(gavel bangs)
-: This meeting of the Public Utility Commission of Texas
will come to order to consider matters
that have been duly posted
with the Secretary of State of Texas for July 1st, 2021.
For the record, my name is Peter Lake.
And with me today are Lori Cobos and Will McAdams.
At this time, we will open up for public comment.
Invited oral testimony related
to a specific agenda item will be heard
when that item is taken up.
This public comment is for general comments related
to today's agenda.
Only speakers will be limited to three minutes each.
Operator, could you please come on in
and provide instructions to the public
on how they can be recognized if they would like to speak?
Operator: Ladies and gentlemen,
if you wish to ask a comment,
please press one then zero, one then zero.
We have one, couple of comments.
We'll have names for you in just a moment here.
One moment.
Drew Gormley, you're open. Please go ahead.
Drew: Good morning Commissioners. Can you hear me?
-: Yes, we can hear you.
Drew: Thank you.
So, I appreciate your time this morning.
This is in regards to Docket 52079 for Energy Monger.
-: We'll, Drew, -: I really wanted to,
-: Why don't we take that up during, on that,
why don't we take that up on that item?
We'll have you -: Okay.
-: Testify on that item when we get there.
Does that work?
Drew: Okay. Sounds good.
Yes. -: Okay.
Thanks.
Operator: One moment.
Jamie Sloss, you're open.
Jamie, you're open on your end.
I don't know if we're muted. -: Okay.
So, basically my question is if Commissioner Peter Lake
and Will McAdams are familiar
with the rights of parties, which is 22.102(b),
the rights to parties.
That's a yes or no. If you're familiar with that.
-: You're welcome to bring any issues
to the Commission's attention you like,
Mr. Sloss, please continue.
Jamie: Yeah, well, that's an issue I brought up
to you guys about three,
this is the third time I'm bringing it up
besides on my closing arguments and on the,
on the oral argument,
and I'm not sure if you're familiar
with the Subchapter section 22.102(b) rights of parties,
because you guys made a ruling.
You guys denied me the rehearing.
And quite frankly, I don't think I need a rehearing because
it's very obvious why AEC does not want me
to cross examine their witness, which is my rights.
So, you guys denied me my right to party.
You guys denied me the rehearing, and you voted,
you took up the proposal for decision by David,
who also took into consideration the affidavit of witnesses
on behalf of AET, but this denied me the right of parties
to cross examine all witnesses.
Now, somebody brought it
to my attention that, yes, -: You have one minute.
Jamie: To present a witness,
but in the rights of parties,
it says that I have a right to cross examine all witnesses.
So, if you're going to sit in that chair
where you're sitting right now
and you don't know what you're in charge of,
then I ask that you step down,
tell Greg that you're not able to carry out the duties
that you are holding
'cause you don't know what you're doing up there.
And I ask you and Will to step down
because you're obviously not familiar
with the rights to parties.
And there's probably a lot more you're not familiar with.
So, Lori didn't get an opportunity
to vote on the rehearing, but you and Will did.
So, I'm asking you to step down
since you don't know what you're doing up there.
-: Thank you for your comments, Mr. Sloss.
(phone ringing)
Operator: There are no other comments at this point.
Please continue.
-: Thank you, Art.
With no other speakers wanting to address the Commission,
public comment is now closed.
This is a work session
where we typically do not take up formal action items,
but due to some accelerated timelines
and deadline restrictions,
we will be required to take up one formal item
for action today.
Mr. Jernay, could you lay that out for us?
Mr. Jernay: Item one is Docket Number 52079.
It's the Commission staff's petition
to revoke the rep certificate of Energy Monger.
Peter: Thank you, sir.
I know we've got invited testimony.
We'll go ahead and hear that at this time,
if that works for you.
Lori: Yes, chairman.
So, I will be recusing myself from this decision
due to my participation in the case at OPUC.
Peter: Noted. Thank you.
Operator, I believe we have a speaker for this item.
Please bring them on.
Operator: If you have a comment, please press one zero.
One moment.
Drew, you're open. Please, go ahead.
Drew: Thank you. Good morning, Commissioners.
I appreciate the time that you're giving me
to really have an open discussion
with you just very quickly about Energy Monger
and you know, the events that occurred to us.
Really, what I wanted to just state a few facts is,
first of all, the settlement that we agreed to
with the Public Utility Commission and ERCOT,
you know, I stand by that.
I did sign it.
I felt that we were really, our backs were against the wall.
We didn't have much leverage. We're out of cash.
We're basically an insolvent company.
Related to the winter storm,
what I really wanted to just state is who we are.
I haven't had the opportunity to discuss
with any of you what we did when we started this.
We're a startup.
We started with about $1.6 million in capital.
And we actually did some things
that probably have never been done in ERCOT.
We built our own systems in really less than a year.
We had our own billing, CRM, transactions.
Everything that we did, we did not use third party vendors.
In fact, ERCOT applauded us
when we went through the ERCOT market flight test,
stating that we were the only retail electric provider ever
to pass the flight test on the first try
with our own EDI, our own software.
And we did it on the first try.
We actually built something
that I think most retail electric providers would envy.
I challenge you to find one other retail electric provider
that did what we did in a short amount of time
to really start in the ERCOT market.
I have more than 13 years of experience,
not just in ERCOT,
but all across the United States
and almost every ISO that's out there.
I opened up Japan and Canada for a retail electric provider.
So, I'm very familiar with this industry,
been in it a pretty long time.
The, really, what I want to point out is what happened
with winter storm Uri,
and really highlight that I feel still confidently
that we did everything right.
We went into February 92% hedged.
We did two short-term hedges in the month of February
to account for usage for the week of winter storm Uri.
And really at the end of the day, it wasn't enough.
That Friday before the winter storm hit,
we attempted to buy more.
Prices had already gone to $4,000 a megawatt hour.
And by the time Monday came around, a $9,000 price,
it had hit the cap.
And we were pretty much stuck.
Our customer usage doubled and tripled
in some cases for our customers,
they were running full-steam.
Every single residential high customer
that we had that was on really killed us.
With respect to our financial losses,
in the span of four and a half days,
the estimated loss was about $10 million
for 4,000 customers.
And I really want you guys to understand the impact
that it had
for a startup who had just started serving customers
in October, had only been in business for four months,
4,000 customers on almost a $10 million loss.
That is unrecoverable.
I had one person tell me a few weeks ago
that I would have been better off investing
in Bitcoin than ERCOT.
And that is a very true statement.
The thing that I really want to point out is what I feel
is what really led to this winter storm Uri event
is what's happened the last 10 years.
Over the last 10 years,
the PUC has allowed a, really, the re-monopolization
of the retail sector.
By my estimates,
$5 billion to $6 billion has been spent by generators
to re-monopolize the market.
You've had, in fact,
I came from one of those companies
that was bought by one of those generators.
When that happens,
you lose the actual true purpose of deregulation.
Under Senate Bill 7, the intent was
to breakup the players in the market,
the market participants,
and when it broke up those companies,
the intent was for them to stay broken up,
generators have capped at 30% of their capacity.
You don't have to produce on any given day their,
what they put on the grid.
There is no cap for them to own retail electric providers
and that's what's happened.
So, for the last 10 years,
instead of generators reinvesting in the market,
putting steel in the ground, natural gas plants,
whatever that may be, nuclear, coal, whatever they felt,
instead that money went to retail electric providers.
I came from a retail electric provider
that dealt with these issues.
And, you know, it was very easy to,
look, let me back up for a second.
What I will tell you is, you know,
there are many reps out there
that have pretty significant losses.
It could take five years, seven years,
or even 10 years to recoup these losses.
What I will tell you is it's very easy
if you are a generator
and you control 40% of the retail electric side
by simply taking your rates up a penny or two pennies,
you can recoup your losses very quickly.
And I tell this is, kind of has been the strategy
for many years is if you've cornered the market
and you have control of the retail,
of the retail sector,
you can easily take your rates up and make back any losses
that you experienced in our winter storm Uri.
So, really what I want to just highlight, and in closing,
what I'll tell you is I'm very well aware
that I'm not the only one in this position.
There are other retail electric providers that are
in this position.
Most are the entities.
And it's a very frustrating situation to be in knowing
that we were a startup,
knowing that we only had 4,000 customers,
knowing that we spent a year trying to build this business
before we even signed up our first customer.
And we were really out the door before we even got started.
I still feel that we did everything right.
We were hedged.
We bought the, we sold fixed price contracts.
We did everything that we should have done
as a retailer electric provider
to make sure that our customers were protected
from any exposure.
To this day, not one customer had any impact related
to winter storm Uri from our customer base.
Every customer's protected on fixed price.
The one entity or person that was not protected
in our case was Energy Monger.
There was nothing we could have done to prevent this.
So in closing, really what I want to say is, you know,
I started with the name Monger for a reason.
It's unique. People remember it.
And it's one of those things that will always be easy
to remember once you see it the first time.
I did a lot of marketing to find out a name
and I came up with the name Monger and what I hope,
if anytime that you guys see
in the future the word Monger is you remember, you know,
our company and really the impact
that these ERCOT prices have on us
and what it did to us.
And really, what I firmly believe is this is truly unjust.
I firmly believe that this could have been fixed
during the event or even after the event.
And really, we were exposed to, in my opinion,
some unjust things done by the Commission
as well as generation.
And the last thing I'll say is this has been experienced
for 2008, 2011, 2014, 2019, and now 2021.
Every single one of those years,
you've had generations fail to deliver on their promise,
of bringing power to the grid.
Every single one of those years,
you'd have prices that have spiked.
And you've had companies experience
significant financial losses because of those price spikes.
I encourage you to look at that
and really inspect those years
and find out what the problems were.
Was it a mothball plant? Was it unforced outages?
But I guarantee you,
what you're going to find is it's going to be tied
to generation and until that's fixed,
I would never bet on ERCOT.
And I don't think in the next two years,
in the next five years, in the next 10 years,
it still isn't built.
If more natural gas plants aren't built,
this problem will not be fixed.
Because you will continue to have this problem.
And I think you're going to continue
to have investors shy away
from the ERCOT market when building,
when putting steel in the ground.
So, I appreciate your time.
Thank you, and look forward to seeing what you guys do
with this docket.
Thank you very much.
-: Thank you, Drew.
I appreciate your comments and insights
and the details of that experience.
We do not have any other invited testimony on this item.
There's a settlement on this docket.
Any thoughts or comments, Will or Lori?
Or Will? You're recused, excuse me.
-: No, I, you know, before we get into the facts on it,
I think his comments are well taken.
I think that he has highlighted one
of the foundational questions
that we have before us
in the near term is how is our market functioning?
And I think that's what these workshops
that you're organizing, Mr. Chairman, are about,
is to highlight how is this working?
Are the right incentives in place to do the right thing?
To invest in the resources
that the public absolutely demands for an essential service.
So, no, I think,
I appreciated that presentation and comments
by the witness.
-: Yeah, that's why we're here today, figure out what works,
and more importantly, what doesn't work,
so we can enhance the competitive nature of our market.
Given the settlement in this case, I will entertain,
is there a motion
to revoke Energy Monger's certificate based
on the parties agreement?
-: So moved.
-: Second. All in favor, say, "Aye."
Aye. -: Aye.
-: The motion passes.
That concludes the formal business portion
of this open meeting.
At this point, we will move to the work session.
As everyone here and watching online can tell,
this is a different layout for the Commission.
This is a very different type of open meeting.
This is one of, this is not our first workshop,
but this is the first workshop directly oriented
around implementation of legislation from the 87th session.
And specifically, some key elements of SB 3.
This is, from this point forward, this,
there will be no formal action taken in this meeting.
This is simply a forum for exchange of information, ideas,
and a forum for discussion
about exactly what Commissioner McAdams just identified,
what's working, what's not working.
How do we make it better?
So, I want to highlight that this is very much a working,
a venue for discussion, ideas exchange.
And this will be the first of many work sessions
on a variety of elements of legislative implementation.
So, by no means should any market participant,
member of the public take anything said up here as,
I think I speak for both of the fellow Commissioners
and nothing said up here should be taken as written in stone
or as some grand intention of future action.
This is purely a venue for discussion.
Is that fair?
-: Yes, sir. -: Yes, sir.
-: All right.
With that, we will move.
I don't have any things on item 2 through 4.
-: No, sir. -: Do either of you all?
-: No.
-: All right.
We will move to item five, discussion and possible,
no possible action,
but discussion on electrical reliability,
electric market development, powered to choose website,
ERCOT oversight, transmission planning, construction,
and cost recovery in areas outside of ERCOT
and electrical liability standards
and organizations arising under federal law.
We have a variety of panels to address the Commission today,
and we'll also be, of course, taking questions.
Our first panel is market design overview.
At this point,
we'll call up ERCOT, Independent Market Monitor,
and representative from the Intercontinental Exchange.
Will: Thank you.
Thank you, Janet.
Peter: We've got a series of presentations
and I know we'll have some questions for each,
I'm sure we'll have multiple questions for each of you
after your respective presentations.
We'll start with our ERCOT's presentation,
then we'll move to the IMM, and then finally ICE.
Before you give your presentation,
will you please state your name for the record?
-: Sure, Dave Maggio.
I'm Director of Market Design Analytics with ERCOT.
Peter: Thank you.
Go ahead. -: All right.
Thank you very much for the time today.
I'm going to walk through a few slides with you all
and really just going
to give a kind of a high-level overview
of the market and in a short period of time,
but I'll focus on two key components a little bit more.
And those two components will be looking a little bit
at our current ancillary services design,
as well as talking about some of the components we have,
including our scarcity pricing mechanisms.
So, if you move to the next slide, again,
this is just to sort of set the stage at a high overview.
So, you can see the ERCOT region here
and the number of stats we have here on the left.
I guess, one of the things
that does stand out is ERCOT is largely separated
from the other grids there at the bottom.
That being the case, we do though have about 1,200 megawatts
or so of ties to the other grids.
Specifically, some of that into SPP,
as well as some in New Mexico.
And it's probably worth noting, not included here,
there is a proposal to add megawatts to those ties
that's currently out there as well.
Although none of that is currently been set
in terms of if and when that might happen.
Going to the next slide,
just talking about the model we have here in Texas,
there's sort of three main pillars to that.
On the far left, you have the supply side of that,
where we have the unbundled wholesale market,
where we have resources competing
within the wholesale market to try and serve load.
We're doing that as a single balancing area
and with the resources we have
that they're settled on a 15 minute level,
and they're settled at a specific location on the system,
and we'll typically call those locational marginal prices,
but there's a specific node on the grid
that's associated with these resources.
And that's the price point at which they're paid.
On the other side of that is the load resources.
And in that case,
they are also settled at that 15 minute level,
within our realtime market,
but they pay prices based on average prices
over sort of a geographical area.
We call it a load zone,
but there's eight load zones that we have within ERCOT
that are these sort of averaged areas.
In the middle there is the transmission
and distribution side.
That is, the transmission
and distribution equipment is really owned
and operated by regulated utilities.
And there's a transmission cost of service
that's allocated to load that that provides some of
that funding for transmission.
And then on the far right is we have the retail side
and the majority of that is competitive
with retailers competing
to serve customers through various products
and things like that they would offer.
But we also as well have the municipally-owned utilities
and electric cooperatives,
that account for about a quarter of the ERCOT market.
On the next slide, talking a little bit about more
of the ERCOT market construct.
So, a key component of the ERCOT market is the fact
that it's an energy only market
and really a key focus for us is scarcity pricing.
So, pricing when things get tight,
particularly for the realtime market.
And that happens through offers from the actual supply side,
as well as a process I'll talk a little bit more about,
looking at, excuse me, the price adders
to try and help us reflect some of that scarcity.
The general goal within the market is for generators
to self commit.
However, to degree we need to fill some gaps in,
there is a process through which we can do
some residual reliability commitments if needed.
But again, the focus is to try
to provide those incentives for the supply
to self-commit and come to the market
without ERCOT necessarily needing to take that action.
We also have a day ahead market
in addition to the realtime market.
That market is voluntary.
And that's where we really procure the ancillary services
that I'll talk about in a little bit more detail.
And we procure that along with energy
and we co-optimize all those things together,
looking at all of the products
that we're trying to solve for in the day ahead.
Within that, we have resources submitting bids and offers
to determine the right level of output.
And we're trying to find,
each five minutes when we're running this market,
trying to find, what is the most economic way to try
and serve the load that we see on the system right now?
And I guess, when I say resources here,
I do mean it fairly broadly.
So, we have our thermal plants are part of that.
We have our renewables,
of course, now, we have energy storage,
as well as starting to see some level
of controllable load resources.
So, actual load that has quite a bit of functionality
to be able to respond
to these sort of five minute instructions.
And along with these outputs that we're providing,
every five minutes, we actually also produce a price.
And that's all those locational prices
that I mentioned earlier.
On the next slide,
this is a graph I think you probably have all seen before.
This is just looking at the installed capacity within ERCOT
and how that's changed over time.
Probably one of the key things you'll notice is the increase
in renewables during this timeframe.
You see that in the top in green with wind,
that's kind of occurred through this whole timeframe
of about 20 years,
as well as seeing some increases in solar.
And then I guess along with that,
you have seen other changes in the system in this timeframe.
I guess probably most pronounced is a decrease
in the capacity from gas, steam,
and actually some degree in increase in the capacity
from combined cycles.
I guess there was also some changes.
Over this time, it stayed, I guess, relatively the same,
but there was a uptick and then a decrease in the capacity
from coal between 2017 and 2018.
And I think where this has really sort of come into play
when we think about the market design
is specifically looking at our reliability needs
and some of our ancillary services
and a lot of the change in fuel mix is tied
into our ancillary services
and how we viewed them and discuss them
over the last few years.
Will: Can we ask questions during these slides?
-: Yes, absolutely. If you'll?
Dave: Yeah, sure.
-: Okay.
So, on that chart gas, as of today, what mix,
what portion of the mix
of the fleet does gas constitute today?
Dave: So, it is the combination, I guess,
of a few different categories up there.
-: Right. -: So they're broken up.
They were broken into the combined cycle,
the gas steam units.
So it's the turquoise color there,
the darker blue, right above that,
as well as the combustion turbines.
And so in total, let's see, that's about 51%,
I would say if I add those three categories together
to look at gas broadly.
Will: Okay.
So, just for the group, PURA, Section 39.9044,
coal for natural gas, subsection A,
"It is the intent of the legislature
"that 50% of the megawatts of generating capacity installed
"in this state after January 1, 2000, use natural gas.
"To the extent permitted by law,
"the Commission shall establish a program
"to encourage utilities to comply with this section
"by using natural gas produced in this state
"as the preferential fuel.
"This section does not apply to generating capacity
"for renewable energy technologies."
Subsection B, "The Commission shall establish
"a natural gas energy credits trading program.
"Any power generation company, municipally owned utility,
"or electric cooperative
"that does not satisfy the requirements
"of this Subsection A by directly owning
"or purchasing capacity using natural gas technologies
"shall purchase sufficient natural gas energy credits
"to satisfy the requirements
"by holding natural gas energy credits in lieu of capacity
"for natural gas energy technologies."
So, you're telling me we are at 51%.
Dave: Yes, so, that's the,
and I guess maybe it's helpful to clarify,
this is the installed capacity.
I know you also, I think,
were talking a little bit about the amount of energy.
I don't have those numbers here handy with me,
but we can certainly provide those as well.
And those could be potentially a little bit different.
Will: Great.
Peter: Was that by company or fleet-wide?
Will: It does not say.
-: It's fleet-wide
of 105,000 megawatts total generating capacity
in the state, rough, is that?
Like nameplate.
We're at 53,000 across all types of gas.
So, point being, we're right at the.
-: We're on the line.
-: On the line of the legislative intent.
Good point, Will.
And while we're speaking about fleet makeup,
when you say, you spoke about how the prices are optimized,
we got prices, just to be clear,
we've got prices at the node level that are then
at the then kind of averaged at the load zone level,
which is what the public would see on the ERCOT website
as like, or the mobile app.
I know the zones are there 20, hundreds, a hundred node,
hundreds of nodes, -: Yes.
-: 20, how many zones?
-: There's really only eight load zones
that we have. -: Eight load zones.
But it's multiple prices across locations
that roll up into successively smaller groupings.
Is that accurate?
-: Yes, sir.
How we do the aggregations and we do provide both on,
sort of all of it available on the, publicly on the website,
-: Yes. -: But the main focus tends
to be those aggregations of prices
into those average values.
-: Okay. So the, I want to make sure people understand.
When you say, you're optimizing these prices,
you're, and every five minutes,
you're optimizing for lowest price for the consumer.
At the same time, you've got
to optimize for that geographic location, right?
A low price in one corner
of the state doesn't mean it can help
in another part, necessarily.
And you're optimizing for that moment in time.
-: That's correct.
And in fact, if you look at the previous slide just here
for a quick moment,
this actually is a demonstration of one of those cases
where we've had some limitations
in terms of transferring power within the state.
And so this is a contour map looking
at how those prices vary within those individual nodes.
In this particular case,
what you can see is we actually had some higher prices
in that far west portion of the state,
where you see the blue color,
that's where prices were lower,
just based on not only trying to find the least cost supply,
but also recognizing some of those limitations
in transferring that power.
Peter: And the transmission constraints
from where the power is generated to where it's consumed.
Dave: That's right. Peter: And you said,
on this one, you say it's generate,
the goal is to have generators self commit.
-: Correct. -: That means,
in layman's terms,
the price has got to be high enough
for them to make money running their generator
at that moment in time.
And at that point, then they'll turn it on.
-: Correct.
Or they at least predict, in the very near future,
that price is going to be sufficient.
-: Gotcha. -: Right.
-: That's the economic incentive.
-: Right.
-: Thanks.
-: All right.
If we can jump then to slide six,
this is just seguing into just giving a quick overview
of ancillary services.
I know that's going to a little bit of a topic today,
but I guess just to provide a little bit of an introduction,
the key thing to keep in mind is that the load
and generation that the supply
and demand are constantly changing.
And really, one of the primary functions of the ISO is
to do that rebalancing.
And there's a variety of things that cause that imbalance.
There's just sort of the daily load patterns of, you know,
in the afternoons ACs are kicking on.
So, people are consuming more energy.
We have sort of instantaneous load variations
of people turning on and off light switches.
We have changes in variable generation output,
and we have things like a generator tripping offline.
So, all those things create these imbalances
between supply and demand
and ancillary services are really procured, again,
primarily in the day ahead market to help reserve that we,
or help ensure that we have sufficient extra capacity
on the system, extra headroom on supply, typically.
Although we do have folks on the demand side as well,
who can help us deal with trying to do this rebalancing,
particularly when it may be to a level
that we can't necessarily just cover it
within the five minute market.
And I guess I'll touch on the three main types of service
and describe them a little bit.
First is regulation service.
This is a really a service that's intended for us to deal
with very small second to second changes.
It's typically a very fast surface.
So, it's something that we deploy in the seconds timeframe.
Responsive reserve service is like regulation
in the sense that it's very fast,
but it's really intended to deal with much bigger imbalances
that we may see.
So for example, that's
that big generator tripping offline causes a very quick,
very significant imbalance,
and that service helps us recover from that.
And then the third service here is non-spin service.
And this is really more of a slow service.
It's technically a 30 minute ramp product that we have,
and really not about solving something exactly right now
within the second.
But I see something coming up in the next 30 minutes,
using the service to help get prepared for that.
So I see, for example,
not right now, but in 30 minutes,
I'm expecting to run out of some capacity
that I'm trying to maintain.
Peter: So it in, or finish up on this slide and I'll.
Dave: Yeah, so, the only thing I was gonna add
to that is the sort of design of these services
and probably more frequently, the quantity
of these services is just sort of an ongoing conversation
that we have with the market participants.
In fact, looking at sort of the methodology
that we use to determine the amounts is something
that's reviewed at least annually,
but can get updated more frequently than that.
Peter: So, to help me translate into layman's terms,
I'm going to say layman's terms a lot today,
I apologize in advance. -: That's all right.
Peter: The, so regulation service,
that's something you can turn on in four seconds.
-: Right. -: That version,
the top version in the blue,
that's as ACs turn on, or the sun sets,
or just a quick imbalance in between general,
electricity produced and consumed.
Responsive reserve service is, was it a few minutes?
-: It's actually also in the order of seconds.
-: It's order of seconds, so that's bigger chunks,
like a big industrial consumer turns on
or transmission lines go down
or some major disruption in the balance
between electricity generating consumers.
Is that? -: Right.
A much larger disturbance of some type has now put,
it'd create a large imbalance in that supply and demand.
-: Like if a nuke tripped, and that
400 megawatts goes off, -: Right.
-: (snaps fingers) They engage that.
-: That's exactly right.
-: So, it's still four seconds but bigger chunks.
-: And yeah, in fact, and to some degree,
it actually doesn't even wait for an ERCOT signal.
It actually senses that imbalance
that we refer to as frequency,
it will recognize that decrease in frequency now
that we, you know, demand is outstripping supply
by that significant amount.
And it will automatically kick in to help recover.
-: But businesses that own
these generating assets have been paid in advance
to make sure they're up and running?
-: Correct.
So, for all the services here,
these are procured advanced in the day ahead market
for folks to be online and available.
In the case of non-spin,
folks are able to do that from an offline status.
They just have to be able to start within 30 minutes,
but in all cases to be on the ready
to provide these services as needed.
-: So, could you give us just a quick overview on how that,
I don't want it to sound crazy,
but how that cash changes hands.
like that's an independent business
in the ERCOT marketplace, the day before,
I know some of the ancillary services are looked at
well in advance and anticipated,
there's an anticipated amount of how much will we need
on a certain day at a certain time.
How does, how do the gears turn
on one, a business being identified
as needing to provide responsive reserve
or non-spin the day ahead?
And how do those gears turn and the transaction take place?
-: Yeah, sure.
So, typically, in our current design,
we actually tell,
we actually we post every December how much we think
we're going to need for every hour of the day
for the entire next year.
So, that information is out there.
It's technically a minimum amount,
so, we can increase it
if we see the reliability needs change,
but that's when we make people aware of the amount
that we expect to need.
And in terms of how those are paid for,
I think that's kind of helpful place
to start is those costs are going
to be allocated to load based
on how much they're consuming relative to everyone else.
And so, folks have to kind of gauge, on the load side,
an expectation of how much they're going to consume
to get a feel for what their portion
of the total ancillary service costs are going to be.
Now, when we get to the realtime, I'm sorry,
into the day ahead market where they're actually procured,
ERCOT, sort of the optimization,
is sort of clearing it on behalf of load.
So for example,
we will tell within the day ahead market
that we need 200 megawatts of that regulation service.
And we have a variety of folks within the marketplace
and again, it includes generation,
in some cases, load for some of these services as well
that can bid in to supply them within our day ahead market.
And we will simply clear,
again to try and find the most cost-effective way
to get those services,
recognizing that we're also solving for energy
and other things as well within the day ahead.
So again, what does- -: And ERCOT,
says 200, we're going to need 200 megawatts
of the combination of non-spin,
responsive, reserved, et cetera for tomorrow.
ERCOT cuts the deal, for lack of a better term.
And then those costs to the lowest bidder
or to the most optimal allocation
of those 200 megawatts price, geography, time.
And then at a later point,
those costs are allocated to load based on the share.
-: Correct.
So, yeah, we will pay as part
of just our day ahead market settlement,
all the folks who were actually awarded,
based on the actual clearing of the day ahead.
And then they have now a really, this is,
the damage is in financial in many ways
as it relates to ancillary services,
it's much more physical.
So, there really is an expectation now
that you have this responsibility
and then you have your plants on the ready
to provide these services.
Peter: All right. I appreciate it.
Dave: All right, if we go to the next slide,
I mentioned that we have talked
about these services over time with the stakeholders,
and there actually are a couple of changes
that are already underway.
I just wanted to make you all aware of them.
These were actually done as part of a change to the rules.
It was Nodal Protocol Revision Request 863.
That was discussed for quite some time
in the stakeholder process a couple of years ago.
And there were two main concepts that were included
in that change to the rules.
First was the creation
of something we call fast frequency response.
This is a subset of our existing responsive reserve service.
And really what makes this unique is that it's fast,
even faster potentially than what we typically see
with our response reserve product.
But we only expect a sustained response
for up to 15 minutes.
So, all of our other services,
we expect you to be able to sustain it for a full hour.
That is unique here, where this service is very fast,
but we only have more of a time limitation
on how long we can expect it.
And then the third piece is actually the creation
of an entirely new service.
We call it a ERCOT Contingency Reserve Service,
and this is much more like non-spin.
It's not necessarily about the exact second now,
but a 10 minute ramp product to help us kind of get ahead
of things that we're predicting here
in the very near future.
Will: So, this is going to be outside
of the three tier ancillary service?
Dave: Correct.
This actually would be a fourth item on that list
that is not included today.
-: Okay. -: So Dave,
and for, you know, just background purposes,
I think what you were referring
to earlier is ERCOT's evaluation
of future ancillary services
that ERCOT underwent a few years ago
to try to identify what additional new services were needed
to address the resource mix that's on the grid.
So, more wind, maybe,
at the time, I think just more wind.
I think the proliferation
of solar has just recently taken place,
but that's how those two new products came about
out of a suite of products
that were looked at at the time,
through that feature ancillary services evaluation.
And so these products are,
were born out of that evaluation
and then I think, for purposes of the public
and my peers here, FFR,
can you describe like what kinds of resources would be able
to provide those new products?
Dave: Right, so, I think one of the key areas
that we see is energy storage resources looking
to participate in that.
Again, they are able to respond very quickly,
but can have more duration limitations
that are kind of unique to that type of technology
that may not exist for other technologies.
So, that was one of the things
that certainly helped open the door I think
for participation from energy storage,
specifically in the ancillary services market.
Although it is not specifically only allowed
for that type of technology,
it is open for others who are able to qualify.
Will: How far in advance, well,
so, the details are still being worked out on ECRS,
or have you launched?
I mean, is this?
-: So, yeah, actually ECRS has not been put in place yet.
That was actually part of our passport program.
And so, I was- -: Okay.
-: Exactly when it's going
to be delivered is still a little bit under discussion.
-: In terms of the parameters of the discussion,
when is the bid schedule on ECRS?
What do you envision there?
Because again, this is a charge discharge type issue.
So, what's the topics under discussion
or the range of options under discussion?
-: So, I'm sorry. The rules have been placed.
We just have necessarily put it into production,
actually made the software changes.
Similar to the other services,
it'd be something that we would clear
as part of our day ahead market.
-: Okay.
-: And so, what would be an example of ECRS?
Is that storage as well?
Are there are other examples for that product?
-: Well, I guess maybe the easiest example is
that there are units out there
that actually can start in 10 minutes,
but right now there's not a separate,
but it can be offline and start up within 10 minutes,
but there's not a specific product for them.
So, they would participate, for example, in our non-spin,
which is a 30 minute product
and they actually could respond quicker if we needed them.
-: Would that be like Quick Starts?
-: Yeah. The Quick Start resources, exactly.
So, those combustion turbines.
-: Economically, would it allow for more discretion
of pricing per, by response, right?
-: Right, -: Precise pricing.
-: Yeah, I recognize I think the even improved attribute
of being able to ramp even more quickly
than what we see with the 30 minutes.
-: You get different economic reward for ramp speed.
-: Right, for that flexibility in ramp.
-: And that's really important, I think,
because as we have more storage enter the market,
you now have a new product in the ancillary service market
at ERCOT to allow them participate in the market
for variety of reasons, as Dave explained,
but also ECRS would allow the Quick Starts,
which would provide a little bit more megawatts for-
-: The peaking, peakers. Yeah.
-: Yeah, the peakers
to help with load variability and reliability.
So, thank you.
-: Yeah, and of course, they are able to participate now,
but this just adds a new service
to recognize their unique attribute there.
I just, in terms of the timing,
we actually did implement an initial phase
of the fast frequency response back in 20,
I'm sorry, in early 2020.
And we are improving on that original implementation,
not necessarily changing the functionality too much,
but trying to improve the capabilities there,
currently scheduled for about the end of this year.
And at least that's where we have it right now.
And as I mentioned,
ECRS is still a little bit under discussion
in terms of when that will actually be implemented.
On the next slide,
I wanted just to talk to you all a little bit
about the operating reserve demand curve,
probably something that you've heard of quite a bit about,
or already discussed,
but just to provide a little bit of history here.
This was really a concept that originally came out
of a filing by GDF SUEZ of a paper by Dr. Bill Hogan,
all the way back in November, 2012.
And it was actually part of a Commission project 40000.
And sort of after the filing of this paper,
there was a number of meetings and discussions
in the stakeholder and at the Commission,
all thinking about that project
and really out of that paper
and discussions is the ORDC concept
that we have in effect today.
It was originally implemented back in June of 2014.
There have been some changes, but,
and I'll talk a little bit that on the next slide,
but broadly the concept has stayed the same
since that time in 2014.
Now, the overall purpose of the ORDC is
to really determine the value of online reserves.
So, the reserves that are available to us right now,
as well as the offline reserves,
so things that are available,
but may take some time and trying to do that valuation
and in realtime and factors in sort of two key points
of what is the current level of reserves
and to what degree are those reserves helping us
prevent getting into an emergency condition.
And I'll talk a little bit more on the next slide
with the shape of the ORDC,
you can kind of see how that ends up looking
in terms of pricing outcomes.
Moving to the next slide,
I have a few different ORDCs here.
I'll kind of come back to the changes over time,
but these are all,
all three kind of give you a feel of the shape here.
On the X axis,
we have the available reserves and on the Y axis,
we have the value of those reserves.
And as you can see, if you go to the far right,
when we have an abundant amount of reserves,
we're further away from emergency,
we're less scarce on them.
You see lower values and lower prices for them.
However, as the thing, as the reserves become more scarce,
as we get closer to potential emergency conditions,
we're looking to strengthen that incentive
that we have in the market,
and you can see the price increase fairly dramatically
and fairly quickly up to the current defined level
of 2,000 megawatts, at which case we put it
at the maximum value for the realtime prices.
Peter: So on the Y axis, that value of loss load is what?
Dave: The value of lost load is typically
that $9,000 per megawatt hour
or $9,000 per megawatt hour of value,
it is currently with the L-CAP in effect
at that $2,000 value. -: $2,000. Got you.
So in practice,
the X axis we see here are the available reserves.
So, as that gets from,
we've got 60,000 megawatt, just hypothetically,
60,000 megawatts of demand for electricity.
And as the available supply goes from 70,000 to 69,000,
to 68,000, to 67,000 to 66,000, I guess this,
for lack of a better term,
the bonus payment to be generating electricity.
So, this only goes into play starting
when you're down at 4,500-ish of extra reserves?
Dave: Yeah, I mean, there are some very minor prices
that kind of go out to those very high reserve levels,
but they're very, they're a very small component
and to get down to,
I forget exactly where they get down to even just the penny,
but yes. -: Okay.
So to get something meaningful, is the,
is that a log scale on the Y axis or is that linear?
Dave: It's more of a, it's a logarithmic scale.
-: Okay (laughs). -: Up until, of course,
where you actually have the sort of shelf there
at the very far left. -: Right. Okay.
So, that's, the Y axis is a example,
not a one-to-one dollar by dollar, but so, I guess the,
I think a key point of this is
that the bonus payment doesn't kick in
until, meaningful way, until you've got say,
35, 3,000 megawatts?
I don't, you can tell me, I mean.
Dave: I mean, I think even now,
probably in the range of 4,000 or above,
you do start to see,
relative to what we would typically see
in terms of the wholesale market prices,
you start to see some significant values.
Certainly, those really extreme type of ones
in the thousands of dollars occur really not
until you get down to that 4,000 or less.
Peter: When, so from,
so, to get the big bonuses you got to be, you have,
you've got to have less than 4,000 megawatts of extra supply
of electricity over your demand.
At what point of available reserves do we start moving
into advisories in emergency conditions?
Dave: Yeah, and so there's a little bit of distinction.
This, I will say on the reserves here,
it kind of looks more generally at available capacity.
When we look at emergency,
it's based on a slightly different measure,
we call it physical responsive capability.
That's not only just capacity,
but that it's frequency responsive.
But within that,
usually it's around 3,000 megawatts of that PRC,
that physical responsive capacity value
that we start doing things like the advisories and all that.
And it's down closer to, well,
2,300 is when we actually start getting
into those energy emergency alert type of conditions,
or at least the initial levels of it.
Peter: Okay.
So, you got to get pretty close to the emergencies
for the bonus payments to really kick in
in a substantial way.
Dave: Right, and it's, you know,
and it's really then as we are
between effectively levels one and two,
that emergency energy alert
that we actually see those prices go to that maximum value.
So, we're already in the emergency
when prices go to that maximum value.
Peter: To get to the value of loss load.
Dave: To get to that value of loss load, yeah.
Peter: Okay.
And at that point you're, for between the emergency,
the first emergency condition
and the second emergency condition is when
that really the prices get to that point.
Dave: That's where that final step you see
where it does finally kick into that value
of loss load, right. -: Typically. Okay.
And then at that point, if you're,
once you get to,
how far, I guess, at that point,
when you get to the second emergency condition,
there's only three, how far are you away from load shed?
-: So the, -: In terms of reserve.
Dave: Right, so the, I'll kind of equate,
in this case, by the way,
as you get close into emergency, the number fairly converge.
So, I can kind of use directly the reserves here
and that PRC value I was talking about.
So, the value at which we would typically have
to start considering firm load shed,
there's not an exact number,
but it's between about 1,000 and I would say,
1,200 megawatts of that PRC value
that would be then when we would have
to take that final step that we have.
Peter: Okay, so if you're,
those prices get up there
when you're about 1,000 megawatts away from?
Dave: Right, when they're still, yeah.
Peter: Firm load shed, okay.
Thank you. -: That's correct.
-: So, Dave, just for purposes of, you know,
putting a little bit more background on this,
these years that you've noted 2018, 2019, 2020,
those are just, would those be, I guess,
actions that were taken by the PUC
to sort of make the slope steeper?
-: Yeah. -: Add more revenue
to the market to incent more generation build out?
Dave: Yeah, that's exactly right.
There was an action by the Commission
in early 2019 to, one, to strengthen the ORDC
and the incentives that we have in the realtime market.
And so, what we're comparing here is what the curve looked
like between, during summer peak hours,
looking at 2018 versus 2019 and 2020.
And when the Commission took those actions in 2019,
they actually asked for that strengthening
to occur in two phases.
And that's why you see a difference between 2019 and 2020.
So, the 2018 value you can see, obviously,
has the same sort of shape,
but for the same level of reserves
and all things being equal, has the lowest prices.
There was a effectively a shift to the right for 2019
and then an additional shift to the right for 2020.
Lori: Right. I'm now recollecting all that.
So can, so the value of loss load,
you've described what that is.
Can you describe the other components of the ORDC?
I know there's like a standard deviation,
and other components
just for additional background purposes.
Dave: Yeah, so, what really drives the shape,
and I talked about sort of the,
one of the drivers being how well it's keeping us
from getting into an emergency condition is we actually look
at the equivalent of a probability of going into emergency.
So, we actually will look back
and then what drives the shape is historical analysis,
looking at things like, effectively,
the amount of reserves we expected from one hour
and how many we actually got an hour later.
So, there's a number of things that factor into it.
That could be a unit trip.
That could be the load was more than expected.
That could be that renewables were not forecasted correctly.
Any of those things lead to in different ways
that forecast of reserves not being accurate.
And so, what really drives this is looking back at,
I think the full history we have of the nodal market
and saying, what was the reserves we expected?
As we were, you know,
an hour or so before the actual realtime market
and what were the actual reserves we got?
And that probability
and that air distribution is what drives the shape here
on the screen.
Peter: Keep rolling.
Dave: All right. Thank you.
And I guess just one last, I guess, topic,
I guess, following the implementation of the ORDC,
there was still some concerns related to scarcity pricing.
And the particular concern was that,
as we get close to emergency conditions,
there are actions that ERCOT will start to take
as sort of defined within the rules
to try to mitigate or prevent getting
into those emergency conditions.
And the problem that folks saw is that these,
some of these out of market actions that we're taking
for reliability purposes have the effect
of suppressing prices in the wholesale market,
sort of at the exact wrong time, right?
We're trying to incentivize all the people in the market
to be responding.
And at the same time,
if we're taking some of these actions,
it's actually decreasing the price that we see out there
in the wholesale market.
Peter: And when you say taking actions,
what do you mean by that?
Dave: And actually, I got a kind of a list
of all the things we include on the next slide,
but it includes things, for example,
of even ERCOT ordering one
of those generators would be online that wasn't planning to.
So, that wasn't an economic decision.
That was a reliability decision by ERCOT to say,
resource X, I want you to be online
and operating during this period of time.
Will: And that's RUC-ing?
Drew: Yes, that's a reliable unit commitment, or RUC.
Will: Okay.
Dave: To mitigate some of these impacts,
we did an initial implementation of what we call
the reliability deployment price adder process
in really just a year after ORDC in June, 2015.
And the idea with this process is
that we effectively run the market a second time,
where we've now changed some of the inputs
to try to offset these out of market reliability actions
that ERCOT has taken.
And it's that, essentially we run the market,
use that for dispatch purposes and then determine prices
through this second run to try to counteract
or offset the pricing effect of those actions.
And I have a graph here in a couple of slides
that will sort of illustrate what that looks like
from just a day, a couple of weeks ago.
On the next slide,
this is actually is the kind of the full list
of actions sort of described broadly
that we currently account for in this process.
One of them that we just talked
about is reliable unit commitment.
We have the deployment
of load resources and emergency response service.
There are certain actions that
if we start taking emergency action at the DC ties,
that will account for it,
as well as something called a block load transfers.
And actually the newest addition, of course,
that we've been discussing with you all a little bit in some
of the open meetings is the inclusion of firm load shed.
So, that rule change was actually approved by the board
earlier this week, and it has actually became effective
at midnight this morning.
So that, that's currently in effect now as well.
There are a couple of other items there
that I mentioned that had been approved,
but are pending software implementation.
So, the rules have been written,
but they're not necessarily effective at this point in time.
And then on the last slide I have for you all,
this is just a demonstration
of what the deployment price adder process looks like.
This is prices, system-wide prices,
over the course of the day
from just a couple of weeks ago on June 18th.
And there's sort of three lines
representing different prices here.
The blue line, that's almost a little,
a little hard to see is the original price
that came out of our dispatch run.
Now, on this particular day,
ERCOT had taken action and we had done some
of those reliability unit commitments
and asked for some generators
to be online during the afternoon
from about a 1:00 to 5:00 PM.
And when that happened,
that triggered this execution of this separate process
to determine the price impacts
now that we've taken that out of market action
and the delta, that that impact is what's reflected there
in that bottom line in gray.
Now in general, on this day,
the impact was relatively small.
I think prices in general were fairly mild
in the wholesale market,
but we did see a maximum impact
of about $20 per megawatt hour.
And it's that gray line that's added to the blue
that determines that final price here on the graph.
That's in green.
And again, for most of the day,
they're fairly similar, but you do see some delta there,
right in that afternoon time where we did take that out
of market action with the unit commitment.
-: So that's, this is a mechanism
to compensate for when ERCOT is concerned about reliability.
It adds supply which offs,
which cause, if there's, you know, supply and demand,
if you add more supply, the price goes down,
which caused a ripple effect.
Well, if the price goes down,
fewer people are going to be incentivized
to add more supply.
And so, this is designed to offset that.
-: Yeah, that's right.
And I guess I'll say,
the actions are not only adding supply.
I think the unit,
the reliability unit commitments are the most common
that we utilize.
It could be actually reductions in demand
that ERCOT has asked for too.
So it actually, -: Sure.
-: But the same logic applies.
-: Where do those ancillary services fit into,
in the sequence of a normal functioning market
to calling ancillary services, to RUC-ing a unit?
-: So, in the case of ancillary services,
those are typically actually deployed through the market.
So they're not accounted for within this particular process.
This is really more either, you know, again,
that commitment by ERCOT
from a unit that didn't want it economically run
or it's folks who, you know,
for example, firm Lochet is an example where, of course,
those folks are not directly participating
in the wholesale market.
And yet, we've asked for that action.
So, those are the types of things
that we account for in this process.
-: In market versus out of market.
-: That's right.
-: Gotcha.
All right. Thank you, Dave.
-: Yep, and that's the last slide I had for you.
Thank you for the time.
-: I appreciate you fielding all those questions.
Next up?
Carrie: Yes.
-: Okay.
-: Go ahead. Fire away, Carrie.
Carrie: Can you hear me?
I can't tell if my microphone's on.
-: Yes.
Carrie: Okay.
Carrie Bivens, with the Independent Market Monitor
and Dave covered a lot of topics.
So, I think I'm just going to kind of dip in and out of some
of the things that he talked about
and expand upon it a little bit
and then happy to take the questions
that might arise from that.
I just want to start by talking a little bit
about electricity markets in general.
They're quite unique to other types of commodity markets
in that there's a vertical demand curve.
Meaning, broadly speaking,
the amount of energy that you use does not change minute
to minute based on what the price is.
Everybody has kind of a fixed demand.
And then you have to procure generation to meet that demand.
Of course, there's some demand response, you know,
around there, but broadly speaking,
it's a vertical demand curve, which is unique.
And also, you know, electricity cannot be stored, barring,
you know, energy storage technologies
that are coming on the market.
But for the most part,
you have to generate exactly what you need
at exactly the moment that you need it.
So, these things combine to create the LMP markets
that we have today and in ERCOT,
we start with a system price we'll call system Lambda,
and you'll see that a lot.
And that is simply the constraint,
the cost of the constraint for meeting supply,
meeting the demand with the available supply.
So, that's kind of just your base energy price.
That's what the generator costs
or the marginal cost of the marginal unit,
short run marginal cost will set that system Lambda price.
And so, that's your baseline energy price.
On top of that, you're adding this ORDC adder,
if there is one, and on top of that,
the reliability deployment price adder, if you need,
if there is one.
And so those three components will combine
to create the total system price at the time.
Now, not only people,
generators that are generating get that price,
they get those adders.
Also, if you're online, but maybe you're at your bottom,
and you have plenty of room to move up,
you actually get paid for what we'll call that headroom.
You'll get paid the ORDC and the RDPA for that for,
essentially, being reserve on the system.
And so, those two components come
into play in different ways.
They're paying generators that are generating,
they're also paying generators
that are kind of online and available.
Okay?
And when we go to realtime co-optimization,
the ORDC component of this will go away
because it's kind of replicating
what a ancillary service co-optimization would do.
So, that's something that's kind of an artifact
of our current market design.
That will change in the future.
-: So, Carrie, not to throw you off track,
when RTC happens, Carrie: Yes.
-: How do ancillary services work under that construct?
-: Yes.
So, in realtime co-optimization, there will be,
it's similar to like the day ahead market is now.
You'll have demand curves that are created
for each ancillary service.
So right now, where we say, you know,
we want to procure this number and it's just a fixed number.
There'll actually be curves that are created,
that'll reflect the value of each service.
So, you know, regulation is the most valuable service.
You have to have that load following every four seconds.
The next most valuable is your responsive reserve service,
which is that frequency response
when you have a unit trip,
and also the 10 minutes spinning reserves,
and then you have non-spin,
which is your least valuable service
because it's that 30 minute service.
And so, these demand curves will have different shapes.
And then you'll have ancillary service offers
from generators
and you'll have the energy offers from generators.
And so, the realtime cost optimization is going
to take the optimal value of energy
and ancillary services every five minutes.
And so, it's going to re, so right now,
you're procuring in the day ahead market.
And you know, if you get awarded 100 megawatts of RS,
you're providing 100 megawatts of RS in realtime.
In this, you could be, it's a whole new market.
So, every five minutes, it'll be telling you,
are you providing RS?
Yes or no? How many megawatts?
Yes or no, you know, 50, 10.
It's constantly rebalancing to reflect the fact
that units are coming offline and online,
costs may change between the day ahead and the realtime,
and to get that most,
the lowest cost ancillary services for the entire market.
-: So, is it fair to swap? It's a mechanism of swapping?
-: Yeah. Yeah.
It's a trade-off, right?
And so, I'll talk a little bit about opportunity costs,
but a lot of the,
ancillary services are primarily priced based
on your opportunity costs.
So, that's the cost that you have,
if you're not providing energy, you have to save it,
then you're losing out on the opportunity
to get the energy price.
So your ancillaries,
you should be indifferent to whether
or not you're providing an ancillary service
or an energy megawatt
because ERCOT needs the reserves
-: Currently. -: And ERCOT needs the energy.
And you, you know,
you shouldn't prefer one or the other.
Peter: Under the current framework?
-: I'm talking about RTC,
but also in day ahead market today.
In day ahead market today, you're indifferent to,
it co-optimizes, in the realtime market right now,
it does not co-optimize.
It's a straight energy market. -: Right.
-: And you just have this fixed requirement
to provide the AS that you were awarded the day before.
-: And so, the reliability deployment price adder
in today's current market is intended
to reflect the opportunity costs.
Is that right?
The headroom that holding, -: The ORDC adder.
-: Yeah, okay.
-: The ORDC adder is intended to reflect that probability
that we're going to go into emergency conditions.
-: For ancillary service. -: It's the value of reserves.
And so, as the conditions get tighter, it's,
the reserves are more valuable and the adder goes up.
-: Right, but the,
for ancillary services. -: For ancillary,
-: Is the other adder, right?
-: In real TC, in realtime co-optimization,
they, AS will have its own prices
and ORDC goes away completely.
-: Right.
I guess, I was trying to sort of just kind of parse out,
in today's current market, -: Okay.
-: You know, you get paid the LMP price,
and then the ORDC adder,
during times of scarcity, as you described,
and then the reliability deployment price adder,
if you're providing ancillary service or RUC
or someone other out of market action, right?
So, in realtime co-optimization,
all that will be baked into one price, all in price.
-: Theoretically.
And so, I guess my point that I was trying to make is that,
kind of feeding off your opportunity cost description was
that that RDTPA's intended to reflect.
-: Oh, the RDPA? -: Yes.
-: The, actually, the RDPA is going
to remain in realtime co-optimization.
-: Okay. -: 'Cause we're still going
to have our market actions.
You're still going to have reliability unit commitments.
You'll still have emergency response service deployments.
You'll still have firm load shed.
Those are still, you know, theoretically,
so, those are still things that you need
to correct the price for to,
so, there will still be the second pricing run.
-: The phenomena of bringing more generation
on for reliability will -: That suppresses the price.
-: Remove the economic incentive
to bring more generation on.
-: We just no longer will need to try
to price what the value of reserves are,
because those will be contained
within the ancillary services prices.
Lori: Okay.
-: Out of market actions, we kind of talked about that.
And so, total price is all three.
Now, the opportunity cost.
So, the day ahead market today does co-optimize.
And so, when there is no realtime co-optimization now.
And so, some of the ancillary service prices have to be,
people have to kind of price
in what they think their opportunity costs are going
to be in realtime.
And so, the market construct is a little bit different
than it will be in the future.
It's really important,
so, what's really important about this,
the ORDC and the RDPA and why you have these adders is that,
you know, maybe only 15% of load is exposed
to realtime prices in a interval to interval basis.
But the realtime prices informs the forward markets
and it disciplines everything coming into the future.
And so, even though a small amount of the load,
actually pays the realtime price, the realtime price
will govern what people expectations are.
The day ahead market is based on expectations
of what the realtime market is
and the realtime prices being correct
not only makes those expectations correct.
It is the short term incentives of ensuring that,
when prices are high, you have generators on,
and then also the longterm investment decisions
to enter the market
or exit the market are based on those realtime prices.
So, making sure
that the realtime price does accurately reflect scarcity
is important for making sure
that you get the most efficient investment decisions
in the long-term.
Yeah. I think I- -: So, Carrie,
back to that, the question of all these adders.
-: Yes. -: So ultimately, that's not,
that isn't as important to the market as,
I'm sorry, to resources when considering investment
as the realtime price formation.
So, if there's a cost that we look at, an evaluation,
it is the accurate formation
of that scarcity in the realtime price,
not necessarily the adders?
Does that kind of? -: The adders are
what helps create the total price,
which is in scarcity includes those adders.
Will: Okay.
So when you say the realtime price,
you're including the adders. -: I'm including all of them.
The total price, yes.
Good clarification. Thank you.
So, in the realtime market is, you know,
natural gas is typically the marginal fuel type.
And so, it's typically setting the price.
So, those realtime prices will change
with the natural gas prices.
So, those are closely linked.
Except when we do experience shortages
and then they kind of become uncoupled
because now your prices are not so much
based on your marginal unit,
but now they're based on these scarcity questions.
-: So, natural gas is the marginal price driver
for 51% of our generation.
How do other sources
that aren't based on natural gas impact
the realtime end of day head price?
-: So, the system Lambda, the energy price,
the base price without the adders is set by everybody puts
in their offers for their short run marginal costs.
And wherever that stack of generators intersects
with the amount of load,
that generator sets the price for all the generators
that are online.
And that tends to be a gas unit.
-: Okay. -: And it's short run
marginal costs are, the highest of those is your fuel cost.
-: So, where, how do the negative prices from renewables
that we've heard so much about factor into all this?
-: Yeah, I'm mostly talking about peak conditions.
So, if you're talking about two o'clock in the morning,
the gas, there's probably,
if there are any gas units online,
they're at their low limit.
And when units are at their low limit,
they don't set the price.
-: Okay, but there, but everybody gets the same price
every five minutes, right? -: Everybody gets
the same price every five minutes.
-: So, in that framework, at two in the morning,
if a gas plant is at it's lowest sustainable load,
they've just got it,
they've got it in the lowest gear possible.
-: Yes. -: So it will be ready
for the next afternoon.
They don't get the marginal cost
of the gas that they're consuming.
They're getting the negative price costs
of the renewables spinning, right?
-: Yeah, so, they have to decide whether or not,
in that case, if you're getting negative prices,
that's a signal that you should go offline.
-: Okay.
So, the current construct, at two in the morning is saying,
if at negative price?
-: You're not needed.
If your marginal cost is $30.
And then, and the price is negative eight,
-: So that, -: You're not needed.
-: That generator, well,
-: You're not needed. -: I may not be needed
at two in the morning. -: At 2:00 AM in August.
-: But if I've got an 18 hour ramp time
and you need me at-
-: Most gas units have much faster start times than that.
-: Okay, but that's saying,
somebody waiting in the, waiting to be ready.
-: Yes. -: And I guess most gas,
most gas generators aren't the ones we need in scarcity.
Right?
It's the ones that aren't the fastest ramp time, right?
When you need everybody.
So, but just to be clear,
the way the market clears right now,
if you keep your gas unit on,
at two in the morning at like the lowest gear possible
to be ready for the next day, Carrie: Yes.
-: You have to pay a negative,
a negative price means you're paying $20 a megawatt just
for the privilege of being on.
-: If it's cheaper for you to stay online
and pay those negative prices and not have to shut down
and then start up again,
you know, you'll have to look over the entire,
if you're online for five days, you know,
maybe one night you're in the negatives,
but maybe your profit and loss is going to be across
that commitment timeframe.
-: Okay, and then when we do get into times of scarcity,
like in the afternoon, you're offering,
and the clearing is designed
so that you're offering, -: Yeah.
-: The lowest possible price,
Carrie: To cover your costs.
-: Because you, because everybody gets the same price
at the same time, -: That's right.
-: You don't care about trying
to get a few dollars more per megawatt.
You just want to make sure your generator's called, right?
And so, you're going to offer the lowest possible price.
-: If you, if you try to offer more
than your short run marginal cost
in a competitive market, then yeah,
you just won't get called.
And so, everybody's
incentives are to- -: Well, it depends
on the demand, right?
-: Well, the demand is fixed. Demand is vertical (laughs).
-: Well, not between 2:00 AM and 4:00 PM. Right?
Carrie: Right, right, but.
-: So if can guess, I mean,
I'm sure all these companies have predictions
about what load and load is going to look like.
But then the question I'm getting at is,
if you've got to pay a penalty to be on
and be ready to go at night,
and you're designed to not,
it's designed to not game the system, right?
You want to, because everybody gets the same price,
you want to get everybody offering
the lowest possible price, right?
Because their only incentive is to make sure they're called.
And if they try to add another five bucks to their offer,
then they run the risk -: They might lose out.
-: Of not getting called and they get no money,
which is a feature.
That's why all power marketers use that, right?
Carrie: Yes.
-: Where in, but where in this framework are generators,
where does the profit and the economic incentive
for these companies to invest in new generators?
Where is, I mean, these are private businesses, right?
-: Yeah.
So, you might've heard of the Peaker Net Margin
as an estimation.
So that's, I bring that up
because it's a representation
of how a plant might look at it.
So, you're not going to make a decision based on one day
or one month or even one year probably, right?
You have to,
as you run throughout the year,
every time the clearing price is above your marginal costs,
that's profit to you that you use to cover your fixed costs.
And you're talking about fixed costs of like being online
when it, you know, you're at your minimum level
or other sort of capital costs.
And over the longer timeframe is
when you recover those costs.
But in any given interval,
you only offer your short run marginal cost.
And so, if your marginal,
all you're covering is your operations and maintenance,
your fuel and whatnot.
But every time somebody is, gets selected above you,
and you're going to get that clearing price.
-: Okay. -: And those are the intervals
in which you're recovering all those other types of costs.
-: So, I'm trying to work through when we,
the question we get is why is there not more generation?
Right?
That's the kind of eternal question we've heard all session.
And what I'm trying to get to is, how can we as a state,
when we've got to find the balance between reliability
and affordability, what, where do we,
and we have the very good point you made
about the dispatchable gas intent of in PURA.
So, for a dispatchable high, like low heat rate,
super high, efficient combined cycle gas plant
that can offer a very low price, right?
Like that's the hope, right?
Like we want really efficient dispatchable generation
for the times when we really need it.
The only time they can make a profit,
if there's a less efficient peaker out there
that gets filled.
And that's what moves the price up to give them a profit.
Is that right?
-: Well, I mean, peaking units have low capacity factor.
So, if you're talking about a peaking unit,
that's a little different from like a combined cycle.
But if you're talking about a, you know, simple cycle GT
that's just, you know,
those tend to be have high heat rates.
So, they're expensive.
-: Okay. -: Right?
Peter: Right, but I guess just hypothetically,
if the entire fleet -: Okay.
Peter: Was super efficient combined cycle gas,
just hypothetically. -: Okay.
Peter: And everybody's marginal costs was $10.
I'm making the numbers up. -: Yeah.
-: And the feature of the market design is
that nobody ever wants
to offer more than exactly what it costs
to make one more megawatt, -: Yeah.
-: Which is gas and labor and, you know,
whatever it costs that day, right?
So, everybody would always get $10.
-: Plus, yes, plus the ORDC and the RDPA if there,
if we are in scarcity or if there is a reliability action.
-: Okay. -: So, there's
-: So the, -: Money on top of that
if we're in scarcity.
So, the idea is that, if we're never in scarcity,
that's a signal that we don't need more generation.
If we're frequently in scarcity,
there's going to be a lot of revenue.
And that's a signal that we need more generation.
So, the scarcity pricing provides
those longterm investment signals.
-: Okay, so, the more we,
so, what I'm trying to get to is like, what is the,
how do we incentivize somebody to invest a dollar, not only,
and if it's a dollar designated for additional generation,
how do they,
why do they choose to invest in new generation
instead of investing in real estate
or any other asset class?
And if they are going to invest in generation, why do,
how are we going to get them
to choose Texas versus somebody else?
And the crux of it seems to be,
if the only way they can make money is scarcity,
what, like how do we balance that intersection?
-: Of reliability between profit?
-: Yeah. -: I mean, that's ultimately,
-: It seems real tricky right now.
-: It's tenuous, right, Carrie?
I mean, that's the crux of it.
And that, and you've argued this
with the high value of loss load, i.e the $9,000.
And I would put, point out,
you've got great charts showing,
and I think Peaker Net Margin plays
into your calculation on this,
but the cost of new entry, the cone.
And we've only hit that once in 10 years.
Carrie: 2019, mm-hmm.
-: (laughs) And that was at $9,000
for six hours? -: That's cost of new entry
for a brand new, -: Combined cycle
which is what he's, -: Yep.
-: What the chair's talking about.
So, how do we normalize this?
How do we reach?
-: Yeah, so in an energy only market,
it's these realtime prices, particularly in scarcity,
they need to be properly formed
so that those incentives exist.
You also have the ancillary services market.
So, we can't ignore that,
is that you also have the,
and they're capacity products, right?
And as long as you are asking for the features
that you need, and you're providing this revenue stream,
then you'll receive those features.
I mean, I think what we're seeing is,
based on the realtime prices and the times of scarcity
and the features of our market is tending
to incentivize things like storage resources,
because the fast frequency response, for instance, is that,
you know, it's signaling,
we need resources that can respond very quickly
to renewable ramps, right?
Or whatever other reason.
And so, the market creates products
that ask for exactly what it needs and no more,
and that provides the investment signal to the market.
So, if there's no,
if the cost of new entry is not-
-: What if it doesn't? -: Mm-hmm.
-: Saying new combined cycles,
the answer may be, we don't need new combined cycles.
And I know that's not maybe the most popular thing to say,
but if you have a 15% reserve margin
and the way that the prices have been coming out are such
that the fixed cost of those are only getting recovered
in certain years,
that might be a signal that we don't need them.
And if that's not the case, for policy reasons,
then you have to make some change to the realtime market
because that's what our realtime market is signaling.
-: So I think, you know, the chairman may, you know,
is asking you obviously very important questions,
very, very important broad questions.
I think when we look at this with your larger questions,
I think we have to recognize that,
I think what Carrie saying is
that we are an energy only market,
and that's based on scarcity price signals
to incent generation.
And there are only certain knobs that we have
in our current energy only market
that we can turn to drive those scarcity pricing signals
at this time, like the ORDC and these adders.
And obviously, we have the ancillary service market
where we're looking at not only the existing products,
but new products that will be put into service
to drive certain investment, like energy storage
and the Quick Start generation unit.
So, I think,
we'll have to work with what we have now
and evaluate other mechanisms potentially
to address some of these broader questions.
-: SB 3 has some pretty big knobs in it.
-: Yes.
Levers.
-: Another thing to consider,
economic dispatch on transmission.
That is at low bid as well.
So, even when we're considering battery discharge
on transmission or a solar, at some points,
and depending on congestion constraints,
again, it's the low bid.
So, whoever is producing at that lowest possible price.
Is there a concern there for the purpose
of drawing in resources that ERCOT may otherwise need?
Because again, a PTC wind megawatt
versus a solar, you know,
whatever they've recouped in ITC,
but a solar, even zero marginal cost megawatt,
and then a battery megawatt,
that wind is going to crowd all that out for a time.
But again, for frequency regulation,
depending on what may pop up as we move into the future,
in terms of the engineering requirements of the grid,
do we need to look at that?
-: So, let's talk about transmission congestion.
You know, it occurs
when you can't use the cheapest generation
to serve your load.
Will: Right.
-: Because there's some problem, you know,
there's some transmission line that's full, let's say.
And so, or group of them, in the case of GTCs.
Those prices will go down and that's a signal
to either stop building there or for some,
it can be a signal,
because a lot of the times when we have low prices,
in some hours, we have high prices in others
in the very same regions,
because it does tend to be correlated with the renewables.
And those price signals are very important
to drive the decisions that need to be made
as to the location.
So now, we're not talking about capacity anymore.
We're talking about where should the capacity be located?
So, to the extent somebody is looking to build,
put new steel in the ground,
those locational prices are going to,
on the other side of the constraint, the price is high.
And it's going to tell you,
locate here to resolve this congestion.
So that's, those are,
those pricing signals are there specifically
to resolve the congestion.
So, in realtime dispatch,
the realtime market needs to, minute by minute,
resolve that congestion
and ensure that the line doesn't burn down.
But from a long-term perspective,
that's also telling you where in the state to put those,
you know, and it tends to be like,
you know, near load centers or,
you know, in weaker parts of the system
when it comes to transmission build out.
-: Okay.
Yeah, and where I go with that is, as variability increases,
again, as the resources that are coming
into the market increases,
and ERCOT has considerations
that are just not price dependent,
but they're based on engineering analysis
on what these resources may or may not be doing
to the transmission system within those given areas,
or within those key links, those substations,
those choke points, as you point out,
do we need to re-look at how that is priced
in order to send the right reliability signals?
It's not just an economic signal,
it's a reliability signal
at that point, and again, -: Well, I think-
-: We're dealing with a commodity
that moves at the speed of light.
So do we, can we pair those two?
-: I would say that's a function of the planning function.
-: Yeah. -: Because I wouldn't want, I,
those pricing rules are important.
I wouldn't want to dampen them.
-: Right. -: Because they do
make more efficient market overall.
And if we were to dampen those price signals,
then you would get build out where it doesn't belong.
You would make the problems worse, right?
Those price signals are supporting the reliability need.
Now, if you need to do something else,
then that's where the planning comes in,
whether there's economic criteria
for building known transmission line,
there's a reliability criteria
for building new transmission line.
-: Right. -: But if the,
if the congestion costs are so high,
that it might meet some economic planning criteria
on the planning side to resolve that congestion
and unlock some of that lower cost generation.
-: Okay. -: Oh and I believe we're going
to be looking at -: Right.
-: The new transmission criteria.
And I think it's really just the,
you know, the overall balance is policy,
balance between building more transmission versus trying to,
you know, signal for generation build out.
-: Sure. -: And how they hold.
Crux, right? -: Yeah.
My point was, is that,
and I think we've all three heard from ERCOT is
that we're going to have a lot of new technology,
new data from this technology over the next year,
that we'll be able to evaluate how the batteries,
how that 1,000 megawatts of batteries are interacting.
And again, just with the increased concentration
of intermittence in certain areas, how that interacts?
And I knew that there were complaints from certain resources
that they weren't even able to get on the grid, you know,
on the lines at certain locations,
because they were never going to be the low bid
because of the nature of the other resources in the area.
So, it sort of hemmed that in,
in terms of what type of resources located where.
-: Yeah, we certainly heard about, I think,
some trapped generation in the valley potentially.
-: Yep.
-: So, that was part of the GTC discussion.
So, there are a variety of different angles
to look at this issue (laughs).
-: All right. Keep going, Carrie.
I know JC's been waiting patiently.
So, we're trying. -: No, I know it.
-: That's all right. -: That's why I'm thinking
I'm taking too much time.
-: It's perfect layout though, 'cause.
-: I'll just mention one more thing.
I think, going back to the ancillary services,
because I know that's a big topic
that I think it's a little bit detailed,
but to get into just thinking
about these ancillary services, when they're deployed,
also have impacts on the market.
And so, it's something to keep in mind
as we're pulling certain levers on the ancillary services
that they also affect the energy prices.
So, like regulation, not necessarily
because regulation kind of happens between the market.
So the, it doesn't have as much of an impact,
but if you're looking at the responsive reserve service,
you know, the more of that gets reserved and the mark,
the realtime market cannot access it, that capacity,
unless we're in an emergency condition
and it gets deployed and then it's released to the market
and then the market dispatches it economically.
So, the more you reserve behind that wall,
the less there is for the realtime market to dispatch.
And that can raise prices.
So, depending on where you put that wall,
that makes an impact.
So, you know, it's what,
just another component that I wanted to mention.
And lastly, with the non-spin,
it's a little bit of an oxymoron
because you can have online non-spin and offline non-spin.
But if you have online non-spin, that capacity is,
has to be priced at $75 or higher.
So, it has an offer floor on it,
so that the market's not accessing those megawatts
until the price gets to $75 or above.
The same's not necessarily true for offline non-spin.
So, those are just two things to keep in mind,
as we're talking about ancillary services today.
I think I'll stop there and let JC talk.
-: Thank you very much.
And I know this is, as I said before,
this is first of several of these kinds of conversations.
I appreciate -: Sure.
-: The information and your candor.
Next up, state your name and who you're with please.
-: Thank you, chairman.
JC Kneale with Intercontinental Exchange, ICE.
I appreciate the invitation to be here today
and let me compliment you guys on the prescience
of having the order that you have set,
'cause you've got Dave telling us how it all works,
and then you've got Carrie telling us
how the prices are formed.
And so, what I'm going to try to inform everybody is,
what do we do with those prices?
It's great that we understand how we make the prices
on the day and even the near term,
but what is that used for?
And why is it important?
And Carrie hinted at it.
It's investment in the future.
And chairman, you've been asking this question over
and over, is how do we get more people into the market?
And so, what we at ICE do is we run the forward market.
So, ERCOT is managing the price signals in the realtime
to make sure we can turn our lights on every morning.
And the model is prescribing a price for that service.
And that's ultimately what we all get paid on
in the realtime and the day ahead for those products.
But what ICE is here to do is
make transparent the forward curve.
So, what do people anticipate the price for those services
to be in the future?
And in particular for ERCOT,
in the power and the gas markets, right now,
we go an average of about a decade into the future.
There are certainly companies out there that do investment
on a longer time horizon, that have their own models,
that guess at what these prices may be two decades,
three decades, perhaps longer into the future,
but it's not realistic for an exchange such as ourselves
to have products that service those markets
that effectively are never actually utilized.
They're just sort of background research.
So, if you could move into the next side, please,
that'd be great.
Just a quick, and I'll apologize.
This is formatted for wide screen and we've got a square,
so, we'll do the best we can.
But in short, the, first couple of slides are really just
about who we are
and ICE operates exchanges all over the world
for all different kinds of assets classes,
whether it's gas, carbon, metals,
exchange rates, interest rates, energy.
And obviously, that's what we're here for is the energy.
We're also a little unique in the exchange space
in that we actually offer our own front ends
for transactions versus just allowing the other folks
to provide that service.
Next slide, please.
A few years ago,
we bought a company that some of you guys may have heard of
called the New York Stock Exchange.
And so, we also service the equities business globally
and with the equities business and the energy business,
I think it gives us a really unique insight
into how investment decisions are made
in the energy space in particular.
And obviously Texas,
I believe the NYC folks would get on me about it,
but Texas alone would represent the, you know,
sixth largest country in terms of listed companies
on the New York Stock Exchange.
So, Texas in particular is extremely important.
And a lot of those companies, as you can imagine,
are energy companies.
So, they, hopefully they know what they're doing.
If you'd hit the next slide, please.
I appreciate it.
So, first I wanted to talk about hedging.
There's been so much discussion over the last several months
about hedging and who hedges and who doesn't hedge
and why it's important or unimportant.
And ultimately, what hedging is supposed
to do is provide you with a bit of assurance
that should you have a resource
and you have estimated the price of that resource
or the value of that resource incorrectly,
this is, in essence, an insurance payment against that.
So, if you go make a particular investment
to provide a service of any kind,
you would hope that there is a way for you
to hedge that bet, so to speak.
Go out and either buy or sell a product
that would give you some sort of financial protection
in case you've made the wrong decision.
And that's what we see in these exchange markets.
And that's what we see in Texas in both the electricity side
and the natural gas side.
The ERCOT market is widely regarded
as one of the most successful markets
in terms of operational investment and trading.
And that trading is important because that is the hedging.
That's what all of the participants in ERCOT are looking to,
to understand the value of their generation stack,
understand where they need investment
and what the potential cash flows from new investment are.
So, if we break it down very simply,
there are three types of hedgers here,
and maybe there are others,
but these are the ones that pop into my mind most rapidly,
which is, you know, first you've got consumers
and I don't necessarily mean you and me,
but the reality of it is,
is in a way it is you and me.
We have the power to choose here in Texas.
And so, we get to make all sorts of choices
about which provider we use and what price we pay for that.
We get to choose what generation stack even.
So, it's a pretty powerful tool for us as consumers.
And hopefully, we're all using fixed price contracts
at this point.
I think we understand the dangers in not,
but there are also industrial consumers,
manufacturers, et cetera,
just anybody on the grid that uses electricity
as a consumer,
and they have the choice to hedge their products,
either on the day ahead market or the realtime market.
And luckily, we had these guys to explain
to us what the difference in the day ahead and the realtime,
I always like to think of the day ahead
as it's everybody's best guess
at what tomorrow's going to look like.
And realtime is just the reality, and it's the difference,
and in fact, one of the most common products traded in Texas
and other markets is a spread
between the day ahead and realtime.
And it's essentially,
it's a guess at how efficient the market is pricing
and understanding in the day ahead
versus what reality will end up.
The next category is we've got the generators
and this is where we're going to spend a lot of time today,
I'm sure, because we understand
that generation scarcity is an issue
and potentially a growing issue in the state,
but electricity generators,
they have a couple of different inputs
and I'm going to keep it very simple.
We'll assume everybody's got cost of operations, et cetera.
But the bottom line is, depending on the type of generator,
I have to buy fuel,
whether that's coal or whether that's natural gas
or what other commodity that,
diesel, I might run my generator,
I've got to buy that.
And so, I have price risk with the input to my generation.
I know roughly what it costs me
to convert those molecules into electricity.
And so, that is the price
for the electricity that's put out.
I have a couple of options there as well.
I can sell my electricity, truly,
as it comes out of the generator
and at which point, I'm exposed to the realtime price.
That's a choice.
We would say that's un-hedged, but that's your choice.
And the other choice I have is I can sell financial futures
or actually the physical power on a forward basis as well.
And so, I can lock in those prices
based on my best guess at my input costs
and my output costs,
lock in my P and L, and hopefully sleep well.
And that all works until something goes crazy.
And though, when I say go crazy, I should back up there.
When the system performs the way it's supposed to
in times of scarcity,
crazy, just implying that prices get higher unexpectedly.
And then we've, of course, got load serving entities.
And load serving entities, in my mind,
are typically entities who don't have enough generation
or any generation to serve all the load.
So, they're usually out there procuring generation to sell
to consumers or anybody that needs it,
and they too have price risk.
And so, they're the opposite,
they're typically going the opposite way of the generators
because they are procuring the electricity
or procuring financial assurances against rising prices.
I know I've said a whole lot there,
and if everybody's on the same page,
I'm happy to keep going,
but I'm happy to answer any questions there
in the middle as well, so.
-: Quick question on the,
especially on the load serving side,
are there forward and future products only,
or options as well?
-: Options as well. Yeah.
Let's go to the next slide please.
So what is the role of ICE in all this?
Well, there's a couple of functions.
So, we operate both an exchange and a clearing house.
The exchange is where both buyers and sellers come
and they place bids and offers,
no different than in the ERCOT model as well,
where we're trying to optimize for the best price.
This is very similarly,
we're optimizing the bids and the offers
until we have a common price,
at which point, we have an executed order.
The clearing service that we offer is futures clearing,
meaning we have a clearing member or bank,
somebody representing the end consumer
or end user offering price protection,
offering credit typically.
And those clearing members access our clearing house.
So, ICE every single day is looking for initial margin.
Basically, that margin is guaranteeing the performance
of both the buyers and the sellers to honor their contracts.
Every single day, we're creating a mark
to market price for the contracts traded,
and we're assigning a P and L, both paying and collecting,
every single afternoon and sometimes during the day,
depending on the commodity.
And in doing so, we like to say that we're,
that initial margin should be enough every single night
to cover the worst move tomorrow.
Right?
So, we've always, we're never so far out on a limb
that we don't have enough cash
to cover any gains and losses the next day,
that isn't always the case.
And that's why we have to raise margins from time to time.
Certainly, in Texas, we saw issues in the winter
where we didn't have enough margin on hand
and that can happen.
And how we react to those situations is really the key
to the clearing house or any credit mechanism.
In futures clearing, we're fairly limited.
We expect payment every single day.
There's no, there's no lack of payment.
If your lack of payment, you're considered in default.
And the rules and regulations provided by,
whether it's the United States, or United Kingdom,
or Europe are very clear,
we don't have much leeway in collections.
So, now, the clearing members can sometimes give, you know,
24 hours or 48 hours to their customer.
But we as a clearing house expect payment daily and timely.
And if you're not made daily and timely,
we can put you in default, potentially liquidate positions,
potentially liquidate the desks and pencils in your office.
We're going to come and find all the money
and we're going to do it as quick as we can
to keep the market whole.
Will: So, question there,
-: Yes, sir. -: When you consider the risk
of market participants,
and where I'm headed is we sort of have,
in the ERCOT market, two clearing houses,
we have ERCOT, to a certain extent,
and then we have ICE, and you're on the supply side,
you know, arbitraging that commodity
and paired with generation and then retail as well,
I assume, because they're hedging through you as well?
-: The reps, for sure, yeah. -: Sure, yeah.
-: Not individuals but reps, yeah.
-: But reps, yeah.
So, in terms of actors who default,
what are the repercussions for that?
If they default, can they not, you know,
what are the ramifications for that with ICE?
-: Yeah, it, pretty swiftly we're going
to remove their ability to participate
because we don't want them to exacerbate an issue.
If we're concerned about a credit issue,
we act swiftly to put a member in default
and in this particular model, and I've got to,
to muddy the water, we actually have two clearing houses,
one for financially settled products
and one for physically settled products.
And so, when we get to the physical one,
that might even make more sense
as to how it relates to ERCOT.
But in this particular model,
there are two different credit assurances
for us, the clearinghouse.
One is we've got member banks or member firms
that represent their customers.
And so, a member firm may have 20 customers.
Every single day, I'm expecting the member firm
to make me whole.
If they have a customer that creates such a large default
that the member firm cannot make me whole,
then I put the member in default.
I potentially remove all trading privileges
for every customer of a clearing member.
And so, those solvent clearing customers would have
to move to a new clearing member
in order to continue to participate.
-: So, there is a direct overlay between the QSE actor
and with ERCOT and ICE.
So essentially, they're, -: Yeah.
-: They're acting in both capacities.
JC: It absolutely could be, right?
-: Okay. -: So, there are certainly
some financial only participants
and as well as physical participants,
but so, not every ICE participant would be at the QSE level
of interaction in the ERCOT market.
But it's probably fair to say that every QSE participant is
in some way active in ICE, maybe not directly,
they may go to a bank for hedging
and the bank may come to ICE, but in some way,
they're interacting with these forward markets
that are made transparent by our exchange.
Will: Okay.
-: So, let's jump to the next slide too.
'Cause I think this one is particularly, excuse me,
we were just going over this slide more or less,
which is ICE Futures US.
So, this is really where we have our financial futures.
This is all cash settled instruments.
So, all, performance is purely did you pay your bill?
Not showing up with molecules.
Now, let's jump to the next slide
where I think it gets a little more interesting.
So, this is ICE NGX.
So, ICE NGX is a subsidiary of ICE
that is involved in the physical delivery,
settlement and clearing of megawatts in ERCOT.
We also deliver, schedule, physical gas in Texas,
but as it relates to this particular discussion,
let's talk about the physical power side.
So, in this instance, ICE NGX is actually a QSE.
So, we truly are involved at the QSE level.
We are scheduling in and out buys and sells
to ERCOT every single day.
Now, by default, we're always flat.
So, we should never be any risk to anybody
because I've always got a buyer and a seller.
But in this particular case,
we do sometimes see defaults as well, right?
So, much like ERCOT,
our first action would be to go in and assess the credit.
We may shut down a customer only buying.
We may shut down a customer only selling,
depending on which side their balance is.
(coughs) Excuse me.
If they are in default,
then we're gonna quickly move into our default procedures.
And we're going to seek
to consume their entire letter of credit.
If that's what we have on hand,
we're going to ask the bank to turn it to cash.
We're going to come after any assets that
that company has,
and we're going to move swiftly to do so, right?
We do not allow companies
to participate once they are in default.
Once we have put you in default,
if you want to participate again in the market,
you have to either make use of any existing balance
that may be in your favor with the exchange.
For instance, a company may go into insolvency,
but have a net balance with us
because they have receivables that we owed them.
So, we would allow them to participate
such that it diminishes their balance,
but never beyond zero.
However, if they simply owe us money,
we shut it down altogether.
We don't allow them to participate.
The next step would be,
we would go to that company and meet with management,
understand what other steps to get back to solvency
if the case or resolve any defaults.
And it may just be a timing issue.
It may be, "I couldn't make the payment today.
"I can make the payment tomorrow."
We have a little bit of leeway to go in and work
with the customer, just as ERCOT has a little bit of leeway,
but if we're ultimately not satisfied
that they can meet collateral,
we just, we don't enable them again.
We're not going to take that risk.
Does that answer your question, sir?
Will: Yes, sir. Thank you.
-: Okay.
And again, so this is on the physical side,
so, it looks a little bit different.
This is more, if you think about it,
there's future style margining and accrual margining,
and this is more of an accrual margining.
So, in future style margining,
there's a daily P and L and there's a true payment
and of every single dollar that comes in and goes
out on a daily basis.
In this accrual standard, cash isn't fully,
or P and L isn't fully recognized until flow has happened.
So, until delivery has occurred,
you can't take your money out.
It creates positive balances
that you can use as margins, et cetera,
but because it's accrual, because we expect delivery,
all we're doing is sort of giving you unrealized profit
and loss on a daily basis.
We still collect initial margins.
We still do all the other things.
We do mark to market, et cetera.
It just, the cash flows a little bit differently.
-: Can you talk about how this schedule,
how you're scheduling of this physical delivery?
Because you got a buyer and a seller
both agreeing, they don't, never,
I don't know if they see each other or not.
This is OTC, your OTC platform, but through you,
they're getting an electron delivered to a certain point
at a certain place in time.
-: Well, really just to the grid.
So we're, you know,
that's the nice thing in a market like Texas is
that you can really think of it as a pool.
So, as long as I'm putting as much power into the pool
as I'm taking out, it doesn't matter.
There are regional markets, we use the hubs.
We also clear out the load zones.
And so, to some extent,
the product you choose determines the region,
but I'm not necessarily getting to the nodal level.
We believe that currently that's too precise.
If we were to go to a nodal perspective,
odds are you'd have only one or two counterparties able
to participate at a single node.
-: Right. -: We believe that creates
excessive risk of concentration and things like that.
-: Sure, so, what I'm trying to get at is how your,
the physical products that are traded on y'all overlays
with both the ERCOT trades -: Yeah.
-: And interacts with the ERCOT scheduling
because you don't -: Okay.
-: Just have a buy or sell ERCOT power
on October 15th product.
You've got a whole lot of products lifted at ERCOT, right?
-: That's right. Yeah, that's accurate.
So, we have everything from,
on the cash side, we do a same day product.
So, people are truly buying and selling a peak load product
for hour 7 to 22.
It's a cash settled instrument that they're using
to hedge what they believe could happen
throughout the balance of the day.
And based on that,
it allows them to make resource guesses about,
should they go ahead and spin up generator?
And if they do so, here's the hedge for the cost
in case it doesn't get called, et cetera,
and everything through a calendar 2032 product,
where you're simply making a hedge or guess
as to what the value will be 10 years from now.
-: How many different geographic, if you,
for lack of a better term, how many different geo,
like, locations? -: All five hubs,
including the newer panhandle,
which is about 18 months old, I guess, now.
And I believe all of the load zones for those hubs as well,
the geographically, for whatever reason,
they're not perfect.
They line up slightly differently.
So in fact, some people will trade a hub versus a zone,
even though it's both Houston hub and Houston zone.
And there is some diff, overlap there, you're right,
or non-overlap, if you will.
We provide all that.
And then as you said,
everything from daily to next week to balance the week,
to the balance of the month, monthly,
on out into the future. -: So, you can,
so, your platform, you can go buy
and sell the obligation to either deliver
or receive an electron in any of these 4, 6, 8?
-: In the NGX platform for physical delivery,
there are five locations.
-: So five locations, so that,
there's a separate product -: That's right.
The five hubs. -: For Houston
versus West, versus North. -: North.
-: Versus south. -: That's right.
-: For any time between now and 2032?
-: That's right. Roughly.
It may vary slightly on the tenor,
but a long time.
Peter: Yeah, Long time out.
And that's a completely different financial product
for the Houston zone and the West Texas zone?
-: Absolutely.
-: And you could also have products
that will trade the spread between those on how,
which to what Carrie was talking about earlier, does that,
that would capture some transmission
inefficiency? -: That's exactly right.
It's a bit of a congestion play, right?
So if I believe that there's going to be a ton
of excess generation in the West,
which theoretically there should be,
there's less people, but there's a lot of generation.
I may spread it to North or to South or to Houston
as a way to cover that guess on congestion versus the load
that I may need to serve in Houston, et cetera, so.
-: But if I'm a generator say in South,
and I want to, you know,
I want to obligate myself to sell an electron in the future.
So, I get the cash now for physical delivery
of that electron on October 15th, 2024,
and it's only for the south load.
That's not just dumping it anywhere on earth.
-: That's right. That's right. -: Okay.
-: And I mean, you know, theoretically,
as the Commissioner said,
this all moves at the speed of light.
So, if you're able to provide to this, to the grid,
then theoretically that power can move to Maine,
but it's about getting it there, right?
So, you've got to have that transmission.
-: Right, but if I took the money now
-: Right. -: To obligate that,
-: But you're obligated for where you bought it,
that's right. -: And if I don't show up
with that power in that zone,
JC: Then you face repercussions.
-: Then I'm in default to ICE?
JC: That's right. Correct.
-: But on that time in place then is,
when does that scheduling?
I've got to get to that zone.
When does the scheduling and distribution
of that shift to ERCOT?
Like, I guess the handoff of that electron.
-: Sure. Day ahead. -: Okay.
-: So, scheduling for tomorrow's electricity is done
and keep me honest, by 10:15, or it used to be,
been a long time since I had to do that.
10:00 AM. Okay.
So, by 10:00 AM each day, I have to have
into the system all of our longs and shorts
to the ERCOT, by location,
et cetera, scheduled in the system.
-: Okay. -: And so,
I want to say in June we had something
like 20 terawatt hours of buys and sells.
And on average,
we scheduled each day about 40% of that total.
So it's, you know,
we get a lot of netting, as you can imagine.
Right? -: Sure.
-: So, buyers and sellers.
We are the counterparty to everybody.
So, it doesn't matter if Carrie bought from me
and then I sold to Dave, they would never know,
nor do they ever need to know,
because I'm the guarantee in the middle.
-: So, 40% of the transactions are based
on power purchase agreements that you're processing.
-: No, I don't, I don't want to say that.
I was trying to illustrate that, of the total volume
that trades on the platform, -: Right.
-: Not all of it gets scheduled.
Will: Okay.
-: So, just because I've bought or sold,
doesn't mean I'm truly -: That's not necessarily
part of it. -: Going to show up.
-: Okay. -: That's right.
Because someone's going to net out.
I may, in the chairman's example,
he bought for October 15th. -: Right.
-: He's got between now and then to change his mind.
And he may very well do so.
He may find a better opportunity somewhere else.
At which point, he would simply come out of the exchange,
flatten out his ICE position
and go sell to that customer directly.
If that's what he chooses. -: Yeah.
I'm trying to figure out what Carrie sees
in the realtime market.
And again, that's what we're watching constantly.
And again, that vast picture
of the bilateral agreements.
What is the pie chart on that?
-: So, you're, -: Right.
-: Where the exchange, -: So all she sees is,
at the point it's been scheduled,
and this is really for Dave too, right?
So, all ERCOT sees, we should say,
-: Yeah. -: Carrie just gets to see
what ERCOT can see. -: Yep.
-: The only thing they can see
is what actually gets scheduled.
So, they wouldn't get to see the other 60% that netted out.
They wouldn't get to see any of the buys and sells
that happened and never actually went
to delivery, et cetera.
They only see what is truly scheduled
onto the system the day ahead.
That's it.
They don't get to see what is going to happen
for October 15th.
Now, they can take price signals in theory, because,
because October 15th traded today,
I can create a mark to market for October 15th
and give everybody investors, generators,
whatever, some idea of what the value of October 15th is.
-: Right, but a bilateral,
I think this is important, like a bilateral
between like Acme generator and Value Co rep,
where they agreed to deliver electrons over the next,
of a certain, you know, over the next three months,
that can be a two party agreement that never touches ICE.
-: That's right. Absolutely. -: Okay.
-: And that's, they schedule that,
Acme schedules it -: They'd have
to schedule it directly.
That's right. -: Directly, call Dave,
-: Got it. -: And says,
this electron needs to go to Value Co, right?
And that's the bilateral you hear so much about.
-: For sure. -: And that's a huge,
-: Huge part, absolutely. -: 85% of the physical,
-: Yeah. -: Of, like I said,
the power schedule. -: It's tough to say
because it's very opaque, right?
And that's the reality.
So, the benefit and curse
of the transparent exchange market is
that it's all right there for you.
So, you can see what's happening, but in the opaque market,
the bilateral market,
which serves a absolutely necessary function,
don't get me wrong.
I don't mean anything negative by opaque.
There's no great way to see what's going on.
Now, on the Swap, capital S, side,
Dodd-Frank tried to bring some of that
to make it more transparent,
which is why they created the swap repositories, et cetera.
-: Okay, but even on the day ahead,
that can be a financial
or a physical trend, right? -: Sure.
That's right. -: So, you can buy
a day ahead and then never physically take or,
or generate. -: Yeah.
-: Yeah, it's an option. -: Ultimately, you've always
got ERCOT as your backstop, right?
And so, a lot of our participants do, in fact,
trade most of their book financially,
because the beauty
of those financial instruments is they settle exactly
to either the day ahead or the realtime price.
So if it's realtime and I need megawatts,
and I have a hedge, well, good news,
the settlement price of that financial contract is the price
of the energy that I need to procure.
-: So, I just wanna make sure I understand this right.
And then ask you
some more specific questions. -: Sure.
-: So, as the Chairman and Commissioner McAdams are saying,
they, basically, your visibility is into the day ahead,
realtime, not into the bilateral market.
There's not a lot of visibility in there.
-: Well, they're the same thing.
It's just that some of that day ahead is bilateral
and therefore, I can't see it and you can't see it.
-: Right. -: Right?
-: So, the bilateral aspect of each
of those markets. -: Yes, ma'am.
-: Okay, so, as you said at the beginning
that your ICE runs the forward market.
-: We operate a forward market.
There are OTC markets that could be bilateral
that I wouldn't have, you see what I mean?
Like I don't wanna get lost in semantics,
but we operate the transparent forward market.
-: Okay.
So, as we're looking at the transparent forward market
and forward prices, what I'm interested in learning about
and getting some clarification from you is,
obviously, the actions we take
as a Commission impact forward pricing.
JC: Yeah, that's right.
-: And that's really,
as we sort of look forward in implementing SB 3
and all the, you know, knobs, I mentioned yesterday,
and the levers that has SB 3 includes in there,
it's really important to keep in mind
that those actions we take
and even actions this summer impact forward pricing.
And so, actions -: Absolutely.
Would you hit the next slide, please?
-: Or even statements (laughs).
-: So this is what we're talking about.
Here, this is the forward curve,
as we know it for ERCOT north hub yesterday
for the peak part of the curve.
And this is speaking to exactly what you're talking about
and you can see there's a very,
guess what those tall spikes are.
That's summer.
Peter: This is a year? Or what's our timeline here?
JC: Through October of '32 or something.
I apologize for the scale.
Peter: That's 10 years.
Will: that's captured a lot of trades, yeah.
JC: That's right.
So, and this may not actually be trades
because we're using some math to say, okay, well,
I had a trade in '24 and a trade in '26,
so I can make a good guess about '25.
Does that make sense?
-: Yep. -: So what, okay,
so what time period,
I guess, for purposes of a timeline, obviously, what the,
if we take actions this fall,
that will impact forward pricing for next summer.
-: Yeah. -: Right?
So, leading up to the pricing this summer,
obviously, there were actions or things that happened
that impacted forward pricing for this summer.
So, what would you say would be ways
that we can positively impact forward pricing?
Because forward pricing is very important
to drive investment.
What are some of the actions you believe are some
of like the zingers that move those prices up, right?
I mean- -: Yeah.
So, I'm not going to speculate on what,
Lori: Not specifics, but like,
JC: Right.
I mean, look, -: Not specific numbers.
JC: Our job is to not have an opinion.
Right? And I don't.
So I guess I have some bias
because I know what leads to more transactions typically.
So, I like a little volatility, right?
That we are a company that makes money on the trading.
And so, when people are doing all this hedging,
that's how we make money.
So, if the market's perfectly flat forever
and ever, and ever, I'm not going to have a business.
But that doesn't mean that's not the most utility
for us as a society.
So, if that's what happens, that's what happens.
That's fine.
But in this particular case,
it's difficult for me to point to any one thing and say,
"Well, if you take this action,
"I'll see these peaks shave off by 30%."
I can't really give you that. Right?
Because it's a complex system.
I think what you guys can do,
and you're going to have people who are way better experts
in cause and effect on actual generation and the prices
and what happens to the customer.
You're going to have better experts than me.
I'm, I am loosely an expert on markets. Okay?
So, I can tell you that the reason those are higher
in those things is
because there's more people willing to buy.
-: So, -: And I know it sounds silly,
but there's more buyers than sellers
and that's why it went up.
-: Okay, so when I hear from the stakeholder community,
that what we did just killed the ICE market,
tell me what that means.
-: I think what they mean is the volatility got so high.
The price got so high, $9,000 for four days. Okay?
Normally being 40 or $50,
recall I have to collect initial margin
from customers in order to protect myself in the event
that there are crazy price moves
or large price moves, whatever you want to say.
I got to stop using crazy. Large price moves.
So, when we see sustained $9,000,
I now have to factor in the reality of $9,000
into my risk model.
Meaning that, whereas, say on February 5th, maybe I assumed
that there was a 0.01% chance the price could be $9,000.
It just doesn't happen very often.
It happens for a couple hours each summer.
And the market absorbs that.
It's not that really a big deal,
but now all of a sudden, I've had $9,000
for four and a half days.
So, now instead of being 0.01,
maybe there's a 1% or 2% chance the price can be nine.
That changes the amount of collateral I need
to require from my customers.
Similarly, it should change the math
that ERCOT needs to collect more collateral
from their customers as well, same idea.
And so, when they say "Killed the market,"
that's very generic.
So, it could mean a variety of things.
And I'm sorry this is so long winded.
-: It's okay. -: But one,
I assume they're saying
that the market got a little less liquid
and the reason it got a little less liquid, in my opinion,
is because margins were so high
that to trade a 50 megawatt hour hedge might cost you
a million dollars in collateral,
but that million dollars represented $800 per megawatt hour
of price risk.
Well, that's not even 9,000, right?
So, imagine if I had to set the margin at 9,000
and collect $7 million
or something on that order for a 50 mega,
the market would have really stopped trading at that point.
So, I think what they mean, my best guess,
and I don't know who you were speaking to.
I'm sorry.
Is that just that with those prices being at 9,000,
it meant that ICE, and by the way,
the gas side too, gas went to 1,200 at a point in Oklahoma
and 900 in a couple of places in Texas,
we had to significantly raise our collateral requirement
and that's cash.
And that's cash that these companies have to come up with
in order to stay sorta,
instead of to stay out of default, right?
But that also means
that where my collateral requirement say,
went from 100 million to 2 billion,
that reduces my ability to hedge the next contract.
Does that make sense?
Because I need to,
I have to come up with more cash to participate more.
So, it took about two months
of operating before the risk model,
and I don't know about ERCOT's, but certainly for our model,
which we cleverly called the ICE Risk Model.
So IRM, it takes about two months for big spikes like that
to sort of decay enough
that margins start to return to a normal level.
Now, you asked an interesting question about what can we do
that changes what will happen on the forward curve?
One of the things I found most fascinating
and I learned a lot during Uri was
about the pool for $9,000.
I actually didn't know
because I don't think we hit it very often before.
So, when $9,000 was sustained for four days,
what we saw is the value, the forward value of summer,
the July and August contract drifted from $87 down
to about $65
in the midst of all time record prices,
the summer, in my brain, should also be going up.
Whoa, look what's possible.
But you have to recall that now,
because we've used all those funds,
the cap is $2,000 for the rest of the year.
So, the maximum price this summer is now only $2,000.
Now, that's, you got a knock on effect.
It means that this summer, the most I can collect is $2,000.
But going back to the chairman's earlier question,
is how do I incentivize generators
to participate in this market?
Some generators have now missed out on the opportunity
to collect on those higher prices at different times
for the rest of the year.
-: I see.
So, because of the sustained impact
of the $9,000 for X amount of days,
it impacted this summer, well, it,
we reached the P and M.
-: That's right. -: That the LCAP kicked in.
We're at 2,000.
So, that impacted, obviously,
the generator's ability that were counting
on making money this summer.
-: That's right.
They may not have been able to run during the winter storm.
And so, they've, for at least a year,
they've lost the ability to capture some of that P and L
that they would have baked
into their financial models, et cetera.
-: Yeah.
Good, good answer.
I know we've got another panel before we get to lunch break.
So, I don't want to burden you with too many more questions,
but please keep going.
-: No, this was really the end slide.
I think this is what it's all about, right?
So, everything that,
that Dave and ERCOT have done to build a market that is,
again, frankly, it's very, well-regarded,
one for its amendability.
So, I'm certainly not going to be somebody
to suggest you throw the baby out with the bath water.
I think that's one of the beauties
of the ERCOT is the protocol process.
And you can make changes and revisions
and create better ideas as you learn.
But everything that Dave does and then, you know,
Carrie is sort of here
to make sure we're all doing it the right way.
You know, that the math works the way
that it's designed.
And then we are the outcome of everything
that ERCOT is doing.
So, we are the forward market
and why this is important goes exactly back
to your question, and Madam Commissioner, your question,
which is, how do I get new people to come in and invest?
Whether it's solar or wind or new gas or nuclear,
whatever it is and it's this, right?
So, they come in and they look at this model
and they look at the peaks and valleys
and they figure out the average cost
and they say, "Here's what my inputs are.
"And based on a decision right now today,
"here's what I think I can make over a 10 year period.
"And does that justify my investment in this state?"
And all the knobs you turn will affect this
and it'll affect it pretty quickly, right?
The market is very efficient
and that's something else to remember.
Again, so the second we hit the P and M,
we saw the summer start coming up.
People are smart.
The participants in this market that are trading forward
and managing their risk, they're smart and efficient.
And so, we see those things happen in near realtime.
Information is good these days
and efficient, so, I guess that's, this is it.
That's the sum.
-: Excellent. Thank you very much.
Thank you, all of our panelists,
appreciate your time, information,
and your willingness to field all these questions.
-: Thanks so much to you three for inviting us.
Appreciate it.
-: Next up, we have TAEBA, Pattern Energy,
and Hunt Energy Network.
Yeah.
-: Yes, please, sir.
(door closes)
(microphone shuffles)
-: All right, do we have a,
we've got TAEBA up first.
Do we have a presentation or?
We're working on it.
-: Well, Pat, you wanted to work sessions.
You got work sessions.
-: Oh, it's bringing back all the memories.
-: (laughs) It's good stuff.
-: I know we have physical copies
if you want to go ahead and get started,
Suzanne. -: Okay.
-: And hopefully we'll get the screen working,
but for sake of time,
please feel free to state your name
and who you're with for the record and dive right in.
-: Great. Thank you.
I'm Suzanne Bertin, and I am Managing Director
of Texas Advanced Energy Business Alliance or TAEBA.
And we are a business association
of advanced energy companies,
where advanced energy really represents a wide range
of technologies that are the best technologies
to make the grid more secure,
clean, reliable, and affordable.
So, it's technology such as solar, wind, energy efficiency,
demand response, energy storage,
and electric vehicles and charging equipment,
all the hardware and software
that ties all those systems together.
Next slide, please.
Actually, you can move next one after that.
So, today I want to focus,
I want to take it up a little bit, bigger picture issue
to address specifically distributed energy resources.
You know, historically when we've talked
about this market, we've always kind of focused more
on the supply side of the equation,
big generation, really, you know,
traveling large distances to reach load in across the state
and distributed energy resources are really kind
of the next frontier
that we need to be addressing in ERCOT.
And these are our broad range of technologies,
distributed solar, battery storage, thermal storage.
It could be, you know, onsite,
you know, solar at somebody's house,
connected devices in the home, electric vehicles,
all those kinds of technologies.
And they're, you know, smaller, much faster to market.
They are typically connected at that distribution level.
So, when you think about the overall grid,
ERCOT is really looking
at kind of the bolt transmission system.
And then you get down to the local utility level,
that's where these technologies are, and they could be,
you know, onsite at a home or a business,
or just connected onto the distribution system.
They are also typically two way,
so, they are consuming from the grid,
but also able to inject back onto the system.
They also affect the whole system from, you know, the local,
obviously, the customer has local benefits,
and then they also affect the local distribution system
in terms of they can provide for demand reduction,
also, it affects the overall transmission system,
and then the amount of generation that's needed
on the system.
Wood Mackenzie has, the consulting firm's actually estimated
that cumulative distributed energy resource capacity
in the United States is projected to grow
to an astounding 387 gigawatts by 2025.
Now, Texas, obviously, we're a huge state.
And so, I think some of the numbers I'm going to share
with you a little bit later will bear this out, but,
you know, we should expect that we're going
to be a pretty substantial portion of that.
Next slide, please.
So, just a few principles here.
I think, you know,
when we think about the overall market,
I kinda like to think of it as, you know,
metaphorically like a symphony orchestra that we have here,
Texas has a wide range of technologies that have something
to offer in the market.
And so, you know, whether it's brass, woodwinds,
or percussion, right?
It's all, everybody playing together
that ultimately, you know, delivers the performance
and the ultimate customer experience.
So, the electric system's really no different.
We should be striving to move policies forward that really,
you know, get the best out of the technologies
that we have and take advantage of those benefits
for the benefit of all the, the system and the customers.
So, you know, to that end, you know,
market rules should be maximizing these opportunities
for technologies to provide services
in accordance with the technical capabilities,
but we shouldn't be pitting technologies against each other.
We would recommend the ERCOT, you know,
when it's thinking about ancillary services and potentially,
you know, future ancillary service changes really, you know,
first set clear guidance
for what is the actual service that's needed,
and then develop the qualifications to meet those needs.
And, you know, be really agnostic
as to what kind of technology can provide the service.
Market rule should always foster innovation,
ensuring that we allow a wide range
of business models to participate.
Customers in all customer classes should have opportunities
to participate in wholesale markets,
whether individually or as part of an aggregation,
and they should be compensated for those contributions
that they provide to the market.
You know, we talked, we've talked about how,
you know, there's a lot of emphasis on supply,
but demand is really half the equation.
The part of the problem we had
back in winter storm Uri was just this humongous demand
on the system at a time, you know,
when we didn't have adequate supply and it was just,
it all ties together.
So, it's half the equation.
We need to be addressing the demand side,
as well as the supply side.
Not all of that demand is inelastic.
It's not just a vertical demand curve,
but in fact, some folks are going to be willing
to modify their behavior based on market signals.
If we've got the prices, you know,
the price signals have to be there.
And finally, we should be,
when we're thinking about market rules,
we should really harmonize the retail
and wholesale use cases
to maximize the value to customers
and the system as a whole.
So, what I'm getting at there is, you know,
we've got sort of local value, you know,
I may have at my house, but you know,
the grid could also get value from that.
So, let's make sure that the rules allow
for that to really take place.
Next slide, please.
So, I wanted to just throw out here a couple of use cases
for DER just to kind of help, you know,
paint a picture for what the opportunity is here.
So, you know, diving into the first one,
electric school buses, you can also think of this
as a kind of more frequently dispatched DER.
And so, the distinction there is really kind of compared
to old school demand response, right?
Where, you know, maybe it just gets dispatched once a year.
So, the distinction here is electric school buses could be
dispatched much more frequently, like, you know,
it's battery storage.
And so, you know, as battery costs are declining,
we're going to see, more adoption
of these electric school buses.
By way of example, up in Maryland,
Montgomery County has just entered into a contract
for 1,400 electric school buses.
As you can see here, you know,
there are 480,000 school buses
that are on the road in the U.S.
We are the number one state
with more than 10% of the school buses
that are on the road.
So, you know, that gives you a feel
for like how much DER potential there really is here.
Everman ISD, up in Fort Worth,
has purchased some electric school buses.
They're piloting it, very excited about what they're seeing
in terms of the value to the school district.
But, you know, right now,
they're not able to deliver that value back
to the rest of the grid that would benefit all of us.
So, you know, the thing about school buses
in particular is that,
you know, they'll transport students.
And then once those school routes are done, you know,
it's late afternoon, evening.
That is a prime time, especially on summer afternoons,
when, you know, maybe they haven't had to do a run at all.
They're just a resource waiting to be tapped into, you know,
to address those peak demand situations that we run into
when we hit those $9,000 prices.
So, a good opportunity there,
let's move, next slide (coughs).
I won't go over all of this in detail,
but 'cause I know we're short on time,
but essentially, this is just demonstrating that, you know,
when we refer to retail services here,
you can think of it as that kind of local,
it could be a benefit to the customer themselves,
or it could be also a value
to the local distribution utility.
Y'all will recall
that the legislature passed SB 415 this session,
which would allow for battery storage in particular
to be used to avoid
or defer distribution system investments.
So, that's the kind of value that we're talking about here.
So, historically, you know, we've had,
demand response that's kind of, you know,
it's really a reduction in load, right?
But where we can take this going forward is to really think
about it more as a virtual power plant,
being able to aggregate, you know,
across the system or in a, you know, a local area,
multiple assets, and then,
and have those multiple assets deliver back to the system.
That is a significant opportunity that is still untapped.
Let's move to the next slide, please.
Another use case,
this is behind the meter solar plus storage,
or you could have individual just,
you could have just storage,
whether that's like a Tesla power wall, for example,
or if it's a electric vehicle at the home.
There, this is an area where, you know,
there's definitely increasing interest
in this kind of local solution.
I mean, you heard stories
actually back during the winter storm of folks
who had a solar plus storage solution at their homes
and they were able to stay up and running for multiple days.
Yeah, so there you go, Pat would.
Even while the whole neighborhood was out. Right?
So, I think based on that experience,
we would expect an increase in interest from customers
in investing in these and, you know,
similar to the school bus example,
EV penetration, also going to be increasing.
You've probably seen the advertisements
from Ford on their F-150.
They are explicitly marketing it
as a backup power solution for folks' homes.
So, these are, this is another one where, you know,
we'll be able to have these solar plus storage systems
that right now,
they are simply just providing these local solutions,
but we should affirmatively work to have them be injecting
into the system in these, you know, these aggregations of,
you know, as this virtual power plant concept.
Next slide, please.
So, again, just you know,
some of the examples again,
when we think about the retail services,
I mean, local or some value potentially
to a local distribution company,
and then, you know, on the wholesale side,
there's all those, you know,
variety of services that could be provided.
When you get down to customers,
like particularly residential customers,
you know, we'll need to think about how does it work
also from those retail types of rules
and making sure that it's not overly complex
for customers to be able to participate in markets.
In some cases, you know,
it may be a rep or a third party provider
that will likely take care of a lot of, you know,
take away that friction from customers, but, you know,
there could be a variety of business models that really,
you know, bring that home.
So, when we're thinking about the kinds of market barriers
that, you know, need to be considered,
and as ancillary services continue to be modified over time,
historically, one of the things
that's come up over and over is really trying
to strike the right balance between what is the data
or transparency that ERCOT may need
to have an idea of what's going on with a resource, but,
you know, if they put too many requirements on,
in terms of telemetry and, you know, data requirements,
it can become too costly for somebody to be able
to justify going down that path.
So, we need to just be mindful of that.
And, you know, only again,
sort of think about what do you really need?
And then, you know, address that,
just exactly what you need and nothing more,
otherwise it just becomes cost prohibitive.
So, these are just a couple of examples
that I've put forth just to give an idea
of where DERs could go.
But I just wanted to mention that, in 2019,
we Commissioned a study from a consulting firm
that has expertise in distributed energy resources
and valuing them.
And we asked them to answer the question,
how much money is left on the table in Texas,
if these DERs that are out there already
on the system can't be integrated fully?
And what they came back with was, you know,
just the 1,000, you know,
1,000 megawatts that's out there right now already on homes,
that it's a $5.47 billion value over 10 years
from part of it being wholesale market value,
about $3 plus billion on wholesale market value,
being able to inject in those high price times,
and then another, roughly $2.5 billion
in terms of those non-wire solutions deferring
or avoiding local distribution costs.
And that data that was used to put together that study was,
you know, the report was in 2019,
it was before we started hitting all these $9,000 prices
on a more regular basis.
So after winter storm Uri,
I think it is definitely safe to say that the number
that was in that report substantially understates
the value that Texas would gain through DERs.
So, I'll stop there with my opening remarks
and pass it on.
-: Has there been any analysis done on, again,
what your technologies,
your suite of technologies bring to the table is the ability
to concentrate distributed generation and aggregate it
in clusters around the state
and throw an immense amount of power back onto the wires.
Now, again, this is going to be coming
from a series of neighborhoods
and facilities that traditionally have been net,
they suck power, you know,
to kind of copy an old Navy engineer I once heard
about this, I mean,
they're constantly pulling power off the system, but again,
the transmission infrastructure around those areas,
it's not a, I mean, this is a distribution system as well.
And so, it's not wired like the industrials, you know,
refineries, it's not wired like a power plant,
so, it's not a net off-taker right
from the transmission system right there.
So, have we done some analysis on what we need
to be considering moving forward
in our transmission and distribution planning
to account for this type of resource
and in these different parts of the state?
What do we need to be accounting for
at the Commission level?
And then there's the cost, you know, which is always there.
So, Katie'll get up and talk about all that in a minute,
but what analysis has been done?
-: So, I'm not aware of a, you know,
specific analysis looking at, you know,
what does Texas need to do?
-: If everybody throws their Ford F-150s in my neighborhood,
in Cedar Park onto the grid.
-: Right. -: At, so, you know,
Cedar Park's not accustomed to that.
-: Well, the individual distribution utilities are
always looking at this.
They're, you know, they're looking five, 10 years out.
And then they're also looking, you know,
a more granular level at, you know,
one year out, for example.
But I would suggest that the Commission would,
we would all benefit if perhaps through the implementation
of SB 415, when you start looking at, you know,
how do non-wire solutions, you know,
how are they brought into the,
that distribution planning process?
You know, having some additional transparency
around what that process is,
and then how distribution or DER providers, you know,
can contribute to that because you can, you know,
you could have a situation where maybe people cluster
or the assets cluster in one place,
but if you've got the right price signals
and information on where would it be most advantageous
to the utility in terms of, you know,
reducing sort of local congestion, if you will,
or local capacity constraints
that the distribution utility has, it,
these are all technologies that provide a benefit
to utility, you know, if we do it right.
So, that's what I would suggest is
that we should definitely have a more transparent process.
Right now, it's just a black box.
Utilities do their thing.
In terms of distribution planning,
everybody else doesn't really have any insight
into what that is, what the, you know,
where the most advantageous places would be
for these resources to locate.
-: But given what you're seeing in terms of your group
and the technologies that are coming on,
it seems like DER could be a ubiquitous source
of power production in the very near future.
And currently, the ERCOT planning process does not drill
down to that degree of specificity to include that,
for us, with the TDUs for our approval
and rate cases or anything else at the wholesale level.
-: Right, I mean, ERCOT,
they look at transmission, right?
And so, there's kind of like almost a line,
like beyond that line,
it's the local distribution utilities
and only they would,
only they know what's going on in their specific areas.
Like I said, it's like a black box to everybody else.
Will: Okay.
-: So, just to kind of dovetail from Will.
So, I think, you know,
what you're generally saying is there's definitely a lot
of potential on the demand side of the equation
with demand response
and distributed energy resources and DG
and ERCOT right now doesn't have, well,
it doesn't have visibility into the distribution network.
They operate at the high level, transmission line level.
And while ERCOT has taken a lot of steps to integrate,
register and integrate DERs into the market
this last year,
there's still some actions that could be taken
to further integrate these resources
and capture value from these resources in the future.
You know, I, there's been a lot of discussion on,
you know, or observations that consumers should be paid
for conserving energy,
your demand response, like other loads.
That's something that I think, you know,
has gotten a lot of attention.
And, you know, one thing that I think,
you know, 'cause I've been sort of thinking
about these issues,
you know, how do we,
how does ERCOT gain more visibility
into the distribution network?
I mean, right now,
they have, for what I understand,
only 100 megawatts of solar DG on the system.
There's about 550 megawatts of storage
and with like maybe about 1,700 in the queue.
So, we are seeing increase, right?
But not a tremendous explosion to warrant,
perhaps, the distribution ISO model that would have like,
you know, little mini ISOs throughout the state
that would be on the distribution network
to feed ERCOT that information.
So right now, we largely rely
on the distribution service providers
to provide that information to ERCOT,
to be able to garner some of that, you know,
visibility and potential benefits
that we can get from these resources
on the distribution network.
So, that's kind of the way I envision
sort of the way it is right now,
the state of the state of DERs, the actions ERCOT's taken,
the visibility they have,
further, you know, steps that could be taken
to gain visibility.
How can ERCOT get visibility now to kind of, you know,
capture the benefit from these resources?
But then to Will's point about cost,
it's a very valid sort of segue into this.
As, you know, as he was I think saying
that the distribution network is built the way it is
right now, and as you have more and more
of these DERs on the system, you may hear from some
of the distribution service providers state that,
you know, these adding, added costs to the system
and how do we, as a Commission, the back end,
while we want to capture the benefit of DERs,
how do we in the future ensure that when TDUs,
distribution service providers, they come in,
basically for rate cases,
how do we allocate those costs?
Because the distribution service costs are
typically allocated to residential consumers,
small business, I guess.
And so, on the back end, on the cost allocation,
that's the part that, you know,
we need to remain cognizant of
as we have more and more DERs proliferate in the state,
how not only from, you know,
demand side benefit perspective, we can incent,
you know, participation and integration,
but also be mindful of the cost impacts
that these resources will have on the system
and ultimately on consumers.
I mean, I think we sort of alluded to this
in the EV discussion back about two years ago, right?
As you have more EV added to the system,
we certainly want to have, you know,
the technology proliferate in the state,
but as you have more EVs charging stations added
to distribution systems,
then who's going to pay at the end of the day?
So, these are just to kind of,
really, my whole point is, as a Commission,
we've got to look at the broader picture of how do we work
to integrate these technologies
that could be very beneficial,
but also being mindful of any cost impacts down the road
as they come to us in various forums, like rate cases?
-: And here's another thought.
So, you're going to need to go through a queasy kind of
to operate in ERCOT.
Ultimately, once everybody aggregates together,
everybody's Ford F-150
and then you're going to go through
in a competitive area through your retail electric provider.
And so, then NRG or Vistra,
who collectively have 80% of the retail electric market,
70 to 80, then are producing power through their rep
and putting that back on the market
through everybody's Ford F-150s.
In the meantime, they have a generation fleet,
which is under cost pressure from all this stuff.
So yeah,
it's going to brave new world. (Peter speaks indistinctly)
No, that's right.
-: Well, and first of all,
back to Commissioner Cobos' point,
we need to make sure that we all keep in mind
that there are costs and benefits.
So, it's not strictly that these are putting more costs
on the system.
They're also providing benefits
to the system. -: Suzanne, this is
a good thing, don't get me wrong.
-: Yeah. -: You know,
this is a good thing, you have a good thing going.
-: And that's all I'm trying to highlight is
there are costs and benefits. -: Right.
-: And we as a Commission need to be mindful of all of them
while, you know, looking for specific ways
from some of the distribution, the DERs,
on ways that we can, like you suggested,
how can we do that?
How can we fold them in,
these resources into these various markets
in a way that makes sense?
I mean, we certainly want to, you know,
encourage the potential, but as a Commission,
we've got to look at the whole picture
and just wanted to highlight that, in some cases, you know,
in the not too distant future,
we may be hearing from some
of the distribution service providers
as we have a rapid increase or rush from these DERs
that want to connect. -: Right, yeah.
100% and, you know, keep in mind also,
customers are already incurring these costs
on their own dime to put these, you know,
on their rooftops. -: Right, some customers.
-: Yes.
Yeah, so it's, you know,
still a small number relatively, but they're,
you know, incurring those costs
for their own personal resilience and reliability.
And, you know, part of the point is that
that is just an asset that's out there
that's available to us collectively as a,
you know, overall system.
And so we need to make sure
that we're putting the rules in place that would allow
for the system to get the benefit from that too,
which will lower costs for the local distribution utility,
if you do it right.
And we, I mean, the not you directly,
but if we all do it right, and have, you know,
all the transparency we need
and also to Commissioner McAdams' point,
it may be the reps who, you know, do this,
but they're also, you know,
you could have totally different business models.
Will: There could be competition for that.
Absolutely. -: Right.
It's a, you know, there's third party providers.
What you're seeing more is also this kind of energy
as a service as a concept or school bus as a service,
even, where you could have -: Right.
-: Somebody come in and you know,
just sell, you know, school buses, traveling on a route
to a school district.
And then that third party takes care
of all of the technical issues.
-: Oh no, I'm going back to my days when TASB,
Texas Association of School Board had a retail contract,
you know, and stuff like that.
So yeah, oh, it's, -: Right.
So, yeah. -: It's going to be
a brave new world. -: Definitely want to,
you know, allow all of the business models that,
you know, anybody can come up with that,
you know, to be able to participate in the system.
-: I would also highlight for you, Commissioner,
get all these things that we're coming up with right now.
And I've been approached by people asking for clarification
of what we wanted in the non-ERCOT proceeding,
rulemaking, on distributed energy resources.
This is exactly why we need a rulemaking
on the non-ERCOT stuff,
because all these questions, it doesn't matter,
it is beyond jurisdiction.
It's applying inside of ERCOT and outside of ERCOT,
how these things are going to be integrated and paid for,
and the various scenarios that need to be contemplated
a little bit of nuance,
but ultimately, it's a new resource coming onto the system
that is going to be harnessed by either a incumbent utility
and sold elsewhere, but it's very technical
and I am not smart enough to put pen to paper right now,
but ultimately, stakeholders and staff need to start that.
-: Well, the resources are going to be
in distribution system,
whether it's on a utility inside of ERCOT
or outside of ERCOT, right?
So, all I'm really asking is we sort of look,
or I will ask is, as we sort of look into the future
and look at ways to further integrate DER
and capture the value that you help us try
to balance these issues out so that we can do it
in a cost effective, cost equitable way in the future.
And as we're going to hear from the wires companies as well
on their opinions and other consumers, right?
To kind of help us reach that sweet spot
to make it all work, because there are, there is potential,
but we gotta be mindful of cost in the back end,
but I'm confident that we can get somewhere
in that whole discussion that strikes the right balance.
-: Absolutely, and definitely appreciate the comment about,
it's not just ERCOT, it's also non-ERCOT utilities,
whether they're integrated or, you know, separated,
like we've got in ERCOT.
And in fact, you know,
the Federal Energy Regulatory Commission has issued
Order 2222 that mandates that, you know,
MISO, SPP, and the other regional grids
that are outside of ERCOT
actually take specific steps forward
to integrate these DERs.
So, you know, it's happening everywhere.
And so, I appreciate the, the, you know, considering,
we need to consider the whole state, and not just ERCOT.
-: Well put. All right, thank you, Suzanne.
Next up, Pattern Energy.
-: Hi. Good afternoon, Commissioners.
I don't have any presentation material.
So, I'm just going to go on my script right here,
but the conversation this morning has been evolving.
So, I'm going to try
to work with the points as we go through.
My name is Kara Beckmann and I'm the Director
of Regulatory Compliance and Energy Policy Design
for Pattern Energy.
Pattern is one
of the world's largest private renewable energy companies
with operating development footprints
in the U.S, Canada, and Japan.
Our headquarters of operations are here in Houston
and Pattern currently operates about one gig of wind
in the ERCOT market
and is a member of the Independent Generators Segment.
As this is my first time in front of you all,
a little bit about me, I have about over 10 years
of experience in the power sector.
I began on the retail electric provider side
and joined the renewable movement in 2019.
My materials are going to be kind of focused
on ancillary services for now,
but they may take a little evolution on that.
According to the ERCOT protocols, as we heard today,
AS is that service as necessary to support the transmission
of energy to loads while maintaining reliable operations.
You know, ERCOT procures AS products
in an array of fashion and Pattern at this time is,
you know, supportive of all different products
and in order for all market participants
to actively participate in the AS market.
As the current fuel mix evolves,
ancillary services becomes even more endemic.
We want to keep those technological advancements neutral
and ask the Commission and ERCOT to respect the neutrality
of the evolving fuel mix as we move forward.
In regards to cost distribution on ancillary services,
Pattern believes those costs distribution
of ancillaries should maintain and stay with load.
We ask the Commission to be cautious
in changing this distribution as AS, we,
we ask the Commission to be cautious
in changing any distribution of ancillary services
to any specific generation source
in order to maintain cost causation principles
and avoid any discriminatory or preferential treatment
by fuel type.
Pattern believes all market participants should be able
to participate in the ancillary market.
Wind assets intrinsically provide ancillary support
even if we do not bid into a product.
During the interconnection process,
wind assets are obligated to respond
with primary frequency responses, voltage support,
per ERCOT parameters.
Before we get part three ERCOT testing,
and to be able to go operational, our control centers have
to provide these immediate frequency and voltage support
as the evolving mix changes minute by minute.
I've even heard of some renewable companies able
to participate in the reg up product,
and we hope and maintain that that's as an opportunity
for future renewable development.
Lastly, it would be remiss if I don't mention,
there's been a lot of activity at the TAC yesterday morning
and the day prior on the additional conservative approach
on managing load solar and wind forecast variability
by ERCOT, it's a very thankless job.
And so, myself and everyone in this room are thankful
for ERCOT's participation
as we kind of navigate this summer.
Due to the lost generation capacity
from outages and forecast uncertainty,
it seems that the new increasing responsive reserve
and non-spin will be able to balance those changes.
Pattern would like
to see ERCOT develop a little bit more accurate planning
and forecast methodology that was used earlier.
There are times, especially in the valley
or in the panhandle, where there is generation
that is curtailed at the bind
at the generic transmission limit.
At this point of time, ERCOT at times cannot,
or does not adequately plan
that this production is not available
to be provided at the grid.
We also look forward to the conversation
about economic criteria to be used
with transmission development
in order to maximize all possible output
to our constituents.
With the lack of transmission, specifically in the West,
we are limited to provide any congestion assistance
or any load assistance while congestion still exists.
In closing, Pattern would like to continue to participate
in any subsequent workshops
and provide more data as the questions arise.
And I'll stop there if there are any questions.
-: Thank you. Questions?
The one quick question, we're still tight on time.
You mentioned the,
one of your requests was about the planning for,
or improved planning
on intermittent contribution to inter-generation.
What, in your mind, what would that look like?
Because you, and you mentioned that the shortages,
the thermal outages, forced outages,
that have been the topic
of such discussion in the last few weeks.
When it comes to intermittence, love the price point.
Kara: Right.
-: But the same time we had those forced outages,
we had 3,000 of 25,000 total installed wind megawatts online
when we really, really needed them.
Those are, you know, it was,
that was one of three variables.
I want to be very clear, forced outages,
lack of wind and then the record demand that day.
So how does improved planning help resolve that?
-: Yeah, from a forecast methodology perspective,
when we're part of the interconnection process
to even be able to serve customers or the market,
we have met towers that are constructed.
And so, telemetry is tested in order
that ERCOT has a direct line of sight
of the forecast of available wind.
And so, how ERCOT uses that forecast,
I'm not very well briefed on it
and nor do I think there's a lot of transparency on that.
When it comes to wind changes, you know,
none of us have the crystal ball and, you know,
things of that nature can happen pretty rapidly.
For wind, it's extremely rare.
You know, with Uri, two days prior,
I mean, I think we already knew the impact
to wind in that area.
And so, I think if there was a more, perhaps,
transparent planning process that we knew
that the wind was going to be offline,
it didn't become offline in a couple hours.
There could be some contingencies planned on that.
I know there's a weatherization docket,
that's open with public utility Commission.
I think there's a lot of availability there. You know?
Part of a compliance team,
we always look at our assets yearly,
actually twice a year in ERCOT,
in June and in September for summer and winter.
And so, there's different, definitely some best practices
that could be used for additional availability, but.
-: Okay. We'd love to hear about that in more detail.
I don't want to belabor the point and I will,
we've had some work session discussions about planning
and forecasting at ERCOT.
So, we'll revisit that,
and certainly room for improvement.
My analogy was skydiving.
You know, statistics only work over infinite iterations,
but we can only get the grid wrong once.
And, but the point I would drive to as to,
for all of us to try to capture the good parts,
the price point, that, I mean,
that is a tremendous benefit while also figuring out a way,
you heard me mentioned how the uniform price clearing means
that the negative prices at night force dispatchable
to pay a penalty for, essentially, being dispatchable.
So, to your point about agnostic about technologies,
how do we find a way
to capture the positives of intermittence
while mitigating the pain points
of the price penalties incurred on others,
and also having 12% of your capacity show up randomly
and with, acknowledge, a full nod
to the lack of predictability,
but the difficulties planning.
So, striking that balance,
I think, will be the key going forward.
-: Yeah. Sure. -: I look forward to working
with you on it.
-: Just one point on the negative pricing with the PTC.
I mean, I think that's what your,
what you guys have been describing it,
I mean, it's endemic, right?
We want to incentivize more of that base low gen
to cover that intermittency.
And I think myself and Pattern would agree with that.
With the PTC, just, it does drop off after 10 years,
and that's not going to help depending on
when the asset was created.
But theoretically in a set kind of zone where you have,
you know, a lot of wind operators in that area
and depending on when they went live will depend on how long
that negative pricing is there.
-: But yeah, point of clarification on that.
I'm hearing from the developers now
that if you refit those facilities, those qualify for PTC.
So the tail, and when I was working for legislators,
we always said, "Okay, 2029.
"If we can get through 2029, we're okay.
"PTC's not effective."
That is not the case. -: No, that's fair, sir.
-: Yeah, that is not the case. -: Yeah, the retrofitting is-
-: We are looking at decades more
of PTC dictated policy constraints.
-: Yeah. -: Right? Okay.
-: I think that's right. -: I mean, it has survived
a lot of different administrations,
so it doesn't seem to be going away.
Kara: Right.
-: It's a big challenge
that holds both difficulties and opportunities.
-: Yeah.
-: Thank you.
Kara: Thank you.
-: Last and certainly not least,
Hunt Energy Network, Mr. Wood.
-: So y'all are getting in about five hours
what took me 10 years to get, so congratulations.
Thank you, and God bless you. (group laughs)
Wholesale market design is not as complicated
as you'd think.
I mean, it's gotten a lot of accoutrements over the years,
but when we decided the wholesale market design for ERCOT,
people think there was this vote and all,
but it just kind of, it just was there,
you had energies and reserves,
which now we call ancillary services and that's it.
So, this whole construct of capacity markets
and all that kind of grew out
of what happened outside ERCOT.
And I have viewed that the East Coast capacity markets,
which I know have been cast about here
in kind of the macro ancillary service debate.
Those really were the 20th century kind of regulatory tool
to really plug the gap for an insufficient
and competitive retail market design in the Mid-Atlantic
and the Northeastern states.
So, whenever y'all talk about capacity market,
I'd be happy to come visit about that one,
because there are some things about it.
I'm not reflexively against it,
my friend Katie's back there.
She'll give you an earful. -: Nervous, Pat (laughs).
-: But you know, I don't really think it's,
you know, I think most of us agree
that wouldn't have changed things in February.
So, but it could change some other things.
But, and when I think about the future
and that's really what that Section 18,
which I think is the, to me, the gem of Senate Bill 3.
There's some other great stuff in there,
but that one really just was a forward lane
about how we make sure that we fix things
that happened in February.
And y'all got wonderful tools to do that.
And I'm thrilled about that.
But more importantly,
this grid is shifting faster than probably any grid
in the world.
Moving with, we have free resources
that the good Lord gave us, blowing and shining on us.
In addition to all this stuff we've been able
to pull up from under the ground and monetize that.
There's not a state like this.
And so, we've got to get this right.
Unlike the past, when, you know,
I got to look at other things
and watch the some pioneers get shot,
so I could be a settler and go get the land.
We figured that out from looking at the UK,
from looking at Pennsylvania, from looking at California,
from looking at New South Wales, you know,
all of these great places, even Chile down there.
Here, we've got to figure this stuff out first.
So, the future scenario that I think about when I think
about what y'all have got before you is 20-blah-blah-blah,
30 something, 80% of the hours of the year,
you're going to have nuke, wind,
and solar setting the energy price.
So, it's this big or maybe negative
in light of our last discussion.
Wow.
So, that great energy market
that we're just counting on energy and ancillaries
to be cashflow for investors here gets shifted
to the other 20% of the hours.
So, the great thing is the 80%, you've got low carbon,
Texas is the hero to the environmental movement,
customers are benefiting from that really low price,
as we have really for the last 10 years,
but that other 20% is going to be really spiky
and really pricey.
And you're going to be depending
on these dispatchable resources,
that section 18, to make the math work.
And so, those units that used to run, I don't know,
60% of the time, CCCTs that came in here when I was here
and it was 60, 70% of the hours.
And now they're down below 40.
How do we keep those employees there,
those plants maintained, that fuel, you know,
lined up with firm contracts?
So, they don't get interrupted in February again.
That's I think going to have to require a different type
of compensation mechanism
and I don't run right to PJM's capacity market.
You know, we've heard some good ideas here today,
and other people here in the room are going
to have some other ones,
but a resource adequacy percentage,
much like they have used in California
or in the Southwest power pool,
some of the regulated states,
a more surgical ancillary service,
ORDC was the political compromise
for not doing a capacity market in 2013.
We can slice it any other way,
but that's what it was.
Bill Hogan, who I respect, who's a wonderful economist,
that I'd encourage you all to get to know him.
He was a great advisor to me here and also at FERC
on market design, the ORDC was the,
my back tool, because FERC could not order capacity markets.
They were brought to us by market participants
And so, the tool that I did have,
if I ever needed to do something
like a capacity market was in ORDC,
which is kind of paying capacity premiums in realtime,
as you saw beautifully illustrated here today.
I'm expecting, I don't know,
I've just heard from market participants whispering to me
that maybe that gets squashed down and flattened out.
So, maybe that helps in those 20% of the hours is
that those 20% of the hours all have an adder on them,
perhaps that is a way to make those more compensatory.
I am going to go find Tommy Merritt's phone number today
because he's the Genesis.
Will: He was the author of that section.
-: Behind point 9044, and I never dreamed in my life
I would ever see that again until this morning,
I had to look it up, and that was it.
Tommy Merritt is this charismatic Republican legislator
from, I think, Kilgore.
Will: That's right.
-: Who saw all the renewable portfolio language going
in right above that in the statute and said,
"Well, I'm gonna do one for natural gas."
'Cause he's sitting on top of the East Texas field.
And that's a remarkable tool because I don't sense
that we'll see any more coal plants here.
And so, when you think dispatchable resources
in the context of Texas,
you may just have a solution to some,
I hate to use the phrase 'cause it's so pejorative,
but the missing money issue that we've got to think about
for those 20% of the hours.
So, bravo on that, Commissioner McAdams,
I think that could be a lot of fun.
I'm also mindful of the importance
of a competitive retail market.
The Energy Monger discussion
y'all just had was very sobering.
And I may be, probably, your own only testifier
in this calendar year to mourn the passing of Griddy,
but I do think price responsive load is
absolutely our silver bullet here, you know,
storage plus price responsive load is that missing interface
that we never had in this very supply-driven market.
But the point of 1999 legislation was
to shift the risk off the back of customers
onto those providers who can better manage that risk.
They're supposed to.
And the operations in February,
particularly the after the fact ancillary service bills,
which we're focusing on here today that came
and I think may have been addressed partially
by the clawing back and the securitization
of those over the market, which is, you know,
a substandard approach,
but certainly, better than seeing those people go out.
But that shows the limits
of how reasonable this market is.
There is, there's probably too much systemic market risk
in the current design.
And as it goes forward,
I think you can, protecting the wholesale market,
but this is the beauty of what your job is,
is you've got wholesale and retail,
which no other regulator in this continent has.
So, you get the ability to see both sides of the puzzle
and to put together those pieces and make them work
for the retail competition
as well as the wholesale competition is an important piece.
So, that wake up call this morning,
forced me to throw away my script
and actually add some thoughts there.
But I should say that it also validates for me the value
of retail competition,
that those resource providers were the ones
who managed the risk, not the backs of the customer,
who in the regulated parts of the state,
and in gas utility land are going to be bearing those costs
for 30 years.
So, that's a phenomenal victory
that we should all take the chance to celebrate,
but it comes at a cost
because there were people who weren't liberated,
who do have a single provider on their back
who was unable to manage it.
But again, stepping back,
I don't know if anybody could have managed it.
And so, how do you reduce the risk?
Certainly, maybe squishing then spreading that adder,
there's a lot of discussion.
I know there's litigation
on the Commission's February 15th order and the 96 hours
and the Independent Market Monitor's been involved in that,
but increasing ancillary service procurements,
we've seen that happen just this week and it was referred
to here by my co-panelists and by the, I think ERCOT,
Dave might've mentioned that earlier,
but ERCOT took some steps to really broaden that then.
And that is an effective way to, in a second tier manner,
push up that forward curve.
When you see there's more resources being procured
on a non-spin basis, that is saying,
"I want more capacity here now."
It's not a three or four capacity construct
like you have in PJM, but it is, it's our version of that.
And I think those signals are extremely important
and they do fly below the radar.
In fact, when I read about it this week, I'm like,
"Wow, that's big."
I mean, y'all didn't have to order that.
I would stay deeply engaged in that
and have a top staffer here for not just that issue.
I've got a few here that we, we're focused on at HEN,
but in any event that there's a lot there.
The circuit breaker, obviously, if the, you know,
I think there's some legislation to drive that.
Getting more price responsible,
Suzanne talked about it better
than anybody I can imagine in Texas.
So I won't, I'll just say me too on her,
but, you know, and then there's a huge slug
of storage coming.
We want to be part of that.
At HEN, we're putting 10 megawatt batteries at, around it,
substations, distribution side of the substations
around the state.
We expect fully that
that territory that was just being talked about there is,
you know, the next ground
to bring in more resources to the state,
a lot of chance to decentralize resiliency.
As I see, the decarbonization agenda,
it's also joined by the de-centralization agenda.
I think pushing that action beyond the substation
toward the customer meter is a new area.
And as we worry about how to pay for that,
I think about as the TDU,
as the distribution utilities reconfigure their systems,
so that the really fatal issue
of how critical load was managed
during the crisis gets addressed,
that's going to take some money.
And I think that's money as a rate payer,
I'm happy to pay for the,
for CenterPoint to reconfigure its systems
so that they can do more surgical roles.
As they reconfigure though,
that 2D, that two way design that we've got
on the transmission grid
that we so much have on distribution.
Although I did tour CenterPoint a few years ago,
when a visiting dignitary was in Houston,
I got to introduce them to the CenterPoint management.
We toured their new backup station.
They have a station like ERCOT,
the big TDUs do to manage their own systems.
There's a lot of capability there
that was put in with smart meters.
And after smart meters went in,
that I encourage the Commissioners to look at
because there, our utilities here have recovered a lot
of money to do it,
but I think the ones that I've seen
in on course will have done a lot of creative things
that really go in this right direction.
And I think a gentle nudge as opposed to a cudgel is going
to be sufficient to just get where we want to go
on this two-way kind of DER rich Nirvana that, you know,
the Texas was intended to kind of generate
that sort of creativity and entrepreneurialship.
So, I want to see that happen.
And again, at Hunt, we intend to be part of
and right in the middle of that, but it's, you know,
this area's been barely unlocked.
To unlock that, ERCOT has to push into distribution.
I know that makes ERCOT cringe,
that makes the distribution cringe,
but at the end of the day, and Commissioner Cobos,
you mentioned about the DISOs.
I think we could probably do something simpler than that,
but I think that's the model.
I think you're right.
What, when 20 years ago,
we wanted to turn the transmission utilities
into a very customer focused,
to both generators and to retailers,
very customer focused business.
And I remember the day after the cut-over happened,
generators came to me and said,
"H L and P is like a new animal.
"They are so happy with the generators.
"We are their customer.
"They're making us deals, you know,
"getting us set up for things that we've fought them
"for 20 years.
"We just can't believe it."
I said, "When you change the business model
"and make the incentives great,
"that's what needs to happen."
I mean, distribution,
I think the legislature said, "You guys are not in storage.
"That's a competitive environment."
We, if it can replace, as Suzanne point out,
if it can replace
and be a cheaper alternative to wires business,
we want it in the mix,
which a great balanced, compromise that I totally support.
But if getting the wires businesses into that same,
you know, viewing us as a storage company or, you know,
as a solar, a community solar farm,
or as an aggregation of Ford F-150s in the neighborhood,
those parties that are going to do that,
and we fully intend to be right in the middle
of all of that mix too,
to know that the utilities viewing us
as happy to be a customer, not to be an annoyance is,
I mean, I had to, one of our meetings,
we had to introduce the distribution staff of a utility
to their transmission staff.
They were separate people and they're separate businesses.
And I think that's kind of got
to be a history book kind of thing.
We've got to move on from that.
And so, ERCOT's already easing into
that role in distribution
by now implementing what were policies made nine years ago
at this Commission on storage,
implementing those at the distribution level
with the distribution generation resource,
which we're firmly involved in and some
of our other storage competitor friends are doing as well.
Other distributed energy resources that Suzanne mentioned,
those are next.
And they're really right on the cusp.
Onto some specific issues, I did leave a,
I did have a deck here and I don't want to project it
because I've only got a short amount of time,
but I do want to, I don't want to give them short shrift,
but I do want to let y'all know that, you know,
we and others are firmly engaged at the working groups
under TAC and the wholesale market working group
to learn from the February event
and make sure that resources
in the ancillary service stack are properly allocated,
you know, batteries should be your last line of defense
for frequency excursions.
You know, we're short in duration,
but lightning fast.
I mean, it used to be hydro electricity was the way
to kind of be immediate.
That's a 12 second response time.
We're a quarter of a second and going toward milliseconds
as the technology gets better.
So, that resource, is it appropriately valued?
Well, I mean, they indicated here in 2019 that
that FFR class was created for fast frequency response.
We're in that.
That class probably able to be bigger
because if you trip a unit here in ERCOT,
there's a substantial response.
In the past, that's what we call inertia.
And it took me years to figure that out.
So, I'm gonna try it real quick.
You've got a generator and three turbines,
say on a CCCT, and they're just spinning like this.
The gas is turned, is burning, the,
or heating the water into steam.
And it's turning those four pieces of equipment,
three turbines and one generator multiple times.
And so, when they take the foot off the gas,
it's just like a car.
Those things still keep rolling.
So, when that, when they've hit the 60 Hertz frequency,
that mass is still spinning,
but we're not adding to it.
Well, that inertia just keeps on going.
And then it basically would fade out if you were not to run
that gas plant.
That inertia has value to the system
that it's uncompensated,
but it's just part of the way it is
because that's just history.
Wind has that, has a little bit, they're a little more low,
but, you know, solvers' inverter based.
So, it doesn't have that at all.
And that's a plus and a minus.
But for returning system to frequency, which again,
keeping it at 60,
as we all know from that wonderful night, that heroic story,
I should say, it scared the bejesus out of me,
but that was a very illustrative event for all of us
to learn from on frequency.
But batteries can be very valuable to that.
Up to now, recently,
batteries have just been pulled out to be energy just
to kind of plug the hole.
I think it's actually, it's tough,
but that, and I mentioned this in the document,
but it probably better to call for another 100 megawatts
of load curtailments than to pirate energy from a battery
in the middle of another February 15th,
because the consequences of that,
I'm a black start missionary,
but having lived through the 2003 blackout
as FERC chair in Ohio,
it went out, it wasn't a controlled outage.
We, this is not a blackout.
And I know y'all are very mindful of that.
This was controlled outages. Dramatic?
Yes, but we did not lose the grid.
If we lose the ERCOT grid, it is stone age.
I mean, it is really,
we are not like Ohio connected to Illinois and Michigan
and Ontario and West Virginia to kind of pull us back up
and get on the horse again.
We got to start from, you know, flint and, what's?
Flint and whatever? At the campfire.
I'm forgetting my Boy Scout days,
but starting from really just scratch
to build the grid back up and match load
and generation all the way back up to 70 gigs,
that's a multi-week event.
So, we cannot have that.
So, keeping the resources that are valuable and that's,
and again, batteries provide that for the grid,
through the ancillary services market and through the suite
of services that are offered there.
ERCOT is getting an earful from us
about what we think they ought to do.
And I've attached that to you.
And again, just ask, in the interest of,
I guess self-interest of getting to a good place
that we think is in the public interest,
but also, certainly benefits the battery business is
that you just keep a supportive push
on the folks over at ERCOT to continue to do that.
When I was in your role,
I really viewed the market participants as the folks
that really got the grunt work done.
But there are going to be times
when there's either a bias against technology
or against a company or against a market segment
that the Commissioners have to get involved in.
And then the other big batch of thing,
and this was Judy Walsh said,
"Look, if you're picking on somebody,
"something or some stuff, we want to hear about it.
"And if it's a money issue, we'll resolve it for you
"so y'all don't have to get twisted around the axle on that,
"but y'all go figure out all the details."
And so, that's really a great balance for ERCOT still.
The market participant process is probably better here
than anywhere in the country and I've seen them all,
but it's one we ought to build on and keep up.
But again, an active Commission staff presence
by somebody who really gets into the detail
and the nerve, we'd love to keep up
with that person just to let them know what we're up to,
but that would be deeply appreciated
because we're pursuing the items on the page,
the last page of my handout,
there's five items that we're currently pursuing
in front of the dockets down there.
And we look forward to hearing back
from the market participants on all that,
and about how that ought to go.
You know, at the end,
if we could ask for anything from the storage segment,
it's just a better vision, crisper for us,
about how you want to see the grid close to,
the edge of the grid, I think, play out.
We can engage resources and the load,
'cause I think a price responsive load is a key part
of the solution here.
Had we had price responsive load the morning
of February 15th, you know,
I think half of the generation,
we've done some calculations,
the former Commissioners and I.
Half of the gigawatts that were being used
in the demand side there were
to do residential electric heating,
which now we've got 61% of the state being heated
by electricity, which is way,
I mean, it was 10% when I was a kid.
So, it's grown substantially
and that's a big part of what's changed around here,
but there's no price signal when you're paying a flat nine
or 10 cents a kilowatt hour to turn it off
or to turn it way down at two o'clock.
Unless you're a Griddy customer,
then you turned it off and froze to death.
But that was, that was tough.
I would, I'd like to think that in the future,
that price responsive demand would be part of it.
But we also want to recognize that, like energy,
the ancillary services that are provided,
both responsive reserves on down through non-spin
and everything above it,
and that expecting that probably in the future,
we'll see some development of a winter,
maybe a winter price responsive
or winter dependable capacity reserve
that people are required to obtain.
You know, I think ORDC probably does a pretty good job
for summer, we'll see.
And the 2,000 price cap makes me just a touch nervous,
but 'cause I don't think anybody really hit
their peaker net margin based
on reading the publicly traded people's generator things.
But I know we've got one testifying here later,
but that be what it is.
2,000 is well above where the market is today.
And I, well, I think,
knowing that the ancillary services have a value
in that environment, both in the summer and in the winter,
we like locational pricing for those ancillary services.
They may make sense somewhere
that where's congestion around the grid,
just like we have, as was mentioned here,
we got four trading hubs there
and a lot more granular than that.
I mean, as a storage resource, we get nodal pricing,
both selling and buying at the different places
around the grid, wherever we locate.
So, having that for ancillaries as well,
maybe it's complicating,
and maybe why ERCOT throws their hands up because you know,
it's hard enough to run the software with the nodes
that we have, but I'm just saying that's a way
to bring some efficiency to the market.
And again, I just think,
how do we bring load into playing here?
At the end of the day,
we can just have a Commission and an ERCOT that continues
to just figure out how to say, "Yes" to new ideas
and new technology and new innovation.
I think that'll bring the value that we all have hoped
to have in this state for a long, long time.
So, sorry, I ran long, but thank you for the invite.
Good to see y'all and thank you for,
thank you for the job you're doing.
I go home tonight and sleep well,
seeing y'all dive into this stuff so deep and early.
-: Appreciate it, Pat and Suzanne and Kara.
-: Thank you.
-: More the, see the Nirvana language spread further
across there, Pat's Nirvana,
you should spread further across the panel,
but we are at one o'clock.
So, I think let's take a recess.
Does that work for y'all?
-: Yes, sir.
-: Let's do a recess for 30 minutes and we'll reconvene
for the afternoon panels at 1:30.
Kara: Thank you.