(hammer beating)
-: Good morning.
This meeting of the Public Utility Commission of Texas
will come to order to consider matters that
have been duly posted with the Secretary of State of Texas
for November 19th, 2021.
For the record,
my name is Peter lake and with me today
are Will McAdams, Lori Cobos and Jimmy Glotfelty.
Welcome back everyone.
Double header feature of the Public Utility Commission.
-: And a lot of jeans.
-: Jeans, casual and surprising everyone,
Commissioner McAdams actually showed up in jeans.
(everyone laughing)
I still think he's going to switch into-
-: I've clip-on back there.
-: All right. I don't have anything for items 133.
That will take us to item number four
regarding electric market, electric reliability.
As you all know, we've got a agenda laid out.
Before we dive into that, first step will be Brattle.
Before we dive into that,
we want to offer a few thoughts to folks watching at home,
as we know, and we've discussed ad nauseum,
we've got two very distinct problems to solve.
Extreme weather events and the blue sky problems,
when we don't have adequate resources
on otherwise perfectly normal day due to intermittency.
Those are our two big challenges.
We have this Commission,
and ERCOT have taken extraordinary steps
in a very short amount of time to address
the extreme weather events.
The weatherization rule's in place.
The operational changes at ERCOT
that this Commission directed
have been nothing short of,
I would say wholesale changes
in both the operations and the management of the grid.
Operating with a much larger margin of safety
and operating grid with an abundance of caution
that will continue through this winter.
And as you all know,
our winterization requirements will be in effect,
starting December 1st. Inspections will start December 2nd.
So we will have a much more resilient grid
going into this winter than we had last winter.
At the direction of Senate Bill 3,
we've also been working on evaluating our market design
and at the direction of Senate Bill 3,
improving and working on improving our market design
to address those two problems as well.
We know that we don't have enough dispatchable energy,
dispatchable resources in ERCOT.
We know that we're going to have to get new money
on the table from somewhere to pay for those resources.
It can come from the generation side,
it can come from load side.
It can come from the central administrative body of ERCOT.
And we know that if somewhere, somehow
we don't have a new money put for us
to procure dispatchable resources,
we will not get new dispatchable resources.
That was made very clear at our last work session.
And at the end of the day,
we know we need to take an all-of-the-above approach.
There's no silver bullet.
It's a combination of tools, techniques,
methodologies, and products.
And we will continue to work through those today
as we narrow our focus approaching the December meeting,
where we will put forth our blueprint for market redesign.
At that time, we have many of the short range tools,
products, and methodologies that we've discussed
that will be ready for action very soon.
And we'll continue to rapidly narrow the scope of those
and then focus on solutions.
We will also be making a decision on the broad direction
of where that longer-term market redesign needs to come from
gen side, load side, or input period through our cottage.
We all know that the details of the longer-term effort
won't be completely solidified in December.
We have always known that.
That's the point where we need to pick a direction,
show the people of Texas, our investors,
our market participants that the State of Texas,
takes reliability seriously.
And that this Commission has chosen a direction.
From there we can flush out the best version,
the best model, the best methodology
of how to implement that longer-term reform.
But we need to chart a course
to move us in the right direction.
We've got a path forward.
We've got a lot of tools and resources and analysis in hand.
And so I look forward to continuing the progress
that we've made building on the success we've had so far.
And with that, we'll welcome Brattle to come
start with the first presentation of the day.
I suspect that they've got a few ideas to share as well.
It'll be allowed, but it's close.
-: But he's got a tie.
-: He's from Boston.
-: Good morning.
Thank you for having me here.
I'm again, honored to, to have this role,
to try to help with this.
It's a pretty big challenge that you have here in ERCOT.
And my role, actually today, what I'm going to do
at the request of Commission staff,
I'm going to talk about market design options
for supporting resource adequacy.
Basically the problems that the Chairman just outlined.
A little bit about the need for ramping
to deal with more intermittent reserves and,
how ECRS could meet that need.
And then third, I'll talk a little bit about
the various ORDCs that have been considered.
And my goal for today is to sum up what we have analyzed,
what we've seen from other stakeholders,
the whole set of ideas,
including ideas from other jurisdictions
in order to inform your decision.
Our job is just to do the analysis and objective analysis
and to just be informative to the decisions
you have to make.
And, you know,
I've got the easy job.
You're the ones that have to make the decision,
but I want to make it as easy for you as possible by
knowing that you have the best information in front of you.
Could go to the next slide, please?
Okay. You all read our disclaimer.
And that was good.
Okay.
So there are two challenges that
Market Design can help address.
And, you know, the really the big one,
the reason we're here, is resource adequacy.
That's my term
for what the Chairman described a few minutes ago.
And that's to ensure there's enough supply
that's always available to meet demand.
And that's under all reasonably plausible conditions.
So we're talking about extreme weather in the winter,
in the summer, in the shoulder months,
when there could be a, perhaps a short heat wave,
and there's a number of plants on simultaneous maintenance.
And when the wind goes down and when the sun goes down.
These are all challenges of making sure there's always
enough supply that's available to work with.
And it, cause it's not just nominal megawatts,
it's not just capacity.
It's available capacity, including dispatchable capacity.
So you can always meet demand.
So that is the,
that's the primary problem that we're here to talk about.
And the main one I'll talk about today.
Now partly just for clarification,
I'll talk about this one too,
but the second problem that is distinct,
is operational responsiveness.
And that's just to manage changes in supply and demand from
second to second, minute to minute, and hour to hour.
And that can arise because of the contingency,
the outage of a large nuclear thermal unit, for example.
And now increasingly we're worried about it arising from
expected and unexpected ramping needs.
So what the expected,
I'm talking about things like the Duck curve,
you can forecast that the sun will go down,
but it's pretty impressive how quickly you lose
a lot of supply and you need to address that.
That's the expected ramping needs,
but they're also unexpected ramping needs when,
especially there's a weather front and, you know,
the wind and the sun perform very differently from expected
in that you've, you know, positioned the fleet to meet.
Now that whole problem, particularly managing ramping,
you can do reliably.
This is not a question about reliability.
You can do it reliably as long as you've solved problem one.
As long as you have enough resources to work with,
you can manage the ramping.
I mean, you could even, you know, for example,
if you have enough resources to meet the load
in the evening, after the sun goes down, you could just
turn everything on and curtail the renewables.
I mean, that wouldn't be the most efficient way to do it,
but my point is, you can be reliable.
What we're striving for here is how to manage
that more efficiently,
making best use of flexibility in the fleet
and meaning economically efficiently,
not ways to leak or dialing things when you don't need to.
But also to do it in-market,
through ancillary service products and the energy market.
And why is that important?
Actually, to send the right investment signals.
You can do it out of market.
I mean, ERCOT has plenty of authority
to order on the plants that it wants
and to dispatch down plants, curtail plants.
It can keep it reliable as long as it has the right rate,
as long as it has enough resources,
but we're trying to do it in-market,
with energy and ancillary services that not only
get the job done efficiently in an operational sense,
but reward all the resources that have the flexibility,
that's valuable and probably pay less to the ones
who don't and make it a harder problem.
'Cause then you get the right incentives for investment
in resources that can help meet load,
you know, reliably at least cost.
And that includes dispatchable resources.
So those are the two problems.
Again, I'm going to primarily focus on number one,
because that's how we got here. We got here because of Uri,
which was truly the largest supply shortfall
in the history of the grid in the US.
And so how to avoid something like that again,
and there are other weather extremes
we have to prepare against, right?
And we're also here because of the growing amount
of intermittent supply that raises questions
about how do you deal with it's intermittency?
So that's primarily why we're here.
And that's the main thing I'll address.
Now, it's my duty to also remind that that, you know,
this is not just about market design.
It is most important to continue to assess
the particularly catastrophic risks.
Everything from new kinds of extreme weather
to cyber attacks.
You think February was bad.
It's much worse if the whole grid were to go down.
So you can't get so focused on market design
loop side of thinking through, all the possible,
particularly catastrophic risks and making sure
that you're protected against those,
mitigating them and able to recover from.
So that even gets into some non-market things like
doing load shed better.
We know that was an issue in February.
It gets into things like Blackstar procedures.
I mean, the whole grid goes down,
bringing it back on is not trivial.
Making sure that you're set up to do that.
And it's just important that we don't lose sight
of protecting from the very worst things,
rather than getting caught up in subtle differences
in market design.
Or not so subtle but still the scope of that
is not the entire scope we're worried about.
Okay.
So could you go to the next slide, please?
Wow.
Well, it's interesting. This is just fine.
These were circles on my slides. I'll work with ovals.
Now focusing on that problem of resource adequacy,
making sure there's always enough supply that's available,
dispatchable to work with to always meet demand.
There are really two viable options.
We've heard a lot of ideas.
Some of them are different forms of these.
Some of them are, you know, quite different,
but don't really do much for resource adequacy
or maybe they're more about operational issues.
And I'm trying to sort out
what the big choices are before you.
Actually, let me say you have three choices.
You could do nothing,
and that's probably not very attractive.
That's your option zero.
Peter: We'd all be looking for new jobs.
-: Okay, well, it didn't even make it onto the slide.
Option one,
is load serving entity reliability obligation,
and we're calling it LSERO+.
And the reason calling it plus,
this is basically the concept that E3 and NRG...
There's Bill. Hi Bill. Bill: Hello.
-: It's basically that proposal,
but with some additional features to address
what we're serious and I think the biggest concerns
we heard about it, regarding market power
and to address that there'd be an auction
that all the large GENCO's would have to offer
all their supply in, at cost,
subject to mitigation by the market monitor,
like the market monitor mitigates the,
you know, centralized energy market today.
And, you know, participation would be voluntary,
by load serving entities to buy from them.
So that's one difference.
And the other differences is that,
LLCs in order to accommodate retail choice better.
LLCs would be able to
show that that they have enough credits
just right before each delivery season.
So they know how much load they have.
They don't have to guess in advance
and there'd be a mechanism for transferring
those load shifts within the season,
using the price from that auction
that was mandatory for large GENCO's.
Okay. So that's option one.
Look, if what you want is to be able
to look at the fleet and say,
"Yup, that's good. We're prepared.
We have a fleet that's ready for difficult weather,
that's got enough dispatchability
for when the wind and sun aren't shining."
If you think you're good,
if you think you're able to look at the fleet and say,
"Yup, that's good. That's what we want.
We're prepared for, you know, any, any plausible event."
This option is the most direct way
to express that to market to set a requirement.
And then to put that requirement on load serving entities.
They're the natural buyers.
They're the ones who consume from load, right?
And then the suppliers are just,
it's all the competing suppliers.
But importantly, it is subject to accreditation
that makes sure each resources only getting credited
for as much as it contributes to reliability.
And that their performance obligations,
so if they've committed, you know,
they really get penalized if they don't deliver.
So to me, this is the most direct way
to express a resource adequacy objective, to the market.
I will get into pros and cons later.
As simple as I just made it sound,
it's not simple in implementation, and it has some
other aspects that people will remain concerned about.
So we have to have an option two,
in case that one doesn't fly.
And the option two, which again I think,
is a viable way to address resource adequacy
is to have a combination of targeted measures.
And I will say this combination of measures is similar
to the package that NextEra presented
a couple of sessions ago,
but it's not identical to that.
So it's really three components.
One is leaning more on the weatherization enforcement,
the weatherization from SB-3, we just heard about,
but truly having to enforce it more carefully.
The second component is to have a,
fuel firming program that addresses
particularly the gas-fired fleet, a lot onsite fuel.
And I'll talk in a few minutes about more of the details
of how that could work.
And the third component is backup reserves.
And don't know if you all got to
yet read everything filed,
but I'm talking about something very, very close to the SRS,
the Strategic Reserves that Commissioner Cobos just filed.
And so, you know again,
there are other options that have been thrown out there,
but that just didn't make it onto here,
'cause I think that either wouldn't work or,
you know, sort of, you know,
so we didn't look at options that would create,
that would try to create a backup reserve,
but not hold it out of the market.
So it would just you know,
it would just undermine some of the in-market resources,
and not actually improved reliability.
Didn't look at backup reserves that
were for a huge commitment to new capacity.
That would be very inefficient to hold out of the fleet
wouldn't be really out of,
out of the energy market and would be very costly.
Didn't look at things to, for example, you know,
curtail renewable resources more than needed
for operational reasons.
But these two options, I think,
are a couple of good options before you.
And what the alternative is, is basically do nothing.
So I hope this framing helps.
What I'd like to do next, if you go to the next slide
is talk a little bit about the details.
So I'm not gonna go over everything that's already been
presented 'cause again, this builds on the concept
that E3 and NRG already presented.
But I do want to elaborate on a couple things with
the load serving entity liability obligation plus.
So the basic features are the ones
from the original proposal.
And as a reminder,
it starts with static setting out,
what is the resource adequacy standard?
What are the, you know,
to what standard do you want to be prepared?
Are there deterministic events you want to be protected
against like a repeat of Uri?
Are there, you know,
looking at many scenarios of considering what happens with
30 years of weather and how that affects load and wind
and sun and make sure you're prepared for basically
always being able to keep the lights on in spite of
all those variations,
but to what level?
You know, cause it's not,
we're not talking about infinite reliability.
You have to define exactly what you mean.
Once you've done that, it's putting the requirement
to load serving entities expressed in the form of
how many credits do you need.
And we usually denote those in megawatts that are equivalent
to an always available dispatchable resource.
Resources that are less reliable than that
don't get as big a credit.
They get a much lower credit if they're intermittent
and correlated with other intermittent resources.
They get a lower credit if they're energy limited.
And some of these discounts are actually quite big.
I mean, what you'll see is that
a dispatchable resource, if it really can also demonstrate
it's well winterized, has secure fuel
would get a really high credit
and resources, you know, much lower credit.
I mean, it very much speaks to what
some of the themes we talked about,
making sure we have enough of the resources
that we need to feel confident to keep the lights on.
You know another important feature,
I don't think that I want to emphasize that
we're sort of adding here is, is an opt-out.
I think it's pretty important to customers
who don't need from power and are able
to really be curtailable or help self-supply,
to not be subject to this.
And now the biggest part that is,
takes by far the most market design work,
and you'll argue about forever frankly,
is supply accreditation.
And we can bring best practices
and some of the things E3 talked about in the prior
presentation, and I'll speak to that.
We know how to think about,
you know, how to discount intermittent resources.
We know how to,
we have experience from other jurisdictions,
how to think about demand response,
but it's actually pretty tricky.
And we're talking about decisions that affect
how a lot of money flows.
And so these decisions will be contentious.
I have a friend who is the President of the,
one of the generator advocacy groups in the Northeast,
who says that 90% of his time is on
issues related to their capacity markets.
And that's particularly on issues that are comparable
to what we're talking about here with supply accreditation.
You'll argue about it a lot.
There's just a lot of money hinging on.
Even though they're sort of industry best practices,
there's a sort of, you know,
a lot of objectivity you could bring
to how to do accreditation.
What is the marginal reliability contribution
of reach resource?
There actually will be a lot of a judgment,
particularly around how well winterized you are,
what kind of fuel you have,
how to deal with limited calls in with demand response,
how to deal with imports?
I mean, there's just
a pretty big set of questions that will need to be addressed
and even updated over time.
This again is the essence of this solution.
It's thinking I want to be able to look at the fleet
and see that, you know, do better than just what's
in the CDR as an indicator.
I want to actually take a really close look
at what is the reliability value of each resource.
And I want to secure it with a payment that gives them
a commitment subject to penalties if they don't perform.
So that is the essence of it.
What is the size of the credit for each resource
and, you know, intermittents by the way,
sometimes choose not to sell it at all because
they don't want to have the exposure to the penalties.
Okay. So credit tracking,
I've been asked some questions about that.
I mean, that's a very manageable issue.
You can do something.
That's an issue that's been figured out.
I think what MISO does,
the Midcontinent Independent System Operator
for its resource adequacy construct,
which by the way, most people don't call a capacity market.
There's bilateral trading and a last minute auction
and that they have a tracking mechanism
that enables those bilateral.
It starts with the accreditation to sort of mint a credit.
It tracks who has them and when they'd been transferred
and ultimately the LSEs get to dispose of them.
By the way, this is also, has a lot of attributes
similar to the REC crediting tracking system
that is already in use at ERCOT.
That's a totally easy, manageable part of the problem.
Performance penalties, I think are quite important.
You know, you'd have to decide how big they are/
You know, there already are big performance incentives
with a energy price going up to the cap
when you have a real shortage.
This would actually increase those,
but in a way that doesn't expose loads.
So generators that have made a commitment
and are not performing up to, you know,
at their committed amount would get penalized.
And now the enhancements that we talked about,
I mentioned the auction for big fish.
The reason that's necessary is to make sure
that large generator, you know,
they can't exercise market power and drive up the price
and then efficiently, physically or economically
withhold resources.
That's quite important because this market with large
generators is structurally not competitive.
And it also would help make sure that they're not
favoring their own retail arm.
That any retailer is free to buy in that auction.
And the price would be,
the offers in that auction would be subject to
market power mitigation.
And this auction would be just before each season.
And it would be a place where the, you know,
and having a competitive price in this
would also discipline the bilateral markets
that can happen before it.
It would create a transparent price that can be used
again to price transfers between
load serving entities within the season.
It's an essential element of making this work.
And Commissioner Cobos, so you've asked before,
how does this differ from something that we looked at
in 2012 that we said not to do?
And we said not to do it,
if it were a purely bilateral without this
auction to deal with market power.
And the other thing we worried about
was in a retail choice environment,
if you were to set up this requirement and make
load serving entities buy ahead of time,
when they don't know how much load they'll have,
and they would have to, you know, buy capacity.
And then come the delivery period,
maybe they have too much, they have to sell it,
but maybe they took a big loss.
They take a lot of risk.
That's why you really, in a retail choice environment,
you really don't want to have this requirement
until just before the delivery period.
Now that means you don't have quite as much transparency
and on a forward basis.
So, you know, LSEs would still face risks.
This is a new thing they'd have to buy.
And they wouldn't actually,
I don't know how liquid and transparent
the bilateral forward markets would be in advance.
So LSEs still would be facing risk
as they're signing up customers.
And if they don't have very good visibility until, you know,
until this auction right before the, and again,
they can buy in the auction, but if ahead of time,
they don't know really what the price is.
You know, hopefully like other markets,
you have a liquid transparent enough
bilateral forward market that, that they do have an idea.
So this is workable,
but I won't deny that it adds some risk
to load serving entities.
It's a new thing they have to buy that's, you know,
that can't completely easily be seen in advance
and to coup the price and hedged.
Last thing the enhancement that's needed is that this thing,
again, mostly because supply accreditation is,
takes so much discussion to get right.
All the elements would take a lot of design.
This would take three years, if all goes well,
to put in place and you need something sooner.
So there'll be interim measures that you would need here.
And those are kind of the same things that are an option to,
well particularly the enforcement of the winterization,
and a fuel program.
Not going to describe that here,
cause I will on the next slide,
because that's a core part of option two.
Here it would be just for, you know,
a year or two and then get folded into the LSE obligation.
Any questions or comments or that,
or should I go on to option two?
Peter: Go on. -: Thanks.
Okay. So again, this is another viable option
for achieving resource adequacy.
The problem that we started with this morning
to make sure you have enough for extreme weather
and for when intermittent resources aren't there.
But without an LSE obligation to sort of make sure
the entire fleet is adequate,
you need all these targeted things to look at
where the risks are.
And so one of them is, again the weatherization.
We don't have commitments and penalties here,
financial ones, like we work with the LSE obligation.
So enforcing penalties just from the SB-3
becomes really important.
Second thing that deserves a little discussion
is the fuel firming product.
I'm talking about something that you'd have to decide,
what are you're trying to protect again?
So is it four days of onsite fuel?
And now onsite fuel is helpful at gas plants, coal plants,
nuclear plants, anybody who's got that.
But there are several variants of this.
You could have it covered all those.
I think the simplest one and the one that seems,
a bit most likely to be implementable here,
is to target just the gas-fired fleet.
So let's talk about gas fired resources that are,
that would commit
to provide a dispatchable power with reliable resources
with four days of onsite fuel.
And the eligibility, again, I think would,
it would involve some of the things like we talked about
in the LSE obligations.
That you make sure that they are satisfactorily winterized.
That there's probably some testing,
although I'll get to that later.
I mean, they really have to make good on their promise.
Now the quantity is interesting.
The way I think about it is if you want it to be
ready for another Uri,
I think there were about six gigawatts that said
they couldn't get fuel.
That understates the problem of fuel shortage,
because there was another, nearly 20 gigawatts of gas-fired
that was offline for other stated reasons.
Now, if they had been otherwise available,
they too wouldn't have been able to get gas.
Cause the reason that six gigawatts couldn't get gas
was a system wide supply shortage.
We just saw in the NERC report, it was primarily that
it was freezing of the supply wellheads,
and it wasn't just about, you know,
pipelines losing power or something.
That was a small part of the problem.
So basically we had six that couldn't get gas.
If you'd had the others able to not frozen the other plants,
they wouldn't have been able to get gas either.
So in an event like that, there was about 25,
and forgive me if my numbers are slightly off,
but there was about 25 gigawatts of gas fired resources
that were still getting gas from the pipeline,
but there was about 25 that weren't
for one reason or another.
And so that's about the size that I think
you'd want this program to be.
So that you'd be ready for another Uri.
Where remember the load got us
the load that would have been there was,
if it could have been served,
was it got as high as 77 gigawatts.
You would have needed basically the whole fleet.
So I would think about something on the order
of 25 gigawatts of natural gas-fired plants.
-: Plants that need firm fueling?
-: Yeah. And they would need to install tanks, you know,
some modifications to the plant to deal with,
you know, NOx emissions, burning fuel, I assume,
depending on their environmental requirements and a few
other modifications and they needed to fill the tank.
And my understanding is that, you know,
the fuel gets a little old and you know,
you need to replace it every year and a half or so.
Okay. But let's talk about how to procure it.
You want to do it competitively.
I think that's quite important because you probably
don't want to make more than, you know,
a couple of year commitment with these resources.
Cause some of them might not,
well, there are a lot of reasons that you might want
to do it more like a two year commitment.
And you just ask them how much
and you solicit from the fleet.
How much do you need to be able to provide this product?
And you take all the ones that
that'll offer it at the least.
'Cause they're thinking about what helps lower the cost,
why it's not the full, you know,
1 to $2 billion that this could cost is because they're
thinking, well, you know, "Actually if I install this,
I'll be able to get value out of it
for, you know, a good 10 years.
And so what I need to be paid as some sort of a,
some sort of a capacity payment for providing the service.
What I need to be, well,
I just mean it's not on a per megawatt hour basis.
I'm not saying that it's the capacity market,
it's either that'd be paid, you know,
for the number of megawatts of you know,
from a winter deliverability."
But it would be, you see,
so if you suppose you get, you know, 40 gigawatts offering,
"Yeah, I can do it. I can do it."
The auction takes the 25 lowest cost ones and it sets
the market price at the highest offer.
And everybody gets paid that, which is, you know,
sort of a lot of theory on why that's a good way to do it
as opposed to through an RFP.
They're not all that different and they're not hugely
different in outcome, but this is good way to go.
And truly, it's what I like about that
more than cost of services.
You find the cheapest ones,
that's the most important thing,
and you're accounting for their anticipation
of getting value from this in the future.
Because this will be continued to be valuable in the future,
assuming this approach such a program.
Cost allocation would, you know,
there are several ways to do it.
You could do it based on energy used in the winter.
You can do it based on winter peak.
But it would go to loads.
The testing would be important because you want
to make sure that they work, I mean, protect it.
So it's hard to test under coldest winter conditions,
but you can at least make sure that
the backup fuel is working.
And then finally you'd want to make sure that
use of this fuel would be only offered at the price cap.
The reason to do that is because, you know,
otherwise they kill the reward that coal and nuclear get
and others that are able to help during those times.
And why would you want to do that? You don't want to unde...
I mean, you could even include them in the program,
but if you don't, you better at least
not undermine the price when they're doing a good thing too.
So they at least get the price cap,
even if they're not getting this capacity payment.
Now the back-up reserves program.
So maybe I don't really need to describe it,
'cause what I would describe as a very,
very similar to what is in Commissioner Cobos's memo.
But I do want to highlight a few things about it.
So the product definition and what this is all about
is having a few more megawatts.
The fuel firming and the weatherization are to avoid,
a really catastrophic problem, to say.
We actually need to make sure that the most vulnerable
aspects of the fleet are secured.
And what the backup reserves does though,
is not so much about that.
It's just a little like NextEra described it too.
It's it's a few thousand megawatts more,
dispatchable resources that,
you can have for the many challenges,
whether it's the blue sky day or that hotter than expected,
where it would be nice to have a few thousand more megawatts
to keep you out of light load shedding.
I'm talking about, you know,
a few thousand megawatts for a few hours.
And because our modeling and a strop based modeling
says that without that,
that'll occur about once every two years on average.
If you don't want that, you want to have more cushion,
and by the way,
with emergency conditions occurring a lot more than that,
but load shedding maybe a couple of years.
And we also argue that, that may be the economic optimal,
but if that's not what you all want and you know,
you do kind of need a little more cushion.
And, by the way, before getting into these elements,
the most important thing is that it's held out
of the energy market.
You can't have this side payment to these extra resources
and just have them in the market.
All they'll do, if you think you've added resources,
actually all you really did is you undermine the price
and you're going to displace exactly that much
in market resources,
whether existing units or other new investment.
So that is critical.
I think this works best if it's targeting existing plants.
Because you know, the ones, the last ones in the stack,
the last ones that are barely going to run anyway,
hold them out in reserves and not until the price cap.
That is by the way that that for sure will increase prices.
It'll increase spot prices,
it'll increase forward prices in a way that will attract
and retain more investment.
A little bit like,
I don't know if you remember, what was it about?
Was it three or four years ago when Vistra retired,
announced retirement about 4,000 megawatts of coal plants.
Immediately, the forward curves went up.
Will: It was 7,000.
-: It may have, is that right? Will: Yep.
-: Okay. Well even more so.
So here to holding out of the energy market,
a few thousand megawatts for sure increases the price signal
that attracts and retains others.
And you know, certainly it retains capacity,
it can attract capacity to, if people trust that,
"Yeah, you're always going to do this."
I know that we're going to have stronger prices
in this market than if you didn't do this.
So it does depend on people believing that.
You know, you can ask whether it should include,
well, you could make new resources eligible.
I just think they'll never win.
You know, they're, they're not the right,
they have too high of fixed cost and usually too low
variable costs to be good candidates for this.
You know, there's a question of whether
to include demand response in this.
So my inclination is probably to keep them in ERS.
And the reason is that,
if the quantity of this is something
that actually varies with,
to get your reserve margin to like 16% say,
and to fill in the gap or the, what the market didn't do.
And if it says, this is something that you buy more,
when you need more and less, when you need less,
that's going to be a pretty inconstant market.
And I think that works for existing generators that can,
all right, they're in market or they're in this program.
I don't think it works that well for demand response
that doesn't really have another model for getting paid
in the years that you're not buying it.
So that it would be kind of dislocating.
So that's something to consider.
You could set this up either with demand response in or out.
Forward timeframe.
You know,
one concept is to do it on a three-year forward basis,
based on the forecast of how much you'll need.
That most clearly would signal to new resources
in time for them to do something about it.
It doesn't have to be that way.
You could do it only just before the season.
And you know, if everybody in the market
knows you'll do that,
their forward expectations of prices will account for that.
So that could work too,
but that's an element to discuss whether to do it just
before three years in advance or what.
Cost allocation, probably be to, you know,
to all load maybe based on some measure of peak.
Okay. So let me just summarize then.
If we could go to the next slide?
Comparing these.
Option zero is grayed out because I don't think
we're entertaining it here.
And the biggest problem with it is that it,
you really have less control to secure the fleet
against extreme conditions.
I mean, there's plenty of there's evidence
and there's plenty of theory
that the energy market helps.
It does. You can expect it to send a signal
when there's not going to be enough resource
under certain kinds of conditions.
Resources that can provide
energy at those times would expect to get rewarded,
to get built.
It's just that in Uri,
there was such a large supply shortage.
I think there's probably a lot of attraction
to being able to do something where you say,
"I can see the fleet and I'm making sure it's ready
and not just including weatherization,
but with a commitment from the generator of some kind
and not just weatherization, but fuel."
So against extremes.
And the other point that I mentioned before is,
even apart from that,
even if there aren't extreme weather events,
just sort of typical, you know, hotter and colder,
you'd still have shortages,
mild shortages every one to two years or so.
And I think an urgent emergency is more often,
I think that's not acceptable.
So we talked about option one, the LLC obligation,
and we talked about option two, the targeted measures.
Both of them would address resource adequacy,
the problem we started with today.
And I'll mention that, you know,
the reason there's only one check with option two is just
because, you know,
it's targeted and it's not actually getting control.
It doesn't control the preparedness of the entire fleet,
you know, resources that aren't part of the
backup reserves or the targeted fuel.
You're not actually getting a commitment from them
and subject to penalties if they don't run.
But nevertheless,
I think it addresses the biggest shortfalls
and the problems with it are more on the subtle side.
I don't think there are any catastrophic problems with it.
No solution here is going to be perfect.
They all have trade-offs.
And I want to be clear that, you know, this is one
that could meet your resource adequacy obligation,
you know, desires.
But it has some trade-off. So does the LSE obligation.
I think they're both,
they're both fine for market and regulatory sustainability.
I work with generation investors
and battery storage investors, across the continent
and I know people have viewed Texas with ERCOT
with particular interest because they have viewed it
as having more market and regulatory sustainability
than others,
where they trust that prices will always fundamentals
in a market-based framework
and are interested in investing here.
And I'm talking about both new and existing assets.
So that is really important.
And I see that being workable under both option one
and option two, probably a little bit more under option one.
Cost on the bill.
We've heard concerns that it's going to cost
much, much more to do to do these.
It's not trivial, but I think what we're talking about
is on the generation portion of somebody's bill.
And I'll show you a little more detail in a minute on this,
about a 7% increase for the LSE obligation
and about a 3% increase for option two.
So compared to the size of the problem, you know,
is that prohibitive?
And then the challenges with that,
I didn't yet mention here with option one,
the administrative intensity of, you know
this shifts about a third of the value in the market
to the LSE obligation, from energy to LSE obligation,
in our estimates.
That is a lot of money that hinges on administratively
intensive processes to decide how much each resource
gets credited and the other rules and how you do,
for example,
how you do the market power mitigation
in the big fish auction, where the market monitor,
they don't have perfect information.
So there's just,
there is a lot of administrative judgment,
that goes into this,
which will be the subject of ongoing argument.
And you know,
what people won't suggest that could happen here,
but people talk about this kind of thing where there's
a lot of money hinging on administrative judgements
as being subject to regulatory capture.
So, you know, I think that's the biggest downside.
I think the, you know,
there is some increased risk to the LSEs on the price
that they're going to pay as they're getting customers.
But I think that the measures that we've suggested
do address the risk that they'd otherwise have on quantity,
which is the biggest concern I think we heard from them.
And it also addresses the market power problem.
All right. That is my sum up of those options.
Let me just show you a couple of things on the cost.
if you go to the next slide.
So this isn't a forecast or anything.
This is work we did with a strap, a,
you know, sort of status quo, assuming $3 gas.
By the way, this is estimated with a 2024 type fleet.
At $3 gas, the total energy costs in the market,
for energy plus,
you know, ancillaries and any reserves on the RDC,
that'd be about $20 billion a year.
That's about what this market is.
Then how much more or less do these other options cost?
Well, maybe I'll start with option two first,
cause that's the easiest.
Because you're holding both of these measures
of backup reserves and fuel firming,
the use of the firm fuel out of the market at the price cap,
expect energy prices to be about the same
as in the status quo.
You're just, to the extent you're holding these reserves,
they're only at the price cap,
it's as if you didn't have them.
So the energy part is about the same and then
the cost of each of those programs, rough estimate,
maybe $300 million a year for each of those at the top.
And that's it.
That's how you get the plus 3% or so.
Okay. And then the option one.
The surprising thing about that is,
so imagine you got to a 4% higher reserve margin
than with an energy only market.
When you do that, you're going to,
and you have more capacity and it's all in market.
None of it gets held out of the energy market.
Now it gets dispatched economically.
You're going to get those shortages.
You're going to have much lower energy prices
as shown there.
And that's the offset.
And it's actually because the energy prices
went down so much, that you need to pay somebody a lot
to be willing to invest in spite of that.
But the sum is,
all right, so you're supporting about 4% more capacity.
And you know, there's a, I won't spend a lot of time on it,
but there's a nice intuition why this is about a 7% increase
and that by the way, that folds in the fuel cost too.
So that's our rough estimate.
Any questions on this stuff?
'Cause then I just have a much shorter discussion
of ramping and RDC.
Peter: Go ahead and finish up the presentation.
We'll do questions at the end for all of it.
Sam: Okay.
Could you go to the next slide please?
Okay. Totally changed gears now for a secondary problem.
This question of how do you meet
the ramping needs in this market?
Especially as we get more wind and solar.
And we're talking about both again,
the expected ramping needs,
for example with the Duck curve
and unexpected, when the forecast changes,
when the actual differ from the forecast.
You can manage a fleet with a lot more renewables,
but you absolutely have to position the fleet
to handle those.
And, so we reviewed what ERCOT's plan is to do that.
And our conclusion is that it will work to reliably meet
the ramping needs and to do it largely in-market.
And their plan is to do that through non-spin and ECRS
coming in about a year and a half.
So we've spent a fair amount of time
with ERCOT's operations folks on this.
And we think that will work.
And again, largely in-market rather than a lot of rocking
when it's combined with the changes that we're talking about
to the RDC, that basically conform the real-time demand
for reserves with the demand for ancillaries,
that's actually procured only to add.
Okay. So that's the most important point here about this.
I do want to say that the quantity that you would need
of non-spin plus ECRS
is much, much smaller than the Duck curve itself.
That even if we were facing a 20,000 megawatt increase
and spread a little less than that, for reasons, you know,
what he explained before about meeting some inertia,
but even imagine it's 20,000 megawatts,
that's a regular thing day in, day out.
You know, the energy market signals, most of you know
how to handle that combined to,
you don't even necessarily need really
flexible resources to do it.
Combined cycles, might turn on the afternoon, you know,
at 3, 3.30, 4, 4.30, you know.
And day after day they'll see that,
"Yep, it makes sense to start coming online
to meet that rising load in the evening."
And you're left with only a much smaller amount that has
to be met by more flexible resources
that you want to make sure,
really, for two reasons.
There is really two reasons for it.
So it's one it's to meet the unexpected changes,
but it's also, there's just some sort of,
that process I just described won't be perfectly smooth.
I mean, there's not perfect coordination across the fleet.
There's some sort of clunkiness and, you know,
having some reserves or faster resources will help.
So the quantity, what we're talking about is probably,
I think ERCOT's put out some numbers a little bit,
but it's probably, you know, between,
depending on what time of day and time of year,
something like zero to 3,900, where 1100 of that
is actually not having to do with this at all.
It has to do with the original purpose of ECRS,
which was for contingencies to restore RRS,
following any contingency.
So the quantity needed for ramping something like 0 to 2800.
Will: 2800 or 3,900?
Sam: The 3,900 includes 1100 or so.
You would want for contingency reasons, is my understanding.
Will: Okay. So all in 39. Sam: Yeah.
And just consider that at preliminary number.
And I don't want to speak for her ERCOT,
'cause if I've misunderstood that, that's sort of fresh.
But my point is that a few thousand,
I also think that there should be something like there is
right now on high uncertainty days where you're able to
increase the amount of non-spin by a thousand.
I really think that kind of thing is a good idea.
And you might consider having that even with more.
-: Oh, we're going to keep doing that for sure.
-: Yeah. But possibly even with more and with the ECRS too.
So I can imagine days, and there's a weather front,
for example,
where you might want to have even more than that.
But I think the quantities that we're talking about,
it's nothing like 20,000, it's a few thousand.
Several thousand in a few days.
And then, you know, we're asked about cost allocation.
First of all,
because the quantity is smaller than some people thought,
I think it's not quite as important, you know,
to do something.
You know, ancillaries are generally allocated to load.
That's the simplest thing to do. Now, there certainly is,
a theory here that makes sense to get incentives right,
to allocate it to people who are causing it.
And that's the intermittent resources.
It might make sense to allocate the costs of managing
their fluctuations with like allocating the cost of these
particular ancillaries to them.
The only warning is it's not as simple as it sounds to do.
And the reason is, I mean,
you could imagine rerunning ERCOT's model that it used
to figure out the amounts and figure out,
well, how much was attributable to these resources?
So you can imagine doing that.
The tricky part is getting all the way down
to the resource level,
because you ought to recognize differences between
say wind and solar, between resources that are, you know,
solar or fixed tilt versus, you know,
tracking a wind that's bigger turbines that have
higher capacity factors and can work better
even in lower wind conditions.
Coastal versus versus inland.
You know, whether they have a battery?
A small battery, big battery.
So there are so many factors
that would get pretty complicated.
There are a couple of models, we haven't solved this,
but I will say there are some models elsewhere,
like in MISO, how they allocate, you know,
basically like rocket costs,
based on anybody's deviations in real time,
from what they said they do.
So you know, there are some models for that,
but that would take some more work.
I want to say, without getting into a lot of detail,
it really is important to start the work
on long-term improvements where I think
the most important thing is real time co-optimization.
I have to put in a little plug for that
because it relates directly to this problem.
So in today's, or even in the 2017 fleet,
the market monitor showed and ERCOT showed that,
that has benefits more than the cost.
The benefits are multiples bigger in a future
where you have a lot more wind and solar.
And the reason is you've got more ancillaries.
You've got more changes between day ahead in real time
where you might want to buy more ancillaries.
You might want to switch, who's providing them.
And then you have way more deployment of the ancillaries,
'cause these aren't just for contingencies.
They're to manage day-to-day ongoing ramping issue.
So it becomes really important
to have real-time co-optimization.
Lastly,
I think the current products are good and they actually,
some of them are pretty, you know,
ECRS is pretty similar to some other ISO's ramping products
that they've developed for ramping.
I think in the long run,
there are some things you could do
to revisit the suite of products to make sure
you've got the whole suite that most efficiently
meets the ramping needs.
And that,
just even, for example, just coming to inform to RTC,
you don't need the, you know,
the duration requirements to be two hours on ECRS.
When you have RTC, it can be shorter.
Peter: Okay, thanks.
Sam: Last slide, actually, that's the end of that.
All I have left is,
is the ORDCs, and it's,
I think you've seen a prior version of that presentation.
This, what I have now adds three curves.
And then for each curve,
it also shows its effect on prices, costs.
And so it's up to you how much you want me to spend on.
Peter: Well, for the second time,
let's do questions on the presentation you just made
and then quickly move to ORDC,
and we'll move through that pretty briskly.
-: Yeah. And I'll do that one really briskly and use it,
just kind of let you all ask questions because it's,
it's so similar to what we presented before.
Peter: Okay. Questions on the presentation Sam just gave?
or we can- -: No, I got a question.
If all the industrials opt out,
is that 7% increase on costs,
reflective of how concentrated it will be on
the consumer at the small commercial and residential level?
-: The only way for all the industrials to opt out is if they
all had, you know, either curtailability or self supply.
And if they did,
that would sort of add a lot of capability to the system.
The cost too, I think that the increase for everybody
else wouldn't be concentrated on that.
It would look something like that.
And it might even be less than that
if the industrials all have that much capability.
-: Okay.
-: I don't think it's the case that all industrials have that
-: But would you agree that, isn't it the broad majority
of the megawatts consumed in Texas is our industrial complex
and those megawatt consumers,
again, this is volumetrically assigned on a megawatt basis.
If they opt out,
then in terms of supporting that 60 gigawatts
of dispatchable, you know,
that we're paying one way or another,
it's going to be concentrated on select consumer classes.
-: No, I don't think so.
I think it's on anybody who has a firm power
and whatever measure you're using too.
It does matter what measure you use to allocate it.
So if it's some measure of, for a given load serving entity,
their constituent customers,
peak loads during a recent measurement period.
So it's based on a notion of peak load
and it would be spread evenly among people who want
firm power and based on their peak consumption.
People who had more peak and want to be firm
is who it would go to.
I'm having trouble seeing a particular concentration.
-: Okay.
In the other areas of the world who have employed
any type of LSE obligation, do they allow an opt-out?
-: In effect, yeah.
Because I mean, they may not call it that,
but either through
allowing them, you're in effect, opted out,
if you're providing demand response,
cause then it's like supply matching your demand.
Or if you have self supply matching your demand.
-: You would have purchasing a megawatt.
-: Yeah. I mean, either way, they're not exposed.
If you know, they're not going to be exposed to,
you know, paying for something.
-: So, if they are purchasing any megawatt, they're still in.
So again, it's not like Occidental Petroleum
can opt out their facility.
Any megawatt that they're going to off-take, they're still
going to pay their share of the LSE obligation.
-: Are you assuming that they're not going to be curtailable
in there and they don't have self-supply?
-: Yeah. So the point is when they curtail either themselves
or whatever program that ERCOT has,
they're not buying megawatts off transmission.
So again, any megawatt they take
will have a volumetric assignment of an LSE obligation.
-: No. It's not volume metric. I mean,
you wouldn't want to do this based on megawatt hours.
It would be based on a measure of how many firm megawatts
you want during sort of that peak conditions.
-: But where, we would require them,
it's still the LSE obligation and their LSEs.
So we would require them
any megawatt that they're taking off-grid
to firm that up, right?
-: No, you wouldn't.
If they say, "Sure, I have been,
but you were conditions were perfectly adequate.
And so there was no reason for me to cut then.
But I've showed you that I'm curtailable,
so you really don't have to charge me for this product
and you don't have to add my load to the demand
in considering that firm."
So there really is-
Peter: That reduces the total cost of your buying.
-: It does, yeah.
Peter: So that cost wouldn't land on households.
-: Yeah, right.
Yeah. Not only would it not land on them,
it wouldn't land on anybody.
-: Yup.
-: Okay.
Lori: Can you please go to, I guess slide six?
There you go.
On the cost on bill,
I just want to make sure I understood.
So you're calculating the firm field product costs
on both options? It's included-
-: It's included in both included in both. Yeah.
Lori: Okay. -: Yeah.
-: Okay.
And then on the challenges
with respect to the backup reserve do not control
preparedness of entire fleet.
Is it fair to say that, you know,
we do have weatherization requirements that are applicable
to the entire fleet and if we have a firm fuel product,
they'll have to meet certain requirements as well.
So there's some back there.
-: Yeah, that's right.
Yeah. I think it's just that
there are other resources that, you know, probably,
maybe they'll operate reliably and they have incentive
to operate reliably certainly through the energy market.
But you're not getting from them a commitment
subject to additional penalties.
-: Okay.
-: And even your accreditation.
But when you do need to do some sort of accreditation
and option two, just to have
an accurate count to how much preparedness you have.
And so therefore how much backup you want to buy. Right?
But it's not at the same level as when there's money on it.
And then the LSE, I mean, you know.
-: And your version of the option two, did you, I'm sorry.
Did you include penalties?
It wasn't too clear.
It sounded like you may not have included penalties.
You did? Okay.
-: Yeah. -: All right.
Okay.
-: It doesn't add to the high-level cost estimates we did,
but yeah. -: Okay.
I think that's all I have right now.
-: Other questions for Sam on the first presentation
before we go to ORDC?.
-: Just one question.
According to this, they're only two opportunities here,
two options..
-: That's my opinion.
-: Of the ideas submitted to-date?
-: Yeah and also that we've thought through.
-: Well, then you have thought through.
-: What?
-: Because there were maybe seven or eight other ideas
that haven't been looked at.
-: That's not true, they haven't been looked at.
So a number of them are different variants of,
part of what have been showed here or sub-parts.
And some of them were not about this problem.
They were about the other problem,
about sort of, more of the operational aspects.
-: Thanks.
-: And then, there were some too that we considered
and thought wouldn't help resource adequacy,
or were kind of
had enough other problems that they really
wouldn't have enough market and regulatory sustainability
or economic efficiency, whereas these options, not perfect-
-: Did you model all those?.
So it's just kind of a gut reaction?
-: No
but this is, you know,
the nice thing about having looked at these problems
in lots of jurisdictions is,
it's a lot more than a gut reaction,
and it's knowing where things have been tried,
where things have been thought, you know,
having thought through these things before
and the implications.
So that is fortunately what we,
that's what we're able to bring.
-: So in all these other jurisdictions,
have you recommended anything other than a capacity market
or load serving entity observation,
or affirming option one, option two work capacity market?
Have you ever recommended anything else other than that?
-: It's kind of a difficult question.
You know,
I do such a variety of work and so many different
angles on this set of problems around reliability
and market mechanisms to meet them.
Of course. I mean.
-: The reason why I asked you the questions are,
'cause I wanted to make sure we've talked about this,
but I think there are a lot more things that we can do
to solve resource adequacy and operational responsiveness.
And I think having just two options here
is disingenuous to the amount of thought that
has gone into this, from market participants.
And I just think that,
that if we get the next presentation,
we go to have more on this.
We got to have more discussion about
more of the options and understand the costs more
and the implications more.
That's where I'm struggling that I haven't been able
to get my arms around some of these things
because I don't have that information.
And in a lot of things, a lot of the documents she filed,
it says that you've had a lot of discussions with ERCOT
on X, Y, and Z.
You probably had more discussions with ERCOT
than you have me.
And, I know we've been trying, but I just,
I want us to have a better
suite of options and maybe they're not.
But I think there are better suites of options
that can solve parts of the resource adequacy issue,
and when you add them up, you get to another,
another resource adequacy tool.
And I just, you know, a lot of these things,
I think take a lot of discussion and we haven't had a lot.
-: So,
I won't respond to some of what you said earlier
in your comments, but I will ask you,
what specifically do you think is not shown here
that contributes to resource adequacy?
-: Well, I mean-
-: And we can talk about why it's not on here.
That's my question. What is left out here?
-: I mean, I've seen lots of proposals by academics
in the west that have come out of our national labs
that deal with other components that
contribute to resource adequacy,
on kind of the demand side of the equation.
You know, I just, I don't see a lot of that.
Maybe it's in your model. I don't know.
But I want to be able to see it,
if I'm going to make a decision, you know.
The other thing is, as I said, as I feel
resource adequacy in the future is not driven by
1000 megawatt plants.
It's driven by smaller resources that are spread,
that have less contingencies on the system when they fail,
but more resources around the system.
And I think what these two,
I think there's value in some of this,
but I think all we're doing is taking yesterday's way
of defining the world in terms of huge capacity resources
and say, we need those for the future.
And I don't think that's the way the world is going.
I think it's energy related. I think it's reliability,
not on a seasonal basis.
On a monthly, on a weekly, on a daily basis,
because the way we certify resources is too broad.
And, in the end we don't need capacity.
In the end capacity does not serve
any customers in this state.
The only thing that does is energy
and energy is the valuable commodity here.
So I just-
-: Okay. Let me step in there for a second.
Brattle was asked to evaluate ideas that were submitted.
-: Agreed. -: And bring us the ones
they thought were the best of the ideas submitted.
They thought were the best ideas.
-: Okay. -: That's what I see up here.
-: Okay. -: If there are other ideas
and I understand there's, I mean,
the issues of communication frequency with the client,
we can take a ball flying.
I don't disagree with you. And that's, that's your call.
They were asked to submit ideas or what they thought
were the best of the ideas that were submitted.
-: And-
-: I understand why we're here.
-: That's what they did. -: Okay.
-: That's their selection.
If there were other ideas from the West
or on demand response, please bring them forward.
-: I will, I will submit, you know,
these other ideas to you and make sure that you have them
today, so that you can begin looking at them along with the
other ideas that the other Commissioners shot.
-: And I also want to say we have from the beginning
taken the approach and I know the legislature
has taken the approach of being a technology agnostic.
-: Yeah.
-: It's not up to us to decide if we need
large base-load thousand megawatt reactors
or small modular reactors.
It's our job to design a market that solves
that problem for us.
-: Absolutely.
-: And I would never presume to think
that I know what the future holds.
That's why we have the market.
And it's probably some combination of all the above.
And so I certainly,
I know the legislature does not want us
dictating what that should be.
-: I agree.
-: Sam, I apologize for coming at you like that
It's a little bit of frustration,
but it's a little bit of,
just seeing the same two alternatives that we've seen
for the last five months or four months or three months,
whatever it is.
And I'll take responsibility for not sending
these others to you.
-: I would like seeing it too. -: Yeah.
We'll make sure that everybody gets into that.
They'll be filed in the docket.
-: Recognize the communication frequency challenges,
and we can work on that. -: Absolutely.
-: Can I add a couple of observations, just one of them?
And it wasn't included, well, I guess it is option zero.
I think it's really important to be clear that,
it's not that we've done a lot and we're going to do a lot.
So even if, you know, in the interim,
we didn't move forward with, you know,
a longer-term solution like the LSE,
your option to backup reserves.
It's not that we didn't do anything.
We were going to do a lot, right.
With ORDC and firm fueling
and all the actions we've been taking.
So I wouldn't want the public to think that, you know,
if we don't move forward with one of those options,
one or two, or any of the other options, that you know,
Commissioner Glotfelty and Commissioner McAdams
will put forth that we have done nothing
because that was the point of my memo that I filed.
I really wanted to highlight all of the matters that
we've been discussing and the timelines of how they can be
phased in to provide more enhanced spectrum of reliability.
So I just want to be clear that the options zero
is not like we haven't done anything.
We've done a lot. We've been at it for months, right?
Looking at all these mechanisms that will help enhance
and improve reliability and operational reliability.
So just want to make that clarification.
The other piece to that, that I wanted to add,
and I'll delve more into, when I talk about my proposal
is on the option to backup reserve.
And that is just really that, you know,
it could be a long-term market enhancement
within our competitive market structure.
But it could also be a bridge to help us continue
to evaluate options that are on the table,
because all of them will take some time of, you know,
we've been looking at all these options
for a while now, right?
Some longer, some not yet and some just now.
So to buy us more time to evaluate matters,
it's I view it as sort of, you know,
either a long-term market enhancement,
or a bridge to help us maybe get some of these
consensus items in place and let them play out
and continue to evaluate longer-term solutions.
And that could act as a supplement to a lot of other,
you know, items we may consider.
-: Thank you.
-: Any other questions on-
-: Sam, an important question. If I may, Mr. Chairman?
Does this plan guarantee new generation?
-: Sorry, which plan?
-: His proposal, sir.
-: He's got two of them.
-: The LSE obligation. -: Okay. Option one.
-: Does it guarantee new generation will be installed?
-: I wouldn't put it that way.
I would say that,
you know, assuming that load grows and there's a,
well, assuming there's a need for it,
which I suppose there are even if load doesn't grow.
So I guess the answer is basically, yes.
You need to add resources for LSEs
to be able to meet their obligation.
There would have to be more accredited capacity
in the market than there is today.
How do you get more than there is today?
There has to be a new generation bill.
So I guess the answer is yes.
-: Okay.
-: I mean, subject to penalties,
if people aren't meeting them,
but those are INO. So they're, you know, it happens.
-: So on the LSE obligation, California, Australia,
and Singapore have LSE obligations. Is that correct?
-: No. -: Okay. Which ones do not?
-: Singapore. -: Singapore does not.
California and Australia.
-: Oh, and Australia.
It's I'm not even sure I'd quite call it that there is this
backup mechanism for,
for supporting resource adequacy.
-: Okay, California.
-: Yes.
But in a very different environment that has integrated
resource planning and not the kind of competitive market
that we have here.
-: Has new dispatchable generation been built
in a system that has a centralized resource planning
and an LSE obligation, to the point of California?
-: Sorry. What do you mean to the point of California?
-: Within the California model,
has new dispatchable generation been built since
it was imposed in 2001,
even with the attributes that essentialized
resource planning model and an LSE obligation.
-: Oh yeah. Plenty of generation was built
since going back to the time you said.
I mean the last several years it's been almost entirely
renewables and storage.
-: I asked dispatchable.
-: But before that, yeah.
I mean, I'm trying to remember in 2013 or 14,
it was primarily dispatchable.
The economics and the demand for the renewables
tilted everything that direction since then.
-: Okay.
-: When was the California market put in place?
What year do you remember?
-: Oh, well, which aspect? -: I guess the LSE part of it.
-: You know, I, it's hard for me to,
I'm thinking through the history.
Peter: Don't worry. Last week we've covered the fact
that California is a very different circumstance.
It's very different retail market and had a lot
of out-of-market state intervention.
So it's very hard to draw an apples to apples comparison.
We established that in the last work session.
-: I disagree. No, we are talking about taking state action
to overlay an LSE obligation.
This is what they did in the aftermath
of the energy crisis of 2004.
Peter: If you...
They'd also have a very different retail market.
They also have had the State directly invest in generation,
which throws the market out of whack.
If you would like a comparison or a side-by-side of how
Sam's proposed or his version of an LSE obligation in Texas
would work versus California,
I'm sure he'd be happy to lay that out for you.
-: I will need that. Yes, sir.
Peter: Okay feel free to ask for it.
-: The resources that are -: I am asking for it.
-: built, there are based on
integrated resource planning that sort of State directed.
But happy to do that.
-: What about SPP then? I mean, I think it would be helpful.
I think I know where you're going.
It's just sort of seed and none of them are
going to be exactly apples to apples, right?
They're all different.
And Texas would be different from California and SPP,
but at least to have an idea of what has the energy mix,
the new generation investment been renewables, gas,
since those markets were put in place.
-: I would barely say those markets.
I mean the investment -: Or aspects of the market.
choices in SPP have nothing, if little to do with market.
It's utilities making decisions what they want to build,
subject to approval by their
State Public Utility Commissions. It's not a market.
-: Vertically integrated utilities.
-: Yeah.
-: Right, right. So much different. Yeah with that.
That does put a whole different spin on it.
If you have, you know,
re linear rate of return that you're, you know,
you're investing in generation and getting to recoup
the rates from your customer.
So it's a whole different spin,
but I don't know if that would be helpful
to at least see a comparison of California SPP and MISO.
I know Australia just got theirs up and running maybe
this summer, so I'm not sure if there's anything there.
-: Right. Yeah. I mean, Australia is more comparable.
I mean, MISO is more like SPP, the vast majority of MISO.
Okay. I do want to mention one thing.
We were looking at these, I mean,
these are sort of the big picture options.
I didn't get into all the details,
but there are a million aspects of contributing
to resource adequacy that might not be
in the examples I used of which resources. So for example,
an LSE obligation that supports on an equal footing with
all other technologies, demand response, energy efficiency,
they participate.
In fact, in a place that has something like this,
but with a centralized capacity market to support VGM,
there's lots of, you know,
even residential level demand response activity that is
getting credited and that gets actually paid,
but you can do it the other way too. You're avoiding paying.
There are a lot of ways. It's in the market.
It's folded into this. I mean, option two when I said,
you know, the backup reserves, you could have a,
whether it folds into that or you have, I can do it too,
or in a separate or suggested, maybe the way of
demand response is different and ERS,
maybe you even have expanded program there.
I do think there's a lot that becomes interesting,
is more of the load becomes able to respond, you know
economically sort of automatically when their retail
provider enables that or a curtailment service provider.
There's lots of stuff.
They can fold into this if you allow them, but they may be,
you know, in a, in a sort of technology neutral way.
Obviously there are also things you can do outside of the
market, like energy efficiency, programs and stuff that,
you know, that was sort of outside of our scope.
-: Thank you.
Any other questions for Sam before we get to ORDC?.
-: None from me.
-: All right. Any questions for us on what we need?
Alright, thanks. -: You. Got it. Thanks.
-: ORDC.
So this I'm going to go through pretty quickly cause
you understand the prior version was circulated.
What we're talking about here again,
this is not about how to significantly
change reserves adequacy either.
We're really talking about three things,
especially when we talked about lowering the cap
and immediately raised the discussion of a wider ORDC
to make sure you're not taking money out of the market.
But it's a couple other things too.
One is to make sure you're sending
the strongest price signal before ERCOT declares,
advisories and alerts.
We've heard that pretty loud and clear that that's desired.
And especially as there are actions to do those,
some of those manual actions, even earlier,
even when reserves are not quite as low.
And we want to make sure that the ORDC
is consistent with that, getting to high prices
and drawing and market response
before you do those things that are costly.
So the third thing is,
that since ERCOT has increased the amount
of ancillary services,
partly to deal with variability,
partly to stay away from the alerts.
You need to, that's actually just a day ahead thing,
to also have a comparable amount of reserves
in real time, you have to put that demand in.
And the only way to do that without RTC is within the,
ORDC, sorry for so many acronyms.
But so anyway,
that merit to a wider curve in those circumstances,
and what I'm gonna show here,
that's different from last time is just adding a few new
curves that were requested by the Commissioners.
And then for each one, we actually, you know,
the trickiest thing in this analysis is to, you know,
not just put in the place and say, "What's the price?"
You actually have to model the behavior of generators
if you're putting in a richer ORDC and there's generators
that could come online and enjoy the online adder.
You have to model, how do they do that?
And a straw, a,
it did the modeling and we've iterated with them
to make sure that that's realistic.
And when you do that,
the wider curves add, they bring on more reserves,
they don't, you know, just raise the price.
Now they bring up more reserves
and that moderates the effect.
Peter: By bringing more reserves on sooner, you're
getting to the highest higher price point less frequently.
Sam: Exactly. Peter: Okay.
Sam: Thanks. Okay. So if you could go to the next slide,
and this is just a picture of the curves we looked at.
And the three at the bottom of the table are the ones
we added here and for your reference and we'll file this,
so you can review the specifics.
Go onto the next slide please.
So one of the purposes was to get the price up to the
highest levels before getting to the cap,
sorry, before doing advisories and other any out-of-market
actions and several of these curves do that,
especially the ones that put the minimum capacity level at
I'm sorry, the MCL at 3000.
They obviously do it. There are a couple other curves.
They would generally tend to do that as well,
even though they don't have the MCL at 3000.
But so we'll probably focus on
some of those curves that solve that problem.
If we go ahead to the next slide.
So then the other problem is, you know,
which ones avoid having to do a lot of RUCs to support
real-time online reserves consistent with
what we're doing with ancillaries.
And there are about, you know, 4 curves in that sweet spot.
It happens to be, they have a lot of overlap
with what we looked at on the prior slide.
You know, I guess if anything,
I'm probably partial to the gold curve,
seems to be about in the, you know, a decent one, you know,
or maybe a version of the gold curve that maybe even go to
4,500 cap, but raise the ball so that, you know,
the market monitor has made a point that I agree with it.
It'd be nice if you didn't have that strange step, you know,
with the price jumping at MCL,
maybe achieve it that way, but something in this ballpark,
ballpark at the gold curve maybe,
go to the next slide.
This just shows, what if you impose
this on a market like, you know, 2019,
well, this is with the 2024 fleet, but with 2019 weather.
It's sort of a static look where you,
you do change the unit commitment response to these curves,
but without varying, without changing investment.
And you know, obviously if you're not allowed to,
if this is right in the short term,
investment doesn't get to respond.
You have some much bigger price differences in some of the
wider curves, richer curves but
put quite a bit more money in the market.
And the top right is how much a combined cycle would earn
on the left under the current curve.
And the reference point
is sort of levelized cost of a new CC.
And, you know, at least under it with a 12% reserve margin,
we modeled in 2019 weather.
Number of these curves would get you even
over that threshold or else equal.
And if you go to the next slide,
you do actually expect investment to adjust, right?
You keep this in place for,
why people keep their resources online or build new ones.
And so if the market equilibrium reserve margin,
where, you know, there is an equilibrium,
because if you added more capacity, depressed prices more,
and it wouldn't be worth investing anymore, for example.
And so we simulate each curve with investment up to the,
you know, where the marginal entrant
is just earning its cost of return on enough capital.
I think people probably wouldn't want to do a curve
that takes a lot of money out of the market.
That's going to give you less investment, less reliability.
So if the current curve would give
a market equilibrium reserve margin around 13.8%,
the way we're counting it.
there are several curves that are pretty close.
For example, the gold curve just slightly below it,
or wait, sorry.
I know I can't quite see that,
the current if that's 13 point something.
13, what is it? One five, yeah.
So, you know,
the gold curve is only just a little bit behind that.
Again, if you did it with a higher vol,
but kept the price cap the same,
that might be better for a few reasons.
Something in that ballpark,
I think would serve the purposes.
As a reminder, this doesn't solve all of the
resource adequacy problems.
As another reminder,
even those resource adequacy solutions that I talked about,
they give you a resource adequacy.
They don't guarantee delivered reliability,
particularly under conditions that, you know,
you didn't anticipate or part of your accreditation,
or whatever, but those are the disclaimers.
Peter: Well done.
Anything else on that?
Okay. All right.
Any questions for Sam on ORDC presentation?
I know we're all in the process of considering it and we'll-
-: Thank you for doing it.
Thank you for getting the numbers in there.
I appreciate that. -: Thanks Sam. Appreciate it.
-: All right. Thank you, sir.
-: Thank you.
-: Laid out a lot for us to consider
and a lot of work went into it.
-: Thank you. -: Thanks. Appreciate it.
It brings us to the next segment of our program today.
Tools on operational reliability,
including ORDC, ECRS, FRS when affirming product ERS
and voltage support.
I know Commissioner McAdams filed a memo on that.
So if you'd like to lay that out,
that'd be a great starting place for.
-: Yes, sir.
As instructed, I just tried to do my homework
on the phase one.
Mr. Chairman, what you challenged us to do on that.
So on ECRS, well, I'll stand by my memo on all of it.
I tried to be as explanatory as I could.
Peter: I think so. -: Yeah.
In terms of sizing, I just took a swag.
Okay. We've all been having conversations with ERCOT
over the last six months, leading up to this
on what their base needs might be.
I would submit that my two gigawatt number
didn't just come out of thin air.
It was based on where RRS had started and we've even
scaled up from there on a responsive reserve service.
Now, obviously as my memo alluded,
we need feedback from ERCOT.
It needs to be balanced according to the auction,
the near term auctions that we'll have
going into the winter.
Those will be telling on what we need
that certainly applies to emergency response service,
which is not an ancillary service, but as we adjust it,
how to orient ourselves, once we get into the winter.
And how much the market will tell us
is the cost of this new enhanced tool.
It's my rambling way of, you know, bouncing around
this winter firm fuel ancillary service thought.
Sam's feedback was very good.
I'm glad to have a ballpark of what we're talking about,
where we're going to drive to.
But again, we've got to start somewhere.
It's gotta be scaled up.
There's a maximum amount of onsite firm fuel
that we know of on the system right now.
So I kinda took that into consideration as we were,
we were looking at this.
The cooperatives have it.
I know that our competitive gym fleet is now looking at it
seriously and starting to talk about numbers that they're
going to dedicate to it.
I know that new pipelines are being considered right now,
depending on this new service that will help provide
certainty for those firm contracts as we evaluate
what firm means.
Table set. I'll yield back to you sir.
-: Thank you for laying all this out
and digging into this issue.
I think I agree in principle with direction you're going.
I know, and this is an excellent opportunity.
I mean, we've made as Commissioner Cobos
said the ERS changes.
That's a substantial change to the way this market operates
and the way we provide reliability.
And you may have a very good point that we're going to get
some real honest market feedback-
-: Soon. -: very soon,
which will, as you said,
be an excellent way to inform how we move forward with it.
It's worth what the market says it is.
-: Right.
-: So that will be a good building block to work from the,
and in terms of the procedural path forward,
these are all excellent examples of,
I think things that in December we need to,
we need to make the decision to include
or not include in our blueprint.
-: Okay.
-: Especially the winter S, that's a completely new product.
But we don't have to pick exactly
the quantity on December 16th.
It's a big decision just to build a new product.
-: Okay.
-: So this is a great foundation.
I mean, I think we generally are in support
of a winter I S product, but that's by way of example,
December 16th is a thumbs up, thumbs down.
If it's a thumbs up,
then we've got the next three to six months to figure out
exactly and work with ERCOT to figure out exactly
what it should look like. -: Got you.
-: This is an excellent start.
Any other questions or comments? Go on.
-: Sure.
I'll just kind of walk down each item
with respect to the firm fuel product.
I strongly support creating it
and I think we have consensus on that.
From my perspective is I was looking at
some of the questions that you asked us to look into
Chairman Lake.
I guess, starting with the type
of technologies that we would want to look at.
I spent a lot of time visiting with
a variety of stakeholders and others about this.
And from my perspective, at this time,
I would structure the firm fuel product to focus
on on-site fuel storage and offsite fuel storage
with firm gas contracts
or control over the transmission pipeline.
I would not go as far as firm gas contracts, cause that's
an added level of complexity there that, you know,
we would have to kind of Zoot get language and contracts.
And I'm not sure how successful we would be
in getting some of that language in there.
And that's just some,
I think the firm gas contracts are what the generation
companies themselves have a responsibility to do,
just to be available and capture the prices
and not pay performance penalties.
So I would move firm gas contracts off.
I would also move dual-fuel capability off the table
because it's, from what I understand is very expensive
and most generation plants that had that capability
got rid of it because ERCOT wasn't paying them.
So again, I would just focus
on on-site fuel storage and offsite fuel storage
with a firm gas transportation contract,
or control over the transmission pipeline to the storage.
So that's the bullseye.
That's what I would focus on, with respect to procurement.
I think this could be done how
ERCOT currently procures black-start.
So through a competitive RFP process,
and I think ERCOT should hire a consultant
to verify that those offered products
or generation units rather,
can actually, you know just to make sure
they can actually provide this product.
To help with testing, we'll want to have them tested.
And it makes sure that there are cost-effective solutions
or offers into the competitive RFP process.
A multi-year contract, I think probably two years as well.
I think that's what Brattle recommended quantity.
I think, you know, Commissioner McAdams,
you made a very solid point.
From the statistics that I've drawn up, there's about,
you know, 33 generation units out there
that have about 2,866 megawatts of onsite fuel oil storage
right now that are primarily owned by the electric co-op's
and maybe some other generation companies out there.
So if you look at what's out there,
just a little bit under 3000,
and then you look at winter storm Uri,
I think Sam makes a point
and it's a huge amount of megawatts.
But the statistics that I have looked at,
that ERCOT has provided me based on the RFIs
that they sent to the generators after the storm,
is that the fuel availability issues,
that specific bucket that they got was 6,130 megawatts.
And then if you look at the reports that,
and that probably is a more accurate figure
because where I went to look at was in project number 51617,
where ERCOT filed the reports after the winter storm.
And that ranged on issues with fuel.
It ranged from about 6,700 to 10,000.
So I know we're not deciding megawatts right now,
but I think from a matter of prudency and also
looking at this from a cost conservative basis
and just starting somewhere,
I think that's what you're saying.
Right now, I think you'd want to capture
that just under 3000, that 2,800,
and then add at least some, you would want to
add more megawatts to at least reach some threshold around
that 6000, 5000-6000, at least.
-: Agreed. We don't want to just pay the existing assets.
We got to put money out there for additional
firming capability and we can't get there overnight,
but that's where we need.
I agree that that's where we need to work towards.
-: Absolutely. And I have heard it myself as well,
that there are some stakeholders out there
that really want to be part of the solution,
that want to be able to help with the firm fuel product
and would be wanting to help, you know,
add those additional megawatts.
In terms of how many days, 2011, from when I got from ERCOT
was sort of a two day issue,
2021 in terms of fuel unavailability
was sort of a three-day issue.
So you'd want to maybe plan for two to three days.
Payment. You know, I don't have any specifics on there
other than that you'd obviously want to pay them
for fuel and operation maintenance expenses.
Cost allocation, it sounds like load ratio share basis.
I know we don't have to figure it all out,
but that's kind of, as I went down
the suite of key decision points,
I wanted to just bring that information and let you know
kind of where I was right now.
And we can continue to refine it
as we move forward to December.
But that's where I'm right now.
I've spent some time looking at it.
-: Similarly, it's an excellent foundation to build on.
The big decision in December is thumbs up, thumbs down,
and we can build off of the numbers you all have laid out,
to put a finer point on it,
so it'll be ready for next winter.
-: Absolutely. -: But this is,
these are the kinds of big steps that,
move us in the right direction and move us to new solutions.
So thank you for putting pen and paper on that.
-: ECRS.
I too have been having discussions with ERCOT
and I would like them to continue to refine that.
I know Brattle gave us some megawatt numbers.
It's very helpful to understand that because
from my perspective, with the proposal I put out there,
what I'm trying to find with the SRS product,
the strategic reliability services,
that hole that may not get filled.
And that hole that may not get filled is contingent
upon how much we have in all our buckets, right?
How much we have in our ancillary service buckets?
How many megawatts?
And I think as you sort of look at ECRS,
I think ERCOT should continue to refine
their solar duck curve analysis,
and also refine their figures.
And I know that, I think I mentioned this last time and,
you know,
SB-3 requires that ancillary service study be looked at.
I know we've gotten some money allocated to the agency to do
that and I think we should continue as a matter
of due diligence to really zoom in on that number,
so we have a real clear picture.
In terms of cost allocation,
I think Sam raised some good points.
You know, we've got SB-3,
we've got language in there that talks about costs causation
on a non-discriminatory basis.
I think we need to have a rulemaking.
I think we add that to our blueprint,
that we're going to have that and continue to work through
that issue to ensure that we follow as SB-3.
And
we can get more information from ERCOT in that project too,
to help us really craft a well-rounded
equitable solution there.
ERS.
I agree.
We're going to get some good information after the winter.
And we should add that to, my opinion,
that can be added to the blueprint in December.
Until we don't have to come up with all of the answers.
Then we can maybe lay out what some of the
major policy questions would be to look at, you know,
how we will procure it in the future?
Is it megawatts or on a dollar basis?
We've already have an order granting ourselves
a good cause exception deployed earlier.
We can memorialize it in the rule.
Also just to keep in mind that, you know,
we did take a little bit of money
out of the summer for the winter.
My best guess is about a million.
So we wanted to sort of replenish that, you know,
we would want to have our rule done by late April, early May
so that we can meet the summer RFP.
-: Agreed. And we can work with the New York hot board
to manage the budgetary side of that.
-: I think those were your three main assignments,
but I know we have to talk about ORDC as well.
-: Yeah.
And yes, thank you for laying all that out.
As I said, great start on big steps forward.
I don't expect Commissioning Glotfelty
has some thoughts on cost causation as well as some others.
-: Nothing, no. Nothing that hasn't already been said by me.
-: Any thoughts across the board?
-: Listen. I mean,
I think both of them have laid it out very well.
These are kind of what I fall
into the low-hanging fruit category. We got to do them.
-: No low hanging fruit. Will: No low hanging fruit.
It's important.
Lori: I'll pull up my ruler -: That's right. Sorry.
There are,
I think some of the details that we've got to work out,
I'm beginning to get a little bit nervous with
what we're doing with firm fuel on plants,
and it's just been kind of hitting me that I'm a little
nervous about water too.
So an interdependency on the other side,
you can't run a power plant without fuel
and you can't run a power plant without water.
-: You can't run a water plant without a power plant.
-: So that's not part of this, but I'm just,
I'm trying to think of these interdependencies
and, you know, how they look that might be part of,
you know, something else going forward.
But I think, I think both Commissioners have, you know,
tried in the sweet spot of where we need to go.
-: And rightly so to think about those interdependencies.
And as we,
if we decide to include this kind of thing in the,
in the blueprint in December,
there's obviously there's a lot of nuances,
even within cost causation, as Sam pointed out,
and we can work through all those things.
But also on firm fuel, there's very much
agree with your point about the firm contracts
can be so nuanced that it's kind of productive to
try to decide for that,
but we will also need to dig into firm transport versus
firm supply and consider attestations, or, you know,
we'll have to take a deep dive in all of this.
We don't need to solve it by December.
It's just making the thumbs up or thumbs down
going forward with these new developments.
You know, the thoughts on, I guess,
the short term solution, including-
-: No low hanging fruit.
-: Short term, immediately actionable decisions.
Lori: You needed a ladder to get to the fruit, okay?
-: Thoughts on ORDC?
Will: Am I going first?
Man, How did I get in this?
Lori: You like setting the table. You do such a fine job.
-: It's true. That's what I told my daughter.
Okay.
Yes, sir. Mr. Chairman.
So with,
with the scenarios that Sam was kind enough to run for us,
on the tail scenarios, again,
I have concerns with modifying standard deviation
or elongating the tail.
And it is because half of what we're trying to do here
is normalize the world with various super competitive,
super competitive renewables coming in.
Long tail means renewables get a lot of good money
as a part of the ORDC.
So in order to, as a policy decision,
I would assert that we need to help manage that
as much as we can in the near term,
by not incentivizing them any more than
we have to right now,
even though there are good resources.
Peter: More than the avalanche of money from DC?
-: Yes, sir.
Well, you said it and that's right.
So I have really focused in,
on those curves without the tail, that again,
we discussed at that the referenced workshop.
I'm keenly interested in a 2,800 MCL
and a 6,000 involved because it looks like
on a loss of load event probability, or on Sam's data,
that we're right in a very tight ballpark
of where the current curve is.
So in terms of adjustment
that the 6,000 still gives ample
load resource response pricing signal.
Peter: Is that just vol, or vol and high cap?
-: Vol and high cap? Peter: Okay.
-: Yeah, I think about and carries here.
I think about trying to explain vol 20,000
to the legislature and the greater public,
but you're smarter than me.
I mean, you can take a straight down.
Peter: Start with your neighbors before
you get to the legislature. -: Right.
Peter: We'll list some opinions.
-: Can you imagine that sunset hearing, when you're sitting
there just trying to justify the existence of the agency
-: I don't think we'll survive -: and I ask you about vol 20.
-: through sunset. -: And anyway,
that's neither here or there.
6,000 is a still a strong price signal
for load response to behave accordingly.
2,800 still gives us room as per my memo,
indicating if ERS was to deploy the loss of a peaker
would still trigger that in before EEA,
you know, or something like that.
So envision a world where the nukes are running.
Our coal is there, we're matching it.
And then some 250 watt peaker gives out. ERS can snap in,
and we still don't go into a conservation notice.
Peter: So between the 2,800 and the 3000 MCL,
is that, you just fill in the gap with ERS,
or is that, what's your thinking there?
-: No sir. The 2,800, because again,
I was trying to hit that cone,
where you still have the cone, "cost of new entry"
being achieved in terms of the scenario.
-: The only observation I have,
and I know this is kind of a moving target sometimes with,
you know, based on our ERCOT's price,
but maybe ERCOT has some input.
But based on my discussions is we are trying to utilize
these tools like ORDC and ERS,
and even the TD voltage reduction program or measure
before we get into conservation, right.
We're trying to even avoid conservations now.
So if that is the case,
then I think ERCOT's conservation,
at times has gone below 3000 during the summer.
It's kind of where I got,
I've gotten two thresholds from them.
I've got 3000 and I've got 2,800.
So that's the only thing that I want to,
kind of put in the background.
And that is the goal is to bring these resources online,
to avoid getting into conservation.
At least what I understood last from the trigger was
when you fall below 300,
that's kind of the discretion they've been using now.
So I know that can vary from, you know,
just high data tie date, but-
-: Yeah, and I think it's an important principle considering
while vol's tricky, we don't necessarily,
they don't have to be perfectly matched.
You can, if we want to have a high cap is a little lower,
but still increase the slope of that curve
with a different valve.
I'm certainly open to that.
Regarding the MCL and your thoughts on the conservation,
I don't know what the right answer is,
while we're going through this process.
But my logic so far has been
or my logic on the 3000 was I think, at 2,800,
that's where you get to a NERC mandated emergency status.
And the, so just philosophically,
I think I would want to make sure that we have,
as Will said, all the resources in our ecosystem,
generators, demand response.
We have all of those,
the price signal is there for all of those resources
to be brought to bear,
before we start asking Texans to power down their lives.
I don't know what the exact number is,
but that was my logic on the 3000 versus 28.
Will: So I'll tell you, I have a runner up.
I have a number two.
3000 MCL and 5,000 vol is next best.
-: Lori, do you want to ask Kenan to come up and,
or Dan, whoever's appropriate to answer the reserve
or the trigger points as we get to decreasing PRC?
Dan: I guess,
we're mandated to,
as per conservation when we get into EA two.
So whatever that was that be.
But as far as issuing an advance, we've set a-
-: Sorry, mandated by? Dan: Mandated by NERC.
-: Okay. Not the board, not something that we know.
Dan: No, by NERC. When we get into EA two,
we have to ask for it then.
Will: But, we can sit? We can sit EEA two.
Is that correct?
Or is there, do they have a hard and fast number?
Dan: No, I think we can, we can adjust that.
And then as far as if we were to ask for conservation
in advance of that,
that's completely discretionary as to when we would do that,
or not.
-: Where are those set now?
Dan: Well, what we've been doing,
well it's changed over time,
but what we're doing right now is,
if it looks like we're projecting that we're going to be
below 2,800 off everything being used,
all the resources being used, then we would
talk to you guys and others about whether
it is your conservation in advance.
-: Okay. And that 2,800 is a change from this time last year.
-: Correct. -: What was it before?
-: I don't know that there was a hard and fast number.
-: More art than science. -: Yes, sir.
-: Okay. So thank you.
-: Any other questions?
-: Thanks Dan. -: Appreciate it.
We don't have to solve that number precisely today,
but we do need to get there pretty quick.
Will: The next time right? We kind of need to have them-
-: Yeah. And we'll, as we've done, we'll look for,
I guess you put it well at option one and option two.
Will: Okay.
-: And my office can coordinate with your individual offices,
and as we did the first time around,
incorporate everybody's feedback and
bring some, I guess, final options to the table next time.
Does that work?
All right. Any other thoughts on ORDC?
Lori: Not for me at this time.
-: All right.
We're dangerously close to the lunch hour, I think.
Is there anything else we want to cover
in the short term immediately actionable changes
before we get to lunch? Anything else?
I know we've got,
Commissioner McAdams has a memo on proposal.
And I know Lori also has one,
so those will be big topics to tackle after lunch.
Will: I will stand by to be the (indistinct)
-: Appreciate your willingness to step forward. All right.
At this point, we'll recess until 12.30.
(loud thud)
This meeting of the Public Utility Commission of Texas
will now resume.
We have reached the point of our agenda
where we're going to address the longer term,
more substantial structural challenges
for resource adequacy.
We've heard from Brattle extensively so far,
and I'm sure we'll have some questions for them
as we continue through the afternoon.
We have some new suggestions from both
Commissioner Cobos and Commissioner McAdams.
And Commissioner McAdams was the first one to file.
So we'll start with you. -: Yes, sir.
-: Please lay that out for us. And we'll go from there.
-: Okay.
In an interest of brevity and saving time for questions,
the memo was somewhat detailed in articulating a framework
for a dispatchable portfolio standard.
Which as the memo alluded to,
could be mirrored after the renewable portfolio standard
articulating a system of acquiring
dispatchable generation or incenting dispatchable generation
to be built within the ERCOT system.
I won't bore with all the,
stipulations of the framework that are in type on the memo,
but I will cover key points.
And I want that to be a starting point for,
Peter: Please. -: for consideration.
With the dispatchable portfolio standard
and the accompanying dispatchable energy credits
that could result.
We as a Commission would identify a need.
What is our target for dispatchability and dispatchable
generation relative to growth within the ERCOT system?
Again,
this has been somewhat of a moving target over the years,
and hotly contested from reserve margins,
capacity market debates, you name it.
We would have a good faith process to determine,
all right, what do we gotta have?
When do we have to have it?
How does that relate to the near term forecast
of growth in the system?
We then establish a performance based incentive.
That's the dispatchable energy credits.
Mr. Chairman,
it's not universally different than a LSE obligation.
Again,
you're imposing a requirement on load serving entities.
We would then narrow the scope of the qualifying generation
to next generation technology that would qualify.
Again, new steel in the ground.
And that is something I absolutely want to discuss with this
Commission, with this group, of the performance standard.
Because again, that will be hotly contested and litigated.
We would then create a market mechanism
through this clearing house,
through this obligation while allowing optionality
for loads and resources to continue
on a bilateral option track,
or go through a clearing house
or incur the penalty of an ACP.
This creates a market and a mechanism that sizes itself
over time as more dispatchable generation becomes qualifying
for decks, the value of the decks go down.
Peter: Is it the size or price?
-: Again, you set the percentage of what you need, and-
Peter: That would never be a self setting. That would be
-: We do that. Peter: set centrally.
The price would be self-correcting.
-: Yes. That's right. -: That's what I meant. Okay.
-: The value determined by the
amount of debt qualifying generation that's out there,
setting that market price.
That limits the overall impact to consumers
and has a future limiting effect on the program itself.
I know there is great concerns of a potential
distorting effect on price formation in the ERCOT system,
and especially on the realtime price, because again,
depending on where these decks are valued at,
they're going to be coming in at that,
I have heard it asserted a subsidized value.
But again,
if you get steel in the ground and the value goes down,
then you're kind of right there with everybody else.
There's a limiting characteristic of the program.
I do want to point out
that this is a performance driven incentive,
meaning that you have to produce power
in order to get a deck. Okay?
So nobody's getting paid to sit there.
You're still participating in the lucrative and that
the lucrative systems of the ERCOT realtime
and they had market,
you still could perform ancillary services.
But the old generation still gets the two revenue streams
that they get today. They get realtime price, ORDC adders,
responsive reserve service qualifications,
non-spin reserve service qualifications,
ERCOT contingency reserve service,
winter ancillary service, and voltage support
that are envisioned in this potential blueprint
that we could adopt in December.
And so with all that, we have to take into account,
"Okay, well, how soon could you see this new generation?"
All right?
It's just not all going to pile in at once,
but one of the key attributes of this plan
is it incentivizes timely deployment of the steel.
Those first to market, get the gold.
And once more pile in, it dilutes the effect
and there's that self-governing aspect.
So those are the points of the front end.
I want to make sure that it's out there for the public,
for stakeholders.
There's a lot to debate here. There's a lot to analyze.
I hope that this survives immediate scrutiny,
and we have time to discuss this further
with the rest of the market participant community,
able to engage and tell me where I'm wrong.
With that Mr. Chairman, I'll yield back to you, sir.
-: Thank you. Nicely laid out. A lot to consider.
And as we know,
this is certainly not a day for decisions
and even procedurally as we get closer to December,
it's the big questions.
Thumbs up, thumbs down, do we do? You said something.
You mentioned, this is something substantially similar
to an LSE obligation.
-: Yes, sir.
One more condition. If I could, sir, at the front end,
this was not my complete idea, okay.
So I am protecting the innocent by striding
stakeholder input into this proposal
and getting it out there so we can debate it, but-
-: I bet we can sniff them out.
-: Yeah. And I think they've talked to everybody, but anyway.
Just a disclaimer.
-: Fair point.
But,
and a chance to highlight that procedurally
the December decision is thumbs up, thumbs down.
Do we want to do something for me on the firming side
or on the generation side.
We want the money to come from that side.
We want coming from some version of
a LSE obligation that would include this.
I would say that's in that bucket.
We don't have to figure all of that out on December 16th.
We've just got to put a flag in the ground and say, that's,
this is the path ahead.
This is the course we're going to chart.
So thank you for laying that out.
And thank you for working to bring
additional new concepts into the conversation.
I very much liked the concept of,
and I know this has been very quick and very high level.
So I don't think anybody should expect
detailed answers on every element. Is that fair?
Will: I welcome that.
-: Well, I'm trying to protect the innocent.
So, and I certainly like the principle that seems to be
enshrined here of providing market incentives for exactly
what we need more, more precise tool than a cleansing tool.
So I think that's certainly a qualification.
Two, two quick questions would, and I know we don't,
we don't know that the doing all the details yet
would in principle,
I know the performance metrics are a work in progress,
a moving target, if you will.
In principle, would you anticipate something like this
being able to include hydrogen, biomass,
nuclear, basically nuclear SMRs, nukes,
or is it very specifically gas?
-: So the reason I put the stake in the ground on
the performance measures that I did,
one, there are very few units on the system today
that would qualify.
So again, I was trying to put a framework of a technical
specifications that would ensure new steel and did it,
the effect was not diluted by the universal application
to what we have today,
even though it's very important to maintain those units.
I think that is something we need to discuss.
And I also didn't want to freeze the market for anything
that is coming in today, if you know what I'm saying.
So those projects that were envisioned to be installed,
I want us to have a discussion about what that looks like,
so that if they can fall up under that umbrella,
we can assess this.
Peter: I guess the second part of that question
on the performance standard.
I guess the penciled in version,
let's say original proposal is five minutes.
-: Yep.
Peter: Would that cannibalize the ECRS
or sort of double qualify the same units?
-: I believe ECRS is a 10 and 30 minute product
as envisioned today, sir.
So no. These would be, if those are flexible units,
we're talking super flexible units.
I mean, rapid responding, work zillows
and latest generation peakers.
Peter: Right,
I mean, it's the cannibalization question is,
if I'm planning on building a 10 minute one anyway,
I can tweak the engineering a bit and make it a five minute.
And I get both ECRS and-
-: In answer to your question,
the deck program is not an either-or.
That's the beauty of it.
You are participating in ECRS and you're issuing that deck.
So you're not cannibalizing any of the tools
that we are currently discussing.
-: Good.
The only other question I had was around the
dispatchability or the dispatchable requirement.
From what I understand, you don't earn a deck
unless the unit's dispatched.
Is that correct? Will: That's correct.
-: Which in principle very much like,
we're paying for simply power that you used.
How would that work in the anticipated wave of wind
and solar that you correctly referenced many times,
as the penetration of those intermittents,
the zero marginal costs or heavily subsidized,
not zero cost, but the,
the front of the stack as the penetration
of those intermittents increases and increases dramatically,
as you correctly anticipate in the absence of action.
How would an investor know that the unit would be dispatched
in order to earn the decks?
-: Meeting that very rapid decline on a duck curve.
And again, that's where that performance value comes in.
Those less than five minute ramps,
can help check and arrest those falls.
So they know that's going to occur on a daily basis.
And they know that wind will fall off periodically causing
scarcity pricing conditions as in our blue sky event
or gray sky event, as other filers have identified
that problem.
So the amount of intermittent penetration into the system
will only enhance and exacerbate those scenarios
that require,
and send a signal that this is the type of generation
that will be needed anyway.
And the deck will help put them over the top
because they know that that is a third revenue stream that,
that facility could experience.
Peter: Under that construct that they would
only expect that maybe an hour or two a day.
-: Yes, sir. Peter: Okay.
-: Potentially, depending on the breaks. Yeah.
-: Okay. So it's a similar investment model of,
I make my money an hour or two at a time,
not on a kind of higher utilization factor.
-: But if it's every day or something like that, you know,
where we, again, that that sun drops off
and if that wind did in there,
it's going to be a very profitable day
plus decks included for that facility.
-: Okay. So I mean,
what our experience in summer has been about once a month,
we get into those really tight conditions where we're
on the edge. So it'd be a couple hours once a month.
Will: And in case it will-
-: I think it's more that that,
because if you're dealing with ramping,
if you're dealing with resources
that will help in the ramping issue,
there'll be there every day.
There'll be in the market every single day helping solve-
-: If there's a split between that solar ramp and the-
-: Right. I mean, that's, that's ECRS, right.
Will: And that's where they-
-: I mean, ECRS isn't built,
it's not intended to use every day.
because on average,
it's the average we're challenging, right.
On average, depending on the time of the year,
as solar goes down, wind picks up the slack.
That's the perfect-
Will: It's the perfect world that the resources perform-
-: We know that it doesn't happen that way.
So I'm just, I'm trying to get a sense of what,
what this would look like in a pro forma DCF.
That's helpful. Thank you.
Any other questions or comments?
-: Commissioner McAdams, thank you for laying this out.
Certainly very creative proposal that I think,
I guess the first question I'm going to,
and I know this has come up
and I know you laid it out in your memo.
I think one of the first questions that,
that I think may come up is do we need legislation?
-: Correct.
-: And I know you laid that out.
Can you kind of talk a little bit about that?
-: Sure.
As it applies to the powers enshrined in Senate Bill 3,
I would look to the new para 39.159.
The Commission shall ensure that ERCOT establishes
requirements in the section to meet the reliability needs
of the grid. And this includes a reliability service.
I would argue that the deck program,
it is exactly the type of reliability service
that ultimately helps growth.
That meet the growth and demand that the legislature
contemplates and what are we going to need
to meet periods of low intermittent resource output.
-: Okay.
Okay. So consistent with SB-3.
So SB-3 would provide the foundation.
And the only reason I asked you, I mean,
that's a question that's come up
as I start to evaluate the issue,
and I know maybe some stakeholders have that question.
You laid it out on those boards and trying to, you know,
I think one of the points that's come up is, you know,
the right training program specifically laid out in statute
in detail. And so that's why I think the question's come up.
The second one-
Peter: So you're concerned, there's not
statutory authority to implement program like this?
-: I'm just wanting to make sure that we, you know,
I understand his basis for it.
I mean, I'm not saying yes or no.
I think that's a question that's come up
because it is specifically set forth.
The right training program or existing ERCOT training
program is specifically delineated in statute.
So I think that's one question that has come up,
at least in my preliminary discussions
with this type of concept.
And so I'm not saying that we need legislation or,
or we don't, I'm just kind of just exploring.
Peter: We better figure that out pretty quick,
or we can save ourselves a lot of time
and just get ahead to the next legislative session.
-: Well, I just, you know, I want it to just sort of,
that's the initial question we must ask.
And so, and, you know, Commissioner McAdams
has his position on that and that'll be something
that we can do to kind of go along.
But second piece to that is,
I think you've said, you know,
criticisms are too small that the program
would focused on a subset of new generation.
-: New generation.
-: And is there a way I think you're
open to kind of opening it up a little bit more on that?
-: I am. Well, we need, and so,
we're starting to have comments filed now.
WattBridge has filed comments.
We need to know the universe of the type of generation
that again, constitutes latest available
new generation technology that is best for the system.
And so-
Jimmy: Next generation. -: Next generation technology.
And so look, I am not an engineer.
I don't think any of us are,
we need to talk to some engineers
and ascertain what's the best qualification
that we can put in place on this,
similar to LSE obligation or any other proposal.
We've got to figure out the accreditation
for what we're going to pay for.
-: Okay.
The other aspect of your proposal that I know,
it's come up a little bit,
is the alternative compliance payment.
-: That's correct.
-: How can the other concerns that, you know,
LSEs would go ahead and just opt out and pay the payment
and sort of would defeat the purpose of increasing
the investment because they get,
then that money then goes to load to reduce
costs of ancillary services.
-: Well, we get our ancillary services paid for,
and I consider that a benefit to me.
-: The roaring costs on the AAS, which will carry more-
Peter: So to make sure I've got the flow of funds, right?
So the noncompliance or the -
-: ACPC
-: In event of an LSE, does not procure the decks,
they're obligated for,
they pay a penalty that goes into the ERCOT hopper
to offset existing ancillary services
or to procure additional ancillary services
to offset that decks that weren't procured.
-: No,
it would pay for,
it is a after-the-event settlement process that goes in.
They didn't have their deck and ERCOT will then go in and
settle the ancillary service obligations with that money.
Again, it's ERCOT established clearing.
Peter: What do you mean settled?
It says reducing the existing fee.
It's not buying additional.
-: No, sir. It's just reducing that obligation. Yeah.
That they have had to procure in advance.
Jimmy: And I think you obviously-
-: We'll commit to in your auction
Jimmy: you won't have an ACP that's pretty high.
-: Correct.
Jimmy: You don't want people to do the ACP.
You want people to do the cheaper option, which was.
-: That's right.
Peter: Sure. But if for whatever whacky reason,
they procure their decks,
that leaves a gap in the dispatchable generation volume,
right? Which is what we want. -: Right.
Peter: So that's why I'm asking you,
that still leaves a hole in our fleet.
So that's why I'm asking if we,
if that money would go to add or
procure additional ancillary service.
-: Yeah. No, I don't think so, sir.
I don't think that's a market signal on this.
Peter: Well, I'm not a market signal.
I'm just worried about making sure
we have the generation we'll need.
-: I understand you.
-: And I'm asking these questions because
these are, as I mentioned,
these criticisms that have come up
and I just want to give you the opportunity to-
-: To me, I view it as a mechanism to pay the bill, you know,
once the check comes after dinner.
Peter: Sure, but not get any new generation?
-: No sir.
Not getting any new gen for ancillary service.
Correct, sir.
And it should not change the calculus in terms of,
the deck program would not change the calculus
in terms of what-
Peter: No I mean, the penalty, the funds that come out
of the wallet, don't go to buy new generation.
-: Or the ACP should not change the calculus
on what Brad feels like.
He needs to procure to meet that day's
reliability condition. Peter: Okay.
-: So it sounds like one way to mitigate that concern
is to have a high ACP, right?
-: Correct.
-: Maybe think of another protective measure to sort of
defray that interest.
So I know it was just, you know,
kind of the initial concept of laying a path.
If you can't get the deck then,
if an LSE does not procure the deck,
then they have another option. So working on that option,
so there's not any independent consequences
that we need to continue to look at.
-: Well. So the ACP,
the sizing of the ACP and scaling was one of the most
important components of the REC program.
So this is going to be on the front end,
one of those things that is going to take
a lot of refinement to get that right.
And just for the reasons you're highlighting here.
Peter: You sounded like you were ready
for coming. It'll be price.
Jimmy: I don't know if it's that high or not,
but it's something high enough, you know.
Peter: People respond to incentives.
Jimmy: I'm sorry? -: People respond to incentives
Jimmy: Well it's true.
-: Those were my two main ones that have kind of come up
as I explored that concept or were just, you know,
the subset of the new, and you can work on expanding that.
And it's tough, you know,
you want to sort of right-size any proposal
-: Yep.
-: to make sure you're capturing the right resources
and sending the right market price signals.
So that isn't a piece of your proposal that can get adjusted
to start to address some of those issues potentially.
And then the ACP part in the opt-out,
addressing some of those unintended consequences
that couldn't go with that.
-: Right.
-: That's all I have.
-: Do we want to ask some smart people up here
who are going to clearly disagree and shoot holes in them?
-: I do have a couple of ideas. Peter: Yes of course.
Jimmy: So one of them is, I mean, I liked the idea.
I liked the fact that it's forward-looking,
that it's money for steel.
I like these components of it.
We're not looking back where we're creating
new programs off of existing models that have worked.
And I liked that.
I think my view is there ought to be some
massaging of resources that are available in this.
Perhaps all things that are within the security,
the SCED dispatch at ERCOT, something like that,
you know, they might be on a lower voltage, not 69 KV, but,
you know, I think we're seeing a lot of
distribution voltage batteries and other things
that may provide a right reliability resource.
And I would say without making the decision,
we ought to at least look at that universe and see
what that could be and if, see if that applies value.
-: Well. And so I think that is a bit of a,
it's a Tesla scenario just on a, on a high level, right?
If you have aggregated power walls, but again,
you have to be able to control it
at transmission interconnection.
Cause that's what he's asking, right?
The controllability, that we've always talked about.
If they are able to do that,
long-term the doors should not be closed off to them.
We have to be somewhat nimble with what,
what could qualify or at least offsetting the obligation.
But that's kind of the beauty of this.
It's happening based on performance.
And that means that it is going to be reflective
of low response.
So again,
if that neighborhood is turning off or they're using their
own solar at certain times, or their own power walls,
that's going to impact that LSE's DEC obligation.
Peter: So similar to the way it was laid out,
Sam laid it out this morning.
So if you provided a response, then you're,
you're relieved of the obligation.
-: That's correct. Peter: Okay.
So same mechanism or same bottom line.
Jimmy: So when I think about this, you know,
think about existing generators are on the system
and I'm assuming that unlike
the total load serving entity obligation,
this is a piece of the puzzle,
that might be it's an entire puzzle
as a capacity market would be.
But so this, you have modifications to ORDC
and you have other things
that are keeping existing resources on the system.
This is the incentive for new resources
to come on this system.
-: That's right. Well, said so,
between Commissioner Cobos
or Sam's backup fuel ancillary service,
I do not consider a RPA DPS and a DEC requirement
mutually exclusive with those products, with those services.
They can come in.
It all depends on the size and how much would you-
Peter: Flush that out for me. What's in your mind,
what's the difference between this program and
invest in just expanding ECRS.
Other than the five minutes, 10 minutes.
-: Well, you got to perform.
Peter: You got to perform ancillary services.
-: Yeah. That's right. Well, yes, that's correct.
That is correct. But again, I won't take a thunder at.
Listen to her proposal.
And then if we could try to ask questions,
because I believe Commissioner Cobos's proposal,
it would somewhat have a similar effect
to non-spin a bit to be there.
But again, if you don't use it, do you still get paid?
And so for mine, you would have to perform, you'd have
to generate megawatts to qualify them for the deck.
Peter: Right. So that seems to be the only distinction
other than the five to 10 minute.
And so that begs the question.
We just want to expand ECRS,
because then, you know, you're getting paid.
You don't have to worry about
how often you're being dispatched.
It's an open question. I don't know the answer.
-: Sure.
Peter: And the same could apply for,
if you said it sounds like SRS sounds like non-spin,
probably the same question is, you know,
do we need to build something new or just expand the
existing well, it's open. -: If it's long iteration-
Peter: Well, it's an open question.
-: Yeah. And one of the other factors again,
with the way the deck program is framed,
I don't know if you get the incentive to deploy early
with just expanding ECRS.
Again, ECRS will be out there in the future
and you'll be procuring ECRS depending
on the amount of intermittency that you foresee.
A deck will again reward those generators
who do it the fastest, get here the fastest
to provide us new steel in the ground.
Because there'll be less competition at that point.
So they can recoup those costs and then normalize that.
Peter: Right. I mean, thus the question,
if you size ECRS instead of three megawatts,
or 3000 megawatts to what size are you expecting on this?
-: It's based upon load growth. -: It is.
And so that backcast of their peak loads
on a seasonal interval, you know,
matched up with ERCOT formulation of how much growth
we anticipate over the coming years.
Peter: So it's like a hypothetical,
what would that look like?
-: Oh I said 2% as a baseline.
-: I mean the procurement like- Jimmy: 3000 megawatts
-: Okay, so this- -: Well early, early,
and it would be an additional 3000 megawatts
that you go and it grows as population grows.
-: Okay. So it would guarantee no more than 3000 megawatts
and grow that 2% a year?
You got 2% in here. -: That's right.
-: That's the model. Will: That's right.
-: Okay. So it's no more than 3000 megawatts.
Will: That's correct. -: Okay.
-: Well, I would say it's whatever the 2% of load growth is,
you know,
it's gotta be based upon a real number of what load was
and what, you know, future load growth is going to be.
It's always perspective looking,
utilizing the back number and then looking forward,
plus 2% to figure out what the load growth is to be.
So we're trying to solve that Delta going forward.
How are we going to get those new megawatts in here
that's going to help sata,
not be a detriment to those that are already on the system,
but in, you know,
how are we incenting this 3000 megawatts this year
or maybe 2000 megawatts the next year.
-: I love the-
Will: So I think the concern is, that if we just create
that fixed megawatt,
again I don't want this to become a catastrophic
price formation distortive effect in the near term.
-: We want to get price formation up for a new generation.
Lori: Can I add one thing?
-: But, but everything is destructive of price formation.
Every new generators disruptive of price formation,
every new transmission line's destructive of price formation
I mean, we can't be scared of price formation.
That is what we do. Will: I agree,
Question around this is, one,
what type of generation qualifies in the sizing of it
and the ACP, the penalty. Three core.
Lori: And, yeah.
And, and to your point earlier about new generation,
I think that's one of the concerns out there, right?
The existing generators won't be able to participate
and they get, you know,
the new subset of the new generation that will be
participating in the deck program would receive an
advantage, a pathway to get in,
versus, you know, other new generation
that doesn't qualify an existing generation, I guess,
from their perspective would be
slugging it out in the market.
And so that, that's when that's, that's kind of,
I think that that sort of criticism potentially out there,
but I think what you're saying Commissioner McAdams,
is that you could maybe work on those,
the participation aspect of it,
the resources to sort of try to address those issues.
-: That's right.
Yeah. That's correct.
Peter: Okay. I'm going to ask the sizing question because
-: It's critical. -: I'm thinking I had to yeah,
a cold evening in January, where the sun is set by 6:00 PM.
Loads increasing as the night gets colder.
So you have zero solar and the wind doesn't blow,
I think right now, we're, I think
the high peak demand for this winter we're expecting
like 72,000, our dispatchable fleet is rated for 67,000.
-: That's right.
Peter: So under that framework,
we don't have enough power.
So for 6:00 PM on January 5th.
And and if this is getting me from 67 to 70,
but I need 72, that's why I'm asking the sizing questions.
-: That's right.
And so how much are you going to get in and when?
And again, the value of the deck,
the initial issue of the deck is going to drive that.
In January, or take a take January of 2023.
Okay. You have a cold front blow through,
and you have the scenario that you described.
In that year, you're still going to have maximum need,
which means the existing fleet will be getting paid,
their contracted ancillary service price,
or the realtime price at that time.
And so these guys were only going to take up so much,
you know, if they get their stuff built now.
Peter: Well, that's what I'm concerned about.
We've got 67,000 dispatchable rated now.
We're going to need to go to 72 and-
-: Hopefully we get our 72 by that point. And then-
Peter: I mean, that's now.
So if the new program is only 3000 megawatts-
Jimmy: How do you add up your 67?
Peter: That's what the latest ERCOT numbers
rated for dispatchable are.
And so that's why I'm asking the sizing question.
I know we're not going to solve it now,
but I know at some point we will need 72,000 megawatts
of dispatchable because the sun sets early
and sometimes once a month when the sun goes up.
I'm trying to put some like a concrete framing around it,
so we know what we're solving for.
Jimmy: Again, the way I think about it
as we go forward is, it's not all a thousand megawatt plant
that is going to be providing this capacity going forward.
It may be a hundred small batteries that are providing
the energy needed in that hour.
Peter: Sure that's my point earlier. I don't care.
Jimmy: But batteries are not in, as I understand it
and most of the other ERCOT models,
they aren't even given capacity values
at this point in time. Is that right?
-: No. Kenan?
Kenan: Sorry, what's the question?
Jimmy: ERCOT doesn't provide
capacity value in batteries right now, right?
Kenan: That's correct. -: Yes.
Peter: Zero, well, we've only got what, 400.
-: Yeah. So, point being that as these grow
and as we're getting more on the system, I mean,
we still need to understand what that is.
-: That trigger, yeah.
Peter: I know what the Delta is.
It's 5,000 megawatts right now.
And if we do it,
and that was my point earlier about the technology agnostic.
As long as it's dispatchable, it can be batteries,
it can be 150 watt or 50 megawatt batteries
to get you to 5,000. That's great.
That's fine. It can be a few peakers and one base load.
That's not something I want to figure out.
I want the market to figure out.
I'm just making sure we get to the total need that ERCOT has
and we have that we're able to provide that
through whatever product we offer out there.
-: All this breaks down into how we identify our target.
How we use, you know, the trends in low growth,
again using that past data.
And then where ERCOT beliefs, as you say,
we're going to need to be.
And you asked me about the percentage versus
how many megawatts are we talking about here?
We're just talking about a baseline,
but it's something that can be manipulated.
Peter: The same as move it to 5,000 or 6,000.
I mean, that work too.
-: Yeah. As long as long as we have a methodology
that everybody can get anticipate. Sure, absolutely.
Yep.
-: The other thing I want to know
is that the Delta between where we are now
and when the CRS is going to be in place
and the amount of solar generation
that is going to be coming online,
right now ERCOT prospectively has it targeted
to be online in 2024. Will: Right.
-: You know, we don't know what's going to happen.
There could be delays. I hope not,
but we're talking about a two and a half year Delta,
where we could get flooded with solar because
of all the federal actions taking place.
And we're trying to send signals for the solar
to show up the storage,
but there could be a lot of storage or solar
rather than shows up without storage.
So we're going to be dealing with Oliver in the interim.
Peter: Do we think we can get this
implemented before ECRS?
-: Alright. It is possible. Yes, sir.
I mean, that's the great thing about it. It's possible.
So until those guys tell the difference.
-: And in fairness to the solar-
Peter: I am looking at Kenan.
Audience member: Pick up the REC program.
Peter: Oh, that's what the NRG said, right?
We built it off the REC program.
-: And just as a report, or if I get started,
I just want to say that ERCOT plants that handle
the solar ramping with non-spin and souped up ORDC
Peter: And curtailment -: if needed.
That's what I hear, but, you know, it's not like
we're going to be completely caught flat-footed.
But my thought on this is that we need to be planning
for that Delta, that gap,
even if we have those tools in place,
Peter: Absolutely. -: because like you said,
we need more dispatchable.
We don't have enough of it to fill all those buckets, then-
Peter: We've got to make sure we got enough.
Question to Kenan on implementation.
I know this is, this is a relatively new proposal,
very new proposal.
-: Yeah. So I mean, the way I look at it,
there's kind of two components to this proposal.
One is the front end, kind of the deck calculation.
-: Right.
-: And that, I mean,
we build some new system around that,
but it could come from a vendor similar to the one
that provides the REC program.
Then the, the other half of this is a settlement issue.
Both of those in isolation are relatively straightforward,
like the LSE obligation.
The challenge for ERCOT will be trying to fit in
the settlement changes with all
the other settlement activity that's happening.
Peter: That's one of Commissioner Cobos's
favorite topics.
-: And that is where we, you know,
there's securitization going on,
so when I can even get that in line is,
the biggest challenge for ERCOT.
Peter: And the point of being the settlements team
is also the same group of people working on securitization.
-: Correct.
And would it be the same team working on a fuel reserve
product or some, some of all of the items as well.
Will: You're not saying that securitization is holding up
the reliability aspects of this grid, are you?
-: No. What I'm saying is I've got a queue and I've got,
I would have to manage that potentially
and recognize that. I mean,
it's the same group of people that are working
on securitization right now, that would be working
on the settlement side of this proposal.
So to me, it's a deliverable product.
It's not touching our energy management system.
It's not touching our market management system,
some of these core systems,
but I have to find a place in line for it.
That's the challenge.
-: Anything. Not just this? -: Correct.
Will: Sounds like our ancillary services as well,
you know, that's gonna get balled up.
-: So that.
-: That's why it's one of Commission Cobos's favorite topics
is anything that touches settlements,
is, this or anything else? It's just that the
resource constraint part of the organization.
-: Yeah. I mean, the distinction I would make around
ancillary services that are procured on a daily basis
is that does touch a core system.
Will: Correct.
-: So this is, from that perspective, a lighter touch.
Will: Important to us,
but bottom line is it's still falls behind.
Peter: Anything less. I mean, Lori's made that point.
I mean, that's a very good point.
Lori: Even if you don't go through the EMS upgraded,
it's not an ancillary service or any other
product that would touch the EMS upgrades or the EMS and MMS
then that would obviously have to wait until after 2024.
So you're trying to avoid going through the EMS,
you still have to go through settlements
and there's challenges because across the team is working on
securitization and resource constraint.
And they're going to have to use the settlements aspect
for any one of our actions like the, firm fuel,
any of our proposals no matter what it is.
So, you know, it's just setting expectations.
-: Expectation management.
-: It's just real.
It has nothing to do with the merits of any given proposal.
It's just a fact that we've got to be realistic.
-: That's right.
Any other questions for Kenan?
-: But it's easier than other things or
where are we on the spectrum Kenan?
You need to give us a hard versus easy.
-: So as a standalone implementation,
it is easier than anything that touches the core systems.
-: Yeah okay.
-: I think that is an important distinction to make.
So I think when Mr. Maggio was here before
you talking about the LSE obligation,
he also said that's a relatively
straightforward implementation.
I think the, you know,
the market power issues and some of those are,
are the real heavy lifts there.
This is a relatively straightforward implementation.
It's just a matter of freeing up the resources.
-: Okay.
-: Thank you. -: Thank you.
-: We're still on you.
I think I'm done.
(indistinct)
-: It's ADD, that has nothing to do with this.
-: Shut up Peter, shut up Peter.
(laughing)
I know I would love to hear at some point from Sam,
since he's been doing the comparison across
the various proposals that have come up.
Anybody start with Sam or anybody else you'll want to call?
-: Yes, so we did have some filings.
I want to start with Sam and then I would bring up
Aaron from Eolian. He had a good filing in there.
And then go from there, Mr. Chairman. See where that leads.
-: Since this is Aaron' proposal,
they probably know more about than anybody.
-: Right.
-: So let's start there, so Sam has the context.
Will: Think you just unmasked someone, in federal terms.
-: Did you have some security outside?
-: Welcome.
-: Thanks for having me.
-: He's brave enough to stand up here.
-: He is.
-: I'm Aaron Zubaty, CEO of Eolian.
I'm going to be ducking laser beams
coming from behind me, probably.
Jimmy: That's the way we roll.
-: So Aaron, describe the practical process for the public,
and then we'll throw bombs at you
and kind of work through this.
So how functionally would this work on a seasonal
or annual basis in ERCOT mechanically?
-: I want to answer that. I'm sure.
I do want to say one thing about the impetus for it,
which was the meeting, I guess, 15 days ago. Right?
And so I think it's an important distinction
about the starting point,
which was looking at the fundamental question
of how do you create an incentive for new generation?
-: Yeah.
-: A lot of people filed comments about that.
How do you create a longterm, you know,
viable financial incentive?
One way is through the ancillary service expansion.
And you mentioned specifically,
ECRS will be there, right?
It will be expanded.
It's unclear to me how the prices will be,
but the bigger challenge is also what you said.
It's unclear today who will even participate in the ECRS.
If you have a five gigawatt ECRS,
who's there to participate,
if today we don't have enough capacity?
-: Well, that's the goal is,
we know we have to put new months,
somebody somewhere to get the money out.
-: And so, that's answering that question.
-: The only distinction is where it says
one of the features of this concept,
we're only paying for megawatts deployed.
Whereas any of the ancillary services
are much more of a capacity,
like centrally procured capacity, we may or may not use it.
So, yes.
Aaron: Right. So there are multiple ways to address
how it gets implemented.
-: That's the feature.
Aaron: Yes. We, we describe it as, you know, pay to play,
or you know, it's performance-based, so the goal is that,
if you're there during specific hours,
there are targeted hours that incentivizes people
to highlight availability during those hours.
There's also performance requirements that are the specific
generation that admittedly everyone in this room has said,
it doesn't exist today to meet the specific technology
and performance requirements needed to hit
some of these moments in these ramps.
Will: I would say, a better way to put that is,
you have to play to get paid.
Aaron: Yes. -: That's different.
-: Very important nuance.
Aaron: And so I think, what we heard, you know,
15 days ago was there was no one who would come up and say,
I guarantee that anything on the table,
I guarantee that we will build capacity.
-: We got some guarantees that it won't.
Some options that it won't.
Aaron: Exactly. Guarantees that it won't.
And when questioned, no one said, I guarantee that it will.
So that was the starting point.
So again, this is about how do you guarantee
new steel on the ground that matches
that performance requirements and specifications
that the market is asking for.
One way is by the market signal, through ECRS
you know specifically laying out where we're going to
take these actions,
but this is the other way to send a market signal to the
specific type of generation for specific hours
that has a very specific need in the system.
There are a couple of things about it that were designed
to protect the existing fleet.
If you can, you know,
have specific ability to turn it on and off quickly,
that's very different than a lot of the CCGT's on the system
and that's on purpose.
Lori: Those are batteries?
-: No, you can have a five minute.
There's an LM, 6,000 with a five minute cold start,
zero to 100, the GE makes.
It's being installed in our car right now by some parties.
So there is technology already being deployed
that meets these requirements today.
Both batteries, you know,
a long duration and than most people in deployment today
and also thermals.
There are multiple plants on the system.
They're small numbers of megawatts that meet the criteria,
you know, Steck, Denton,
basically people who saw this problem a few years ago,
started investing to this type of dispatchable generation.
So the idea was, no one would commit to it,
so how do you force, you know,
create a market signal for the product
that's needed for these hours.
It would not be needed overnight.
There was normally plenty of, you know, energy at night
and that market signal would be based on two things.
One would be, you must be there to perform.
So if you clear,
so there are two ways to handle the question of,
how do you get a deck and how you get paid?
One is a clearing mechanism.
So the key is you cannot have a contract where
or you can't have a construct where people say,
"I exist. I want to get a deck,
but I'll purposely put in a super high price and not clear,
and then not have to perform."
There are other jurisdictions that have some RA contracts
like that, that I'm familiar with.
We actually have one in California. It's not very effective.
So the goal is you must clear a product to get the deck.
So you either clear the ancillaries,
or if you have not cleared,
then you have every incentive during those ramps
to be there, you know,
to basically be there during those peak hours,
during this critical kind of, you know, kinship point hours.
So there,
there are ways to handle how you truly generate the deck.
You could make it only when you dispatch.
What that would mean is you probably
have less decks generated.
And so the imputed price per deck would be higher.
And it's harder to predict,
which is what Gen Elec said,
it's hard to predict exactly the volume that you get
dispatched and when the other approaches cleared amounts.
Will: Sorry. Important nuance.
I was trying to make the point that
you got to play to get paid.
And so the nuance is you bid in into the day ahead.
-: Physically committed.
-: Yes sir. -: No upright?
-: So you have to-
-: You can't financially scratch your offer.
-: Yes. You get the deck by physically committing clearing.
And again, if you've, you know,
like everyone in this room bid the wrong price
and you think, you know,
you can get the highest price and it turns out
you've been wrong,
then you've got an incentive to be there the next day,
during those peak hours,
to push energy out of the system, to drive 10, you know,
to basically help keep those prices in check.
-: But I guess the,
the withholding offer deliberately high offer can go.
And that's the problem you identified.
Could you not do that in the day ahead as well?
-: You could, but then you don't clear, right?
So, every day with our, you know,
you have to choose what price per hour, if you're thinking,
you know, "Ooh, it's gonna be high price."
-: So it's the day ahead clearing that you're worried about.
-: Yes. So you can't game the game the day ahead.
So once you, and if you have not clear day ahead,
then you have a big incentive to participate in the
real-time market, which is Commissioner McAdams's point.
The goal is to incentivize active participation at all times
as much as possible to drive down the cost of both energy
and ancillaries over time.
And that's the other critical piece of this.
By incentivizing generation that can actually be there
when ECRS is ready,
you ensure that the price of ECRS is not extremely high.
You basically make sure that the generation is there,
that the new ancillary products
are giving a market signal toward,
to help make sure that all ancillary costs
basically do not get extremely high.
And there are people in this room who are concerned about
these volumes and what the cost implications are,
which is-
Peter: We're gonna need a high price at some point,
whichever product is the first one out, right?
If it's ECRS deck or Acme proposal number 17, it's,
you know, we don't have the generation,
the first program out there with the first new money
will be a high price until we get the supply.
-: And the goal-
Peter: It's a self-correcting mechanism.
-: Exactly.
And to your point, the goal of having a,
a program set out from day one with a clear delineation
of how long it will be,
what that actually does is unlike the ancillary market,
which, you know, you can expand it,
but people have much less visibility about that
versus a tenure or whatever.
You know that a timeline's there with specific volume
compliance over time, that is the long-term price signal,
that many people in this room and whose final comments
have asked for.
To say, we want something that will ensure
that there's some form of long-term price signal.
What this is not, is a PTC. I'm going to be very clear.
This is not something with a fixed price signal
for a long period of time. And that's really important.
It is why it becomes self-correcting.
When there's enough supply, that price will go down
and you could say, well, will people invest to that?
That is part of the risk of any investment,
but unlike a PTC,
which does lead to these price distortions,
because everyone knows it's there at a very clear price,
it lets you bid at a very clear price.
When you have a market mechanism on what this is worth,
it doesn't give the same freedom to bid
the way that a PTC does, for example.
Lori: So Aaron, is it
fair to say or clear enough to say that the program,
as you said, you know,
over time the price moves down and to trigger a certain
amount of new dispatchable resources.
Is it fair to characterize this program as sort of a glide
path to ECRS to make sure that that bucket is full
or at least get some, I mean,
is this a glide path for certain resources to start
getting in the market to fill up the ECRS bucket?
Will: Possible generation, right?
-: It's a very good question.
I would say, this is one of the pieces toward,
how do you have all these market signals?
I mean, you know, you mentioned the 2%
and you were mentioning the low growth versus even today.
Again, 2% load growth,
if you started a hole of 5,000 megawatts means in 10 or 15
years, there's a 15 to 20 gigawatt hole.
That's like a $20 billion plus investment hole that,
has to be filled. So to your point,
even if ECRS hopefully comes on and you know,
one, two, whatever many years,
the worst thing that could happen is there's a waiting
period because people don't know how long it takes,
for ECRS will be, and there's no price signal.
No one really knows yet. And so you wait to see.
The worst thing that could happen is
those generators that are needed for ECRS,
wait two to three years to see what ECRS looks like,
and then start trying to deploy,
because it's already too late to a point.
And that would actually be a bad outcome.
So this is one way to bridge the uncertainty
on how long ERCOT will take.
And again, Kenan was just up here.
It's unclear how long it will take,
as there a lot of resources required to do everything.
I think that's the challenge is, if it takes a number
of years for ECRS to come to fruition
in that intervening period,
it's hard to make a lot of decisions without
necessarily knowing those.
This is one way to bridge that period of time
because it's a different price signal.
And the nice thing is, it's solving the broader need,
which is functional dispatchability with generating
resources that currently do not exist on the system.
And it's forward looking for new technologies and it sets
a target to say, these are what we want in the future,
because this is the type of product we need in the future.
Peter: You mentioned the forward pricing looks like
an ECRS or any other ancillary service,
you don't know how much volume,
you can look at current prices or historic prices
of ancillary services and just what volumes you don't know,
the investor would not know
how much would be procured in the future.
The question is how far in the future
would you propose procuring the decks?
So, or setting that volume?
Aaron: Since I'm here to pile on of people, you know,
I would ask even a question of someone like Brattle,
how effective have consultants been at forecasting
ancillary price markets?
It's a rhetorical question.
It's extremely hard because-
-: Everybody's bad at forecasting.
-: Exactly and it's marginal units, right?
So the problem with a lot of ancillaries,
they are asymmetric, because when they can be very low
for a long time, and then when someone doesn't show up,
the price is very, very high.
That type of volatility is extremely hard to forecast
and predict in any econometric model. And so to your point,
it's extremely hard to predict.
I would give our own personal example,
when we decided to make starting three years ago,
investments in our energy storage projects,
they're now operating under construction.
We looked at every consultant,
we looked at the models and we said,
this is not a justification.
This literally doesn't work because
it captures no volatility.
You don't have any visibility on what the price signal is.
Peter: How would the deck correct that?
-: Because if you set out from the beginning and said,
this is either a ten-year program at 15 year program,
or like RPS,
there's a minimum requirement that we're going to start
at 5,000 at year one and go to 15,000 by year 10
to match load growth.
That sets that target over like a 10 year volume.
Peter: The volume target, not the price target.
-: That's right. There's a volume target. And then the-
Will: The price target on year to year,
that's a self-correcting mechanism.
-: Well, there's the ACPS. -: Oh, I'm sorry. The ACPS.
-: Right. But so,
I mean the ancillary service volumes are set a year
in advance, traditionally they have been.
You could move that further, you know,
you could move that out. I think it's December when
ERCOT has traditionally set AS for the next year by volume.
So the volume predictions very easy.
ERCOT tells you what they're going to buy.
The price prediction or forecasting is the hard part,
very asymmetric. As soon as you run out of offers,
it gets real expensive real quick.
So I can see on the deck program, how the volume,
you can set the volume forecast very easily.
But how does that improve on the price forecast?
Aaron: It's the ACP, that's the way to think about-
-: That's the benchmark.
-: Well, it's the max and this is why it's important.
What is important about an ACP is that that's the maximum
exposure that consumers will see.
That's very different than other proposals
where there's a floor price,
because it's one thing to say that generator's guaranteed
a floor that does not cap consumer exposure whatsoever.
It's basically the inverse.
So knowing there's an ACP means as a, you know, again,
a participant in REC markets, for example, over the country,
you know, there's a price, you know, there's a,
a demand for a product.
Maybe there's a band like anything in life. There's some,
you know, statistical uncertainty.
You can say it's likely to between, you know,
five and 10 or whatever.
But, you know, there's demand for product
years in the future.
And there's at least some sense that there's some realistic
price formation for that.
You know that if people don't show up, there is an ACP.
So maybe that happened, you know,
I don't want to say you'd hope for that as a participant,
but-
Peter: Theoretically the first deck ever traded should
trade it with ACP.
-: Yes. And so there are markets, there are REC markets-
-: And they never trade higher? -: Yes.
Peter: I'll never do that again.
Well, I mean, if it like by definition
and you don't have the generation you need,
the very first trade is ACP.
And then as long as you have zero plus in supply,
by definition, that price has to get that.
-: But one of the interesting things
about a market like this,
when there's an ACP, Peter: That's a good thing.
-: Yeah. It incentivizes a generator to actually
see if someone will take their product
at a known price for multiple years in the future.
So unlike the retailers being sort of, I'll say, you know,
naked on, you know, short term contracts,
if you have a generator and you think
there could be a lot of competition coming in,
you go look for people to take a three or five-year strip
of your product now at a known price.
And guess what?
That trait's normally significantly below the ACP,
because the whole point of someone lacking
and on the other side is they get a deal.
They know they don't have to pay something
that's even close to ACP. So when you look at-
Peter: Moving risk. -: Yes.
And so a lot of the markets, again,
I'll just use their REC markets that look like this,
where there's an ACP that declines or increases through
time, those markets typically have people trying to lock in.
You know, multi-year, if you're on the retail side,
you want to do that too.
Peter: That's financial risk management.
-: Yes, sir.
-: Very straightforward in most places, power markets.
-: But to your point, it's the ACP that helps set.
There is a price signal of some in almost knowing that
there's an ACP out for a long duration,
helps people then come to terms on some duration,
of contracting, that's typically not just spot.
Peter: Oh I mean, the feature is it forces the price up,
but you forced the first price to be with ACP.
And the absence of that penalty,
nobody has any incentive to do anything
and nobody has any idea what the price would be.
-: Right.
-: So that's a feature. -: Yeah.
But the key features is it caps the cost to consumers.
And I think that's really important point,
and like Commissioner McAdams said,
the dollars that would flow from ACP would basically go to
the ancillary costs for the rest of the system
to buy them down. It would be a friendly loop, right?
The point being, if this generation does not come,
it is likely that the ancillary costs in the market
will be higher. So in effect-
Lori: Then we wouldn't have generation.
Peter: I mean, at some point it's all academic
as rights go.
-: Right, within the bounds of right, within some bounds,
there's some supply and demand.
The goal is to use this, to help drive down,
ultimately ancillary costs by having enough generators
that can really participate.
And if you can't then, or if you choose to not participate,
then you are helping reduce the costs for the other
participants who actually did participate.
Peter: Excellent.
Questions, comments?
Will: I want to hear Sam. Sam is going to come up here.
I liked everything he said.
Sam will smoke out the devils.
-: Done? -: Thank you. Don't go far.
-: Yeah, don't go far.
-: All right. Sam, come on. Come on back up.
-: Thanks. Good afternoon.
-: Welcome back. -: Thanks.
-: Name for the record.
-: Sam Newell from the Brattle group.
-: Thank you, sir.
You've compared a lot of different ideas.
You presented the two,
you and your team rose to the top to date.
We've got a new proposal.
I would love to hear your thoughts
on pros, cons, features, bugs.
-: Don't forget when we said the rose to the top,
it was for solving the resource adequacy problem.
Right? Peter: Yes.
-: Okay.
This proposal does not help the resource adequacy problem.
Not one little bit.
It does other things, but
it may tilt to some of the supply a little bit
more towards stuff that can meet ECRS.
And I'm not even sure that's something
we should be trying to do right now.
As for the problem of,
do you have enough supply to serve demand,
even when things get tough and you're close to shortage?
Remember, that's the problem.
That's the primary one we're worried about.
In weather extremes when the wind is not there.
And those things are, you know,
all the times we've experienced it.
They've been predictable a day in advance.
And it's not even a question that we don't have
enough flexible supply.
It's about enough dispatchable supply that can be there,
whether it takes a day to start.
Cause you know,
you know when it's the hottest day of the year coming
and that's actually what's in shortage.
And then I'll tell you why I think
this possibly makes that problem even worse,
but for sure it doesn't help it us.
Peter: Okay. We'll start with that before we get to-
-: So it's very tempting to come up with something.
We got into a lot of details,
many of which were very clever,
but it's tempting to look at it targeted program like this
in isolation and see how that'll help certain resources.
These are resources we'd like to have
without seeing the unintended consequences.
Let me talk about what the unintended consequences are
and cause we heard, "Oh, it won't run all the time.
So it won't always distort prices."
It will run. First of all,
we'll be providing ancillaries a lot of the time
and reserves.
It will be providing energy or ancillaries, especially-
Peter: From a generating asset or?
-: Anything that's providing decks. Okay.
Peter: Okay. So it meets the performance standards.
-: Yeah. And it will be providing energy or ancillaries,
for sure. I mean, especially if it's reliable.
For sure, during the periods when prices are very sensitive,
that is in the higher demand periods, right.
In the higher price periods, it will be there then.
And it will be undermining prices then.
Here's the way, just take a step back
from all the details for a sec.
Sorry. What were you gonna say?
-: Well, I was going to say, you said undermining prices,
Can you flush that out? I am not sure I follow.
-: Okay. So you are,
suppose this incentive does cause 2000 megawatts
of this attractive supply to invest in and come online.
-: The LM- -: 6000's.
-: LM6000's
-: Batteries, whatever qualifies.
And you really get that and you can point to them.
Now let's talk about the unintended consequences.
And let's back up for just a second,
where and why you have to put it in the context
of the market that we're talking about.
So we actually depend on the market for it,
unless we're going to do all new investment
through special programs.
I don't think we're looking to do that. Right?
We actually depend on merchant investment
that is willing to invest because they
expect prices to be high enough.
And so there's enough room in the market for say
for so much capacity that is able to produce
during those short periods.
And that's when so much of the shortage value is.
There's only room for so much because
if you added a little bit more,
it would reduce the price and you'd realize,
"Ooh, it doesn't make sense to invest."
-: Equilibrium is the point to make.
-: Exactly. Yeah. And so, there's a room
for a certain amount.
What happens if you say,
"Oh, I came up with a way to give a side payment,
that's not in the rest of the market
that everybody's eligible for.
Give a side payment to a certain kind of resource,
you bring them in and then boop,
you're going to knock off exactly that much.
So if you brought in 2000 megawatts of this supply,
you will lose 2000 megawatts of other supplies.
Peter: Explain the knocking out part.
-: Well, because this is this,
this is just what we were talking about.
Imagine that,
Jimmy: That doesn't account for low growth, does it?
-: Let's hold, you know, all else equal.
Cause we're not changing load growth.
And actually I like that point. So here's the total,
if demand is only so big, I have to make it,
so it works in the, you know, transcript, you know,
I can't just use symbols, right?
If it's only so big, the demand,
the amount of room for it for supply,
given how high load gets during these shortage periods,
whether it's because it's the highest load
or low wind or whatever, right.
There's so much demand,
that gives you so much demand for supplies.
The only thing that can increase the amount of supply
is if you increase the load
or increase the demand for ancillaries,
and see it through with online reserves too,
with the ORDC are ultimately our real-time compensation,
but you actually have to increase physical,
real time demand.
If you don't do that,
and that actually does expand how much supply you can get.
But if you're not doing that,
you're actually holding demand, physical, realtime demand,
which is actually what determines the shortage pricing.
Peter: Okay. Let me see if I can understand.
-: Hold on. If you don't change demand-
Will: You've got to build new generation
under this construct.
I mean, it just wouldn't happen, right?
-: Well, no, you do. Hold on, just a sec.
So you are, in fact,
unless you're planning to use special programs
for all new investment, forget about merchant investment,
you are actually depending on people to see.
You know, when the forward price goes up
and when their forecast for when there's going
to be a good pricing enough to build a unit,
you actually are having them, you're depending on them,
looking at this dynamic of, you know,
how much supply is there compared to demand
and what do I expect prices to be?
You were going to say something Chairman.
-: Well, I mean,
I wanna make sure I've got the concept down,
the knocking in the blueprint.
If you have essentially a subsidized side payment,
like subsidized segment of supply yeah.
And it's still this year's load or load with next year,
whatever that load demand is, it will, the,
the subsidized product will beat out,
will beat the economics of the other 2000 and essentially
forced retirement because they don't get the revenues
because the substitute good is cheaper.
Sam: Exactly.
-: And the same thing would happen if you built transmission
and you solve bottlenecks on the transmission system,
or if you built a new gas plant, it's the exact same thing.
They're all, it's all price formation. Well in competition.
-: And I agree with you if those are actually,
but I only agree with you if those are out of market.
-: Why is that? -: Well, no,
I mean, it's true in general,
if you add one that, you know, somebody else isn't, but,
but with growing demand or, you know, retirements and stuff,
there actually is a signal for people to build.
I think it's-
-: What's the difference between that signal and the signal
that's in Commissioner McAdam's memo that says
we need 15,000 megawatts in 10 years?
-: I'm sorry.
-: 2% load growth every year for 10 years,
just say we need 15,000 megawatts.
-: And can you complete the question now?
-: What's the difference between the price signal that,
that the market price signal that you think the new,
that the generators get from the existing market signals on
it today and the price signal or the signal that
new generation is needed by having a 2% goal that we're
paying for an additional 15,000 megawatts over 10 years.
-: Well if this payment that you're offering is,
is just a side payment.
I mean, it doesn't necessarily hurt.
It's just costly,
but it doesn't increase the total amount of supply because
the total, and just an easy way to think about it, you know,
there are a lot of hours in a year.
Just as a simple mental model,
imagine there's one really challenging hour.
And that's where a lot of the value is.
There's enough demand for just that many resources.
And, you know, imagine if you had one more resource,
you'd kill the price and it shouldn't be there, you know,
it should have retired or not dealt.
And that is essentially that's,
there's this stack here where if you make a side payment,
whether it's, you know, to some resources that,
and not others, it, it actually pops somebody off.
So you could take an idea like this.
It's just that you'd have to expand it to eligibility,
not just to new resources,
but to all resources that are providing competitive value.
Peter: And it's, to your point, you mean,
it's important that we can't be afraid of price formation.
I think when I, make sure I get this right,
in the case of a more economic unit displacing
as a substance and more economic substitute good
for an old unit, that unit's losing a hundred percent of
revenue clearing up congestion,
or is not that reduces price point by 5%, not 100%.
-: Quick questioning.
Isn't that in fact, the definition of equilibrium
at that point?
-: Yeah, the market's always searching for equilibrium.
-: And remember, if you want more supply,
you have to supply a,
total supply increase only if you increase total demand
for either, you know, real time physical energy,
which is the load plus ancillaries that are going to be held
out in real-time or as expressed in our cups market without
real time co-optimization through the ORDC,
other, you know, those reserves.
That and actually right, shifting, enriching,
the ORDC does increase demand,
but unless you're increasing demand,
you've actually not helped the supply.
You've actually not increased the supply,
even if you do a side payment to somebody.
Somebody else will pop out the same number of megawatts.
-: It's the same phenomenon that
a federally subsidized intermittents,
that you correctly point to.
It's the same phenomenon they've had on dispatchable.
-: Yeah.
-: Is that fair? -: It is.
-: I mean, they're just,
the subsidy makes them cheaper and knocks out.
-: I'm confused on this because that is exactly right,
I think if you're not growing the load.
Will: Right, it's increasing-
-: Its intent is to focus it on a percentage.
-: But that the load is growing anyway,
you have to treat that all else equal.
I mean, you really have to think about this all else equal.
Am I better off with this side payment
to help me whatever demand that's,
growing over time or without the side payment and how
the market will meet that growing demand over time.
You have to think about it as,
cause it's not like load growth is being created
by having this program. If it were, I would agree with it.
But load growth is a given and for whatever load there is,
for whatever physical demand there is,
there's only a limited appetite for supply.
And I can estimate if you put in,
so let me guess that if this program adds 2000 megawatts
of supply, that is quite nice to have.
I can estimate quite accurately
how much other supply you'll lose.
2000.
And then the question is,
is that even better because this proposal has,
remember the biggest problem we're here to solve
is resource adequacy.
This program would have two hour battery qualify.
What if that knocks off a combined cycle that would have
been built that can run for days when in an extended event.
Is reliability actually better?
Now we heard arguments about, and then here's another.
So I'm not sure it helps. I think it may even hurt.
Second of all,
it actually creates, we got into a lot of details,
but by having,
a per megawatt hour payment for something where what we
actually value truly is Reserve's ability to be there at
these really challenging times.
It's not to produce all the time. You don't need to.
I mean, it's not really an energy concept.
You don't need to pay them every day.
It's just a payment formation, payment mechanism.
You might as well just give a subsidy
to some new generators.
But by doing the volume metrically, you distort things.
So imagine if an 8,500 megawatt heat rate plant and it,
sorry, 8,500 heat rate plant qualifies is getting this,
they'll say, "Great." You know, it's true.
It's easier to implement in the ERCOT systems
because the private participant is saying great.
I'm going to get the side payment. How much am I?
What's my offer for energy? Really low price.
In fact, I'll push off for energy purposes
at that 7,000 heat rate unit.
You know, that's not a good thing to do.
It's not, it's not healthy.
-: Scenario for you, Sam.
Look, the production tax credit and federal subsidies.
It has been asserted, create a distortion in the market.
With so long of a depreciation schedule
for a new dispatchable facility,
30 years, 20 years, something like that,
takes to pay off the thing, right?
How do you invest in the face of that, without, I mean,
your capacity payment spread across the system, you know,
to all of the old, we've got 1974 facilities in the system,
say if we've got 1960 facilities in the system.
My daughter will see one of these systems running in 2060,
you know, under that model.
So how you get the new technology installed
in the face of all that intermittent penetration,
that's going to be constantly suppressing prices without
getting them a fighting chance with something like a deck.
-: You know, you have a much bigger problem on your hands.
If you don't believe in the energy only market
being able to give you price signals to attract new.
Will: Let's not like this religious debate here.
I mean, this is talking about federal subsidies versus-
-: Oh well, but I don't think those,
of course those subsidies don't help
the resource adequacy problem, which is what we're-
-: I mean, the same thing you're describing of knocking out
other ones is what the federal services did to dispatchable.
-: That's right.
-: And how do we remedy that? That's what we're here for.
-: Well, and I guess what I'm saying is
some of the elements of that are present here too.
And what I,
and all I was suggesting is that sometimes it is hard
to believe why somebody would invest
in a dispatchable resource without something special.
And I know it's hard to believe because we've had several
years of not a lot of investment in dispatchable resources.
It does in fact, and I don't mean a religious point,
but it does take some faith that, you know,
if load grows or more retires,
we really will see forward prices go up.
We really will see investors say,
"Hmm, I am very interested now in building this battery
or building this generator."
-: Let me try to clarify what another point
you made about the demand and make sure I get this.
Knocking And booping.
The other scenario laid out earlier,
cold January, winter evening,
sun is set, wind doesn't blow for that day.
Or we saw in October, several days,
just doesn't show up and we need 70,000 megawatts.
For what I hear you saying is that's,
that's 70,000 megawatts and demand response can be part of,
will be part of answering, not the surprise.
But I think what I'm hearing you say is you have
to have some form of fashion,
the demand for 70,000 of dispatchable
through some mechanism. Sam: Some mechanism, yeah.
-: So could you make this instead of 3000, 70,000?
-: Yeah, you could.
I mean, but then it starts to look a lot more like the,
you know,
like the LSE obligation, but you've obviously
suggested different accreditation criteria.
So we're, you know, here-
What's that? Will: New.
-: Well, no, because unless you pay it to new and existing,
you're actually going to undermine. And I heard it.
And what I'm saying is that this starts to look like that,
but of course this had, other than the new point,
this had, you know, flexible, you know,
certain heat rate and faster.
It had certain things.
Now I don't think you'd need to have
the whole fleet look like that.
But that is, that's sort of the insight that leads to,
in some ways you could call this a capacity payment,
a side payment,
but at least it's going to everybody who provides, you know,
comparable, accredited value.
And so you don't have this bump-out problem.
It's in effect actually increasing the demand.
Jimmy: So do we have to do anything to the ORDC?
-: Well, that is another way to increase demand.
I mean, that's how we-
Peter: How do we increase demand?
-: So the ORDC is an expression in real time
of demand that we're really going to pay.
So if you're providing energy,
if you're providing online reserves.
Peter: Oh, you're not increasing 70,000 to 72,000,
you're just saying you're artificially bumping the price up
to act as if you had 75,000. And instead of just 70.
-: Yeah. And it's actually,
because what matters is the real-time demand for energy plus
ancillaries or reserves you're willing to pay for a lot,
which is another way of saying, you know,
physical energy plus ORDC.
-: Well, I mean, I just wanted to clarify that we're not,
nothing changes the seventies,
whatever the realtime demand is, including the banners.
So you hear the rest of that answer to that question.
-: By the way. So there's just one other point here.
And, you know, cause it's,
it's just acknowledging the market construct that makes it
hard to do something on the side. That's why, you know,
sort of one option is just energy only
with a more goosed up ORDC.
Of course that's not perfect because when you do that,
you have too much online, more than you need all the time.
Okay.
So another way is a side payment with capacity
and it avoids this problem of, you know,
knocking somebody else out because it's actually paying to
everybody, but let's still call it a side payment,
but it's to everybody.
So it doesn't have that knockout problem.
Then there's this third approach,
which is the SRS or reserves where it avoids the knockout
problem by deploying you only at the price cap, right.
-: It's not what I proposed but yes.
-: Oh, I'm sorry, I won't call it SRS.
(indistinct conversation)
-: Oh, market price because you may need the product,
when you're not at the price cap.
-: Oh well. -: It was my goal.
-: Oh, I see.
Well, I think we can talk about that more later,
but if you, you know,
if you pay somebody truly kind of a capacity payment to be
on standby, backup reserves,
you really do kind of have to say,
and we're not going to run you except at the price cap.
Otherwise you do have this bump-out problem.
And that's why at least the concept that,
that I presented the backup reserves
was actually that and all it is,
all of these things are recognizing that we,
it's reminding ourselves, we are not actually
programmatically deciding what to build when,
and that we're going to rely on that for all our resources.
We're actually primarily relying on the market price signal,
which is driven by the demand.
And if you pay something special to one,
you got the bump-out problem.
Unless either you pay everybody or you still just pay a few,
but you don't let them in the energy market.
So they don't have the bump-out problem.
Jimmy: Do you think those less efficient units
to get bumped down anyway, if you pay everybody?
-: Sorry, which one's?
Jimmy: The less efficient, more costly unit because that,
that bump-out payment is not going to cover the cost.
I mean, even the...
-: Can you,
Jimmy: Well, I think - -: explain more what.
Jimmy: You're saying that,
if you just give a side payment to 500 megawatts,
-: Yeah.
-: then you're going to kick 500 megawatts out.
If you give it to everybody,
let me say it this way.
If you give it to everybody and new units come in,
ultimately you're going to kick other people out.
Sam: Oh, well, no.
Cause and the idea of in a LSE obligation,
it's saying, oh, you know,
how much capacity we're going to pay this to?
Not just peak demand, but you know,
your 90 10 demand or your,
demand forecast plus servers plus, you know,
15% reserve margin or something.
So that actually is expanding total demand in the market.
-: So do you think-
Sam: Again, I'm not advocating for that.
I'm just trying to deal with this reality
of what it takes to accomplish more resource adequacy.
-: If you kick somebody out with this alternate payment,
do you think you'll kick out the most efficient plant
or the least efficient plant?
-: It's whoever has,
so there are a bunch of resources that are kind of
on the margin in an investment sense.
So they may have a,
it could be an old steam plant that has, you know,
I don't know, $40.
I don't know, you know,
$50 a kilowatt year ongoing fixed O&M costs and
is making very little in the energy margin in the markets.
It could be a well, actually a better way to think about it.
It's not even fixed on them. You know,
they would have to do some major cap backs to keep going and
they just don't see prices quite high enough.
So it could be an existing unit like that,
or it could be, you know,
that somebody who's just about to build that many batteries
or just about to,
and there were a lot in the queue or maybe about to build a
gas fired unit and then they don't.
So that's the dynamic that I'm thinking that.
Yeah, it's probably some combination of old, you know,
retirees are most likely steam units that would
need to do a big capex to keep going.
And- -: How hard a problem it is to solve?
-: But isn't that what you want,
regeneration within the fleet.
We want that new technology to come in there.
We want them to retire on their own, I mean, economic path.
-: Well, Yeah. It should be on the economic path.
Now it's also true that if you have some old generators
that just are really unreliable, you do kind of want,
you hope that doesn't hurt you.
-: Okay. So what happens if the Biden administration
comes out tomorrow with an attainment standard
in the Houston ship channel that puts half of NRG's fleet
out of Commission tomorrow,
which frankly was a concern five years ago.
I mean, it was a real potential
and we have no mechanism to sort of incentivize near term,
you know,
installation of a comparable megawatt of a facility.
-: Yeah.
-: So, these are dynamics where we're trying to work through,
you know, in an LSE, anyway.
-: Well, by the way, -: I didn't get there.
-: the fundamental concept would be LSE obligation,
by the way.
And just,
I'm glad we got a chance to have this conversation.
It's not about, you know,
some mechanism that's kind of cool and that is especially
good for certain resources or something.
It's just dealing with this concept that
if you want to expand the amount of supply,
you have to expand the demand and you have to, you know,
pay everybody who you're hoping to get it from.
The thing you value and you value it just from so much from
existing resources as from new.
So you have,
and that's all that was acknowledging.
Not that I'm particularly enamored of that.
It's just that, you know, and we've for-
-: And do we value capacity in an energy only market?
-: You do.
You do because, so imagine if,
you know there's sometimes going to be shortages.
You don't know exactly when, but, you know,
you know when there's less capacity around,
you'll have more of them.
And then you have a resource that you realize
maybe I'm even very high heat rate or whatever,
but Sam reliable enough and dispatchable enough.
I can take advantage of those because
I can be there when it's hot,
I can be there when it's cold,
I can be there when the wind suddenly stops.
And, and so that actually does value that capacity.
Even if they're providing very little energy all year,
what actually matters is that they have this option
to come in and be helpful.
And the energy only market is actually
pretty good at distinguishing,
who's the most helpful because the most available,
reliable dispatchable resources can capture all those
shortage prices.
Whereas resources that are, you know,
intermittent producing at the same time as other
intermittent resources, the more you get the worse it gets,
you know, they're not even going to get there.
Their average energy price will be really low.
So the energy market is actually quite good at rewarding
capacity and the capacity that's the best
at being available during the shortages.
It's just that we want to also feel better prepared
for certain extremes that
didn't work for well enough this past year.
And we also want to have a little more capacity to stay
further from the edge of shortage then we have.
Jimmy: I guess we're,
I struggle on many of these and it is that,
to me, paying for capacity is a historical rate of return
vertically integrated utility concept.
What we want is a daily.
We want to make sure we have energy on a daily basis.
And-
-: Yeah. Ultimately it's only energy that matters.
Right? Jimmy: That's right.
-: I totally agree. And the energy-only market embraced that.
It's just that don't be confused that, you know,
like producing energy in times when there's no shortage,
you know, when they're easy substitute,
somebody else who can provide it at a, you know,
another low cost, eh.
You know, the times that we really care about with energy
or when it's going to be in short supply,
and there are resources that might be kind of almost never
producing that are great at helping with that.
So it is a bit of a capacity construct.
I mean, I totally granted that it's a long discussion
how you want to best reward that.
I do have to say a lot of people loved,
from all over the world,
look to ERCOT as the ones who had gotten it right
with the energy-only market.
because it does so well at valuing just what you want.
It's just that it's not giving us a level of reliability
that we're fully comfortable with.
-: And that's the point is that under the one-in-one-out
kind of, or we shouldn't have to wait for a catastrophe,
even under any construct that we adopt for you to get
a new plant built, and that's the point, right.
-: Get away from the crisis. -: We got to get ahead of that.
And we got to get new steel in the ground quick
and no guarantees.
-: Yeah. Part of that challenge is,
and I'll spend some more time talking about this is that,
right, we are moving away from
the crisis based business model.
And we have taken out tools that we've historically had
in ERCOT's toolbox with a latch on it
that we only take out when we're in emergency.
And so, because we are now moving away from the crisis based
business model that the crisis based market
had tight conditions and scarcity,
and that's an energy-only market.
That's when generator make money, right.
During tight conditions, during scarcity.
And maybe because we're moving away
from tight conditions and scarcity,
we need to send a signal somehow because,
we're living in an energy only market world
moving away from scarcity and tight conditions
because that's what the public wants and deserves.
And that's what the leadership wants.
So how do you inset new generation in an energy-only
market construct if has no scarcity or tight conditions
because we're pulling everything out, ORDC, ERS, everything.
So that's why you need to somehow raise energy prices
in a very conservative and efficient manner
to send a stronger price signal over the long run,
to get that investment over a 20-30 year life
and sustain your existing generation because,
we can't fool ourselves and think that,
oh, we're just going to somehow attract investment with,
you know, no scarcity and tight conditions.
We have to somehow increase prices.
-: I agree. -: New money on the table.
-: And don't forget also the IMN will still say,
well, first principle is prices should only be high
when you are in those shortage conditions.
And yet it's also true what you're saying.
We don't want to be in shortage conditions,
and if you're never in shortage conditions and that's the
only time high prices are, you don't get a price signal.
So it's sort of a catch 22.
-: Well, I mean, you can also,
we want to get away from the crisis based business model.
That doesn't mean we don't ever have price spikes.
That's right. And you can also,
you can increase revenues to generators by increasing
the price per unit, in this case megawatts,
and the number of units deployed, right?
Part of our challenge is,
we've got a very low utilization factor
on a lot of our dispatchable assets.
-: And so one thing that is important to say is,
I'm sitting here saying these things is for the public
and whoever's listening because cost is important.
Cost is important for the consumers of Texas with any type
residential, industrial, large commercial.
We have to balance that consideration,
the cost impact consideration with the fact
that generators have to be able to make some money,
to sustain their existing generation and provide us
that year-round reliability and to drive new generation
into the market.
New dispatchable resources into the market so that we
can maintain reliability today and in the future.
And the only way generators are able to make money
is by selling their power and getting paid for it.
And right now,
because we don't have tight system conditions very often
in our energy-only market, they're not making money.
So we have to be able to sustain the generation companies
like any other business, any other regular business in the
state that needs to have customers that needs to make money.
I wanted to make that clarification for anybody listening
out there is just not,
we're not wholesale just trying to increase prices
for the sake of increasing prices.
We're increasing, we have to figure out a way to send
-: We've got to get something to term.
-: a stable price signal,
a stabilized price signal to drive investment
in long-term assets, 20, 30 year assets,
and to keep our existing generation in the market.
-: I think stable is a different, oh, sorry, can I?
-: Yeah. Well, I do want to, I know we're getting to,
or sorry for, it's going to break here in a minute.
-: And we want to hear a proposal.
-: We want to make sure we reserve time for Lori.
-: Did we earn the right to continue
the conversation on maybe this one, Mr. Chairman?
-: Absolutely. -: Okay.
-: I mean, absolutely.
Like I said, there's a lot of features in this
that I think were very compelling.
This is not an easy problem to solve, universally.
That's not something that can be,
there's a silver bullet for or some magic formula
that we just need to conjure up.
So yes, this, I mean,
there's certainly a compelling proposal and certainly,
I mean, absolutely.
I mean, at worst case scenario,
there's some great ideas in here, right?
And there's a lot of other and that's,
and there's more good things than that in this proposal.
And like the most important thing is procedurally
as we move forward, the decision point we have for
these big longterm structural changes in December is
in addition to the immediately actionable items that,
we're taking a big strides on.
This is the kind of thing where in December,
we just need to make the thumbs up, thumbs down.
Are we going to focus on a load side solution like this?
Or are we going to go to the, you know,
more generation side, kind of a, more of a blunt instrument.
But if we go to the load side, then this is, you know,
this is very much in that bucket of solution sets that
we'll continue to get a finer point on.
And we want to make sure to reserve time,
plenty of time to cover your memo and your proposal.
Anything?
-: Can we take a little break?
-: There you go. Let's do 15 minutes.
-: Yeah.
-: All right. Thank you Sam.
15 minutes, be back at 2.30.
All right.
This meeting of the Public Utility Commission of Texas
will reconvene.
We've covered a lot today.
This final segment of our programming, we're gonna-
Thank you Commissioner McAdams for laying out your memo,
and leading that discussion.
And thank you participants. -: Thank you.
-: Good progress on all points.
Next up, we will go to Commissioner Cobos's memo.
Love to hear you lay it out,
and I'm sure there'll be some questions.
And then we'll open it up,
if folks want to call up stakeholders.
Lori: All right. -: Forward to you.
-: All right. Thank you Chairman Lake.
So, before you know, kind of as a backdrop,
before I lay out the broad strokes of the specifics
of my strategic reliability service.
You know,
I worked at the Commission a little over 10 years ago.
We were going through this whole resource adequacy
discussion and trying to figure out how to incentive
dispatchable generation, trying to fill some hole,
trying to, you know,
sort of almost the exact same deliberation, right?
The way I've looked at this problem,
and I continue to just identify it that
what we're searching for is some kind of,
some kind of insurance policy,
something to help us fill in those gaps.
That we are now starting to see more prolifically
because of, you know, these, these unexpected blue sky days,
these low probability,
high impact days that seem to be occurring.
-: More and more probable. -: More and more probable.
And so, as I sort of went back,
I thought after our last work session and had, you know,
it started really kind of putting pen to paper and thinking
about, well, what are we trying to solve for, you know,
one hand you are right, we're trying to insert more
dispatchable resources into the market.
And, how do we get there in,
in the market that we are creating today,
which is moving away from a crisis based business model and,
and where we're trying to avoid having tight conditions,
we're trying to avoid emergency conditions
and rightfully so.
So what do we need to sort of plan for the future as an
enhancement to our existing energy competitive market,
but also potentially as sort of a bridge to get us to
evaluating more longterm solutions.
And so giving us some versatility as we move forward with
our market design evaluations towards December,
after December.
So the strategic reliability service that I put together,
is it does have pieces of prior proposals.
It's different in some ways.
The strategic reliability service is intended to be a new
dynamic, flexible reliability tool that will serve
as an insurance policy.
To help ensure grid reliability in our state, you know,
rapidly evolving market that is experiencing
a high penetration of renewable generation
and rising electricity demand resulting from significant
economic and population growth.
SRS is consistent with,
I would venture to say directly consistent with the
reliability service envisioned by SB-3.
And will preserve the integrity of our competitive market.
SRS will prospectively target and meet specific
reliability needs that will not be addressed
by ERCOT's realtime and ancillary service market.
SRS will expand and contract based on dynamic
market conditions and specific seasonal reliability needs.
Again, it's an insurance policy,
that's there when you need it,
that can be adjusted to meet specific risks.
How will it work?
The way I've laid it out in my memo is,
is a forward annual procurement.
I'm open to discussing if it needs to be longer,
but in terms of just getting an initial stake on the ground
on an annual basis ERCOT will conduct either
a competitive RFP or competitive auction
to partial procure a percentage of the needed SRS
on a forward basis for the four seasons
into one year into the future.
So ERCOT will prepare a portion, a certain percentage.
Let's just say, for example, you know,
40% of what's needed for the next four seasons.
Then ERCOT would conduct a final seasonal,
competitive RFP process or auction three weeks before
the beginning of each season to procure
the remaining percentage of the SRS that was not procured
at the annual RFP process or auction.
And so you would,
and this could be like the remaining 60%, that's then
broken down for the three month period for that season.
So you have a more closer look at to what
your specific reliability needs will be.
And you could either maybe procure less or procure more
depending on what you are seeing on a more closer
and seasonal basis.
A competitive RFP process or competitive auction
will ensure that the lowest cost dispatchable resources
are procured for SRS.
Seasonal procurements will allow again for adjustments
to be dynamic market conditions associated with,
firm demand and available supply.
It will ensure that it's not over procuring.
Again, trying to focus on
low probability high impact scenarios,
higher than expected demand, coupled with lower or
extremely low wind and solar output and higher thermal
generation outages both planned and forced,
as we see in our several reports.
What resources would be allowed to participate?
Accredited dispatchable resources that are weatherized,
have secure fuel supply arrangements
and are seasonally tested to ensure that they will
be available to provide the SRS when ERCOT needs to service.
SRS resources can synchronize to the grid,
must be able to synchronize to the grid,
within two hours or longer,
and I'll add some more explanation there in a second,
to provide ERCOT with flexibility to meet
its operational needs and will run for a minimum
of eight hours a day for multiple consecutive days.
They must have that ability.
New and existing dispatchable resources
and potentially demand response would be able
to participate in SRS.
And the reason that I put the initial stake in the ground
for within two hours or longer is because,
if you make it within one hour,
you're probably just going to get peakers,
and that's great, we need that flexibility.
But as SRS is the backend insurance policy,
I want to be able to give ERCOT operational flexibility,
to be able to procure more than just peakers
through this program.
And also to address kind of longer term, you know,
more hours than just like the two hour problems.
You know, when we see those days up ahead in our reports,
we get from ERCOT, those seven days out or we see maybe
we have three tight days coming,
SRS will be able to match those longer timeframes
that we are seeing in the future,
or will be available for unexpected,
again, blue sky problems, et cetera.
SRS would be deployed last in the bid stack to support
market efficiency and to avoid any impact on real-time
prices and will be deployed to avoid emergency conditions.
SRS will be paid.
The market clearing price,
the way I've structured it now,
I know Sam mentioned the price cap,
we can have that discussion
of what are the pros and cons of doing that?
I started with the market clear price because
SRS could be deployed when the prices are not at the cap.
We sometimes have had very tight days
where the price is lower than the cap.
So we want to make sure that they're capturing that market
clearing price that has arise during those tight conditions.
Failure to perform will be met with an assessment
of a stringent non-performance penalty and the clawback
of any payment that's paid to the SRS resource.
Cost recovery.
The cost of SRS would be recovered from load,
on the load ratio share basis that is measured
on a coincident net peak interval.
And that cost allocation method is,
I proposed it in order to help further support
adoption by demand response.
And so what's it, an epic load is basically your peak load,
knitting out solar and wind.
And so providing that that cost allocation functionality
would better accommodate and then help support
demand response.
So SRS will send a forward signal,
a clear forward signal to help incent investment in
new dispatchable generation help maintain the existing
generation fleet in ERCOT. And this is how.
So as I explained earlier today,
we have a variety of operational tools that were previously
used by ERCOT during emergency conditions and are now going
to be used by ERCOT to avoid conservation appeals
and prevent emergency conditions.
And so in a market that's built around scarcity conditions
to provide generators
the pricing and the price signal that's needed
to make long-term investment.
We've got to compensate for the fact that we are now
even reducing even those times of scarcity, that,
that the market would typically rely on
to look to make investment.
So therefore stronger pricing models will need to be
there to drive longterm investment in dispatchable
generation assets.
We've got to find a way to send stronger price signals
because of the actions we've taken by moving away
from the crisis based business model.
So SRS in combination with an enhanced ORDC,
ultimately whatever we decided on ORDC,
will efficiently raise prices in the real time market
to drive investment in new dispatchable generation.
Qualifying existing resources,
will have another avenue to participate in the market.
Implementation based on my conversations with ERCOT,
SRS is not an ancillary service,
so it will be procured through the day ahead market.
As I said, it would be procured through a competitive RFP
or competitive option.
So it will not have to go through the EMS upgrade.
However, you know, there will be settlement, you know,
work that has to be done by ERCOT.
And based on my conversations with ERCOT,
that SRS could be implemented in 2023,
potentially the first half of 2023.
But of course we will all work with ERCOT
to try to get things moving faster.
But, you know, as ERCOT has said,
their settlements team is challenged
and with any one of our proposals,
we're going to have to expect a little bit of a delay
because of all the ERCOT's team is working on right now.
So as I said earlier, and we'll continue to say,
SRS is a versatile reliability tool
that can serve as a long-term market design enhancement
to help ensure grid reliability in the future,
or conserve as a bridge while the Commission
continues to evaluate and implement
other long-term market design changes and await ECRS.
Will: That means the first deck could go out in 2023.
(laughing)
Peter: Thank you Kenan.
-: So that's kind of just the broad overview of
the strategic reliability service that I proposed
in my memo that I followed yesterday.
Of course, I've included more details in my memo.
And at this time I'll be happy to answer any questions
and make any distinguishing comments back
to distinguish about what it is and what it's not.
So I'm happy to answer any questions or comments.
Peter: Thank you for laying that out.
Most importantly, God grateful to have your new ideas.
That's the most important element of all this.
Jimmy: Thanks.
(laughing)
-: Thank you Commissioner Glotfelty.
Appreciate it Lori. Thank you for laying that out on the,
one of the things that sticks out about this is,
is it 40 or 4 year for procurement?
Lori: I said one year.
-: One year. Lori: For the four seasons.
-: The four seasons for 40%.
Lori: Whatever percentage. There is no rhyme or reason.
You'd want to get a good chunk of it,
so you could send a signal to the market
as to how much you're going to procure,
but you would want to procure all of it so that you can.
-: More precise as you get closer to the-
Lori: Exactly.
-: Yeah, that's forward pricing is much better
for the investor universe than a day ahead or
closer to the operating thing.
That's something that they've been pretty consistent about,
certainly about that component.
Implementation of course would be tough.
I know we all love to hear Sam's thoughts at some point,
but any questions or comments for Lori?
Go straight to Sam.
Lori: I'm getting off easy.
Will: Well, I think it may be tougher.
I just want to compare notes about between what he's,
you know, and then sizing to.
-: Yeah. And I mean, it's the same question I asked earlier
is, you know,
what is the difference between,
I guess we'll start with sizing. Let's do that.
I mean, how does this differ from non-spin?
Lori: Okay. And that's a great question.
Okay. So first of all, it's not an ancillary service.
It's not going in prepared on a daily basis,
centrally procured or an RP or bit of auction,
so this will better.
So instead of buying non-spin, you know,
on a one year forward basis,
what that would do, let me backtrack.
So if you bought non-spin on a one-year annual forward
basis, you basically just be paying certain resources.
You'd be basically paying all the resources pay non-spin,
and then other new resources that can qualify for non-spin
which is our resources that can synchronize to the grid,
within 30 minutes.
My product is much more expanded than within 30 minutes.
-: A broader performance standard.
-: Broader performance, and, and it'll incent investment
because this product
will essentially,
number one, attract different resources, but two,
by having some resources come in last than the bid stack
that you will have energy pricing and the real-time market
increase through the ORDC.
So the new dispatchable generation can be part
of my SRS program, but we'll probably be very interested
in the real-time prices and the real-time market.
-: A clarifying question. Did you say that ORDC
will incentivize new investment generation?.
-: It's a combination with SRS and ORDC together,
will work in concert to incent
new dispatchable resources generation.
So I guess with non-spin you're basically would just,
I mean,
what the difference is is that you buy it forward non-spin,
you're only going to be basically paying non-spin,
instead of the existing resources that pay not-spin,
that participate in non-spin,
or maybe creating some incremental investment in resources
that can respond within 30 minutes, which are peakers.
But because with SRS is you're holding certain programs,
I'm sorry, certain resources would be part of SRS
that would come in last in the bid stack,
you would be serving those for specific reliability reasons.
The real-time pricing would increase because of ORDC
and because some of these resources
are now coming in the backup bid stack.
So energy prices would increase and
you would have a dispatchable generation of any type,
not just speakers, would be incented.
Does that make sense?
-: I certainly appreciate the fact that it's a
broader performance standard that leaves more flexibility
for the market to determine,
what is best at that moment in time on fuel costs
or technologies or what not.
-: Also, sorry, SRS fills a hole that's not met by
the real time and ancillary service market, right?
So we've had some of those days where, I mean,
if you don't have dispatchable resources, enough of them,
then you're not going to have enough of them to be able to
fill the real time market to participate in real time market
and also provide the ancillary services that are needed.
So it's outside of those two constructs.
I think that's the way I would
sort of describe how it's different.
-: Okay.
The follow up question,
it has a broader performance standard to kind of, I guess,
backfill non-spin or insurance in case you run out of the
non-spin, but non-spin because of the non-spin has a higher
performance standard resources that currently participated
in non-spin could participate in SRS too, right?
-: Yeah. Cause it's within two hours or whatever.
So I'm just trying to broaden it out so that we're not just
having just peakers, right.
Since it's the backend resource you'd want to have ERCOT
have different types of resources to fill, you know,
peakers and other resources to fill that operationally,
that'd be operational flexibility to fill that,
that specific reliability.
-: 'Cause they could ramp into it.
They'd have more time to gauge and use the different,
the different resources that they had contracted for,
to ramp into that need period.
-: Gotcha. -: Yep.
-: Thank you.
Questions, comments?
-: I think that's exactly what's going to happen.
So I want to talk more about this, but I think that,
I think that, you know, as we see this market evolve,
we're gonna have to kind of feel like we're building,
we build ancillary services now,
we'll go more and more and more, and we're more,
we almost need to like start over and go.
So what do we need in the future?
But we are,
the resource mix, it's going to be interesting as we see
how these new resources play in each one of these
ancillary service markets.
It is, they're going to start filling in short term,
short term, short term until we get to the longer spin.
I mean, you know, as we said, we may see, you know,
thermal plants have batteries,
so that can plan additional markets, you know.
And you know, those will change as these incentives
and these ancillary services change.
So I'm glad you, you put this out here.
-: Well, the other important element of what you're saying is
economics will change faster than we can change the market.
-: It's exactly what I was saying.
-: There's still lot to change here.
-: That's what I was saying.
-: Well, put Jimmy. -: Thank you.
-: It kind of gets back to the old,
this isn't Berkshire,
but the argument that this is not Berkshire.
(indistinct)
-: But it played into one of the arguments that was had
during the session is how much do you need the right sizing?
Because it's, it's being held out there, right?
And then what metrics do you use?
-: That's held out there, but I just want to say, it's,
you know, it's going to come in at the end of the bid's line
-: At the end of the bid's line, yeah. So.
Peter: Well, finish the question.
What are you anticipating in (indistinct)?
Is that an important part of all of these?
-: Absolutely. You know,
I can't sit here and just throw out a megawatt number
at you, but I think if you look at the SARA, right,
and you see those holes that are not being met
because of the scenarios.
-: You do that on a historic average basis maybe, or-
-: Yeah and what ERCOT's projecting out through their SARA,
I mean, that's one tool how to use it, right.
I mean, how to determine how much you need,
because the whole purpose of the SARA report is to project,
you know, how ERCOT is going to look
from a reliability standpoint for the next season.
And so, as you look at all the scenarios,
like for instance, you know,
more than one thing going wrong,
you have a higher than expected demand,
low wind and solar and higher thermal outages,
then you can see at that bottom row, you're going to be out,
you know, 2,500 megawatts for that season.
And so, you know, that's how you size it.
So it's its size based on specific reliability that
ERCOT's able to identify for the year out,
but then closer in to each season,
really zoom in and be able to tell,
on a seasonal basis, based on something like the SARA,
how much they would need to plug in for those holes.
-: Yeah. And that's, I think that's one of the,
when we spoke about this earlier this week,
and I think that's one of the very clever elements of this
is very precisely focusing on the vulnerability gap.
And I think,
I think the way that things would work with this,
these are all moving targets,
but essentially the Delta between spatch bowl and your
intermittence, because that's where your,
the correlation of outages and intermittence is much higher
than dispatchable, right?
Like use,
we've never lost 100% of the dispatchable fleet, right.
That can happen.
That happens when the sunsets or the, you know,
the wind drops off.
So that's a very clever component of this, I think is,
is focusing on that specific vulnerability where we can have
where we've have the once a month event,
where we have 8,000, 10,000 megawatts
that we expected to have, are not there.
All right, anything?
Sam, come up and share some thoughts.
Sam: Yeah sure.
Thanks.
So I'd like to respond first at a high level
and then with a few possible adjustments to the concept.
So at a high level,
as you know, I think this is a viable option that,
and at a high level,
the problem we face is, right now in the energy-only market
prices are high only when you're in shortage.
Investment requires high prices.
And so we're going to be an operating shortage.
And that, you may say that's,
some of us might think that's economically optimal
or something, but it's not desired.
And we want more supply and more cushion.
And there are, I think only two thematically,
two ways to get that.
One is to increase the total demand either through,
you know, real-time reserves like with an ORDC shift,
we'll probably end up only doing so much of that.
Or through demand for capacity in an LSE obligation.
More demand for physical supply
that you're willing to pay for.
Then just what you consume is energy.
That's one theme.
And the other theme is you pay something aside payment,
but hold it out of the market so that
you don't have the bump-out problem.
Because there truly is only so much room for supply
and there's only so much demand for only so much supply.
And if you want to add something on the side payment,
you get the bump-out problem. And this avoids that-
(indistinct)
This avoids that-
Will: We're going to have another meeting,
you can try and kill the deck in another meeting, Sam.
Sam: I'm really sorry, but
because now we get to the adjustments.
So I would say, you said at the top of the bed stack,
actually the top of the bed stack is at 9,000, I believe.
And Carrie could tell us.
Lori: What would it be like? 45 Or 5,000?
Whatever it is, right?
Sam: Yeah. The price cap,
because I mean the voluntary mitigation plans and some of
the small fish, they have little bit probably at-
Lori: And the energy storage, there is always
(indistinct)
So if you put a truly at the end of the bit stack,
it's probably going to be.
Sam: If you do that, it works best.
Lori: What I'm trying to avoid
is an impact on price reversal, price distribution,
because that's not what SRS is meant to do.
It's meant to just, you know,
make sure we have that backstop insurance policy to ensure
reliability in those days where we just have a hole
and we don't have enough power.
And so by moving those resources,
having that, that pot of resources,
you're essentially allowing existing generation
that wouldn't be running anyway,
but it's tested, performance tested
in certain performance operations.
So you're not having cash for clunkers.
You're basically making sure that you have some,
I mean, they're going to have to
meet the operational characteristics,
be tested on a seasonal basis and if they don't perform,
they get penalized and they get their payment callback.
So you're just talking to throw in
your so-called clunker in there, right?
I mean,
you don't want to put yourself through a penalty or get your
payment called back and you picked out of the program.
So you're going to have some reliable assets in there,
but by having this insurance policy,
you are essentially one providing the public leadership,
some confidence, right.
Which is important.
And that's what we're trying to do here too.
But then you're also sending a stronger price signal in the
real-time market that will drive investment and help push
some of that generation that's in,
in the interconnection queue right now,
the dispatchable resources over the line hopefully,
with SRS and ORDC combined.
Sam: Totally agree with the concept.
And I think the way to make sure it works
is that they would offer it at the price cap.
And imagine, by the way, with the ORDC,
imagine they're coming in at the price cap and that
it's the cap at, you know, 3000.
You will use them before you have advisories and alerts.
You probably like that.
And okay, so there are two other issues on the design.
One is eligibility.
I would probably make it, you know,
you can start within six hours or something.
(indistinct)
Something more than, I mean you want combined cycles,
maybe even steam units to be able to participate.
And it was for a couple of reasons.
One is,
you don't want to be tying up the stuff that you'd hope
would be fairly frequently, but you know, more frequently,
you don't want it to just be the quick start that you'd like
to be more frequently playing in the energy
and ancillary service markets,
because this is stuff is really being held out.
So I'd make it probably include some of the slower stuff.
Don't forget that actually will help the problem we're most
worried about, which is, you know, not the quickness,
it's the, "Whoa, it's going to be really hot tomorrow,
really cold tomorrow, really low wind tomorrow."
Any of those. So I would expand that.
And the last thing is on the timing.
I think this deserves more discussion,
the timing and quantity.
I think there, you know,
I can imagine one approach where it's 4,000 megawatts
all the time.
You know, and, and just,
everybody knows you're going. And maybe you, maybe I don't,
it doesn't matter how,
I don't know how far forward you buy it, but we're just,
everybody would know, oh yeah,
it's just always a 4,000 megawatt question or something.
Something like that.
There would be another approach,
which I think is closer to you were saying.
And I think this deserves more thought whether you would
look forward and you would say, Hm, three years forward,
you know, we're projecting only a 10% reserve margin.
And when we count everything right.
And that's too low.
So we want, you know, we wish we had 5,000 megawatts more,
so do a reserve for 5,000 and hopefully that'll then
draw in more investment and we'll get total reserve margin
we're more comfortable with.
You know, the one thing it's just a tiny bit
weird about that.
Two things.
One is that, just when the reserve margin is projected
to be low, you're pulling stuff out of the reserve.
I mean, you almost, you know, if you want to support,
you know, more stable high prices,
you'd actually pull it out when things are long, you know.
Lori: They are long. Have you seen her CDR report?
Sam: So, you know,
so I'm somewhat more inclined to do more
of a constant pull up, but this is worth more thought.
But I do think everything you put forward I think,
is helpful in that, you know,
and it's creating a viable option. And I don't.
So those are just a couple adjustments.
Peter: Relative to the option to you laid out
this morning where are the overlaps, where the differences?
Sam: The core ideas are the same.
It's in the concept of,
if you don't want to expand total demand and pay everything
that's reliable, you have to pay a few things,
you got to hold them out of the market. Same core idea.
Peter: Same conversation. Sam: Same.
Peter: Okay.
Lori: Thank you Sam, and really the goal here is to,
I do want to make sure we get the right resources,
that SRS peakers will have an opportunity and you know RRS
and non-spin ultimately ECRS, but they're able to want to,
and want to play in this,
SRS product that they can do so as well.
But I think having that wider spectrum
is what I was going for,
because I do think that there are other types of resources
that we would want to have to come in, you know,
should we have one of those way,
that to accomplish the goal that SRS is intended
to accomplish and with respect to, you know,
how they're paid, I mean, I'm open to hearing that too.
What I'm trying to avoid is price reversal
and price distortion.
-: Yeah. Yep.
And I think that's, I think you got that.
I want to add one other observation about it though.
It's kind of what I showed before, just to be clear this,
you know, the cost of this is modest.
Like, you know, in our estimate,
this could be in a $20 billion in your market.
This could be, you know, 300 million or something.
That's just a rough estimate.
And imagine if that's allocated to everybody, you know,
the people who don't like paying for capacity,
they're not going to pay for very much.
I mean, this is a pretty small ladder for everybody.
-: So that's why I put that condition in the peak net load.
What I'm understanding is that would help
some of our consumers. -: Well, that too.
-: And so, and would like for, I know there,
you could either keep those resources in ERS,
but if there's a way, you know, to balance this out,
you know,
that's why I put possibly demand response, so this works.
I mean, we want dispatchable, we want, you know,
tested reliable resources to participate in SRS.
And so it's really what I'm trying to go for my proposal.
-: All right. Any other questions, comments we're saying?
-: Nope. I don't think so.
-: Thank you. -: Thank you Sam.
-: Thank you Lori for working on that and laying it out.
A lot of good elements to consider.
And I know I've said it many, many times.
I say it again, there's no silver bullet.
There's no readily apparent solution, but I will add.
We're not in the business of endorsing or killing anything.
We're in the business of Frankensteining,
the best components of each and the,
like I said about the strong and the only guarantee
is the first crack, that first crack that we take,
won't be the right answer.
And I think that probably applies to the first crack
any of us take it at anything.
We very much want to capture the good elements of all of
these proposals and make sure we continue to keep working
forward towards the best solution.
So thank you again for laying that out.
Thank you Commissioner McAdams for laying that out.
Thank you for your company. -: My pleasure.
(laughing)
-: Thank you for your consideration Chairman Lake,
and I hope I've earned the right to be added for
the next round.
-: Yeah, of course, of course.
We're in the business of vetting ideas and continually
iterating to closer and closer to the solution,
the right solutions, set of solutions.
All right. Unless there's anything else,
I think that'll cover our agenda for structural changes
for resource adequacy.
And that is the last item I have on the agenda for today,
unless you all have anything else that.
-: Mr. Chairman,
Commissioner Glotfelty and I may give you an update
at the next open meeting or workshop.
We had a good productive workshop
on the prioritization for transmit.
-: Excellent. -: Yeah.
-: That's interconnection.
-: Yeah, transmission interconnection.
And so I know everybody's tired today,
but we will have an update for you at the next.
-: Appreciate that. Thank y'all both for it.
Fortunate head on that.
Look forward to that update. It'll be December 2nd.
-: Great. -: Waiting for that.
All right. Having no further business,
this meeting of the Public Utility Commission of Texas
is hereby adjourned.(loud thud)
Will: Thank you Sir. -: Thank you.