was filed early May.
-: All right, this is this unique case, I suppose.
Any thoughts, comments?
-: Firstly, Mr. Chairman,
I appreciate and applaud staff's diligence on this matter.
And I think there's a simpler path forward
for the Commission.
I believe that the Commission should process
this application as an amendment
to an existing exempt utility.
The applicants are merely seeking to notify the Commission
of the change in connections of the utility and the change
in the name of the person that owns or manages
the facilities at issue,
given that there's no need
to cancel the existing exempt utility registration
and issue a new exempt utility registration number.
As such, I would move that we should remand the proceeding
for further processing.
I would also ask Commission staff
and duo to work with this applicant to obtain the data
necessary for the Commission to update its maps
with the following understanding: while maps for CCN holders
must provide precise mapping data,
it makes little sense to hold an exempt utility that is not
required to hold a CCN to those same stringent standards.
My understanding is that the map
for the previous service area already exists
in the Commission's mapping database,
and therefore it should be possible
to update the map accordingly.
-: Agreed on all points. Do you consider that your motion?
-: I would so move.
-: All right. Thoughts, comments?
-: I'm in agreement and I'll second that motion.
-: Great. -: All right.
Before we move forward,
I do want to highlight something
you said that in general as a status quo,
default setting, very much appreciate staff
being more accurate and getting more information.
This is unique in that it's such a small utility,
but certainly appreciate their diligence.
-: Absolutely.
-: As their starting point in being
in case a question would prefer they defer,
they default to more information
and more accurate information.
-: Absolutely.
In my view, sir, they were correct in their process
and in their reading,
this is just a more expeditious way to satisfy the needs
of the... -: Agreed on all points.
-: Yes, sir.
-: Appreciate the diligent staff.
All right. We got a motion and a second.
All in favor, say aye. -: Aye.
None opposed. Motion passes.
Next item please, sir.
-: Next item is item 15, docket 53109,
is the application Undine Development
for system improvement charges.
(murmuring) Nope. Nevermind.
It's all to you now.
(Stephen laughs)
-: Thank you for the articulate laying out
of this item, Mr. Journeay.
Oh, this item has some complexity to it,
but I'll start by saying
that at the core of this,
I think there's an element of identifying
which elements of utility are doing what
of the broader corporate structure.
And that's an open question in my mind
in this one, and leaves some questions to be answered.
Thoughts, comments?
-: Agreed the issue of what entity or entities constitute
the utility is a very important issue.
It's an issue that I know this Commission has sought
to address diligently in the past.
As, you know, water utilities are set up in a variety
of different arrangements and determining who the utility is
in this case will drive a lot of really important
issues with respect to the rate of return that's used
for the system improvement charge,
the rate classification of the utility,
and how that they will be required
to file a rate application
if the SIC is approved by the Commission,
the annual reports that are provided to the Commission.
So figuring out who the utility is impacts
very important issues that not only apply to the SIC,
but going forward for the utility.
So I am in agreement that that issue
is a critically important issue.
It needs to be added to the preliminary order.
-: Yeah, I would agree on all those.
I think we can't understand rates,
we can't understand charges if we don't understand
what the costs are that go into that utility.
So we have to have that basic understanding.
I think there's another part of this utility
that is actually not part of this docket,
but it's a sidebar that I think there are some questions
about what their rates are and what they're earning.
And as as a side, we might ask
the right regulatory division
to look into their rates and see,
and report back to us in a few weeks and see if there's
a reason for a full-blown rate case,
or if they feel like their rates are just and reasonable
and in line.
-: Commissioner Glotfelty,
I am very much in agreement with your point.
I actually spent some time looking into this issue
and what I discovered,
and I appreciate staff's research into this issue is
that the greenshore system that was acquired
by Undine Development used to be owned
by PK-RE Development.
PK-RE Development sought rates at the TCQ
and the TCQ approved rates in 2012.
And those rates that the TCQ approved
in a settled case constitute a rate base of, depending
on how you look at the numbers,
anywhere from five to $6 million,
when the purchase price of the system itself
was 1.8 million.
So to your point, Commissioner Glotfelty,
I do think that rate regulation needs
to assess whether Undine Development is over-earning.
I think it's extremely prudent because if we ultimately
approve a system improvement charge,
then Undine Development wouldn't come in for a rate case
for another eight years,
as they are claiming they're a class-C utility.
So that's 18 years of no actual full-on rate case.
And so I think we gotta be mindful as this is the first
system improvement charge case before the Commission,
but as additional water utilities come in,
that we need to be mindful as to who the utility is
and also know that if we do approve
a system improvement charge,
depending on what size the utility is,
they may not come in for another four,
six or eight years after the charge is approved.
So wanna make sure that we are not approving
system improvement charges
that lead to over excessive over-earning.
So I agree with your point Commissioner Glotfelty.
I do think that rate regulation
should take a closer look at Undine Development
and report back to us in parallel with this process,
whether or not they're over-earning.
-: I appreciate you highlighting what are certainly
some big discrepancies in this case,
and agree that they need to be addressed and evaluated.
-: You're welcome.
(Peter laughs) -: So, Mr. Chairman, I'd agree
on all parts, as you have implied.
I don't believe we're limited in our scope as a part
of this proceeding.
We have a duty under the law.
I do believe there needs to be some fact-finding in terms
of determining the affiliation of all the arms
of the proposed utility to see where we fall
in the spectrum of the classes of utilities
that we're talking about,
and the number of years that could be impacted by any type
of approved rates.
And so I'm in agreement with the Commissioner.
-: All right, so sounds like we've got
a number of questions that we want to ask
OPDM to include in a briefing order.
First is questions about asking
parties to define and articulate
the nature of the entities and relationship of the entities
underneath Undine.
-: Sir, we were not intended to brief that issue.
It's factually intensive.
We just wanted to put that issue into the issues
of the preliminary. -: The preliminary. Okay.
-: Yes, sir. -: Gotcha.
So we've got, laid out the issues
to include in the preliminary order.
Stephen: Would you like me to run through
the briefing issues?
-: That'd be excellent.
Summarize our discussion, if you will.
-: One of the issues we'd like
to brief the parties have raised in this case, is whether
the provisions related to affiliate charges apply
in a proceeding for a system improvement charge.
-: I think another one is,
should the utility be required to offset costs
and base rates that are no longer needed
because of the improvements
included in the system improvement charge?
And then thirdly, our developer contributions
in aid of construction included
in the cost for plant provided
by explicit customer agreements-
-: Agreed -: Or funded
by customer contributions in aid
of construction under 16 TAC 24.76, subsection DE3,
and then can cost of eligible plant
for which Undine Development is seeking
a system improvement charge, be considered
to already be included in the utility's existing rates,
just because the utility is currently over-earning
through its base rates, if it is, which may be determined
by any type of investigation
on the part of the raised (indistinct).
-: We'll include that
in the briefing. -: In the briefing.
-: And that touches on the point of concern
you mentioned earlier.
-: Yes. Yes.
So we've got four issues, as laid out,
that would be part of a briefing order that would go out.
And then the issue of the who's the entity
or entities that constitute to utility is just
an issue that will be in the preliminary order,
'cause it's a fact-intensive,
it needs to be developed in the record.
And so that's just added to the preliminary order,
but for now we're not issuing one out,
but we're gonna issue out a briefing order to get briefing
on those four issues.
And then we can either, I guess,
just wait until we get the briefs and decide
those four issues and then issue out a preliminary order.
-: That works for me if- -: I believe that's-
-: I thought we could probably get briefs back and get
this back to you at the July 14th open meeting.
-: We'll ask for responses to briefing order by end
of the month.
-: Yes, sir.
Around that 2 or so weeks, 14, 15 days.
-: Let's do two weeks from today. Does that work?
-: Yes, sir. -: Sounds good to me.
-: Yep. Yep. -: Good for everybody?
-: And in parallel, the rate regulation review.
-: Do you want to do an order on that or just to have
your instructions here at the open meeting to do that?
-: I think instructions. -: I think instructions.
-: I'm looking at Daryl right now. He acknowledges.
-: And then just for clarity,
because you had emphasized evaluation
of Undine Development Company,
which has its own rate schedule,
should the earnings evaluation be limited to Undine itself?
Or given the uncertainty of who we're looking at,
do you want... -: And including affiliates?
-: Do you wanna do one with everyone in it,
and one just looking at Undine Development?
-: Yeah, let's do that because that will at least help us
as we review ultimately, who is the entity.
-: Yeah, that will help inform the later decision.
-: Yeah, both of those pieces will inform the other.
-: Wait, so say that again. You want to do...
-: So we would have ask rate review
to do two evaluations here.
One of the entire Undine system.
-: Got it. -: Okay.
-: And another one, separate analysis just
of Undine Development Company,
which has its own separate rate schedule.
-: Got it. Yes.
I think that's the right thing.
-: The actual provider
and then the entire corporate, correct?
-: Yes. Yeah.
I think if we don't know what the entire holding company is,
then understand what the costs are.
-: And that's, I think, to Commissioner Cobos' point,
both like that analysis will also compliment
the results of the briefings we get
on definitely the character of each of these entities.
-: Correct.
You could even ask them to speculate if they got everything
they're asking for in this docket,
would that cause them to go into an over-earning state?
-: Well, I think we've got enough to chew on here.
Stephen: All right.
People just wanted me to complicate things.
So I'm trying to accommodate them.
-: We've got plenty to work with without any rampant
speculation from the bench there.
All right.
I think OPDM has everything they need.
-: I got a feeling this thing may result in a memo,
so I'm not gonna make a motion on this.
-: (laughs) There's one other issue that I think we need
to address, and that is that the parties
wanted to limit the list of issues
to the list of issues that were provided about the parties.
And I think that, just as a matter of standard practice
and law, that the Commission is not limited
by the list of issues submitted
by the parties requesting a hearing.
I mean, our standard practice is
to not only get lists of issues from parties,
but to ensure that all the issues are addressed to allow us
to issue out an order in compliance
with our Commission rules and statutory authority.
-: Would you like to add that as an issue
to the briefing order?
-: No. It's just a statement.
-: It's our opinion. -: It's our opinion.
It's our conclusion on that issue.
-: You mentioned earlier you agree with that.
-: I do agree with that, yeah. -: We all agree with that.
Yes, thank you for clarifying that.
All right do- -: So just a motion
to delegate a story issued briefing order
on the issues identified.
-: So we got a motion.
Do we have a second? -: Second.
All in favor, say aye. -: Aye.
None opposed. Motion passes.
Thank y'all for work, everybody
for working through all that.
-: You bet. -: Next item please, sir.
-: Next its item 18, docket 5229,
petition of Crown Castle Fiber
against Lincoln Property Company.
A proposal for decision filed on April 7th of this year.
-: Okay.
I think we've concluded the water portion of our agenda.
Moving to communications and electric.
Is that right? -: Yes, sir.
-: All right.
Crown Castle Fiber,
thoughts, comments?
Seems pretty straightforward.
-: From my position, sir,
I would support moving to adopt a PFD,
but modify it to dismiss without prejudice,
because the question of notice sufficiency
does not determine the merits of a case.
So I base my decision on that.
-: Yeah, agreed. You gotta show up.
-: I agree.
-: All right. Do we have a motion?
-: So moved.
-: Second. -: Second.
-: All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
-: Next item I believe is...
Stephen: Moving to electric, sir. Item 21.
-: Moving to item 21.
-: Docket number 52120, petition to Simon Property Group
and Simon Property Group Texas for declaratory order.
A proposed declaratory order was filed on March 3rd
of this year.
-: Thank you, sir. Thoughts, comments?
This is multi-jurisdictional, if you will.
-: Yeah.
I think the Commission should decline to issue out
a declaratory order at this time because the requested
declaratory ruling is premature.
The Florida complaint case involves a lot of different
violations of law, federal and Florida state law.
In addition to the references
to the violations of the Commission rules and PURA,
I think the basis for issuing out a declaratory order is
when is only appropriate when the entire controversy may be
determined by the judicial declaration,
and we would not have that impact
on the Florida complaint case
by issuing out a declaratory ruling.
So I think it's it's premature
and is not pivotal in the case.
And so I would recommend that we deny the request
for a declaratory ruling or order in this case,
and also request that we take official notice
of the Florida District Court's order to support
the Commission's denial of the petition.
-: Mr. Chairman, I agree.
The Florida court said the reference is not pivotal
to the resolution of the claims,
and so what I'm in alignment with you, Commissioner.
-: Agreed on all points. -: I'm gonna agree.
-: All right.
Does someone wanna offer a motion that takes official notice
of that Florida case?
-: Yeah. Yes.
So the motion would be to deny the request
for a declaratory ruling in this case
and for directing Commission advising
to take official notice of the district court's order
to support the Commission's denial of the petition.
-: And I would second.
-: Got a motion and a second.
All in favor to say aye. -: Aye.
None opposed. Motion passes.
Thank you, Commissioner Cobos.
Next item please, sir.
-: Next item's item 24,
but you said you wanted to take up item 25 first,
so item 25 is docket 53442,
application of CenterPoint Energy Houston Electric
for approval to amend its distribution cost recovery factor.
Before you is an appeal of SOAH order number five.
-: Thank you, sir.
And we're taking up item 25 and then 24
and Commissioner McAdams has a memo.
Would you lay that out for us, please, sir?
Yes, sir, and thank you.
As I set out in my memo,
I believe that CenterPoint may request recovery
of section 39.918 costs through a DCRF proceeding,
but not as part of a DCRF rider itself.
The section 39.918 costs should be in a separate rider,
in my view, from the DCRF rider.
Section 39.918J in statute states that a utility may
request recovery of a reasonable and necessary cost
through a DCRF proceeding.
-: Sorry. -: That's all right.
Thus section 39.918J requires
that reasonableness and necessity and compliance with PURA
be determined through a proceeding under 36.210 in statute
or in another rate making proceeding.
This is fundamentally different from section 36.210
in the Commission's DCF rule.
The DCRF rule contemplates the reasonableness
and necessity of DCRF cost being litigated
in a future base rate proceeding,
unless the presiding officer finds good cause to address
those issues in the DCRF.
CenterPoint can still request
approval of a separate rider for section 39.908 costs
in this DCRF proceeding or in a standalone severed out
rate making proceeding, or in a base rate case if it wishes,
but either way the rider should be separate, in my view.
A DCRF proceeding simply serves as a venue
for requesting section 39.918 rider.
Based on that, I recommend that the Commission
grant the appeal in part and reverse
the SOAH ALJ's decision to dismiss CenterPoint's request
for section 39.918 costs from this proceeding.
However, I also recommend
that the Commission instructs CenterPoint
to amend its application to separate
the section 39.918 costs into a separate tariff rider
in this proceeding.
Once CenterPoint amends its application,
the Commission should consider
a supplemental preliminary order
addressing issues under PURA 39.918.
The crooks of it, Mr. Chairman, is DCRF
is an expedited rate making proceeding.
It is designed to provide you expedited recovery.
CenterPoint has the statute, again,
as per my memo, and my view is clear,
they can avail themselves of it.
The question is whether something with the magnitude
of a mobile generation could bog down
a overall DCRF proceeding
in litigation, or should it be carved out
to where just and reasonableness is still evaluated.
And then we establish precedent moving forward
to where these cases can be judiciously adjudicated,
and again, processed expeditiously,
which is the intent under the law.
-: I agree and well, again,
highlight your point that the most important element
of this is this cost recovery can be included in this DCRF.
-: Yes, sir.
-: And then I've got a couple thoughts to add,
but I'll open up your thoughts and comments before.
-: Okay. Sure.
So I think, you know, I generally agree
with you, Commissioner McAdams.
I just have a slight nuance. -: Okay.
-: So with respect to the first issue, I agree.
I think the legislation HB 2043
and PURA 39.918 are clear
that a TDU may recover their mobile generation costs
in a DCRF proceeding.
The legislative language is clear and unambiguous.
And so the question really is can they do it
in this DCRF proceeding? -: Mm-hmm.
-: And if so, how? -: Sure.
-: So from my perspective,
in reading 39.918 and 36.210,
I believe that the, SOAH ILJ's water number five is contrary
to the overarching policy goals of the legislation,
which is intended to enhance the state preparedness
for future weather events and great emergencies
by incenting TDS to invest in the mobile generation.
I think that when you read both sets of law
and the Commission's rule
and the Commission's order adopting the rule,
and that rule being 24, I'm sorry,
16 TAC 25.243,
I believe that that CenterPoint
and that TDUs can recover their mobile generation costs
in a DCRF proceeding,
and CenterPoint can do it in this DCRF proceeding
through a DCRF rider,
because the statutory law
in 36.210 states that
the allocation factors must be consistent with,
that the inputs must be consistent with the allocation
factors approved for each rate class in the last rate case.
Now, when you go to the rule, it says
that the inputs for a DCRF formula, and you bear with me,
got a lot of information here,
that basically, if the input in to a DCRF formula
is not clear that you can rely on the information
that's similar to it,
so it doesn't have to be exact or the same.
So when you go back and you look at the Commission's order,
adopting the DCRF rule,
the Commission responded to a party's argument
that, the party argued, that before a utility applies
for a DCRF, a contested case proceeding should be required
to establish a DCRF formula inputs.
The Commission responded stating that such a requirement
would be inconsistent with PURA,
which PURA 36.210.A1,
which provides for an expedited proceeding.
-: That's right.
-: So based on my reading of 36.210,
the rule and the Commission's order adopting the rule,
I believe that the Commission can adopt
or can approve these costs in the DCRF proceeding,
through a DCRF rider,
and I will also say that I think it's a cleaner way
of approaching this issue.
I know you wanna separate it out, and I know why,
but we've never really separated out any costs
in a separate rider and a DCRF proceeding.
I know this is a case of first impression,
but we would be setting up a framework that hasn't really
been used before in a DCRF proceeding to separate out costs
in a rider, and so I'm not really sure that it's necessary,
and I think from my reading of the law,
it's possible to just approve it in a DCRF proceeding.
Of course, you know, they got parties
gotta go through this proceeding,
but it's possible to approve these costs
in a DCRF proceeding, through a DCRF rider.
And then we can reconcile in the next base rate case
that CenterPoint files. -: If it's-
-: Which you're required to. Absolutely.
There's a true up at the end of the rainbow,
you know, on that.
So I just worry, take an army term.
This thing becomes a bullet magnet, you know,
and then the whole DCRF is kind of contemplated as a part
of the bullet magnet that's housed within it.
And so, yeah, I get it, Commissioner.
-: I guess another way to approach it
is even if it's not required
to be severed in a separate rider,
is there necessarily harm or foul other than setting
the precedent of the ability to do that?
-: Well, I think that we haven't adopted a rule yet.
My understanding is we're gonna have a proposal
for publication at the beginning of the next open meeting
that implements 39.918,
but I think that it doesn't cause a problem necessarily,
but I think it's unnecessary complication
to a DCRF proceeding.
We're just going to evaluate 'em as a DCRF cost
as distribution invested capital,
then we should just do it as all in one rider,
because we're gonna end up setting precedent here,
and so we're gonna end up having to evaluate the rest
of these investments with separate riders,
that to me...
-: You mean the next mobile generator case,
or- -: Sure. Sure.
The next time a TDU comes in with mobile generation costs
in a DCRF proceeding.
-: So is that risk isolated
to the mobile generator and cost recovery?
Or is that precedent,
are you concerned that precedent expands to a broader
universe of potential cost recovery?
-: Well, potentially, I mean, we have other types
of new distribution investment capital costs.
I mean, are we gonna start approving different riders
and DCRF proceedings for those?
-: We're plotting a lot of new ground here.
It's not...
All of this is very new.
-: I think you have good thoughts on it.
What do you think? -: Well, so,
I wanna step back and say, obviously,
I respect the legislature passed this and allowed
TDUs to get into the generation business
in emergency situations.
That troubles me having gone back to the unbundling
of the electric system and kind of blurring those lines.
This is the first time we've done that.
And this is not my...
I would not have done that, but the legislature has spoken.
So I'm here to implement.
There are some challenges that I see with this.
So I'm not getting into the rider yet.
I just want to give you all a thought on this.
And I don't understand how it works,
that a TDU puts
these mobile facilities in place.
They can't charge for energy and they can't be
part of price formation, so how do they build?
They don't even have a interaction
with a QSE or a retail electric provider.
And it says that a T&D utility that leases facilities
may not sell that electric energy or ancillary services
from those facilities.
So if they're not selling it,
and if I look at my discussion with CenterPoint has been,
you know, they want to use a mobile generation facility
to help in the event that there are rolling outages.
They can take a couple hundred megawatts
of load offline, use these generators
to roll outages where it's helping the system.
And I think there's value in that,
but I just don't understand the price side of it.
Does that mean that every person on that circuit
gets free energy during that process?
Or is there there's another provision that says
that there should be an adjustment of the usage
for billing purposes out of the retail customers'
retail electric provider?
I don't know.
It just seems very convoluted and hard to understand
when it's just black and white on paper.
That's why I would suggest and support
Commissioner McAdams that just a rider,
I mean, this is a brand new type of facility
that's going into a DCRF.
We're historically talking
about poles and wires, substations,
and other types of equipment,
and this is a totally new piece of equipment
and something very different.
And I think we've seen interest at least in this docket,
from the other TDUs, that they're gonna do
something like this,
and would think that if we can at least have those set aside
now in its own rider, but in this DCRF proceeding,
I would say that that for me, is the best way
to evaluate those costs going forward.
-: It's a layer of transparency.
-: So by separating into its own rider,
you would provide a venue for answering these questions
and evaluating these issues
without holding up the broader DCRF proceeding?
-: Absolutely. Yeah.
And I mean, I think the language,
it's pretty clear on the law.
I mean, they have the authority to recover this.
They have the authority to make these investments.
It's not questioning that at all.
And I know that there's value in this.
Like I said, the blurring of the lines
of the separation
makes me a little nervous, but the law
is passed and I'm here to implement, but...
-: That's the most important part.
-: (laughs) That's right.
-: That all makes sense to me.
And those are important questions that need
to be answered and have those issues articulated.
I would add if you're laying out
a list of questions being answered,
I'll jump in and add- -: Please.
-: Request some clarity on
when these resources should be deployed.
Is it system wide outages? Is it local outages?
Because I know specifically for the CenterPoint territory-
-: Hurricane. -: Hurricane damage
to both transmission and generation assets is a big issue,
so even if they're not taking load offline,
they may be getting load that was removed from the system
due to hurricane damage back online.
-: Yeah.
-: So that's an important clarification
I think we need to make.
-: Being a load pocket, I think that they're
in a pretty unique situation down there,
and we ought to have that clarified.
-: Well, the statute says
that it's for an extended power outage,
which has lasted, or is expected
to last more than eight hours.
-: Right. -: So, I mean,
I think that's, you know,
and if there's a question, I think in this case,
as to whether CenterPoint used those mobile generation units
in the past, or will use them in the future
before their next rate case appropriately per the statute,
then that could be litigated out in the base rate case,
right, as you prove up your cost.
Reasonable, necessary and prudent review
would be conducted then.
So, I mean, okay. I'll let you proceed, Chairman.
-: Yeah, I appreciate the points.
I think the general sentiment is
we do want it in a separate rider
so we don't hold up the DCRF and we can answer,
we can have some of these questions answered and litigated.
I certainly, and importantly,
it's expected outages of eight hours or more,
the question is that if a hurricane hits Houston,
but there's no system-wide problem in Abilene and Amarillo
and Odessa, do we not want to deploy these generators
for people who are without service in Houston?
I think that's not clear in the statute.
I think the intent is clear.
-: Say that again? I didn't understand that.
-: The difference, like,
so Commissioner Cobos laid out the statutory requirement.
These can only be deployed in the event of blackouts
of eight hours or more? -: Mm-hmm.
-: Or expected to last eight hours or more.
It's unclear if that's outages system-wide.
-: Right. -: The entire ERCOT grid-
-: Right. Yeah. -: Or localized outages,
which is the key question that we need to answer.
I mean, I think the intent,
my understanding of the intent is they certainly want,
especially in this region, these mobile generators
to be deployed if there are local outages,
as in particular, as a result of a hurricane
that knocks out transmission resources,
and I certainly would not want
to deprive the people of Houston or the Gulf Coast
access to these generators and access
to power just because said hurricane did not
create a system wide outage across ERCOT.
But that's a question that needs to be answered
and clarified as part of which I think
is another good reason,
like you said, to have this issue separated.
-: Yeah.
-: Well, that could be addressed in the rulemaking proceeding
that's gonna be opened up by staff.
And I agree with you, Mr. Chairman, I think, I mean,
that's the whole point of letting
the TDUs own the mobile generation units.
They serve specific service territories that are challenged
by different weather patterns or, you know,
natural disasters, hurricanes, tornadoes, you name it.
We've got everything in this big state.
So, but as we move forward
with the general policy foundation
and the rule, then we can, you know,
better hammer that out in the rule.
-: We certainly can.
I don't know where this falls
in our very crowded rulemaking schedule,
but in the meantime,
I certainly don't wanna hold up their ability to move
forward with this recovery. -: Agreed.
-: How would we get some answers to some questions about,
you know, kind of the mechanics
of the interaction between the customer,
the TDU and the retail electric provider in terms of-
-: I suspect Mr. Smeltzer can...
-: Oh, hello. (indistinct)
-: Oh, dear.
I don't usually participate in contested cases.
I come up because you guys were asking questions
that some of which we hadn't thought about
in the rulemaking team,
so I wasn't sure if I should clarify.
We'll still try and keep it on for next open meeting,
but we may have to, we're gonna go back
and scrutinize this transcript and see
if we need a little more time
to make sure all these are answered.
So I don't wanna weigh in on the specifics
of a contested case.
I mean, I think that in our meetings on the rulemaking,
I can tell you that the TDUs will spend
a lot of time thinking about this.
So I think there are people that in this room that know
the answers to some of your questions,
but I wouldn't want to opine
on a case that I'm not a part of.
-: Well, it may be possible.
'Cause some of the things you were asking,
I don't think are issues in this case.
And they could be,
perhaps, we could propose questions in the rule proposal
to have people address them.
-: I think I agree that they technically
are not part of this case.
They are general questions on the implementation
of the section of the law- -: Right.
-: On how that functions, but think-
-: We can tackle it from both sides, too.
Doesn't have to be one or the other.
-: Yeah, and think that, again, I feel that,
you know, these are not distribution poles,
this is not a conductor.
This is something that's very different
and having its own line item
and its own rider that's separated out
so that we can see all the costs that are associated
with this new statutory provision
seems to me in this case to be the best path forward.
-: Yeah, and we're on the same page, like,
we're on the same page with respect to,
can a TDU recover these costs in a DCRF proceeding?
Yes, the law says so.
The question is,
in this case, we agree. -: Correct.
-: The question is how.
I certainly respect where you're coming from.
-: Oh, and-
-: I'm just coming from my experience
dealing with DCRF proceedings and just reading the law
and based on my review, I think that it could all
just flow smoother if we just get
it through a DCRF proceeding rider.
It is, you know, a case of first impression
to have a separate rider in a DCRF proceeding.
I'm wondering mechanically how it works
with a DCRF proceeding,
like to the point of, we don't wanna slow down
the DCRF proceeding because there are,
you know, deadlines with the DCRF proceeding,
but how does it work with when you have a separate rider
in there, in a DCRF proceeding?
I mean, you're gonna have to have CenterPoint amend
their application, separate these costs
into a separate rider, right?
-: Well, I would think so.
So, you know, how to design that particular rate.
-: So then is it part of the DCRF?
It stays in, this is this docket,
but it's just an amended application that separates it out?
-: It seems like the application needs to segregate,
as I understand it, to segregate
the cost of all the distribution cost here
and the mobile generation cost here,
and the rate will be designed, the DCRF will be designed
for these costs
and the mobile generation rate recovery rider,
whatever it's called, will recover these costs right here.
They will go in parallel,
and if it gets tied up, I mean,
they can sever the...
If the DCRF is done and they settle on all that,
they can sever it out and send it back
and do a final order on that and continue on.
-: So are you relying on the...
Well, 'cause you're saying we'll separate it out
and the rest of the distribution investment capital costs
that are not related in mobile generation will be part
of the DCRF rider, but then we'll have a separate rider
in a DCRF proceeding in the same application.
Yeah, I mean, presumably
CenterPoint's already separated these costs
in their application because I think they have spelled out
that they have over a billion dollars
worth of costs that exclude
the 200 million invested in these mobile machines.
-: I know just a smidgen of what's in their application.
So I don't know what the detail is.
Maybe it is already in the shape that they can move forward
as is, I don't know.
-: Well, that's what I recall
based on my review of the application.
-: Yeah. -: And so again, I'm not trying
to complicate this discussion up.
I'm just trying to figure out, you know,
how this all works mechanically and procedurally, you know,
and so with the rider then, we approve a rider,
ultimately, you know, we'll approve a DCRF
and we will approve a rider,
separate rider in a DCRF proceeding.
And then when they come in for a rate case,
they'll take the cost and that rider,
reconcile it, you know, do their, you know,
we'll do our just and reasonable prudent review process,
and then it stays as a rider
in the rate case application?
I mean, I'm just trying to figure out-
-: Hopefully by then we'll have our rule done with,
but you know, the cost recovery rider's,
usually in a base rate, get zeroed out,
items get moved into base rates.
-: Okay. -: And then we start over
with the next round of recovery factors.
-: So you're saying there's a reconsolidation of the entire
rate structure with all the expenses?
I'm seeing a lot of head nods behind you.
-: Yeah, I mean, that's how the other ones work.
-: Yeah. -: I mean,
I think my understanding of this, it's a new statute,
we haven't gone through a case yet,
but this is similar in the sense
it's wanting to capture the investment in this type
of facility. -: Absolutely. Yeah.
That all makes sense to me.
It may be on the front end,
a little more complexity and administrative burden.
I think that'll yield some clarity,
both on the actual rate recovery of this new,
unique element of a TDU that we've not dealt with before,
and also allow a separate venue to answer some
of the questions that have been laid out here.
-: Well, it does in this particular case, sir,
but the Commissioner McAdams memo
has a suggestion in it that you could do a separate mobile
generation cost recovery rider
in a standalone rate proceeding,
where that's the only thing there that you're not tied
to putting, you don't have to recover it
in a DCRF proceeding.
And if I read his memo right,
he suggests you could do it here,
you could do it at base rate procedure,
you could just file- -: You can use this
as a vehicle or you can carve it out.
But again, the beauty of the DCRF
is it expeditious recovery, you know?
So- -: Well, it is here right now,
I think is the advantage of it in this case.
-: That's very important. -: Hurricane season's upon us.
-: So the statute says DCRF or other rate making proceeding,
so you can rely on the other rate making proceeding.
The DCRF has deadlines, the rule, the statute, right?
A rider, if we do it in a separate rider case,
won't necessarily be tied to those same deadlines.
-: Whatever we end up putting in our rule.
I mean...
-: It's in the process.
-: If you narrow down and only looking at one particular type
of cost, it eliminates
a lot of complications
in a major rate case where you're looking
at all kinds of costs.
So I don't know that you can't...
If you decided to write a rule and gave and gave them
the option to file a separate proceeding just for this,
that you could put the same type of timelines that you have
in the other recovery factor cases.
-: Something to consider in our rulemaking.
-: I don't know. -: So, okay.
So my final question then, because this is an application
for a DCRF would then, okay,
we would have to ask CenterPoint to amend
their application, take those mobile generation costs out
and file a new application
for the mobile generation costs in a separate rider case?
-: No, I just said I think his memo suggested
you could do that somewhere in the future.
Right here, I think y'all are all on board
with it being done right here, right now.
If their application has the cost efficiently identified,
maybe the only thing they have to amend is the title
of their application, application to amend DCRF
and establish mobile generation cost recovery.
Maybe they don't have to do anything
if their application has...
I don't know, I haven't looked at the application
in that kind of detail.
-: All of those can be addressed in the rulemaking.
-: Well, and it can be addressed by the parties in the DCRF.
I mean, if- -: They can settle.
-: If they think the costs are adequately identified,
that they can move forward with the review of them,
I don't know why they need to do anything
but just get going. -: Okay.
Well, yeah, and I think that's right.
If we move forward with this new framework
and a DCRF proceeding in our rule that,
I think I'm hearing from you, David,
will come up in the near future,
we can finish off that process by capturing
that rider framework in that role.
-: We certainly can do that.
As contemplated, we weren't looking at...
We hadn't parsed out those details, but we certainly can.
And I think Mr. Journeay has volunteered to join
the rulemaking effort on this,
and so that will be helpful. (Commissioners laugh)
-: He certainly has to. -: Very painful for us
but we'll pull through. -: It's his rider proposal.
(Lori laughs)
-: Well, that's the kind of teamwork
and collaboration we celebrate here at the PUC.
(Commissioners laugh)
-: Thank you, sir. (Commissioners laugh)
I mean, there is the one complication though,
of looking at the reasonables and necessity
of these particular cost in this proceeding,
which you don't do with the other cost in the DCRF.
So there is some complication here beyond just
putting some of the cost recovery
in this rate and this rider
and some of in this rate and this rider.
-: So you're saying that we will or will not look
at the reasonable necessary of those mobile generation costs
in the rider?
-: If I read his memo, right, he says yes.
-: Yes, absolutely.
-: Okay. Okay. -: Oh, absolutely.
-: Okay, which is a little bit different than DCRF
because you only do that unless there's good cause shown.
-: Right. -: So yeah.
I mean, I'm fine with that,
but we also will do another scrub down in the rate case?
-: It is true. -: Yeah, absolutely.
All right. -: So I think we have a plan.
-: I think we're in a good spot.
-: I'm gonna have a motion. (Lori laughs)
-: Give it a shot. -: All right.
I'd move to grant the appeal in part
and reverse in part the SOAH ALJ's decision to dismiss
CenterPoint's request for section 39.918 costs
from this proceeding.
Additionally, I'd moved to instruct
that the Commission instructs CenterPoint
to amend its application to separate
the section 39.918 costs into a separate tariff rider
in this proceeding.
Is that adequate?
-: I think it captures it. -: Motion stands.
-: We have a motion.
Do we have a second? -: Second.
-: We've got a motion and a second.
All in favor, say aye. -: Aye.
None opposed. Motion passes.
-: Right. That's good. -: Now, I think we need
to do a supplemental preliminary order
to deal with these issues and bring it back to you quickly.
Peter: Yeah. Yeah.
-: Very quickly. -: I'm good with that. Yep.
-: Now I gotta clean up 52976, too.
-: Next.
-: So that would take us back to item 24,
which is docket 52976,
petition of CenterPoint Energy Houston Electric to add
to Chapter six of its tariff
for retail delivery service.
Commissioner McAdams' memo addressed this.
-: Related topic right on cue, Commissioner McAdams.
-: Thank you, Mr. Chair. -: Lay out your memo for us.
-: As per the memo,
I would recommend that the Commission request
that docket management prepare a proposal
for decision dismissing docket number 52976.
The possible grounds could be unnecessary duplication
of proceedings or other good cause shown
because it is more appropriate to address
the proposed tariff language
alongside other rate making issues that will already require
changes to Chapter six of CenterPoint's tariff,
if the Commission establishes a new rider
for section 39918 cost.
-: Which means go put it
in the DCRF proceedings. (laughs)
-: That is exactly what it means. I would so move.
-: Thoughts, comments?
-: I would second that one. -: Second.
-: I've got a motion and a second.
All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
Nicely done. -: Thanks.
-: On average. Your layouts are not too long.
-: We haven't gotten to that next memo yet.
-: You have another one? -: No, no, no.
It's the good one. It's the sugar.
Next item, please, Mr. Journeay.
-: Item 27 is docket 53625,
The application of SWEPCO for a CCN and related relief
for the acquisition of generation facilities.
Draft preliminary order is filed on June 10th.
-: Thank you, sir.
As much as I hate to say it,
this is an issue where costs incurred outside
of the boundaries of Texas are potentially levied
upon Texas citizens,
which Commissioner McAdams has taken the lead on.
So you, once again, may have some thoughts
or opinions on this?
-: Yes, sir.
In its proposed list of issues,
SWEPCO raises the question of whether
the generation facilities in question
that are outside of Texas qualify as a transaction
under PURA 14.101.
I believe, and I welcome your thoughts,
that this section is a question of law that does not need
to be litigated and can be settled here.
If you all agree, then I would move
to have OPDM request briefing on this issue
while simultaneously issuing the preliminary order.
And so I would like some feedback
on our scope and again, how those facilities impact us.
-: I agree with the addition of that issue
to the preliminary order.
And I also agree with the procedural approach.
I think that the case we can go ahead and issue out
a preliminary order and start addressing the issues related
to the CCN, which unfortunately entail
a different set of criteria.
And then once we get briefing,
we can make a determination on this PURA 14.101 issue,
which is a separate set of criteria when you review
transactions on the basis of whether or not they're
in the public interest. -: Right.
-: Thoughts, comments? -: So just,
I'm a little confused.
Do you all want to go forward with the preliminary order
or delay the preliminary order until it gets briefed?
-: The idea would be to issue the preliminary order
concurrent to that have briefing on the question of law
on whether we can actually impact,
qualify as a transaction under the 14.101 stipulations.
-: The draft preliminary order has issues that as if you do
have to address the 14.101. -: Okay.
-: If you wanna do that.
We'd need to pull those issues out if we're gonna issue
the preliminary order until after briefing.
And then depending on your decision,
we might have to do a supplemental to put 'em back in.
-: Okay.
I just understand there needed to be a bifurcated approach
'cause the question of law, so...
-: Well, usually when we brief issues for preliminary orders,
they're questions of law, they're not fact issues.
So I mean, this could be a quick brief
into if we could do it and have
it back on the July 14th open meeting.
-: But could we approve a modified preliminary order
and have you just take it out,
take out the portion. -: We could do that.
We could pull all those issues out
for the out-of-state facilities in brief,
and then depending on your decision,
if we needed to put 'em back in,
we could do a supplemental order later.
-: So we can do parallel,
which may require editing down the road
or do a quick briefing.
-: I'd rather have input on it sooner rather than later.
I mean you're kind of impacted by this stuff, too.
-: I really, I'm not married to either approach.
I think, you know, mechanically,
we can approve a preliminary order
with changes consistent with our discussion
that would remove the PURA 14.101 issues
and get that process going.
So the parties can start addressing the CCN criteria,
in this case.
And then while we await briefing, in parallel
we will get briefing, and then we'll issue out
a supplemental, we'll make a decision, and either, you know,
issue out a supplemental preliminary order,
I think at that time, that will address PURA 14.101.
So we could do it in parallel.
I don't think it's complicated,
or we could wait and do it all at once, I'm...
-: I guess, if it's either or is there.
Is there... -: We make fewer mistakes
cutting stuff out than putting stuff in.
-: That's true. (indistinct)
-: And the magnitude of that feedback.
I mean, it impacts a lot of stuff,
so again, the parallel approach
would get us answers sooner rather
than later for both of our purposes in MISO and SBP,
just so that we proceed forward with that view.
'Cause this is gonna be happening all over the country.
You know, these type of readjustments of resources.
-: Yeah, absolutely.
In terms of staff resources- -: Yeah, no problem.
-: Is one better than the other or is it
a six one way, half dozen the other?
-: Minuscule less if we briefed and waited
on preliminary order,
but it's not really enough, I think to worry about.
-: Okay.
-: So I have one further question,
if it's appropriate now. -: Okay.
-: So I'm interested in this case.
Obviously SWEPCO wants to purchase generation facilities
that are not built yet in areas of MISO
that has huge amounts of congestion.
And there's nothing in the preliminary order that talks
about what deliverability or congestion costs might be
associated with these facilities,
and I'm wondering if we could at least just put a question
in there that might address that as it goes to SOAH,
to ensure that we understand full costs associated
with transmission costs associated with the deliverability
of this energy.
-: There's a general issue in most of these cases
talking about effective upon other utilities and stuff.
We did have one with Entergy,
my memory is not serving me well, that we had
a similar type of discussion,
but I don't remember if we put special issues
in on that one or not.
I'd have to go look.
But that- -: Is there any...
Can't put it in? -: Does that mean we can't
put it in this? -: No. Well...
-: Maybe it just means to answer the question twice
in a different way.
-: Sub-question.
-: You could tell us that you want that issue added
and we'll go do the best we can to put it in,
and if we don't get it good enough when it comes
for signature, then we'll have to bring it back
to the next open meeting
and have further discussion on it.
(tone dinging)
Wait a minute, the guy who might know something.
(Commissioners laugh)
-: Phone friend, I like it.
-: Lifeline.
-: Again, outstanding collaboration
amongst team members here. -: He tells me to look
at (indistinct) 4B, which I guess is an issue.
Well, it does talk about congestion charges
for the need of it.
So maybe these are the ones that we did similar ones
with that Entergy case that's in my mind.
And so it's on page 13 of the draft.
Will: Oh yeah.
-: And there should be a similar one for...
-: Oh, okay. Listen, this solves my question.
So these are in there.
So I'm totally fine. -: Ah, texting's great.
-: Whoever drafted this preliminary order did a great job.
-: Well, he just mail ordered me that answer. (laughs)
-: All right, so which way do we wanna go?
We wanna parallel or.
-: I believe parallel.
I believe sever those questions out.
Let's address that through briefing.
That way we have the answer back and the preliminary,
the proceeding may move forward.
-: Yeah, it's fine with me. -: That work, Commissioner?
-: Yes, sir.
-: Fine. -: All right.
Looking to Stephen.
I would make that motion consistent with our discussion
from the dias. -: Fine.
-: Second.
-: Got motion and a second.
All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
Next item please, sir.
-: Next item is item 28, docket 52710,
compliance filing for docket number 52322,
which was the big ERCOT thing.
Chairman Lake, you've recused yourself from these issues.
-: I'm recused.
I'll turn the chair over to Commissioner McAdams.
Will: Okay, sir.
-: Commission staff filed a memo discussing
procedures related to the distribution of bond proceeds
and other related matters.
ERCOT also filed a memo asking that the Commission
give ERCOT direction on some of the issues raised
in Commission staff's memo on distribution of proceeds.
-: Okay, so you you've read it, you brought it up.
So I see both Commission staff and ERCOT have recently filed
memos in this docket.
So staff, Connie, I know you're up.
If we have questions,
do you envision bringing anybody else up on this?
-: I mean, Floyd is here with me to answer
any further questions. -: Okay.
If he wants to approach, we may have some on that.
So if you would, walk us through the compliance framework
that you have envisioned for the record
for the distribution of debt obligation bond proceeds.
-: Floyd Walker, Commission staff,
beginning with the receipt of the proceeds for ERCOT,
according to the debt obligation order,
there's the proceeds allocation table
that they're gonna follow.
And so they will issue the money to the LSEs.
This is the general case. -: Yep.
-: And then the LSEs will submit confirmation.
I'm sorry, they'll submit it to the QSEs.
QSEs will send it to the LSEs,
LSEs will submit confirmation that they've got it and lay
out their plan for distributing it,
according to the requirements of PURA
and the debt obligation order.
That's sort of the first step.
And then after that process, we want a status update
to show what they've done so far
with the process.
Have they distributed it all?
And that will then allow staff
to sort of audit the process,
make sure the money's been spent properly.
And one of the considerations going with that
is sort issue of refunds.
We understand that that could have the process,
and so we want to get quarterly updates if they're not able
to do that timely by the November 15th deadline
that we've set up.
Will: Okay. Great.
-: That's the general event of the case of there are
some exception to LSEs that are
no longer market participants in that case,
because they don't have QSEs
and ERCOT wouldn't be able to give the money to those,
even if, I mean, that was something we wanted to do,
and so they would withhold that money pending
further instruction from the Commission of that issue.
Will: And on that, you've seen or ERCOT's filing?
-: Mm-hmm. -: You've seen the question
of future directives from us that they have
posed for those out-of-market participants now.
Floyd: Mm-hmm.
What are some possible solutions to that?
What feedback would you offer to that filing.
-: It's staff's position that
that is sort of what they would have
to do in the case
of the one LSE that didn't send verification,
then they wouldn't be eligible to receive funds.
So in that case, ERCOT wouldn't be able to issue.
That's one example
and the other four, because they don't have QSEs,
the debt obligation order says
send it to the LSE's QSE, and so if that doesn't exist,
they really don't have an option but to withhold the money.
And because the debt obligations going smoothly
spell out exactly what to do, in that case,
they hold the money.
Then that's where we'll seek clarification on exactly
what be the appropriate outcome on that.
And there several options, but we'd open up a docket,
and so all those things could be considered.
-: Okay, so you've got several options,
and you wanna wait until
we open up a docket to pose those?
-: Yeah.
We wanna have an opportunity
for the affected LSEs (indistinct)
to, you know, weigh in and say,
hey, this is what they would want.
And then time to have a full recommendation of what we think
the best outcome would be.
-: Yeah, it's a limited number of entities,
as Floyd suggested, and order to get
the best outcome, and implementing this whole
securitization process, we would wanna consider
the specific facts surrounding each of the entities.
Will: Okay, go ahead.
-: So, okay.
So first and foremost, you know,
I do wanna thank Floyd and Harika for laying out
a very detailed plan on how we will ensure compliance
with our debt obligation order
and PURA Chapter 39 Subchapter N.
I think there are a couple of points
of potential clarification.
One is the one that ERCOT requested,
and, from my perspective,
I think what ERCOT wants to hear from us is
that they can actually get that money
and segregate it into an account.
I would add that, you know, if we give that direction
here today and solidify that direction or that clarity to,
or that information directive to ERCOT,
that we request that ERCOT,
hold that money in account until the Commission issues out
an order directing ERCOT to take action
with the money and proceeds.
It must remain segregated and held out until we issue out
an order determining what we do with that money.
And so am I hearing from you,
I'm a little confused, but am I hearing from you
that you want to open up a separate project docket
to lay out specific steps on how ERCOT would hold the money?
-: No, Commissioner Cobos. -: Okay. Okay.
-: It's actually how they would distribute.
It's the holding, we don't believe, it's for the direction.
-: Okay, so you're- -: It's just that
not that they've held it,
our order is saying you will use the money in this way
of the available options that-
-: When we issue out the order-
-: Yes.
-: We determine, you know, for certain,
what's in that account?
-: Yeah, so right now it's that 24 and a half million
that would be withheld.
And then we issue order and it would say,
you know, spend it this way.
-: Yeah, and I'm in support of providing
that clarity for ERCOT,
that they can hold that money in a segregated account.
-: Agreed. -: Pending a Commission order.
Jimmy: Yeah.
-: So any feedback on that? -: No, I'm fine.
I think that's (indistinct) -: I agree.
The direction on holding...
Okay. At this point, procedurally, what do we need on this?
We don't need a motion.
We don't, I mean, this is good to go.
-: Well, it's a little unclear,
but I think that you've given direction.
And so I assume that satisfies ERCOT's needs.
-: And staff has also what it needs to move forward.
-: Yeah, that's my understanding.
-: Okay, great.
With that, Mr. Chairman, I'll hand it back to you.
This is a-
-: I have one clarifying question.
-: Okay. -: (laughs) Sorry.
I'm just wondering, and mechanically, you know,
I'm wondering, you know,
there's the priority list at the very back end
that you've laid out, Floyd and Harika, and you know,
there's a whole process that ultimately culminates
with the November 1st 2023 final report.
As we look at priority, you know,
it's enscripted in our, laid out
in our debt obligation order
that the first priority is refunding and crediting
the retail customers
that paid or would otherwise be obligated
to pay those qualifying costs.
And then the second priority is payment of obligations
to third party entities,
and then the reimbursement to the LSEs themselves.
I guess the question is, you know,
as the LSEs look to credit and refund the retail customers,
must they do that in full before they pay themselves
and pay their parties?
Now, what I'm saying is that, for example,
an LSE got $5 million and they earmarked 2 million
that has to be refunded or credited,
and that's been earmarked and that's consistent
with our debt obligation order.
And the rest is gonna flow through to paying third parties
and paying themselves.
Must they completely conduct the entire process
of refunding and crediting?
They've already earmarked the money.
That's what has to be earmarked as first priority.
Did they have to go through the whole process of crediting
and refunding before they can tap into the rest of the money
to pay themselves back and pay third parties?
There's a mechanical issue there that I think-
Will: Otherwise they'll be waiting,
what is it? -: 'Til 2023.
-: Yeah, I get it. -: For sure.
-: I mean, they've earmarked the money, they've provided,
I believe in the compliance docket, invoices that state
these are the customers,
this is the amount they're setting it aside.
They're not gonna tap into it.
They're gonna exercise all efforts
to refund and credit that money,
and that process will go on till November 1st, 2023,
'til they file that final status report
and we figure out what to do if they have
any remaining money in that bucket.
But the rest of it that's not earmarked
'cause that's not part of the refund or credit process,
they can move forward with those steps.
I'm just trying to get clarity here because I think there
might be some ambiguity.
-: Yeah, no, I get it.
In terms of the mechanics that staff had envisioned,
what do you, what are you looking to see?
-: In the example you used,
what we'd understand is that if there are 2 million
that's available for customer refunds,
that 2 million would be sort of set aside to issue refunds,
but if there's money in excess of that,
then they would be able to use it
for paying other debt obligations.
So the process wouldn't be held up until all refunds are
issued to the other uses,
but the thing is in terms of absolute priority,
that if they can't issue all refunds,
if there's nothing left after that,
then they wouldn't be able to use money for other purposes.
If- -: Mm-hmm.
They'd have to hold it until we get a Commission order,
we issue out a Commission order-
-: Determining distribution. -: Determining, yeah,
what we're gonna do with that money.
-: Yes. -: Okay.
-: So if it's owed,
holds in an account and then we order a disposition,
but if it's over and above that, they access it.
Lori: Yeah.
Floyd: That's Commission staff's understanding.
Lori: They can try to allocate it
all back to the customer,
and if they didn't find all the customers,
then they leave that money there and we figure out
what to do we figure out what to do
via an order. -: We figure it out later.
Floyd: Yes.
-: Good with that? -: Yes.
-: Okay, me too. -: I'm good.
-: I think that settles all business on this one.
Mr. Chairman.
-: All right. That concludes business on item number 28.
And now that we've concluded business on that,
before we move on, just as a personal note,
I do want to say thank you to all of the staff at the PUC
who worked tirelessly on an unprecedented securitization
with unprecedented complexity,
and I'd also extend that thanks to the multitude of people
at ERCOT who spent a lot of late nights,
a lot of Sunday afternoons, and just a lot of sweat
making this thing happen.
There's far too many to name, but many, many thanks
to the teammates on both agencies.
Again, huge, huge securitization,
unprecedented complexity.
So many, many thanks to all the folks.
They know who they are.
Next item, please, sir.
-: I'm guessing the next item is 30,
which is the review of Wholesale Electric Market Design
in which Commissioner McAdams
filed a memo last open meeting,
but held it over for discussion purposes to this meeting.
-: That is indeed our next item.
And, to inform, Commissioner McAdams has a memo.
-: Hot dog. This is exciting. (Commissioners laugh)
Thank you, Mr. Chairman.
As I have had the privilege to sit on the RSC
for Southwest Power Pool and Commissioner Cobos has had
the privilege to sit on OMS for MISO
and Commissioner Glotfelty seems to know
just about everybody in the industry,
all across this country, and you Mr. Chair
try to keep the trains running on time in ERCOT,
one thing has become clear, planning for resource adequacy
in all grids has taken a taken on a new sense of urgency.
And I think we see that with Woody Richardson's transition
over to that position at ERCOT.
It's very important.
With my memo, I am trying to do two things.
One, identify policy areas necessary to grid planning
that are right for reform.
And then two, draw a line among these issues,
issue areas that I believe should be addressed
by the Public Utility Commission through rulemaking,
and then those areas that should remain delegated to ERCOT,
to functionally administer the grid.
I believe if we were to embark on rulemakings,
as outlined in the memo this summer,
a concrete framework of principles could be enshrined
and ruled by this December and help to comport the 2023 CDR
and SARA reports and accompanying defined metrics
to a format that supports
our contemplated phase two market design reforms.
As this memo articulates,
I believe rulemaking could address the frequency
of reliability reports as it relates to the CDR,
the reliability metrics or metric by which we measure
the health of the system, and the imposition of a registry
for large loads that must be accounted
for by both the market and the grid operator.
So again, we attempt to get a better fix on supplies
and demand.
As such, if you refer to the memo, the first component
is I believe we need a seasonal CDR,
because the report is not just used by the market.
It's very important to us.
It's important to the legislature.
We use it to determine a probability
of scarcity in coming years.
And I speak to the CDR specifically.
By having a CDR on a seasonal basis
rather than a twice-a-year method we use now,
the Commission would be able to see when expected projects
may be reasonably expected to become commercially available,
specifically in the spring and fall.
Okay?
Which has become periods of tight conditions on the system
that are frequently experienced due
to plant maintenance cycles.
I'd like to know, given this potential restructuring here,
on a more granular basis,
that we have more generation coming online in future years
during specific periods.
This report could help inform our POC,
maintenance scheduler process at ERCOT,
which is currently being formulated
on a potential five-year basis.
And I can hold there 'cause that's the first component,
but I welcome any input in that aspect.
Secondly, as contemplated in the memo, hard timelines,
hard no-later-than dates,
I suggested imposing those dates in rule
that would comport to the emergency planning,
the emergency condition planning process that is
contemplated by our TDSPs.
Again, they always have certain
planning cycles where they try to have
the key number of megawatts allocated
so that they know, going into winter,
that they can adequately rotate outages,
given a certain threat condition.
So CDR could be conformed to that schedule,
and ERCOT staff could be held accountable.
It gives certainty to the market and decreases ambiguity
about when these reports become issued.
But with that, I'll open it up to the Dias. All ears.
-: Thoughts, comments? -: Yeah.
I would say I appreciate the efforts
that you've done on CDR SARA.
I know you've worked with Woody and ERCOT,
and I think the goal of this process is admirable
and necessary that we get a new set of reports
that are filed at the right time
to give us the right information.
The system's changing and we need to have that.
The there's only one thing that I struggle with,
and it's not...
This is a much more general issue.
This deals with phase two, this deals
with all of this thing,
and that is the resiliency and reliability metric.
-: Sure.
-: Because I just don't know
what that metric is going forward.
Is it, you know, one in 10?
So, you know, a loss of load expectation, you know,
does that...
We don't even know what's acceptable in that space.
You know, we want it as low as possible,
but as we are changing from a capacity-based system
to an energy-based system, which I believe
is what's happening.
Some of the old standards and metrics don't make sense,
or they're not as relevant, they still may be relevant
and they still may need to be
reported, but there may be a whole nother set of them.
So I know your effort here is to,
let's try to fix, let's throw those out
to the market participants and see what
the right one is or what the right set of them is.
And I agree with that.
I just, I hope we can come to some agreement that,
or some belief that, well, maybe I should say it this way.
I just don't believe that one metric for reliability
or resiliency is what's is necessary.
I think we're gonna need more of that.
-: Maybe. Yeah. -: So.
-: So a clarifying question. -: Yeah, go ahead.
-: How do you envision the seasonal quarterly CDR
interplaying with the SARA report position?
-: So was robust conversation
about the need for, okay,
do we just have one report moving forward
on a monthly basis?
There is clear value in having a separation
of a long-term capacity demand and reserves report
and a true resource adequacy report,
well out into the future on a five-year basis.
The SARA still has value in that it contemplates
various scenarios,
especially in the near-term as ERCOT approaches
certain conditions, certain weather-based conditions,
ERCOT believes, and after discussion with stakeholders,
there's certainly value on a monthly SARA report moving
forward that the system could be conditioned to follow,
especially as we enter periods of certain weather,
La Nina, El Nino patterns that bring
their own set of scenarios to bear.
So that's more granular, that's beneficial to both us
to know kind of what we're
dealing with and as shaped as we get closer in
to various seasons.
CDR, again, the main point,
the market participants didn't believe there
was any value in breaking it out
on a seasonal basis, but they're not us.
And they're certainly not the legislature.
And we got our own set of problems to deal with in trying
to communicate this stuff to the public.
And we're constantly going from type period to type period
because of various issues.
One, cold fronts, two, hurricanes,
three, La Nina, four, maintenance cycles,
six, stuff breaking.
I mean, so it's, I think we need
a more targeted, granular approach.
And again, we could set the schedule
and the non-negotiables in rule
that hold everybody accountable, ERCOT the TDSPs,
the resources, the loads to a certain extent,
but not required, everybody.
-: Okay, no, thank you for that clarification.
I think that's important to, for us all
to understand how the CDR
and these more near-term resource adequacy assessments would
work together, right?
You know, the SARA has proven to be valuable and,
you know, just for his historical purposes,
you know, in 2011, we had the rotating outages in February,
and then in August of 2011, we had, you know,
triple-digit weather for over 90 days and nearly hit
rotating outages again in August,
and everybody was, you know, kind of surprised
because the CDR or reserve margins looked so healthy.
So at that, based on that outcome in August
and what happened, ERCOT started looking
at more near-term seasonal resources,
producing this area to provide
a more near-term resource adequacy assessment.
Will: Correct.
-: As now we are laser-focused on resource adequacy
year-round, reliability year-round,
I think it makes sense to zoom in even closer
on a monthly basis. -: Okay.
-: If ERCOT can do that, you know, in an effective manner,
and everything works together.
I think that makes sense.
-: And broadly on the CDR, again,
the resource adequacy report on a four-times-a-year basis,
do you have any concerns on that or?
-: No- -: 'Cause that is
a defined topic in the current rule,
so it would certainly be subject to adjustment.
-: Sure.
So the current rule only envisions the December CDR?
Will: That's correct.
-: And so I think by laying out when, you know,
by what the end of what month or in some form or fashion
in the rule, when those CDR reports
would be published would be helpful.
Will: Okay.
-: For the public, for the legislature,
for us, everybody involved.
So I think that's helpful as long as we structure,
you know, the language in a way
that provides flexibility as we work
with ERCOT to produce those reports.
The third piece that I think
Commissioner Glotfelty raised,
and this is maybe a question and then maybe some additional
kind of perspective on resiliency
and a reliability standard.
So, you know, the resiliency standard,
as I see it, is different in the transmission world,
from the generation world, right?
Transmission, if you look for a reliability standard
in the transmission world, according to NRC,
it's in minus one. -: Right.
-: If you look for resiliency,
it could be in minus one, minus one.
And then in generation world, in my mind,
resiliency is weatherization and firm fuel products
and other, you know, actions ERCOT or products ERCOT
are putting in the market.
So is your thought more...
Are you more focused on the reliability standard part
that would then provide resiliency?
-: Yes. -: Okay. Okay.
And so you're- -: And the intent would be,
we need a metric that attempts
to harmonize this bifurcation
between resources, facilities,
units that can support a given system,
and again, the ability for the grid itself.
Take Houston, you know, a finite amount
of transmission going into an area,
an islanded situation.
We need to be able to break down walls and get resources
to where they need to go.
I know this is gonna be music to some people's ears
and terror to others, but reliability drives resiliency.
-: Okay.
Okay, so then the process would then be to get
stakeholder feedback on different reliability standards
in parallel to our phase two. -: Concurrent to.
-: Independent consultant process.
And that will hopefully at some point dovetail together
to at least provide additional options
for review in the phase two independent consulting process.
Will: Yes.
-: And then at that point we would direct ERCOT
to implement the reliability standard, or-
-: And Mr. Chairman- -: I think that to be
even take that a step further, Commissioner Cobos,
and your intention or design would be
to have whatever reliability standard
is established sync up with the reliability requirement
of the phase two tool.
-: My intention sir, is
that the principles that we enshrine be harnessed
for whatever phase two is designed to cure.
-: So those would sync up?
-: Yes, sir.
-: And whatever, if we need to get here, and whatever number
of metric that is- -: That provides us our goal.
-: The phase tool mechanism will be set
to however that looks.
So those two match up. That's the ultimate goal.
-: That is the goal.
-: Okay, and let me, can I just say that
I think we've got one foot in the capacity world
and one foot in the energy world here.
We have, this is a challenge
that not just ERCOT is going through,
everybody's going through,
as we're moving towards energy resources,
as we're moving towards demand response,
this is becoming a more daily energy use issue than it is
a capacity issue,
on how we measure reliability,
and everybody's struggling with this.
And I just, you know, I'm eager for us
to see what the industry has to say about it.
I'm personally, I'm not optimistic
that we are gonna solve something that nobody else
can solve right now,
but I think we need to be part of the debate here in this.
-: What job were you told you were signing up for?
(Commissioners laugh)
'Cause I think that's exactly what we're here for.
-: I'm talking the metric, not the reliability.
We will have a reliable system. There's no doubt about that.
So this is just a metric.
-: I was told I'm jumping a volcano and to see if I make it.
(Commissioners laughs)
-: So anyway, my point here is we are
in this transition of this industry and of these metrics
and it's my belief that more metrics are probably
more valuable than less metrics.
We shouldn't just be judging the system
by one single metric.
So a handful of them would probably be very valuable.
-: Sure.
-: Well, even with one event in 10 years, I mean,
you still have to evaluate, well, how long is the event?
The duration. -: Yeah, exactly.
-: What's the cost of the event?
-: Exactly.
-: But as we're all moving towards
this new market environment
in Texas, across the nation, you know,
with more renewables on the system,
aging thermal generation, retirements,
not a lot of new generation on the forefront,
which we're working on it here,
you know, I think it,
we must be proactive in trying to figure out
what reliability metrics are there outside of,
aside from this one in 10 reliability standard
that's been the utility, you know, standard for,
since utilities were probably around.
And so, I mean, we need to think more progressively,
I think, go and see what's out there.
-: So having gone back to the history,
the reason I'm not as afraid of this as other people are,
is we've got well-blazed roads
on this topic specifically.
ERCOT and PUC worked together for two years, 2012 to 2014,
docket number 40000 on this specific topic.
ERCOT did an extensive valuation in 2010.
Woody, were you here or around here at that time?
Anyway, at that time, to set the 13.75% from 12.75%.
So they underwent an evaluation just
on the high-level metric at that time,
and then there was an extensive conversation,
I've got the minutes, ERCOT in 2005.
So every five years or so
there's a deep dive into what it means to be reliable
and what the goal is.
-: So, and all I agree with that,
all I'm saying is that 2005, 2010, 2014 and 2022,
-: Totally different. -: Totally different.
The resource mix, everything that's going on
in terms in this system is totally different.
-: The loads are totally different. You bet.
-: That's the recognition I wanna make sure
that we- -: I think everybody is
on board with the fact that the one
in 10 loss of load probability
is not only older than the iPhone,
but more vintage of Betamax and VHS.
So certainly needs improvement both in sophistication
of the tool and the scope of tool or tools to be used.
And I'll also highlight the fact,
as we have all experienced
in the last 14 months that these are good metrics and tools
that certainly need to be updated,
but they are also at the end of the day,
just academic analysis that don't take into account
real-time conditions on the ground
and contingencies that cannot be planned for,
like personnel and switch yard,
and things like that.
So they're important tools to have,
but I also want to always be cognizant of the fact
that they're academic constructs
that provide good guidelines,
but are not the end-all and be-all in terms of reliability.
There's still the real world, as we all know,
has ways of proving studies wrong.
-: You bet.
-: And in terms of both what we build to and how many
CDR SARA, how many, you know,
the lowest metric possible a Commissioner Glotfelty said
as always I'll remind folks,
we'll approach that through a lens of cost-benefit analysis,
to make sure that our ratepayers are getting value
for the dollar spent on any and all of these products
and initiatives.
On the seasonal CDR. -: Yes, sir.
-: I think in general, that's a good approach.
Another question for you is I understand your intent is
to, in the updated version,
incorporate not only an installed capacity
of the fleet metric,
how many of each type of resource and et cetera,
but also a much more finely tuned probabilistic
operational expectation on what we can count on.
-: Yeah. That's more precise
than just on average.
-: That that's correct, sir.
And so let me, let me break that out a little bit.
There were components that I envisioned
we would enshrine on a principle basis
in rule and those still being worked
on by the grid operator.
Again, through delegated authority
from the PUC, accreditation on these resources
is ongoing at PUC.
They have a good model during the workshops that we held.
Most stakeholders were put at ease on the type
of hybrid models that they were considering using.
So no, that more granular fine-tuned view
of what anticipated output is being taken into account
as part of these two processes.
-: That is the crux of your initiative in my mind,
that is the most important thing
to highlight the difference
between a soil capacity and expected operational output.
And if we are going to move in the direction
of truly looking at two things,
I don't know what the statistical metric is,
but something more precise than average over peak,
something like a standard,
two standard deviations away from peak,
what is our worst case scenario, or not even worst case,
just what is the downside scenario
that we truly need to prepare
our fleet for to provide reliability?
If we're moving that direction,
then I think it makes a lot of sense to do it seasonally,
because our intermittent have vastly different-
-: Different profiles. -: Performance over seasons,
and the maintenance profiles of our dispatchable have
different profiles over different seasons.
So if we are moving in that much more granular,
probabilistic direction, then that makes a lot of sense.
-: Okay. Yeah.
-: If we're just replicating the same thing,
which I don't think we are,
then that wouldn't the cost-benefit on that wouldn't make
a lot of sense, but that I think all that's
moving in the right direction.
Only other note I would make is that,
I think Commissioner Cobos may have touched on this.
If we're doing a seasonal, in rural,
I'd formalize the seasonal nature requirement,
but not set hard dates, leave some flexibility to,
a requirement for each season or quarterly or whatnot.
But as we've all learned,
the operational nature of the grid can shift priorities
around from day to day and time, you know, week to week.
So I'd make it,
I'd leave some flexibility on the date specifically.
-: Okay. -: Wouldn't hard code that.
-: Yeah, that was an ask by TDSPs and ERCOT,
would've appreciated any type of hard date just so that they
have a target to shoot for,
but understood the operational flexibility.
I was wondering if we,
I would have universal support on that,
but understand the constraints.
-: Or week-of perhaps.
-: Okay.
-: Something there. -: Cool.
It's better than I have. So cool. (laughs)
-: You've got more?
-: And I can, now,
since we've talked through the metric,
the periodic review loads.
So we have as noted in the memo,
an ongoing proceeding at the Commission right now,
which is working in tandem with task forces formed by ERCOT
for large flexible loads,
but it's project number 51888,
and loads are a key component in our effort
to provide reliable service.
Senate Bill 3 defined critical industrial customers
in section 17.02 of the Utilities Code now,
and orders us under section 38.076 Utilities Code
to have our utilities develop plans
for designation and power restoration to critical loads.
The memo highlights Project 51888 as a precursor
to a rulemaking that could require the require ERCOT,
not the loads, to form a voluntary registration,
a repository for voluntary registration of loads that meet
the critical industrial load designation and potentially
large flexible loads.
This is for those type of loads that never want to turn off
while also providing a registry for those loads that wish
to hold themselves out as potentially controllable,
that aren't necessarily participating in the ancillary
service component of controllable loads,
but may seek that in the future and want participate
in a registry that allows us to know on a LMP basis,
on a locational basis,
whether they will assist the system or if they are going
to be a source of demand
that must be satisfied on the system at any given time.
The way I envision that is the Private Use Network
line item in the CDR.
We have a number of megawatts
that we have affixed in the CDR for that purpose.
It plays in generally
to the reliability metric that they use,
again, the reserve margin, but for my purpose,
I'd like us to look down the road,
especially on a rulemaking about having
a locationally based registry,
meaning if a semiconductor facility wants to register
and they wanna hold themselves out,
as they never want to be turned off,
they obviously will be as a part of any type
of load shed plan, but they never wanna be turned off.
That LMP is very important for the market to know
where it is.
Okay, what load is beyond that LMP,
because hopefully we wanna incent resources to locate near
there to support that load.
So it's important for our planning purposes.
It's important for our market to know that it's there,
so that resources locate themselves accordingly.
For the flexible loads,
we just need to know how much is out there,
and ERCOT can base other policies
and other considerations based
on their willingness to register
and let us know that they're there.
-: Thoughts, comments?
-: So I think, Commissioner McAdams,
your overall goal is to determine what load resources we can
count on for resource reliability benefits.
-: Correct.
-: And which resources we have to serve,
which industrial resources we have to serve for SB 3.
So project number 51888
was opened right after the storm.
There's not a lot of activity in there.
It seems to be an open book right now.
We know it's for critical load standards and processes.
And I think there's maybe two to three moving pieces here.
One is the implementation of SB 3
and the critical industrial load consumers provision there.
And then there's the piece of the,
maybe trying to get some of those larger
flexible loans registered.
So with respect to the critical industrial consumers,
I think it is important that we implement
the SB 3 provision.
I think we need to develop criteria
and some kind of registration criteria so that we can ensure
that the industrial customers that are signing up to be
critical load are in fact critical,
kind of like on the natural gas facility
critical load registration process.
I think we have to to set up
some criteria so we can ensure that we're implementing
that pie of statutory provision appropriately.
-: When everybody's critical, nobody's critical.
Avoid that. -: Yeah.
-: Yeah. Ultimately, right?
So we need to have some registration criteria
in that project or in a new project
that's titled appropriately.
I think understanding, getting a better handle
of what load resources are out there
that can voluntarily respond is important.
I think Brad always, you know, ERCOT always says, well,
we got about four to 500 megawatts of voluntary response,
and thank you to the industrial for a voluntary response,
but getting a better handle of what's out there
is really important.
And maybe through the registration,
the large flexible loads gonna be registering
as critical loads,
but they'd be registering so that we can have
a better picture of what's out there.
-: And again, under a definitional basis,
they could register as a voluntary flexible load,
but again, they may want to agree
to certain conditions that guarantee
that they could in fact, be flexible, that, you know,
they could be controllable for the purposes
of our resource adequacy, our reliability.
Voluntarily.
-: Voluntarily, and confidentially.
-: That's right. -: Presumably.
Yeah. Good point.
Commissioner Glotfelty? -: Well you know,
I think it's a good effort to help give us
information in the future.
-: Yeah, I think for both of these initiatives,
I think as long as they're voluntary and confidential,
it's a good start.
The only ask I have is that on the large flexible load.
Will: Yes, sir.
-: That whatever steps we take in this don't get in front
of the task force that's currently underway.
We're all counting on the participants there to help
show us the way on that.
So I'd ask that anything on large flexible load
either be in conjunction with,
or don't get ahead of the work they're doing.
Will: Absolutely sir.
-: Appreciate it.
What else you got?
-: Well so that delineates
the rulemaking scope that could occur,
pending the consensus of the Commission.
As per my memo, I would still lead discussions
that have concluded potential improvements
to load forecasting generation accreditation,
scenario analysis, and formatting
to the grid administrator to continue
to refine for more accurate reports and to help, again,
the rules should enshrine principles
that the grid administrator should conform
their processes to meet.
And that would also give it the force of law,
which helps the credibility of everybody.
Now with that I'll close, Mr. Chairman.
-: Makes sense to me.
-: All right.
Okay to move forward? -: Again, I want to say,
I appreciate you taking on these two pieces, you know,
with ERCOT, with new types of assets
coming on the system like storage,
making sure that they're updated in these reports is very
valuable for us in the industry going forward.
And I just think that accreditation is
a huge issue on renewable and thermals.
-: Right. -: And storage, quite frankly.
We gotta get our head around that.
We haven't done it yet in any formal way, but understanding
that is really important,
so I'm glad that you're leading up these efforts.
-: Well put. Thank you, sir.
-: So with that, Mr. Chairman,
I don't think I'll make any formal motion,
just directive to staff.
-: Yeah.
-: If we could proceed consistent with the memo.
-: I think staff has everything they need?
-: Right. -: Yes.
-: As you said, no formal action required on item number 31.
That brings us precisely to the two-hour mark.
So let's take 15 minutes and we'll reconvene at 11:45 AM.
(gavel bangs)
This meeting of the Public Utility Commission of Texas is
now called back to order.
We don't have any business on items 31 or 32,
which brings us to item number 33.
I believe Commissioner Glotfelty has some comments
on this item.
-: Caught me with some M&Ms in my mouth.
I apologize.
Docket number 33 is a review of transmission rights
for exports from ERCOT.
It's pretty narrow, pretty simple.
We've gone through a process here
of trying to figure out if export tariffs
deserve to have three times the export charge
during June, July, and August.
DC ties can have a very valuable reliability,
resiliency component for our system.
We don't know if we're gonna get more of them,
but this is potentially one of the barriers to getting more
so, as we've looked at at DC lines,
one of the issues has been this tariff.
It seems to be outdated.
We've gone through a process with stakeholders.
It's, you know, we've really had almost unanimous agreement
that it's okay to have this eliminated,
this three times the rate, not because ERCOT
has the very specifically the authority
if there's a reliability impact
to shut down the DC ties and keep that power in the state.
So again, this is process going forward, which is
we've put out a straw man.
We've asked for input from stakeholders.
This would be just to approve the formal process
of publishing a draft rule and moving that forward
in the general rulemaking process.
It's very short, but I'm happy to answer any questions.
-: Thank you. Thoughts, comments, questions?
-: Firstly, Commissioner, thank you
for affording me the opportunity to dig
into it more and understand
what we were talking about.
My comfort level with moving forward,
pending staff's bandwidth and everything else,
you know, I know I just made an ask for tool rulemaking,
so I'm happy to support my colleague on that, but no,
I think if we have the bandwidth,
we should move forward on it.
-: Same.
I think you've gotten some comments that majority support
making these changes to the rule.
I think we know why they were put in place in the past.
And so I appreciate your leadership on this issue
and if staff has the bandwidth, let's move forward.
-: Agreed. Thank you, Commissioner Glotfelty.
Staff have any other questions or.
-: Well, so we have the discussion draft, but also
if rather than just recall that as a PFP,
I think staff has a few additional tweaks
that they might want to make.
So if we can send down our usual scoping document
in proceeding of the PFP with our fleshed out
version of how we would react to the comments,
we'll we can proceed in the next little bit on that.
But yeah, we can do it.
I just wanted to make sure that we can just go
through the normal process rather than just refile,
if that works.
Jimmy: That's fine.
-: And that scoping document, too,
will have a recommended schedule that will allow us
to slot it in among the other rulemakings
in a way that's feasible
for our resources. -: Okay, good. Got it.
-: Thank you. Appreciate that.
Thank you, Commissioner Glotfelty.
-: Thank you.
-: Next item is project number 53298,
related to Wholesale Electric Market Design.
Commissioner McAdams, I understand, has some comments here.
-: I do.
Mr. Chairman and I believe, so let me say this:
our recent request for information from stakeholders has
recently concluded.
I know all of our offices are digesting those comments.
This is a dynamic area of the market that could prove
to be an invaluable resource moving forward.
I know that Commissioner Glotfelty has also thoughts
on how far and how fast we may be able
to move in the near future.
I know this, that the winter,
this Christmas is
a transformational time
for what we are doing here
at the Commission and on the ERCOT system.
That that is a target for both staff,
ERCOT staff, stakeholders
in trying to formalize a framework of tools to combat
and solve for reliability moving forward.
So DR's, whether they're on the supply side,
or, well, on the demand side or the supply side,
are going to be instrumental in providing
a long term solution for the system.
Just like everything,
there's a time and a place under Heaven.
I'm not sure if we can move forward at the moment,
but I'm interested in thoughts from other Commissioners
on how far, how fast and what we could do right now.
And without Mr. Chairman,
I'll open it up for other thoughts.
-: Suspect Commissioner Glotfelty has some thoughts on that.
-: Yeah, go ahead, Jimmy.
-: Are you specifically bringing up DER pilot projects?
-: Yes, sir. It's teed up. -: So, yeah.
So what I think is we've had some discussions back
and forth on what ERCOT can and cannot do
with pilot projects in this space.
And should we have a task force instead of a pilot project
to resolve all the issues?
My experience has been that task force solve
a lot of issues, they delay a lot of issues
that can be resolved as well.
So I think you get to the same answer
if you do a pilot project,
a very defined pilot project
that can help answer very specific questions
on DERs, VPPs and other things like that.
What I've experienced in the past
is that you do a task force,
the task force comes up with a bunch of issues,
the issues go to the real implementation on the system,
and there's still a whole bunch of issues that still have
to be resolved, and believe that as you go
through a small pilot project,
you get to the exact same point.
And that the further point on kind
of virtual power plants is that we we're trying
to figure out where batteries fit.
Are they loads, or are they generators?
-: They're both. -: They're both, right now.
And this is not just small storage facilities.
This is large storage facilities.
They are everything on this system.
And that's what makes them a wild card.
And so, you know, I just,
I think that if we could have parties, you know,
put together a pilot project and have it scoped out,
I think that I've talked to folks at ERCOT about it.
I know there are some difference of opinions,
but my opinion is that we ought to go forward and we ought
to find a way to encourage ERCOT to get stakeholders
together and do a pilot project and make sure
that the issues that come up are answered in that process.
-: So is there a specific request for a pilot project or is
this this a concept you'd like to open up
to the broader community?
-: So this is a issue
of a request by Tesla
to modify a...
I don't know what an OBDR... -: OBDR.
-: Other binding document. -: Other binding document.
-: Yeah, another binding document there
to allow them to create
a virtual power plan here in Texas using power walls
and the challenge,
you know, I think there's some overburdenness,
you know, with ERCOT, you know,
they've got a lot of task forces,
but this is what my request would be,
is let's figure out how we can move forward and let them
create a small pilot project to do this going forward
and answer any questions that we have, reliability,
economic, settlements, all of those things,
through a pilot project, rather than just
some task force that goes
and kicks the can down the road for a few.
-: I will say in some cases, task forces are excellent,
like large flexible load. -: I totally agree.
-: When some elements present risk to the system.
-: Absolutely.
-: Sometimes it's more prudent to step back
and evaluate those issues
in a task force format. -: I understand.
-: Related to any particular NPR, OBDR,
I think there's a time and a place for us to opine on those,
but it's certainly after the ERCOT board and staff have gone
through their process.
-: Yeah, and this has been an issue
that has been pending before the ERCOT staff
for many months, we're we can invite Tesla up
to lay it out for us, if you want.
I know the there's gonna be a discussion
at the ERCOT board meeting on either Monday or Tuesday,
and we can wait for that and then come back afterwards.
I really just want to make sure that...
I'm a believer that these are part
of the solution going forward.
Yeah. -: Yeah. Firm.
We're all, I think, supportive of all of the above approach.
-: And the other thing is
as we look at these pilot projects, you know,
a small pilot project becomes a rounding error in terms
of energy on the system.
And, you know, you're kind of shaking your head here,
but listen, the amount of load that flex
on the load side, that's moving up
and down every second of every day makes
the surrounding error on the generation side, so.
-: Right, I'm just, I'm more thinking about it of as,
from the perspective,
if we're gonna divert resources from ECRS
or voltage support or other key initiatives
for a rounding error,
I'm not sure that's the most prudent.
-: But this is something that has to go forward.
We've gotta find some solution to these issues.
I understand what you're saying.
You know, I think ERCOT needs
to make that decision, but my view is let's let you know,
Tesla and others who want to, you know, create
and use virtual power plants in some fashion,
you know, put together a proposal to ERCOT,
but that ERCOT looks upon it favorably.
Obviously, they have to look at it
from a reliability perspective, but look on it favorably
that we can do these tests and solve problems
in a pilot project, as opposed to just a task force.
-: So, yeah, absolutely.
So one of the considerations that in my deliberations
on the topic that I believe is essential,
is you have to have the right system.
You have to have the right distribution system
for the pilot project.
Our large scale TDSPs,
I'm looking at 'em over there.
I'm sure they may be cagey about that.
However, a non-opt-in entity
that has a contiguous distribution system
that fairly well controls their own distribution system
in a more manageable way.
They may have interest.
And so my belief was
there's responsibilities on everyone here.
ERCOT certainly has some, but they're doing
a lot of different things over the next several weeks.
It may be feasible or advisable to get feedback
from the TDSP community,
the electric utility community on who might volunteer to be
involved in some kind of pilot project,
if they were interested.
Because again, it's all
about distribution system management.
You guys are transmission system managers.
And this is a DSO. -: Yeah, this is huge,
hugely important point. -: Right.
-: Is that ERCOT is a transmission level operator.
-: Right.
-: And for a pilot project or a system-wide change,
moving ERCOT from just the transmission level,
into the distribution level, to the extent they would need
to have visibility,
command and control necessary to maintain reliability,
not to mention execute any project of any scale.
That transition is a huge undertaking.
-: It's happening. It's happening today.
So, you know. -: That's fine,
but ERCOT's not doing that today.
And doing that system wide is a huge, huge undertaking,
which I think is to your point.
-: That's why you limit it.
That's why it's small. -: It'd be kind of-
-: So I think self-contained sandbox, if you will.
Makes a lot of sense. -: Yeah, for experimentation.
-: Yeah. That makes a lot of sense.
Trying to force feed it through an OBDR
is something that ERCOT board can consider next week.
I guess the first question
that makes like a pilot project,
a self-contained NOI, makes a lot of sense,
and I'm happy to concur with Commissioner Glotfelty
that nothing teaches like experience.
So the sooner you get something in the field,
the more you learn faster. -: Right.
-: It's just the trade-offs on doing so.
Is there anything, the first question
I think we need to ask,
is there anything in place today preventing
an independent company like Tesla from partnering
with a NOI to move forward with a small pilot project?
-: I have a question.
'Cause I thought I read in the news articles, you know,
in the press, that Tesla currently is looking to do
a test of their VPP model in north Texas.
And so they already have something that, you know,
they're working on right now.
And I don't know if that's connected to, you know,
Encore's distribution grid or NOI.
It looks like yes. Liz is shaking her head yes.
So, okay, so there's that to take into consideration,
(laughs) but I guess my question is, and I'm still parsing
through the comments and I'm just trying
to figure out exactly- -: Oh yeah, we are.
-: What we're tackling here.
So I know Tesla has their OBDRR and had a workshop,
and so that's an avenue that they're pursuing
that'll go through the, you know,
stakeholder and board review,
ultimately over here, if the board approves it.
And I think what I'm hearing from at least Jimmy
and both of you guys,
is that you would prefer piloting the program rather than,
you know, maybe putting in a task force
where there's just a whole lot more, you know,
process and, you know... -: Commissioner,
my position is just as, maybe in the middle on this,
would be if feasible, certainly pilots
are very useful for experimentation
and just problem-solving on the front end,
if feasible.
Key term.
So if you get the right system,
if you get the right partners,
if you get Tesla married up to the right distribution system
so that we can work our way through this,
but that's a lot of what-ifs and my non-negotiable
on the other side was as we are
analyzing the feedback from this docket
and from our DER comments,
a task force or some type of construct acting concurrent
with us, partnering with us
to make recommendations by the end of the year,
given any type of outcomes,
either from a pilot project
or from the task force's deliberation
on their own would be useful for our purposes
to guide rulemaking for the next year,
so that we could possibly start to count on these resources
in the near future.
I'm uncomfortable with just leaving it open ended
to where we're not doing anything on DERs.
-: Absolutely not.
-: And my read of your orders
to my office is let's try to do something
and we're going to,
so it's just a question of how best to get there
by the end of the year.
-: Absolutely.
And this isn't part of all of the above approach.
I'm just not prepared to sacrifice ERCOT resources
working on ERS, or ECRS, or voltage support,
or any of the other, or RTC,
or any other big initiatives for 50 megawatts,
potentially. -: Got it.
-: But we need to move forward under that.
-: Yeah. -: 100% agree
we need to move forward.
Under what framework, is the open question.
-: Yeah, so- -: And you two
are the leads on our DER initiative,
so I think you've got a question,
and I guess I've got a question.
We might have some folks in the audience,
if y'all would be willing to ask the Tesla folks, if we can.
-: Absolutely. -: I don't wanna steal
any thunder from the ERCOT board though next week.
-: Yeah, I mean, and that is the thing.
We could bring it up at the next meeting as well.
-: Sure.
-: After the presentation to the ERCOT board
and the ERCOT board has a discussion next week about it.
-: Well, there's no time like the present.
-: Okay. Well, let's steal some thunder.
-: Well, okay.
-: And you have a question about what they're actually doing,
and I have a question- -: Let me just say one thing.
Since we unbundled this market and restructured the market,
we've tried to eliminate barriers to entry,
to getting new entrant into these-
-: That's true. -: Systems and provide
new products to consumers.
-: That's my question, what barriers exist to (indistinct)
-: So that's why that is one of the issues.
I printed this map yesterday.
This was at 1:47 yesterday, the ERCOT heat map,
which shows that we've got a very big challenge
across our system that has some areas of...
This system, as funny as it looks,
is still 100% reliable or 99.999% reliable.
It's just very inexpensive in the blue and very expensive
in the red,
and if we can help solve some of those problems,
you know, with this and transmission,
obviously that's what we need to be working on.
-: We'll get the small modular reactor guys up next week.
-: Are we having them in?
-: Well, we can. -: I think-
That goes a long way to solving that problem.
-: If they can fit into the market construct
and they can pay for it, for sure.
-: (laughs) All right. First question.
What barriers exist to currently implementing Tesla's vision
of a VVP and a NOI?
It's on. -: It's on.
Peter: State your name for the record, please.
-: Hi, Arushi Sharma Frank.
I'm sorry, there were 67 pages filed last night,
but most of our data from the VPP trials itself.
All right, so main issue is that right now
the ERCOT system cannot see
an export from the distributed system.
So it can't value it, it can't settle it,
it can't control it.
The idea of the virtual power plant is essentially command
and control over distributed energy resources while they're
either reducing load or they're exporting,
and while they're exporting providing ancillary services.
Peter: You mean exporting out
of that physical location. -: Correct.
Out of the physical location. -: Not out of ERCOT grid..
-: Correct. Out of the physical location or this site.
The biggest challenge is that right now,
the only recognition you could get for ancillary services
from these distributed systems
is as load reduction resources.
So if you have, which you have,
let's just take the example of a local area here, which is,
you know, 7,000 parallels in, you know, the top, you know,
30% of the neighborhoods in the state.
All of those battery systems have the ability to provide
expert capacity and to do it instantaneously in response
to real time signals from ERCOT, and ERCOT can't see
or recognize, or even dispatch it.
So the whole point of the OBD filing is one way to look
at how do you get that dispatch to ERCOT
part of a larger load,
we're calling it clumping, it's become a big thing,
but the idea is that you have a large load that's responsive
register as an aggregated load,
and only some devices or sites within that aggregated load
are providing injection value.
It raises the same question that ERCOT is already going
to face around devices that export.
DERs obviously export constantly to the system.
But the whole point in the virtual power plant is to take
these energy-dense, high-capacity resources
and move them from just dispatching
at random over 24 hours of the day and moving them
into a concerted command and control dispatch
directly from ERCOT
That's essentially the problem we're trying to solve.
In terms of an approach to do it,
I mean, for starters,
the OBD is tabled at the technical advisory committee.
So really there's no action for the board to take next week.
The OBD has been proposed.
It really, for us, it's a straw man
to get the conversation started and remind
folks that look, the data supports us registering an ALR,
and aggregated load resource, right now.
But if we do it right now, half the value
of those systems that would be in the ALR
like is literally waste.
You're wasting it.
So the price signal is not complete to the customer,
and if it's not complete to the customer,
it's not complete to the entity
that's offering that resource into the market,
whether it's a NOI or whether it's a retail energy provider
in a competitive area.
So that's the essential challenge of like why you can't
register an aggregated load resource right now,
and it's also why no one has tried to register one
for almost a decade since we've had the policy in place.
The pilot idea, I must say, is an interesting one
and a potentially really good one.
And a lot of markets, in Australia,
for example, we had a three-year pilot
where the set megawatt capacity
that resources, which export could provide
and all of these issues
that we're talking about here that are raised by utilities
and by us in the docket, they're all studied simultaneously
while the pilot is ongoing,
and just to address Mr. Chairman's question about resources,
the work in that 67 pages of filings,
98% of it is Tesla's work.
The amount of time that we took from ERCOT is 15 minutes
to half an hour, every couple of weeks for six months.
All ERCOT does in these sorts of qualification tests,
which are our normal process of qualifying any resource
for ancillary service is give us a guideline,
give us historical data,
you look at it and you say, okay,
I can make my real-time resources perform exactly like
your qualification test.
It is essentially the same normal work
of qualifying your resource to provide that service
now in the market.
This is how far we've come,
and I think that with the collaborative approaches that are
being suggested in the docket and that I'm hearing today,
we can probably continue that and keep it really
a low-key effort on ERCOT's part in terms of resources
and be mindful of that.
I mean, we know as much as anyone else
that everything takes time and resources to get done.
-: I appreciate you contributing the work so far,
and I'm glad ERCOT could spare the 15 minutes.
I suspect building out systems
for a broader integration of the distribution system would
take more than 15 minutes. -: Much more. Yes.
-: So what barriers exist today to doing a pilot project
with a NOI?
-: I don't know that we've even explored
going with a NOI specifically.
I think that one of the issues is that if you have customers
in a competitive area, you're able to aggregate
to them across a very large load zone.
And let's say you have protected circuits over a large area.
To get the minimum aggregation size,
you'd be able to go out and pick up 10 customers
at one point, 10 customers at another point,
and do the pilot without getting into serious issues
around congestion, specifically zonal versus nodal.
In a NOI, depending on where
the aggregation was being built,
you might be a little more constrained,
'cause NOI territories are generally smaller.
If you're trying to stay- -: Got some pretty big ones.
-: You got (indistinct) and some other pretty large areas,
but that is a potential issue.
Eric, do you think there are others?
-: There's one specific issue that's pretty key,
which is that in the competitive areas,
we have EZIDs that go through the ERCOT process,
so ERCOT has direct access to all the meter data that they
don't have for NOIs.
So we'd have to create a new process
to get that meter data earlier.
-: The NOI would have access to their meter data.
-: They would, but the point is for ERCOT to get confident.
And so there's an existing process for ERCOT to get
all the (indistinct) -: I think the point is
for the concept to be proved out-
Eric: Sure. -: In some sort of partnership
like Commissioner McAdams mentioned.
-: Yep. -: And that data
then brought to the broader stakeholder community.
-: You're right. -: Which sounds like
it can be accomplished within an existing NOI
if there are enough resources in the geographic footprint.
Is that?
-: You're not wrong,
but we'd have to reinvent the wheel on how to get
the meter data to ERCOT,
and so it'd be a way to simplify the work
of the pilot program.
ERCOT would have to figure out a new way to look
at meter data that they don't currently have.
Whereas today, if there's a competitive area,
there's an existing process we've used since 2001
for ERCOT to see meter data in a competitive area.
So it just- -: Well, hold on.
Lori: It's more efficient process.
Is that what I'm hearing?
-: So Liz Jones for Encore.
So first of all, the meter data is not gonna be sufficient
to support an aggregated load resource,
because a meter measures inflows and outflows,
and it's my understanding what Tesla's looking for is
to actually account for what's going on behind that meter
with respect to a power wall.
So that is an issue.
The second issue is with respect to the testing that Tesla
has done, Encore was not advised of the test,
and we have not been able to take a closer look
at what issues are or are not,
I mean, I'm not gonna foretell anything.
What issues may result from an exporting
DER on the system,
particularly in such small increments and aggregated,
as has been suggested.
I will tell you that in the past week we've been engaged
in discussions with Tesla, we are supportive of a pilot.
The reason we're supportive of a pilot is that it can be
isolated and reviewed and hopefully not
have larger transmission system implications.
But I will tell you that nobody tests
on the transmission system without ERCOT's sign off,
and I feel pretty strongly that a similar proposition is
necessary on the distribution system.
-: And the meters that do the real-time telemetry
are individual device meters that are actually
attached to the power wall system itself
and they provide two-second telemetry.
So yeah, the revenue meter is a 15-minute interval meter.
Peter: Yeah.
-: And then the additional one is the one
that does instantaneous. -: So the power wall
meter data would be- -: Correct.
Peter: Available to Tesla, the company.
-: Yes. -: Pending terms
and conditions for the customer,
and presumably ERCOT could read that.
-: You're right,
but to verify it for the measurement verification process,
in the past, ERCOT like to see meter reads on their meters
they get as well to confirm the data that they're receiving.
-: You're not gonna see anything on the meter except inflows
and outflows, Eric. -: Well,
there's a measurement verification process called
meter before meter after
that's been used for these processes before,
and I think our approach that we've suggested
is to use both sets of data in order to confirm
what's happening on both and have it match up.
-: Well, and that's certainly possible,
but that also leads to the question...
I'm not supportive of a task force at this point, either.
I do think a pilot would be more instructive,
but I do think a pilot design is going to be important,
both for ERCOT the settlement entity,
ERCOT the reliability operator,
and whatever distribution utility
is participating in that pilot.
-: So I there's been a lot of...
Woody, do y'all have an opinion on any of this information
that's being shared?
No? (Peter laughs)
(Lori laughs)
-: Kenan Ogelman with ERCOT.
So let me just start off by saying that ERCOT agrees
with, I think, the point that Commissioner Glotfelty made,
that solving the DER issue ends up being a critical
answer to reliably maintaining the grid.
And I think that's a really important point
to just start off with.
Now, the devils is always in the details,
and getting that right is really important.
And just as y'all pointed out,
there has to be this really effective partnership
between ERCOT and the TDSPs to make it all work out.
And I mean, their concerns end up,
in some instances, being paramount,
they have to manage that distribution system.
ERCOT doesn't.
So with those initial, you know, hierarching statements,
what I would say is we think a pilot
with a willing DSP partner,
and that could be anywhere in the ERCOT footprint,
would be a good way to move forward.
We have serious concerns about the OBDRR.
It's primarily around the fact that there are these things
that are injecting into the grid being netted somewhere else
in the entire footprint of the zone
with load.
And that actually could make your, you know,
heat map worse because you could have load going up
in the wrong area and or generation ramping up
in the wrong area.
So we think pilot is a really good idea.
That does not mean that we should stop
on getting to a long-term answer,
which I think happens in the ERCOT process.
I don't want say task force or anything in particular,
but that also has to, we have to keep working on that.
-: That's an incredibly important point
in this framework or construct, the difference
in geographical, physical location
of the exporting, discharging device and the load.
Right now, a home with a power wall
is important for the public to know,
a home with a power wall, for example,
or Entergy, Generac, or anything else,
can reduce its load in the same physical location
by using that backup resource.
That happens all the time today in ERCOT.
So I wanna make sure the public is clear that we're not
in no way preventing that right from happening now.
Solar panel, any configuration thereof that happens now,
Kenan's very important point of the difference in,
it's not a reduction of load over here,
it's a addition, a discharge of a power wall over here
in Abilene, which may not necessarily help in Houston,
but these are the things that we need to figure out.
So that's the difference in geographic location
is a hugely important distinction here.
Do you have a question? (phone ringing)
-: No, I mean, I'm just trying to figure out,
'cause it sounds like, you know,
ERCOT, you have concerns with...
Come on, sorry. (phone ringing)
You have concerns with the OBDRR,
and I'm wondering if the most productive way to approach
this issue is through a limited pilot that will explore
all of these issues.
And then out of that pilot would come market rule changes,
potential market rule changes that are then more effective
at at addressing these VPP issues from an ERCOT standpoint,
but also from a TDU and DSP and you know,
VPP provider standpoint rather than...
You know, 'cause I task forces,
I think, you know, Liz, you mentioned
that ERCOT's had a task force on, you know, DERs
and addressed a lot of these issues already,
and I don't wanna reinvent the wheel.
It's just kind of coming up with a roadmap,
is what I'm hearing, to how to figure out what opportunities
and challenges are in a way that is
efficient and effective
so that we can see if we can reap rewards
out of, you know, benefits, reliability benefits,
from this, you know, VPP concert.
Liz: If I may.
-: Oh, go ahead, Liz.
-: Although ERCOT and Tesla have been in discussion
for several months, the wider market participant community
has been in discussion for a matter of a few weeks,
and I think we would all be well served to have
an opportunity to go back
and think about these circumstances
and how we might proceed,
and Encore is committed to having that conversation,
but rather than trying to resolve the matter today,
if you all could defer this for a month, six weeks,
so that we could figure out if it's feasible
to design a pilot, what that pilot might look like,
and how we might answer
at least some of the questions that you have posed.
Peter: Good.
Thank you, Liz. -: Just one more point
I was gonna make on the pilot is,
in the Commission's rule on ERCOT pilot programs,
it requires close coordination with the executive director
and Commission staff,
so it's a way for y'all to make sure that we don't
overburden ERCOT in the process.
-: Appreciate you highlighting that.
We'll make sure keep that in mind.
Very good point, Liz.
From Lori's questions down to Jimmy's layout,
what I'm hearing is I hate to say this,
but we almost need a task force to design the pilot project.
(group laughs)
Just calling 'em like I see 'em.
But most importantly, I'd say in the spirit
of actually moving forward. -: Yeah.
-: We have an initiative here at the Commission led initially
by Commissioner McAdams with your,
once you got here, joint leadership,
we have a forum for exactly these kinds of discussions.
So I would propose that you all-
-: Why don't- -: Work with the stakeholders
like Liz? -: Why don't
one of us follow a memo?
(Commissioners laugh)
-: Before- -: You've been talking all day
about how you don't wanna file any more memos.
-: Before next open meeting (Jimmy laughs)
delineating a process, a timetable,
about deliverability or deliverables associated with this.
Again, putting an RFI out to stakeholders,
again, interested parties on who could come
to the table with Tesla,
partner with Tesla or any DER system
that could be overseen by ERCOT,
or can work in coordination with ERCOT,
just so they don't, any pilot, ultimately,
doesn't foul up the transmission system,
and is closely managed at distribution, and-
-: Yeah, I mean, do all those things, but do it...
-: We'll file them. Well, somebody will.
-: I mean, it doesn't have to have
a hard and fast sell on it,
but the both of y'all- -: No, or-
-: Is the one's leading this initiative,
sit down, do what you did with CDR SARA,
y'all sit down with the stakeholders.
-: Yep. -: And start pulling
these parameters together, work with the stakeholders,
and at the same time, Tesla and anybody else who wants
to pursue this kind of pilot project,
in the meantime, please be actively engaged
with not only the TDSPs,
but the DSPs, and actively searching for a potential partner
who could come to the table with you arm in arm.
Arusha: Absolutely.
-: And so it's a more comprehensive approach than-
-: Sure.
Peter: Just kind of swinging wildly.
-: And we can commit to doing that with NOI partners,
as well as with TDSPs like Encore.
I mean, if anything what we're learning
from discussing with Encore more recently
is that learning experience for the utilities is important,
so if that experience can be part of this pilot,
and we can also, at the same time,
we're considering doing more workshops
or other working sessions where we just have
all the companies that are participating
presenting informations
in coordination with DSPs. -: Defer to Commissioners
Glotfelty and McAdams to provide the-
-: Yes. We'll invite them personally. (laughs)
-: But I think those are gonna be the ones
doing the inviting. -: Yeah.
Arusha: All right. Thank you.
-: And Commissioner McAdams, if you would,
ideally, take a scope of the issues
before you set timelines.
-: Yeah, no, I get it Liz.
I mean, we we'll get it done. (group laughs)
-: Yeah. Go ahead.
-: Oh, I'm good.
I think you hit it on the nose in terms of,
you know, workshops.
I think, you know,
having a workshop Commission-led workshop, whatever,
but a workshop, period, just to get, you know,
some parameters in place for the pilot, and-
-: And I'd say, and as we work through this,
this is exactly why we have
y'all leading these kinds of initiatives,
coordinate with the stakeholders.
We appreciate working with the TDSPs, the DSPs,
to to come together with a partner.
And most importantly, as for everybody involved in all this,
we want to as always explore the opportunities
for every avenue to all of the above,
but at no risk to reliability.
We're gonna start with a small steps.
-: Yeah. -: To ensure that
in this isolated, whatever version of this type
of pilot project eventually emerges,
that on an ongoing basis,
at any point in time, these initiatives
and efforts present no risk to reliability
for the people of Texas.
As always, reliability is paramount.
-: You bet.
-: All right? All right?
-: Thank you. -: Thank y'all.
Arusha: Thank you.
-: I would highlight that the feedback to our RFI
to the system was due yesterday.
So they came in yesterday. -: Yeah, we still got
a lot to work with. -: Everybody's really eager.
But it was yesterday.
So I appreciate that. -: Thanks for this discussion.
-: Yeah, well, this has been, something has been
in the works for a long time, but yeah,
it's a long list of things to work on.
-: Thank you, Eric. -: Thank you.
-: Thanks Eric.
All right.
Stephen: 35, sir.
-: Oh, sorry, yeah.
I think we've covered everything on 34?
-: Yes, sir.
-: All right.
35. Please lay that out for us, Mr. Journeay.
-: Item 35 is project 53493.
It's emergency response service.
Commission staff filed a memo and proposal
for publication to amend 25.507.
Chairman, you have a memo in this matter.
-: I do. I do have a memo.
This is pretty straightforward.
This Commission has been very deliberate
in its phase one market redesign to make
the ERS, industrial demand response program,
more available and more ready to be utilized in the event
of tight grid conditions.
Most importantly, this Commission has been very deliberate
and direct in its intention
to deploy these industrial demand response resources
that we have already paid for as ratepayers
to deploy these resources
in the event of tide grid conditions
before we ask residential households
and residential customers to alter
their energy consumption.
In that spirit,
this rule is designed to ensure that if and when ERCOT does
deploy ERS industrial demand resources,
those resources can be readily reloaded,
so we can essentially use those resources
more than once a season.
If they are completely depleted,
you'll seen my memo and I'm sure staff has provided
whatever briefings are necessary.
I don't think there's anything more complicated
about it than that, but would be happy to hear
your thoughts and comments.
Or entertain a motion to approve the DFP.
-: I will move to do that.
-: Second. -: Second.
We got a motion and a second.
All in favor, say aye. -: Aye.
(indistinct)
-: Sorry?
(indistinct)
-: Consistent with his memo. -: Yep.
-: That was my motion. -: Motion and a second.
All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
Thank y'all.
Don't have anything on 36 through 40.
Item number 41, please, sir.
I think that's Mr. Hunter.
-: Item 41 is project 43517, delegation of authority
generally the executive director.
Federal government comes to visit.
-: Good afternoon. Chairman, Commissioners.
Before you today is a request from staff to delegate
to the executive director of the authority to finalize
and file on behalf of the Commission
comments on the Environmental Protection Agency
Transport Federal Implementation Plan
on or before June 21st.
We are continuing to revise and refine the draft
we sent you earlier this week and we're working with ERCOT
and TCQ and the Attorney General's office,
and we'll finalize those comments and happy
to answer any questions.
-: Thank you, sir. Questions, comments?
Jimmy: I think he's doing the right thing.
Will: Yeah, it was a mountain of work, Tom.
Peter: Yeah, A lot of work,
a lot of coordination appreciate the efforts on those.
-: And obviously this issue could have a huge impact
on the reliability of our system.
-: Absolutely.
-: So being on top of it and in front of it,
I applaud y'alls efforts to work on behalf of the state.
Thank you. -: Thank you.
-: And consumers (indistinct)
who pay everything.
-: Yeah. Do we have a motion.
-: So with that, Mr. Chairman,
I'd moved to delegate authority
to the executive director. -: Second.
-: All in favor, say aye. -: Aye.
None opposed, motion passes.
Nothing on 42, 43, which brings us to our
item 45, which is update from our executive director.
-: Thank you, Mr. Chairman.
Good afternoon. Commissioners.
First, I'd like to welcome Connie back from her stay
in Oklahoma City and congratulate her daughter,
Camille, and the UT softball team for their run
in the Women's College World Series all the way
to the Championship Series.
Amazing job by them.
Secondly, I just want, you know,
a couple meetings ago I pointed out that Charlie Hemmeline
left the Solar Association,
so we had an opening on TERC.
As of yesterday, Bob Helton has accepted that post.
Bob has, you know, some 30 years of experience
in the industry, currently works
for NG and his vice chair of TAC,
so he brings a depth and breadth of knowledge
that will be a great asset on TERC,
and I just want to thank him
for accepting that post yesterday.
And finally, you know, most of the time I try
to keep these informative and light,
but on a bit of a somber note,
I'm sure most of you all heard that on May 31st,
Former Commissioner Brandy Marty Marquez's mother
passed away.
Today is the visitation rosary
and tomorrow's the mass for her,
so just wanted to take this opportunity to send
our thoughts, prayers, and love out to Brandy, Enrique,
Max, and the whole Marty family,
as they deal in their grief and these difficult times.
And let them know that we love them
and we support them in this time of grief,
like I said, and know that they are,
you know, we're lifting them up
and hope that they find comfort
in their family and their faith.
-: Indeed condolences from all of us
to the family and extended family.
Thanks to Bob Helton for taking this on.
He's a greatly valued resource in this marketplace.
That's a big job and he already has a big job at TAC,
so appreciate his willingness to step up.
-: Sure.
-: He's like the ERS of stakeholders.
(group laughs)
We plug and play him (indistinct)
-: Well-played, Commissioner. Very well-played.
-: 24/7 duration. -: Yeah.
-: Exactly.
-: We need to give him a reload. (laughs)
And again, congrats Camille and the whole squad.
The position of this Commission shall remain book 'em Horns.
Having no further business
and having convened (laughs) (group laughs)
a duly noticed open meeting,
the Commission will now, at 12:33 PM on June 16th,
hold a closed session pursuant
to Chapter 551 of the Texas Government Code
sections 551.071, 551.074 and and 551.076.
We'll be back in a bit. (people chattering)
This meeting of the Public Utility Commission of Texas
is now back in order.
Considering the discussion closed session,
I will now entertain a motion to authorize our counsel
to file a nonsuit in Public Utility Commission
of Texas v. March, cause number D1G N22-000458.
-: With prejudice.
Without prejudice. -: Without prejudice.
-: So moved. -: Second.
-: Got a motion and a second.
All in favor, say aye. -: Aye.
-: None opposed. Motion passes.
There being no further business to come
before this Commission, this meeting
of the Public Utility Commission of Texas
is here by adjourned.
(gavel bangs)
-: You can read.