-: Afternoon, this meeting of Public Utility Commission
is now back in session.
We'll move on to our ancillary services panel with, Randa,
Sorry, we have our weatherization item.
We're gonna move to and table item four,
moved to item 10 for weatherization
staff is prepared to proposals for publication
for a new rule related to weather emergency preparedness
that we've all familiar with and discussed exhaustively
this proposal relates to one of the Commissions.
Well, whether development standards,
I think we, like I said,
we've all been part of a robust stakeholder process
and lots of discussions.
I'll open up the floor for discussions, questions for staff.
Do we want to call it?
We can call it Barksdale English.
Anyone else from staff who maybe needed,
I've turned over questions, comments,
or we can discuss timing for final adoption
on other a few options there.
Any, questions or comments before we get to the timeline?
You good?
-: I have one item that I need to pull up the hard copy
so I could mention it.
(clears throat)
Specifically, one minute, on page nine of the proposal,
subsection two.
-: Okay.
-: There is a language in there that says
by December 1st, 2021,
a generation entity must submit to ERCOT
a form prescribed by ERCOT and developed
in consultation with Commission staff,
a winter weather readiness report.
I had visited with staff about this during,
when we had an opportunity to review the draft,
a proposal for a publication
and(clears throat) had offered a proposed addition
to this language that would be better
discussed that here in open meetings
and it was a substantive change
and I was interested in hearing your thoughts on whether or
not we should include or require the generation entity to
submit the winter weather readiness report
to the Commission and ERCOT
and I know ERCOT is gonna be providing us a summary report
with a variety of information
regarding the generation entities compliance.
But I do think it's important that to have the generation
entities file the report at the Commission,
because those reports are gonna include the attestations
from the executives with binding authority
and so I think as a matter of ensuring our oversight
over the standards that we have,
that report filed at the Commission and at ERCOT.
So adding language, it says,
submit at the Commission and ERCOT.
-: Good afternoon, Barksdale English
on behalf of Commission staff.
Commissioner Cobos, so I think we can add that language
if that's the direction of the Commission.
-: Yeah, just as simply adding the phrase,
the Commission and to ERCOT and the Commission
form prescribed, et cetera.
-: Yes, a generation entity must submit
to the Commission and ERCOT.
-: On the form prescribed, et cetera, et cetera.
Works for me.
All right, so we'll any motion will be in regards to
the proposal for publication as amended
per Commissioner Cobos.
-: Yes.
-: Request in terms of timing,
I know staff laid out several options.
We obviously, as we've discussed
working on an accelerated timeline,
both to adhere to the legislative deadlines
from the 87th legislature,
but also to make sure that our generation fleet
is more resilient going into this one winter
than it was going into last winter.
Most importantly, as such given the timelines,
the tight timeline and in consideration of make sure
consideration making sure the generators have time
to implement, turn the wrenches
and fastened to bolts on these improvements.
They have time to implement these changes
and these are the weatherization requirements.
We're looking to accelerate a timeline.
If we published the proposal today,
it technically will not appear in the register
until September 10th due to the print timeline of that,
but it will be available online immediately.
So given both the fact that it will be available online
immediately for stakeholders to review, process
and comment on prepare comments on,
and the fact that we've had such a robust
and thorough stakeholder process, both staff-level
and with this Commission,
I'm comfortable moving forward with the date,
the proposed timeline that gives us an effective date
of the rule of November 3rd
would leave a three week comment period
from online posting,
it would only be in the register for six days,
but the public would have a full 21 days to review that.
But I think we'll see in the timeline.
I'm comfortable with that, but it happy
to hear your thoughts otherwise.
-: Mr. Meltzer, does that comply our
statutory and tax obligations on comment period.
-: Davidson Meltzer, Commission staff.
(clears throat)
Yes we believe it does as we've discussed before,
there's not a minimum comment period other than
members of the public
must be given a reasonable opportunity for comment
and so we think that this is after the notice
and the register that should be sufficient
three weeks plus all the process they've gotten before
should be enough and it gives us a little bit of,
we can get it done quickly,
but it gives flexibility before our statutory deadline
if you guys need an extra open meeting
to consider it on the backend or anything like that,
but that is what we have laid out is option one
in the materials we gave to you is statutorily fine
and we're ready to do it, if that's your preference.
-: And they also lines up
with the customary Texas register posting halo.
-: Yes, sir. -: Okay.
-: I agree with the
faster timeline. -: Okay.
-: Good deal.
-: I agree.
-: All right, in that case,
is there a motion to propose new substantive rule 25.55
for publication and public comment
where they comment deadline of September 16th?
-: So move. -: Second.
-: And we've got a motion and a second all in favor, say aye,
-: Aye.
-: Motion passes.
-: And chairman we understand that motion to have included
Commissioner Cobos this direction.
-: Yes.
-: Thank you. -: Thank you
for the clarification.
All right, thank you, gentlemen.
I appreciate the accelerated timeline to get to this point.
I know it's a lot of work in fast maneuver.
-: Happy to do it.
-: That concludes item number 10.
We will go back to item number four and bring up our
ancillary services panel Randa Stephenson from LCRA
Bill Berg Exelon and Scott Gahn from Just energy.
Welcome all.
Randa is up first.
-: All right good afternoon.
I'm Randa Stephenson
and I am the chief commercial officer at LCRA
and one of my responsibilities is portfolio management.
So I did want to just veer off for a minute
to clarify something about unit commitment
and how generators are committed.
In our current operating plan these are obviously plans,
which we make sure our plans are shown as available
and we do these, on a week out basis
and they are updated as soon as possible
from a generation a resource standpoint,
but having a portfolio that you have generation and load,
there's a lot of different things we have to manage
day to day and things that change like the weather,
the wind forecast, gas prices,
these are all things that clear daily
and so the reason you probably,
I understand what he's concerned about,
getting a better understanding of which units would be
committed or not.
Sometimes we just don't have the information
to commit a unit until the day before
and also until the day ahead, market clears,
usually by the time the day ahead market clears,
I then know if it's economical to run my unit
or to buy from the market.
-: As a result of the then.
-: Correct pricing.
Correct exactly. -: Pricing.
-: And so that's one thing to consider
as we look at improvements
is just like ERCOT doesn't have great weather
or wind forecast a week out, neither do generators,
neither do load.
I mean, this is an issue on both of our sides.
So just one point,
and if you all are ever interested in knowing more,
we can talk to you about our real-time operations
and our dispatch floor with the trading group.
So kind of give you a little more detail on that so.
-: Randa on that and it's, thank you for bringing it up
and in terms of the operation of the market
any type of significant change will necessitate
in depth stakeholder review
and to work through those specific nuances
of the market, it's not like it would,
it could happen overnight to a degree that
we change foundational processes within the system.
-: Yes correct.
-: But if, there's gotta be a way to reconcile
Woody's engineering and operational concerns
and that of the market operations,
if it's a matter of building in other more forward-looking
constructs, again the foreign markets,
go out indefinitely before real time.
-: Correct. -: And it's a,
there's got to be a way to establish markers
that ancillary services guide off of,
and then that ERCOT operators can make significant decisions
based on to have adequate resources available in real time
with enough lead time to where
they can evaluate all that information.
Would you disagree with that?
-: No, I agree 100% with you.
I actually think what I'm presenting today
about a dispatchable reliability ancillary service
does just that.
-: Okay.
-: That's the requirement.
It is going to be a forward looking,
seasonal or annual contract
that that generator has to be there for you
and I think that's the key to how we do this other than just
relying on our current market structure that helps.
Okay, I go next slide please.
So I've been here before, and I've talked to you about it
as special reliability service.
I wanna include that it's not just thermal units,
hydro units we have 300 megawatts,
We have storage for three weeks.
We are there.
We were very integrated part of the solution
during the winter storm, batteries is another area.
So it's more than just thermal generation,
when we talk about dispatchable.
Also from fuel ancillary services,
I'm gonna go into a little more detail
about our proposal we'd like to see considered
and all we're trying to do is enhance reliability to again,
incentivize new build
and keep the remaining generation online.
I think that's a very key part.
You got to look at both sides of that equation,
and we have always been supporters
of market-based principles.
So competitive market solutions
that are not regulated solutions.
We think that really is the most efficient market design
and decreases cost to our customers,
the cooperatives and the municipalities.
Next slide.
So I bring this slide up because there's been so much
discussion about all these proposals
to do a rate regulated type solution.
I've been doing this for about 20 years,
and I actually went back to my notes in 2018 and 2019
and we were debating the ORDC and how we change the curve
and moving it one standard deviation or not.
When we were arguing that point,
that was a $70 million annual increase to load.
This proposal right here is at $800 million
increase to load, it is huge.
It's swings the pendulum all the way to the other side.
-: So you said 70 Million increase load
was a pretty one standard deviation move
out of total annual spend.
-: Yes, for increased customer costs by 73 million
by shifting the curve is what the-
-: So 70 Million out of how much total spend was,
that'd be like 10% of.
-: The market's probably $1 billion I mean.
-: But it wasn't it a low,
it was actually a lower amount than otherwise feared
because it based on just the demand of that year,
right due to the load. -: Correct yes.
This was what was planned.
This was what we were debating.
This was not actual, to be honest.
And so we had I think it was Brattle
who did that report for us, but yeah,
I mean, so you can just see the biggest change of money
and if we go with a rate-based solution,
one of the things you have to consider
is what happens to the existing generation
and then what happens to new generation.
As we start to pick folks to get a regulator rate of return,
what it does is we lose scarcity pricing.
So it does put price dampening impacts on increase
for actually current generation to stay online.
But then also for new generation,
they're gonna want rate regulation.
So there's a lot of consequences for this
and I know that there's been a lot of testimony
and debate about this,
I would say to do something like this,
and then do a bandaid to fix the energy only market
that's still left over
is gonna cost you another $800 million.
So now we're looking at $1.6 billion annually
for load costs.
I believe we can do that a lot more efficient
and a lot cheaper by using competitive solutions
in the market, okay and that's next slide, please.
So I've talked about this dispatchable reliability service.
It has to be able to respond 30 minutes,
It has to be in the cap, committed showing it's online
and then provide uninterruptible power
for at least 24 hours.
I think this is really key.
This was a big issue with the fuel supply
and I think that is, should be mandatory to be honest.
We also believe longer term procurement
is good for load and generation.
So we then provide the signals to load that this is an
additional cost that needs to be hedged at a certain price.
-: What kind of quantity of generation would you anticipate?
-: Sure so in our comments,
we talked about using reliability metrics that incentivize a
loss of load that is more bearable or withstandable.
So lately we've had a one in two years loss of load event.
What we're recommending is a one in 10 years
loss of load event.
So what you would do is determine
ERCOT actually has done this study in the past.
We go ahead we determine what that one in 10 year
loss of load is,
we look at what amount of capacity has to be there,
look at the Delta between what you have that's dispatchable
and what you need,
and that would help figure out what that amount should be.
So I think there's more studies to be had
and a lot more discussion with
people that are much brighter than me
and I think we could get to a point that we could determine.
So you're welcome. -: Thank you.
-: I think a lot of folks talked about financial penalties,
If you're not there, we agree, obviously,
making sure the cost of this market base backup service
can be directly assigned
is something that was not only in Senate Bill three,
but I think is fundamental from a load perspective too.
I think any of these solutions we're talking about
are gonna be additional costs to load.
We need to be very cognizant of what those are
and transparent, but I do think that value of backup service
can be computated and we could have a good idea
based off a lot of studies that I've seen done in the past
and then we have to evaluate every year,
this has to be a current, we have to keep going back to see,
is this working?
Is this incentivizing things?
Do we need to adjust?
How do we pivot?
And that's something that hasn't really been done
at the Commission that often
as we put in some of these market design changes.
-: So if you could elaborate on that,
cause it's a very important principle
that was heavily debated in the legislature cost causation.
So in your mind,
how functionally would that be applied
and how broadly, how specific please describe?
-: You gonna get me in trouble,
okay, no, it's truthfully,
I think we need to look at it from a market wide impact.
-: Okay.
-: There's obviously load is variable,
renewables are variable,
really go back and look at what's causing what
I think the ancillary service methodology is a great guide
that talks about why we buy certain ancillary services
and that's a study ERCOT can perform,
I mean, they're doing it already for responsive reserve.
We should be able to do that
for any type of dispatchable reliability service.
-: Do you think this type of service
would have actually helped last February?
-: Absolutely.
-: What part of it would, because obviously?
-: That's 24 hours uninterrupted power.
-: Understood, but also obviously financial penalties
for failure to deliver,
but they may have had gas contracts to deliver
and what happened. -: Well I think
one of the requirements you have to have
is either gas their available storage,
dual fuel capabilities,
so if they did have shortage, they could switch.
So that's one of the biggest pieces
that I think a lot of us face
we're working towards improving that,
but that gas supply is very key or that water supply
or whatever the supply of fuel in that mix has to be there.
-: So that's, what's embedded in the 24 hours
of operating is they have to make the choice as to
how to assure that they show up
with either a dual fuel or some other component
that makes sure that they have the onsite storage
or something that makes sure that they can run for 24 hours.
-: That's correct. -: Okay.
-: I mean and we'll talk about my next idea.
So firming fuel product, right?
So you may not bake in all your costs in this product.
You may be able to recuperate some of your costs
for doing this in affirming field product as well.
-: Do you think that something that would be
like this dispatchable reliability service,
would it be seasonal.
-: It could be, yes.
I think it definitely could be.
I think you're really gonna have to look hourly
of the effective load carrying capacity of a renewables
and really determine and make some studies on what,
I think you've got to do some probabilities and adjust
if we're thinking of a P50, a P75,
a P85 of what that effective load carrying
capacity should be.
It's not just one number we've learned
our lesson is what I feel like,
we have to look at the biggest range
and then determine the right way to go.
-: To your earlier point is dispatchable
is not necessarily not renewable.
-: Correct.
-: And intermittent renewable resources with battery
with compressed air with-
-: Could work exactly.
-: Or that falls in the dispatchable universe.
-: I agree, yes.
-: What would provide more regulatory certainty
making changes to non-spin, the existing non-spin product
or creating a whole new product.
-: I believe because this is gonna be forward-looking
and has to be something
that we give some long-term commitments to
that something like this incentivizes new generation
better than our existing fleet of ancillary services
and I'll talk through building a new peaker
and what we're looking at in a minute.
-: Okay.
-: Thank you. -: Okay.
So firming fuel,
I really believe that a lot of the extreme weather
emergencies could have been somewhat relieved or reduced
based off having different firming fuel capabilities
wouldn't have solved everything by any means,
but we have not been incentivized to have dual fuel storage,
multiple pipeline interconnections,
They're very expensive.
There are two and a half to $5 million
in a market where a generator right now
is just making marginal cost,
it doesn't pay to do that, right?
And so having a process that generators
can competitively bid into
and I believe you're gonna need
to hire some expertise here.
I believe you're gonna need to have
an independent consultant work with ERCOT
who has gas knowledge of how pipelines
and compression stations and everything works
to determine the most cost effective solutions.
I've really, ERCOT has a lot of great expertise,
but understanding how fuel flows and the limitations
and the changing market with LNG and pipeline development,
I mean, you really need an expert on this.
-: Would you include from gas contracts in this?
-: Yeah absolutely yes.
-: Would you distinguish between intrastate or interstate
in that analysis?
-: Its a good question, I don't know.
I think that'd be something that needs to be looked at.
-: All right what are the economics on
on-site fuel storage into a dual capability
or what's ts option? -: Sure.
So they are expensive.
I've just, these are things
that are big capital investments for generators.
Some of us have had dual fuel capabilities
with some of the older units
and reinstating that may not be as costly
as building it new.
So you do have some, I think efficiencies there,
but storage is definitely very costly
and it's very locationally specific
and we do have a storage facility.
It is volcanic and, we're just at the right spot
and we built the plant there,
knowing that we wanted storage,
not all generators have that flexibility,
but I do think looking at variety of options
and whoever knows what's the next new thing
could be something that really just gets us
some fuel certainty throughout the grid.
Okay next slide.
So this is a very, very high level understanding
of how you decide to build a new power plant or not
and I looked at it from 100 megawatt peaker plant,
my team did, and these are the things
and not all-inclusive by any means that we are looking at,
we're really looking at a return of investment
that's greater than my cost of capital investment.
Every person who makes these, I mean, these are,
hundreds of millions of dollars of investments
are going to have to meet some type of hurdle rate
or break even requirement.
If you're a competitive or in the mini-cooperative space,
these are long lived assets, 20, 30 year life
they're capital intensive, like I said,
it's very dependent on future power and gas curves.
We've been talking about this for a long time.
The forward curves are inverted and declining,
so that makes it, and if you see my graph to the right,
that makes the money you make in the future,
it makes your loss larger and larger, right now,
we also looking at fuel supply, environmental regulations,
transmission access, am I gonna be congested or not,
technology selection, tons of other things, water supply,
a lot of other factors,
but this is part of the consideration.
-: Please elaborate on environmental considerations
and do ESG requirements impact your analysis.
-: Yes definitely.
We obviously have a very great and cooperative TCEQ
that has really understood the need for generation
and what we have to provide, but at the EPA right now,
it's a whole different consideration
and Bill is probably better than I am to talk about it,
but there are, it's like death by a million cuts,
I'll just be honest.
It's not a carbon tax,
It is multiple different regulations that will be coming on
coal and gas generation in the future and that risk
and being able to understand it,
monetize it in a way that makes sense is important
when I'm making an investment decision.
'Cause I'll be honest,
when I look forward to gas construction
at a peaker unit that has higher emissions,
that plant may not have a life longer than 10 years,
depending on what happens in a lot of things that
none of us control, elections and directions of the EPA
and the government, federal government.
-: May I ask you, so the Fayette power plant,
which you own was one of the last coal plants
to actually have a environmental enhancement,
meaning scrubbers who invested a significant amount of money
in those scrubbers,
do you think given the current market conditions
and the financial conditions,
you could finance that project today with ESG pressures
within wall street- -: Absolutely not.
-: Okay so for the current fleet,
the one that's in the ground right now
that Woody says we kind of have to maintain,
otherwise it becomes a problem
given the amount of variable energy that we have out there.
What is the financing conditions for those facilities to,
again, continue to stay operational?
-: Sure I mean, we all have long-term debt on us
and so making sure that we have,
revenues available to meet our debt service
and our debt service coverage is key.
Each one of the plants have been financed differently,
so it's hard to say exactly what the number is,
but when we made those enhancements on the scrubbers
at Fayette, they were over $400 million.
-: Correct.
-: I have not covered that cost by any means.
This is something I'm still paying down year to year,
as many generators that have,
long-term financing again, 15, 20 year projects.
They have a debt payment schedule that they have to meet
before they're making any,
net income and meeting their whatever hurdle rates
or rate of returns that they finance these projects on.
-: So where I'm going Randa with the line of questioning is
I'm trying to figure out if,
so there's the ancillary service approach
where we can pay for
some of these specific performance measures,
to help our system, but then given the universe of headwinds
for dispatchable generations
of a generation of different types and vintages
in order to maintain operations,
do we need to consider a more significant design change
in order to maintain that fleet over the near term?
'Cause again,
you're not gonna build a peaker just overnight,
and it's gonna take some time
and I'm not expecting 10,000 megawatts of batteries
to be deployed next year.
So how do we kind of bridge this gap?
-: I really believe in incremental steps.
I think that's the first way to get out there.
I think you need to provide some regulatory certainty
about some of these products from a longer-term perspective
and if you still don't see people building new,
or you still don't see enhancements coming to the system
and the again, constant evaluation,
I think then we have to re-look at it.
Are we getting the right- -: Do you think as a regulator,
we will have time do that, I mean,
if people start retiring facilities and we get tight,
I don't think I'll have the time.
-: And I agree you're in a difficult situation.
I do not disagree.
-: Okay, so I'm gonna ask you a question.
I read your comments to our questions
and you're the one I was most scared of on the market,
So I'm being brave here,
but would more participation in day ahead market
increase your visibility on the likelihood
of your participating in the real-time market?
-: Absolutely not.
-: It would not, why?
-: So when I'm a generator,
I look at what my cost to produce is,
and I create an offer curve from a day ahead perspective
based off my fuel, my gas cross and my variable ONM
that gas cost is changing every single day, right?
So that is what I bid in from a generator standpoint.
I also have load, I'm trying to serve my load,
the least expensive way.
So that does not mean that it's coming from my generation.
That may mean that I'm gonna buy it from a renewable
asset because that price is gonna be less than my price
of power if it takes me to produce.
So let's just say I have a gas plant
and I have a, my lowest offer is $30.
If the clearing price is $15, I did not run that unit,
I bought that power from the wind generator.
I don't know any better how to commit that unit beforehand
until that market runs because I'll lose money otherwise,
because if I commit it and prices are lower,
I just lost money.
-: So in that line of thought,
it really is contingent upon
the conditions of your gas supply,
'cause again, you're having to buy that out, right?
-: Sure I mean yes.
-: So given your menu of options that you proposed
and we create an ancillary service for
on-site fuel storage or something like that,
it would incent gas generators, gas resources,
to have some type of on-site fuel storage
to compete for your ancillary service
that'll be out there theoretically that helps you smooth out
that condition in day ahead.
-: Right so generators are only a very small, I mean,
there shouldn't say small,
a significant part of the gas market, right?
We don't just me having certain amount of gas supply
or storage doesn't mean that when I inject or withdraw
in my storage facility,
that the price of gas is gonna move daily,
regardless of what payment I'm getting from that
from fuel price.
-: But it does have the effect of creating
a natural hedge for you
'cause you've already paid for it, you've got it there.
-: Yes I would call it a dirty hedge.
I mean, that's what he did
when you can't hedge the whole product
it's called the dirty hedge, right?
And so you still have put risk on that generator
and so I still think you have the same issue.
-: Okay, I'm gonna keep pressing on it.
-: That's okay and again, I do, please.
I invite you all to come in and see how we operate.
I mean, it's really is very interesting.
-: In this economic example that you,
your staff worked on for new builds.
Is that a simple cycle peaker or aeroderivative.
-: Its aeroderivative actually, it's a jet engine yep.
-: So that's obviously the cheapest
peaker you can get out there. -: Exactly.
It's about 800 to $1000 of KW right now.
-: Okay.
-: So obviously we kind of talked about plant costs,
construction, operational debt
and then what do we do?
I mean, it's like any investment we do
a discounted cashflow analysis
and we look at, what type of market prices
and revenues are needed to meet our hurdle rates
so nothing different there.
-: So you do you do your DCF and we hear not just from you,
a lot of people that in your green box and lower,
or are there predictable and sustained annual revenues
for a 20 year asset life?
I mean, there were a lot of DCS out there in the world
that have that run a lot of businesses that don't have
any visibility on the revenue inputs,
in those and high Cap Ex infrastructure industries
that don't have any visibility or even any foreign markets.
So even the benefit,
I know our inverted Ford curves for power prices
are a problem,
but there are forward contracts to limit natural gas
price volatility that generators can procure
from next gas date of four-day packs or even further.
So in this compared to other industries,
like how predictable and how sustained do they need to be?
Because there is no industry on a planet that has 20 year
visibility into revenues and costs.
-: No I agree 100% and there's not enough liquidity
in the market to do any of that.
risk management, hedging.
-: Sure even oil and gas maybe goes out four years.
-: Exactly.
-: And so it's not just you,
we hear a lot predictable and sustainable revenues, right?
So like how realistic is that in any industry?
-: Well, I mean, I think we've talked about it
in other markets and I know Bill we'll touch on that.
A capacity market does that, right?
-: And legislature debated that exhaustively.
-: Exactly I'm not saying that's the answer by any means,
but if we go to the next slide,
what I do say is I think it's multiple different services.
I really believe when you're trying to meet
that revenue target, like right now,
this is based off current market.
So things change day to day.
But currently right now,
if I'm looking at building this peaker over 20 year term,
this is kind of how it money's out.
It's losing $82 million right now.
it's based off running at,
maybe 10 or 20% for energy.
So very low capacity factor on this unit
so I'm making my money or making the value
to run this unit based off a lot of different
ancillary service products.
-: So I guess another way
or another a corollary question would be
when you've got such a low capacity factor
peaking that gets back to high revenues,
only generated when our reserve margins get
tighter and tighter and tighter
and so this is a somewhat philosophical question,
are we just skirting around the edges of this thing,
looking at different services,
different versions of ancillary services,
or do we need to be looking at how to move revenues
to ordinary operating times like businesses as usual
where dispatchable generators can generate enough revenue
and again, any form of dispatchable, battery,
compressed air, thermal, anything, but just,
it doesn't require a crisis for generators
to have that increased level of revenue
and that it happens on a regular enough basis
that those forward power curves for power in Texas
can get to a level that's not an extraordinary burden
for a consumer,
but provides a financial incentive for investment
in the dispatchable capacity we're gonna need.
-: Yes, I agree with you.
I think, when I look at all those services
that there could be predictable payments for like,
I'll just take voltage support.
We're the only market does not pay for voltage support.
MISO pays for it, SPP pays for it.
That to me is a very easy, I mean,
we can send you the tariffs even.
That's a very easy, predictable stream of payment
that ERCOT has not historically ever paid for.
Black start service,
if you look at what we've paid, our Black start units,
and I have one it's 84 cents, a megawatt hour,
ancillary services are clearing at $14, a megawatt hour,
and Black start has cleared for 84 cents a megawatt hour.
I mean, these are all things I think we can tweak
and figure out how to enhance payment streams
and predictability for existing generation
and future generation to stay online
and to be built, that firming fuel service.
Again, you want me to invest 500 million, I mean,
$5 million into, additional pipelines.
Well, there's gotta be some type of reason to do it
well okay, pay me affirming fuel service, ancillary service.
-: Is that voltage support in SPP, MISO,
is that born on LSCs or is that assigned?
How is that assigned?
-: Yeah was the LSCs pay for it?
-: The LSCs did, okay.
-: I mean, I have always said in this market,
and I'll try to wrap up 'cause,
there is a lot of efficiency that we've gotten out
of this market, a huge amount,
but we did it at the cost of reliability
and I think this is a prime example of what happened
in winter storm Yuri,
in which we need to switch the pendulum
and look at paying for these reliability services,
like Barbara has shown earlier,
a lot of other markets do a lot of things that enhance
the revenues for generators
and I know it costs a load money,
but I also can tell you that we lost billions of dollars
during winter storm Yuri
and I don't think any of these solutions
that are competitive in nature would cost that much money.
-: So you're saying remove or move revenues to reliability
within the existing competitive framework.
So we capture the market efficiencies and the benefits
for consumers of competition amongst
both generators and retail providers.
-: Yes.
-: Thank you.
-: Randa, do you have
pricing figures for your new firms fuel AS,
I know you provided some for the,
through dispatchable liability service.
How would do you, can you give us a little more.
-: I think its very specific to everyone's own generator
and how they're connected?
So when we develop power plants, some generators,
depending on their vintage and year,
there was a time in the nineties,
we all did multiple gas, interconnections
things got tighter we had to get capital costs down.
Now, some of the newer stuff's only
connected to one gas pipeline.
So it's very specific on each power plant
and the individual characteristics of that plant
and location.
-: So the payment would vary by the year.
-: It would, it would.
I think the first thing to do there
is when you get that independent consultant or study
is say, well, how much do we need?
And then start a competitive process in which folks say,
this is what it would cost me to do X, Y, and Z.
Here's the fund of dollars, how do we do that the best way?
Because it's not only just allowing folks
to be able to recover that cost,
but getting that gas availability in the right spot
in the grid is key
and it goes back to also the Black start
and how you do the islands of bringing back
the black star units.
-: Voltage support, oh, sorry one more.
You mentioned how other markets pay for voltage support
and I think you've mentioned tariffs.
Can you speak to a little bit more about how other markets
compensate for voltage support
and how that would be done in ERCOT?
-: Sure, I actually have a summary I can just send
that may be the best thing to do, so I'll do that.
-: Maybe let me do it.
-: Bring on it.
-: We talked about the dispatchable generation
and what it costs to do a peaker I should say
you have a metric to do this already.
You have the peaker net margin analysis
that is part of your rules right now.
The costs need to be updated is what I would say.
It hasn't been updated since 2012.
So what I would recommend is to have a better understanding
is update those costs.
You can look right now,
the red line shows that you need at least $105,000
of a cumulative peak net margin to get to help incentivize
and yes, we've had instances that that's occurred,
but it still is not enough certainty in the market
to invest, $300 billion in a project based off
the outlier of 2021, right?
We hope we never get there again.
-: All right thank you ma'am.
-: Thank you oh, no, it's the same thing.
-: Good deal, Exelon is next the floor is yours.
-: Yes thank you very much Commissioners
for the opportunity to be here today.
My name is Bill Berg and I'm vice president
of wholesale market development for Exelon Corp.
What I'd like to walk through with you today
is our proposal,
the comments we filed focusing primarily
on the ancillary service product,
the it's a new product we're proposing,
which is available to dispatchable form resources
and we'll talk about what those resources are
and can include and how it fits into
and strengthens kind of the existing market design
and improves reliability.
As we were kind of developing this proposal, we took,
we've kind of looked inward.
We looked at the unique nature of the Texas grid,
the existing market design in Texas,
as well as the recently passed legislation
to try and come up with a strong man for a holistic proposal
for the Commission to consider.
So the first thing we commented on,
I won't spend a lot of time on this because it's not
an ancillary service product per se,
is just the price cap in the ORDC.
We are supportive of lowering the price cap
and kind of widening the tails
and we list a couple of reasons why we do that.
It would on the margin move reliability away from the crisis
situation we're at today.
I think resources could build into that
and I think what we're seeing from ERCOT and kind of their
change and kind of operating philosophy is adjusting that
ORDC would take a lot of these procurements that ERCOT's
doing today out of market and move them into market,
which I think,
using the market to achieve your objectives.
I think most of us would agree
is better than command and control.
-: Bill can you explain how it would move us from the crisis
standard that we're on right now?
How does broadening the ORDC tail do that?
-: Well, what you're basically doing is,
and you think of the end of the tail, right?
So think about the ORDC, when does it start providing,
making the $100 adder.
Does it start providing $100 adder at 4,000 megawatts
or 5,000 megawatts
and so by widening the tail to, as I said,
you will be carrying more reserves in real time.
So if the $100 adder occurs when reserves
fall to 5,000 megawatts,
people will commit their units to capture that adder.
Does that make sense?
-: Yeah, well, I mean, you're elongating the tail,
but you still get to crisis to trigger the tail.
-: Absolutely and changing the curve
is only part of our solution.
-: Okay.
-: Changing the curve alone in our opinion
is not going to dramatically help the situation
that you're facing.
-: I think, let me make sure I got the concept right.
For my own edification that you were saying about by
flattening that tail or broadening that curve
instead of a unit and the unit understandably
would hold up out of the market, not commit to the market.
If it's a 12 or 18 hour start time unit
right now that unit staying out,
waiting for that adder to, waiting until that reserve margin
shrinks enough, that there's a possibly for an adder
in the meantime,
what he's looking at and say, if it's 18 hours out
and I don't have it committed yet I'm rocking it.
-: That's part of it for the long lead time units.
But it's also for shortly time units as well.
Anybody who says I can make money
at this higher reserve level,
they're gonna self commit.
-: They're gonna stay off until.
-: They're gonna stay off until
they think they can make money
and so that kind of- -: So long as the margin,
it gets close. -: That's right.
And then they're gonna commit it.
It doesn't have to be logging any time.
It could be quickstart peakers.
It could be any type of resource.
-: What number do you suggest that we lower the cap to.
-: We have put in there $4,500, $3,000.
I do want to say,
I think the ORDC curve is an incredibly powerful tool
for the market.
I think energy prices should remain a prominent feature
of the market
and I don't think you should try and go too low
energy prices as we talked about
it's in price responsive demand,
and we're gonna talk about non price, responsive demand here
in a minute,
they inform the market as to the duration of an issue.
Is there a tight system condition for an hour,
a day or for four hours a day or for eight hours a day?
And now all that information,
very informative to the market in terms of
their calculus as to what type of resource should I build,
where should I build it?
And so we think the ORDC curve should remain a prominent
feature of your market.
We just think you need more.
-: Do you think the ORDC will incent if there's changes
you made will incent generation investment alone?
-: Not in and of itself no matter.
Okay, the, are we good on the ORDC?
-: Yeah keep going.
-: Okay so now we're kind of delving into the new product
and I want to kind of go back to the first thing
that Woody said this morning about his number one issue was
what is the amount of reliability you're trying to procure?
And that really is kind of the foundation
for a lot of these discussions, I agree with Woody,
that is the first question
that the Commission needs to wrestle with
and I would argue it is the most difficult question
to wrestle with because it's a little bit of a Goldilocks
situation here where if you incent too much reliability,
right, consumers are burdened with that cost
and you have a, your grid becomes stagnant.
You have too many resources that are inefficient
and they're just hanging around too long
and they're really not providing much reliability,
too little reliability, right It's devastating as we know.
So defining, finding that spot
where you are comfortable from a public policy perspective
of this is the right balance of reliability we need,
we think is your first it's a very important issue
for you to solve and it becomes the foundation
for a lot of these other conversations.
Where I differ with Woody a little bit
is how you define that reliability,
Woody was talking about, defining that reliability
in terms of a planning reserve margin concept,
the planning reserve margin concept
has been around for decades,
it works exceptionally well when your universe of resources
is called nuclear and gas.
That is not the environment we were in Texas.
We are in an environment where there's an increasingly,
there's the mix of generation,
as we've talked about is becoming increasing intermittent.
So what we're proposing to kind of define the reliability
standard is to look at the concept of net peak load seasonal
net peak load, which is from load expectations,
minus your intermittent renewable resources.
The difference is what you need to solve,
for dispatchable resources
and we're going one step further
and this is kind of where the art comes in
from the Commissions perspective, we're saying, all right,
we can start with net from load minus intermittence
and both those are expected cases, right?
The load is 50,50 probability of happening the intermittence
or whatever resource,
effective load carrying capability we give them,
we're saying, take those two numbers and stress them,
stress the load up, stress the renewables down
and that is the amount of dispatchable reserves you need
to have reliability.
-: How far down would you stress it?
-: That is the art and that is really
where the art comes into this?
There's a lot of good information in the Sara report today
where ERCOT looks at what happens if the load goes up
to a 90, 10 case or whatever case,
what happens if the re renewables go down to the,
same case, right?
What we're suggesting is,
and we probably are gonna need some analysis from ERCOT
and definitely some policy consideration from the Commission
as to look at those two events jointly,
what's the probability of those happening at the same time
and such that, you could pick it a one on 100 year standard
or one in 50 year standard,
but there's definitely some art as well as science
into that conversation.
But it truly is foundational to kind of defining success
and defining a market design that achieves success.
-: We tried the probability thing in June.
-: Yes, sir well, I'm gonna get to that.
But in all right,
so let's, what is a dispatchable from resource?
It's a new term that sounds similar to dispatchable
reliability service.
I think the concept's saying the same,
but we're talking about creating a procurement of resources
as determined by what the reliability standard
you just talked about is,
and they would be seasonal
because the kind of the net peak load concept,
we were talking about changes by season,
the amount of swing you could have in the load
changes by season, the amount of swing you could have,
in your inner resources changes by season.
So you want to come up with that kind of
seasonal reliability need,
and then procure those dispatchable resources.
What are those dispatchable resources?
They are obviously thermal resources
and we would include nuclear in there
because they're always on,
even though they're not technically dispatchable,
there must run resources.
They could also include,
and it should include demand response.
You have the ERs program,
that's kind of its own little capacity market
out there today.
You could roll that into this product
and they could do that.
We talked about residential demand response,
that could be part of this as well.
I wrote down voltage reduction because
that came up today as well.
The trick is create a broad market
for these dispatchable services
and then clear it on a competitive market basis.
What do you get for it?
What we're proposing here is that there,
you could put some conditions on this.
You could require anyone who receives a dispatchable
ancillary service to offer into their ahead market.
-: Physically commit.
-: To commit, not to necessarily run,
but to throw in a price-based offer.
You do not want, it's not good for a generator
that has a marginal cost of $30 to run in a $20 market.
That's not, that's right,
but you could have them submit an offer.
You could put some conditions on
kind of pre-submitting maintenance schedules.
There's a lot of conditions you could do with this.
So what does this do?
This would, we think improve reliability in all seasons
and as we've thought about this,
and particularly as it relates to the ORDC,
if this works, you're going to attract,
and we hope it would,
you're going to attract more dispatchable resources,
which means now we're not in the day
where we're committing more resources,
self committing in the day.
You just have more resources in general
and so that is gonna keep you from the super steep
portion of the RDC curve,
because they're around and they're available to commit
and so yes, there might be an incremental cost
with this ancillary service product,
but we would expect there to be an incremental reduction
in kind of life on the ORDC curve.
-: So that's important and nuanced distinction,
but an important that those two elements are tied together.
-: Yes, sir.
-: As to your reliability standard and how it works,
how it syncs up with the dispatchable AS product
that you just described.
If you'll humor me, let's do a quick.
-: Yes, sir.
-: Back of the envelope calculation,
you said peak net load say this,
we'll just call it 75,000 for a normal,
not extreme weather event, normal August afternoon,
-: Right.
-: Back out the intermittent switchers, 35,000 right now.
So that gets you to 40,000, right?
-: A little bit-
-: But I've got a discount factor on the intermittent.
-: Definitely a discount factor, I don't think you'll pull
we're not suggesting you pull out all the intermittent.
-: Okay so this is the art part that you mentioned.
-: You're gonna stress them down, the question is how much?
-: Okay so right now we're at 7% of installed capacity
for our wind fleet.
-: Yes, sir.
-: So that's, I wouldn't say that's is that again?
To see all right we don't have to figure that out right now,
but if you take a snapshot of 1:15 this afternoon,
mid August or late August, we're at a 7%.
So say so there's more than that so it's.
It's got us, there were about 80%.
-: Correct.
-: So let's say we've got the grand total we're getting is
10,000 megawatts normal day right now.
So if you back that out,
we're from 75,000 peak net load and afternoon to 65,000
and then what's the next step in your process?
Are you saying the rest of that's the dispatchable?
-: That's your dispatchable need without,
before you start stressing the load up
and remember, this is the peak net load
for the season we're talking about.
-: Sure. -: So you're talking about
a normal day, but let's just assume
it's the peak load for the season
today was the peak and we're applying our methodology
then yes, the dispatchable requirement would be 65.
-: So that would be ERCOT procuring on a week ahead or.
-: Well so, couple a month or two prior.
-: Sure the month ahead or even seasonal for the summer
hey, we're quarter by quarter we'll look at it.
So that's what you're saying.
-: Yes, sir.
-: Looking at ERCOT runs its analysis
We think on August 26th,
we're gonna need a dispatchable.
We need to procure 65,000 megawatts of dispatchable
resources and ancillary services.
-: So I just want to make sure I'm tracking.
So the next season is the fall, right?
-: I'm saying if we had done this model.
-: Absolutely If you had done this,
if you had done this in the spring.
-: For the summer,
-: For this summer,
you would have already procured all those resources.
Those resources were gonna be, they're committed to you.
They have an offer into every day, had market every day.
They have performance obligations
throughout the entire season they're committed.
-: Okay.
-: And so on any given day within that season,
they're yours and there are ERCOTs and at your disposal,
but you have secured the right amount of dispatchable
to kind of deal with variable load
and variable, intermittent resources
and the payments are targeted
to those dispatchable resources.
So you're actually beginning to target the money
and the payments to the resources that kind of balance out.
-: Like Randa said, revenues to reliable.
-: That's right, revenues to reliable reliability
That's right.
-: Can you compare and contrast your two products
cause they sound very similar.
-: They are. -: What's the difference?
-: We should have spoke.
-: I know now I think the big difference is the way I,
what we're recommending that art of how you determine
how much you need, that's the big difference
and I think that needs to be studied further.
My concerns are, if you procure so much,
it becomes a balancing act, really?
Because if you procure so much, it sounds funny,
but people will start bidding close to zero
and that amount will clear at a very low,
low value that doesn't enhance anything.
So it has to be a balancing act
of determining the right amount and,
we also talked about a price floor to look at
as an option too, to make sure that the value is there
in the future to incentivize it,
or it could be driven to nothing
and we've seen that at capacity markets I hate to say that,
but, we've seen that.
So it's gotta be a nice balance of what we need
and how you keep those generators online also connection.
-: I imagine Scott will have a few thoughts
on the expenses related to this?
-: But it does.
the pricing of the market is important,
but how much you procure,
what you need for reliability is your first step.
And that is the art
we can deal with in a price is going zero
through market design enhancements.
You could put a downward sloping, demand curve,
like the RDC there's things you can do to kind of mitigate
some of the price volatility.
But again, coming back to kind of studying
the quantity of resources you deed is important.
-: All right.
-: Okay just wrapping up here.
There's been a lot of talk about winterization
from fuel maintenance outages,
there's been a lot of conversation after the storm
and because this is a seasonal specific product
you can develop seasonal,
you can and should develop seasonal specific requirements.
So you can think about to salvage dispatchable from service
dispatchable from resources, sorry,
I'm already picking up on yours.
In the winter you have to do A, B, C, and D
to sell it in the summer,
it's another set of requirements
spring and fall you're dealing with your maintenance issues,
but it does provide a nice umbrella to kind of wrap
a lot of the reliability requirements
you're struggling with right now
and trying to figure out under this umbrella,
because you can put some conditions on selling this product.
-: So those seasonal examples you've mentioned
tailor what's required by SB three and that based,
or based on those aspects.
So the spring and the fall,
basically the shoulder months.
So are you suggesting an AS product
dispatchable AS product that would be compensated for
scheduling and some other different way.
Like, can you explain that spring and fall one?
-: So the spring and the fall,
you're gonna start with the same kind of analysis,
which is how much do we need
of seasonal kind of net peak load for that season.
It's gonna be very different than the summer.
You're gonna also take into,
and then you're going, procure that amount.
What we're saying with the spring in the fall
is we have to find a way to also incorporate
maintenance into that as well, 'cause we're starting to,
we're at kind of at a point now where
it is difficult for the thermal generation
to take maintenance outages in the spring and fall
simply because I'm not sure we have enough of it.
-: Thank you.
-: Yes, ma'am.
-: And that concludes my presentation.
-: All right thank you, Bill.
Any other questions or comments for Bill.
All right somebody gonna pay for all this.
(members laughing)
-: Thank you.
-: My name's Scott Gahn, I am the CEO of Just Energy.
We are an independent retail electric provider in Texas
and 11 other states in the U.S. and six provinces in Canada.
We have formally provided retail electric service in the UK,
Ireland, Germany, and Japan,
and have departed those markets
and I mentioned this and I beg your pardon, chairman Lake,
I'd already told you this,
but I would like to express
from the experience of this company from,
by experience being in the industry for 35 years,
I entered this in 1986, I've done nothing else since,
and being in all these other markets,
despite the challenges that we're discussing today,
despite what happened in February,
Texas remains the best market in North America
and those four other countries we used to be
and I would say on the planet,
but I haven't been in every market.
So we are committed to this process
and I'll tell you as CEO of the company,
We will remain committed to the end to make sure
that we get the right outcome for ERCOT and for Texans.
So having said that,
I wanna give you a little bit of the context,
of what it's like,
what a retail electric provider who's unaffiliated
without affiliate generation what they see
when they see things like this next slide.
So this just to pick something recent,
is a graphical representation of what we see
from the recent increases in the non-spin reserve
service for reliability,
and we support reliability.
I would be in a way different position right now,
if we didn't have the February reliability event.
But when we look at it,
the first thing we see is that we've now got additional
ancillary service obligation
that we're gonna have to meet.
This is the entire market.
Ours would obviously be low ratio share of that,
but we view it as something that is occurred,
that it's outside of our ability to go into the market
and to hedge.
So it's new volume it creates an impact.
One of the things that I think we talk, and I think,
my two colleagues mentioned this and I'll mention it
when I finally answer your question and that is,
we do believe the market should be used to the maximum
extent, practical to resolve these issues
and we should take advantage of all benefits of the market.
But when we take actions within a market,
as complicated as ERCOT,
that has all the tentacles out to even ice,
where people trade product night,
there is going to be a response,
and we have to consider that.
But sometimes it's unintended consequence
that we really don't want.
So I just would say for us, this remains, this would alone.
We've already started implementing this on July 12th.
This remains uncertain costs to us.
It is a significant hedge risk
because we can't find a counterparty in the market
that will trade this with us
and, I signed up last month,
I signed up 29,000 customers, new customers last month,
and I renewed 25,000 customers on new contracts
and the average term of those contract is 2.2 years.
So I've taken up a position out there
and we've made the decision to do
we have faith in the market,
we have faith that we're gonna resolve this,
but when these costs come up,
these changes in what we do come up
within the term of the contract,
it has a significant impact on us
and so we've now got to figure out how to do it,
but what makes it even worse is when the change happens
and there's no vehicle in the market
for us to go out and hedge it.
So I can't even tell my board risk committee
that I'm not gonna be in violation in three months,
because I'm gonna figure out how to do it.
Right now we have an exception from board risk policy
to carry this over in position next slide.
So this is a representation from July,
through August 23rd of RRS daily average
and NSR is daily average prices.
These are the actual costs
of the volume increases at settle prices.
So this is the volume increases,
ties to settle prices for the period from July
through August 23rd.
If you look, you can see the spike that occurs on the 12th
when we started with the increased volume
and you can see the orange line is non-spin reserve
and the blue line is RRS
and this is what the additional volume traded at.
The green shaded line,
which is tied to the right-hand axis
will reveal that the costs to the market
of this reliability action
for the first 43 days is $50 million.
So it's not an inconsequential amount of money,
but it's not 40 billion
so we understand what we're after here,
but it is a significant impact
and I had my supply guys go back and say, well,
tell me what this risk could be
I've got to figure out what it could be over the next year,
give me an annual number and they look back at,
five-year look back on the market clearing prices
applied it to these volumes, it's $200 million.
So this could be a material cost
and it may be the right thing to do it.
We've got to do something we're 100 on board with it,
but I just want, as a retailer,
we look at these things and it's so important
when you're standalone retailer,
because we are retail are built in the image
of SB seven because retailers
weren't supposed to have a generation
when we started out.
So these things,
when they change have a significant impact,
if you could go to the next slide,
I'll explain to you why were the whiny retailers?
So this is what a doll,
this is a illustrative example of what a dollar of
revenue looks like at a retailer like us,
and these are built off a real numbers,
but they're averages because, if you go to ERCOT,
the TDSB charges are different than if you,
if you're in center point or TDSB or somebody or AEP,
but this gives you a breakdown of that dollar.
So 37 cents or energy costs, what we know as,
is what we hedge as energy, what we hedge
and pay for in the day ahead market for ancillary services,
as well as upload charges,
37 cents out of the dollar 42 for TDSB costs.
So the delivery costs in the provision of that service
by the TDSB is 42.
So out of that dollar,
you could see how much we've got in 79 cents of it
is cash out the door, right out the door,
3 cents of it is taxes and 3 cents of it is bad debt
and, you'll hear us also get cranky
about disconnect moratoriums although we did,
much better than I thought we would
with the four month disconnect moratorium
and then we've got about 10 cents to run the business
and it leaves us at the end of the day,
out of a dollar with a nickel
and so we have been very successful in ERCOT
at making a commoditizing this business,
which has been good for consumers, right?
There's just not a lot of not left,
not a lot of operating income after.
So when we look at a number,
like a nickel on top of a dollar,
when you have what look would appear to be relatively small
changes in some of these costs within the contract term,
we're dealing with, it could turn things upside down
and, like I said, we wanna find a resolution to these things
we wanna to and we do support all the things
you're talking about doing to try to
create a more reliable market,
because like I said, retailers,
as much as anyone can survive an unreliable market.
So next slide.
So now I'm gonna try to answer your questions.
So what principles should the Commission focus on
to optimize between reliability and cost?
I would say one thing Mr. Berg said that I agree with,
I think the reliability standards should be established
first, and then you should attempt
to reach that reliability standard in the lowest pie,
the lowest possible cost
and we think that utilizing competitive markets
to the maximum extent you can
is gonna be the best way to get there
and help you achieve that lowest cost.
But we do think that while ERCOT,
and the Commission need the flexibility
to take reliability actions.
We think that to the extent,
the benefit of those reliability actions
is to the entire market, right?
Or is to all customers forcing the entire cost
of the reliability action through a P and L
that has a nickel to play with is really hard
and worse than that, but what happens is that,
and I'll jump to my fourth bullet,
is that the uncertainty associated with us,
having to price that into our product
and we don't have to price fixed price product,
but it is the primary value proposition,
89% of the officer in power to choose
our fixed price term products.
If we're gonna continue to be able to provide that
to customers, which is the preferred product, not gritty,
it's, we need to have some certainty
as to what the recovery of that is.
We can't bear the burden
of the entire reliability action hitting,
hitting retailers and not have the ability
to recover that from the beneficiaries of it.
Customers are beneficiaries of reliable grid
there's no question about it
and then in a different market environment,
that's how that would be recovered.
So, and I'll jump back to three,
cause I do wanna reiterate something that
my colleagues have said,
and that is that we think that one of the principles
for grid reliability has to be,
to encourage all market participants
and customers is participate
within some organized framework in grid reliability
and associated costs.
I think there's so much technology being driven
at the meter level.
We're being contacted all the time
because we have a lot of customers
and so the technology providers want to get to our customers
and they wanna talk to us about things they can do.
I think a really healthy market for another place,
for ERCOT to lead,
where we've led in other areas like wind and solar
is to lead in the types of things
that are being designed now,
both load as a resource or load with resource
that can create a more reliable and more efficient grid
and that's my comments I'll be happy to take questions.
-: All right, thanks.
-: May I?.
-: Yeah go ahead.
-: Before, Will gets to his questions,
I do want to say we very much appreciate your comments
about the additional ancillary services costs this summer.
That's very much our effort and our cots effort to stabilize
the grid for the summer,
knowing that Texas can't have another misstep
after the February event,
we're going through this entire market redesign effort
to make sure that we don't have to keep
procuring those additional ancillary services,
that extra margin of safety indefinitely.
We're gonna do it while we go through this process
and certainly throughout the summer,
but I know your company and many other retail providers
are in many ways bearing the brunt of that.
So thank you for hanging tough this summer
and being part of ensuring we're stable for the summer.
I just want to lay it out.
-: I second that, Mr. Berg, one question,
having heard the panelists before you,
I'm sure you saw dollar signs flashing in front of your eyes
at every one of those bullet points on,
on the two previous speakers
and if, what was suggested was to come to fruition
and to be passed down to the LSC level,
allocated to the LSC level,
would you even stay in business?
-: It depends on what the cost was.
-: Well, if it's gonna be a lot, I mean,
just from what I was looking at, that looked like a lot,
and it seemed that it has a natural
in terms of the retail market,
it would have a natural effect on those retail providers
affiliated with generation
and those that did not have a natural hedge.
So was that your read on it?
-: Yeah so I think it's a cost though,
even for affiliated generation, if you put that cost on it,
because that resources now having to be devoted to an
ancillary services support load,
to the extent itself arranged, right?
That's why my $50 million doesn't move self arranged out
because it's still a cost, right?
So, while a retailer with affiliated generation
can sell for range that,
that resources now devoted to a new service.
So I'm not sure that they don't see a similar impact
'cause they might've been,
that generation resource it's out being self arranged
for a new ancillary into something else.
I also think that it's a tricky market, right?
I sit here and talk to generators who complain
about the same thing I'm complaining about
'cause they're saying it's reducing realtime energy,
it's reducing real-time energy,
and I sit there and go, well,
if I could only be short real-time energy,
that'd be great because then I get some of this back.
Well, I sell fixed prices to customers.
I have a risk policy.
I can't take advantage of the real time energy market.
I got pushed into the real-time energy market
when half my customers came on with 48 degree homes
and businesses and doubled my load
and I'm in real-time energy
and now where I am now.
So I can't, even if we have situation,
it's sort of like the unintended effect
the deployment of the additional ancillary
could suppress other costs in the market.
So I'm not sure what happens,
Commissioner McAdams, with all the other costs,
we'd have to look at that,
but I do control what I sell
and so my view is to the extent we have a lot of this,
and there's a lot of uncertainty,
I think me and other retailers are going to change
the product we sell.
There'll be less fixed, shorter term product out there,
or people will wear the risk
and then we'll see what happens with that.
-: I'm sorry, Mr. Gahn.
So do you believe those retail electric providers LSCs
with affiliated generation,
do they operate under the same kind of breakdown,
of profit versus liabilities that you do that nickel?
Is that what they're looking at?
So everybody kind of squeezed.
-: They compete against me they might be better.
They might be more scalable if I have,
just under a million residential customers,
but they're in 12 different jurisdictions.
Somebody has a million in ERCOT,
they're gonna have a lower operating cost.
So they may do a little bit better than me
because they have a more scalable system
within Texas, right?
They're heavy in Texas, not elsewhere.
So the other thing too,
is they may measure their P and L differently because
I'm not sure how they'll clear the transfer,
the internal transfer price between
their self arranged generation and the retail business.
-: So, Mr. Gahn.
-: But I think the concept would be the same.
-: I have a related question.
So setting aside what has been happening this summer
with the procurement of more ancillary services and also,
echoing the chairman's comments about,
having to stabilize the grid and in our efforts,
this current venue right now to address market design
changes for the future
and I know Commissioner McAdams asked you to apply it on,
what will those costs look like for you going forward
and obviously there's still a lot of information
that needs to be developed on actual pricing.
Would it be fair to say that what you need
from us as we develop new ancillary service products
is just more visibility and transparency
as to how they're gonna be priced.
So you can plan your yearly contracts
and I mean, cause you're, you just bake in those costs,
we create two new products.
You would look at the products,
see how much they cost and bake that into your annual
contract for your rate, for your products
for your customers.
-: Yeah, so I have two issues here.
The one you're talking about is the,
what I would call the issue that I would embrace
and would want, certainly wanna have that.
So that as I, cause I'm gonna add another 25
or 30,000 customers this month, I'm on track
and renew another 25,000.
So the sooner I know and all those customers
are paying higher prices because of
some of the things that are going on now.
Some of it's just gas prices are up
and so power prices are up.
But so I wanna know it's exactly what you said,
transparency and advanced knowledge,
so that I can start to build out and understand
what wholesale products are available to me
so that I can hedge or dirty hedge,
which we have to do from time to time.
What the risks that's gonna be put on me
and I could price it into my product
so that I know I've got it,
but I've got I signed term contracts,
which I may compress those terms in ERCOT
because of what's happening
because all of the contracts that I have
do not have this cost in it, but I'm gonna incur it.
So they'll, so all of that,
that margin that I was looking for,
that nickel on the portion of my book
has already been priced and is there,
is gonna be impaired by this.
-: So when you look to develop your annual contracts,
do you do that at the, like the last quarter of the year?
When do you touch.
-: It's realtime, we're selling every day.
So we it's a very dynamic process.
-: Okay so what you're saying is you'd want to shorten those
contract periods so you can remain nimble to whatever
changes occur from these new products
and so what we can provide you from our standpoint
is transparency and visibility
as to what ancillary service costs you may be
having incur in the future,
not only for new products,
but also there are other existing products
and how much are ERCOT's gonna procure
and that's something we'll have to go back and look at
in the fall to see how we wanna change
the minimum AS methodology, et cetera, going forward
to hopefully give you some more transparency and visibility
and then as we have these discussions and we just,
if we decide to move forward with AS products,
new AS products,
then as we shape those out PUC here by role,
and then also through ERCOT market rule changes,
then you'll start getting more information to be able to.
-: There's one other issue and I appreciate that
and that's exactly what we need going forward.
That's exactly what we need from you going forward.
But we also have an impairment to an existing
say series of contracts by virtue of these costs
and so we believe that that should be something
and in any other market environment but the one we're in
those would be socialized costs
because they benefit everyone,
but they're only socialized to us
and so it's really two places where we see it.
We see that within contract impairment
and then there's the, how do I go forward?
How do I create a sustainable business plan going forward,
given the things that are necessary in ERCOT to make it
reliable and as vibrant as it's been?
So yes, we would like both
and I know the one is more controversial
because nobody wants to do that nobody wants to see
pass in fact,
we've got the consumer protection rule talking about making
sure ancillaries don't get through
because of the magnitude that you can see,
but from a reliability cause when we do
and I wouldn't say pass through ancillaries
on a normal basis anyway,
but when a decision is made to enhance reliability
and that changes the profile of the ancillary costs
as a result of that,
and I'll call it a non-market decision
out of market decision.
We believe that should be,
we should be able to socialize that to the market
or to customers
because it's, they are the direct beneficiaries of that.
We are too, we are too, I'm not gonna deny it
doesn't benefit all the stakeholders,
but we don't believe we should be the sole market segment
to bear the cost of that.
So it's both.
-: Is there to to build on Lori's point about the variability
and ancillary services at a high level
in the past ancillary was that services,
the amount of ancillary services for the next 12 months
were identified, I think typically in December
and that was the set amount of the, I guess,
the reserves for ERCOT for the next 12 months.
And if you go back to slide two Connie,
the red bars are the high,
what you've got labeled as high variability days,
which is one of the changes we made this summer
with the notion being that the amount of reserves
ERCOT has available to it should be,
should reflect real time conditions,
such as heat waves or droughts or tornadoes and hurricanes
impacting transmission and congestion,
which for whatever reason was not done
in considered in the past.
So to Lori's point about visibility, I mean,
I think we think this is a feature,
this is an improvement on recognizing real-time conditions,
as an improvement.
-: Right.
-: But to Lori's point about how y'all can manage that risk,
whether it's, if we continue doing
kind of forecast variability procurements,
which are day by day or three days to three days out,
or if it's like Bill said a more seasonal look at
some undetermined amount of dispatchable ancillaries.
-: Right.
-: That would only give you all the three months.
If you wouldn't know that until ERCOT sets it for the next
three months, maybe a month in advance of that.
Other than shortening contract terms with your customers,
which I could see being a benefit
and an annoyance to customers.
-: Right.
-: Depending on which way the reset goes.
Is there any other mechanism
or that you can currently use
or would need to be provided to help facilitate that?
-: No, I think the communication and certainty
are key elements and the way that we would price it out,
one of the things that we're dealing with in ERCOT is
if some of it is post-storm.
Some of it is starting to come back is there is a little bit
of a liquidity issue for us in being able to acquire more,
I will say exotic things, not just an energy swap,
but to acquire certain types of options
or certain types of ancillary services.
Like we can acquire this.
We've tried and we may be able to,
as things start as market participants start to see
where the market's gonna fall out, then they,
the people who would provide us this product
would be able to bridge that and so this, my expectation is,
and this is an optimistic expectation just because
I've seen this in the market before
you end up with situations where there's a change,
everything seizes up,
there's no liquidity people figure it out.
Now all of a sudden you start getting product,
you get wholesale product
that allows you to manage this type of risk.
-: That's what markets are supposed to do.
-: That's right yep.
-: All right.
-: So to crystallize that if you see that again,
the 7,000 megawatts,
that conservative strategy is somewhat institutionalized
on a going forward basis, you are able to,
you believe you will be able to smooth that out over time.
I mean, if that's what it's gonna be.
-: That one I think right now it's an open position to me
it's completely open.
-: Yeah.
-: But I think as certainty comes back into the market,
I'll be able to build that.
In fact, I've already built into price,
this additional costs.
So the people that we were renewing
we were renewing a bit higher prices because of this
and there's a little bit of a premium in there
because it's an open position that's uncertain.
I don't know whether it's gonna be $200 million
on an annualized basis to the market.
I don't know whether it's gonna be, 150, 350.
It's really a function of what comes out of SB three market
redesigned too, right?
Because it may not be based on it.
So some of the uncertainty is a function
of where we find yourselves today
and I understand that it's the business that we're in,
but we think, on those two elements
as we make these changes, we think that,
and it's our position that these costs should be,
should not just be born by a P and L
that has a nickel despair.
It should be borne by those that benefit by the market
and so we can with certainty and communication.
We can get a wholesale market
that will support these products.
I'm sure of it because that's what competitive markets do.
They figure out how they're gonna make money at it
and they'll come out and we'll be able to price product
and set terms and do what we need to do going forward.
But it really is gonna require us
to have a really good solid set of rules that we,
everybody can get their head around.
-: So you heard Mr. Bergs suggestion,
as it related to ancillary services, possibly,
a requirement for the resources themselves
to kind of participate in day ahead,
day ahead, it's a useful tool to you, is it not
to kind of see how ultimately resources shake out,
what you're ultimately facing the next day?
-: That's right. -: Okay.
So from a retailer perspective,
it is a useful tool to sort of smooth out volatility
that you're otherwise gonna experience.
-: Well, we're following load, right?
I mean, we're following residential customer,
load and commercial
and people were talking about forecast error,
we have weather changes
and so day ahead market is a very useful tool
for us to make sure we can balance ourselves
going into the uncertainty, the real-time market.
-: Okay, thank you.
-: Can I. -: Of course.
-: Just one point, and I think Mr. Gahn got there
and I appreciate it.
It's I think what we're all struggling with right now
is a little bit of regulatory uncertainty.
And what I mean. -: That's what I wanted say.
-: And what I mean by that
is we're having a very important conversation
on market design.
It's going to take a little bit of time to work through,
but once we do,
even if there's the market is gonna figure out
how to provide term and if the market's gonna be able
to understand the rules
and go back to short term, medium term,
long-term contracting.
That's true even if we have a three-month seasonal product,
'cause the market is gonna understand and digest how,
what the new equilibrium is in terms of market design
and digest it,
manage those risks and provide those benefits to customers.
I just wanted to kind of underscore that point,
but right now we're all kind of in this spot where we're not
exactly sure where it's all gonna land and the sooner we
can get through this very important process,
I think the better it is for consumers
and the market that all.
-: So I think that's an actually very important point.
I know everything that's coming out of our mouth
individually scares the market
because it introduces uncertainty
and maybe this is a segue into just a conversation
about process or ultimately
where we wanna try to get to be a near term, medium term,
long term, I don't know,
but he brought up a very cogent point
that markets have to have time to adjust
to whatever is done here
and what do you think Mr. chair?
-: Sure I think we've laid out of what is admittedly
a very aggressive timeline
for between now and the end of the year.
-: Yes, sir.
-: So to get what we told the,
what I told the Senate was the blueprint.
We don't know what that will be,
ORDC new seasonal products,
farming requirements of duel,
whatever that ends up being in that blueprint,
that's an aggressive timeline,
but I think it's important one
because we know we need to make these changes.
We need to give certainty to market participants,
investors we'll need to,
nobody's gonna move money out of the bank
until they know what the full scape of changes look like.
I think that's fair to say there.
They need to see what it's gonna look like before anybody
invests in new generation or makes a decision to
not retire an asset.
The implementation part of that.
I think if we stick with the end of the year timeline
that would give us, four or five, six months,
depending on what the mechanism is.
The implementation at ERCOT would is varies
from a few weeks to a couple of months, but importantly,
that would give folks while we're implementing that,
that would give folks in the marketplace
time to say before June to adjust their businesses and how,
and start positioning for those changes to go into place
and finally, and I guess most importantly,
I think we need to have,
we need to deliver results for SB three,
certainly before the next session comes in in January, 2023
and even on the timeline we're on now,
May, June 2022 is pretty close to the gavel dropping
for the 88 session in January, 2023.
So I think that that's my thought,
obviously men make plans and God laughs.
-: Yeah, I would echo all of the comments to be expeditious
in how we get through this.
I think while market participants
may not like 100% of what we do,
if we get through it quickly and set the rules quickly,
they will adapt and so let's get it done
let's do our homework, let's get our input,
let's get it done quick
and I believe in markets
and I believe market participants will adapt
and they will find ways to make money
in the market as long as we set the rules
and then leave them in place.
-: Absolutely, I agree as well.
I think we need to take expeditious deliberate action
and in every step of the way,
try to provide as much transparency,
visibility, and regulatory certainty to the market,
to the investment community and also to the public
that we are taking aggressive action
and steps to ensure that we improve
further liability in the longterm.
-: Yeah and just for me, I think we're in alignment
giving the market time to absorb
giving stakeholders time to work through the details.
I believe what we can do in this process
before the statutory deadlines come into play
is to provide direction on what the non-negotiables are
for the ERCOT market.
What we have moving forward,
not necessarily in terms of hard dates on
final implementation depending on nuances of smoothing out
the market integration details just as we've done
on nodal or other major system changes in the past,
but ultimately the financial community,
the generation community,
the retail community will know where we are headed
and what our non-negotiables are and what we must have
and I think that's the best thing we can do.
-: Yeah well put in to the extent we can identify
broad principles sooner rather than later,
even if we don't know the exact mechanisms
of implementing those sooner rather than later,
I think is. -: Yes, sir.
-: Along your line of thinking, yeah.
-: Yes, sir.
-: All right thank you.
-: Thank you Mr. Chairman.
-: Ladies and gentlemen,
appreciate y'all's time and input at this point
let's take a 15 minute break
to let folks stretch their legs.
We'll come back at 2:10 PM.
All right this meeting of the Public Utility Commission
of Texas is back in session.
We are coming up on our final panel of the day
before we have our concluding Commission discussion.
Thank you panelists for being here.
Turn it over Mr. stones from Dow.
I think that's your first up.
-: Yeah, okay, is this on?
-: Yeah. -: Okay.
-: All right Well thank you chairman Lake and Commissioners.
My name is Edward Stones on the global business director
for energy for Dow, which is formally known as Dow chemical,
but some as you know, Dow is a global manufacturer
and we're heavily invested along
the Texas Gulf coast since 1940,
our assets stretch from Orange to Seadrift
and we have our largest site globally in Freeport, Texas
and that manufacturer is over 40% of the products
we sell in the United States and 20% globally.
We employ just over 10,000 people here in the state
and since 2008,
we've invested over $10 billion in new assets
and modernizations at our sites in Texas.
As you can see from this slide
Dow committed to sustainability
and we support reliable integration of
renewables into the generation.
We're actually among the top 20
consumers of renewables globally as a corporate.
And that's, we have these goals
from a sustainability perspective
to reduce our annual carbon emissions
by 5 million tons or 15% by 2030,
and then be carbon neutral by 2050.
But we also have scale
and so right now we have more than seven of power
and steam globally.
We consume more than a million barrels,
a day of feed stocks,
and we have more than 50 gas and steam turbines and boilers,
and that feeds more than 100 furnaces.
So we're a big company we need consistent,
reliable power and affordable power
to make our stuff go.
So what's the problem from my perspective,
we define the right solution,
we really have to identify what the problem is first
and what I would say is over the last few years,
ERCOT has been increasingly reliant
on intermittent generation,
which are renewables for the most part to serve peak demand.
As this trend increases,
stakeholders have become uncomfortable
with potential liability issues.
So why is this happening?
Basically, government incentives have caused
a disproportionate investment in renewable generation
compared to dispatchable or thermal generation
and those renewables don't respond to price.
So traditional market signals and incentives
don't increase output or improve performance
from these resources.
So if prices rise, customers pay more,
but you don't get any more energy
from the intermittent generators.
In fact, it actually works the other way in Texas
high renewables supply leads to low prices
for all sources of supply
and low renewable supply leads to high prices
for anybody who's left
and that's kind of where the net load concept
that has been discussed.
The problem in some ways that customers in ERCOT,
and not directly linked to their contract,
its source of physical power, if they were,
would solve the problem,
because those who only buy renewables would be directly
exposed to the risk of intermittency
and would have an incentive to contract around that.
So if you go to the next slide,
these are real data from our facilities.
So this is not some hypothetical,
this is actual real data
on the left you can see our renewable contracts,
we have something in coastal wind
and we have a panhandle wind and then I show a gas turbine.
The gray bar of the left bar is the capacity.
The green bar is our March delivery and the July bar is,
the right bar is the July delivery dark, right?
So you can see it it's quite different by month
from the wind.
Whereas the gas turbine pretty much delivers
what it says it does.
If you actually go to a kind of five minute basis,
which is the chart in the middle here,
this is the month of July, 2017
and all months look like this.
This is just one that we picked.
You can see the gas turbine is like a rock just solid
and the wind goes all over the place and it goes all over
the place every day there's no pattern to it.
That's fine, but it's a fundamentally different product
than a gas turbine generation
and so since we, our own retail electric provider,
we can blend dispatchable and renewables in a way
that's tailored to our load profile and our risk tolerances,
but the centrally dispatched integrated system
can't do that.
All system resources are shared on all parties are exposed
to the lowest common denominator
in terms of reliability risk
and even though we manage our risk,
we're still exposed to the price and supply volatility
of others through this common system,
because ERCOT for us is the balancing wheel.
It's the last thing that
we use to make our numbers work when,
on this chart, there's times when I get
100% delivery from both wind deals
and there's time when I've got less than
2% of the capacity delivered.
So just to give you a sense of how that works,
therefore, what you Commissioners have to do in our opinion,
is directly manage this risk for the entire ERCOT market.
I mean, that's the task you've been set
and it's not an easy one.
From our perspective, lowering the price cap
and flattening flattening the ORDC just won't work.
A competitive market depends on an accurate price signals,
an accurate price signals drive generator performance
in times when the system needs it most
and they provide price signals for efficient demand
and response and efficient demand response,
manipulating the ORDC really just raises overall prices.
It won't improve your liability
or it won't change investment patterns.
It only increases cost to customers
and frankly, in our opinion, decreases risks to generators.
In 2019, the Commission shifted the ORDC
by a quarter of standard deviation
and adopted a second quarter of a standard deviation shift
that was implemented in 2020
and that was just last year.
There really hasn't been any time
for the investment community to fully respond
to these changes
and now we're thinking about further changes,
this sort of instability in the market design
deters investment and is challenging for large consumers
and retail electric providers to handle.
So turning this ORDC into an around the clock price adder
essentially makes it an energy tax for customers,
and that can create the wrong incentives.
It reduces hedging incentives and hedging is driven by
the risk of high price is not the absolute
and we want to avoid crises,
but the fact the balances may have shortages in the future
rises the, makes the forward curve rise.
Even if those prices never occur,
that, future supply demand shortage should send investment,
which is reflected in the hedging, right?
Newly built generators make most of their money
through bilateral sales and not through the realtime market.
So most generators are only exposed to realtime prices
when they fail and have to replace a bilateral option
or bilateral position
and that's why you hear from generators
asking for a lower price cap, not customers or consumers.
Increasing prices at higher reserve levels
actually increase revenues to non-dispatchable generation.
It's a blunt tool,
and this could make the problem even worse
because right now the ORDC primarily kicks in
when the intermittent generation has dropped off
extending the ORDC to be hired,
a lower reserve level will increase the revenues
to intermittent generation or perpetuate this overbuild
of intermittent resources in our opinion.
So a more targeted solution is required
and we think that's where ancillary services come in
and they should address the seasonal net load variability.
Increasing the overall price won't impact the resource max,
instead the Commission should identify
exactly what the reliability is, in other words,
how much extra dispatchable generation do we need online
to address potential net peak load conditions
and it's targeted away as is possible.
Then ERCOT should buy this dispatchable generation directly
through a seasonal and slurry service
that reflect the variability of the intermittent generation
and this is a targeted direct way to buy what you need
rather than just increasing prices
and reducing performance risk.
Ancillary services could drive more investment in storage
to smooth out variability
and could help reduce costs for batteries
as more come online.
We also see technologies continuing to develop
for renewables to replicate
or provide the equivalents of conventional power
things like synthetic inertia,
fast frequency response to market mechanisms,
to financially compensate those who provide them,
could accelerate these technological developments
and their implementation
and I was glad to hear Woody speak about this
at the beginning of the day,
I thought those are really good things.
So that's generally my major comment
and I would say, for us ancillary services
would be more targeted
and a more efficient way to solve this.
But with that, I'm open for questions.
-: Thank you questions come up, Mr. Stone.
Heard you say several things there.
One of which was overbuild of intermittence.
-: Yeah.
-: That's jumped out, the other more importantly,
you said the revenues are going to generating assets
that aren't price responsive.
-: Right.
-: And I get what you're saying in that if
a resource happens to be generating in a moment of scarcity,
if the price goes to $9,000,
that when asset can't make the win $9,000,
won't make the wind blow anymore than $40 debt.
-: Right.
-: Or the sunshine at 8:00 PM,
any more than $100, if we're looking on,
so the broader question is,
if on the one hand we just spent a lot of time talking about
spending more money on ancillary services,
which we heard from Scott and Just Energy about
how that is that obviously we'll go to the customers.
Do we also need to be talking about removing revenues
from generators that aren't price responsive
and can't provide reliability
to cushion the blow to the customer if you will?
-: So I'm not sure I would do that.
I think from my perspective,
I would prefer to be technology agnostic
and just let,
have the grid pay for only the ancillary services
they need and the high prices for those services,
which would have traditionally
gone to conventional generators.
Well both support operation of those types of generators
and incense, the deployment of new technologies
like batteries, like grid farming,
like all these things that we spoke about.
-: Sure, I mean, if it's going to do,
like the revenue's going to reliable assets.
-: Right.
-: The issue is if you have a solar facility
and you don't get that revenue
you and eventually the market will only pay
so much for power
and so if you're not getting your share of the good stuff,
you are actually getting less,
that's how that I think would work in the real world.
You don't have to take it away from them
because the market will.
-: Okay, because I'm also,
when you said that I started seeing a picture
of know customers paying extraordinary prices
in these moments of scarcity,
which we of course want to minimize.
-: Right.
-: But those, some of those revenues are going to
the dispatchable generation that they need,
whether it's a combined cycle gas turbine or a battery bank,
extra solar panels or any of the other dispatchable assets.
But they're also because of the way our market clears
uniform price coring instead of by volume,
that the customers are also dumping money on
whatever happens to show up.
It's, non-responsive.
-: I think what you'd be surprised by
is how little that actually happens,
because the reason that the price is so high
is because there were so little renewable available
and that's what happens.
I only got 2% of my capacity from my wind deals
in the very high price period.
So I don't get, the reason why.
-: The impact on customer isn't as large it-
-: What I'm saying, is there, you're not sending money
to the non dispatchable at that time,
because there is no non-dispatchable because if the were
we wouldn't have a problem.
-: Okay.
-: It's sort of a weird tautology of the market, if you will.
-: Its not fair.
-: Mr. Stone's question for you about sort of
the mentality of the market right now.
I know that it is,
I believe it is commonly held amongst the market
that renewables are in the public interest.
You know, they're in the societal interest,
low cost and carbon neutral.
Do you think, would Dow chemical buy renewables
no matter what?
-: No we only buy renewables
if we think we can make money from it.
-: Economic, okay.
So it's an economic condition
and where I go with that is like,
if that cost burden shifts over from the consumer,
that load serving entity, and as some have asserted,
we should assign costs to the renewables themselves,
the intermittence.
I mean, what does that do?
-: So I don't think that's smart because I think
all of a sudden you're picking winners and losers
and I don't like that idea.
I think what you do is you define what you want,
which is I want enough load serving capacity
in the peak times, right?
And then let the markets technologically
and economically solve for that.
That's why you get more batteries,
if, I don't think you want to penalize anybody.
I think what you wanna do is pay for what you want.
-: So like a different version of Will's question
we heard earlier that we're the only market
that doesn't pay for voltage support.
So if we move to, if we change that and start providing
through some form or fashion,
whatever the service looks like,
or the compensation looks like
who should bear those costs
because we're paying for what we want
it's have we'll have woody come up with
a standard of synchronous voltage support
and it's whether that's synthetic or rotating master,
whatever the technical specification needs to be,
we'll pay for the output we want
technology agnostic.
-: Right.
-: I think the question is when something like that,
where should those costs be assigned?
-: So I'm not a market design expert.
I'm not sure I'm qualified to answer
where they should be assigned.
What I would say is let's please
have as few of those costs as we can.
(members laughing)
and as targeted as we can.
So that's why I kinda liked the idea,
honestly we see problems with voltage support.
So yes, we, the benefit of that,
but should we be the only ones bearing those costs?
I don't think so, but I don't know who should,
that's not my role.
What I would say though, is let's please design for,
like I think fast ramping services are good,
I think, voltage support may be an unimportant thing.
I don't know what other problems are.
Somebody, ERCOT has a lot of very expert people,
they can go and study these things
and come up with the right answers.
But for example,
let's not buy extra capacity in March at night
when it's windy, right?
Buying extra capacity in July or August
when we're right up against the net load limit.
That makes, maybe that makes some more sense, right?
And where we are as a consumer is we want to put our assets
where the market works as efficiently as it possibly can
while still maintaining the reliability we need to operate,
because it costs us a lot of money.
That's why we have gas turbines or cells
is to maintain our reliability, right?
I don't know if I kind of evaded your question, I apologize.
-: But very artfully so.
(members laughing)
-: So I agree with your points.
I think they're very well articulated about assigning costs.
I think it gets us into a challenging position
because then we are influencing the market
on what single piece,
what metric are we gonna use to assign?
It could be,
we don't like gas turbines running at $12 gas.
-: That would change some people's thinking.
-: Nobody wants that,
we've had that once, we don't want that again.
But you know, then you create a market,
an out of market mechanism for that.
No, so I just think that one of the challenges
that we've had- <v ->Recently, right?
-: I'm sorry.
-: I had gas turbines running at $300 gas very recently.
(members chuckles)
-: One of the challenges, I think, as we look at
electric reliability through the lens of the old world,
which was, we had plants that ran all the time
with all their fuel in piles or in their gas pipeline
and that attributes of our
generation resources are changing
and we just have to make the market change to that.
You pair, wind goes like this and solar goes like this,
that line is almost flat.
You just have a little bit of areas you have to build in.
-: You got a problem at 7:00 PM.
-: Yeah, exactly and or seven in the morning,
but that's where this market is working,
that we can look at the,
put the products out there
and let the market solve the problem,
as opposed to, this one's bad for that reason.
This one's bad for that reason.
Let the market take over. -: Sure I mean,
I'm certainly wanna agree with both of you
and that we want to pay for outcomes.
We don't want to pick and choose the input variables.
We, I think that throughout our discussions this summer,
we've all been consistent on that,
but I do want to be cautious of going through
a market redesign the SB three market redesign effort,
reacting to the external variables,
like tax credits and what private
would wall street investors want,
shouldn't drive our market design.
We should drive.
We should undertake the market designed
to drive the resources we need in Texas
and I think, you want to be careful about that nuance.
-: We would agree with that.
-: So this brings up an interesting question, sir,
because ultimately if we're on current trajectory,
we will have an abundance of wind and abundance of solar
and that is absolutely great resource.
But to the chairman's point,
there is that probability
that you will have a cloudy windless day.
-: Sure. -: A lot.
-: So how does,
how would Dow chemical propose a hedge against that?
-: So, okay, so we manage that risk
by having our own generation
and also purchasing a portfolio of renewable supply.
-: You're not suggesting the Berkshire plan, are you?
-: No, no, no, no.
Actually I'm certainly not by the way,
but what I would say
from a market perspective, design perspective,
I think one thing you have to think about potentially
is are your ancillary services poorly priced too low
and is your power, your net power price, meaning it could,
the power price can come down,
If the ancillary services go off.
That was one of the points that somebody who's dealing with
a peak or example, right?
Right your short facilities that can ramp quickly,
you're short facilities that can give you power
when you need it in a low, renewable load situation.
You're very, very long renewable power
or power in general in the night
in March when it's 75 degrees
and you have to be careful that
the solution you create,
doesn't spend a lot of money on times
when you don't need the power
to get a little bit of power in August
and that's why I think for us, the ancillary services,
and maybe it's seasonal, and those,
it may be very expensive to do business in August.
I mean, that, and then people will start to react
and move on from that.
-: So am I hearing you say that you're comfortable with
costs going up if the money is spent on the right resources?
-: I'm never comfortable with costs going up
on the manufacturer. -: Right.
-: But I think if we can get reliability,
we do need a market that's works, right?
We need an affordable, reliable,
sustainable market that works within the political realities
and the bounds of physics.
That's what I always said.
-: Is that all anything else.
-: You need all five.
-: Okay so what I heard you say earlier
is you want a low cost, reliable market.
Is that fair statement.
-: I wanna a low cost reliable market with that's sustainable
for the planet that is within the bounds
of what society wants.
So, I can't live in an island by myself
and it has to work in terms of physics.
I always, I'm sorry to repeat them all,
but I need all five
because I've seen markets around the world
with only three of those, with are only two of those
and they fail.
That's why like Australia,
which is one of the world's greatest gas reserves,
exports gas to Japan,
the price of Australian gas in Japan is cheaper
than it is in Sydney harbor, is because they screwed it up.
-: You know, as we look to develop or redesign our market
and if we continue down the path that we've been
sort of hearing about today
and potentially making ORDC tweaks,
if you ultimately decide that new AS products
(clears throat)
costs are gonna go up,
I think costs will have probably have to go up
to meet the reliability goal that we're trying to
reach with our new market design changes.
So there's gonna have to be some give
between having reliability and the least cost
so that the cheapest power you can have
and then also, I'm hearing you say,
you're good with sustainable energy,
but I've heard a lot on this side, too.
I'm a little confused.
Is your Behind the meter power renewable generation.
-: No, our Behind the meter is not,
we have a gas turbines behind the meter.
but we are PPA off takers.
What I would say is the challenge I would say to you is
there's another cost of power embedded in most markets
that is today very well minimized in ERCOT,
which is in most markets,
there's a market inefficiency, okay?
In most other markets in the world,
the market inefficiency exceeds that in ERCOT
and my request is whatever you do,
I get that you have to solve for reliability
and you have to be,
I also know the concerns you all have about affordability,
but let's preserve the market efficiency
because you lose much more in market inefficiency
than the cost increase
you'll have to get a proper market design in my view.
So that's my request.
-: Fair enough.
-: I don't mean to take them away.
-: No, this is good.
this is good and I suspect we'll,
some of these questions will apply
to other panelists as well all right.
-: All right Bob Helton NG North America,
(clears throat)
of course, this is NG,
we are the developer, constructor, operator
and owner of Wind Solar storage
and then we also have a rather large book of industrials
with it's real small on the retail side of it,
the Resy side, we own that plant by the way,
one of his plants,
I'm gonna throw that one in there.
We really appreciate you letting us be involved in this.
This is really important
and NG believes in trying to get the best market
we can both reliable and sustainable
and I don't mean sustainable
from a sustainability standpoint.
I'm talking about a sustainable stable market
that we can rely on both from reliable
and in the market standpoint (clears throat)
and you've got a difficult job
and we just talked about it a little bit
to where we're going we have a lot of renewables
and why do we have a lot of renewables?
He had it on his first slide.
They're gonna be 50% carbon are 50%.
-: We cut, we gonna cut emissions 15% by 2030.
-: Yeah so they're looking at,
everyone's looking at cutting emissions,
both the companies that are here
and the companies that are wanting to move down
and do move down to Texas.
So that's gonna continue.
So that's a reality,
and I really liked what you said, chairman lake, right?
A minute ago, we can't let those outside pieces,
'cause those that's a little bit
of a different economic model
than what is on the thermal side drive completely
what we're doing with the market design.
So it will play a deep part in that, but we do,
I believe you're correct and right on that,
there is some separation we need to think about there.
(clears throat)
To move on the main thing that I was gonna bring up first
is that his first thing that he had from Dow was the ORDC
and to back it up a little bit,
whenever we first brought in the,
first started talking about the energy only market
versus a capacity market,
we came in and said,
go buy 3,300 megawatts of additional reserves
in the day ahead
and that'll give you enough market revenue
to get you to about a 12.5%,
which was our target at the time reserve margin
and that didn't go.
So we understood that the operating reserves demand curve
and reserves in general are in an energy only market
the only way you can get there,
it's either gonna be ancillary services
or it's gotta be the energy price, that's it,
that's all you have.
So we have to figure out how to get that in an equal place
that'll give us what we need.
So what we're solving for in my mind is,
and it's been mentioned a little bit around here today
is I've heard, the economic optimal reserve margin
several times today.
That's a good number.
It's nice number to know.
You wanna know where you're at on that.
But to me, that is not the most important number,
the most important number that comes out of
and you talked about it earlier, Commissioner,
the Brattle report, out of that report
there's also another number in there,
which is the market equilibrium reserve margin.
That's the number you wanna try to provide revenues in
that will get you to the reserve margin
that you're seeking under an energy only
because you don't have a mechanism to ensure
you're at 13.5 or 12.5, you don't have it.
So you have to supply the revenues
that should incent those investors to invest
for that market.
So that's the number I think we need to look at.
-: So Bob, on that question,
so that market equilibrium reserve margin,
again when we were at 9% was only at 10.5%
as I recall, or 11%.
-: You used a couple of numbers.
Oh yeah it was down the market equilibrium number
was down also.
-: So it's like instead of a one in 10 standard,
it was like a one in four standard.
I mean, it was still terrible
for liability purposes.
-: Exactly and that was part of the reason that
we went ahead and did make the standard deviation changes
is 'cause we felt there
was needed more revenues into the market to bring that up,
to try to incent to bring that up
and we did make those changes.
Now what I'm looking at is several things
It has to include both ancillary services.
It also has to include, I believe the realtime energy
and whenever we first did the ORDC,
we didn't use what we call the
cumulative distribution curve, which is what we use today.
That's what's in the curve when it was approved
and that's based on inputs from forecast error
and a few other inputs that come into that I believe
and then you get your curve
and then the only way really to adjust that curve,
it's the curve itself
and you keep hearing the standard deviation,
you change the standard deviation and that moves the curve.
Doesn't really change the shape,
but it changes the curve moves it to the right.
So when we originally did this
and the original ERCOT filings for the ORDC
had what we call a piece wise linear
and I know I'm the only one that uses that term,
but there's some other curves out there
that are similar to that, that was in some other filings
and why would I push to do something like that?
What you can do is instead of changing standard deviation
and the whole thing just moves,
I can move different pieces of that curve
that I want to get the economic outcome that I want
and that's where they'll have a problem with that
is that the curve goes from just a distribution function,
you decide on an economic outcome
and then you can shape that curve in the manner,
you want it to get that economic outcome,
and that would drive forward prices,
it's not gonna give you all the money,
but it'll give you more money into the market
to try to incent that the investors can rely on,
on a more regular basis.
So that's what the reason is for that
and there's two other things that we think you ought to do,
but that's the reason that you'll hear Katie and them
complain about it because it is as she would say made up,
I don't believe it's made up.
We will study that and make sure that,
we have Brattle do it for that matter to say,
what do we need to get a minimum of 12.5%,
along with the other changes in the market,
'cause it all goes into that figure.
So there's ways we can do that,
that are done by a professional that knows economics
that could get it done for us.
The other thing that we think you need to do is
since we are buying more reserves,
that means we value reserves more,
which means we should protect more
and we believe that you should move
the X factor we called it, which is now 2000 megawatts
that's when you hit ball, move that to 2,500,
at least somewhere in that neighborhood,
or you could change it a little further
and make it a function of load growth and as load,
or you can call it net load,
whatever you want to use for that factor
and you can move that number based on that also
to where you think it needs to be for,
what do you want to protect for reserves.
And then the third piece is dropping the cap to 4,500
and I think what that does is it doesn't
and by changing to a piecewise layer,
moving that over X over and coming to 4,500,
you can get the revenues you want without relying on
having to get to a $9,000 price
that this will get you where you wanna be at a lower price.
If we'd have had 4,500 in that curve, instead of 9,000,
we'd have been in a much different place today
from a market standpoint,
not from a human tragedies standpoint,
but from this standpoint.
So that is the reasons that we say do those three things
and that's all in the filings.
With that I was just kind of move on
to the ancillary services,
a lot of that's been talked about already.
I was really happy and pleased to hear the conversation
that y'all had just a minute ago
after Just Energy was up here, saved me a lot of talking.
So you don't have to listen to me very long
because that's really what we're after
we agree with where that is,
we need it, we need to know what it is, what level it is,
and just make sure that it's transparent liquid and stable.
So that's where we're along with them on that,
so I'll skip right through that one.
The next one is the any new ancillary services.
The way we look at it is we need to be looking at,
ERCOT need for reliability and what they say they need
for reliability and not the other way around.
So we're a little concerned about that
and so we wanna make sure that anything that comes out
as a new ancillary service is directly tied to
a verifiable reliability study
or something along those lines that says
here's what we need and for an example,
the ramping product, yeah that's used in other markets,
it's a good product can be used,
we're not necessarily opposed to that.
The only problem we've seen with it.
So just to let you know, if you do go that route,
some things we'll have to consider is
in the Southwest power pool, we're trying to do that also.
We're having problems with trying to figure out
how to deal with uplift
and uplift is not very good for the mark,
for spit out here for our EPS either.
So that's just a comment on that.
After listening to the last panel,
I think there's another decision
that the Commission is gonna need to make
and that is when does an energy only market not become
or not remain an energy only market.
I think that, and I'll use the capacity word.
I think that the proposals earlier you have to question that
is does that change us from an energy only
to a capacity market?
The question would be is what is a capacity market?
Is it a formal centralized procurement, which they are,
is it one year, three years, six months?
How would you define a capacity market to make sure that,
you'd have to ask those questions to say okay,
are we ready to end that energy only market
and go into some type of a capacity component
outside of our normal ancillary services?
So also we believe that raising the current
ancillary services is okay
as long we know the right amounts
and like you said, at the right times,
but a bigger amount is fine
as long as we know what it is, we're fine with it.
We can go out and hedge that moving into the future
and my guys can go out and buy the 2024 ancillary
services that they're holding off on
'cause we don't know what's gonna happen.
So I would say that that would be another one for us
to look at.
Let's see, I'm trying to see if I missed anything.
When you come up last, there's good and bad.
The good is you could kind of shoot holes
sometimes the bad is
everything you wanted to say is changed.
So I think with that, oh yeah, talk about,
you talked about voltage support,
let me address that question.
All generators have to supply voltage support.
So I just wanna make sure you do
that the way you were talking.
I wasn't sure if that's what you were saying,
but for voltage support, everybody does,
that's a requirement for ERCOT for reliability and.
-: So what was Woody concerned about then?
-: Woody was concerned about inertia.
-: Okay. -: Which is a different
service, which yes we will be needing
to look at that in the future.
I think there are ways to do that,
but that's another discussion we'll need
where we haven't quite got to a complete need for that yet
that is what he was saying, but we have got close.
-: Well, I think when you get to the point
of complete need for that,
you don't have a function grid anymore.
-: Right yeah.
-: So we don't want to get closer.
-: No I was saying.
-: This was not a lab experiment.
-: And that goes back to what I was saying.
When ERCOT says, I need it
regardless if that's today, tomorrow,
or next week or next year,
then we need to get on the ball and get it done.
So I fully agree with that.
But that's from the standpoint of, like I said,
with the other ancillary services
that ERCOT has to come and say,
we've got an issue coming in the future,
we need to resolve it
and then we go out and resolve it as a market
and I think with that, that concludes my thoughts.
-: Thank you.
-: Open for questions.
-: Questions, comments.
I'll give you one question that
merges with the Exelon conversation
about the art of picking,
how much of those ancillary services are needed
and reconciling that weather dependent,
renewable resource with reliability
under that framework, just by example,
I'm not endorsing it or saying,
it's the way we should go.
You could do you discount those risks, yeah
an intermittent resource
that doesn't have a dispatchable enhancement like batteries
or co-located compressed air or something.
-: You would have to, they do,
ERCOT does that today with all their ancillary services
-: Right but that also doesn't work.
-: Yeah, I know that's why I was saying
having ERCOT look and see
at what level of reliability in real time they want,
and then implementing those ancillary services to do that
is appropriate.
-: So I guess, I mean, is there from the Dow
example or the graphic it's anywhere between 2%
and 98% is that.
-: That's right yeah and that's not on purpose.
-: Right I mean, that's just the nature of the resource
and it has features, which will point it out.
-: Right, so, and that's, everybody's challenging,
that we're having across, Southwest possible.
All right so we're all trying to figure this one out.
-: Well, we've got to figure it out pretty quick
and as Commissioner Cobos correctly pointed out,
there always seems to be a gas generator behind the meter
when you need it.
So what, huh.
-: To pay for that.
-: Right you gotta pay, you're paying for reliability.
-: Right.
-: So is there, whereas this is just gonna,
you're gonna how do we get to that number?
How do we get to that?
I mean, we know what the ERCOT numbers are.
We saw the Zara study.
-: I'm gonna agree with Randa.
There's some really smart people out there
that we would need to sit down and talk to on how
we could get to that number,
because I'm not smart enough to do that one.
-: Okay I guess let me put it another way.
If you look at the Dow data set,
is there any universe where you don't discount it
to that 2% scenario?
-: You can discount whatever is appropriate
based on the studies and what you're looking at.
The reason the CDR is where it is on those
is we elected back.
I forgot what it was, I was on the board back then
to use the past average,
I think it's, five-year, I forget the exact number now,
the back average of on peak for those resources
and that was just the election we decided to go with,
and we thought we could manage it from that standpoint,
if that needs to be changed,
then that needs to be looked at.
-: That's what we're here for.
All right thank you.
-: So Bob another question in terms of things to consider
are these ancillary services again,
how much time do your generators need
in order to absorb that?
How much lead time should we consider here
on a generator side or- -: Yeah on generator side
market construct side.
-: That gets really difficult 'cause most of those contracts
are 10, 20 years.
So without affecting a contract,
I don't see how you can do it.
-: Let's see how I make move as a Commissioner
without affecting a contract.
-: That's correct, correct.
-: So okay.
-: Yeah oh, one thing I did want to add,
speaking of contracts,
it was mentioned just a minute ago also depend,
I don't know how his contracts are set up,
but the you'd like other generators,
the only way renewable would get the ORDCs
if they were long in the market
and if we're not long in the market,
we're settling with our contracts,
outside of the ERCOT, ORDC, it's included in there,
of course, because of the settlement point prices,
but that's all contractual and that doesn't flow through
the way you would normally expect someone that's long
in the market and get to the ORDC.
-: So if you explain there. -: There is some nuances there.
-: So when you say long is that commitment,
how do you mean long?
-: Yeah like, for instance,
if I'm a pure merchant and I go into the day ahead
and I don't have anything out there
that I've got scheduled on the other side,
then I'm getting whatever the LMP price is.
Now, if I've signed a bilateral contract
and I've scheduled 100 megawatts in on the gen side
and 100 megawatts in on the load side,
then I've netted out and there's really no RDC there.
-: At the $60 or $20, whatever you set that price at,
regardless of what they already sees, $500.
You're not, you're still clearing 25.
-: Your still clearing.
The only time it would hurt, which it did.
I will say during this unfortunate storm is if,
based on those contracts,
if wind doesn't perform or solar doesn't perform,
they get hit outside in those contracts
the same way other generators do.
-: Same way, that's why they're very interested in a cap
and a moving up the curve left.
-: A lot of generators are.
-: Right.
-: So the, I guess what I think I'm hearing is the only,
the most important times ORDC comes to play
when a generator of any nature can't cover its commitments
and is short, and it has to go pay the extraordinary prices,
which of course were then passed on to consumers
or if they're just a merchant generator.
-: They are from bilateral contracts,
they may just need it themselves.
-: Yeah.
-: Sure but it only hits the consumer, I guess,
or the balance sheet of a generator if they're short
or they just happen to show up without having any.
-: Yeah.
-: Without having a PPA,
in which case it's just a lotto ticket.
-: Poor faith yeah without people.
-: They'll cover 80% of their generation would be with
bilateral contracts and take the last 20% of themselves.
-: Yeah so some will do that yeah.
-: So that kind of goes to.
-: And some of that is hedging.
-: Yeah I think this kind of goes,
I think this line of discussion,
but maybe after I'm gonna turn it on its head.
But I think Bob said earlier that
most generators have financial hedges,
so they're not getting the ORDC.
Is that what you're speaking to right now?
-: No, no those hedges are, those hedges,
I'm trying to think
that depends on how that comes through ice
and how it gets scheduled at ERCOT actually,
I think that'd be the easiest answer for me to say,
cause we do try to hedge that and we're hedging that
we did have some hedges for being short.
They turned upside down on us.
So we lost money also
So you can hedge and lose in some cases also.
So I'm not the one that's doing the hedging for NG.
So I'd hate to go much deeper than that.
-: Can you explain,
then who's getting this pattern.
-: Who is not getting it.
-: Who's not getting it right.
-: Yeah who's in and who's out on the ORDC.
-: Who is in and who is out is who is out,
is anyone that's taken a commitment
and provides that commitment.
They don't get it the same way.
That means also if I have a bilateral contract
and I have scheduled through ERCOT,
so many megawatts coming in so many megawatts going out
and that's equal,
then that would be settled that way it nets out.
It's only whenever you have imbalances at the settlement
point price, does that get paid out or brought in.
-: And that's paid out based on.
-: The imbalance and where we're at on the curve.
-: Okay so how does SCAD and low cost dispatch fit into this.
-: Dispatch and low cost?
-: Yeah so SCAD lease costs.
-: The SCAD yeah.
It's economic security constraint
and it's looking at everything out there
and if I'm scheduled out there,
I've also have offers in, on talking more thermal,
but we do have some down, we have to,
have offers for down also as they go through,
they'll go up and down your offer curves
and then you'll be working in the most efficient way.
So you'll be coming in and out of that, depending on.
-: So let's just say X kicks in
and we're writing the ORDC curve
and so who's capturing.
-: Okay, now let me get into the way that kind of work.
Let me use a schedule in and schedule out ERCOT
and then say, I have an offer in there.
I've got more generation leftover, say the 20%
and SCAD takes me that extra 10 megawatts at 20% I have.
Then there's an imbalance in that settlement point,
I have 10 megawatts more than what is scheduled.
So there's an imbalance and since I'm over producing,
I would get the revenues from that,
which would be include the ORDC if there was,
if by chance I was dispatched down,
there's an imbalance there also
and with that imbalance, I would be charged for that.
-: Okay cause I'm just trying to think about how.
-: Now same thing goes with the load too
I mean, it hits load the same way if they're short or long.
-: Okay so what I'm trying to assess is how,
ORDC interacts with low cost renewable generation
that has low marginal costs
that reasonably would be dispatched
based on at least cost model.
Can you speak to that a little bit?
-: It's all based on just what I was talking about,
how those contracts are written.
Now there is, I won't put a caveat on this for right now is
since URI, the renewable contract world has gone crazy
and there's a lot of questions about how the contract
now forward on whether you do some of these from
and do these contracts like like this,
or if you turn around and you do unit contingent,
there's a lot of things being looked at right now because.
-: Contracts can be changed.
-: Well, that's the ones we're signing, coming up.
-: The ones that I already own.
-: Yeah that's the ones, that's going forward
for those contracts for today's contracts.
That's how that works, go ahead.
-: The only thing I would say is the one thing that the ORDC
does do is it affects the forward curve
and the forward curve allows you to either
get a sort of broader, higher level of revenue
or a lower level of revenue
and that allows you to either build,
renewables or even conventional generations.
-: it affects the hedges, which affect the forward market,
whichever everybody absorbs and books,
ahead of the real time.
-: Right. -: Right, yeah
and that goes back to the Myrtle and the ORDC changes.
-: Right.
-: Just thought I'd circle back to that.
-: All right thank you.
-: Thank you for this time. -: Appreciate it.
Turn it over to Denton to bring us home.
-: Thanks and always great to be last.
So let me, I'm Terry Naulty assistant general manager
at Denton municipal electric.
I'm here on behalf of Denton
and just to give the Commission some perspective on
the municipal segment, we're a small,
relatively small municipal utility,
but we operate as a non opt-in electric, non opt-in entity
and we run a vertically integrated utility company.
So we're really, we're not in the market,
but we're in the market because the only way that I can
deliver energy to my customers is to buy it from ERCOT
and the only way that I can monetize the value of my assets
is to sell it to ERCOT.
So we're in the market, but not in the market.
The municipal segment is about 15% of the ERCOT market
with about 10,500 megawatts of generating capacity.
We serve a little over 5 million Texans
and so it's a pretty significant portion of the market.
Our generation represents what some would call the backbone
of the ERCOT market with a very diverse mix of nuclear,
coal, natural gas, hydroelectric, and renewables.
I think our focus is on real cost-effective reliable energy.
Because as a load serving entity and a generator,
my obligation to my customers is to keep the lights on
and during the February storm, I couldn't do that
and that was a real problem
and for us as a vertically integrated utility company,
relying on the ERCOT model,
the only thing I could tell my customers was that
the reason I can't keep your lights on is because of
the way the market is structured
and what happened in the market
as a market participant, we have to reduce load.
So as we think about market changes,
and I'm very encouraged to have what I heard today
from some of the panelists,
we're certainly interested in a well-functioning
reliable market that provides competitive stable rates
and it also needs to allow the municipal model to work,
which is a model,
that prioritize the individual priorities of communities
and in Denton's case,
it's we want to be 100% renewable community
and so those individual
things that are important to municipals
have to be able to be accommodated in this market.
Is she's not gonna put up my slide.
-: Sure we can, we'll get to them.
I'm sure she'll be back soon but if.
-: Okay let me just talk a little bit about
what our portfolio is and because I think
it answers some questions that I've heard today
about types of resources.
So we're 100% renewable energy community.
We have about the numbers here,
if I had my slide up, I could give you the exact numbers,
but we have roughly 500 megawatts of renewable energy
that we've contracted for under long-term contracts.
One of which is with NG,
we also own the Denton energy center,
which is a quick responding reciprocating engine plant
225 megawatts and it was a cornerstone
in our renewable energy plan.
-: So that's a natural gas facility.
-: Natural gas facility,
and it has the ability to respond to the market prices
in five minutes,
it can go from zero to 225 and five minutes.
-: Help me reconcile your statement that you just said
that you're 100% renewable
and in your filing, the next sentence,
it says that you built a big gas generator to back up
the renewables, to fill the gaps in your renewables.
So while I appreciate this'll be the Dow demonstration
of 98% to 2%, and then the steady gas line
very much appreciate why you would do that
for your customers to ensure reliability.
I don't know how that reconciles as 100% renewable.
-: That's a great question and one I get all the time,
but yes, the key to being 100% renewable
and that is measured on an annual basis.
All the megawatts that are consumed by the city
have a rec associated with them from a contracted asset,
the generation so the actual natural gas generation
is used as a financial hedge
against those inevitable periods in which
our renewable portfolio is not gonna perform.
We have to have a financial hedge against that situation
and we've experienced obviously some episodes
where our portfolio had zero output of renewable energy,
and we relied 100% on our gas generation.
-: So to get to the threshold of on an annual basis
saying you're a 100% renewable,
you're going out and buying additional renewable megawatts
to offset those, to take care of the natural gas
generated megawatt.
-: Yeah, I think the way to think about it,
chairman Lake is we operate our renewable portfolio
in the time market, just like everyone else does
and we use that.
We're just selling into the market
and then we're buying from the market for our load
at whatever the market price is as well.
Those two offsetting positions on an annual basis,
if they're zero, if we've had enough.
-: You're saying your renewables on an annual basis,
your renewable fleet generates enough electrons
that go somewhere in the ERCOT system
to match your entire load for that same year.
-: Yes, sir.
-: Okay but the get- -: But in the meantime
your burning gas to keep the lights on?
-: Exactly.
-: I just want to make sure I'm thinking about this, right?
-: The physics of the system are what they are
and we have to deal with.
-: Okay, I mean, I get why Dow has the blue line there,
I just, it's tricky to match that up with the,
so the point being is somewhere on the grid,
somebody has gotta be burning natural gas.
-: Absolutely. -: Okay.
-: Absolutely.
-: And so, I guess the point I wanted to make is that
we've been able to do this
and we've remained competitive.
Our age, the bottom graph shows our rates
are right in the middle with the competitive retailers
that offer 100% renewable energy as well
and I'd say even with the non renewables,
our rates are very competitive with them.
So we believe that this is a business model
that demonstrates that a market with
high renewable penetration can in fact provide low costs
and we believe that the market redesign needs to continue
to access those low cost,
renewable energy resources for the benefit of rate payers
in all cases.
Lets go to the next page.
So the truths, what I think about the market,
where the ERCOT truths,
this intermittency is gonna dominate the market
by driven by the things that are listed there.
We live in a society
where people want the environmental benefits,
the ERCOT transmission grid,
incentivizes the continued development of renewables,
tax incentives continue to provide a level of subsidy
for these assets that benefits rate payers.
We want to take advantage of that,
I think all Texans want to take advantage of that.
We do know from our own experience that the intermittency
during peak demand periods is highly likely,
and this doesn't mean that we should build roadblocks,
to low cost renewables,
but rather we should design our system to take advantage
of those low costs, renewable energy.
I'm concerned that because the PUCT cannot drive
weatherization or mandate weatherization
that the weatherization may or may not happen
as I sit here today I can't tell you that I've seen
a high level of probability
that we're gonna actually achieve it.
We didn't have
choose that one- -: Weatherization.
-: On the gas system.
-: Okay we just issued weatherization rules, okay.
I'm just point of clarification.
-: Delivery system.
-: Do you need to go back and rewrite that.
-: No, no and I bring that up only,
(members laughing)
I bring that up because,
if we're gonna rely on weatherization,
to build that reliability
and that weatherization includes the gas delivery system.
So we think that you should drive policy to increase
reliability based on what you can control
and that weatherization of the gas delivery system
is probably not something that's easily controlled.
-: What do you think we can control?
I mean, when it comes down to that crux, I mean, I said,
I think critical load, ignition and fuel security.
-: Fuel security is what you can control
by mandating certain types of fuel security
and whether that's dual fuel
or whether that's some higher standard of from deliveries,
all these things cost money,
significant monies that ultimately load is gonna pay for,
but that you do control absolutely.
And I guess the other last thing I'd say about
the current market is that in our assessment,
the audit does not provide sufficient cash flows
to incentivize new generation
and so any solution that you come up with
needs to change that paradigm.
So we think that it's a multi-pronged approach.
I think it's been discussed here.
It's not different from what we've heard
from other panelists,
but changes to the Arctic are needed.
I'm not gonna get into,
the details of what those changes are.
They're way more qualified people that understand
the math better than I do.
We think that if you make drastic changes in the ORDC
and rely on it solely to fix the reliability problem,
that there'll be unintended consequences
and that any changes that you make
require some level of track record in order for
financers of generation to actually
deploy their risk capital into those markets
and that will take some time.
So we think that that just ORDC changes can achieve
the reliability fixes that are needed
and we believe that you should look at
the amount of dual fuel that's needed in the market
from existing generation.
That any dual-fuel capable units like black start units,
for example, to the extent that they're firmed up
and become more reliable,
not subject to the types of fuel interruptions
that reduces the amount of incremental generation
that is needed in marketplace
and so we're suggesting like others,
some sort of form of grid, reliability, service,
ancillary service charges to order to get that money
into the marketplace, to pay for that dual fuel
and then secondarily on the next page
would be new cost some way for peaking generation
to be built based upon an analysis that shows
how much additional reserves are gonna be needed.
Now, one thing I'll point out
about the technology selection.
-: What I can tell you is when I look at these numbers
and I see the proformas that you've been shown today,
the forecast,
all those are based upon the forward curve
and the forward curve is really a,
is a hourly in its current form.
The way most people would look at it would look at the
hourly scalar or the hourly cost,
for each hour of the next five years.
And the Denton energy center,
which can respond in five minutes.
It achieves incremental revenues as a result
of its inter hour its ability to re react inside of an hour
inside of five minutes
and we're glad to share with the Commission,
the historical performance of that,
that extrinsic option value
that it's able to achieve is significant.
So the right type of technology can drive higher returns.
It's not as well documented, I mean, it's still a little bit
theoretical about how much,
but there is data out there you can see from the 15 minute
settlement, if you had a machine that was able,
to react to those 15 minute and the five minute prices,
there's additional revenues that can be achieved
that will drive returns up higher and keep
and if you specify the amount
of additional generation that's
needed and it's of that type,
the cost to the consumer should be lower
and we do support reducing the value of loss load
to $2,000 or thereabouts until you can get
enough generation built to
address the reliability issue.
We do not support any changes to the
intermittent resource offering that was discussed
and I'll just say that as a buyer of renewable resources,
I'm long that position at a fixed price
and to extent that there are scarcity premiums
that are available.
I achieve those scarcity premiums as the buyer
of that fixed price energy at a nodal point.
Now that's offsetting the price that I'm paying for load.
So it's a net zero effect, but there is,
there will be basis differential will be congestion costs
between those points.
That's important to keep in mind as well.
So there is value for those of us
that have entered into long-term contracts
with renewable energy resources,
to be able to continue to achieve those scarcity premiums
when they're available,
because I'm gonna have to pay it
on the other side for the load
and I need that for a financial hedge.
The other thing I'd point out is that
when you make changes, the contract changes
that Commissioner McAdams is worried about
that I'm worried about as well,
changing law under those long-term renewable contracts
means that I'm either gonna terminate a contract
or I'm gonna end up having to pass through costs
to my customers
and the customers are the ones that ultimately will bear
the costs of any of those changes
and I think the Commission should keep that in mind,
as you pursue that.
So with that, I'll be glad to answer any question.
-: Commissioner McAdam said it best earlier when he said that
any meaningful changes we make as directed by
SB3 will result in a lot of contracts being changed.
Don't know which ones are how, but that's just
gonna be the nature of a meaningful change.
Questions, comments.
-: Page four.
Sir, all market participants should bear the costs
of these incremental reliability costs,
all market participants.
Can you define?
-: Yeah that is all market participants.
I mean, I believe that I'm not just load serving entities.
-: Okay.
-: But hedgers traders,
everyone should bear a cost,
a portion of the cost to participate in this market
and if the market is gonna be viable,
it has to be reliable long-term.
So why do we want to just push the costs solely to the load?
-: Got it thank you.
-: All right thank you very much I appreciate it.
That's our last formal panel of the day.
We've got Barbara and come on and yeah.
We'll to come up for our concluding comments.
Yeah, I can not highlighted that.
He's fourth in a row, he's been in here.
-: Everyone is tired.
-: Immediately after saying that,
I realized that all three of you are here
the same amount of time, and I'm complaining
to the wrong group of people.
-: We sort of work here. -: Its okay.
-: You don't.
-: I'll put in my time,
this is slated to be our concluding Commission conversation
with the goal of identifying key points
that rose to our attention of course,
we'll provide more in depth guidance
for stakeholders next week per our schedule,
but a chance for us to discuss key points
that we thought were of interest today,
and perhaps some quick thoughts on where we
themes to focus on moving forward
as we continue through this process,
a few things that jumped out at me, reliability standard,
establishing that reliability standard
obviously is a key component
as we've talked about this extensively,
but need to screw down on accountability
and associating the accountability,
of showing up with what came up several times a day
in terms of moving the revenues to reliability,
dispatchable, all forms of dispatchable assets,
importantly not excluding intermittent weather dependents.
If they have farming capacity.
We're gonna get to the demand response next work session.
Obviously a lot of opportunity there,
voltage reduction, increased precision,
in granularity and load shed,
and then paying for what we want
paying for the outcomes we want
of course, being the broad theme,
not trying to pick the inputs
and one of those outputs that we want is I think inertia,
and we certainly don't wanna get close to
going over the edge or lack of inertia.
So I'll open it up for discussion to the board.
-: I guess I would add
to your point about the reliability standard.
I think focusing on ensuring
that we have the appropriate liability standards
sounds like one in 10 year liability standard
is the utility industry standard.
But also determining
the amount of dispatchable generation that's needed.
and what's the difference between what we have now
and how much we're gonna need, what's that Delta
and does that help us meet the reliability standard?
How much do we need to meet the reliability standards?
So updating the loss of load probability study,
which ERCOT mentioned they were in the process of rerunning
having independent third party analysis of
some of the market design changes
that we're looking at right now,
like ORDC changes and ancillary service changes
and anything else we consider
I think is gonna be very important,
including if that same consultant or another consultant
can look at the gas supply pipeline aspect of the market.
I think that's important as well.
-: Good point.
-: Does anybody else think the current operating plan system
in ERCOT is not what we want?
Does that jive with the enhanced command and control,
goal that like he says we need?
-: The jobs was enhanced command and control
and visibility for our grid operators to know
what resources do they've got
when they're gonna have it
and that also overlaps with making sure that
the resources they need
are the resources that get the economics.
-: Yeah, I mean, so, well, anyway,
I want to hear everybody's thoughts on that
if it's just the way caps are submitted determined,
I mean, would he sitting there kind of playing chicken
it's somewhat disconcerting,
to watch this process in play out
and from an operational standpoint, it just seems, no,
we need something more
and then it kind of feeds my logic on
any type of forward commitment,
but the points of market participants are well-taken.
If that means ancillary services,
are a component of that to incentivize that
all well and good,
but it lends itself to greater visibility
on the operator's part to be able to make decisions
before we get into game time.
-: Or crisis mode.
-: So focus on refining real-time operations
through better visibility to the caps.
I know there's an information we got today.
I think what he's been saying that he is struggling
with the caps for probably years mow.
-: Yeah and it's come up through stakeholder processes
in ERCOT when you were watching it.
So it just seems like a consistent dissatisfaction.
-: Yeah and I think in practical reality,
there's some disconnect with trying to improve that
and then that sounds like on the generation side,
there's some challenges as well,
or they're having to deal with forecasting as well
on a daily basis.
So trying to marry that up together to come up with a
better caps, and I'm not sure what that is.
-: Well and better caps,
but also harmonize the economics of that.
So it is not disruptive.
I mean, I think that goes to what they were saying
is that if you tinker with the caps,
this is a major data point that everybody bases there,
forward projection, but also real time,
expected time commitment and activity in preparation.
So that's kind of where my head has been
and that's why, have been harping on day ahead so much,
It's just because it seems to line up with that system of
administrative control and then, where the actors
or the generators are in terms of position
to be able to perform so.
-: Don't you think it's also important distinction
that you can offer into the day ahead market
and not get cleared.
-: That's right.
-: Right so that's no,
just because you show up doesn't mean that
you're gonna lose money because you may be forced to,
I think it's the complete opposite, right?
Like you're not gonna get clear in the day ahead unless.
-: It goes through the same security constrained economic
dispatch that the market goes through and you may,
or may not clear, you may not,
we make clear energy and not ancillary services.
There's, the engine is gonna run based on the economics
and the system need based on the forecast for that.
-: Whether or not you wanna buy gas for the next gas day
before, you know how the dam clears,
that's a different operational issue.
-: Yeah that's right.
But doesn't the mint Okay.
So, and another takeaway for me was, again,
menu of ancillary services, more targeted ancillary services
based on performance measures
that we want to purchase procure.
So that seems like it does jive with a more forward look
on what type of ancillary services we're gonna need
again for the retailers to take that into account too,
on a seasonal basis, what that seasonal forecast looks like,
what the rolling average is of
seasonal intermittent variability are,
so I think just more of a comprehensive look
at how the caps currently are formed and submitted
what ERCOT operations sees,
in terms of that interplay
and then how we can try to smooth out this ruck system
with the ancillary service, get ahead of that.
So we don't need to ruck.
So that essentially our ancillary services
is filling that void on a more basis.
-: Yeah it's the ultimate goal.
-: So just so I could,
so kind of the list that I provided earlier,
I think is sort of a level set
from my perspective let's level set our data.
-: Yep.
-: Get those studies done
and then I agree with you Will Commissioner McAdams that,
we did hear about a new suite of ancillary service products
that we got some information on
probably needed a little bit more,
but we can start sort of,
kind of narrowing down what some of
those new AS products are looking like.
It seems like there's some commonality amongst the different
products we heard from Denton and Exelon and LCRA
and a recognition that these new products will target
issues that we're currently experiencing right now
with trying to stabilize the grid
and the variability on the grid.
ORDC, I think there's know almost uniform agreement
that alone is not gonna move the needle.
-: Correct.
-: And so, as we look at that mechanism,
running simulations on different runs
and seeing what it does from, with a third party,
but, just recognizing that alone is not gonna get us
what we need.
We're gonna have to look at
the ancillary service markets as well
and it seems to me because of these ancillary service
markets being discussed in SB three,
that perhaps thinking about whether we want to
open up a rulemaking project to get more information
and refine stake holder comments at some point,
whether it's, not necessarily today,
but to consider that so that we can get more tailored
stakeholder comments on those new ancillary service products
that we heard about today.
Like the dispatchable reliability service
fuel firming the winner.
-: Yup.
-: Okay, considers rulemaking or open a dock on that
and we could also use the milestones of the Commissioner
guidance as we go through them.
-: One of the others are more key takeaways.
Now I want to see if you had thoughts on
it sounds like ORDC is not as impactful
for the bulk of intermittent resources by nature of,
again, the bilaterals it's a consistent thing that comes up.
-: Or maybe infrequently felt,
but incredibly impactful when felt.
-: Yeah, no that's, I think that's accurate.
So, but again,
any enhancement to ORDC is that going to,
is that gonna have any unintended consequence on,
I don't know and how it's deployed, what time,
what are the conditions of deployment.
-: Right, the X factor in the minimum contingency level,
should we increase the X?
We heard a lot about lowering the cap.
Some stakeholders provided us with specific numbers
to where to lower the cap to others have not
just said they just provided lower the cap.
Maybe we need to get stakeholder comment about,
what's specific to what specific number.
It seems like everybody's been kind of coalescing around,
well, not everybody, but it seems.
-: Like two to four thousand range.
-: Yeah 4,500 being the highest I think,
and so getting a little bit,
cause that is an important mechanism, right?
As we are in this energy only market,
and we don't have hit the price cut very often,
but in terms of we are gonna change the ORDC
and there's, I think majority support for lowering the cap,
we're gonna change the ORDC to what number
and while we're at it, thinking about,
are we gonna change the X,
what are we gonna do with the standard deviations?
Just to run simulations, to see what it does.
-: Yeah and we don't have to be married to
the previous logic that dictate that there's different.
I mean, if the goal is to get assets on the sideline,
into generating posture,
we might need to look at heat rates and sparks spreads.
I don't know.
-: And how do you define reserve?
-: Yeah well, again, what's your target is
the other thing I want us to remember about ORDC
what came out is the ultimate impact of ORDC
is on the forward prices,
'cause everyone's having to hedge to avoid the thing
and so when we do, when, again,
I think we need to analyze cap submission,
how that interplays the command and control for ERCOT there,
tied in with their reserve margin,
that they feel that we need a target reserve margin
and then ORDC and what it does to shape
or enhance those forwards.
Because again, that's good money into the market,
theoretically for dispatchability
depending on how it's designed.
-: Yeah. -: Right and how do you,
how would you design it to just provide money
to dispatchable generation,
if that is the will of the Commission, right?
So how would you do that?
How, maybe a function of that is defining
what a reserve means
and so the other piece that I wanted to go back to
in the ancillary service suite is the black starts.
It seems like there could be some improvements there
as well so that may be another avenue that,
or another area of sort of product that we need to maybe
look at it as well,
to ensure that when we need those black starts
that they're available,
we didn't have problems during this last winter storm
with those units and I think pricing them
and ensuring they have field security
and really doing a robust analysis of those units
is also important if it's not gonna necessarily,
I don't know that that's gonna be move big needles,
but that's also something, as we look at our market design,
we're looking at ancillary service products.
We should be thinking about
if there's anything we need to do with Black start
and I know ERCOT has been doing some work on him,
but maybe we reign it in
and bring that information together
and make sure we got that suite.
-: Yeah, I mean that plays into the overall resiliency,
package that you want.
-: Commissioner Glotfelty.
-: I'm just sitting down here listening,
new guy on the block, taking it all in,
I think there've been great ideas today,
great discussions on ORDC
and I just wanna make sure that we realize
that whenever we do some implementation,
there's gonna be some reaction by the market,
hopefully positive,
but we think there may be something negative as well,
but it will adapt, I do believe it will adapt.
I just, I haven't totally gotten my head around
all of the things that I think we ought to do.
So this has been hugely helpful today to hear,
Barbara, what you put out in different markets
and I think it's really a really good Blackboard
that we have of ideas that
we're gonna end up coalescing around
that is gonna really improve this market
for the good of reliability.
-: Yeah great.
-: One thing I'll urge you to do as you kind of liberate
is that market design sometimes takes time
and is complex and requires system changes and things
talking to stakeholders about near term solutions
with the current suite of products,
i.e how ERCOT is managing the additional ancillary services
they're procuring and more transparency on that.
So that loads really know what their obligations
are gonna be they can start hedging around
at what ERCOT is going to be doing
related to those ancillary services.
All of the things that we're gonna be doing
through kind of sometime in 2022,
because these other things we're talking about,
although you can do them somewhat quickly,
but much of it's gonna require some level of system change
and effort on behalf of ERCOT
at a time that's already, there's a lot going on.
So looking at how we're managing the system today
to make sure we're sending transparent
and non-discriminatory signals around the market
is also something I would say to get some feedback on that
and what people think kind of is the,
the next 12 months versus,
the future of the ERCOT market and the future design.
-: So could I opine on that a little bit?
So I worked over in the legislature for a bit
and we have to start somewhere
and so hat's the problem.
My term runs out September 1st, 2025,
and I do not want to be catching a falling knife
of 70% renewables on our system,
dominant fuel source and trying to back it up.
So I do need the market to understand now that yes,
me personally, I don't expect a lot of significant
design change immediately come January one,
but I do expect us to start conversations
to where this market adapts to the resource mix evolution,
to where we do not suffer reliability issues moving forward
and so that we are moving in a tandem
with the way the ERCOT system is evolving
and that's ultimately how I believe
the Commission should proceed
is to start those conversations,
get them in study and get us on the implementation schedule,
to where the market knows what to expect and how to comply.
-: Long as it's consistent with the legislative direction.
-: That's true.
-: And we, I think we, like I said earlier,
we need to find the balance of recognizing,
I think Mr. Stone said it that,
well you made a good point of this earlier.
Like this is a lot of this was designed around
natural gas as a base fuel.
We've got different opportunities for new technologies,
and we certainly want to take advantage of the opportunity
to generate power from a zero marginal costs intermittent
instead of burning $4 gas during the times we can,
but not at the expense of reliability for Texans
and so we've.
-: In the economy.
-: In the yes, absolutely all the jobs
these businesses create
and so we need to,
we need to recognize the new opportunities and realities
that are facing the market,
but avoid letting the tail wag the dog of our market design.
We should make sure that we always keep as our North star
reliability and affordability and a competitive construct
that ensures that the market design
dictates the outcomes we want for our state and our economy.
-: Great.
-: Any other Canaan or Bar any other parting thoughts?
-: I guess, just to manage expectations in terms
of what I think Barbara kind of touched on this,
but without, trying to prejudice the merit of the proposals,
generally, what I would say is the ORDC changes
are easier for us to implement quickly.
I would say that there will need to be a substantive rule
change if you wanna move all off of $9,000.
So that might be something to contemplate
and I would say the ancillary service type changes,
not that we would wanna we need to get after it.
So I agree with that point,
but that will take longer as I try
and get those into my systems so that they move from
the day ahead market system
and to getting dispatched and so forth.
So there are system changes associated with those.
So I just wanted to share with you kind of that
in terms of how quickly we can turn things around.
I think the AS type things
are slightly more time consuming,
The ORDC can be done fast.
-: I appreciate that.
-: So ORDC quick change may require PUC rule change
the ancillary services.
One thing that I think we need to consider
if we're going to move forward with these new products
is trying to put as much, (clears throat)
create as many guard rails as we can
over here at the PUC so that we can get them done,
hopefully a little bit faster at ERCOT, right?
Because if we just send a direction,
then it's gonna be purely stakeholder process
market will change
and I'm also wondering if EMS upgrade
impacts any of these new products.
-: It is likely to fight for resources
with implementing ancillary services
and there could be some lockdown time periods
where we're trying to stabilize EMS in terms of when we can,
we might not be able to even introduce the changes
into that system while it's trying to be stabilized.
We will do the best we can to fit all that in.
and I do wanna emphasize that all the ancillary services
don't necessarily work the same.
So for example, black start is procured,
not on a daily basis,
but on, I think it's a two year now basis.
So something that works like that would look different
than something that I have to kinda clear
with optimization with energy and ancillary services.
So that's why ECRs might take longer than maybe a change
to black start.
So there is a differences within
even the suite of ancillary services.
-: And to be fair
and I think the PUC rules at this time don't have a lot of,
I mean, all our products are in our cup market rule.
So the only difference here I think would be
to consider whether these new products would be better
housed in PUC rule to provide more regulatory certainty,
or you set up sort of the framework,
and then you let ERCOT implement
through market rule the details.
-: True I mean but it would need protocols
and probably system changes depending on
the product that you wanted us to pursue or products.
-: And in those market rules,
you would be able to still have the flexibility of,
so you wouldn't be just be tied to,
you'd have flexibility to do things with those products
like you currently do,
but we would set the framework in PUC rule potentially
to add more regulatory certainty,
which is a deviation to where we currently are today
with AS products.
-: That's a good point.
We certainly wanna, when we figure out
what the blueprint is,
we wanna build and we wanna put belt and suspenders on it
to make sure it's executed and yeah.
-: Yeah, I wouldn't have too many concerns either way.
I mean, I think there are protocols, first of all,
you oversee the ERCOT protocols
and approved the ERCOT protocols.
So the Commission's sort of role in this
is to provide that guidance on what the best practice
based on the conclusions you're making in this proceeding.
But I think that ERCOT protocols
are kind of the natural place for the details
it fits best in those,
and might actually increase the complexity if you separate
have certain ancillary services
that are only in the protocols
and certainly on ancillary services that are more
directed through PUC rule it, I think,
just out of a transparency for market participants,
you're probably best suited to have those,
have the Commission guidance,
put those into the details into the protocols
with regard to things like a,
the LLP study and setting a reserve margin to move to
and how these ancillary services play into,
that does sort of kind of fall to a more,
oversight kind of rule.
But when you get into the details of sort of the market
products, I think I would urge you to
sort of keep those into the protocols.
-: Sure the problem is things tend to die
in stakeholder processes in ERCOT
and they die for a long time
and so nothing ever comes out of them sometimes
and so I concur with Commissioner Cobos
in terms of sometime a parallel proceeding
to maybe more directive and not as detail oriented,
but requiring ERCOT to provide some type of service
that's fits a certain profile
and then you work out the details.
-: Yeah I think that is. -: At the end of the day,
state of Texas is telling you to do it
and so that seems consistent with the oversight approach.
-: And the newly reinforced seventh legislature's complete
and total oversight posture.
All right well, thank all of you.
Thank you both of you for it's been a long day
and thank you to all of our panelists and participants.
This is immensely productive for me.
I hope it is equally productive for y'all
and we will not be going into closed session today.
So having no further business,
this meeting of the Public Utility Commission of Texas
is hereby adjourn.
(gravel hammering)