-: Good morning.
This meeting of the Public Utility Commission of Texas
will come to order to consider matters
that have been duly toasted
with the Secretary of State of Texas
for October 21st, 2021.
For the record, my name is Peter Lake.
With me today are Will McAdams,
Lori Cobos and Jimmy Glotfelty.
First up on the agenda,
we have docket number 51840.
Mr. Smeltzer and Mr. English,
would you please lay out our proposal for adoption?
-: Good morning, Utility Commissioners,
My name's Barksdale English,
on behalf of Commission staff,
the microphone is not on. -: I don't hear that.
Peter: The mic is not on.
(indistinct chattering)
Will: Can anyone hear any of this?
-: Can you hear me? -: Yes.
-: Is this now on? -: We can hear it.
-: Yes. -: I can hear that.
-: Can you hear me?
All right.
So, one more time, my name is Barksdale English,
on behalf of Commission staff,
good morning, Chairman and Commissioners.
Before you today is the staff's recommendation
for the proposal for adoption for a new rule,
16 TAC, Chapter 25.55,
it lays out our recommendation for
weatherization preparation plans
for the upcoming winter season.
And we are happy to take any questions,
comments and concerns that you might have at this time.
-: I appreciate that.
First and foremost, I'll say thank you.
Thank you to both of you gentlemen,
and to all of the staff who worked on this
substantial and landmark rulemaking
that was done on an incredibly fast timeline.
Thank you for all your hard work on that.
The bottom line,
and the reason all that hard work was put in
on such a rapid
timeline was because we've got to make sure
this is in place for this winter.
And this rulemaking will be a big step
to ensuring that the physical resiliency of our grid
is vastly improved this winter over last winter.
I would also wanna thank our stakeholders
and especially our generator and transmission community,
because they have largely
been ahead of the curve
in buttressing and reinforcing their infrastructure
ahead of this rulemaking.
So, I appreciate their, not only contributions to this,
but also the efforts they've made proactively.
And the final thing I'll say is that this is,
so you've probably noticed,
this is phase one of our rulemaking.
This is an operational standard
to be ready for this winter.
A more robust
and year round preparation standard
is being developed by ERCOT to be implemented later.
I think that was a good suggestion
of Commissioner Cobos,
to stagger that rulemaking.
So thank you again,
open it up for questions or comments.
-: I just wanna echo the Chairman's ...
Can you hear me?
The Chairman's comments.
Thank you very much to you Barksdale
and David and the rest of the staff
that worked on this very critically important rule.
It was quite a task
to get the rule done in time for the winter.
And as the Chairman said, I think it is
a landmark rule on weatherization because
never before have we had
such robust weatherization standards
in place with enforcement authority.
So, I think that is a huge step forward
for the industry in terms of weatherization
to ensure we have
a more resilient
generation fleet and a transmission system
for the upcoming winter and for the public.
And so thank you very much.
And thank you to the industries for working with us
on such a short turnaround time.
-: All I can say is, great job to staff.
You turned this around in record time.
I would say that,
I hope the generators,
and I have been assured that the generators
are ahead of the game on this
and have proceeded down a implementation plan
in advance of the rule.
Consumers are on the other end of the hook on this.
So let's get out there,
let's start imposing this standard, get 'em ready.
Winter is around the corner, but thanks.
-: I would echo the Chairman
and my fellow Commissioners' comments
on thanking the staff and the participants too,
for their efforts to do this quickly.
If I go back and look at the winter storm,
to me, there's not one issue that was the problem,
but there's one major solution
to our piece of this puzzle
and that is winterization and weatherization of these plants
to make sure that when we want them there,
that they are there.
So, I believe this is absolutely the first step.
I believe this absolutely makes our system
more reliable in wintertime,
and I believe we're absolutely on the right track
to making this
the standard for winterization and weatherization.
Again, weatherization, so winter and summer,
but we've historically been a summer peak.
Everything was ready for summer, but not for winter.
So, I applaud you all for the efforts
to think outside the box
and to get this done quickly, thank you.
-: With that, is there a motion
to approve the proposal for adoption?
-: So moved. -: Seconded.
-: All in favor, say, "Aye."
All: Aye.
-: Motion passed, thank you, gentlemen.
Next item is docket 52373,
a review of wholesale electric market design.
As you all know, following the memo last night,
I apologize for the late hour of the filing,
that was a result of some IT challenges,
which we can all see will continue to plague us
in various forms today.
Before I get to the memo, I do wanna touch on
an item that's gonna come up
at tomorrow's ERCOT board meeting
regarding increasing the
certain types of load that can participate in non-spin.
This has been
a robust stakeholder process to get to this point.
The most important element is that
it will bring more capacity and more reserves
into our margin of safety this winter and next summer,
which goes a long way to ensuring reliability.
And a lot of folks worked hard to make sure that
the way this is implemented is
on a resource agnostic basis.
And that's exactly the kind of principle
we want to implement in this
and I think going forward.
So, I'll tip my hat to all the stakeholders
that have gotten us to this point.
Regarding our market redesign memo.
First and foremost, I wanna say,
as we've discussed extensively, this is a starting point.
This is by no means exhaustive.
This is just a starting point or a draft
of a draft of a draft.
I very much anticipate
this being a dynamic and fluid document
with y'all's input and continued stakeholder input.
The only thing I'm certain of
is that I got a lot of this wrong
and I'm sure the details will change.
I anticipate staff, today we can aggregate,
we've identified the concepts
that we want to focus on moving forward,
to narrow the scope of this effort.
And also importantly, identify the concepts that we
don't wanna focus on going forward.
Importantly, I think we need,
the four of us need to identify key questions
in this narrowed scope, so staff can issue
a formal straw-man draft early next week
for stakeholders to respond to.
I would ask the stakeholders to respond
by November 1st on this much narrower scope
of items.
We'll have more details about that
when we do issue the formal document early next week.
As you all know, there's no silver bullet.
We've gotta use a combination of tools
and please do not take my memo as an endorsement
of any single plan.
I did my best to
select the key elements of what I think will work
best to stabilize this ERCOT market.
As for the meat of the memo itself,
I'll lay out a couple of thoughts at a higher level,
and then look forward to having a
detailed discussion with you all about all of this.
First of all, I'll start with
concepts I think we need to take off the table,
that are not viable for consideration going forward.
The biggest of these is,
what I think of as a capacity market disguised
as a new ancillary service.
Even if
a capacity market disguises a new ancillary service
and might solve
our short term reliability problems,
in the long run, if we continue to have
increased intermittent resources in our grid,
it's just a bandaid on a bullet wound.
It will not solve the problem longterm
and the problem will only get bigger
the longer we ignore addressing it head on.
These kinds of products,
may be successful in retaining
existing generating assets,
but they've not been successful
in incentivizing new generating resources anywhere else
and I doubt that they would be successful here.
As for what I think would work, as you saw in my memo,
ORDC, I think everybody would agree
this is an improvement we can make.
Certainly, it would drive revenues
to reliable dispatchable resources
during times of scarcity,
that should help retain our existing fleet,
which is incredibly important.
And it's also a market-based mechanism
to bring more generation on sooner
rather than out of market action, like RUCs
that we've had to rely on these last months.
And I think we should make those changes too,
to ORDC, as you saw in my memo.
However, we've made changes to ORDC before,
and they clearly did not solve
either the extreme weather problem
or the blue sky scarcity problem.
So, we've seen this maybe before,
what's different this time?
Well, I think it's a good improvement to make,
I don't think we can stop there.
Thus, the LSE obligation.
Philosophically, it's the only thing
we've seen that, to my mind,
integrates reliability into the normal everyday
functioning of the market, absent of a crisis.
It drives revenues to reliable dispatchable assets
that we need,
without paying a lot of money for assets
to sit on the sideline and not generate power.
And importantly, it leverages the
competitive market forces of our retail market.
Functionally, there are two key parts
of what I hope an LSE obligation can become.
First, an accreditation of resources
by generator type.
We have to be honest about
how reliable different resources are.
It is entirely unacceptable
that on these blue sky days,
that we expect 10,000 megawatts of wind
and get 1,500 and
in the absence of any other problem,
ERCOT controller, it is scrambling to find resources.
We've got to stop that
way of doing business.
We can not continue to run this state
and this economy that way,
our homes and businesses need reliable power.
We've gotta be honest about how reliable
each resource type is.
The accreditation is the first key part.
And the second key part functionally,
I see in this framework,
is providing forward price signaling to
the investor universe.
You saw my memo, I'd suggest
some percent of anticipated load up to three years out.
I targeted on that because right now,
as of this morning, the price of power,
a megawatt in Texas, in the summer of 2025,
it's 50% less than it is right now.
And that's what the financial markets are saying.
I don't think any of us believes
that a megawatt of power in Texas
will be less valuable
three years from now than it is right now.
It shouldn't be with the growth we've got
and the lack of dispatchable resources we've got.
So we need a mechanism like this
to provide real financial
price formation and price signaling into the future,
so investors can see what a megawatt's worth.
I picked three years,
because investors need to see
what they're gonna get from a megawatt
when a new resource would come online.
It takes at best,
three years to get a new
substantial dispatchable resource,
permanent build connected.
So, that's the framework
and the logic behind three years.
If I'm gonna finance
a new dispatchable resource in Texas,
what kind of megawatt am I gonna get?
And I need something I can take to the bank
and show them that this is real price formation,
these are real transactions in the future.
There are obviously some challenges with an LSE obligation.
First and foremost,
we've got to make sure it does not open the door
to market manipulation.
The competitive retail market,
it is not only a feature of the ERCOT market,
it is one of the crown jewels of the ERCOT market.
It is absolutely critical
to the functioning of the market and for our consumers.
We absolutely have to protect that.
And secondly, we have to make sure
that we can incorporate,
not just incorporate it, integrate
fully demand response into any LSE obligation
that we put forward.
If we can't, and there are a variety of other questions
that you still don't know,
but if we can't get this LSE obligation right,
I'd rather not do it than do it wrong
because doing it wrong would maybe cause more damage.
And if we can't get it right,
the only other option we have at that point,
to truly establish reliability in our grid would be to
set some sort of fleet-wide affirming standard,
reliability standard,
require all fleet-wide reliability.
So, I'll stop there.
Obviously, I know,
I expect you all have lots of thoughts and ideas.
Jimmy, you've got a lot of notes there, problems?
-: Oh no, no, that was weeks ago.
-: Oh good, I'm glad you've got more sense then.
I'll stop there and love to hear y'all's
thoughts and comments.
-: This is not on your proposal, I thought.
-: Yeah, so Mr. Chairman, compliments on the matrix.
So,
the details
and the detail column.
I gotta tell you, just from the outset,
I am not prepared on this day
to endorse any details.
Peter: Sure, it's a starting point.
-: I would strike that though.
Peter: Well, we've gotta get to it.
-: I know, okay, let's discuss this.
From the standpoint of a staff straw-man,
because I don't want staff unleashed, sorry staff,
but on any particular mechanics that are preordained.
And I say that because these are defined
mechanical components to the market design
that began your questions, man, I'm with ya.
It's a well thought out, targeted.
They trap, they drive toward these points,
but for the traders watching this meeting,
the detail column,
I wanna make sure and affirm that again,
I am not endorsing those details
and just for the group and you may not be either,
it's a concept map that you're articulating here.
The ORDC, absolutely 100% agree.
I believe that the MCL should be adjusted out.
Everything that we've heard over the proceeding workshops
leads us to that conclusion,
that its status, set at 2000 megawatts of reserves
is counter to the public interest
in that it hides behind
already sending the public a conservation notice,
which, what's the point of sending
price responsive signals or sending
price signals that you hope
consumers will respond to,
if you're already asking them to conserve?
-: Yes, not a lot of options. -: It's counterintuitive.
I believe we should offer up
a range for study moving forward
in the near term as a part of your straw-man concept.
And your questions asked for Brattle
to provide us again those cost impacts
as per your questions.
Peter: Sure, can we pick the scenarios together?
Can we do that today?
-: I'm ready for that.
-: Because stakeholders have told us
lots of different versions.
I wanna get at least a series of numbers on paper.
-: Absolutely ready. -: All right.
Will: Moving on, just so I can open up the field
and end my comments.
LSE obligations,
since we're focused on these two topics
and I agree with them.
I'm definitely not ready to endorse
an LSC obligation today.
I have significant questions
about what this would do to our market.
They must be answered before
any type of endorsement
is considered by the Commission, in my view.
Market power, who administers the program?
Does the PUC become the IRS and audit all these people?
This is a wholly different system from RECs.
Nobody cares about RECs, I'll say it publicly.
I mean, they care, they buy them,
but this is a requirement and it's not just a requirement,
it's a hard to get to requirement.
You have to be dispatchable
and what qualifies as dispatchable?
And all roads lead into that with the accreditation system.
So, I would love to have more study on this.
My view of affirming requirement, as you say,
and put it together, affirming requirement,
either an LSE obligation or a resource obligation,
'cause that's what you implied in your ...
If we don't get here, then we may end up there.
-: No other option. -: Right.
Will: With the amount of intermittent only resources
that are coming into the market,
that will penetrate our market in the very near future,
in the next two years and especially the next five years.
And especially with federal policy enhancing
that market momentum,
we have to have the breathing room to study
affirming requirement on one side of the other, now.
We have to be down the road
in order to meet those challenges some way.
And it may not look exactly as proposed,
it probably will not.
And I would suggest it will not, as proposed by E3.
However, we've gotta put the legwork in now
to be on target
for whatever that market looks like in five years
and it's gonna change dramatically, we know this.
And then whatever batteries do,
in terms of technology and economics and
the new innovations.
So with that, I believe we need to study this,
but be ready to kill this thing in its crib
at any moment.
No endorsement, no endorsement,
indeed ask the right questions, study them,
have Brattle do the analysis,
make recommendations,
bring in a comprehensive stakeholder process.
I view the LSC obligation,
it's almost like a drug entering the market.
It needs to be peer reviewed
and everybody needs to log every bomb in their
arsenal at it and they need to defend it
and find out a way where we can get to a place
that's in the public interest.
So that's my view, sir, thank you.
-: I very much appreciate that.
I think between now and our blueprint in December
is where we need to get comfortable with a
thumbs up thumbs down on LSE.
We don't have to have all the ...
We don't have to have everything answered.
We have done an exhaustive stakeholder input.
We'll continue to do so, and in no way
do I think the
belly of that memo was the E3 proposal?
-: Okay. -: Big differences.
So again, the starting point,
but I think between now and December,
I think the goal would be to focus that stakeholder process
on figuring out if we can get to the comfort level
on LSE obligation, thumbs up, thumbs down by December.
And we've still got a lot of work to do after that.
-: Yeah. -: For sure.
And then if not, if it's a thumbs down in December,
absolutely 100% prepared to kill the idea,
if we can't get to answers that are satisfactory
and then move towards
the other reliability standard,
which will also take time, that's not something,
but
we've gotta do something.
We've gotta pick something and choose a course
to go down a path to go down,
relatively soon.
We don't have the luxury of years of studies.
-: Okay. -: Go.
-: And if I could. -: It's fine.
-: Okay, so a lot of comments
and I'm gonna try to parse this down
and really, I have a lot of very targeted comments.
So first and foremost,
I've said this many times or I'll say it again.
I think our focus should be
on addressing operational reliability issues
that we have and will continue to experience in the winter,
and that is cold weather events
and periods of time when we have
higher than expected demand and/or
lower than expected generation output of all types.
And I think that we're living that,
we've been living that or it's all types.
And so those are the two operational scenarios
that I believe that we have faced, we'll continue to face,
and that has brought us here
to this very desk today, to try to
look at the market again with that lens.
And underneath it all,
to provide that foundation of reliability that
we believe the market, the leadership,
the consumers, Texans, expect and deserve
and that's why we're here.
So how do we get here,
in this market construct that we currently have?
I will say, with respect to all the proposals
that we've received,
all of them involved a capacity market element,
all of them.
In one hand, it's a central procurement
of resources by ERCOT.
On the other hand, it's a capacity obligation on LSEs,
they have to go to the bilateral market to fulfill.
So there are both ...
Peter: But the only difference with the LSE obligation
is that's the only one where you're required
to procure generation that you actually plan on using,
not sitting on the sideline,
that is a key difference.
-: Then hoping you have enough,
so I'll get to that.
Just to level set, that is my perspective.
All of them have a capacity market
element to them.
Matter of fact, the LSE obligation is called,
the bilateral capacity market.
Okay, so as we look at, what do we do next?
How do we, and I completely agree.
We've gotta do something.
We have to attack the issues
that we have on our table right now.
But what I wanna do is,
I wanna do it in a targeted, strategic manner
that solves the problems
that we are actually going to be facing now
and in the future and have faced.
Okay, so ORDC, 100% agree.
We've lowered the price cap,
we need to make adjustments to make sure that
the ORDC is sending the price signals to the market,
to incent investment in existing generation.
And what I mean by that is additional units,
the generation plants, upgrades that squeeze out,
shoot out more megawatts per month from a plant
and potentially some new generation.
So ORDC reforms are necessary,
but we must do so in a balanced manner
that will drive investment
in dispatchable generation.
And from a reliability perspective,
ensure that operating reserves
are coming online earlier
than when we are already in the A1,
because the A1 is 2,300 megawatts
and the ORDC kicks in at 2,000 megawatts.
So the MCL has to increase
from a public policy standpoint, the ORDC
needs to kick in a lot sooner,
and I think we're all in agreement.
It's just a matter of
what number, and I saw your recommendation and
that is a threshold.
I think that is on the ERCOT matrix of
when emergency purchase procedures start
below 3000 megawatts.
And so, I see where you came up with that number
and I think we should look at it.
And so the other aspect of the ORDC
with respect to policy considerations,
the VOLL/price cap.
We must set price cap/VOLL
at a point where generation that fails to perform
will still have performance penalty.
We must ensure that generators are
held accountable for not showing up.
-: Yeah, all types. -: When they're supposed to.
All types.
And also that
we are setting the price cap and the VOLL
at a point where we are still
maintaining an incent demand response,
that has been also very important
for maintaining reliability on the grid.
And as we move to the MCL agreement,
we need to go up,
I think we should at least study 3,000 and 2,800
and maybe a little bit higher
if you wanna start it before.
But those are some numbers in there
that we need to look at
if we're trying to set the MCL at a place where
we're not already in emergency procedures.
With respect to standard deviations,
and shifting and extending the curve,
there's a lot there, there's a lot there
and I think we need to see some analysis,
because as you shift an extended curve,
there is going to be more ORDC adders
over a longer period of time,
which could provide price signals for investment
in new and existing generation.
But it could also
provide ORDC adders to renewable generation.
And we as a committee, and a megawatt is a megawatt.
Megawatt is a megawatt when we need a megawatt on the system
to maintain our liability.
But if the goal, the public policy goal
of the condition is to incent more investment
in dispatchable generation,
then we need to strike a balance in there somewhere.
So, I would suggest,
as Commissioner McAdams has recommended,
that we give Brattle some very specific parameters
to at least give us some context
as to what those parameters would do
with respect to consumer cost, adding revenue to the market.
So we have some third party analysis of it.
And so Brattle and Estrate are perfectly veered
to give us that context.
I think if they can get it to us before November 4th,
the work session November 4th,
I think that would be very ideal
so we can start making decisions.
I think 4,500, 3,000 and the standard deviation,
I'm fine with having them study that.
I think that's a great starting point
and thank you for recommending those.
The other one that I would suggest
that is interesting to me,
and I know the MCL might scare people,
but I have heard,
a little bit from the generation community
and the consumer side that they are
comfortable with the IMM's proposal.
And so that's,
in and of itself that you can get some generation
and some consumers to agree
that that might produce the result they want
and be comfortable with it.
And since the ERCOT IMM
is in a neutral position to provide us this kind of input,
I think it's just another piece of context.
Look at that
suggestion as well, your suggestion,
and any other parameters that
we can think of in the meantime,
to have Brattle (indistinct).
The other thing I will add,
as we prepare to go to the winter
and we wanna have all the tools in our toolbox
that we can have to maintain reliability.
My suggestion would be,
since we do have the rulemaking open right now
for the price cap and our goal is
to have that price cap adjusted by January 1st,
because that's when the old cap at 2,500 goes away,
and the new price cap kicks in.
My suggestion would be that we have ORDC reforms,
however, have them in place
by the beginning of the year in January
and I think that's totally possible.
All we need to do is have an OBER approved,
once we give them a directive.
And that way, when we enter the winter season,
we have an ORDC in place that will
signal more operating reserves to come online
before scarcity, to maintain reliability
during the upcoming winter season,
as an additional tool to our arsenal of tools.
So,
the LSE obligation,
I think I have a lot of questions myself.
I'm not prepared to endorse it at this time.
I questioned whether in a short amount of time
that we have from now until December,
if we're gonna get all the information we need
to be sure that this path is gonna give us what we want.
We don't know until we know.
I think we can ask a lot of questions,
get comfortable,
but until we're actually in there building that framework,
that's gonna take a little while.
At least, I don't even wanna guess,
it's gonna take a while to build that framework.
We're really not going to know
whether that LSE obligation is gonna produce
the reliability benefits that we want
until many years out.
And the last thing I wanna do
is spend a whole lot of time
working on a very complex market design change
that will not give us the reliability
and drive the investment that we needed
and we are still continuing to experience
the operational and reliability issues
that we are experiencing today.
And so the accreditation process-
Peter: I would say, the fear of something not working
is not a reason to avoid trying to make it work.
-: But in the meantime,
we could have significant impacts on our market,
our retail market.
We must ensure that market power
is monitored by the ERCOT IMM.
Market power is monitored in a bilateral market
that the IMM does not have visibility into,
and that the retail market is protected.
And the retail market is
when you squash on an LSE obligation,
there's a lot of complexities that's there;
there's customer migration,
customer switching, polar events,
a lot of migration that the LSEs will have to
take into consideration as they prepare on their obligation.
And I wanna say one thing that's very important.
We've spent, we all have in one form or fashion,
spent a lot of time working on
landmark securitization
and to stabilize the ERCOT market.
And part of that stabilization
was to protect the integrity of our
crown jewel retail market.
And I wanna make sure that
all this hard work we're putting in,
that at the back end,
we're not gonna come in and just
all that hard work is gonna be for nothing and destroyed
because we're looking for reliability.
(sighs) If it comes off, it'll be a Texas talk
in all the wrong places.
(people laughing)
-: I like that, and I'll say
that if I feel like this is gonna squeeze
the independents and non-affiliates out,
I will vote no on that thing today.
That is a red line for me, so it has to be addressed.
I'll take it off the table today
and make 'em go back to the drawing board.
Can't have it, in my view.
-: And so, what I'd say ...
Peter: That's exactly what I've put in my memo.
-: And I wanna say Chairman, and thank you.
I think conceptually what you're seeing,
the overall picture
where you're trying to head with this,
I think that that's
something we all can agree in one form or fashion.
The accreditation, we can handle that accreditation
in other policy
decisions that we made with respect to allocation of costs.
There's other avenues to
make sure that we develop an all resources economy.
I don't wanna use a very complex market design change
to make sure we're all resourced together.
Peter: Well, let's get the other ones
that are on the table. -: Absolutely.
-: If we can do it quicker, sooner
and cleaner, absolutely.
-: Absolutely, but I will say that,
and I agree with Commissioner McAdams,
I don't want this to turn into, and I know that it won't
because we have a deadline by the end of the year where ...
I think it's gonna take a little bit of time
to answer all our questions
and we're not gonna really know
everything by the end of the year on this option,
is my belief, but I wanna make sure that
if we're not getting satisfactory answers
that we move this off the table,
because I think the longer we have it on the table
and try to squeeze out something out of it
and not get comfortable, get comfortable,
the more uncertainty we send out to the market,
to the investment community.
And so we've moved this option once before off the table
in 2013, 2013, without a blink of an eye, okay.
So, we've gotta make sure that what has changed so much
in this market, and there's been a lot of change,
there's been a significant integration
of renewable generation, we've had a devastating storm,
but let's keep our eye on the ball
and make sure that we're delivering reliability
in all the right places and all the need.
-: Chairman,
can I ask you a procedural question
and that is ... -: Ask me anything you want.
-: Are we gonna go through
all of the components of your plan
or are we just gonna do the first two?
-: We can go through however many
we want or more.
Apparently there's some new ideas on how to
ensure accountability of resource.
I'd love to hear those.
My goal,
by the end of this is to have narrowed the scope.
And to be clear,
I'm not asking for endorsements or for votes today.
I'm asking for us to
dramatically narrow the scope.
We've heard what the stakeholders want.
We need to start making decisions about what this
Commission wants. -: Right, I agree.
-: So I wanna, by the end of the day,
I wanna narrow the scope
dramatically enough that we have
a concentrated top list of topics to talk about,
so we can start making those decisions.
We can get the questions
and we need to specifically give staff questions
we want answered from the stakeholders.
So, I know the staff is prepared to,
by concept or by theme, for each idea,
a list of questions for each one,
we'll publish that next-
-: But my question was because I didn't ...
I'll stop at my comments on ORDC and LSE obligation
because everybody else has,
and we can go through the others, subsequently.
First of all, I wanna say,
I appreciate your leadership in doing this.
It's never fun to be the first guy
to get shot at all the time.
-: Absolutely. -: Yes, absolutely.
-: I know what you're doing is,
you're putting something out there that can be shot at it,
as you've said so eloquently, that
all I know is the first draft isn't gonna be right,
but it still takes courage to do it
and I appreciate that.
There are a couple of things that I premise
my belief in this market on.
So first of all,
I believe that we should do no harm.
I believe that we ought to be enhancing the retail market.
And I believe that all resources are equal.
A megawatt is a megawatt
an electron is an electron, especially in scarcity.
And
a megawatt hour or a kilowatt
not used during scarcity is equal as well.
With that being said,
I think we need a reliability standard.
I think we have to tell the market and the people
that we are serious about this, and without a specific.
I don't know if it's one in 10
or one in five or one in two.
I don't know if it's ...
I don't know what the number is,
but to me, if you're not aiming for something,
then you're scattered everywhere.
So, that would be first thing: let's aim for something.
Secondly, I wanna say that,
with all of these proposals that came in,
including the LSE obligation,
I don't have any idea what they cost.
They're fantastic words on paper,
but none of them say how much they cost versus the other.
These are ultimately things that we
are costing the market or putting money into the market
and being paid for by consumers.
So, we talk about
putting additional revenues in the generation sector.
How many?
How much money versus another alternative?
And I don't know the answer to that
on any of the proposals,
but think that Brattle needs to help us quantify those.
I don't have a problem paying more if you're getting more,
but if you're not,
then I sense that that's not a good decision to make.
I think there's some things that
ERCOT has on their agenda now
that make what we're doing over here a little bit ...
Well, let me say it this way.
We have to encourage them to finish their
co-optimization ASAP.
We just don't know what's gonna come out of that.
And a lot of that affects
what these load responsibilities would be,
or how much generation we need in the market.
Finally, as I've said in the past,
we still have some megawatts on the system
that can't get to load because of transmission constraints.
And there are out of market mechanisms
and reliability mechanisms
that are being used by ERCOT to limit that,
that I hope we can help resolve in this.
Again, I think a electron is an electron,
especially during scarcity;
we need to think of that.
I would say very specifically, just a couple of things.
One of 'em is,
as we talk about this,
I think we're doing a lot of supply-side work
and not much demand-side work.
We are looking backwards to a
vertically integrated, real vertically integrated market,
where all we look at is how we deal with supply.
The demand-side is really important
and the demand-side from,
whether it be price-responsive demand of residentials,
but all customer classes,
if it deals with electric vehicles and batteries,
those are all things that I think are forward-looking
that we need to consider today,
not just the backward-looking things,
only on the supply-side.
I feel two things are important.
One of 'em is, I think we need to pay for voltage.
We haven't historically done that.
Voltage is one of those things where people said,
"Well look, the market doesn't even function.
The transmission system doesn't function unless you use it,"
but there's a cost to it and there's a value to it.
And if we're in a market,
we ought to pay for the value of that component.
I'll say specifically about
the ORDC and the LSE obligation.
I think ORDC is a no regrets action.
I think we can agree that something
needs to be modified here and what those numbers are,
I don't know.
To get me comfortable on the number,
part of that has to be the study behind it
and what we get for it and what it costs.
We must allow all generation types
to collect ORDC revenues during scarcity.
That includes variable resources, renewable resources.
Again, my belief is an electron's an electron.
So, if they're producing,
then they can get ORDC payments as well.
So, supporting that and figuring out
what the analysis that we need.
The numbers are fine: MCL 3,000, 2,800.
We might wanna do
something that is extremely low and extremely high
to put a band ...
Peter: Like a scenario analysis.
-: That's right, as a comparison.
Same thing, are we going to 4,500 or 6,000?
We might try some things that don't seem logical
as benchmarks or bookmarks on either side
so that we can understand
what something really high or extremely low does
to the market.
And then onto the LSE obligation.
I think that it's a massive market change.
I'm not totally convinced it's needed
as I have mentioned.
My fear of market power
is front and center on that.
I don't want to go to four gentailers
that have unregulated monopolies in the state.
I don't think that's good for consumers.
It's complex, the duration for implementation is long,
and if we can do it sooner, great,
but we'll have to see the details and how that works.
As Commissioner Cobos said,
if it's detrimental to
customer and retail competition,
it's gonna be really hard for me to get over that hump.
20 years ago, 25 years ago,
I spent time trying to help create the retail market
and I think it's been great.
I wanna see a more robust retail market,
not a smaller retail market.
And then my last question on this is,
I don't yet have any assurance
that this will actually incent new generation.
What amount of new generation we need, I don't know,
because until we have a robust demand response in this state
that affects price, affects supply needs, we won't know.
But I believe, as in your memo, demand response
has to be used as a grid reliability tool
as often as we can use it.
It does, it is a tool that should be in the toolbox.
And I think as we get new technologies,
we spent billions of dollars on smart meters.
We don't know if they're the right smart meters
for the demand response, but
that's what some claimed
and we need to figure out and push the envelope
on technology to be a supply-side,
a demand-side market.
And almost every other product,
we get to not buy it if we don't want it,
we get to go to another store.
We get some of those here,
but electricity is obviously that fundamental right
that we need and I believe that
the demand-side increases reliability,
demand-side functions increase reliability,
and a decreased cost for the market.
-: Well put.
If you'll all hear me,
I've got some quick thoughts on those comments
and then I would suggest we
start with the easy ones and
give staff a list of
concepts to consider,
not endorsement, but concepts to continue considering
and then a list of questions for each of those.
Quick thoughts.
ORDC, very much as I stated in my memo,
very much want to see some scenario analysis.
I do want to be wary about
over-engineering and overthinking this.
The biggest point of error
in any ORDC analysis is gonna be
number of days or hours used.
So, we can easily get
caught up in over-engineering standard deviations
and some of the nuances.
The biggest mistake is gonna be,
how many hours that is used here?
So those revenue productions are
gonna be wrong, and so
at some point we just need to pick something
and it doesn't have to be complicated.
On the Ellis, I'll save it though,
save that for last. -: Thank you.
-: Demand response.
I've put it third on my list for a reason:
it's incredibly important.
And I do want to,
I guess, share the breadth of what I'm thinking about.
It's a little understated on a grid in a Word document.
But when I say upgrade hardware and software,
that's essential hardware and software that runs,
that collects the smart meter data.
Doing that, upgrading that
to increase the frequency of the pings from that telemetry
and being able to handle and manage that increase in data
is a massive, massive investment
and it's a massive effort.
It is no small feat.
And I think the reason I focused on that
was because
that is the keystone that will unlock
an extraordinary amount of capability for demand response.
And so it's a little understated
as presented in the memo,
but I do wanna highlight that that is
a extraordinary large project.
And I do want to make sure that folks know that
just because we need to increase demand response,
doesn't mean that we don't have robust demand response now.
We heard in our demand response workshop that,
from one of our largest retailers, NRG, that
the only constraint they have to more demand response
is price signaling and customer willingness.
There are areas we can improve,
but we know it's happening;
just because we can't see it at the ERCOT level
doesn't mean that it's not out there.
As for the LSE obligation,
we know, we don't know
what any of these will really do in practice to prices;
even the ORDC.
It's a huge margin of error in trying to presume
that we know how many hours it'll be used every year.
We've got a lot more data about the stock market
but nobody on the planet can tell you what it's gonna do.
Just to think we can
predict the weather in the power grid that accurately.
We know we don't have enough dispatchable power in Texas.
The wind stopped blowing yesterday.
Everything else is working just fine, or as expected
and prices went to $400.
The market is set to go to $500.
That's 100X pricing
that customers will pay for
because we don't have ... The wind stopped blowing
and we don't have enough dispatchable resources.
And while in the longterm,
we obviously want to keep
competitive retail market;
in the short term, we need to be prepared
to face the possibility that prices may go up
because we don't have enough of the supply we need.
We know that, that's why we're here,
but the cure for high prices
in a properly functioning market is high prices.
The investment's signaled
to bring more supply to our market,
more dispatchable supply, which is exactly why we're here.
So while there may be short term increases in price,
we of course wanna minimize that,
over the longterm,
we need to provide the financial signal
to get more investment
and more dispatchable supply in Texas, we have this.
LSE, yes LSE obligation is a
monumental change to the market,
but we saw both this winter and
in the extreme weather event
and on the blue sky problems,
blue sky day problems we've had this summer
and even this week that
we can't not take drastic action.
The lack of action in 2013 didn't work out so well.
We've seen the ORDC movie before, we know how that ends.
So, I don't know how we can
say we're doing our job without at least
taking a serious, serious look at something like this.
And that's all I'm asking for
over the next couple of months is to
set a narrow focus on figuring out what that LSE obligation,
if we do it, should look like,
so we can all get comfortable with the problems
identified in my memo,
and you all have all articulated so well.
As I said at the beginning, this is not the ESA proposal,
this is not the NRG proposal.
This is my version
of what an LSE obligation could look like.
As you saw in the memo,
one of the proposals is a bulletin board type posting,
centralized posting for price transparency,
so IMM and everybody else
can see into bilateral transactions,
so they can see what those prices are,
so they can see who the counterparties are,
they can see what kind of megawatts are moving where.
That's middle of the road on that spectrum.
Under no circumstances can we leave,
if we do something like that, can we leave,
leave the bilateral market for
these types of credits in the dark, absolutely not.
On the most extreme end of the spectrum,
which may very well be a viable choice,
is to have all of these credits be required
to be traded in a centralized location, run by ERCOT
like the CRR options.
So, there are no bilateral (indistinct).
Everybody's gotta trade these credits
on an open central exchange.
I don't know what the right answer is, but
I think we have to start asking these questions
and figuring out where on that spectrum might be suitable,
and if it's viable, to get there.
I'm sure we will have more thoughts on that
as we move through the morning.
If y'all are game,
how about we start with a few easy items
to add to the list of questions,
items to consider moving forward with,
start with an easy one: FFRS.
Do you wanna keep that moving forward?
-: A question, Mr. Chairman, procedural.
Could we adopt and maybe rule
as we move through your list, it's a good list,
to contextualize it, what could be implemented,
as Commissioner Cobos has suggested, six months,
in the next six months or a year?
Peter: Can we do the list and then look at what ...
-: If you want to, but as you discuss it,
it might help us frame it.
Peter: Sure.
-: But, however you wanna do it.
-: I don't really wanna do it really.
How I moved through my list
to have a conversation with this,
and I'm just trying to figure out
what the most efficient thing would be to do.
As I discussed with ORDC,
having something in place by early January
so we can get the online midterms going.
I took a phased approach into it.
So, I know we're talking about broad market design,
but as we're looking at market design,
some of these features that we may be interested in changing
may take years or months
and so we need to have interim measures
all the way through
to ensure that we maintain reliability
and address the issues that we have
and will continue to experience along the way.
So your next topic,
I think it's actually the next topic
I was gonna go to anyway, which is
demand response NARS reforms.
-: Okay, so I was gonna start with the easy one,
fast frequency response.
-: We need to know what the treatments are, yeah, yeah.
-: Okay.
That's fine, I mean ...
-: So, is everybody comfortable
continuing (indistinct) -: Yes.
A Response on the. -: Absolutely.
-: Stated timeline, all right,
Let's get that on the list, everybody's good with that.
Jimmy: As long as all resources can participate.
(Will laughs)
-: I think that's the plan.
How about our ECRS ramping product
that's currently under development at ERCOT
continue on current timeline, implementation timeline?
-: Yeah, I think we don't have a choice
and that would because ERCOTs EMS upgrade,
but I do wanna add a little bit there on that.
So I think the ERCOT community reserve service
is important.
It is going to provide
an opportunity for batteries, quick-starts and loads
to help with the ramping issues
we're already experiencing.
And so,
ERCOT TCRS won't be implemented until 2023 or 2024,
because of the MS upgrade.
However, I think that it is incumbent upon us
as we're starting to experience these ramping issues
to start thinking of an interim measure.
-: What would that look like?
-: I would direct ERCOT to scrub down their existing fleet,
I mean their existing ancillary service product fleet,
just to see what we can do
with an existing AS product,
which are a non-spin regulation service
and see if there is something in there
that they can create a subset of
or some kind of requirement where we can start incenting
the opportunity to address this ramping issue
with a variety of technologies.
-: How about we expand RRS?
-: Where we do not spend, that's up to ERCOT.
I think they have ideas. -: True.
-: I don't wanna tie their hands.
I wanna give them the opportunity
to scrub down their existing product list so that
we can look for opportunities
and I have a very specific idea in mind.
So, what I mean by this is
we're waiting for ECRS out here and absolutely agree.
Please have ERCOT continue to work on it
and get it done sooner if they can.
And that ancillary service is gonna help us address
the ramping issues and in a combination with
ECRS and Nomsten,
I think we're gonna get a lot of value
to address these and the operational issues
that we are already experiencing
and continuing to experience
with a higher level of only the one system.
But in the interim,
I think we should have ERCOT look at the AS products,
figure out if there's a subset they can carve out
or some kind of requirements
they could work with and incent,
because the main ramping issue we're going to experience,
I think that we're starting to experience,
that you have brought up, is solar
coming down off the system in the evening,
and you gotta get ahead of it, right.
And ECRS is intended to address that issue,
however, it's petered out.
And what I've heard from the solar community,
and I think this is where I'm going
with the policy consideration of,
okay, well if we're having to procure
or do some kind of manual workaround right now
with our existing AS fleet to address this ramping issue,
then maybe you can look at causation,
balancing out societal benefits and cost causation.
But there's a real opportunity, I believe,
as you've highlighted in your memo,
that there's a lot of storage in the interconnection queue
and it's about a two hour duration.
And what I have heard from the solar community
is that in fact, this combination
of solar and storage
can actually help smooth out this curve
and our duck curve right now, if they expand in the future,
as will probably be in the short term, maybe two hours.
And so if we're gonna continue to get,
if we're gonna continue to have solar show up in ERCOT,
which they do provide a reliability benefit,
it's that ramping issue we're gonna have to deal with.
How about we look for ways to incent,
to provide an opportunity for these co-located technologies
to enter the market so we can reap
the reliability and operational benefits.
And what I mean by this is that,
if we can find a way to allow this combination,
solar and storage, to enter the market now,
before the OCRS AS product is in place,
I think we're gonna get a lot of operational benefits
out of that co-location and right now,
out of about 19,000 megawatts,
that's in the solar queue,
over 50% of it has storage with it.
So it's a package. -: Fantastic.
-: Exactly, so how do we move
these bundle technologies into the market,
because if we want solar to show up,
we'd wanna preferably for them
to show up with storage, right,
so we don't have this big ramping issue.
So, what can we do in the interim
while we await ECRS to create
an opportunity for solar and storage
to get out of that queue and enter the market
and provide us that reliable (indistinct)
if we can. -: Sure,
it's certainly a problem
and it's the problem that ECRS has been built to address.
There's a time lapse.
I'm very, very wary of asking ERCOT
to build something new while they're building something new.
Lori: It's not building something new,
it's looking at their existing fleet.
-: I'm very comfortable with asking them
to expand an existing AS product.
And also, do we wanna make sure
the public understands that,
even in the absence of any action like that,
solar and batteries today
can participate in the market,
in the energy market as they choose, as they see fit.
I think expanding the ORDC
provides a big financial incentive
for those batteries to start discharging into the grid
if we get into moments of scarcity.
So there's a robust mechanism and presumably,
very soon there will be increased revenues available
for anyone who has batteries.
So, I would certainly be okay
thinking about expanding a product,
but it's hard to ask ERCOT to build something
while they're building something else.
Lori: And that's absolutely not
what I'm asking ERCOT to do.
I'm asking them to look at their existing suite
to see if there's something we can do
with an existing AS product,
so that we can send that price signal and get those-
-: Sure, they will be considering bring in load
and do non-spin tomorrow,
which is a huge increase in our margin of safety.
-: And as a compromise.
So,
this goes hand in glove
with a consideration that we had
on firm fuel AS and possibly
getting expedited in non-spin.
I remember folding that in,
and that would necessitate a system change
as per Kenan Ogelman, his response to that.
So it's all about the timeliness
of the computing and fixing their systems.
So it could be a question of where they could file comments
as a part of your ECRS.
Peter: Sure, let's add it to the question list for ECRS.
-: So that it could be taken up.
-: Absolutely, and I have had conversations
with ERCOT about this,
and I don't think it's gonna take a system change.
I think it's gonna just take some tweaking
of the market rules
to be able to provide this avenue
to open up an existing AS product
a little bit more so we can encourage these technologies.
And I think it's important, because it's gonna be years
before we get ECRS,
and let's start getting these technologies in
so that we can address both reliability
and operational risks that we're gonna experience
because of more solar showing up without batteries.
Let's get them to come across the finish line
with the batteries.
-: We'll add a question about an interim
to the ECRS concept, an interim product adjustment
within the existing AS suite
that can be implemented
to mitigate the
duck curve.
-: I think we need to ask about
some pros and cons of different durations for those,
if it's batteries and it's ramping,
is it two hour?
One, two, four, six or eight, I don't know.
-: Right, and that's where I'm hesitant
because that's what ERCOT's gonna work through on ECRS.
And if we asked, and in some ways asking them
to solve that problem in non-spin
and opening the hood up on non-spin
to rejigger that market. -: Does it need really ECRS?
-: Well I mean, you're just doing ECRS under a different ...
You're doing the same mechanic work under the hood,
you're just doing it under a different product.
-: I think what Commissioner Cobos said,
the question is, can we wait that long?
Can we wait for ECRS for three years
for that type of product to come in?
I've been one that I think
that we have to find an interim solution,
whether it is the expansion of an existing
ancillary service,
if it's lifting, if it's lowering the durations
or allowing batteries into
different types of ancillary services,
or in fact almost all of them, then I'm for it.
But I think that's a problem
that we are gonna have to solve sooner rather than later.
And waiting till ECRS is completed,
we're gonna be late to the game.
-: And we'll continue to look for,
use our existing tools to deal with ramping issues
that we're gonna continue to experience,
because what we're dealing with right now
is the ramping issue.
It's not a huge duck curve yet,
but in the coming years with 19,000 megawatts
in the system, in the queue,
we're gonna continue to experience these-
-: I'm aware of it.
-: So, let's get ahead of the game
and not wait around and have an interim solution in place
while we wait for ECRS,
which I think is gonna provide
those services to be able to address the ramping issue.
And like you said, when we get into,
how can we look for accreditation
in our existing energy only market?
We can have a conversation about
how ancillary services are allocated,
what's the societal benefit to the market
by having these AS products
versus who's calling these calls for AS product.
I think that's where we can find
a policy-based forum and avenue
to address some of these issues
that you wanna try to address for accreditation.
-: Say that again.
-: So, I don't wanna go into a rabbit hole on this,
'cause I know we've gotta keep moving,
but you had asked me, how can we get there?
How can we require firming
outside of accreditation in our current
only energy only market? -: Right.
-: Well, one way is to look at policy avenues
that we would have in place
through ancillary service cost allocation.
And I think that has been on the table.
The Governor asked us to look at it, we can look at it.
We'd have to come up with a policy-based ...
-: So assigning existing ancillary services
cost to intermittent.
-: Potentially, we have to look at societal benefits,
cost causation, capacity short.
There's a lot of policy ways to get there,
where it is some ...
-: Yeah, that's a whole new can of worms.
If we wanna do existing.
-: I'm not saying existing,
I'm saying as we get new products in place
that are geared towards a very specific problem,
like this ramping issue, that's what I'm talking about.
I think if you wanna look for avenues,
there's avenues, right?
During an accreditation process to the LSE obligation,
which I believe is gonna turn into
potentially a litigated process.
And there's the ancillary service avenue
where we can look at who's benefiting,
who's causing the cause,
we can come up with a policy-based way
of looking at those issues.
-: That's a good question,
well we'll have the question on the list, Jimmy.
-: I'm sorry. -: Did you get a comment?
Jimmy: I don't know, I'm sure it'll come back to me.
-: Okay, all right, so for AT ECRS,
we've added Lori's question
to the list of questions to be addressed,
including from ERCOT, most importantly from ERCOT.
-: I do have one question
or one maybe question we can pose,
and this is specifically for ECRS.
And as I understand it,
there's a six hour requirement for the existing proposal;
what would be the benefit of
either reducing that or eliminating that
or extending it?
-: Operational benefit, not profit margin benefit.
-: Operational benefits, absolutely.
-: That's consistent, right,
because it's supposed to be that's the footfall,
it's the range of rampability.
-: Right, yes, I wanna make sure
we focus on the operational need.
-: Absolutely.
-: Not letting the market duration design
tail wag. -: Agreed.
-: The operational dog.
Just because two hours happens to be the
current duration of what people can make money on.
All right, other questions for ECRS?
I've got obviously the quantity,
what quantity should be procured
and should it be seasonally-based?
And if so, what metric?
Lori's question has been added
and then the question about,
what is the appropriate operational
or the appropriate duration requirement for ECRS
to address the operational need?
-: Mr. Chairman, on seasonally-based, you know what,
I 100% agree with that. -: I had a feeling.
-: But I had thought that it'd be a great policy proposal.
It is that applied to all the unit?
I'm trying to get my arms around
the menu of ancillary services
that we're either in process of creating
or what we have existing today.
And now feels right at 7,000.
And so, as a doctrine on the part of ERCOT
or a taken
component of the mechanics,
price formation and procuring enough resources
to match seasonal variability,
should it be sized to seasonal variability?
So, is that question applied in your matrix
to all those ancillary services?
And if it is, that question forms the policy.
Or should it be a separate-
-: I did it by product.
-: If that's the way it is, I'm good with it.
-: Well, it may end up being all of them.
-: Okay.
-: So, I just didn't even think about a blanket approach.
I just tried to pick where seasonal would be the most.
-: They just keep on talking about it.
Well, 500 sounds right. -: Yeah.
500 sounds right.
I'd like to tie this to some sort of weather forecasting.
-: Yeah, I agree. -: Or it's not okay.
-: Okay, ECRS is a topic
we would like to continue to get questions on,
any other questions?
-: No, I think those are the main ones
from me and you.
-: Same. -: Thank you.
-: All right, ECRS staff could.
All right, let's go to some other ones,
hopefully on the low-hanging fruit.
Jimmy: And again, we're not designating a timeline
on that either, right, Mr. Chairman.
-: No, can we circle back to that?
My goal is to keep us focused
on getting the list of concepts we wanna limit the scope to,
and then the questions we want staff
to issue to stakeholders. -: Yes, we're coming.
Lori: One thing and I guess, or a couple.
So, will ERCOT just respond to these asked questions
regarding ... -: Mm-hmm.
-: Okay, maybe one question.
How soon can, if they find
a way to modify an existing AS product
to address the ramping issues while we wait for ECRS,
how long will it take to implement?
-: And what delay would be caused on ECRS?
Those are the same resources.
-: If there was, I ...
-: We'll have to ask the question.
-: Yeah, I don't know that there's a delay again,
because ECRS is in the oven right now, in the MS upgrade.
It's in the system chain,
this is an existing non-AS product
that they're just gonna do some testing
of market rules, potentially.
So this bus is moving and this won't get in the way,
they're on two different-
-: I'm not sure we know that,
I think we need to ask that question.
-: Okay, well. -: Just ask the question.
-: I've had many conversations with their cockpit
on financing questions.
-: Good deal.
Voltage support, how do we feel about that?
Jimmy, you had a pretty good idea.
(Lori laughs) -: Yeah, let's go.
Jimmy: I had one question about it.
When you say a voltage support product in that broad term,
do you mean an inertia product as well?
-: Yes. -: Okay.
-: Included in the service.
Jimmy: So I think paying for it,
but also maybe clarifying what an inertia product is
and understanding is
synthetic inertia,
what are the types of inertia that are out there
that might help the system?
And then how would we package them in a product?
-: Would, the question was,
an appropriate standard metric for grid point capabilities.
-: That's right. -: To cover that?
-: Yeah I think so.
-: Are we done concluding voltage support on the list?
-: Like your questions yesterday.
-: Any additional questions?
All right, we've got three down, wow.
All right.
Winter ancillary product, can we save that to ...
That's complimentary with where we ended up in December
as in if we're comfortable with
something like in the load obligation that can address that
and the timeframe, then we don't need to do it.
But I certainly, well, I guess we'll just dive into that.
I certainly think if we're not comfortable
with weatherization in winter,
winter affirming being addressed in whatever
new product is developed,
we can then
divert to the ancillary product,
the winter under the Black Star framework.
-: The only thing I'll add,
is that if we ultimately got comfortable
with the LSE obligation,
we don't know how long it's gonna take to implement it.
It's really unknown.
And so, my preference would be to have
a winter resiliency product in place
to at least address, not this winter,
but the next winter, because I don't wanna leave
our market and the public without some kind of
confidence that we'll have some product to address it.
I think, we'll have weatherization in place.
And if we could have this winter fuel
resiliency product in place,
I think that could help us address any potential
gas availability issues in the future.
And if we do end up going with the LSE obligation,
we can roll it in, or any other proposal ultimately,
or it stands alone and we have
a product in place.
I think it's a no regrets option as well.
And I would add it to go ahead and add it to the list, now.
-: Okay, it's a good point.
Very good point, I'm gonna add it to the list.
-: Yeah, same.
-: All right, questions related to
winter ancillary services product.
The first one I got was the definition
of what firm in the winter means, that's a big one.
Lori: I think that's a good question.
Is it onsite, offsite?
-: Or a combination thereof.
Lori: Firm contracts for gas, coal ...
-: Okay,
like most of them, how should the costs be applied?
I'd love to hear the nuances of that, if we could.
-: Right, I can add that to the list.
Question list for winter ancillary services product.
Lori: So defining it, I think is important.
What does it mean, how will it be procured
by ERCOT and how much?
-: Procurement methodology can be in that, okay.
What quantity have we got on there?
Lori: So do we do it in a megawatt amount,
like Black Star, or do we do it as a dollar amount like ERS?
-: That's a huge question.
Will: That's a good question.
-: That's a huge question
and how we procure it and how much,
because if it depends on what kind of
winter standard we're looking at,
that could get to be a really, really big number.
Will: Okay.
-: Depending on what kind of winter event
you're preparing for.
Lori: And duration, right?
How many days are we preparing for
and how long are these contracts?
Right now, Black Star is two years.
So how long are the contracts?
And I think another question is,
does ERCOT have the expertise
to review these RFPs? -: Balance.
-: And/or should they hire a third party
independent consultant to help them review the RFP?
Not only from a cost perspective,
but also on a verification perspective
that these resources that are going to participate
and have submitted in our peak
are in fact going to be able to be firm.
-: Yeah, so what?
I'm gonna put that.
What auditing and validations,
standard and methodology should be used to
affirm
obligation.
Lori: Yeah, something like this last one.
-: Yeah, okay does it work? -: Works for me.
-: Yeah, and Mr. Chairman,
I know we've passed over these,
but it applies to this one, same deal,
especially on ECRS and voltage support.
How should cost be applied?
If that's the Rubicon to be crossed on this,
then let's have stakeholders,
yeah and get that through.
-: Okay, is that,
where should cost be allocated for
ECRS voltage support and winter ancillary product?
Does that work? -: Yes.
-: And I would add one more question for the winter product,
and that is, how quickly can it be implemented?
I've been told by a lot of different stakeholders
to have something in place by next winter 2023,
but I wanna make sure that we get
a little more information on that.
Peter: Yes, we certainly wanna make sure it's ...
Lori: Done in a time efficient manner, not waiting.
We're not two, three winters out from getting it.
-: Yes, I agree.
I guess to your question, to your point earlier, Will,
for all of the things that are a cost-specific question,
but for all of these,
we know we've got a timeline for ECRS and FFS,
but time to implementation for voltage support
in winter, yes.
Right, everybody good so far?
-: Yes. -: All right, moving up.
We've got page four and five done.
Cautiously optimistic.
ERS, yes?
Lori: That was my favorite one.
-: Okay, here we go.
(they talk over each other)
-: Okay, so I think
we need to look at ECRS.
We need to look at the rules,
but I think we need to take some interim steps
for this winter. -: Okay.
-: And what I mean by that, is that,
based on my review of the rule,
ERCOT has a $50 million annual cost cap,
and they have four contract periods.
The contract period for the winter is coming up,
and that is for December, January, February.
ERCOT has issued an RFP for that contract period.
However, they have until November 8th
to modify their contract period.
And so we have some time to give ERCOT some direction
for this winter.
And what I mean by direction is that
I would like to direct ERCOT
to use more of that annual budget
for that winter contract period.
And we can work with them on coming up
with an appropriate amount,
because I wanna make sure that it's balanced
so that we're gonna increase that amount that's appropriate
for the winter contract period, potentially,
but I don't wanna set ourselves very short
for the summer
and the rest of the contract periods throughout the year.
So we can work with ERCOT in coming up with an amount,
to direct them to add more money from their annual budget
to that winter contract period.
And also, based on my review of the rule,
the rule says that the ERS product is intended
to be used in an EEA event.
I think the language is that is, doesn't say, "Must."
It doesn't say, "Shall."
From my perspective, I think we can direct ERCOT
to go ahead and deploy ERS before we enter EA1.
But if from a legal standpoint,
there are still some concerns,
I think staff has some procedural options
that we can exercise
to waive that rule requirement for this winter,
so we can add more load resources
to reduce demand on the system
in this upcoming winter season to maintain reliability.
Will: Let's get a question out there on the
illegal interpretation.
Peter: Yeah,
a clarifying question, you're talking about
a change to the existing contracts or
directing ERCOT to adjust the contract terms
of the contracts that will be applicable
for the winter season?
-: Adjust the contracts, take out EA event from the contract.
-: Okay, so we're not changing existing contracts.
We would be considering
what mechanisms, procedural mechanisms we can use
to direct ERCOT to change the upcoming contracts.
We're not messing with existing contracts.
-: So my understanding is that
we can direct 'em to add more money right now,
because the RFP, we've got the number of rate,
they can change the RFP.
That ERCOT can adjust the existing contracts
and Kenan, please,
if you wanna get up here and please give us your input,
that they could just go in there and adjust the contract,
and take out the EA bit.
-: Yeah, so everything I'm about to say
cannot go on with ERCOT public.
Everything I'm about to say is
applicable to the future contracts.
So, we have issued the RFP for
December, January, February, March,
but we can update the RFP.
We need to do that before November 8th.
Peter: Okay.
-: We believe,
I think there's some additional legal
hurdles to jump through,
but we believe we have that authority already to
adjust the dollar amounts in that contract.
I will just caveat that with,
we very often exhaust all the bids.
So initially we might not get any more,
but it does send a signal
for the program to grow going forward.
But I just wanna be cautious on that front,
that we may not get more megawatts
just because we increased the budget initially.
That does mean that we are taking dollars away
from future procurements.
Peter: Yeah, that's a concern we don't wanna ...
We need to buttress for winter,
but we don't wanna leave ourselves high and dry
for the spring and summer.
-: Which is why I believe
you should open up the ERS rule
as part of our list on the blueprint
and evaluate that program.
And while we're in there, we can adjust for what we do here.
-: What is procedurally,
what would be required to increase that
annual amount in the budget?
-: Procedurally, the total annual budget
is set by substantive rule,
so there would need to be a change in the substantive rule,
either eliminating the cap
or putting a new cap in place
or defining other parameters that the Commission-
-: Right, but we can open that rule up
and get it closed before, not November 8th,
but the next procurement period.
-: Or at least by the summer.
-: By the summer, yeah.
-: So, the RP will go up
late April, early May for the summer procurement.
-: That sounds right.
The new four procurements go four, two, four.
So, the summer one would be
in the April timeframe is when the RFP would go.
-: RFP would go out in March, March 1.
-: For the summer?
-: The RFP would.
-: Because it closes in May.
-: Well, when do you have,
up until what deadline can be?
I guess if it goes out in March,
do you still have, like you noted for the winter,
there's a grace period where you could still
make a change to the RFP?
-: Could we do that?
-: Yes, just like the beginning where they do do now,
we consider the RFP after March 1, yes.
-: Cool, we'll aim for March 1st, and we've got it
if we need a grace period ...
-: Let me just for the record,
he said that while we would have to issue the RFP March 1,
we could update the RFP
to reflect a higher budget later.
Peter: All right, so what do we need?
What's the ask specifically,
and then let's get comfort level around the table.
-: I think the ask is,
have ERCOT modify their RFP,
to add some extra dollars to see if we can
lure in some more of the load resources
for this upcoming winter, with the goal being
reducing demand on the system,
without any reserves it's reducing demand on the system
during the winter season to help us maintain reliability.
The second important piece to that is
having ERCOT work with their existing contracts.
I know there's some legal
review that needs to be done,
but based on my interpretation of the rule,
there's not a strict requirement to use it in EA1,
but even if the ultimate conclusion is that
ERCOT were not comfortable ...
Peter: So you're talking about the contracts
that have already been executed or in place now?
-: ... Probos is asking us to change the RFP,
to reflect two things:
one increased budget, and two,
earlier deployment prior to ...
-: EEA Commissions. -: EEA, right.
-: Yes. -: And that's the legal hurdle
that we've gotta pass, because of that rule.
-: Well there's a legal hurdle in that
if you believe the language restricts you to EA.
I'm not sure it's a tight restriction,
but even if you believe it is,
we have procedural mechanisms
to waive that requirement for the winter.
Connie, can you speak to D?
Connie: Yes, we do have a number of mechanisms
that we can bring before the Commission
regarding whether there was a strict
prohibition on releasing those
ERS megawatts before EA.
-: But even if your review says that
the ruling, which is a little bit more restricted
then I believe there are procedural avenues
to allow us to wave that rule requirement for the winter.
-: That's correct, the Commission
can waive its own rules with the costs.
-: Okay, so we've got a request to ERCOT
for budget, options to increase budget,
including, please include in that current budget
for the winter and what
the remaining funds under
the existing budget, so how high could we go?
And then the second request is,
what contract changes to future contract language
would be needed to move
deployment of ERS out of emergency conditions
and a recommendation on where on the PRC
spectrum you would deploy ERS.
-: Yeah, and I think that's a policy decision for us, right?
So we know that,
we're in a watch advisory
at 25 kW, 2,500, below 3000.
So it's a policy call there in where we wanna have,
at what point we would wanna have ERS deployment.
One thing to consider is, irrespective of that,
a lot of ERS does early deploy
and they will take actions to come off the system early.
But if we provide ERCOT with some flexibility,
we can get the other rest of the loads
to come out and help us reduce demand on the system
before we enter emergency conditions.
Peter: It's a policy choice,
but we're gonna have to make it before November 8th.
-: Yes.
-: You know where I am,
I'm happy to do 3000 for everything-
-: 3,000 MCL,
ERs deploy post 3000 or sub 3000 reserves.
-: Yeah, I mean there's a time gap
between the ORDC and the ERS,
but hopefully it'll all line up
to be in place by January, philosophically.
It makes a lot of sense to me that
wherever your MCL is,
just at that point, everything goes, right.
You need to be, if your MCL
is where you're hitting your high cap,
that's the end of the road.
You need to fire every bullet you've got at that point,
including ERS.
And after that, it's only after that
is when you start asking people to
turn off their own doing businesses.
Will: Yeah, I agree with the high level policy approach.
-: And does that mean in ERS,
all resources can play in that, and in all durations?
-: I'd say for right now, let's do the winter,
let's stick with whatever the existing framework is,
for the rule, just for the sake of expediency,
but for the substantive rule change,
let's get some feedback on that.
-: Yeah. -: Does that work?
-: Yeah, okay that's fine.
-: Yeah, I think that's a great approach.
I think as we open up the rulemaking,
we'll have to look at important issues
like the cost cap, program participants, deployment,
and we can explore all those long-term issues in that.
-: Yeah, and I will,
I'll go ahead and channel our industrial partners
in saying that the more we expect to use ERS
and the sooner we move it out that PRC spectrum,
the more expensive these megawatts are gonna get.
I'm comfortable with that,
but if we're paying for it,
we should expect to be able to use it.
All right.
Anything else on ERS?
Are you sure she didn't need anything to throw?
-: I'd say that
you're doing a heck of job as Chairman.
So where are we at on here?
All right. -: So I think we've got ...
-: RFP's gonna get modified.
-: Well, let's ask Kennan what he thinks.
-: Yeah, what do you think? (people laughing)
-: So RP is gonna get modified.
And there's two paths that we're looking down.
One is completely within our control,
and that is the budget.
However, there is still this outstanding question
of whether or not it's legal for us to
deploy earlier.
So we're gonna, I believe get further instruction,
either in the form that it is ...
Peter: PUC staff will provide
procedural
options to accommodate that change.
-: Because even if your legal department
is uncomfortable with the rule language,
there are avenues to waive our own requirement.
Will: And we're meeting next week.
-: Yes, well we'll review it
and discuss it with ERCOT's legal counsel
and bring to you a response next week.
Peter: All right, can you
bring
options?
Next meeting will be the 28th.
Can you all bring options
to each individual office before that?
-: Yeah.
Peter: The day or two before that,
so we can discuss at our next meeting.
-: Absolutely.
-: All right, where are we on the ERS?
So Kenan's got those two questions?
Connie's got the procedural options
that will be presented
to each of our offices individually,
so we can discuss
next open meeting.
So, let's call that the immediate action
for this winter on ERS. -: Yes, sir.
-: For the broader
ERS reform,
I feel confident at this point,
we were on the list of items to be considered.
What questions for stakeholders
that will be due November 1st,
not, if you can answer right, yeah.
-: Thank you. (people laughing)
-: But feel free to chime in,
to make your comment.
-: Mr. Chairman, you've got a good question on there.
One thing, I wonder if we could consider,
should the deployment of MCRS
in the context of a question, be the subject
of a question related to
MCL, okay.
Should ERS always be deployed after MCL?
I think the response is gonna be yes,
but where I'm going with that is,
should we consider having it adjusted,
the deployment of ERS,
based as a percentage of seasonal peak net load
forecast in the SARA?
Peter: So I'm hearing two questions.
-: Yes, sir.
-: When should it be deployed?
When should ERS be deployed and
what quantity of ERAs should be procured
seasonally or ...
Will: That's fine, keep it broad
in that way they come in.
-: You want more specific? -: No, sir.
But overall, what I'm wondering is,
should that be a moving target and not a fixed target?
You know what I'm saying?
Should it float?
Peter: What methodology should be used
to set quantity to be procured?
-: To set quantity and
period use.
-: And when it's deployed. -: Yes, sir.
-: Several questions. -: Yes.
Peter: All right, got that.
All right,
do you have a question on this duration?
-: Yeah, I was just ...
I think that the question was,
how do we incent longer duration,
what is the duration optimum here?
I mean, I think Will said it right, which is,
having this spectrum of the suite of tools,
having them fluid, as in the day,
where we're trying to get as many
tools in there early, so we avoid
the biggest event at the end.
This is the most important.
-: Question about resources,
what load resources qualify for ERS?
-: Yeah, I think that would be right
and if there's a duration requirement,
what's the optimum?
-: The duration of load, essentially
in load sharing, self-imposed load sharing.
-: Correct, would definitely have to be.
-: Okay, got it.
-: So my biggest questions, I think,
and they may be baked into some of these is first,
I think there's two ways of looking at it:
should we modify the annual cost cap or
should we procure ERS
on a seasonal basis, based on net peak load
or some other form that's more targeted
like Mr. McAdams was saying,
'cause right now we're at this cap, right.
Should we just continue to buy X amount of
load resources or should we modify how we procure them
into a more targeted,
seasonal approach, based on net peak load?
'Cause otherwise, we're just throwing out
a megawatt number without it being tied to-
Will: And you can ask that now, or ...
Peter: I think that's included.
Will: Well, I'm definitely gonna include that,
I have general orders ...
Peter: Yeah, but I think that's included
in the question we're asking, isn't it?
-: Right, it is, I just wanted to clarify it more.
Peter: The question
should have been wrote down, right?
-: Yeah, I just wanted to clarify
the way I was thinking about it.
I think deployment, program participation
are key in that.
And I think Commissioner McAdams' question about
when will it be deployed.
You're deploying it earlier outside of EA1,
but you wanna do it in concert with the ORDC
so that there's some kind of
reliability sort of synergy,
just reliability spectrum, right?
-: So yes, it should all sync up.
Is that?
-: What I wanted to clarify is what
Commissioner McAdams alluded to, and that is
a lot of these questions that
we have identified for ERS seem to be
fundamental design questions for ERS going forward.
And I wanted to clarify whether you want
those to appear on the upcoming round of comments,
or if you want to defer them to an ERS board meeting?
Peter: Let's get those questions out there now.
Will: Okay, and then we can just roll that again.
-: And it'll still be valid ... -: An ongoing process.
-: Does that work? -: It works for me.
-: Okay. -: All right.
-: Looking at the look on Connie's face,
staff's not gonna be required
to answer all these questions.
-: Absolutely not. -: They don't ride on anything.
All right, okay. -: We will
provide more specifics when we issue the question.
-: Okay.
-: The concepts and question list next week,
but in the spirit of
dramatically narrowing the scope
on all of this for all of us,
I think we'll primarily be asking for
very abbreviated stakeholder comments,
preferably in the form of an executive summary, a one pager.
And of course we can follow up on good ideas
and we'll have
more conversations like this, and we can
invite specific stakeholders
who have compelling ideas to come to this Commission.
-: Okay. -: All right, ERS.
Are we good? -: Yes.
-: Good, thank you.
Connie, hang on.
Sorry.
I suspect we're gonna need you in a minute.
All right, we are moving up the chart.
How about we dive in to everybody's favorite,
demand response?
-: So, I have a question.
Earlier, when you were talking about upgrading the system,
are you talking about Smart Meter Texas?
-: That's exactly what I've got here.
-: Okay.
-: So I wanna be clear that this is ...
-: Where are we on now?
-: Just demand response. -: Okay.
-: Does that work?
I wanna be clear, this is an upgrade to
centralized hardware and software.
As you pointed out,
we spent a ton of money putting distributed hardware
while we're out in the field to capture this data.
From my understanding, the bottleneck is
at the centralized
aggregation dissemination point.
What we've discussed this, and if you'll
explain the, I guess,
I've got a good sense of what we're solving for:
better telemetry, more granular load shed,
and the first part more frequent.
And it's just more frequent data about
our distributed grid, is I think the, like I said,
the key that unlocks
all sorts of capabilities for demand response
and enables the marketplace
to capture that demand response, to encourage it,
to innovate around it
rather than us trying to regulate it,
which I think is a much more productive exercise.
So, I know what we're solving for,
at least what I'm solving for.
I'll defer to Connie on
what kind of upgrades are required
to achieve that improvement in telemetry
and frequency of telemetry.
-: So, Smart Meter Texas
is a joint endeavor by and for TDUs.
And they have employed a single vendor to run that
centralized hub for Smart Meter Texas.
So,
the bottlenecks for the data
could in fact reside there and some probably do.
There's also
located at each individual TDSP,
their own meter management system
that could also be the source
of some of the limitations we see in the telemetry.
So I would imagine that upgrades would be required
in both spots.
And we have TDU folks here that could probably
speak to a greater detail if you'd like.
-: Okay. -: Sure,
Perhaps we could use you both,
you are welcome to come up and do this,
you don't have to.
-: I'm good. (Peter laughs)
(they all talk at once)
-: For the record, my name is Liz Jones.
I'm employed by Oncor.
There are a lot of things that could be done differently
with the AMS system and with the Smart Meter Texas.
I would encourage you all,
as you think about what things you want to envision,
that you make time and space for
a cost benefit analysis on those changes.
There is a frequent misconception
from my perspective on
whether SMT and AMS is necessary for demand response.
When this was originally started
in 2008, 2009, 2010, 2011 timeframe,
I think that there was a firm belief
that Zigbee, which is a particular kind of protocol,
would be the necessary gateway
to enable demand response in the mass markets.
And that that would have to work hand in hand
with the meter data.
It is Oncor's perspective,
and it is evidence that we presented in the last
SMT case that
the meter interaction is not necessary
for demand response in mass markets.
And that in fact, Zigbee has not been
the golden ticket that we all thought it would be
10 years ago, but rather
internet-based applications
are much more effective and much faster.
Now, the meter data
is the trust and verify piece of that
and so it can be available,
but I don't think, and I have not seen
my work on AMS and SMT;
that has to be the exclusive mechanism by which this occurs.
And so, we are supportive of doing what you want
and we could make necessary upgrades
to enable the kind of functionality
that I think you all are envisioning.
It is not clear to me that that is
the most cost effective way
of getting where you wanna be.
-: Thank you very much.
As I mentioned at the top of the meeting,
we heard this in our demand response workshop, that
there's a lot of demand response happening now.
Just because ERCOT can't see it,
doesn't mean it's not there.
Price responded part of the internet applications,
smart thermostats, et cetera, is ...
We keep hearing this is,
do we need to do anything.
I'm afraid to ask, but if it's already happening
and the capabilities are there through other mechanisms,
the internet applications, smart thermostats, et cetera,
or REP developed software,
are we overthinking this?
-: So, I'm not the best person to answer that, right?
Because we do not, in fact,
administer any demand response programs.
Through energy efficiency, we write checks,
but that's not the same thing.
I think it's perfectly reasonable to ask
competitive service providers and retailers
and qualified scheduling entities,
who are also a big piece of this puzzle,
what they think.
But, at this point ...
-: We did that. -: Okay.
Peter: In July, or whatever it was.
-: Right, and you know you've gotten the right answers.
I'm gonna tell you that as an initial gating item,
I don't think it is the AMI SMT technology
that is impeding it.
I think that there are product development issues
around demand response and mass market demand response
that haven't been fleshed out,
and that's a different problem.
Peter: Okay.
-: On this, Mr. Chairman,
and it sounds like moving forward,
this is definitely a high value target, demand response,
as a component of redesign, you've asked good questions.
-: I think so, but I keep hearing
that it's already happening.
-: I know, but why not just keep it on list?
Continue moving forward with the data.
-: Sure.
-: You've got your questions.
-: Yeah, I think we've gotta refine,
but we can refine our questions saying,
what technical specifications
are needed or improvements to
what technical specifications
should we be solving for
to enhance demand response?
What hardware,
centralized hardware and software upgrades,
because I don't wanna play the game of,
we need ... -: Correct.
-: 30 million new meters in Texas, we already did that.
What centralized hardware and software
changes are needed to enhance demand response?
-: And depending on the answer you get
to those two questions,
the TDUs are in a better position to come forward
and talk to you about
how we would accomplish the changes
that others have recommended.
Peter: Fair enough.
-: I think that's great.
I'm with you, Chairman Lake,
I know there's a lot of capability out there
with respect to demand response,
especially with all this technological revolution,
with smart meters and apps and everything out there.
And so, when I start thinking about demand response
and how we can better
capture those opportunities
and use them for reliability purposes
and at least have some visibility
so that ERCOT can take them into consideration,
the demand response penetration into consideration
for reliability purposes,
it starts getting great for me
because I hear these great ideas
and we heard 'em all at the work session,
but what can we as a Commission do to
help this move along?
Is it ERCOT technical specifications,
rule changes?
Peter: I think there's some merit to
the notion that the best thing we can do
is stay out of the way.
-: Perhaps. -: Yeah.
Well, and on that Mr. Chairman,
and I think it might fit.
Didn't make the original list, but
node pricing for load resources versus the zonal pricing.
Again, that plays into your telemetry argument,
getting that right command and control signal, is that ...
-: I think that's more about matching up the prices,
demand response, participant or resources received
with the rest of the market.
-: Yes, sir.
And sending the right signal for them to
turn up the thermostat or whatever, real time.
-: And there's a little bit of a thorny issue there
because when
this Commission made the initial determination
of how to transition to the nodal market,
one of the pieces was that
retail pricing would occur zonally,
and that was intended to be
a protection for the retail market
and also for the retail customers.
-: To cushion the blow of node, right?
-: Yes, and so the last time we talked about this
and it has been a recurring theme
in some of the ERCOT activities,
there was some difficulty in understanding
or accomplishing something where
a customer is being charged on a zonal basis,
but is being paid. -: Right.
-: MDR on an LMP basis.
And so that's not an unsolvable problem,
but it is a problem.
-: And it's more of,
again, as we heard from the workshop,
that's more of a long-term,
they gotta do a system.
-: Yeah, is it worth having a question in there?
-: Yes, sir.
-: Pros and cons,
please address the pros and cons of switching from
zone pricing to LNP pricing. -: Yes, sir.
-: And I wonder if this is a proper fit,
'cause I'm sure we've all heard
through various stakeholder conversations about
how we can utilize customer aggregations
to turn them into virtual power plants.
That's, I think, a form of kind of new thinking
of how we can take all this demand response
and use it in a cumulative basis
to reduce demand on the system.
-: And ERCOT already has rules about aggregation.
It might be constructive to have an opportunity,
or create an opportunity for a workshop
for ERCOT to discuss with interested parties,
what the existing rules are.
And maybe at the conclusion of that,
there's an opportunity to discuss potential change.
-: You mean a ERCOT stakeholder workshop?
-: Yes. -: Yep, okay.
-: And then maybe come back to us
with some kind of a roadmap for us to consider
on how we could help.
-: It gives a menu of options, if nothing else.
Liz: And I'm sensitive, as you all are,
to making work for ERCOT.
I just think ERCOT,
the expertise regarding current roles
resides at ERCOT and it could be best communicated there.
-: Fair enough.
We can address that offline with ERCOT, I think.
But if everybody's on board with ERCOT,
asking them to
have a workshop to investigate specific ...
I mean, we do want the questions on this list
about technical specifications,
specific hardware, software upgrades needed,
pros and cons of
general to LNP pricing for demand response.
And then we can also separately ask ERCOT to
hold a workshop with the stakeholders on
what works and doesn't work
with the existing rules of DPPs
or aggregated resources,
does that work?
-: Great. -: Sounds great.
Thank you, Liz.
All right, so I think we've got
the zone and LND addressed,
we've got hardware, software,
telemetry issues addressed.
Last one is
performance standard for energy efficiency program.
I'm coming at this from a pretty high level.
I know we spent a lot of money on this,
as Liz said, they write checks.
And I'm not entirely sure if
the rate payers are getting
the highest bang for your buck on this.
We know that we have a very concentrated
avenues to ... In Texas energy use,
it's, I guess, the top three in summer:
air conditioning, air conditioning,
air conditioning, in winter it's heating.
So I really just wanna open to,
and this is why I ask the question,
what is the highest performance standard we can set
to get the highest value
for our rate payer dollar?
I know a lot of the participants in those programs
almost always hit their performance bonuses,
which makes me think there's room for improvement.
-: They're not small performance bonuses.
-: No, they're not. -: Oh.
-: So, on that one, I'll go and open up first.
-: Right, go for it.
-: I'll try to set the table.
I believe there should be,
as a part of the bones of a
greater market reform effort,
EECRF reform to the degree that
we also have to recognize what we're dealing with.
We are dealing with
very specific constraints in statute,
and we're also dealing with
very specific, and a very large substantive rule
that goes a lot of different directions.
I believe when we're talking about
enhancements to this market
and any new revenues, and Mr. Chairman,
you may go and say, "Hey, let's look at it all."
But I'd say in terms of the near-term,
when we consider new revenues or augmentation to
what we're already paying out to the market,
dollar we're talking about more dollars,
then there should be again,
specific performance standards outside of the existing rule.
This should be considered;
again, who participates in it.
And there's something, there's already
a filing out there that may become a contested case
so I don't think I can talk about that here,
in terms of just the application of those programs
on a seasonal basis,
which lines up with earlier conversations we had
from our workshops.
But my point is, how the retailers and the
transmission distribution service providers interact.
And again, how retailers, with their aggregated DR
could actually perform
on a dollar for dollar basis
with any new monies coming in.
Again, in the command and control construct,
managed by the TDSBs,
that we can actually account for,
on a more granular basis within the CDR.
Peter: Sure, so what's the question.
How are we gonna capture that in a question?
-: So.
Lori: We need a question.
-: I'm hoping on avoiding some hate mail
with the way I couch that.
-: There's no avoiding the hate mail,
if we're doing our jobs right.
-: I know, I was trying to manage it.
We're getting toward Christmas.
-: So I definitely wanna hear
from the stakeholders and ERCOT,
what is the necessary command and control.
-: And you have that, I believe, sort of.
-: Well, I think it covers ...
But what is the necessary command and control
to utilize demand, resources,
demand response resources,
to ensure reliability,
to ensure an enhanced reliability?
-: Correct. -: Right.
Just because you've got
a Tesla plugged in and ORDC kicks in,
and you decide to start making some money on it,
that doesn't necessarily help
ERCOT's ability to
enhance reliability 24 hours in advance,
48 hours in advance.
-: How could additional resources
in EECRF
be applied
and broadened to include
greater participation by the competitive market
within the managed programs
of the regulated utilities?
Is that broad enough for it,
that would elicit some response?
-: I think that's right.
One of my questions, and I think,
as you looked under the hood,
is whether we should allocate some of the existing funds
underneath or the TDs have
from the spectrum of programs
under the energy efficiency umbrella.
Should we allocate funds from
some programs where we're not getting that much
bang for our buck
to REP demand response type programs,
delivered from a broad spectrum of stakeholders
and I thought that that might be a more efficient use
of that energy efficiency money.
And then also looking at program participation
and I think right now it's more residential,
it's not commercial,
and it's largely geared towards the summer.
I think there is, in SP3, there's an ability for
TDUs to offer
to have a low membered program
for the winter, for non-residential,
which I won't get into
because that's part of the contested case,
that's before the Commission.
But I guess,
I think your overall question is great:
accountability performance standards,
where should those dollars be going?
Where do we get
a bigger bang for our buck, who can participate?
And should we be modifying these programs
to better target seasons, especially summer and winter?
Peter: Can we do that
in the second round of these questions
after we get responses on the biggest bang for the buck?
-: Sure.
Really the way I envisioned this is to add this rule,
2521, I believe, to the blueprint.
And so we can open up the rule
as part of our ...
-: As we get there, yeah. -: Yeah, as we get there.
-: Okay.
-: And I agree, and it's a big rule, Mr,
and you'd spend years inside that.
-: All right, let's start
with the bang for the buck questions,
and then after November 1st, let's see what we've got.
And then we can start asking the questions
about how we allocate, does that work?
I know our stenographer needs a break.
-: Did we ask what the amount should be?
I mean, I think-
-: That would be valuable. -: That's a good ...
Well, I mean,
is that something we wanna ask for,
or we just need to set because ...
I've got a good idea that
certain segments would think
whatever it is, bigger is better.
Well, I think there's
some analysis that could go into that.
-: Fair enough.
-: That we ought to determine what that amount is.
I think, where it hadn't been
increased in many, many years
and that we ought to at least get some perspective
on what a viable amount would be.
-: Fair enough, can we add that to the ...
Connie: And when we say amount,
are we talking about energy efficiency goals,
dollar amount or ducking megawatt hours or in dollars?
-: What should the method be, and what quantity?
-: Yeah, I mean, I was thinking dollars,
but obviously we want both sides of the equation to work.
-: We can see
if we can, yeah, aggregate all of it,
see where that leads us.
-: And Connie, am I right that
some of those dollars are used
for demand response as well in the TDE programs?
-: I believe there are load management programs.
-: So, the other question that I thought
I had asked this a few months ago was,
if we're trying to create more robust
demand response programs within the market,
can these dollars be dedicated
to energy efficiency programs?
And I'd like to know what people think.
-: I think the market's already solving that problem.
-: The demand response program,
then use all these dollars for
whatever that larger number would be for energy efficiency.
-: And Chairman, I'm not sure
if you'd like to just lay out
for some of our online viewers and the general public,
the distinction between demand response
and energy efficiency,
is that something you'd like to speak to,
Commissioner McAdams?
-: Well, the way I'd use energy efficiency is
megawatts that we consider saved,
that again, we are taking off the system,
but again, we're paying for that.
And there is a public interest finding
in the rule and the statute
that it is designed to assist low income consumers,
enhance their energy efficiency in their home
and let them participate in these programs.
Again, the cost of those programs are
socialized throughout the broader system.
And we approve those rates every year
where that socialized cost is spread.
What we're talking about with demand response ...
Jimmy: And one thing I might add on that is,
when you make those energy efficiency upgrades,
they stay in place. -: That's right.
Jimmy: So, these are not a daily modification.
Those are things that happen
in spades, which forms the problem.
-: For the folks watching at home,
in practice, that's paying for someone to
get a new air conditioner that uses
fewer megawatts for the same cooling ability,
that's a 15 year old. -: That's right.
-: 15 year old air conditioner.
Connie: Exactly, so think measures that will,
on a very long-term if not permanently
decrease the amount of energy use in that location.
-: That's right.
So again, the nuance of demand response is
this is a controllable energy resource.
Again, energy efficiency is always there.
It's steady state, it's megawatts taken off the system,
but demand response could again be
a command and control asset of the system.
-: In practice, it's a consumer of power
deciding they'd rather
at a certain price point,
sell their power back into the grid
either by consuming less,
or by reverting to their own backup generation
to continue whatever operations they ...
-: And just for the greater public.
-: That happens constantly, all the time.
-: Yeah, and to put it in context right now,
we account for somewhere in the neighborhood
and it's on our cost chart
of a TDS load management megawatt hours,
300 megawatts at peak, that's there
and it's accounted for at EEA2 conditions.
-: So that's the other issue we need to explore,
is when those load management programs are at fault.
-: Well, that's part of that case now, it's getting ...
-: Okay, we don't wanna open that right now.
-: Well, in the rule.
-: Yeah, when we get to that point.
-: If we add it to the blueprint and open a rule,
I think that something we can look at.
-: Okay, absolutely.
Anything else on demand response?
I know our stenographer needs a break
and I wouldn't mind one either.
Have we got a list of questions?
-: Yeah, I think so.
-: Good, all right.
Let's take a 15 minute break and reconvene at 11:55.
-: Yes, sir.
-: All rise.
(indistinct chattering)
For those
brave enough to
hang in there as we continue through this day, thank you.
I hope you're in health.
We've got a good ... I think we made
a lot of progress so far.
We've got two key items left.
Ambitiously, I'm gonna say,
let's try to get this knocked out by
one o'clock, 1:15ish?
Let's tackle ORDC.
I think we've all discussed that,
the high level points.
I think everybody's generally aligned on that.
I think the big, what questions?
I mean, I think we know that the top questions is,
we wanna see some scenario analysis
and I'd like to be able to give
very specific numbers to our consultant groups.
You know my numbers
and if possible, I think it was,
we'll have another crack at this,
but it may just be the most straightforward thing
to just have each of us submit one scenario
we'd like analyzed and we'll have four scenarios
that they can bring back to us
and we can go from there.
You saw my numbers
in the memo, I briefly give you the logic.
HCAP and VOLL,
the VOLL concept
is extraordinarily academic in assuming that
the value of a margin electron
is the same for every person, every business,
every moment in time,
but we've got to pick something.
I think 4,500 keeps us
a good way away from the
extraordinarily punitive $9,000.
But it's still, as Miss Cobos pointed out,
a substantial number
that will incentivize demand response
as we move up that curve.
The 3000 megawatt MCL, my logic there is right now
we enter emergency conditions at, I think 2,000?
-: 2,000, 2,300. -: 2,300.
My logic there is, let's ...
We don't like, we don't wanna do emergencies.
We wanna get away from this crisis-based business model,
so let's build in one major, a big unit trip.
So at 3,000 we can still have one unit trip,
one of our biggest units trip, machinery breaks,
and we're still, we're still okay.
We've still got a cushion.
Call it N minus one, minus one, if you will.
And then, no change to the standard deviation.
I'll just refer to what I've said earlier
about over-engineering.
We're more likely to be wrong
on the number of hours used per year
than we are on the standard deviation.
And most importantly, I think,
don't quote me on this,
but the last analysis I saw was under this framework
with Kenan, we were looking at it.
You don't need to come up, but I think,
under this curve
at 6,500,
where we currently start deploying AS,
this would result in a $50 adder.
-: It's around the $50. -: Yeah, so that's yeah,
roughly 50, so it's 6,500 where
we are currently operating
on our new framework, conservative framework.
That's where we get worried,
that's where we, as a marketer, are getting worried
and we start deploying AS.
If you've got $50 on top of the
energy price, the realtime price,
you're very quickly gonna be moving
into the $100, $200, $300 range.
We know we get demand response from
some of the controllable load, like
crypto mining and
data centers at $200 unless
there's just some extraordinary degrade problem.
$200, $300, every unit should be on and moving,
and it's a demand response question from there.
So, I'll stop there.
That's the scenario I would submit.
-: All right.
One last component, Mr. Chair, for discussion is
the backcast scenario for Brattle.
Again, those years or scenarios
where they'll do the overlay to determine the cost.
I would throw it out,
2019 is a big year for ERCOT,
because again, we were at 9,000,
the economy was roaring at that time,
low growth was still in its normal trajectory,
it was before COVID distortions occurred.
ORDC did engage with those weather patterns.
So I would submit that,
just in terms of a near term backcast scenario,
we view 2019 is a significant year
just to give Brattle guidance
on what to measure this against,
with what do you think of this?
-: Would it be conditions? -: Yes, sir.
-: Sure. -: Yeah,
'cause it's just how you apply
the numbers that we're gonna talk about.
Peter: Yep, yeah, good, good point.
Why don't we ask them ...
-: If they have any other years, that they would ...
-: This is a base case. -: Yeah.
Peter: Worst, call that extreme heat summer case,
and you can almost call this year,
the summer of best case, right?
And it's one of the ... -: Went down pretty well, yeah.
-: Things I love about Arvin Wood,
the financial model or anything else,
zero scenarios, two years ago, any predictive model had
a very mild 2021 summer, it was $6 natural gas.
I wish I had $6 gas in my model.
Yes, we'll ask for a base case, worst case, best case.
Do you have numbers, that you'd submit?
-: So at high range,
I would like high cap considered at six.
Given the panacea comments we had
from that again, that memo that we filed,
that was TIAC's comment threshold.
Because again, we're trying to find that happy medium,
where we actually see price responsive behavior
from our industrial load, starting to turn off.
So depending on the price
for the value of a semiconductor,
which is way high right now,
'cause nobody can get semiconductors.
-: Or Bitcoin. -: Calculate that,
or Bitcoin.
So, $6,000 high cap, one of those scenarios.
And then,
I agree with you, building in a margin of error
to where on MCL?
3,000, definitely okay with that being a mark.
2,750 is what I would advocate that we have
baked in there because again,
it was a historical line
that they were targeting in the past.
-: For NCL? -: Yes, sir.
And that would also account for D rates,
that would also be ahead, that would be within
already a control room advisory status
under existing conditions,
but ahead of control room watch status.
And then on the high end for MCL, if we wanna say,
I don't know, subject to opinion on this,
because I think 3,000 needs to be
that intermediate step: 3,100 or 3,050.
I realize, I know that Carrie Bivins
is not enjoying this conversation right now
because we're arbitrarily
pulling numbers out of the air,
but just to show a spectrum
so that we can see cost impacts.
3,100 or 3,050?
Peter: I can't say (mumbles) ...
If you're gonna have a higher, then go to higher.
-: Okay 3,100.
Lori: Okay, so y'all are covering
almost all the spectrums I can think of, but ...
(they all laugh)
But let's see if I can sneak one in here,
but I'll let you finish, as you probably have ...
-: Well yeah, and so just
wanna make sure everybody sees a demarcation
control room advisory exists for 3,000
megawatts of reserves down to 2,500
under current operating protocols within ERCOT.
Sub 2,500, that's in a control room watch status.
So as you think of adjusting that MCL,
and we're also considering tying ERS deployment in that,
that's what you're gonna start seeing activate
within ERCOT's systems.
So, I'll stop there.
-: Okay, so I think you've covered some spectrums.
You're trying to avoid the watch and the advisory
and you have to be above 3,000.
So just for a matter of just seeing
where that puts us, I think.
I mean, I don't wanna say 3,200.
I mean, you're trying to avoid getting below 3,000,
I'd say 3,200, right? -: Okay.
-: And so 3,200,
3,000
and I would say probably in my opinion, 2,800,
'cause that's the other MCL
that we got a lot in comments rather than 2,750.
-: I'll settle on 2,800. -: On your load?
-: Yes, sir.
-: And then I would also,
because I mentioned this earlier is so,
Curtis Washington, (indistinct) as well,
that the IMM one, so that would be 1,430,
but understanding that there's a lot of interaction
where that's not actually the main sales trigger.
Certainly, that's 14 ...
1,430 as MCL, so you have this spectrum.
-: Available 1,430 is MCL.
-: Right, but the way the ORDC interacts
with the VOLL being a lot higher.
-: Certainly. -: It's actually not.
-: That's why Kenan was like.
If I have to go explain this to the government,
they're coming around to the legislature
on how we work this, and it's very tough to sell.
-: Which one? -: I'm talking about
the IMM's proposal right now.
I mean, I'm sure there's merit.
I'm just saying that,
I don't even understand this thing.
-: Okay. (Lori laughs)
-: But get a transcript. -: Well.
(they all laugh)
(Lori's voice is drowned by laughter)
-: Okay, so ...
Peter: I know there's some merit
to sticking to the basics for twice a week,
and it's very easy to over-engineer this stuff.
-: Yeah. -: All right.
I was just putting it in there,
because it's from a third party neutral
party that I've heard
both the generation side and the consumer cost side.
-: Good data point to have. -: Good data point to have.
-: Sure.
-: Not because I'm 100% behind it.
I need to see spectrums and figure out where I land.
So I think as a matter of due diligence,
because it is a third party, you're providing them
a proposal that
I guess would maybe provide the incentive,
in their opinion, for dispatchable generation
and (indistinct) solve the generation
and starting the flow of customers
that they would be comfortable with it.
I would like to at least see what it does.
-: Yes, and along those lines,
will you add to the request for this analysis
to not only show the
additional revenue contributed to the marketplace,
which is, I think what we're all solving for here,
under the base case, best case, worst case,
can weather condition scenarios,
but also have the analysis show
the ORDC at or at 6,500 megawatts,
what will that be across all spectrums?
Because what I'm solving for in this
is a market base rocking,
getting units on sooner rather than later
so these generators
can operate their businesses at a reasonable profit
without the grid having to get to the brink,
get away from that crisis-based business model.
Lori: So in terms of price caps,
I think you've covered the spectrum.
I think let's look at 6,000, let's look at 4,500.
And I think for the sake of
following through on the IMM's proposal,
you have to decouple it, so you'd have,
I believe a 20,000 VOLL? -: 20,000 VOLL.
-: And a 5,000 price cap.
-: Okay, that's a good scenario, that's all right.
Lori: And in terms of standard deviations,
I think we don't include one.
And I don't think any of us
have looked at any of that.
-: No, it's all right,
just stick with the current.
Lori: Stick with the current,
see what we get. -: Can you do one?
-: I think that we covered a lot of scenarios
and I wanna see what the data looks like
when we run the scenario,
so I don't need to add another one
and we'll see where this analysis goes.
-: All righty.
Staff got everything they need?
-: I could repeat back from the Chairman's memo.
HCAP and VOLL at 4,500 and MCL at 3,000.
Commissioner McAdams,
you had VOLL at 6,000. -: Correct.
-: And HCAP at 4,500.
-: So, still under the scenario of VOLL and HCAP
at same level, so 6,000.
Admin: And MCL,
2,800
and 3,100. -: That's correct.
-: 3,200. -: Oh yeah.
(they speak over each other)
Admin: Okay, and then
the IMM scenario. -: Mm-hmm.
-: Yes.
-: Y'all merged. -: Correct.
Admin: Thank you.
Peter: All right, good. -: Yes.
-: Yes, and we need to get those back before November 4th.
Peter: Yeah, November 1st.
-: Yes, exactly, as soon as possible.
Peter: But sooner would be preferable.
-: Exactly. -: All right.
I think the other questions,
ORAC is pretty straightforward this morning?
-: Does the current ...
I'll throw one out there
that was litigated in the past.
Does the current curve form
satisfy the current market needs?
Meaning, that they consolidated the curves in the past,
should it be opened back up
to more than ...
Peter: If you want it on the question list,
we can put on the question list.
-: All right, put it on the question list.
-: So evaluate whether or not
we'd go from a blended curve
to seasonal curves. -: That's the question.
-: All right.
One item left on my list.
I laid up a lot of thoughts on
at the beginning of this meeting,
the only other thing I'll add is that
much like I'm trying to think of the ORDC
as the way to bring, it is a market-based mechanism
to bring units on when we're in scarcity events
or there's a threat of a scarcity event.
I think we can do better than
requiring generators to build their entire businesses
and billion dollar investments on
trying to guess how many hours a year
they're gonna be in the scarcity event.
I spoke about the forward price formation, et cetera
before, I won't belabor that point,
but I'd like in a perfect world,
I know we're far from a perfect world,
is power generators should build their business
on the forward obligation and those agreements
and get the ORDC bonus for being reliable
when we really, really need 'em.
At that point and so I'll stop there
with the first question we need to ask is,
do we wanna include LSE obligation
on the list of concepts to ask questions about?
I think we absolutely have to consider
this and for the reason I stated earlier, I think
fear is not a reason to not dig into a valid concept.
And then, if we're gonna have it on the list,
what questions we wanna ask,
I'll open it up.
-: I would just like to clarify that,
this is where I'm coming from,
it's not coming from Peter. (laughs)
Well, I won't get into that,
but I think yeah, let's ask questions.
I mean, if you want it evaluated, we can ask questions,
but at the same token ...
So, it sounds like a lot of
the rest of the proposals that were submitted
or are just not being considered,
for a variety of reasons. -: Yeah.
-: For a variety of reasons.
But,
what I don't want to happen is,
because we have one left on the table
that that's the only one we're gonna (indistinct).
What I would like to send
a message to the stakeholder community is,
you've probably heard there's concern with your proposal.
It's too limited, it's holding out resources.
There's different criticisms you've heard
from your peers in the stakeholder community,
from the Commission.
We have two avenues, right now, I think,
and then one of them, it seems
that would involve, I'm not saying yes or no,
I'm just saying one of them seems to involve
a central procurement of resources, right.
That's kind of the ...
Peter: When you say central procurement,
that's the ERCOT Inc. procuring resources.
-: So those are the proposals that we've gotten, right.
They're also a central procurement.
And some of them involve
going through the day ahead market,
which would be significantly delayed by the EMS,
which is not helpful.
And some of them involve procuring resources
like we do today for ERS,
but for generation sources, so there's that side.
And then we have the LSE obligation
imposes an obligation on the LSEs
to go and meet that obligation in the lateral market.
Peter: (indistinct) says,
requiring them to be fully hedged.
-: So,
is there something out there
that you haven't thought about,
hearing this conversation
that you can coalesce around and bring us
that will address the concerns
that have been raised,
that helps us achieve this foundation level
of reliability without having to
significantly change our market
to get there.
So, if you're hearing me, please, please,
please maybe coalesce and think
if there was anything you
might've thought about blending together
and coming up with something,
because I don't wanna just go down a path
with one option because the other ones didn't work.
Peter: Sure.
-: We need to leave the door open.
-: In that spirit,
I would propose adding a question to this list.
What would a fleet-wide generator
firming standard look like?
And that can be as simple as saying,
all generators in ERCOT must have
60% of their nameplate capacity firmed up through
either onsite, through standard operations
or through storage or through
some sort of offsetting agreement with
a dispatchable resource.
I don't know, but in the spirit of saying,
"Hey, if this LSE obligation doesn't work out,
we're thinking about a backup plan."
So we can get some feedback on that.
I'd be interested to see that.
-: And whatever
new approach is provided,
ultimately there one is that is open to
resources that would be available immediately
and that existing double drive investment
and existing generation and new generation
and demand response,
that will not be intrusive in the market,
that at least comes in at the price cap.
Some kind of concept that addresses
the issues that have been raised
throughout all our conversations
and even today. -: Sure.
-: That's what I would like to see
is some other proposal out there.
I fear that,
well, I shouldn't say fear
but I wouldn't say I don't fear, but (laughs)
at some point our existing generation
has to make some money.
There were many years without ...
Peter: To be fair,
all of our major generators
post substantial annual profits
operating income in their annual reports,
the public innings we can see.
-: Okay, so ...
Peter: And from their Texas market.
-: I'm just saying over the spectrum of the
20-30 year asset life of these generation plants,
there have been some dry years
based on all the information historically we've gotten
in the past now.
And we've gotta make sure
that we're sending a signal
to keep our existing generation fleet
on the system, because we need 'em
and the generators in order to go out there
and be able to finance these big, expensive assets
that'll be around for 20 to 30 years
are going to need to have a price signal,
and they're gonna need to make some money, right.
So I don't wanna just
move off proposals on the table,
because they might make money.
They have to make money to be in this business.
So anyway, I'm gonna end it with just,
there is some other concept out there
that could address our concerns.
Please come forward,
we would love to hear about it.
Peter: Okay, got that, the staff?
-: Yes. -: All right.
-: From Monday, Mr. Chairman,
like your question number one, how do we ensure ...
Okay, back to my original statement and just reaffirm,
I believe we need to examine a firming requirement.
And the proposal as constructed at hand now
is a LSE obligation,
but essentially it's a firming requirement
on load serving instincts.
And in order to address future needs,
we need to have analysis conducted,
so this is an opportunity.
I believe we should move forward and analyze this.
So, in that spirit, with your questions,
how do we ensure the continued viability
of the competitive market?
Absolutely essential.
Peter: Well, that's number one.
-: I can't answer that, and I'm out.
How do we prevent market manipulation
by affiliated gentailers
at the expense of independent retailers?
Again, speaking to the competitive health
of the energy only market design,
like how do we ensure demand response resources
can participate fully at all points in time?
Absolutely critical in my view,
so everybody hears that.
If there is so much a semblance
of pulling up a ladder on a independent retailer
being able to innovate their way
into a firming construct, to where they have
DR or DG, that's a problem
and we have to address that on the front end.
What is the appropriate accreditation level
for each resource?
Again, speaking to that issue,
what is the appropriate segment of time
for each obligation?
Months, weeks, 24 hour operating day,
12 hour segments, or hourly?
Again, speaking to the liquidity or capital requirements
for new market entrants,
and that's a crucial question,
because again, if you're a small fish retailer
and you wanna get in,
that's gonna be a barrier to entry.
And again, the health of our market
has always been the doors wide open,
so we have a competitively healthy market.
Well, again the non-gentailer segment has shrunk over time
so we're watching that carefully,
but it's crucial in our consideration.
So in that vein,
another technical question,
what mechanism will ensure those receiving revenue streams
for the reliability services perform adequately?
Again, the meaningful penalties must be in place,
so how do we address that
within the proposal?
And how should we address that?
And how will the reliability needs of the system
be determined and how will objective standards
around the value of the reliability
providing assets be set on an ongoing basis?
And that gets to the heart of it.
What problem are we attempting to solve
for a 1 in 10 standard?
I mean, that's always been
the devil in the detail on this argument.
-: Can I drop a footnote on that?
-: Go ahead.
-: I think as part of this evaluation,
we need to have
Brattle and Strope and ERCOT develop
options on reliability standards or targets
and bring them to us,
so that we can at least have an idea
of what we can put our pin on,
and it doesn't have to be
the 1 in 10 reliability standard.
We could look at a more granular, seasonal standard.
-: That's a good idea.
-: Ones that are focused on dispatchable configuration.
So, I think we need to have them
put a study together
that strictly by options for our evaluation.
-: Can we add a menu
of reliability standards to the list.
I'd like to see the top three
global versions of reliability standards.
Does that work?
Will: Yeah, because the Europeans
are having to face this right now.
It'd be interesting to see how these things are tweaked.
-: Yeah, I mean
the Europeans, the Chinese are in a massive,
UK, France,
a massive energy crisis because of the same,
the penetration of intermittence,
the lack of new dispatchable.
This is not a unique problem,
but we hopefully will be,
we need to be ahead of the curve on this.
-: So just to make sure that we have enough information,
because I think we might find
that there's a lot of 1 in 10 out there,
and I wanna kind of get away from that
and think outside the box.
So let's look at
maybe a standard that's based on
some kind of dispatchable generation foundation,
some kind of option there.
Peter: How about this?
We need three options for reliability standards
from local examples or proposals.
None of the three can be 1 in 10 or one in anything.
Okay. -: Something there.
-: Maybe?
-: That's gonna narrow the field.
-: Well, the seasonality. -: Well, yeah.
I mean, we know what that looks like.
We don't need somebody to tell us
what that looks like.
All right.
-: Okay, as we move forward again, near-term
and this is such a broad concept.
It has far reaching consequences
if it grows out of the crib.
What assurances from the public utility Commission
need to be made to help stabilize
both retail and wholesale markets
in the event of a LSE obligation being imposed?
Peter: What do you mean by stabilized?
-: Again, if say
liquidity dries up?
What do those independents,
non-affiliated, non-gentailers need to hear
that assures them,
that they have a place in this market
under this new construct,
a covenant between the state and that
non-aligned, non-affiliated segment of the market.
-: Okay. -: Put it to bed.
-: What?
-: You can go ahead if you want to.
-: Yeah, I have a couple thoughts
and one of them is on questions
for the LSE obligation, that would be.
So what is a rational and realistic timeline
for implementation at the PUC as well as
every component of that at ERCOT?
-: Yes,
can we save that for round two,
until we get more specifics on what we ...
'cause it changes dramatically, right.
-: I don't know, does it?
I guess it does.
-: So, if we're gonna have a centralized
clearing exchange that needs to be built out
where only these credits can be traded through that,
that's very different than saying
churches are gonna do an audit mechanism
on a bulletin board.
-: That is very true.
-: Well, that's a good point, so let's go for this.
So let me ask you this in dovetail
to your idea, Commissioner.
So in SPP, this came up in prelude to a
regional state committee meeting.
SPP, does it, does this,
they manage the centralized clearing house in-house,
it's incredibly complicated.
Their staff takes no ...
I mean, it makes no bones about it.
And then they outsource different advice
capabilities to a consultant, so
is that appropriate on this front end to ask,
is this the state's job to administer this thing?
'Cause that's a big question for me as a ...
You tell me the answer.
Peter: I mean, I'd put that in the same bucket
like round two. -: Round two.
-: Because if we decide we need
a centrally clear must offer in,
you can only trade these credits
in a place where everybody gets the same chance to bid
and everybody can see the prices that are traded,
that's a different implementation
than a bulletin board audit system.
-: Okay.
-: But if we get to that point,
depending on where we're in, I'm 100% comfortable
asking that question, but
completely outsourcing the development of that
to the market industry.
Yeah, I mean, there's a huge universe
of companies that do this and they do it all,
if this was all they do all day, every day,
I'd be more than happy to outsource that,
management of that, and ask that question,
but yes, let's get some scope on the ...
Let's narrow what we're comfortable with
before we try to get
in the weeds on implementation,
does that work, does that makes sense?
-: Yes, it does.
-: I think it's really important for us
to ask the question as you posed here,
what's the appropriate accreditation level
for each resource?
I think it's,
what are the attributes of them that we are gonna value?
Whether it be on-site storage from gas,
what is it?
And how's it applied equally across the board,
I think is really ...
-: When you say equally, what are you ...
-: Well, I mean equally in terms of,
if you put up a battery at one resource
and a battery in another,
if they are alike, they get a like accreditation.
-: Okay, sure, sure.
Universal application of accreditation standards.
-: Yeah, yeah, yeah. -: Okay.
-: I'm fearful
of who would do that.
But, I'll save that for next time.
And the one thing that I wanna bring up on the ...
So, I really don't have anything else
on the LSE obligation.
I really think it's, for me,
the greatest hurdle is what does it,
does it decimate the retail market?
How do we deal with that?
All the other issues that you all have brought up
are secondary issues to me
and I believe that we are on track for
asking the right questions. -: Okay, correct.
-: The other issue is,
what proposals are out there if we decide to scrap this?
My view on this is
there are proposals out there that
ensure that existing megawatts
that are on the system don't go away.
We're in a transition period.
What I don't want is to incent a market
and people to come to invest capital
for a 20 year project or a 20 year asset
that in five years goes away.
We've been through the stranded cost issue before.
And there's no assurance
that they would ever get recovery on that,
like they have in the past.
But if there's a way to incent existing units
that are on the system,
for a short period of time, a transition time ...
I hate to use this,
but Cash For Clunkers was the name.
At least in the old ...
You'd turn in your old car and you'd get cash for it,
but keep it running,
keep the things that are running on the system
before we have to build something new.
Allow demand response to work,
allow the batteries to work.
So all I'm saying is, if we're not looking at
an LSE obligation,
that might be something that I would propose
that we at least look as an interim measure
of megawatts on the system.
-: Cash For Clunkers. -: Yes, sir.
-: Okay.
I'm highly confident
I don't wanna do something like that.
-: I understand.
-: And in the interim,
or if this is not what works, I think
Lori, the question around what else.
My question I already said is fleet wide firm extend,
I'd rather do that straight away.
Will: At the end of the day,
don't we have Cash For Clunkers?
It's called Reliability Must Run?
You wanna retire your clunker, and we're like,
"We're gonna pay you a rate of return to keep that
thing running." -: Yeah, in a sense,
we did run it.
(they laugh)
-: Okay, fair enough.
-: Anyway, that's my view.
-: All right.
Lori: Okay, so I have
a variety of things I wanna address.
And one thing I wanna just go back to
and just to level set again.
We centrally procure right now,
load resources through the ODRS, let's not be
too scared. -: Centrally procured ...
-: Centrally procuring ... -: Non-spend and
-: Delivery. -: RRS, yeah.
-: Okay, so we do a lot of central procurement already,
so let's not to be too, just overhead,
fearful (laughs) of ...
Peter: Sure, but I'm confident if the legislature
wanted a capacity market, they would have put that in SP3.
-: Right, but this is a competitive auction mechanism
that I'm looking for, not a capacity market
that's open to all resources.
I shouldn't say looking for,
but that's what the other ...
They're very much different.
So, okay.
So, let me just get away from those concepts right now,
so that we can get to these questions.
Okay, so with respect,
I'm with Commissioner Glotfelty,
the two primary issues that are, out of many,
that we need to focus on, at least preliminarily
is the impact of the retail market.
And, as a subset to that,
what is the impact to customer choice
as we have customers switching, migration,
and how would we monitor
market power in a bilateral market?
What mechanisms can we put in place
to ensure that the ERCOT IMM
can do her job, okay,
monitor market power in a bilateral market, okay.
Then I would look at ...
I know we need to wait on the implementation
and scope a little bit more of the main elements of it.
How will the proposal
address realtime market operational reliability issues?
That's the other issue I really wanna understand.
Peter: How does it impact it or enhance it?
-: How would it address, I'm sorry.
How would it address realtime market
operational reliability issues?
I really want that answer because I think
that's what we've been dealing with,
that's what we continue to deal with.
And I'm wondering how it all works in the construct,
fair game? -: Sure.
I've got a pretty good idea
what the stakeholder response would be.
We've got two stakeholders that say it's great,
and the rest of 'em are saying it's horrible
because it's not their idea.
My short answer would be,
ECRS addresses realtime and whatever ...
AS, expanded AS, expanded RS,
that addresses realtime operational concerns.
And that's why you pair 'em together.
This provides
accountability and honest accountability
of resource reliability standards
by type and provides forward
investment price formation signals for
people to make those billion dollar decisions
to build new generation.
-: And Sam would say, he knew all,
watching from Massachusetts or wherever,
but he would say we're trying to solve
for two issues, right?
And I can't remember the order,
but one was solving for duck, that curve again,
that variability within the new resource mix that will come.
And that's the realtime
performance basis and operational
incentive system.
And then we are attempting with this proposal
to solve for the other problem,
which is the long-term on aggregate
dispatchability capabilities of the grid in general,
not on a performance basis,
not on a specific technical performance basis,
but on a dispatch-
Peter: Resources, have long-term resources.
-: Yeah, great resources.
Peter: And I'll say,
the second helps the first.
-: Yes, theoretically. -: Yeah.
-: So let me ask you this,
if in fact it would incent,
and maybe we turn this into a question
and I'm gonna try and figure out how to do this,
because what I'm wondering is,
if we have this LSE obligation,
and we have more dispatchable generation ultimately,
or some incremental increase,
how does that LSE obligation account
for the increased amount of forced outages
that we've seen in the summer?
We've had a little bit of that go on too,
so I'd want to forget about the fact that
we need to add it, and that through ORDC
will add money to the market to hopefully
pay for maintenance and
upgrade some of these existing facilities
and take care of that.
Peter: Just looking, so first,
just because you provide money
doesn't mean it goes to maintenance.
It could go to the shareholders,
it could go to dividends ...
-: Well, that's where the penalties come in.
-: Right.
-: Well, I mean, I've already seen that.
You're just dumping money on performing assets,
we don't have any control over where that money goes.
-: That's right.
-: So, let me just backup.
I think just asking that question
will cover all of those sub-issues like
these specific operational scenarios and also ...
-: Okay, so what's the question?
-: So, how will the LSE obligation
address or maybe not address,
but how will the LSC obligation
assist ERCOT with realtime market
operational reliability issues, including
winter cold weather, which I have an answer.
I mean, we know we don't have an accreditation.
Time periods where we have higher than expected demand,
lower than expected generation output of all types.
And,
for times when we have,
which I guess gets baked in there,
times of higher than expected for status.
-: Well, is that covered under my question?
-: Yes.
-: What mechanism will ensure those
receiving revenue streams,
where the reliability services perform inadequately-
-: Penalties, yeah. -: Penalties.
-: We even have those questions.
-: Yeah, I really want my question.
-: Sure. -: Okay.
-: Have you got it? Okay.
-: The other one is,
how will the LSE obligation incent demand response?
Will it result in ultimately
disbanding the ERS program?
I mean, how does it impact of the ERS program?
-: I don't know. -: Do we continue having-
-: I don't know that there's any relation.
I would not, under my proposal, I would not ...
I don't know that the other two would interact.
I don't know why you would ever not wanna have
any ERS programs.
-: Well, I'm just wondering,
because if you're moving
all the resources to get accredited,
are we still gonna have the broad suite of AS services?
Because presumably, this LSE obligation
would provide us with an intermittent,
a significant amount of reliability where
we wouldn't need as many ancillary services.
-: So no, at no point would I propose
getting rid of ERS or the existing AS suite
as currently constructed and anticipated
with the fast frequency and ECRS.
-: Okay, so then let's stay with the broader question,
the demand response. -: Okay.
-: And then ...
-: What was the question?
-: How would demand response
participate in LSE obligation?
And I guess that ... <v ->Does the question,
how do we ensure demand response resources
can participate fully and at all points in time,
address that concern?
-: Sure, that's okay.
Let's see, so
the other burning question I have is about
the industrial consumers and how would that impact
their ability to ...
So, what happens with respect to
business site?
What is the economic development impact on this?
Because I think that we have a lot of industrial,
large commercial consumers coming in
and they may have to be ...
They're part of this entire LSE obligation,
so I really wanna understand what impact it has
on the large commercial industrial consumers.
They're gonna have to plan to have X amount of power.
-: In terms of their requirement to participate
or their ability to participate in demand response
or both?
-: Their requirement (indistinct).
Peter: Any transmission mode,
that it would apply to everybody.
Any option two transmission level LSE
would be required to have the same ...
-: Firm equivalent. -: Yeah.
-: Okay, so what is the impact
on those businesses,
from a society perspective.
-: I guess it's
business specific and would probably be
any negative impact of actually having to hedge their book
or their demand, which most of them promise
and pinkie swear they do it anyway.
Any negative impact of increased administrative cost
or perceived burden would be offset by
the dramatic increase of reliability
by knowing that we're incentivizing
and getting real price formation on
dispatchable generation.
-: Okay, well can we ask them?
-: Sure. -: Okay.
-: I'm sure they'll be available.
-: I just wanna make sure we're looking at it
in a 360 perspective of all the impacts.
Obviously the goal would be to have it in place
when you do reliability,
but I wanna make sure we're looking at it
holistically on all the different impacts,
not just on the retail market and
market abuse, those are very critical, important,
critically important issues,
but we gotta look at them very holistically
because of the pronounced impact it would have
on the existing market.
-: Okay, agreed. -: For my opinion,
okay. -: All right.
-: I think those are all my questions or statements that ...
-: Do the staff have all the clarification they need
on questions that have been submitted on this topic so far?
Okay, all right.
Let me offer some quick thoughts
if, for nothing else, to just provide some clarification
for you all and our stakeholders.
Everyone has highlighted
the concern to retail market
and demand response.
That's why those were the first three questions
on our list, and
I'm gonna be absolutely clear that
if I do not get satisfactory answers
to those three questions, this thing's dead on arrival.
Like I said, at the beginning,
I'd rather not implement this than do it wrong
and cause more harm than good.
Full-stop, not even to think about it,
if we don't get satisfaction for the answers
to those three questions, out of the gates.
The small fish problem,
we've heard a lot about independent retailers,
a lot of concern about being able to forecast load
and what they're, I think at the most simple level,
just say, like I said,
nominate a load share ratio from the CDR,
which needs improvement.
-: On that, Mr. Chairman, so
your list was comprehensive
and
okay, so load forecasting,
we have all shared comments, I've filed memos.
CDR and SARA needs to be reworked.
Peter: You use the same accreditation standard
that you use in this, for those.
-: Okay. -: So they match up.
-: So the question is,
is that a component of everything we're talking about doing,
in terms of a more specific drill down CDR,
again, on a seasonal basis
rather than the twice year standard.
-: Yeah, absolutely. -: Okay,
so we are gonna open up that.
Peter: Yeah, in parallel.
I mean, I think
that's not market in and of itself.
I'd say that yes, very, very deliberate
in my thinking that the accreditation standard,
whatever it's five credits or 10 credits for wind
and 60 credits for solar or whatever,
whatever you use in this accreditation standard,
you use for the new and improved CDR.
And so
the simplest version is saying, load share ratio
of what we think your load's gonna be in three years,
by example.
Not gonna count on individual businesses
for whatever they think.
They usually have load forecast
and customer forecast for their investors,
more than a year out.
So, somebody's making a prediction in that business,
how many customers they think they're gonna have.
And
I wouldn't ask,
I think I put it in here.
The escalating obligation, right?
Three years out, it's incented to
ask for 100% procurement, but some small amount,
some 50%, 30%, 60, something out there.
So you're not required to have a perfect visibility
or perfect answer on what your load's gonna be
down the road.
And as you can see, from what I laid out,
that obligation would narrow in on 100% percent
as you got closer to the operating day.
And even within the month,
that's where the realtime and the day ahead market
still perform a valuable function,
because even a month ahead,
you're not gonna be 100% accurate on your load forecast.
We just need people procuring the product
they assured their customers they were gonna deliver
when they took the customer's money.
Barriers to entry.
Definitely don't want 'em too high,
but we also don't want 'em too low.
And I think there is some merit
to having a kind of, if you could call it,
if you will, market-based credit check.
If you can't get some sort of financing
or convince investors that your game plan
is worthy, then I'm not sure
we want that credit risk in our marketplace.
And if any business model has
a 50% drop in customers anticipated three years out,
that's no business proposal
that anybody actually stands behind, right?
So, we don't want barriers to entry that are too high,
but I'm okay having some.
Penalties, absolutely key part of it,
lack of procuring, whatever mechanism of credits
or whatever mechanism when deciding lack of procuring those
would be on the LSE side;
lack of performance on
whatever generating assets sold those credits.
And if that asset doesn't perform on the operating day,
penalty goes to the generating asset.
Substantial in both cases,
but a lot to flesh out there.
The accreditation,
that's a key part of this whole thing.
I'd say the most important part about it
is being honest about the reliability of our assets.
We had a 100X increase in prices for customers
yesterday and today, in the day ahead market,
because on average diversified wind portfolio
across a mammoth state like Texas
is expected to produce between 10 and 12,000 megawatts
over peak and yesterday we got 1,500.
We've gotta be honest about
these assets not being reliable and we've gotta
hold the marketplace accountable.
In terms of implementation,
we've tabled a request for the details on that.
And so we narrow the focus
what we really are comfortable with,
or what we're interested in learning more about.
I would say that there's certainly some merit
in a phased-in process with price caps.
We know, or waive penalties in the early stages.
We know we don't have enough dispatchable power
in Texas, if there's a liquidity problem,
to your point Will,
that could really, really be dangerous
in terms of prices spiraling out of control.
So you could certainly do some price caps
in the first few years to ensure that
there's definitely revenue there for those generators,
but it's not exposing LSEs to some
just unmitigated price spikes.
And finally, I'll say
the retirements is a concern.
This, I think I already see
should help that if we make those changes,
that should help keep
interviews for life assets in the market.
And if we do find an acceptable version
of an LSE obligation,
that would definitely keep dispatchable,
that's a huge incentive for dispatchable resources
to stay in the market,
if they're being rewarded for the
reliability they bring to the marketplace.
Timeline TBD.
So, just wanted to lay that out
to address some of the concerns around the table,
but also, and I'm, by no way saying that solves them,
but also to make sure our stakeholders have a sense of
the framing I'm thinking about.
Again, this would only be 100% of
expected load, not a reserve margin or a capacity factor.
That's why we have AS, that's why we have ERS;
that's our margin of safety.
Outside of the concerns,
the very valid concerns of market power,
market manipulation and demand response,
which we've addressed thoroughly,
I'm curious to know, other than the accounting mechanism
and the administrative transaction,
how this is different for a fully hedged LSE.
We're not asking them to buy any more power
than they expect to use at 100%.
-: I guess the question is ... -: There's a penalty on this.
Will: Are they actually fully hedged,
what's the definition of fully hedged?
-: 100% of your expected load, right.
Will: I know.
-: But are they?
Is a very good question. -: Yeah.
The world is about definitions: net carbon footprint,
it's all about that. -: What we heard on our ...
We had a very liberated intermittent panel
to talk about intermittent resources
and every one of them had gas behind the meter.
It was offset, but it's still,
it's still producing.
So, I'll leave it there.
Any other questions
or we wanna put it on a list or closing comments?
-: Other than, so I think I got an answer from you
on load forecasting.
We're still gonna have to look at that
as a part 25505 long-term
because it has to be reopened and thus
we can address that.
Okay, transmission prioritization for dispatchability,
you want that, is that part of this, or how do you ...
-: I think that's a separate action.
You've taken a great lead on that
and continue to follow up on it.
-: Okay, I just wanna make sure it didn't fall off the plate.
-: No, no, no, I mean, I don't think of it as a ...
-: Market design. -: Piece of the market.
-: I got it, okay.
-: And I'd also, another element of that
is transmission planning.
I don't think it's a piece of the mechanics in the market,
but improve as we ...
We sat up here and heard all the reasons
why we can't ... -: Right.
-: Build new transmission, import.
(Lori responds indistinctly)
-: We can't build new transmission because it's
unreliable right now,
but we need to make it more reliable,
so we've got to build more transmission,
but we can't build more transmission.
-: Okay.
-: So I think that that process,
from tip to tail needs to be redesigned at ERCOT.
-: And then unless,
and maybe we're thinking the same thing.
I was just gonna ask on the
prioritization of work and then phases
but if you're not ready to cross that bridge now,
and we'll talk about that in a minute,
I'll leave that, okay.
-: I think that
everything that you've gone through with your list,
I think that's the end of our want to design.
I had come up with a list for things
for Brattle to do and I think we agreed to them
conducting the reliability standard,
and giving somebody the analysis.
-: Is there anything not included
on our list of questions for them?
I think we've covered everything we talked:
the reliability standard, the scenario analysis.
I think we got everything.
-: We might wanna get them to give us their perspective
on the LSE obligation, how it would fit in our market,
questions we could ask, they've done it before.
I know they had a lot of negative comments,
but to really give us some additional updated feedback.
-: And included with that, I'd ask what
their opinion on what works and what doesn't work
in the SPP version, it's a different market.
Australia is doing a similar thing.
What's worked, it's very new.
What's worked, what hasn't worked, et cetera, yeah.
-: I mean, I think it might be helpful for context as well.
And I know they're conducting
an ancillary service study as part of SP3.
It's my understanding, where there's (indistinct)
they're gonna have that to us by the end of the year.
I think that's important as we continue to look at
how we plan for the future on the ancillary service side.
So, I think those are all the items
I had on the list for Brattle, but
with respect to your transmission issues.
I think I see that a little bit outside
of the market design discussion,
but I did wanna circle back up
on the interconnection queue
discussion we had at the workshop, in your memo
and just to understand where we're headed, really.
-: Yeah, so I've got a bit of an update,
but I'll save it unless you wanna close this out
or whatever you're doing.
-: I'm good.
-: Yeah, if you can give us an update,
it'd be great and then
we'll wrap it up.
-: I have been able to communicate with ERCOT and
not every stakeholder.
I mean, people are gonna say,
"Well, you didn't talk to me,"
but the wireless companies and
a representative from the Noe segment.
We did have substantive conversations
in terms of the mechanics on how we could proceed
in order to satisfy concerns raised
during the previous workshop.
And after discussing the idea
with these stakeholders, I believe this is something
that we could and should move forward with.
And in my view, the Commission could
direct ERCOT to prioritize interconnection projects
at transmission voltage, key nuance transmission voltage,
and it should follow the following order.
And the reason
this will not have a discriminatory practical effect
is because,
according to all stakeholders
who are managing their individual systems,
there is no barrier right now at present
to a dispatchable resource deploying now,
it's the economics (indistinct) project
that is the determining factor.
Prioritization of that would not
change the expeditious nature of their
interconnection and energization.
It is simply, they did say,
"Look, if you wanna send the market signal,
it's a market signal."
The grandfathering clause is key to that
on at what stage of the process
those resources that have achieved financial
and technical viability in their studies
could move forward.
And again, this is different
than the non-ERCOT regions
who have to deal with those RTOs.
And man, those studies are a bear,
just what I've experienced over on the SVP side.
So my proposal, and ask me questions on this,
is to prioritize, any orders should prioritize
based on three things, and in order.
Non-inverter-based resources, okay.
And that's your ...
That's not your intermittents, that's not your batteries.
Those are based on inverters
and whatever type and technological capability
of the inverter.
And that changes, the inverters typically
change the technical studies that go on
as a part of
the TSP evaluations.
So non-inverter-based resources,
and then second, dispatchable inverter-based resources.
Those were those projects paired with batteries.
And then finally, the interment inverter-based resources,
so intermittent only.
Because again, those wind towers inverter-based,
solar inverter based, you would not have a battery
co-located or joined with that project.
-: Would you assign a duration to the
solar plus storage?
-: And I would stand to my four hour on that.
-: The only thing I would say is,
based on my conversation with the storage community,
there are no four-hour batteries.
-: Correct.
-: So, in order to be able to reap
the operational benefits of
having solar and storage coupled together,
gain the reliability benefits
of those combined technologies,
and also get that operational
lead that we need at the backend with ramping,
I would maybe loosen that a little bit to two.
-: So, I talked to (indistinct) as well
and other project developers who, again,
yes, there are two hours or nine, I think,
two hour capable projects that had
that battery component.
But again, this isn't gonna send them
to the back of the line.
And let me just describe the grandfathering condition
and this may change the dynamics for them.
I would leave the mechanics of implementation up to ERCOT,
'cause I believe that they are well prepared
to impose such a thing,
but I believe the process we would need
would need a certain amount of grandfathering.
And that should be based on projects,
ready-to-go projects that could be energized
in a timely way.
And we would make that fully collateralized
and then have a notice to proceed.
So again, in terms of those steps through the studies,
that shows that they are financially viable
and then also technically viable.
Again, they're entering that final stage of ERCOT's study
which would be ...
I'm sorry.
Yeah, ERCOT's screen.
-: Screen them. -: Yeah.
The final four to five months stage.
So, you're either in or you're out.
And again, we're trying to flesh this out,
it's not gonna prevent them,
it's not gonna reset 'em or anything like that.
And we have to establish a threshold somewhere,
because again, this is a market signal.
We're trying to send some type of preference for the market
and ERCOT says that they prefer
having that headroom of four hours.
Two hour guys are fine, and they're gonna match up,
and especially with what we're considering on ORDC,
those guys are gonna come in
because they're gonna be hitting that ORDC.
Peter: I think you're heading in the right direction.
-: And I'm willing to continue working on this
and formalize that.
Peter: Yes, I think ...
-: The order is gonna be simple
in terms of a policy contract.
-: I think you're absolutely heading the right direction.
I'd love to see it in writing, I guess.
-: Okay. -: I guess, in a memo form.
-: Fine, I'll formalize a memo.
Peter: To the duration standard,
as a treatment we covered
when we talked about concerning DCRS,
I think the key point is,
we need to identify the operational need,
and then set that as the standard,
not set the standard based on existing technology
that may or may not address the operational need.
-: Right.
Peter: And a key part of that is
one of the features of batteries
is that they're highly modular.
So, if you've got a bunch of two-hour batteries
and we need four hours, stack 'em up.
If there's a challenge with that,
you can also aggregate them.
There's nothing preventing
battery operators or storage companies right now
to aggregating multiple batteries and then
offering that or offering that up.
So, I think we always wanna keep
the operational need as our North Star.
-: So, let me just start taking away,
'cause again, this is a building block
and then we'll have a memo to consider
with an actual proposal on it.
But, it's 18 months on general, all in
for the study period.
Okay, from ERCOT to the TSPs, back to ERCOT.
First three months, that's ERCOT's screening,
and then it goes over to ...
Or it could be happening concurrent
with a typically year-long to a 15 month process
for the TSPs.
And if we want to, we can get Liz up here,
but I'm sure she'll be proud
to hear me give this book report.
(people laughing)
One of the decisive points for the study,
where you get a battery on board,
is it, in fact, it affects the stability study.
And again, that's that new inverter that gets put on there.
And so when that happens,
that's typically a one month
extension on that process
because they have to go back and reanalyze
that component of the four studies that they typically run.
So, I don't think this just
automatically resets the whole process for everybody,
but it does reset certain components of it.
And what I'm thinking about,
and this is what I told the TSPs,
I'm trying to establish a standard
that everybody's accustomed to.
And they typically see surges of
interconnection requests
when new transmission lines are built to new areas.
We just authorized a whole lot of transmission
for south Texas.
And it's gonna be a resource-rich area of the state
for different resources, solar or wind.
And it's close to load centers.
I see that as being a lucrative area
for generators to move into, and that's a good thing.
So if we get ahead of this
and we establish a policy purpose now,
then we could see some real benefits from this
that shouldn't hang people up in the future.
I mean, they just talk to their banks
and start talking about the latest available
investible technologies and batteries
that they could go look at them.
So, I'll formalize that- -: That'll be great.
-: We'll talk about it.
-: Works for me. -: Thank you for doing that.
-: Yes, ma'am.
Peter: Good deal.
1:11, I think that
concludes all our business for today.
And as such, this meeting
of the Public Utility Commission of Texas
is hereby adjourned. (gavel whacks)