-: Right.
Welcome back to this work session
of the Public Utility Commission of Texas.
At this point, in terms of scheduling,
we will finish the panel from this morning.
And with NRG excellence panel,
and we will move to some timing constraints,
we'll move straight to Dr. Brattle.
And then circle back to Commissioner McAdams.
-: Dr. Patton.
-: Dr. Patton after the panel,
and then (muffled speaking).
-: Yes sir, the name change anyway.
-: Sorry.
(crowd laughing)
All right.
Energy is on.
-: All right.
Thank you, Chairman, Commissioners
appreciate the opportunity to be here.
Bill Barnes for NRG.
I'm gonna help tag team this
with Arnie Olson for me three.
Because you guys are asking such good questions,
I'm gonna sit up here and help him out
and also have a few brief introductory remarks
for handed over to him.
Last time, I was up here on a market design panel
that was in your first in early July.
And we had just begun the process of talking
with the three and developing our thoughts
and proposals on market design concepts.
And we got the message loud and clear,
work with urgency but work with purpose.
And two main components to what we had through our minds
as we developed this proposal was one
is the reliability expectations
and goals of our market have been
redefined from now until forever, right?
So the prior expectations, the prior thoughts
on what our market design needed
to achieve from reliability has changed.
And that means moving away from scarcity events,
moving away from what you call crisis based pricing,
moving in a direction that ensures
and helps increase the likelihood
that we have more reliability, higher reserves.
And we've heard that consistently from our customers
from the public, from our legislative members
from the Governor's office,
that is our common goal common objective.
And we felt very strongly that we need to do
that the right way by setting the right foundation first.
And that begins with setting a reliability requirement
and having the market achieve that.
Any other proposal that you've heard today
that doesn't start with that shooting in the dark?
And so then that's what we kept getting back to
because we need to begin with the right part,
and give you guys a plan and a process.
As you said, hope is not a plan.
And so that's what we have worked diligently
on last few months to deliver.
And the second component that was important for us
is you have to achieve the goal
and the requirement through the competitive market,
preserve what has worked so well in ERCOT,
the best and most robust and competitive retail market,
empower reps analysis to solve
and contribute to the reliability.
So with that backdrop, I'm gonna turn over to Arnie.
-: Thank you. -: Thanks, Bill.
And Charlie Commissioners thanks for the opportunity to come
and talk about our proposal with you today.
So just to echo what Bill said, our proposal is,
in fact, to ask the Commission based
on technical work conducted by ERCOT,
to establish a forward looking reliability standard
that the Texas electricity market
would be expected to perform too.
I think, to me, that's the central question
that this Commission faces, is do you wanna continue
with a market where reliability is an outcome of the market?
So we send market signals that we hope will incent
companies investors to invest in generation.
But we're not sure how much reliability
we'll get out of that system.
Now, the theory of that is
that the market outcome should be a function
of customers value of reliability, right?
That's the theory, and it makes sense.
The challenge is we don't really have a system
where customers can realize and experience
their value of reliability in the marketplace.
And we've seen some challenges and dangers
of what happens when we expose customers
to real time prices all the way up
to what their value of reliability might be.
So the reality is, we have a system where
we're not sure what level of reliability we're gonna get.
So that really is the key question
and what we've offered is in effect a straw proposal
or if you accept the proposition
that a forward looking reliability standard is appropriate.
You've offered a straw proposal
for how you might get there in
a way as Bill said, that's most friendly
and most consistent with competitive market principles
as it can be as we can design it,
which is to embed it in the LSE load serving obligation.
So we've listed up here, the challenges that we see.
And we've designed the proposal to address,
ensuring sufficient generation capability.
And this is what Sam described.
That's problem number one, supply adequacy.
And really, all over the proposals
that you've been hearing about today, they're
all really aimed at problem number one, supply adequacy.
I haven't really heard any proposal
that says whose main purpose
is day to day reliability positioning this system
to have the operational responsiveness that Sam described,
they really are always at raising electricity prices
during certain hours of the year to provide incentives
for people to make investments,
they really are all aimed at that investment challenge.
Most of them are aimed very indirectly at that challenge
by incenting behavior and dispatch in response
during certain time periods of the year.
Ours is aimed directly at it by identifying
the characteristics that are needed
to ensure reliability throughout the year,
and directly rewarding them through a generator
accreditation program, which I'll get into.
If you go to the next slide.
So our proposal is a load serving
entity reliability obligation.
In fact, it's a procurement obligation
on the load serving entities,
to procure the quantity of resources that are required
to meet that forward looking reliability standard.
I'll walk through a few of the elements here.
The first element is that ERCOT would on a regular basis,
semi annually, annually do very detailed modeling,
loss of load modeling, considering all
of the various weather conditions
that the system might expect to face,
all of the various supply conditions
looking at conditions on the natural gas system.
And through that process, develop a proposal
for what that reliability standard might look like,
along with information about how costly it would be
to achieve different levels of reliability,
what types of resources that you would need to achieve that?
How each of those resources contributes
towards the meeting that reliability standard,
and whether the system is in fact adequate,
based on their best available information
that they can muster, to look at this problem.
And based on all of that, they would come to the Commission
and ask you for a determination of whether or not the system
is adequate, what the reliability standards should be.
And if the system is not adequate
to trigger this load serving entity reliability obligation
on a three year forward basis.
So in time for new steel on the ground to be developed,
new resources to be constructed to remedy this situation,
so that we can go into the operating near
the operating season the operating day,
with enough capability to make sure
that we can operate the system reliably.
The requirement falls onto the LSE.
It's a natural extension again of their role
in hedging forward energy purchases on behalf
of their customers, assembling a portfolio of resources
that they believe best meets the needs of their customers,
this is just one additional component of
that procurement obligation that they would need to look at.
There will be a showing one year ahead of the time period in
which the deficiency was identified.
That showing is a formal requirement.
And if LSE are deficient, they're penalized.
And any penalty monies that are caught would collect
it could use still in the year ahead timeframe
to take some actions to attempt to remedy the situation.
That's not a lot of time.
But it may be enough time to implement
some emergency demand response, type programs,
load shedding programs that might need to be in time
to identify backup diesel generators,
for example, that could be deployed
to help prepare a physical remedy for the situation.
So we believe that establishing
this forward looking reliability requirement is responsive
to the requirements of SB 3,
which it says that the Commission
should establish requirements to meet the reliability needs
of the power system.
It says that the Commission
should determine the quantity and characteristics
of reliability services necessary
to ensure appropriate reliability.
It procures ancillary and liability services
on a competitive basis, and it develops appropriate
qualification performance requirements for generators.
I spend just a minute now
on this slide about resource accreditation.
So this would be an important component
of the forward shelling process,
which is that LSEs would signed contracts
with individual generators
to procure reliability attributes of those generators.
In order to do that, in order
to know whether our system is gonna be reliable.
We need to have a way of accurately assessing
how each resource would perform
under the conditions that matter most.
And the conditions that matter most are
when the system is the most short
and the most at risk of suffering a loss of load event
and The types of modeling that energy planners do
are designed exactly to address that question
of what are the most stressful conditions on the system?
And narrowing in on really what
is a very few number of hours.
When you might expect to suffer loss,
you don't suffer loss of load once a month,
or even every year, it really only happens under
the most extreme weather conditions.
So what matters the most is how these resources perform
under the most extreme our weather conditions.
And this is what a forward looking assessment
can do for you as you can identify these in advance, again,
as best you can, given the limits of data available to you.
So each resource has its own characteristics.
None of them are perfect.
Each of them have limitations,
solar and wind have limitations based on.
When the weather the sun shining, where the winds blowing,
some of the thermal resources have limitations
based on whether they can get fuel
or whether they're weatherize and those sorts of things.
Can just maybe have another risk.
A couple minutes, I'll wrap up quickly, yeah.
So the next one gets into the issues of LSE showings.
So if triggered, each LSE would be required
to procure enough reliability attributes to meet its share
of the system requirements as identified by ERCOT.
If you go to the last slide.
The LSE obligation would be extinguished at the end
of the four week showing period.
So in fact, you're ahead.
But this really it's an obligation not just on the LSE,
but also on the generators that agreed
to sell these reliability attributes to the LSE.
So the generators would then have an obligation
to perform during the system events.
So ERCOT would identify the potential
for reliability events to occur.
And the generators that sold these reliability attributes
would be required to offer
all their capabilities into the market.
So that ERCOT can be assured now
that those resources are actually going
to be available on the operating day available
for dispatch when they need them the most.
Male: Counter argument.
-: Let me take the first one.
So yeah, the most popular counter argument
I think we've heard so far.
And obviously we've talked a lot
of other stakeholders about this
is that it disadvantages smaller participants
included particularly smaller retail electric providers,
Male: Unaffiliated.
-: Unaffiliated or smaller.
I don't believe that's true at all,
and for a lot of good reasons.
First, is, although this mechanism
is modeled off of Australia,
and it's similar to SPP, and I've also heard some try
to compare it to California, you cannot compare
ERCOT retail market to any other market that exists today.
It is highly robust, the barriers
to entry are extremely low, you are seeing eight
to 10 new rep certificate applications being filed
almost regularly, it's easy to enter
and exit the retail market.
There's really no other market
that you can actually compare it to my opinion.
And so part of the delivery mechanism
that's proposed here is after the accreditation is done,
each of those resources gets a certificate
or a rec like product.
And that is a tradable liquid product that can be purchased.
Similar to what we see today
with the renewable portfolio standard.
I've heard it no one complain about
how the rec market disadvantages any types of retailer.
It's liquid, you can talk to a broker and get a quote on it.
The delivery mechanism and fulfillment mechanism
can be similar to that so
that you have a liquid tradable product.
That is probably the biggest attribute
to help achieve and accomplish that goal
without advantages or disadvantages certain participants.
The second is the amount of the obligation
is based on your sizes rep.
The entity that will have to procure the most capacity
to meet this obligation is right here.
So if you're a smaller rep,
and this is what we really like about this product,
and what really allows reps and LSE
to differentiate themselves, if I'm a small rep
and I wanna meet my obligation
with just demand response, I can do that.
When you're a rep of our size, and you have
to procure thousands of megawatts
to meet your obligation, we don't have that option.
So we have to go out and get all kinds
to meet the reliability share.
So in a way, I would argue it's more burdensome
for the larger reps because we have
a much bigger obligation to cover.
And that's the way it should be, right?
We all need to step up and make sure
that we're covering our share of the obligation.
The third thing which is completely unique to ERCOT,
is I just checked last night,
I see about 2000 broker registrations,
we have a very robust and mature market for retail brokers
that helped provide substantial liquidity on
any types of products energy,
and this product would look no different in terms
of their ability to provide that liquidity for all shapes
and sizes of market participants.
I did you have anything else to add on that one?
-: No.
-: And then the second counter argument
that we've heard is concerned about market power.
And in a way, some of what I just said
that addresses the first counter argument
also helps address the second counter argument,
which is when liquidity.
So do you have a tradable product that's liquid
that helps all entities shapes
and sizes meet their obligation?
You can develop a mechanism to do that.
And the biggest thing that I wanna try
to draw comparison to is today,
the vast majority of reps analysis
meet their energy obligation.
So when we all hedge, we have
to procure supply to meet our load.
That happens through the bilateral energy market.
Vast majority of power that's transacted energy
that's transacted is in the bilateral market,
which would look similar in a concept to this.
That there's been no concerns that I've heard
from the IMM about the bilateral energy market
having a structural issue, that there are mechanisms
that help ensure that there's market power
abuse is prohibited on spot and energy prices,
that helps limit that behavior in the forward market.
But still, that exists and with sufficient competition,
and liquid product, that competition diminishes
those market power opportunities.
And I'm gonna turn the market power
issue over to Arnie to address in more detail.
-: Yeah, which is very briefly,
market power rests in concentration,
if there's degeneration resources,
or too concentrated in a small number of owners,
they might be able to withhold,
and thereby actually execute market power.
That concern exists within all of our cuts markets,
then all of the organized markets,
and there are detailed mitigation plans
that are put in place for the energy market,
we think those could very easily apply
to the sale of these forward reliability certificates
as well, there's no reason why they couldn't.
I've got maybe just a couple of others to raise,
just briefly the issue on the timing that Sam raise.
So we recognize this as a long term solution.
And that's why it's important to plant the seeds now
to start the process now of developing
a more comprehensive holistic reform,
so that over time, we evolve towards a system
in which all of the LSEs have the right incentives
to invest in the right types of resources
that the system needs for reliability,
you can certainly put in place some shorter term fixes,
as this process plays itself out.
And all the design parameters are developed.
And we've heard a lot of ideas on that.
The last one I wanted to raise, actually,
could you go back to the slide
with the restructure accreditation,
I want to address the issue around averaging
that you brought up Chair Lake on this.
And then we have heard this concern
about these types of methods
for accrediting renewable resources in particular,
is this really just a complicated way
of calculating an average?
And I wanna show you that it's not.
And it really is the focus on those most extreme hours,
that prevents you, you know that moves you away
from averaging, you really are concerned
about how does the wind perform
when it's the coldest day of the winter,
when it's the hottest day of the summer.
And it turns out that in most markets
wind is anti correlated
with load during those most extreme events.
So the average winter time wind is might have nothing to do
with how the wind performed during the most extreme day.
And this method is the most accurate one
at capturing the performance of those resources
during those hours that matter the most.
In fact, any other method that moves away
from this invites more and more averaging.
And we heard a lot of discussion
about the RDC proposals that earlier.
And all of those would involve more averaging than these,
although it would provide incentives
for performance during hours that are maybe kind of tight,
but not the most extreme hours
where you really are most worried
about loss of load events potentially.
And then maybe the last thing is that
if you have this reliability certificate program,
there's a question, is this increasing
costs to everyone else?
And what I would say to that is,
this is really ends up being a residual market.
So if all the resources can realize enough revenues through
the daily and hourly energy markets,
and through some of the RDC reform proposals
that we heard about earlier,
then there'll be plenty of certificates.
And there won't be any need really,
for anybody to fuss too much
about procuring enough of this stuff.
It's really only if those other resources,
other systems don't work.
These certificates become in short supply.
And the remedy to market power ultimately, is new entry.
And that's exactly what this is intended
to unsend on a three year forward basis,
is provide the incentives for new entry
into the market building new steel in the ground.
So that provides a natural ceiling on
that the price of these certificates is
they should never get higher in the long run
than the cost of building their resources.
-: Sorry, just to piggyback on that,
and a couple more about the big change,
we're not gonna sit up here
and act like this is something simple
that can be done next year, right?
This is a plan.
This is a process.
Katie mentioned it and I agree there
are numerous important policy decisions
that would need to accompany this proposal
that would need to be made, that's paperwork.
We believe system light.
I agree with Kanaan that it would require changes
to the settlement system for the performance assessment.
But in terms of system and implementation time,
we think that's light.
But there are policy decisions that need to be made.
If we had tried to guess I would say two to three year
implementation time to get all those decisions made.
And then the second thing I wanna add on
to is Katie's concern about guarantees.
You're also not gonna hear us sit up here
and say this is gonna guarantee reliability,
nothing will guarantee you reliability,
a fully regulated utility market
would not have prevented URI.
What this does is it lowers the risk.
Well, it doesn't take zero.
-: Yeah, fair enough.
All right, let's do a quick round of questions.
-: Can kind of go first? -: Yeah, yeah.
-: So Bill, I wanna have you counter
to your own response to that argument.
And that is the impact to the retail market.
You mentioned that.
In fact, California and SPP in Australia
have an LSE obligation in place right now.
But that the difference between those obligations
and in other states and markets countries
is that we have a robust retail market.
So I really wanna understand that a little bit more,
because I almost think that you got to turn
that on its head a little bit, right?
Because that is what we have to be sensitive to
because we have a robust retail market, right?
And I understand that, you know,
we have new reps coming in on a continuous basis.
But isn't that the reason?
Having a robust competitive retail market
is a reason we have new reps signing up to come in.
So I just wanna make sure that I understand that fully,
because that's why we're different.
I don't know if it's a positive,
I think it's something we have to recognize is
that we have a retail market, unlike California.
And, you know, most states in SPP,
and I'm guessing Australia,
but I also do wanna ask you to counter
how your proposal may impact,
could potentially negatively impact
smaller MOUs in some of the smaller electric cooperatives.
-: So yeah, let me try to rephrase your question.
In the context of does this create any advantages
or disadvantages for smaller versus larger entities,
whether it be a rep or an MOU?
And the way that we've thought about that is,
does is there something about this mechanism
that makes it easier for NRG to meet our obligation
than it would a smaller participant?
And I believe that would be true
if there were liquidity issues,
if the market wasn't as competitive and robust
if the proposal didn't accompany
and was fulfilled by a tradable incremental product
that mimics something similar today
that you can get quotes on.
I think that would be a concern.
But that's not what we're proposing.
I don't see that, to me,
the burden is on how much you need to buy.
And, to me, that would be a larger rep that
whoever needs who has the largest obligation is the one
that's gonna have to come up
with the most amount to cover their share, right?
And also, if this proposal required LSE or reps
to buy a very specific type of technology,
like, you know, thermal or some type of mechanism
or some type of resource, instead of anything
that can contribute to reliability gets credit, right?
And so what's gonna happen is LSEs
are gonna naturally gravitate towards the resources
that can provide their obligation,
they can meet their obligation at the lowest cost.
I think demand response is a big winner
in this proposal.
DG, small incremental batteries.
And so those things help really,
I think, really help address the concerns
about any advantages or disadvantages
as a part of this proposal, yep.
-: And then as a spin off, you mentioned how this could work,
sort of the accreditation process
could work like our existing rec trading program.
Is there a salient difference in
that maybe you'd be don't meet your rec,
trading program requirements
that you don't impose a penalty, is that true?
-: I think you have to retire a certain amount
of wrecks to meet your obligation.
If you don't you get assessed a penalty.
-: But in your proposal, if you don't
meet your requirement, you're assessed to penalty.
-: Correct. -: Okay.
-: And that's part of I think,
what Arnie was touching on in terms
of market power concerns, there's a maximum amount
that this product would be valued at,
and it's wherever we set the compliance building.
-: Okay, and then one more on the implementation timeline.
Greater than a year, we know that,
but is it true that we kind of really don't know?
Because I think the only comparisons we have are California,
which is drastically different.
Because they have just a whole different kind of market
with regulated utilities, et cetera.
I think what I heard from Brattle,
and I'll let Sam speak to it later is
that the closest comparisons are California and Australia.
And California doesn't really match our market profile.
So that's not I don't know how much lessons learned
we're gonna squeeze out of there in terms of
how do we build it and how quickly
and then Australia was just a recent market development.
Australia just put in their LSE obligations.
So they really don't have a historical tread
that we can compare to in the lessons from necessarily,
although they do have an energy only market.
So I'm just trying to figure out, as we look at again,
like I said, at the beginning,
near term, mid-term, long-term solutions.
And I know you all conceded, this is a longer term solution.
And but as we sit here today, trying
to ensure reliability in the future,
we got to make sure that we're being realistic
about timelines for implementation and truly calling,
truly making sure that we're taking steps
to get these done in the interim,
even if we have more midterm and long term solutions
out there and being realistic about the implementation,
and complexities surrounding all of the options.
-: Yeah, fair point.
We've got appreciate you guys sticking around
for a little bit longer.
I know Dr. Patton has to get on a plane.
So if it works, we'll just move straight onto
that segment of our programming for today.
Come on up.
-: Okay, can I ask one question real quick,
in the view of this as key LSE
reliability obligation elements.
You have reliability, standard resource accreditation,
system assessment and performance assessments.
Are you proposing that every component
of this gets done by ERCOT
or PUC have a role in setting those standards,
quantifying the value of the resources, things like that?
-: You know, our view of it is that ERCOT would conduct all
of the quantitative modeling.
And they would develop a rich body of evidence,
different model runs at different levels of reliability
with different cost levels
and different levels of resources added.
But then they would bring that to the Commission.
And it would need to be the Commission's job
to look at all that and determine
what an appropriate reliability standard is
how much we ought to be willing to pay for reliability
in Texas and then as to whether or not that it's warranted
to trigger the obligation based on your concern
about how short the market might be in three years.
-: Thanks. -: Thanks, John.
-: Thank you. -: All right.
Come on up.
-: (muffled speaking) what's my timeframe?
-: Your timeframe? -: Yeah.
I have two hours.
Male: We're not that long.
But let's bracket it.
-: Okay.
-: Let's start with your presentation.
And we'll aim to have this segment wrapped up by.
-: 6pm.
-: Okay, yeah.
-: We'll aim for no more than a 30 minute discussion.
-: Okay.
That's great, because I think there are some comments
I'll make that you may wanna discuss with me.
As I go through the presentation.
Even before I get to some of the potential changes
in the market, particularly on this first slide, slide two.
One thing that I think is critically important is that
and I'm glad Sam framed us at the beginning is
that we think really hard about what our objectives are,
and map these various proposals to these objectives.
And one thing that's very useful is
that some of these proposed changes have actually been tried
and other markets we monitor, New York,
New England, the mid-continent, ISO as well as ERCOT.
So other RTOs that we monitor have tried some
of these things, and some of them haven't been successful.
So I think it's really useful to learn
from their experience, and I can talk about why they have
or haven't been successful.
But even before hearing Sam's categorization
of the objectives, I propose these three objectives.
And interestingly, I think they aren't exactly matched up
with Sam's, but I can map these to what he talked about.
And importantly, number one, and number two,
so number one, I labeled as increasing
the total capacity margin,
or targeting some level of capacity margin,
as a potential objective that some
of the proposals seem to be trying to accomplish.
And you can think of that as being
a steel on the ground requirement,
how many power plants do we have?
And then I argue that wasn't really an issue
with winter storm URI, the problem was really
in category number two, which is the objective
of having our power plants be available and be flexible.
So if I were mapping this to a supply adequacy objective,
it's really a combination of number one and number two,
it's how many power plants you have,
and how well they perform.
And the reason it's important to break those apart
and not call them both supply adequacy is
that all of our problems were in number two,
just about if we had more power plants,
we still would have had our outages,
the problem was the power plants we had kind of run.
So understanding how the different proposals would achieve,
you know, more power plants being built
versus allowing power plants
to perform more reliably is critically important.
And then number three, I think
we haven't really talked about it.
But when you rely heavily on the tail end
of the RDC curve at $9,000 to incent behavior
by participants, you can end up
with the sort of catastrophic economic impacts
that we saw coming out of URI.
And I think, in theory, like if you took an economist
and just say, well, should this work?
An economists would say, yeah, well, this should work.
The problem really is we're putting most
of your expected revenues are very large share
of your expected revenues at the tail end
of the at the most extreme end of the RDC curve
in terms of pricing and revenues, is problematic in
that those conditions are extremely hard to forecast.
So if you look at the economic outcomes coming out of URI
for various generators, like the companies
that those generators were well winterized and ran,
the difference between how they fared
and how companies who weren't well winterize performed.
I mean, you're talking about billions
of dollars of differences.
Say you have to look at that and say,
it doesn't look like we have an incentive problem
with winterizing, so why wasn't everybody winterized?
Well, the problem is that if you ask anybody you know,
calculate the percentage chance
that something like URI would happen.
Like, it's almost impossible to even calculate that number.
It's so small.
It's so unlikely.
So if you build a market design around delivering revenues,
in conditions that are almost impossible
to calculate the probability of then
you won't necessarily get get people committing capital
to investments that would address those concerns.
And so that's why relying on the ORDC
and scarcity pricing in and of itself isn't a terrible idea.
Because as you move away from the extreme conditions
that the simply the tight conditions,
those are much easier to forecast
how often you're gonna have those.
And people actually will respond to those incentives,
because they can build a business case around the revenues
that would occur on parts of the curve,
that you're gonna hit 1000 hours a year,
versus the part of the curve that you're gonna hit,
you know, just a few hours, maybe every five years.
Okay, so that's why our proposals generally
address number two, and number three,
now it's unambiguously true that if you do something
to get people to build more power plants,
that's gonna result in more reliability.
But I think that it's a more costly approach.
And when people talk about establishing
a minimum reliability requirements,
and then structuring a market around satisfying,
they're talking about number one,
that's what the capacity markets do in other markets,
they say we're gonna meet a one in 10 standard,
we have to have a capacity margin
coming out of the planning models of 16, 17%,
whatever it is, in different markets,
and then we structure our market to procure it.
And you're largely doing number one, although
how your credit resource should account for number two.
The problem is that those accreditation models
don't envision the sort of extreme circumstances
that you have in like a URI, like,
you're never gonna tell a gas plant
that you're gonna credit them way down,
because there may be some very unlikely situation
where they can't get gas,
because there's a power outage
to the compressors, so gas won't flow.
And so you can't really address number two
with a capacity market very effectively.
You can try to but not really.
So just keep in mind that when you establish
a minimum capacity or a minimum capacity requirement,
you're essentially establishing a capacity market
as you do that, even if it's a bilateral market.
Okay, so, any questions on those sorts
of comments before I move
to the proposal? -: I will save the
questions for end. -: Okay.
So one thing I wanted to mention that hasn't been well,
or hasn't been discussed yet today
is how important Real-Time Co-optimization is.
A lot of the questions that you've asked earlier today
about how you accommodate extreme ramp demands,
like with solar, which is gonna be a problem that needs
to be managed by ERCOT, as well
as fluctuations in wind output, and so forth, are things
that Real-Time Co-optimization is really the only thing
that will meaningfully help ERCOT manage those well
and set prices that reflect the true market conditions.
So I'm gonna sort of refer
to how Real-Time Co-optimization would change
the performance of the markets as
I talk about the first proposal
that I wanna discuss which is related to the ORDC.
So if you'll skip ahead to proposal number two,
I apologize that I'm taking this out of order.
So proposal number two has to do
with improving our scarcity, pricing, our pricing of energy.
And I'm gonna talk a little bit about what's wrong
with what we currently do, which would help improve
reliability and ERCOT and then some
of the changes that we should make.
So at the outset, one thing that's really important is just
to understand what this curve actually means.
It's the shortage value associated with energy and reserves.
And the best way to calculate it is by calculating the value
of lost load how much electricity is worth
to consumers times the probability of losing load.
So as you become more and more short of reserve,
the probability that the lights might goes out goes up.
Now the reason.
So for example, the reason when you're at 5000 megawatts
of reserves, you only get a price of, let's say, $200.
Even though the value of last load is 9000,
is the probability of losing loads at
that point is below 1%.
And so as you start using up your resources,
so you have less resources in reserve,
that the probability something could happen,
that would cause the lights to go out goes up.
So you're moving up this curve.
There's one thing that in Texas,
as always sort of a departure from that basic idea,
and that's this minimum contingency level,
which sort of arbitrarily jumps you up to the cap.
Right now, at 2000 megawatts, there's really no rationale
for that, all it does is just put some revenue
in the very tight conditions.
So it increases your reliance on the extreme events,
I can't see any reason why you shouldn't do away with that.
So that's part of our, that's part of our proposal.
Now, the other thing that you should know
about how this varies from sort
of an economically sound approach, is number one,
because you don't have co-optimization,
you're not utilizing all of your resources efficiently.
And this is particularly important when you ramp.
The amount of reserves you actually have available
to you is the amount of megawatts you can get
to within 10 or 30 minutes, okay.
So put yourself on the bottom of the dark curve
and start ramping all of your conventional generation
as fast as you can.
At that point, you can't get megawatts out of any
of those units that are ramping.
So let's say they're ramping for an hour,
and then you lose 1000 megawatt unit.
You're done, there's nothing you can do
because you're already ramping those units
as fast as you can to make up
for the solar that's going down.
And so effectively, you don't have operating reserves
that are spinning at that point in time.
Now, in ERCOT, that's invisible to you, right?
Because the without Real-Time Co-optimization,
you're not really tracking how many megawatts
you can ramp within 10 minutes,
and you're not trying to allocate your resources
between energy and reserves in the way
that's the most efficient.
Now, what happens in other markets
that are co-optimized is when you're on that dark curve,
if you get into the circumstance
where you're ramping as fast as you can,
and you can't meet your spinning reserve requirements,
which is based on how much you can
ramp your regulation requirements,
which is also how much you can ramp
just in a few second timeframe
as supply and demand fluctuates.
Those markets will recognize that there's a shortage,
and you'll get a high price for 10 minutes, 15 minutes.
And it happens a lot.
Because like in miso we had prices in over $1,000 range
twice in April this year,
because wind chopped off 30 minutes
before it was forecasted miso has in the span
of just an hour to last up to like 12 gigawatts of wind.
Now, if you don't forecast that drop properly,
like if it happens a little earlier
than you thought it was gonna happen,
you're gonna have a serious ramping problem.
And so you can get the shortages that last 10 or 15 minutes.
And those high prices conveniently
don't get paid to the wind
because they're causing the problem
they're not producing out but they do get paid
to everybody who can ramp
and the faster you can ramp the more money you make.
Also, and this is a problem in ERCOT,
it gets paid to your offline peaking units.
You're not paying your offline picking units
except a very small subset of people
who can start in 10 minutes.
So in other markets
because this curve sets the price for reserves.
Anybody who's selling reserves gets paid.
So I guarantee you want your gas turbines
to get paid the ORDC adder even
if they can only start in 30 minutes
because they are a critical component of what's keeping
They're included in the calculation of your reserves
to some extent, but they are critically important
for determining how likely am I to lose load.
So there are some not having co-optimization makes
it harder for the ORDC to be fully effective
at compensating dispatchable units,
flexible units and gas peaking units.
But so there are some improvements
that you could do in that regard.
Even before you get to co-optimization,
we could track how much ramp bubble capacity you have,
or ERCOT has, so that you could adapt the system
to recognize ramp shortages.
And if ERCOT says Real-Time CO-optimization
is I don't know what they're saying now, to be honest,
but if they're saying it's four or five years away,
it might be worth doing that.
If we're gonna get a lot of solar
before Real-Time Co-optimization can be in place.
So go ahead to the next slide.
Go one more, I'll talk about these things.
So this is in effect, what
we're proposing you do at the ORDC.
And I think what would be useful is
to talk through a lot of the scenarios that you raised,
and how this would affect those scenarios.
But one important thing to keep in mind is that you know,
people have listed as a con of a lot of these proposals
that it won't be guaranteed that people will build.
But as an economist, and I think what I would say is
that if you increase the expected revenues
that a generator would receive all other things equal,
they're gonna invest more,
and they're gonna retire fewer resources.
And we're already seeing that even in today's market,
although there's opportunities for improvements.
There's one company that's in the middle of a process
to build 4000 megawatts of peakers.
I think by the end of this year, they will built 1500.
We've seen units come out of mothball.
Our capacity margin next year is forecasted to be 28%.
So we do see folks responding to the shortage pricing,
I think when you rely on extreme events,
the bad part of that scenario is
that when they haven't happened
for a while, people will underestimate
the probability that they would happen.
And then once they happen, they'll tend to overestimate
so you end up with kind of a boom bust.
And I think we're kind of in the boom part of that
because of the amount of money
that people saw change hands during URI.
So we don't disagree with your objective
to move away from the reliance on the emergency conditions,
which is really down in the blue area of this curve.
And one way to do that is to cap the system wide offer cap,
the maximum price that can be generated
by the curve at something like 5000 megawatts,
you do you want it to be high enough
to provoke the demand response that can respond
to help you keep the lights on for the non-flexible loads.
So I thought the comments of the industrial
representative were extremely insightful in that regard.
So capping it at something like $5,000 makes sense.
Now, I've heard people talk about
fattening the end of the tail.
If you go back to the formula of value of loss load
times the probability of losing load,
you shouldn't arbitrarily change the probability
of losing load to something that it's not.
So some proposals that have said
increase the standard deviation.
That is a deliberate departure away
from what ERCOT is estimated the probability of losing load
is the variable you can change
and should change is the value of last load.
The study support a much higher value
of loss load the $9,000.
Now it doesn't mean you'll actually pay it,
it means that and then in this green line here,
the reason that it's higher on the tail end of the curve,
is because we're calculating that curve based on something
that's closer to a $20,000 value of loss load.
So what you're saying when you do that is when we start
to get tight in the five to $6,000 range,
we care a tremendous amount that we minimize the chance
that we're gonna lose load
because losing load is extremely valuable.
In fact, it's more valuable than $9,000.
It's easy.
We're proposing in my so a $23,000 value of loss load,
it's easy to support a $20,000 value loss load.
It's not easy to justify paying it for 30 hours straight,
which is why the cap makes some sense
to de emphasize the extreme shortage,
but that area I've circled there,
it's important to recognize you're gonna be in that zone,
probably one to 2000 times as often
as you are in the blue zone.
So although it looks small and we do zoom in on it,
so that you can see better
that there's a meaningful gap in prices,
you're there so much more often than you are
lower in the curve, that if you look at the performer
for a peaking unit, that would hugely incentive
or increase the net revenue of peaking units
who are providing your reserves,
presuming that they get paid the ORDC,
adder which they don't all get paid.
So we should fix that.
So this would be a meaningful change,
it wouldn't rely on the market being so tight
that you're on the precipice of losing load,
but it would, it would greatly increase the the payments
and to the comment earlier about,
you don't wanna fatten the tail to just create a tax.
This is absolutely not a tax
because that adder is based on the probability
of losing load times of value that we all believe in
as far as the value of keeping the lights on.
So when you get into that area,
and you're paying $100 adder, let's say, or a $200 adder,
that adder reflects the reliability threat
of being in the tight condition.
So it's absolutely justified.
And it's in no way in my mind, a tax.
And now let's talk about the solar the dark curve ramp.
If ERCOT is not perfectly prepared for the dark curve,
in most cases, they should be prepared in terms
of how they turn on the units
and their dispatch software should
be holding units at a level that when you enter
into the dark curve, you're right
that just a few combined cycles can't handle it.
But if you have 100 units that are all way down
in their operating range, that it's not gonna
be overly taxing for them all to move.
But you will bounce into this range
for 15 minutes, 30 minutes an hour.
And when you bounce into that range,
you're gonna be generating revenues
for the units that are dispatchable.
And that are helping you maintain reliability.
And importantly, what we've shown in our reports,
is when you get deeper into this range,
like into the three 4000 areas,
that's almost always gonna happen
because the intermittence are producing at low levels.
So we have this concept in our reports called the net load,
which is the load minus the renewable resources.
So although we wouldn't advocate
for doing anything deliberate
to discriminate against the intermittence,
like don't pay them the ORDC,
it's naturally going to be the case
that to the extent they're putting you in this range,
they're generating at very low levels.
And so the meaningful revenues that are generated
by the ORDC are gonna go to everybody else
who's helping you and not go to them.
Trying to think if there was
another scenario that you asked about.
It's not coming to mind, but so why don't I pause there?
Do you have any questions about this
particular proposal? -: Well, I tell you what,
we're getting tight on time,
if we're gonna keep going.
So go ahead and bring it home for us, if you will,
and we'll do a round of questions with the Commission.
-: Okay, so let's go back to proposal number one.
Okay, so I don't wanna mislead you into thinking
that we are opponents of capacity markets,
we don't think capacity markets are evil
or should be avoided at all cost,
but we think they have significant problems.
And the most significant problem is the money
for nothing problem, that we accredit resources.
We pay the millions of dollars,
and then you get into a circumstance like URI or situations
that are less dramatic than URI.
And you look at a bunch of resources
that you paid in the capacity market,
and they weren't there.
And you say, well, what are we doing here?
You know, why are we giving these people money
if they're not gonna keep the lights on?
So go forward one slide.
So one way to even out the revenues
that generators receive and to pay for reliability in a way
that will sustain an adequate resource base.
But do so in a way that's consistent
with your energy only market is
to create a mandatory forward hedge.
So this is a I call it a four shortage energy hedge.
So it has some of the characteristics
that look kind of like a capacity requirement,
but it's really not, it's entirely a financial product.
And it's based on the amount of an accredited amount
of the hedge that a particular generator
could be deemed to be adequate to sell.
Because you do want this to be a physical product.
So what happens is, I have a 50 megawatt gas turbine,
it's accredited at 45 megawatts.
So I buy 45 megawatts of this hedge from the turbine now,
when the shortage happens, and that turbine is producing
or selling reserves providing reserves,
they don't get paid the ORDC adder,
because they've sold that forward.
So they're gonna get a ton of revenues
by selling the hedge, but they don't get the ORDC revenues.
Now, if they're not available,
they have to pay the ORDC price.
So they are directly on the hook for the extent
to which they are contributing
to the tight condition, or the load shedding event.
But remember, most of the ORDC adder
is gonna be in periods where you're not very close
to shutting load, it's just tight conditions,
they're contributing to it.
And so they're financially on the hook.
If you do that, I guarantee you that
that's gonna create an enormous incentive
to firm your fuel to have dual fuel capability
like no company is going to be wanting to hold these hedges.
And not have the ability to perform
with a reasonably high probability.
So creates a very strong incentive for companies
to do things to ensure that they will be available
and it directly compensates them
with based on their actual availability.
And what it does from a revenue standpoint,
is shown in the picture here.
The one problem with relying on extreme events and the ORDC.
Is you get what you see on the left.
And if you look in our report at the net revenues,
we compare the ERCOT to other markets around the country.
ERCOTs almost always the lowest, and it's the lowest
because when you don't have a significant amount
of shortages, basically you're relying on energy
and ancillary service revenues and non shortage hours.
And there's not a lot of profit margin built into those
because the outcome market is fairly competitive.
In other markets, there's a big chunk of capacity revenues
that look like the green on the right,
like in the rest of the Eastern interconnect.
But in ERCOT, all those revenues
are embedded in shortage pricing.
So you get almost nothing in most years,
and then you get the one year where it's enormous.
And it makes it hard to invest around that
because if you can't calculate the probability
of the year for happening, then it's really hard
to make the business case and get financing.
But if you have a mandatory hedge,
it will spread out the revenues associated
with the mandatory hedge will be based on
the expected value of your for happening.
And so you'll get a much more even incentive to invest.
I think it'll go a long way to meeting the obligation
to maintain a an adequate base of resources,
but also give them a much stronger incentive
to perform as the system starts to get tight.
And that will be more and more important.
The more intermittency you have,
the more you're gonna bounce into the range
where the market is tight,
but not now the lights aren't going out,
but the system is tight
because the intermittence are fluctuating,
particularly if it's hard to forecast.
So wind is a much bigger problem than solar,
because it's hard to forecast the wind,
and they're highly correlated with one another.
And then the last proposal is,
I'll just mention it briefly
so that you all can ask questions.
The one thing that's really missing in a lot of markets,
including ERCOT is a longer term reserve product.
We have 30 minute reserves and 10 minute reserves
are common in all markets, but what we need
with more and more intermittency is something like
a four hour reserve product, a two to four hours,
so when a RTS starts to realize
that the wind is forecasted incorrectly
or the load is higher than expected,
instead of doing things out
of market like wrecking resources,
they deploy these longer term reserves
and more units can sell it.
So it syncs up the operations of most RTS with the products.
And importantly, it's integrated
with the rest of the products,
the one thing I think I would stay away from are products
that are outside the market operations,
that's been tried and not worked,
you know, buying reserves forward.
And trying to hold them outside
the market was done by New England,
it's really been kind of a disaster,
and they're trying to eliminate that product at this point.
This, on the other hand, would would be integrated
and co-optimized with the rest of the reserve products,
and a lot more resources could sell it,
you know, any resource that could get on within,
say, two hours could sell it.
And the importance of allowing them to sell it is
it puts all of those actions
that ERCOT takes committing units like that
and puts them into the market and prices them,
which provides better incentives for everybody.
And it gives you a better signal
that you're actually getting tight,
when you start to run out of two to four hour units,
you should be recognizing
that the system is starting to get tight.
So that ORDC could capture
this product when and if we define it.
-: All right.
Good deal.
Thank you very much.
There's a lot to unpack there.
I know, my colleagues will have some questions.
I'll start with just one question.
Both in your comments and a variety of others
two themes have heard our (indistinct) procurement,
more than just the dam,
allow us visibility on extend revenues out more than a day,
potentially, a month, a quarter a year,
and essentially require full hedging.
Especially your comments and the previous speakers.
But what I'm still have an open question about
is we're trying to solve a lot of problems created
by weather dependent resources that suddenly stop generating
and forecasting weather is hard.
It's hard for everybody.
Nobody's particularly good at it.
Some people are better than others, but it's difficult.
And so even in your example of the forward hedge
with the entire name, right? -: Yeah.
-: And in a lot of other comments we've had
the reason we've got that high cap that high vol is
that's a huge incentive for generators to perform,
because if they don't perform, most of them are hedged.
And if there's a required hedge,
they've got to go pay this extraordinary cost
to meet their obligation to provide power.
That's a tremendous incentive to generate power.
Where's the incentive for intermittence
to generate power when we need it?
Why don't they get the same penalty
for suddenly stopping generating power?
Another way to think about it is if you have two windmills,
for example, one investor has a freelance,
if it does have a bilateral,
it's as generated not even a fit curve contract,
you have another windmill that is associated with storage,
battery, compressed air, whatever collocated,
associated off site, whatever it is,
what in any of these proposals is going
to incentivize an investor
to firm up that intermittent resource?
Whether avoiding a penalty or providing a proactive,
like avoiding the high cap penalty
or providing a adder or proactive incentive?
-: Yeah, that's a great question.
And I wanted to distinguish one thing
about the forward procurement in some
of the other proposals from this one,
because I think it goes directly to your question is
if you look at the economics associated
with that forward hedge, although you're buying it forward,
all of the economics and incentives associated
with it are linked to what's happening in real time.
So it links back to our real reliability circumstance,
which is critically important in my mind
because it is the one thing that ensures
that the resources that help us keep the lights on get paid
and the ones that contribute to the lights going out,
don't get paid or get charged,
which is different than some of the proposals
that procure things forward and generate revenue streams
that are not connected in any real way
to the real time outcomes, so, to the wind example.
It's one of the reasons why I can't get away
from the primary incentive being paying people
for the value of the reserves
and the energy in the real time,
because if I'm right, that fast forward five years,
nine 90% of our shortages are gonna be
when intermittence are producing at low levels,
and I'm a wind resource.
And I can see that my net revenues aren't very good,
because every time the price is high in ERCOT,
I'm not running, or I'm producing very low,
because I'm contributing to the problem.
The economics of me putting a battery on my site,
so that when all my buddies are producing nothing,
I'm producing a lot.
Like my net revenues versus them
are gonna be night and day.
In fact, we've done that calculation.
-: But it hasn't happened yet.
We've had those incentives, we've had 9000,
and there are no batteries
next to wind mills of any meaningful scale.
-: Sure, but that goes back to the fact
that all we've really had is a circumstance
that would have been almost impossible
for someone to attach a probability to
and spend a lot of money on the basis of
with the change in the ORDC that we're discussing here.
The economics, given that you're running into the bottom of
that curve thousands of times a year,
you're dramatically increasing the value of having a battery
that you know, if I can make $200 $1,000 a year.
-: Shifting ORD curves firm up our entire intermittent fleet.
-: It will form up the entire intermittent fleet,
I would doubt that's the case.
-: Because right now, it's pretty close to zero.
And if we don't from a fire in intermittently,
we're gonna be chasing the dark curve
for the next 100 years, whether
it be eternally spiraling towards.
-: The other thing I would say about
that the other proposal.
Remember how I said, for the forward hedge,
it's gonna produce a lot of revenues
that are very predictable over time.
And that I said that, that has to be a physical,
you have to have the ability to perform,
you don't want that to be a purely financial product
that J.P. Morgan can come rolling in
and sell it to you with no power plant.
For example, as soon as an intermittent resource
puts a battery on their site, the amount of
that hedge they can sell is gonna go from,
let's say, 7%, five to 7% to some much higher level,
because the amount of firmness
that you can accredit them goes way up, so that change.
-: And then they're also under the full hedging construct.
They're also liable to that penalty as well.
-: Which you absolutely want.
-: I agree.
I don't think a lot of window operators want
to be associated with that penalty
when they've got essentially a free ride right now.
-: Yeah. -: I was gonna say,
well, I think one
of the reasons why they're not putting batteries on,
love your opinion is a lot of these
in West Texas are bought behind congestion.
So they're not even getting paid right now
because of their getting curtailed.
So why would they go add more capital costs to their plant,
if there we don't have any expectation?
-: (muffled speaking) if they were worried
about generating revenues,
they wouldn't have built behind congestion.
-: Well, I think what happens is they didn't
they did the smart movers built first,
you know, the farthest away to the best wind resource.
And then the way our interconnection process works,
everybody built, you know, in front of them towards load.
So, you know, the original wind generator went
to the best capacity factor wind,
which was the furthest away, and then everybody said,
Well, what the heck?
I'm just gonna build along
that same transmission line closer,
and the furthest ended up being the one
that gets curtailed first.
So it's not a matter of when you invested.
Well, it is a matter of when you invest it,
but not the value or the volume of your wind.
-: Sure.
So pay that forward.
And if the winds not blowing and prices are high,
even under a current construct, even a battery on
that furthest windmill should be generating excess economics
and others wouldn't, we have no battery.
-: I think on a compared to basis between
one mill and one without.
So it might produce, if you're assuming
that all the congestion has gone?
-: No, I mean, I think if we can't get an investor
who's firmed up in intermittent resorts
to make money first versus other folks,
then we're not doing our job.
But the point of the battery was even
if there's transmission, even there's congestion
in West Texas, if the winds not blowing and prices are up,
that fully charged battery would have a free pass down
that transmission line to the revenues, right?
-: Potentially, I think.
As long as solar and all the other resources
don't come in in front of them.
-: So I will say with the data we have, we could estimate
and I'm 90 some percent confident that we could show you
a battery is extremely economic under these proposals.
Because you know, we can calculate
how much additional net revenue
a battery in West Texas would make if you were
to just the ORDC in this manner.
Male: Good to know, it's that simple.
-: It's not simple.
We have access to a lot of data.
-: Okay, so kind of back to a broader discussion
on this forward hedging proposal that you put forth.
Can you just kind of compare and contrast it
with the LSE obligation?
I know you mentioned that it's not purely financial,
but it involves some physical, right?
And it sounds like the LSE obligation
is more of a physical obligation.
Can you compare and contrast
your forward hedging proposal with that?
-: So we've estimated in other markets,
A one in 10 reliability standard implies
in terms of the value of loss load.
And it's somewhere in the neighborhood
of $200,000 per megawatt hour.
So the if you were to ask the question,
why, in New York, for example, if I look at a peaking unit,
why do they make more than half their revenues
in the capacity market and the rest in the energy market
because they have shortage pricing and so forth,
or same thing in New England?
It's because they have a capacity requirement
that is extremely expensive to try to satisfy.
And so they maintain a base of resources,
that makes shortages, less frequent.
The thing with the forward capacity hedge is it links
to whatever value of loss load you're setting
for your energy and ancillary service markets.
So you get much better performance incentives out of it.
But also, you won't generally maintain as high a level
of high a base of iron in the ground,
or steel in the ground as you would
in a traditional capacity market.
So I would imagine, it's hard to say where you'd end up
in the E3 proposal.
Because we don't want know what
that requirement would look like.
But I would imagine it would lead you
to more installed capacity
and weaker performance incentives.
-: So would your forward hedging proposal be contingent
on a successful real time quantization implementation?
Or could it stand on its own two feet
and still provide value?
-: It can still operate under the current ORDC,
it's just that the problem with the current ORDC
is we're not gonna price a lot of the circumstances
where we actually are tight,
particularly the ramping hours where we're tight,
but because we're not jointly optimizing our reserves
and energy, we just don't price that today.
-: So you mentioned better performance?
-: Yes. -: That's the key.
-: Yes. -: And I know nobody
can guarantee you still on the ground,
I mean, how does it impact dispatchable
generation in this though?
-: It will definitely increase dispatchable investment
because the predictable increase in net revenue,
like any investor who's doing an analysis
of the economics of an investment in a peeker resource
with an ORDC that is going to trigger
and generate more than double the revenues
that the current ORDC does during tight conditions
is gonna find that the incentive to invest in
a peaking unit is significantly higher than it is today.
Now, again, it's important that the peaking units
get paid the ORDC adder and many of them don't.
So that's an important caveat.
So if you're talking about investment in new gas resources
that don't have access to the ORDC,
when they're offline, that's a problem.
And we should fix that problem.
-: But is it an offline peaker problem
or more of we're looking to add more hours of ORDC
and we're gonna have less peak times,
And so peaker units are not just gonna be
on the system, whether they're?
-: No, I mean, the thing is the I don't know
if you can go back to one of the charts that shows the ORDC.
But either one, that quantity
of real time reserves down at the bottom.
We don't calculate that exactly correctly today.
But let's imagine we calculated that
so that it reflected, our online reserves,
our offline 10 minute reserves and our 30 minute reserves,
so that every megawatt you're seeing on
that axis as a megawatt of peaking resource can sell you,
as you go short, it's gonna be the case
that any available peaker is gonna be selling you one
of those classes and reserves
and should be getting paid the ORDC
if we made some changes to how the ORDC settles,
And so that's why I think, yeah,
we're not gonna have a problem under
this sort of reform
with under compensating peaking resources.
-: Okay.
Do other markets have a forward hedging mechanism
that we can compare to?
-: They do they, I mean, one thing
about the electric industry is everyone wants
to use their own terminology,
and it sort of muddies the water,
but PJM and New England has something they call
that pay for performance regime.
And if you look hard at what that regime is
it basically when they buy capacity embedded
in the capacity product is a forward hedge
of a component of their shortage pricing.
So right now, for instance, in New England,
I think we're now at $5,700.
If they have any sort of shortage
of 30 minute or 10 minute reserves,
and you're a capacity seller,
and you don't perform, then you're charged $5,700.
And if you're not a capacity seller,
and you do produce megawatts
or self reserves, you get paid $5,700.
So that is a forward shortage pricing hedge
it's just cloaked in terminology
that might not make it clear that it's similar
to what we're talking about here.
-: Yeah, I wanna get one in.
So, Dr. Patton, the backstop reliability service,
which was proposed by the industrial energy consumers
before you spoke, let me read you this slide
consider allocation similar
to the reliability unit commitment,
which allocates cost to capacity short,
qualified scheduling entities,
this would increase long term hedging incentives.
When net peak load is anticipated,
the price of the service should increase
and more costs should be allocated
to capacity short entities in the market.
Can you please explain the difference between
your forward shortage energy hedge and that proposal?
-: Well, I have to say I'm not an expert on
what they were proposing.
But to the extent that there's a separate product.
I mean, that would be the key difference
that the forward hedge that we're talking about
is links back to energy and ancillary services
that ERCOT is utilizing to keep the lights on
and that we are pricing in the real time market.
And so as we get short of the megawatts
that are providing our reliability, the price would go up,
and the hedge would settle against that.
I think any proposal that would create some separate product
that is not part of our cots operating protocol,
I think is you know, doesn't have the same advantages.
-: Okay, but conceptually,
they are in the same universe, sounds like?
-: They maybe, why don't I get back to you?
Male: Okay, that would be helpful.
-: I'll take a look at that product
and try to give you a better idea
of what the difference are.
-: You did prefer it uncertainty product, which.
-: Yes. -: Might be why
you preferred it.
-: That's simply a longer term reserve
product longer than 30 minutes.
So most of the time, just kind of an idea why 10 minute
and 30 minute reserves emerged in the industry,
is generally those reserve products exists
to satisfy narcs reliability requirements
that when a big unit ships off, within 10 minutes,
you need to have supply and demand in balance,
and then within 30 minutes, you need
to recover your 10 Minute reserve.
So you need to have something
you can turn on within 30 minutes.
Now, if you listen to that explanation,
I didn't say anything about missing the wind forecast,
for example, or missing the load forecast
we're headed into as a situation where
having a unit trip off our
is not our big reliability problem.
It's Miss forecasting the wind
is much bigger problem and myself.
And responding to that concern, there a much larger number
of resources that that take longer to start
that can help you with that problem
than the immediate problem
of replacing a unit that just chipped off line.
-: Would your product needed ERCOT system change
that is impacted by the MS upgrade?
-: Yes.
Yeah, the good news about the ORDC
is this sort of change can be done very, very quickly.
And it's the most effective thing that you can do,
then certainly product is a new product
that I imagined would be in Kaanans,
you know, to your timeframe.
-: All right, excellent, Jimmy, any more questions?
-: No.
-: All right.
Thank you, Dr. Patton, will obviously love for you
to stick around as long as you can,
but don't miss your flight.
-: I'll be around for another hour and a half.
-: Okay.
-: So you can let me know if you have other questions.
-: Brave man to admit that information,
will have you back up here.
At this point, we're gonna shift gears a little bit
and ask Commissioner McAdams to lay out
his memo on interconnect priority.
We'll lay that out.
And I know we'll wanna have some discussion
on the Commission and hopefully by 2:30.
We'll start with the rattle conclusions.
20, 30 minutes on their thoughts
on the presentations for the day.
And from three to four, we'll wrap up
with open conversation for the Commission,
does it work for everybody?
-: Good for me. -: All right.
-: Commissioner, as I tried to be brief
and concise in the memo, the overarching policy premise
is speed expeditious employment policy,
to where we can start sending meaningful signals
to market participants as soon as possible.
And I'm gonna welcome thoughts on this memo.
But as you all know, we have a great deal
of we have natural gas in queue
and transmission interconnection
but we also have a great deal of batteries.
And what we're trying to do,
I believe, in our conversations, and even today
with the greater market design efforts,
is send a layered strategy of signals
to market participants that we want
certain performance characteristics soon
to arrest any type of dark curve phenomenon
to help meet the threat of a URI event.
Bottom line is we need you to be able,
we would like you to be able to be dispatchable
in the future for command and control of ERCOT.
The transmission interconnection process is in my view,
one of those pieces of low hanging fruit
that could be looked at sooner rather than later.
And I'm talking about working with TDSPs,
starting next year to prioritize those dispatchable projects
that could be and again right now,
it's just first come first serve you're in line due
to the date of your application.
And again, it's an 18 month process typically
to do the studies between ERCOT
and the transmission service provider,
the on course, the APS, but even the knollys.
What this would do is depending
on those performance characteristics,
and I actually articulated what in my view,
some of the non negotiables are I actually shot the moon
and for our dispatch ability.
Again, it's not the 24 hours,
which we can talk about with Randall later
but it's takes a step in qualifying batteries,
you know, pairing of batteries with intermittent resources
to qualify, and getting those front loaded
in those interconnection processes.
It's my understanding that a great deal
of the financing that happens in the renewable space
or any generator, but especially the renewable space,
and especially solar, is that those financing arrangements
aren't really like solidified until they get
a firm confirmation of an interconnection process
from the interconnection process.
And so right now, there's not really an
a clear cut black and white incentive
for them to deploy batteries as is,
because the price of power is still lucrative for them,
the federal policy is still lucrative for them.
So this would be just one more signal
that we could send to those developers
and then to the financiers who are funding these projects,
that this is what the state of Texas
ultimately desires more in the near future,
and you might qualify.
So with that, we've got a lot of experience on this Dyess,
so I'd love to hear any thoughts.
-: Sure.
Thank you, Commissioner McAdams for looking into this issue,
as we look to it, you know, ensure more greater liability,
more dispatchable generation investment in the state,
we must leave no stone unturned.
I generally agree with the spirit of your memo.
I guess I have a question, and then maybe a statement.
So I'm trying to understand the mechanics
of how this will work.
Okay, by moving generation up batteries up
and then having renewable generation
after them in the interconnection queue.
So would this mean that if you're ready
to go as a solar generator, or wind generator,
do you have to wait until the gas generation plant goes?
And what if they're not ready?
-: Right, so that's why I put a time limit on this
to where that process resets.
If they get all of their ready to go,
key condition dispatchable projects studied
and approved and on course, for execution of the project
and development of the project,
then those non dispatchable paired intermittence
would then be right there in the queue.
I think the problem is there's a backlog,
there's so many projects in queue within
so many transmission service providers,
either, again, non opt in entities or competitive area,
territory, service providers, that a backlog forms,
and again, they're inundated with requests,
I liken it to a city permit office, you know,
so they're trying to meet the shot clocks
that they have on themselves.
But any type of prioritization effort
that is beyond just the normal time
of application submission,
could make a meaningful difference.
And again, get those projects reviewed through
and then they turn to the straight intermittent
resources after that, they could still process them,
but then they reset that queue after a year.
-: Okay, I think I understand that.
So, you know, again,
I guess kind of a mechanical sort of statement.
I mean, does ERCOT need more
interconnection assisting staff?
Is there a shortage out of ERCOT?
-: I don't know, if this necessarily
the ERCOT phenomenon is the TSP.
-: Okay.
-: Again, ERCOT does a component of the studies
but then the TSPs, they're in the trenches doing this.
It's their systems that are.
-: Okay. -: Interconnected.
-: Okay.
Thank you for that clarification.
So it resets every year almost?
-: Yeah, because if it's an 18 month process,
again, you want and a portion of that,
say eight months of that is ERCOT,
we can get ERCOT up later Kaanan,
I'm sure you don't wanna get balled up
in this this in your field.
But we can talk to him about it later.
But if eight months of it is ERCOT
and a year of it is the TSP, then we wanna try
to get them, you know, through their backlog
of qualified dispatchable projects, if any are ready to go.
-: Okay.
So it's more of a signal to the utilities.
-: That's right. -: That we want them
to prioritize that type of, rather than ERCOT.
-: Well, so I think everybody applies
to the ricotta interconnection process.
Everybody's in the same queue.
There are different types of resources in there.
Obviously, if you've looked at the interconnection queue,
it's very long and there are ways that projects
that are ready can get to the head of the line anyway,
it's because some of the TSPs
actually get the studies done quicker.
And, you know, a lot of this is done by the TSPs.
In other markets, they use third party firms that go,
they hire additional third party firms
to do interconnection work and do the studies.
There are three or four different studies,
depending on markets, what needs to be completed
before you can get your final interconnection agreement.
Sometimes those take short time,
sometimes they're very, very controversial,
depending upon what facilities are deemed needed.
That's not as much a problem in ERCOT,
because the TSP pays for most of the interconnection.
So that challenge has gone away to a large extent here.
I think the goal of moving something that's dispatchable,
you know, satisfies what the Governor wants
And is, I think something that the market needs.
I'm concerned about one thing, and that is,
if there are entities that are in the process
that have already spent money on studies,
as they have been required to
is there some legal issue associated with that.
-: You mean grandfather and conditions that can be imposed,
If they're almost there that they just move on through?
-: Yeah, yeah, exactly, something like that.
I'm afraid that we don't wanna get
into a legal snafu here.
But, you know, if we tell, you know,
a guy who's number one in the queue, who, you know.
-: Who's almost there. -: Who's almost done,
you know, you have to move to the back.
-: But this is our value, your experience,
because a lot of them just sort of put
that minimum amount of,
so what's the threshold that you'd advise on?
-: I don't have an answer for you right now.
But I know, you know, we could come up
with one that I think would be valuable.
I think we have found that there used to be a lot
of as we called Mom and Pop developers
that would just go file or interconnection,
they were developers that were wanting to sell projects.
So they just filed these interconnections.
-: Buying a call option.
-: Buying a call option, and that's exactly right.
Interconnection didn't cost much.
You didn't have to do money studies,
you just threw your name in the queue,
and you were done with it.
I'm not sure that is all of our problem right now.
I think we've attracted so much global attention
to build resources in our market
is really what the issue is.
But I think, you know, sticking
with finding something that's dispatchable.
And if we're trying to remain agnostic,
if we're gonna put a battery with wind
or battery with solar, I mean, actually,
you could put a battery with thermal generation too
and actually make it even quicker start they could apply to,
you could put it at a combined cycle plant
and they can ramp very quickly.
But doing this, I think follows the the point
of what I think we're intending to do here,
and I just don't want there
to be some unintended consequences
that people have already spent a lot of money
and gone away down a queue process to be disadvantaged.
-: And that's where I was going next.
And so I definitely agree with the spirit of your memo.
And obviously, we are charged
to carry forward this direction from the Governor
and in some cases, the legislature
with respect to this specific issue,
as I look at it, that's the lens I'm looking at it is
from an unintended consequences standpoint,
with respect to impacting investment
that's already been made.
That's sort of, like Jimmy described,
already has some momentum going
and they're gonna get reshuffled.
Also, you know, recognizing the fact that,
you know, by moving we are here today,
because we're working on trying
to send more price signals to the market,
so that a portion of that 13,000 megawatts
actually does come to fruition, because right now,
based on historical trends, it's only 1%
of gas generation that comes to fruition, traditionally,
so by moving it up, we're hoping that you know,
what we do here, actually, you know,
sends it out of the gate, right?
Secondly, I wanna kind of zoom in into sort
of a point I tried to make earlier,
I completely recognize that renewable generation
has its variability issues.
But with respect to solar, you know,
we have received grid reliability updates all summer long
from ERCOT, where a significant percentage
showed up during the summer
to provide generation that we really needed.
And I do think that in some cases,
solar is a little bit more of a predictable resource.
And what I don't wanna do
is having unintended consequences on
a little bit more of a reliable intermittent resource
that has actually helped us in some situations
where we are really tight.
And it also a resource that can be built very quickly.
Months, you know, in about a year versus,
you know, a gas generation plant
that can take about two years or more.
So in the interim, while we send these signals out
through whatever pathways that we ultimately decide,
we have to recognize it's gonna take about two years
to get a plant online, if not more,
but what are we gonna do in the interim,
and I just don't wanna impact our ability
to get some quickly built resources
that can help us during times when we need it
in certain periods of the year.
I reshuffling but it sounds like
from what Commissioner McAdams is saying
that the shot clock, you know,
starting in a periodic basis might address that issue.
And I would also expound
on the legal issue that Jimmy raised.
I know, Commissioner McAdams you mentioned the TDUs.
But one thing we got to make sure
that if they're ready to interconnect,
we can't just tell them no, right?
There's a pair of statutory required.
-: That's not the intention. -: Okay.
So because there is a statutory requirement against
that Imperial right now we're at 39 151.
And I just wanna be mindful,
and it's a requirement on ERCOT.
I just wanna be mindful that we're not putting you know,
anybody in an illegal stable.
-: I think (muffled speaking) are you ready to interconnect?
I mean, are you going, you know,
and we have so much hypothetical, we still do,
I mean, queue huge, hypothetical projects out there.
And from a sorting perspective, again,
this is just one more layered signal that says,
look, you can get to the front of the line,
after all these guys who have said,
they're ready to interconnect,
and they're gonna energize
that they're gonna get their eye out there.
After they're, you know, flush through the process,
then then we get to this prioritization scheme.
And it'll be there for you.
And hopefully, it proves decisive in years to come.
I mean, it just seems consistent policy with again,
what we're talking about on that curve.
And as the solar deploys, and I agree with you,
it's a great resource at peak, we just have
to how it how we come down off that solar hot.
-: And we need to continue to study the dark curve,
because again, I still think
we are different than California.
And I really want ERCOT to really take
a deeper look at that.
I know they already have been
but really give us a very Texas perspective
of what we're facing with that amount
of solar on our system.
-: Value here.
And what you propose, well, it's just two part,
one, it's a very important signal
that we value dispatch ability of any flavor.
-: He's right.
-: That could be combined cycle gas could be bigger gas,
it could be battery, that could be compressed air,
it could be hydrogen, it's dispatchability the key,
certainly never gonna tell a generating asset
that they can't hook up.
We're just gonna focus on the dispatchable ones first.
The second real value add, I think is
that to Laura's point about timing.
Certainly solar is very quick to be in terms
of implementation to full operation and fully energized,
but batteries are even quicker.
And so to the extent that this can move batteries up
to the we always wanna be wary of unintended consequences.
But if one of the consequences is we have more batteries
at the front of the line sooner,
that's one of the best things we can do in terms
of physical steel on the ground for next summer.
And I think the important value in this proposal,
I think the devil is always in the details.
Certainly think just because you bought
a call option hold your place in line,
I don't think that means you get to preserve
that place in line, we're not gonna tell
you can't stay in line.
If somebody has procured cost
to move forward in the process.
I would certainly hope we can let them continue in
that process if there's a dispatchable asset
that is co-located or associated with an intermittent asset.
So we value solar but we value solar plus battery more.
We certainly would consider that dispatchable.
And like I said, this is a great step we can take right now
to both show the market that we do truly value dispatchable
and to drive action on the ground
to move these things forward.
-: I have one other thing to say.
And that is there's really two parts to this one of them is
those that are in the interconnection queue today,
under the old rules ought to be able to have some process
to say that they can amend their solar only project
and add batteries to it.
-: Agreed. -: In their
same queue position.
That if they meet that new standard,
then this new standard adding for our batteries,
they get to keep that same position,
you know, everything else being equal.
-: I agree.
Since we do have next week,
could we get some feedback from ERCOT,
possibly on the logistics of that?
Because I agree with you, I mean, you wanna be able
to amend it, and it's in our interest that you amend it.
-: Yeah.
-: Can you work with ERCOT
to work with him to bring a proposal on logistics
and implementation timeline for this change?
-: And let me just say one other thing,
that interconnection queue is only one part of the process
of interconnecting the facility.
Obviously, you have that interconnection piece,
but I mean, you have energy
that's flowing across the ERCOT system.
So you may be creating more congestion,
you know, as we're adding, you know,
so many megawatts of storage, we may be create exacerbating
that congestion problem on different areas of the system.
That I mean, it could create all sorts of problems,
or it could create none, you know,
that's something else
that we should ask ERCOT to think about.
-: We also hoped that the clever investors behind this
wouldn't put a bunch of storage behind congestion.
-: Again, as we said, or as I said earlier,
you know, it was great when you built,
you know, way out there.
And but you didn't know two guys,
were gonna come in front of you.
-: On this one, I will say, and I'll birddog it with ERCOT.
But I can tell they're gonna get fidgety over there.
And rightly so. (crowd laughing)
As I understand it, the inverters
of the batteries do cause a little different
study constraints in those processes.
So I'll get you details on that.
And we'll get something by next week.
-: In addition, Commissioner McAdams,
just to give us all some you know,
just to confirm, because I wanna make sure
that as we move forward with this path,
you know, we've dotted all the ORDs
and cross all our ORTs, and it's all sound.
Can you please also check with our colleagues,
they don't have any concerns?
-: Sure, that will be a pleasure.
-: Thank you for taking the lead on this.
-: Yes sir. -: Great initiative.
We'll look forward to hearing that day naturally.
All right, 2:30.
Next up is Braddell for a debrief on everything
we heard and learned today.
-: Okay.
Looking forward to that, so it's been a long day,
but I think my job is to kind of remind everybody about
the problems that we're focused on today,
that needs to be in the blueprint,
like over the next week and months,
in terms of what are what is kind of the suite
or package of solutions that can address those problems.
So before kind of reviewing the menu of options
that are on the table, I just thought
it would be worth getting back to the problem statement
and making sure that, you know,
the Commissioners have a chance to, you know,
agree on what is the set of problems we're trying to solve.
So I think we have two that Sam articulated
at the beginning of the day,
the Market Monitor are articulated a third,
and I think it's, you know, really helpful
to this whole room and and us,
if we get a, you know, an affirmation or,
you know, confirmation of that's what we're trying to solve.
Problem number one being supply adequacy,
that we have enough resources in the system in the grid,
to meet all system conditions, supply available,
all winter conditions, all summer conditions,
including, you know, extreme winter events
and extreme summer events.
So that's problem number one is supply adequacy.
And also, we actually did hear a case that's actually kind
of a an inarticulate definition of the problem.
And so I think, you know, just clarifying,
is that a problem that needs to be solved?
And how are we gonna define that exactly?
Number two, is operational flexibility and performance,
making sure that the resources
that we have on the system are positioned
and ready to respond at all timeframes
to provide that flexibility
and operational support that the system needs.
Through market incentives,
not through control room reactions,
not through out of market means
but through market incentives
that incentivize strong dispatch, ability and performance.
To meet all system needs, contingency risks
and system uncertainties, ramp known ramping,
expected net load variability as well
as uncertainties around that expectation.
And then having a strong system of incentives
and potentially penalties for folks who perform
and address that problem and penalties
for those who kind of exacerbate the problems.
And then the third one that I think we probably have heard
less from the Commissioners on, it would be helpful
to articulate is that third problem
that Dr. Patton identified, which is related to hedging.
Is part of this trying to find a solution
to extreme financial events?
And looking at that, both from the supplier perspective.
I mean, are we trying to smooth out revenues for you know,
kind of a smoother year to year investment signal?
Or is that actually not what the Commission is trying to do?
So that's one piece, or articulated
from the customer perspective.
Are we trying to find an insurance product
that protects consumers from extreme financial consequences?
So I think, you know, all three of those problems,
actually, if we have direction as to,
that these are the problems on the table
that need to be solved, can then be turned into a numerical,
you know, set of parameters, right?
Exactly what is the level of reliability
that we wanna support in the system,
whether that's a target or a standard
that needs to be enforced?
And then on the financial side, you know,
what is the level of financial consequences that you know,
consumers can be exposed to?
And those can, I think, guide a lot of the parameters
in terms of some of the details of the solutions, as well.
So back to summarizing some of the solutions
that are on the table for problem one,
which again, are very related to problem three,
because they're the solutions are gonna be very related.
So there's also, you know, again, coming back
to some of these solutions, there's a time element to it,
how quickly can these be accomplished?
So the first panel today, we heard
from three different entities,
most of them had more than one component
to their solution to have a complete package.
And you know, some of them had some similarities.
So I'm gonna talk about them thematically as
to the differences and those
that are kind of complementary versus standalone.
So one portion of the solution,
potentially the most urgent is addressing fuel security.
So we're talking about winterization.
And, you know, if not entirely preventing
at least mitigating and limiting the extent
of something like what we saw last winter.
So we're talking about fuel security.
Some of the problems that we see are the challenges
are some of the solutions on the table
are not really market oriented.
They are kind of a cost recovery sort of mechanisms.
If we you know, end up using some of those mechanisms,
we may end up at a place where we're having
some component of competition,
but it's in the end of the day potentially
not gonna be as resource neutral
or market oriented as some of the others,
we may have spillover effects into the rest of the market.
That being said, it is the most urgent problem.
The second category as I would characterize it
is something on the order of a strategic reserve.
So these are the reserves that can be procured
and kept available out of the energy nicely.
service markets are combined those in advance.
And again, in terms of the timing dimension of this,
that can be done, I think
we heard quickly, like within a year.
So with those, we already have a product similar
to that ERS with demand response,
this would be an extension of that sort of a product,
you'd withhold these resources out of the energy
and ancillary service markets.
And that has the spillover effect of boosting energy
and answer service prices.
So the incentives we're getting in the market are stronger.
And presumably, that's gonna add
to the supply investment incentive.
So that approach is attractive,
because it can be in some flavors,
you know, more resource neutral,
it is using the market
to provide most of the investment signals.
And those signals, again, are gonna be driven
through energy and ancillary service markets.
The disadvantages of that being
some operational inefficiencies,
because we have resources being held out of energy
and ancillary service markets.
So on a day to day basis, they're not providing some of
that performance support that we wanna see.
So that's kind of a disadvantage of that approach.
And then another disadvantage,
I would say is that we can size the quantity
that we're procuring in order
to target a specific reliability level,
but we don't have the same level of kind of guarantee,
you know, to achieve that reliability level.
So a bit of a pros and cons that we see there.
And then a final or another solution to achieve
that reliability standard is the LSE reliability obligation.
One of the options, that's the one
that is the most likely to, I won't say guarantee,
but close to guarantee that we hit the reliability standard
if we adopt one.
And that can be tailored to the winter needs.
And so therefore,
if we have certain fuel security requirements
or on site fuel requirements that can be built right into
that reliability obligation.
And so that makes that an
in market mechanism for that problem.
We also talked about some of the disadvantages
of that approach, it will take longer to implement,
than some of the others were talking about,
I think, would be very optimistic to say two years,
it can take, you know, let's say three years
to implement something like that.
That being said, that can be
a long term sustainable solution.
The other challenges with that solvable challenges,
you know, need to adopt and implement
a robust monitoring and mitigation regime.
So anybody who has, you know, market power,
we'd need to make sure that there's
a monitoring mitigation regime that would address you know,
prevent the exercise of that market power.
And then the other piece, again, that needs
to be fleshed out, that hasn't been as yet is to ensure
that it's totally consistent with the retail choice market.
So making sure that all of the positive and you know,
competitive attributes of the retail market in Texas are,
you know, continue to be supported,
enabled under this mechanism.
So again, you know, a few pros and cons of that option.
And then the final option, this forward hedge option
is can, as Dr. Patton said, be
a solution to either just problem three,
which is about hedging, you know, protecting,
you don't either smoothing investment incentives
for the suppliers, and smoothing,
you know, impacts for consumers.
But it can also be combined with physical requirements
on the generators, saying, you know, you actually
can't just be a financial entity and sell this hedge,
you have to be a physical entity, you have
to meet certain physical performance requirements.
In that case, it can also be a solution
that meets, you know, a particular reliability standard.
So that one, I think, has at least, you know,
two variations depending on
which problem you're trying to solve.
So I think, you know, those being kind
of the menu of options on the table,
any one of them probably does need
to be fleshed out further,
and there will be many kind of calls along the way,
but I think, primary pros and cons there.
So, problem number two, I think, you know, what I heard,
I believe, kind of from all fronts is
that there's a common agreement that problem two is one
that needs to be solved, which is operational flexibility.
And I also think what's, you know,
interesting is that we have, you know,
even if there's not 100% agreement on the exact set
of solutions, some very common threads.
And this is a package of reforms,
some of them that are ongoing, and some of them
that will take some time to implement.
So the nearest term things
that can be implemented are changes to the ORDC.
Again, those kind of guiding principles,
in terms of the problem statement may drive us
in a different place in terms
of exactly what reforms get implemented on ORDC.
But at the end of the day, I think
that can also be done quickly,
the implementation timeframe is pretty fast.
The other piece is to the extent that we see operational
and reliability problems today,
immediate solutions to that are gonna end up being
higher quantities of existing ancillary service products.
Or we're gonna end up with out of market actions
to address operational reliability problems.
So, those being the most immediate solutions.
And then the other kind of very soon
to be implemented as fast frequency response.
So kind of an already ongoing not a complete solution,
but contribution to solving some of these problems.
Medium term. -: What was that last one?
-: FFR. -: Okay.
-: So like fast frequency response.
So medium term, some of the solutions
that are available in the medium term are really those
that are kind of already in progress,
talking about ECRs so enhanced ability
to respond in a 10 minute basis to contingencies
and ramp system ramping needs.
And then there are other some other components,
Commissioner Cobos, you really emphasize the importance
of timing out when companies, you know,
different exciting solutions be implemented,
given the upgrades to the EMS in real time optimization.
Now, EMS, right now we heard 2024,
that feels like a long time.
And then I think even after that,
we're gonna see Real-Time Co-optimization.
One of the things that Dr. Patton articulated
is the importance of that Real-Time Co-optimization,
despite the fact that it's quite far out there
is a really essential and important enabling tool set
for the effectiveness of things like ORDC,
for the effectiveness of ECRS, and, you know,
any other balancing products that may be implemented.
And so the timing is a bit of a challenge.
But at the end of the day,
I hope we're going on a pathway where
that enabling tool to achieve that operational response
and effectiveness won't be delayed further
by the, you know, the strain on resources
that, of course, that we're gonna see.
And then as we look to 2025, and beyond, or, you know,
hopefully some of it could be expedited,
we're gonna need a suite of ancillary service products
that make sure that we have that operational flexibility
and performance at all timeframes, you know,
if cycles, you know, within cycles, within 10 minutes,
within 30 minutes within two hours,
because as we see, again, back to the 10 more gigawatts
of solar or other resources that are gonna introduce,
you know, that ramping need, we do need to make sure
that ERCOT has the tools in his toolbox
to send market based signals for the market to pre position
and then react to those system needs.
So once we get out a few more years down the line,
seeing either increasing needs for more ramping capability,
so perhaps that's ECRS, maybe it's more volume of VCRs.
And perhaps it's addition of new products for ramping,
for example, the two hours
or some of the dispatchable reserves
that we heard from TIEC.
And then finally, you know,
are we gonna need other products such as inertia.
And those again, I think, probably do need
to be on the roadmap of reforms and solutions today,
because this is a problem that's gonna come very quickly,
you know, given the timeframe to implementation,
but at the same time, can't really be expected
to be in place, you know, next year or even a year after.
-: All right.
Thank you very nicely.
Summarize, you've been taking notes.
Well done a quick turnaround.
Yep, state your name and who you are
for the record, I'm sorry.
-: Kathleen Spees from the Brattle group.
-: In the the fifth 10 or 15 minutes,
we got left, and we made it do a quick break it
let's say 2:50, and reconvene at three.
I'll just do a quick response
to your clarification on problem statement.
Number one, supply adequacy.
Yes, of course, I'd break it into three components.
Reliability when we need it, it's available.
Two resiliency.
When unusual conditions arise, extreme weather, et cetera.
The assets perform.
And three, quantity, obviously
is the most important part of the supply.
In the context of a reserve margin, somebody mentioned
that we're looking at like
a 28% reserve margin in a year or two.
If you discount wind and solar
to a bad day, that's like six.
So we need to be realistic about what that quantity
and the character of that quantity should be.
Number two, operational ability, flexibility,
You all said, it's what I've, in my simple parlance,
called the Blue Sky problem, you can have
a perfectly lovely day expectations
of intermittent are off weather wind or solar.
There's a thunderstorm in West Texas,
but it's hot and sunny in Dallas
or the wind drops off whatever blue sky day
and we are in suddenly very suddenly
in very scarce conditions.
That is no way for a civilized country to live.
So we need to solve that.
And then finally the, I guess the financial
or the the hedging challenge.
I don't think I do think we need reliability
to be a standard feature of this market.
As I've said before, that is part
of its day to day operation, not a bolt on
or an add on or an afterthought.
And like the things we heard today around that concept
or since we are requiring some sort
of full forward looking hedging.
I think a byproduct of that would be both providing a bid
for investors to see what future revenues are out there.
And also by requiring full hedging,
minimizing volatility in price risk to consumers.
So while that's not a problem we're solving
for I think it's something we should expect
to see as an outcome of the, if we do our job correctly.
I'll stop there.
I just made it. -: You said a lot.
(crowd laughing)
-: (muffled speaking) I know her hands are tired
so we can break now if you want.
All right, we'll take a break now and reconvene at 3pm
for the final hour of discussion.
But the only thing I can guarantee is
I think all four of us will be ready
to walk out here for.
(crowd laughing)
See all of that.
(crowd chattering)
All right, folks, it is not quite yet happy hour,
but I like the spirit.
All right, we're closing out a very long but productive day
with open discussion with our Commissioners
and our participants today,
the especially on specific plans.
I know Commissioner McAdams has
a very particular question to ask first.
That is on timeline.
So I'll turn it over to you.
And we'll go from there.
-: Yeah, Dr. Patton.
I see you moving close to the mic.
Thank you very much.
Katie, would you approach your mic so we can.
(speaking off mic)
Oh, yeah.
Yeah, if y'all wanna start doing that,
I'll go ahead and feel my questions
so we can get Dr. Patton good to go.
I wanted to see conceptually since
we've had 10 whole minutes to reset
and figure out some very important economics,
forward shortage energy hedge
versus backstop reliability service.
Katie, in your mind, what are
the significant difference between years are there?
Or is it just a question of mechanics.
-: So having seen this proposal from Potomac
for the first time a few minutes ago,
I probably need a little more detail myself.
But what I can appreciate at this point is our proposal was
that we would have some level of dispatchable resources
that we're procuring every day for operating reserves,
and I think we've got some flexibility,
they had proposed like a two or four hour product,
I think that could I think we're open
to that as an alternative.
But we were proposing to allocate
that on a capacity short basis.
As I understand Dr. Patton's proposal it
is a broader attempt to allocate more energy
and ancillary services at large in perhaps a similar manner.
The thing that I think is similar about both
that we like, is that it is more
of a real time dynamic allocation instead
of some fixed administrative four word allocation.
-: Anything further down on that (indistinct)?
-: Yeah, in simple terms, and I went back and read,
and I'm still a little foggy on exactly the nature
of the product, but I think, and please correct me,
our forward hedge covers all generation and all load.
So you're buying 70, some 1000 megawatts of it.
And, and almost all the generators are selling it.
I mean, they might put a risk premium.
And they may not all clear if you don't need
as much hedges as there is generation.
But it's covering the entire market, essentially.
And I believe your product is more like a reserve product.
So it might be 4000 megawatts or something.
-: I think you've covered this,
and I might have missed it in terms
of implementation timeline,
given what you know about the ERCOT market.
I mean, this is a system change, it would require.
-: The hedge? -: Yeah, yeah.
I mean, I think they could have
it implemented in just a few months.
(crowd laughing)
I'm just kidding. -: Well, that's great.
-: Okay, no, I'm kidding.
The, the settlement piece of it
is there would be settlement system issues
that would take some time.
In concept, it's not complicated,
because you already know who you're paying the ORDC to.
And so this would run in advance,
it'd be a very simple auction,
and it would establish obligations.
So, in concept, it's not complicated.
Probably the most complicated part of it
is doing the accreditation, like
how much of the hedge should each generator
have the ability to sell?
Which, you know, it takes some time,
and in any time, there'd be a lot
of money associated with this hedge.
So anytime you have that much economic value
that developing the rules is you have to be super careful.
Take time, so my guess is a year or two.
-: So in terms of comparison to the E3 proposal,
it again, the devils in the details on the accreditation,
so to speak, I mean, were you're trying
to establish a standard on that nameplate
or average unless you have to hedge to?
Yeah, I think, and I said this to someone at the break,
I think the accreditation, there's less at stake.
Like if you're a little more optimistic,
like your credit somebody a little bit higher
than what they can perform,
they're gonna end up buying back,
they're gonna end up owing you the ORDC.
So the cost of being a little bit wrong
is not really high in a capacity
market proposal, like the E3 proposal.
You're giving them money
that you're not gonna take back if they don't perform.
I mean, there may be some penalty regime,
but unless, unless the penalty regime is the forward hedge,
you know, you have to be super careful
about how well you accredit the resource
to make sure you're not paying somebody
for something where they're providing
you much less reliability than what you paid them for.
And that's particularly the case for intermittent resources.
-: Okay, does anybody have anything on that
because to ask about ORDC to?
-: If I could just clarify your guests
a little bit on our E3 proposals
that there is a penalty provision in our proposal,
where in fact, they would have to give back whatever revenue
they might have earned through the sale
of the reliability obligations,
add a time plus a penalty on top of that,
plus not being able to sell into the energy market
and all the natural penalties that they would otherwise see.
So there is a penalty provision
that we think would help ensure performance.
And that's an important part of it.
-: Can I say one thing about that penalty,
and why it's different?
So if you remember my bar chart where
the hedge is like a very measured value,
or it's gonna fluctuate,
but the ORDC adder is gonna end up being low
and then be huge when you have shortages.
Just having them give back what you paid them
is not nearly enough,
because the cost of the system during
the very infrequent event where they happen
to not be there could be 40 times higher
than just taking back, you know,
the expected value payment that you paid them.
-: Along those lines on this topic.
Katie, your final slide says the allocation method
of the costs to short entities would be
if applied more broadly, would increase
long term hedging incentives, which seems
to indicate that incentivizing
that would y'all would be supportive
of even any stronger incentives
almost requiring long term hedging, physical hedging sorry.
-: I think incentivizing hedging
is a critical part of the market.
I mean, that's the whole $9,000 price,
in the first instance, was not about setting prices at 9000.
It was about scaring the you know,
what out of everybody so that they hedged.
And so, you know, different ways to do that.
You know, I think this is a really interesting idea.
I think the our capacity, short allocation
for the services meant to get at the same thing.
Where we start getting uncomfortable is something
that's sort of like an administratively determined mandate
with a long lead time but encouraging hedging on
a dynamic real time or day ahead basis.
Yes, we very much support.
-: Is the long term nature of some of these proposals,
or the administrative oversight
of the proposals that are worried them?
-: My experience is those go hand in hand
because the longer term you're trying to set something,
you're kind of having to make it up out of thin air
and set parameters and things like that.
Whereas what Dr. Patton just said as a great example,
you can figure out like the value
of not being hedged based on something
that we already have, the ORDC.
And that's gonna change in real time.
So features like that, that have a dynamic value
that still incentivize demand response
or generator performance based on the actual conditions,
not hypothetical conditions that are, you know,
laid out in advance, that's a better program, in our view.
-: On the penalty side,
or the original bid side (muffled speaking)?
-: So if you think about like our proposal,
and where we're proposing, like additional reserves
to cover off this operational uncertainty,
the value of that is gonna increase
on days where there's more of that.
And so if you allocated that on a short basis,
people who were short on those days would pay
for the service when it's a higher price.
On other days, when there's not as big of a risk,
that service might be close to zero.
And that's what you want.
And that's a lot better,
you know, there's gradations of this.
And, you know, there's gonna be some
forward aspect to all of it.
But the more it's got that sort
of dynamic tracking what's actually happening,
the easier it is for us to manage as loads and respond to
and give you guys extra megawatts manage our costs,
and the more you're gonna get generator
incentives to perform so.
-: Okay, I need to kind of straighten this out in my head
because your proposal, Dr. Patton.
Sounds very similar to the LSE obligation,
except there's, you know, some key differences
that you've noted.
One piece that I just heard
from you was that it'll take maybe two years to implement.
And I'm just trying to capture, you know,
are we actually gonna drive
dispatchable generation investment
with a forward hedging proposal?
Are we just gonna get optimal performance potentially?
-: Yes, to be absolutely clear
that the value in the hedging product is derived from energy
and ancillary service pricing,
and the improvement in the energy
and ancillary service pricing could
be done within a month or two.
And so that's where the economic value is.
The hedge smooths it out.
So that's probably valuable for investors.
But the by far the most important component
of these proposals is the improvement in the energy
and answer service pricing.
And so one of the key differences, that mean,
you asked about the timing,
I would absolutely not procure those three years ahead.
I would procure it in advance of the season, perhaps.
So you're procuring the hedges for each season.
And the reason I went into it three years ahead
is there's no reason to buy it three years ahead.
We monitor and evaluate forward capacity markets.
And if you think how investors are looking at investments,
they're not gonna make an investment decision
three years out based on a one year hedge, right?
They're building a 30 year power plant,
what they are gonna do is they're gonna forecast
what the value of this hedge is gonna be over 30 years.
And they don't get better information by you're procuring
that a hedge three years out
versus in advance of the season.
In fact, they get better information
if you do it seasonally, because the quantity, the supply
and demand and the price of it
it's gonna be far more accurate
if you're not forecasting three years in the future.
-: There's a lot of big investments made
on three year five years, say oil, gas, future strips,
-: Well, and but think of this hedge,
this will be priced seasonally,
and the price will change every season.
Now you can forward contract around
that product and energy and ancillary services.
So the fact that ERCOTs not buying the hedge,
you know, three years out doesn't mean that investors
can't engage in contracting that would lock in
the value of the hedge for three to five years.
-: I don't know any oil or gas investors
who would rather just have a one year future strip rather
than a five year future strip, even though none of them.
I mean, that's the pricing mechanism
in the pro forma, right?
So is there I guess that leads to the question,
is there a way to provide price visibility
because investors they can't see a central point
of transaction or price formation,
like WTI if the entire forward market
is bilateral off the automatic run.
So is there a way to require or incentivize
or those transactions to happen,
I want more forward basis to provide
price formation information
and transactions without incurring
the administrative troubles the non market,
centralized clearing mechanism.
So to try to capture, I guess, selfishly
the best of both worlds?
-: Absolutely.
So if you think of what's happening
in most forward markets is buyers
and sellers are voluntarily engaging in forward transactions
because the buyer presumably is getting
some hedge value the seller is locking in revenues
and it's entirely voluntary.
The one thing that changes in electricity markets
when you talk about Ford procurement
is you're forcing the demand
to buy three years ahead of time, which isn't.
So you're creating a forward procurement
that doesn't look anything like for procurements
and gas or oil or anything else.
But what you could do, let's say it's mandatory
for the load to buy these hedges seasonally.
What you could do is transact voluntary hedge auctions
that ERCOT could administer a year out, two years out,
three years out, and you would get
some portion of the hedges clearing.
I mean, there's no reason as an LSE,
you wouldn't be willing to buy ahead
if you thought the price was attractive,
and the suppliers could sell ahead.
But they would all be bidding and asking prices
that reflect what they imagine they're gonna have
to pay if they wait until the very
last auction where it's mandatory.
-: Sure.
So a quick clarifying question,
I think there's no requirement for oil and gas.
Central hedgers, like WTI and CME,
there is no requirement to utilize those futures.
Those are hedging mechanisms,
not the physical, like spot contract.
-: Correct. -: There's no requirement,
but they also don't have a guarantee of being supplied,
the good they're looking for, like LSE are, right?
And LSEs just sits back and say,
hey, I've got this load that's up
to the control room to serve that load.
-: Yeah. -: That didn't happen
in a refinery, right? -: Yeah.
And that's why the LSE procurement has
to be mandatory at some point.
I'm just arguing that it should be mandatory
in advance of the season.
-: Physical procurement at some point.
-: Yeah, the hedge. -: Okay, I got you.
-: I mean, they're gonna have to be forced to buy it.
Whether you force them to buy it three years ahead
versus in advance of the winter season in the summer season.
-: And can I add something to this just from,
you know, when we're talking about investing,
bringing the Stephenson LCRA.
You know, we talk about
the forward market, like it's liquid.
And it's not. -: It's bilateral or ice?
-: Bilateral and ice, both of them
are very illiquid right now.
Okay, obviously, there's a lot
of regulatory uncertainty that is creating that.
But I mean, we've had these conversations over the last 10
to 15 years, these are the same market signals
we've talked about, these are the same,
you know, the load obligation is a little different.
But I will say that any sophisticated party
should have already done a load obligation deal
to hedge their risk looking out two to three years.
And one counterparty didn't do that,
and got in really big trouble,
like we all know, over the winter store, okay?
And so these theories are very meaningful
when you think there's a liquid market
with people wanting to transact.
But when there is not, this is extremely difficult
for any generation or load side entity to do and perform.
And so, you know, as we talk about certainty
and out of market actions, and what is really a good signal
for new generation to be built.
Obviously, anything that provides certainty,
strong signals, easy to understand, just be very,
these are some very complicated proposals.
And a lot of the hedge funds and investment banks are very,
very smart people that work on these all the time,
but they're not in the details
of my load forecast looks like this.
Therefore, my load obligation is based off this and that.
And so if we're trying to send signals for folks to invest,
I think the way to make sure it is meaningful
and impactful is the rules to be clear.
The rules to be certain and the rules
to have some type of reliability mandate
to get generation on.
-: Nobody's gonna fault you for making fun of hedge funds.
But continue that thought, both bilateral markets
and centralized hedging markets
and ice don't have liquidity.
-: They do not. -: Even the sun last year,
they didn't have adequate liquidity begs the question,
how do we provide liquidity for (indistinct)?
-: And I think regulatory certainty I mean,
I'll be very honest, having the rules very clear,
and very understandable with all the different
financial players is important,
-: Of course, always, but I mean, we've changed ORDC,
in the past, we had regulatory certainty,
I would guess, last this time, you know, October last year.
-: Well, I would argue that ORDC
does not provide regulatory certainty.
ORDC duty is pricing during scarce periods
of time in which you cannot predict.
-: Right, but I mean, we heard a lot about ORDC
today solving all sorts of problems.
-: I disagree with it. -: But I mean, in regulatory,
we've had in the past 10 years,
right periods of regulatory certainty.
I'm new here, but I certainly hope
there's been more regulatory certainty than we have today.
-: Yes. -: Okay.
So is there an open question,
how do we provide more liquidity?
We're not gonna solve that right now.
But I'll leave that up.
-: Yeah, I mean, I do think it's just clear rules,
I mean, a bilateral market that function Wales
has financial and physical players
that are willing buyers and willing sellers, right?
And so to make sure everything is as predictable
and understandable as can be, I think helps.
It doesn't per se me in a capacity market.
And I don't think capacity market does that.
But I do think understanding and implementing rules
that are, you know, easy for folks to understand.
I keep saying this, because we over complicate
things in ERCOT so, so much sometimes
that it makes investment in this market very difficult,
and makes it a difficult market to transact in
and find folks other than literally five
or six counterparties bilaterally, that transact right now.
To me, that's not really a true market
where you can hedge yourselves get the benefits
of building new generation assets.
-: Thank you for your comments.
I mean, I'm kind of sitting here trying to understand
that proposal myself, in terms of, you know,
setting aside economic theory
and thank you for highlighting
the elliquidity of the forward markets.
And we've got to look at all these proposals
and from a robust, holistic perspective in,
I'm just trying to, in my mind trying to figure out,
I know that your proposal is sort
of maybe geared towards addressing the LSE obligation,
maybe with less negative impacts,
but I'm still wondering how this helps
us solve anything going forward.
I just don't have that transparency.
-: Okay. (crowd laughing)
It's gonna be hard for me to answer that question quickly.
And I do have to excuse myself
but what I will say is that the combination
of the ORDC reform, which is necessary,
no matter what else you do, in my mind,
together with the hedge will provide
an extremely strong incentive to be available
and to be flexible, which incense everything
we say we want firming field,
batteries behind wind resources, you know,
dual fuel at gas only units, winterizing units,
all of those things are incented
by compelling participants to settle with ERCOT,
based on the value of energy and ancillary services
when the conditions are tight, and the need to do that
it's gonna get higher and higher and higher,
because we're gonna see more and more
frequent conditions where fluctuations in
or intermittent resources as their penetration increases,
will create ramps shortages and forecast errors
that cause us to be short when
we didn't think we were gonna be short.
Now as we were saying that the ORDC reforms
aren't relying on periods where we're
on the verge of turning the lights out,
but it will greatly increase the revenue
in periods where ERCOT can't hold the quantity
of reserves they would like to hold.
So the probability of losing load instead
of being you know, one half of 1% is 3%.
Now, that sounds like a small deal,
but if you multiply that increased percentage times
that $25,000 value of lost load,
there's a lot of money that we should be paying generators
to make sure they're available or penalizing them
when they're not have billable and they contribute
to getting us into those circumstances.
So to provide very strong incentives
to move in the direction of
that your objectives are indicating that you want to go.
And that hedge, although it's linked back
to the shortage pricing,
because it would provide a smoother revenue profile.
In almost every scenario, it's going to be
a better starting point to finance investment
than having, you know, the extremely volatile revenues
that you get from shortage pricing alone.
-: Can I jump in for a second, though?
Because there are two points that are
because there's a lot of interest in your proposal.
I know you have to go and just a second.
-: A second ago, I had to go.
-: I'll just say there are a couple things
that I'm still puzzled about.
-: Good, I'm glad I'm not the only one.
-: So one is, I agree with you that the fundamental
is the real time signals and they
and what you change what's in the ORDC.
And there's already strong signals there.
And what you're proposing which makes sense
to me makes that stronger.
But to some degree, all else equal,
sure you said the prices would be higher.
But if you also then attract or retain more supply
that can be available and realize those prices,
you've added only maybe 1000 megawatts
in the picture you had before prices re-equilibrate
to about the same that they are today.
So okay, that helps, but it's marginal
about maybe 1000 megawatts more available supply.
Then with a forward hedge.
I don't actually see how that again,
that doesn't seem to change the fundamental.
And there's lots of hedging today.
And so I would be nice to understand
what you're really adding by making that mandatory.
And it also then this is to Katie.
Actually, I was actually surprised
you thought that sounded okay.
And this is not comparable to what you proposed at all.
This is mandating that.
-: Yeah, I missed that part that was in the slides.
-: Okay, but you need to go (indistinct).
-: I do that the short answer is
that this would motivate far more than 1000 megawatts.
So I'm not sure how you get to 1000 megawatts,
but I'd be happy to talk to you offline about that.
I mean, already, without making any changes,
we think seeing 1000s of megawatts of response just
from people for the first time
seeing the ORDC implication play out,
which they hadn't really seen before this.
But you're right, that mandating the hedge in and of itself,
because it has to be purchased, will move in the direction,
like you do have some flexibility on the quantity
of the hedge that you choose to buy.
And the higher you make that quantity,
the more you're gonna force the market
in the direction of having
to sustain a higher capacity margin.
And I'll be happy to talk to you offline, it's okay.
-: Thanks.
-: So the piece that I did not pick up
from the slides was that there would
be some administrative assignment of a lot of this
that wasn't fleshed out to me.
So I was thinking this was more like
a broader way to do a rock allocation.
So that is different.
And just to put a finer point on that, I mean, this is one
of the things we're struggling
with all of these types of proposals
that have some sort of mandatory obligation.
So like, one of the things that's really hard
for my clients is, if you say to one of my members,
who has demand response capability,
how interruptible are you?
How much of your load is interruptible?
And how much of it is firm?
They're gonna ask you, what season is it?
What day of the month is it?
What are, you know, the product that I sell?
What is the demand for that product?
Do I have production quotas with counterparties,
that I have to meet in a week or not?
And that's gonna make their interoperability
and how they participate in the market vary wildly.
And then when you fix those types
of requirements in advance, it's not conducive
to my members being able to manage their costs
and participate effectively.
Now, if you can have like obligations in advance
that then if their situation changes,
they can liquidate that position in real time.
That is easier to deal with.
But some of these things
that are administratively determined,
and you pay costs up front, and then that's what it is.
That much harder for them to manage.
-: So, Katie, thank you for touching
on the demand response impact of some of these proposals.
What I would like you to address is,
what is the economic development impact on some
of your clients with some of these proposals?
-: Well, like I said, I think the ones
that they can understand like how they can manage it
or not manage it that I think that's really helpful.
One of the things that I've gotten a lot of questions about
is we've sort of socialized the NRG proposal is
and I asked this at the workshop the other day
and there is an answer but if I'm a large load,
and I'm looking to site here in Texas,
and there are these forward obligations,
I have to not only bottle like,
what do I think my energy costs would be in the market or,
you know, buying through a rap or whatever?
But also, there's this new obligation
that I've somehow got to figure out how to meet
and quantify, like, what that's gonna cost me
for something like an LSE obligation.
If that's determined three years in advance,
and then somebody is gonna bring a large new load online.
No, LSE is gonna have links sitting there
to accommodate a huge chemical facility,
or a huge, you know, semiconductor manufacturer.
And so then that puts the load
in the position of trying to figure out,
well, how am I gonna get an LSE
that can cover this off for me, right?
And the answer has been, we're gonna create
this wreck trading program kind of thing.
But then, you know, they don't know what that cost,
that's an LSU is gonna have to try
and go out and get that for them.
It's extremely complicated.
And and I think that's what makes it challenging.
And also what level do they have to cover off based on,
are they considered interruptible or not?
-: To what extent do clients typically hedge other feedstock?
And how far in advance I know changed by industry?
And I don't want ask any company specifics,
but like fertilizer, natural gas,
just by example, not your client.
I don't know if you have clients,
but like fertilizer plants, bio water natural gas features?
-: I mean, I do know that they had natural gas,
I can't speak to a lot of the other ones.
-: I don't know about.
I mean, electricity is another feedstock, right?
-: Sure.
And they do hedge.
This is the other thing, I mean,
it kind of depends on their business model.
So the ones that have more predictable interoperability
where you know, they can kind of turn
their process off like that, they tend to hedge less,
because when prices hedge less in terms of contracts
with another Counterparty, because when prices rise,
they have a natural hedge of being able
to turn off, the ones that can't do that.
They hedge a lot more.
And I mean, I like I said, I can't really speak
to how long they hedge differences.
-: Does that concern for your clients diminish
if the forward mandatory physical hedging
is a percentage of three years out and slowly ramps up
to say, a quarter, it's not 100% until a quarter out
or something, some escalating requirement like that.
And wouldn't that be on LSE as part
of the risk book rather than your clients?
-: It is their risk.
But I mean, at some point, they've got
to recover that from somewhere.
And if they're gonna get costs assigned
to them based on our load, they're gonna want
to charge those to our load.
So is it one for one?
No, probably not.
But it does tend to increase the cost that we would be asked
to recover from us to pay from an LSE.
And it's like what I said earlier,
they want the ability to liquidate a position
or trade out of a position closer to real time.
And I think one of the tensions here and I don't know how
to resolve this is that requires some kind
of centralized market at some point.
And the LSE obligation is sort of premised on avoiding that,
kind of trying to get to the result
of a centralized capacity market,
but avoiding that centralized procurement
and the costs associated with it,
trying to somehow then translate that into a product
that you can you liquidate in
a centralized manner in real time.
I don't know how to do that.
I don't know that anybody knows how to do that.
-: So doesn't this take place, look, again,
the whole point of the E3 proposal,
or at least one of the the crux points of it was,
again, those LSE are able to offset
those obligations moving forward, again,
distributed generation DR your guys kind of do that a lot.
I mean, it's one of the central components
of manufacturing in Texas.
And we've set up our entire system around it.
So doesn't that sort of offset the industrial concern here?
I mean, yeah, you're dealing with an LSE
for some of your members.
But again, if they modeled their business correctly,
if they've got their own distributed generation,
and again, it's credited and then they offset just doesn't
that neutralize the impact to a certain degree?
-: I mean, so it goes back to there's a lot of features
of this that haven't been ironed out yet.
Male: I think it's gonna be long process anyway.
-: Yeah, I know, but at a high level, the way I understood
the proposal was that these obligations,
were gonna get set three years out,
you didn't have to come in and show proof
until I think it's a year before.
-: It's a year out. -: A year out.
And you know, the three year forward setting
that's really challenging showing it a year out.
You know, it's less challenging than three years,
but It's not clear to me
that the obligations change a year out.
It's just that they might be traded around.
But I don't think that we, I mean, to your point about DER,
and DG, I mean, that's still going toward
what counts in the static look,
that still doesn't account for how things actually operate
in real time and how that interacts
with what the capacity obligation was in advance.
So if I'm a load, and you say,
how interruptible are you gonna be
and if you're not as interruptible, as this,
you're gonna have to pay a penalty than my, you know,
maybe I'm gonna say,
I'm less interruptible than I actually am.
And then I'm gonna hedge for that.
And then when you get to real time,
what's my incentive to interrupt at that point,
you know, I already paid for whatever,
you see how it can interfere
with the real time performance incentives.
-: And that's what I've been very much wondering about
and invest, you know, in our Genie three about it,
and all the other stakeholders,
as we look to address market design changes.
One very important goal for me anyway,
and I think I can speak for my colleagues
to address operational reliability.
And, you know, as I think somebody mentioned earlier,
maybe it was Dr. Patton, that said, you know,
you could accredit a plant, because you know,
has firm gas or on site storage,
and you give them a higher accreditation,
but then there's gas that doesn't have
those components to it, that could show up
in a real time condition where we actually need them.
But they were disadvantaged in the accreditation process.
Also, you know, real time conditions,
as I noted earlier, you know, the accreditation process,
I think the answer has been well,
you get higher accreditation, if you're weatherize
and you have onsite fuel
and dual fuel capability, et cetera, et cetera.
So that may hopefully address like weather conditions,
presumably, and then, but then there's
the real time actual market conditions when all of a sudden,
we have higher than expected demand.
And renewable generation drops off or thermal generation,
we have a higher than expected level of generation outages.
And then at that point, that's what I'm wondering like,
where we go from there?
Do we just turn to our ancillary service market
or, like, how does it work?
I can focus on that area.
-: If I can jump in there, just real quickly
to describe that goods, the way
that we see it playing out is that, you know,
really, this is just an additional layer,
that's a three year ahead, forward look based
on physical capability, right?
Then it's far enough out that there's still time
to do something about it.
If it looks like you're gonna be short.
It doesn't supplant, you know,
or replace any of the hedging the activities that would need
to happen, it doesn't necessarily replace an ORDC reform
that still provides all of those incentives
to get the plants operational, have them
perform in real time, it doesn't replace
the ancillary service requirements,
that we're talking about the four hour,
you know, flexibility requirement
that helps us address the dark curve and all the wind
and solar ends, do we still have
to have all the operational incentives lined up as well.
This is just an additional layer of insurance that says,
I know that I need at least
this much physical capability on the system.
And you do that look far enough out in time
to where there's still time for a new investment to come on.
And maybe somebody hadn't already been planning.
-: Okay, compare and contrast to some
of those other insurance policy proposals
that are out there, like a Bistra or NextEra,
that seem to be more right sized for certain conditions?
-: Yeah, so good question.
So a couple of differences.
I think some of those proposals
that are more kind of seasonal proposals,
those are meant to take a certain proportion of the capacity
and target that and set that aside to make sure
that at least that amount, and it's a much smaller amount,
a few 1000, megawatts, 8000, whatever it is,
are ready to go and able to provide a reserve service
on let's say, a quarterly or a seasonal basis,
whereas ours is much more like Dr. Patton's proposal.
It's market wide, it's the entire market.
We wanna know how many megawatts
of load we expect to have, under
a whole bunch of different weather conditions,
and how many megawatts of effective capability
with that the entire fleet provides you.
So it's much more of a comprehensive system wide look,
and that gives you some assurance,
then that when you get into
these really difficult conditions
that the system is gonna be able to perform,
but it's just as simple physical look,
I think it's actually less burdensome
on the LLSE than the hedging requirement.
Because that now gets into well,
how much hedging should there be what proportion
of your portfolio should you be hedged
on energy basis on $1 basis,
or different LSE have different hedging strategies,
already, you're getting way into their business
of how hedged they want their portfolio
to be rare as we're just saying.
It's just a physical capability that everyone needs
to do their share to make sure
there's enough resources online so
that the market can clear when people want
to do both hedging and real time transactions.
-: Okay, may have missed this,
but we've covered a lot of ground today,
three years versus the one year.
What does that get us in the system?
I mean, it allows people to build a power plant,
apparently, in three years, you know,
and get themselves right with the system, but what else?
-: Yeah, so that's the main rationale
for the three year hedge forward look is.
-: No, the power plant? -: Enough time that you
can actually remedy the situation
with steel in the ground, if you're looking season ahead,
you really are just limited to hedging,
you know, maybe doing some maintenance deferral,
you really are limited to the resources
that you've already have in the ground,
and making sure that they were available,
you really don't have the remedy of looking out
and developing something new.
So the system I look would be three years out.
But there's but we also recognize
that not everyone knows what their load obligations
will be three years out.
So that's why there's a notice period
that says in two years, there's gonna be a form
of showing by then we'll have a better idea
of what each of these obligations are going to be.
And then here's your what your proportion would be.
And then then come up with the form of showing
that says you're doing your part.
-: I don't think this may or may not be part of the purpose.
But I think about if you think back
to one of these first work sessions, like in June,
when Ice presented the forward curve,
remember what product it was.
And it was backward related.
And so if you're an investor,
and typically you literally put those prices in oil, gas,
soybeans, whatever, you put those prices
at your revenue discounted for any differential, whatever.
But if the market is telling you,
your revenues are going down,
because the only thing they have to look at right now
is the CDR, which claims at 28% reserve margin when we know
that on a bad day, it's really five or six.
-: Right.
-: You've got no reason to invest.
But I think a byproduct of a market wide
essentially saying we need the market
to be reliable, every day, all day.
And we're gonna require people
to put a bid out there in the future.
You're also requiring them to show what they're willing
to pay for a reliable asset three years from now.
In April 2024 or whatever. -: And I agree with it,
and I think your summaries absolutely spot on.
My point is, is that kind of with all the other movements
that have been suggested by you to stakeholders,
and that we had talked about leading up to this point.
And again, that layered strategy on dispatch ability
and paying for it, from where we came from in 2013,
to now is light years, I mean, to what we're talking about,
and we were talking about a lot of stuff.
So MCL movement on ORDC that means more consistent,
you know, reaching high cap,
that means more money into this market.
Now with, you know, any type of firming obligation,
three years out, I mean, that's a lot of liquidity plus,
you're hitting more consistent,
plus the odds of you hitting more high caps
because of increased penetration by solar, you know,
and then curves occurring more often.
That's a lot of money coming into the market.
In my view, I'm just hearing a lot of money
starting to come into this market.
-: And then the other thing is changes
that you all make impact the forward curves
for years in advance, even if they don't dictate what
that price is gonna be years in advance
or set a price years in advance. right?
So I do think, you know, if you do one of these things,
that's gonna procure more dispatchable every day
and assign a value to it.
Even though you're not doing that three years in advance,
the market will be able to rationalize
that three years in advance, as long
as the structure stays, you know.
-: Consistent. -: Consistent, yes.
-: And the only reason I flagged it now is
because one of the topics that keeps coming up
and your group has already identified it
and then that attempt to do address it is the liquidity
of the market three years in advance
those independent retailers trying to buy those blocks
or enter the market, you know, this new entrance
to be so well capitalized where
they can be firm enough or.
-: Working capital.
-: Yeah, working capital three years in advance,
you know, so it's a little bit higher road.
-: Is that good or bad?
-: I don't know, I'm thinking about it.
-: Well, again, just to be clear,
the obligation becomes formal one year in advance.
-: Right. -: The three year in advance
is just the ERCOT wide look
that says we need X amount of total capability.
We haven't divided it up among the LSEs yet
until much closer in time to when they know what
their loan obligations are gonna be.
-: I know I've asked this question a lot
and I'm trying to understand it sounds like
at least setting the framework
of how it'll work would provide
that one year three year
out liquidity investments potentially.
I'm just wondering how long it's gonna take
to get that framework in place.
These are, you know, in Brattle, you know,
Sam and Kathleen.
I really would like to get a little bit more input
from you all.
I know that we took a ride towards this path in 2012.
And I went back and looked at the report you provided us
and some of the subsequent answers
and to before technical conference.
And I'm just gonna sort of give you some blurbs
from your report and from the response.
And one of them, I think I really wanna focus in on
because I just wanna see
if anything has changed from back then.
I know our market has definitely changed.
But the primary disadvantage of imposing
a resource adequacy requirement on LSE is not
that the approach is that the approach is complicated,
incur substantial implementation costs
or requires a number
of new design elements to be introduced.
Then I go to a chart that was filed after this report.
And it says that the risk to investors medium to high.
And then let me actually quote something,
another piece from the report,
because this is kind of what I've been sort
of zooming in on a little bit is with respect
to the retail market.
And what that, you know,
in your report, you talk about how a disadvantage is
that the requirement, the LSE obligation requirement,
cannot be imposed on a four basis due to the stranded costs,
risks that would be imposed on reps in ERCOT,
retail choice environment.
Can you speak to some of these statements
you've made in the past, and let me know
if there's any difference from then to now?
-: Yeah, sure thing.
So I think a lot of the issues
that we flagged then are really the same
that we've been discussing today.
So for example, forward obligation.
Three years forward,
if you impose an obligation such as this on retailers,
it would be very challenging for them
to know how many customers
they're gonna have three years from now, right?
So that was the issue identified.
That's why you move that requirement as close
to the prompt timeframe as possible.
If you don't have a LSE, like an agnostic for procurement.
So if you do for procurement, you don't wanna impose
that on individual entity LSE for showing
I think that's still true today.
In terms of the implementation costs,
I think we need to put that in context
to the other options on the table.
I think the costs of implementing that, you know,
in today's environment, first of all,
they're absolutely negligible compared
to the size of the problem, we're talking about solving.
So they are substantial.
And they come in the form of, you know,
timeline to implement upgrades to,
you know, various systems and so on.
But you don't you're talking about,
you know, 10s of millions or up to 50 million or something
and implementation costs, but compared to the size
of the problem we're solving,
it's more about timeline, I would say.
-: I'd like to add a couple of things.
Well, you go ahead but I wanna respond.
-: Can you respond to this first because its important.
-: Risks investors, medium to high.
What did you mean, if you can remember?
-: Can you remind me what it says
under centralized capacity market for that?
-: Yeah, we need to say it in in context to the other.
-: Right yeah. -: Things it was compared to.
-: Yeah.
-: It was compared to pure energy only
with market base reserve margin,
which is kind of what we had back then without ORDC adders
to energy only with adders
to support target reserve margin would,
which is where we're at now.
And then a centralized capacity market.
-: Yeah, well, I also wanna add
that you missed one of the concerns,
which is market power in a bilateral,
see it's actually the concept
the problem itself that it's solving.
What's the demand our resources accredited,
that's all fairly similar to a centralized capacity market.
It's just that you don't have
a centralized auction, it's bilateral.
And actually the biggest problem is that in that context,
if it were purely bilateral,
you cannot I don't think satisfactorily mitigate
the structural market power that exists in selling a product
to meet peak load plus of reserve margin
or a high measure of peak load,
there's structural market power that has to be addressed.
And it could be and I was actually having a side chat
with like a session talk about that.
But let's just say an idea that, you know,
you might have to require the biggest generators
to have to sell all their capacity,
offering it at cost in an auction,
maybe administered by market, buyers could decide whether
to buy there or in the bilateral market,
you'd have to do something where you're able
to make sure that the largest generators aren't economically
or physically withholding from the market.
Don't be distracted by this is even more fundamental than,
you know, how much they would charge some other retailer.
And don't be distracted by when they say,
no, we're also a retailer, we're a buyer,
that's not really true.
They don't have long term obligations such
that they have a short position in the market,
they are long in the market,
they do well, when prices are high.
The biggest problem here
is market power by large generators.
And that would have to be addressed.
That was our biggest problem with it, then.
And it would be now if you thought
let's just do it bilaterally.
You have to have some way to address that.
As for the risk for investors, look,
this is gonna be a risky business no matter what
I think we'll have to see if
no design was low, except if we talked
about some you know, undesirable re-regulate?
-: Well, you did have low for an interview only
with a backstop procurement out of minimum.
-: He didn't like it (muffled speaking).
-: We actually had lower economic efficiency.
Sorry, all of them are high.
(crowd laughing)
-: So my generator friends are probably angry
what I just said, but I will tell you that the business
that they're in is a tough business.
It's risky.
And, you know, you can't expect them to do things forever
without paying them for it.
So that's, maybe they'll like that I told you that part.
-: Fair enough.
Being mindful of the clock, we got five minutes left,
I wanna offer one closing thought and then obviously,
hear from my fellow Commissioners.
I started the day by talking about optimizing our portfolio
and one of the things about the accreditation
that is not concerning but is a problem I'd love
as we go continue to move forward.
I'd love to hear more about not now
because we're leaving it for the kind of like
what Katie said, like the ability to hedge a portfolio
in real time is a feature of this market.
And if you accredit wind, solar, et cetera,
only a certain percent like yes,
that's being realistic about our resources,
but afford obligation that's married
to those accreditation standards,
and limits the ability to flex in real time between
if the winds blowing gas prices are $6,
I'm deploying my wind resource, the winds not blowing
and coal is cheaper than gas, this heat, right?
I'm deploying my coal.
So I'll just ask everybody involved
to think about how do we capture the feature of yes,
we want the entire market to be reliable every day,
while still also allowing our participants
that real time or near real time
portfolio optimization flexibility,
without requiring ERCOT to administer an ice or CME,
like centrally cleared market stuff.
-: And that's where I'm coming from how do we ensure
a year round reliability and address the operational issues
that we are have been faced with could be faced with again,
in some form or fashion in the future and are being faced
with and what I mean by that is cold weather
and a tremendous amount of variability on our system.
And oftentimes, real time conditions that we're having
to deal with as a result of that, but also you know,
just higher than demand higher than expected demand
in conjunction or separately
from higher than expected generation,
higher than expected lower generation output
and that could be wind, solar and even thermal.
So that's how we classify operational reliability issues we
that I would like to solve for, in addition
to providing a bedrock of as a bedrock as we can provide
of year round reliability for the public and Texans.
-: Kind of the bottom line then, all right we closed.
-: I'll yield my one minute back.
(crowd laughing)
Will make an exception for it.
-: So do I get two?
I guess I just wanna thank all the participants.
I mean, we've gone I put in a lot of work,
have done a lot of effort.
It's a good discussion.
You know, I hope that we come
to the conclusion that creates the right investment
atmosphere, that's what we need.
That's what we want.
And certainty is I think,
the name of the game going forward.
How do we get it we set it and we keep it.
So thanks.
-: All these smart people are not procure to small expense.
-: And I would like to thank the stakeholders for that.
The effort is, as noted, and on behalf
of public we'd like to thank you.
This has been productive.
-: Well put.
Many, many thanks.
And 3:59 at 43 seconds there being no further business.
This meeting of the Public Utility Commission
of Texas hereby adjourned.