-: Good morning.
This meeting of the Public Utility Commission of Texas
will come to order to consider matters
that have been duly posted
with the Secretary of State of Texas
for October 14th, 2021 for the record.
My name is Peter Lake
and with me today are, Will McAdams,
Lori Cobos and Jimmy Glotfelty.
For today's work session we will only be taking up item 23.
We've concluded business one, two and three?
-: Yes, sir.
-: Outstanding across the board.
Going to item 23, as I think most of you know
we have a full slate of speakers and topics today.
So let me lay out a few logistics to kick us off.
We'll start off with commentary from Brattle
on concept and examples over liability standards.
Then ERCOT staff will discuss near term improvements
that compliment our overall market design efforts
and design discussion.
After those presentations,
we will begin our panel discussions.
Each panelist will get up to eight minutes of uninterrupted
presentation time.
At which point we're all good with holding questions
until each panelist has concluded their presentation.
Also, Commissioner McAdams has filed a memo
on this docket that we will take after lunch
during our open discussion period.
And then after lunch,
we will wrap up with some commentary
and feedback on the discussion that was had in the morning
from both Brattle and Potomac economics.
We'll aim optimistically for noon-ish lunch.
And whenever we do take lunch,
it will definitely be at least 45 minutes
over 30 minute lunch ambitions.
But before we begin the formal agenda,
I'll offer a few comments.
And of course we'd love to hear comments
from my fellow Commissioners.
As you all know, today is the last part
of what has been an extensive, robust and exhaustive
stakeholder engagement process.
As part of this market redesign effort.
And going forward, we will be switching to the final stage
of the market design as this Commission crafts,
what will eventually be the blueprint for ERCOT market
redesigned to be delivered in December.
Of course, we will continue to take input
as we go through different draft versions of that blueprint,
but the next 60 days
or so will be intense for all of us and all involved
decisions that are gonna start being made rapidly.
So for myself and all of her Commission,
staff and stakeholders brace yourselves,
this is gonna start moving very quickly.
At the end of the day,
market redesign is about reliability for Texas.
I've said it before, and I'll remind everyone
here in watching at home that the paramount goal
is reliability for Texas,
not preserving business models or propping up profits.
We have plenty of generation in Texas,
but a third of it can vanish
if the wind stops blowing the sun stops
or the clouds cover the sun in West Texas,
and it's hot and sunny in Dallas and Houston
or natural gas stops flowing.
And if those things happen,
that leaves us with a reserve margin of almost zero.
I have been and will continue to be harshly honest
about the pros and cons of each type
of resource we have.
Some of the highlights of wind and solar
are the self-contained supply chain.
You don't have to worry about the supply chain
that we're all dealing with and reading about with shirts,
ice tea, computer chips, supply chains around the world,
wind and solar don't have that problem.
They're self-contained, which is a tremendous feature.
Their marginal cost of operating is also a great benefit
of wind and solar, especially when natural gas goes to $6.
And that's a tremendous benefit operationally
for our market participants, but also at the end of the day
our consumers in Texas.
The downside of course,
is the wind can stop blowing and clouds can cover the sun.
And we can't control either of those factors.
Just like anything else, natural gas
and coal have pros and cons.
They're dispatchable, we can turn them on and they generally
run as long as we need them.
Of course, the downside is machinery breaks
and sometimes gas stops flowing.
Supply chain issues, hit coal and gas,
just like everything else.
So again, we will be harshly honest about pros and cons
of each of these resources,
but the bottom line is we need to firm up our power grid.
You're up in California, learning hard lessons
right now about ignoring the realities
of their resource mix.
And they're facing the biggest energy crisis
in a generation.
We will not fall victim to the fallacy
that averages are always accurate.
As we all know wind blowing,
clouds cover the sun and sometimes natural gas doesn't flow.
This Commission will not structure a market
around hoping averages
all are always exactly on average.
Hope is not a strategy and we're skydiving.
You can only be wrong once.
The Texas economy...
Turning off the Texas economy is the most expensive
downside scenario we have.
Texas will not sacrifice its own businesses,
and safety of its citizens on the false premise
that we can have a reliable grid
without reliable generation.
And that cuts across all resource types.
We will leverage the benefits of each resource type.
We'll optimize our portfolio of generating assets,
and we're gonna hold all of our market
participants accountable.
Look forward to hearing your ideas
about how we accomplish
this and as all the mechanics of doing
so as always the (indistinct) in the details.
At this point, I'll open up for comments
from my fellow Commissioners.
-: Sure, I did prepare a few statements
for this morning's work session.
And first of all, I would like to thank my fellow colleagues
for all their hard work on these critically
important matters.
Having been through this type of discussion
years ago, I know exactly how complex technical
important and challenging these discussions are.
There's a lot of hard work that goes into coming up
with proposals and a lot of factors
that impact how you develop those proposals.
And I have had the experience of working with many
of you on these topics several years ago.
And I wanna thank you for your hard work and feedback.
I wanna thank staff and the Brattle group
for their work on these important matters.
I echo many of the words that Chairman Lake said today,
and I think it's really important that we focus
on making market design changes that help ensure year-round
reliability and address specific operational issues
like the cold weather events
and periods where there is higher than expected demand
with lower than expected generation output.
Because as Chairman Lake has highlighted,
that is across all generation types,
whether solar and wind drops off,
or we have a higher than expected amount of thermal
generation outages.
From my perspective, I view this workshop as an opportunity
to identify potential short-term, mid-term
and long-term solutions that can help us restore
public trust and ensure your year-round reliability
is our market continues to evolve in the future,
and our state continues to expand from a population
and economic standpoint.
Thank you very much.
-: Thank you, Mr. Chairman.
I don't have any prepared remarks,
but in the spirit of speaking to the moment,
this Commission was comprised constituted,
appointed selected by the Governor to make the hard choices.
Nationally, globally the industry that supports
one of humanity's most ubiquitous essential services,
that's now enshrined and ingrained in every aspect
of our daily lives is being disrupted at a transformational
moment with new and innovative technologies,
new resources that offer the public great benefit
on the part of affordability
and just self regeneration.
I mean, there's no into it, and this is a good thing.
Our task and our mission is to harmonize this new resource
with the interests of our economy
and the reliability of the system.
And so we must harness this and integrate
it in a way that solves for concerns
that all three aspects of the problem present to us.
So with that, I appreciate the work that everyone's done.
I think the legislature, the Governor,
the public is crying out for a new model
in ERCOT that again toward that drive toward harmonization
sends the appropriate signals
and takes the safety
and the physical status of the consumer
out of this equation.
We pay for performance and we pay for that surety
that when we call that consumer
to turn off, it is that effect of last resort.
And I think that's what these briefings,
what these proposals are designed to address
in one way or another.
And I think the work that we have done in no way speaks
criticizes discriminates against or considers taking
punitive action against any particular resource,
it is simply designed to harmonize new and intermittent
affordable power sources within the system
that we have today.
And our task is to set that framework
and our non-negotiables so that everybody
can move forward and innovate toward a better outcome
for the public interests.
Thank you, Mr. Chairman for leading on this issue.
-: I don't have prepared remarks either.
I think short and sweet is probably better
we have a long day ahead of us.
I do wanna thank all the participants
for putting in the time writing comments,
spending resources to analyze models,
trying to understand each other's proposals.
I wanna thank you for your comments.
And I think I want to chastise you for filing
so many of them.
(laughing)
On behalf of all of us, you all have done a great
amount of work.
And I think it shows that everybody has confidence
in this market and that we believe it it's the best market
in the world.
And we can't afford to lose that.
So what we're gonna do is we're gonna
fix it to make sure that the issues
that the chairman mentioned,
and the other Commissioners mentioned
are we're not doing a wholesale restructuring
of the entire market.
We know a lot of it works,
but if we can make some small efforts to improve
our reliability to make that the paramount concern,
I think we're gonna have an even better economic growth
in the state.
And we're gonna allow all the resources
that we have, that are given to us, solar, wind gas.
We have...
We are blessed with all of those resources in Texas,
and we ought to be able to use them.
Just think those in Connecticut,
they've got a pipe in natural gas.
We have it right here.
So we ought to not fight against each other and figure
out what's best for the state and the economy
so that we can continue to be the model.
Thanks.
-: Thank you all.
At this point, we'll start the formal agenda
with the (indistinct).
-: Good morning.
Is the mic working?
Can people on... Can we tell that people online
can hear me 'cause there's no mic on my phone.
Got it, thank you.
Well, good morning.
It's really great to be here with all of you.
Many of you, I saw a (indistinct) about 10 years
ago when we were facing similar questions
and it's good to see a lot of old friends.
Now we are here because the system has been tested
and failed in a very, very big way in February.
And because the fleet is changing and ways far beyond
what we even thought about 10 years ago,
that requires taking a fresh look at the market design
and making it better according to the objectives
we just heard from the Commissioners just now.
And it's for us it's really an honor to be involved
in this most important matter.
Our role is to take a very critical look
and an informed and analytical look
at all the possible solutions to help the Commission
come up with a market design that supports
their objectives.
And today we will...
Actually what I wanna do right now is just help frame
the discussion for so that today is informative
to the Commissioners because they actually have to...
And we'll help them.
They have to come up with a plan by next week.
So with that, where I'd like to start
is based on our having talked to the Commissioners
and having talked to market participants
and having looked closely at this market.
We're here...
And by the way I'm here with my colleague
Kathleen (indistinct),
so you'll also hear from later today.
And we're hearing two distinct problems
that we're here to solve.
So one is supply adequacy,
and that is what that means is making sure
there's always enough supply available to meet demand,
whether it's very cold, like in February,
or it's very hot, or the wind isn't blowing
or the sun isn't shining.
And that is the, I see as the primary challenge,
that's what happened in...
That's what the problem was in February.
And now to solve this we do have to sharpen a little bit
what we mean by how reliable do we want it?
Are we doing, we wanna be prepared for a repeat
of the weather in February.
Do we want to...
You hear about these sort of probabilistic analysis
that we wanna have enough supply to meet demand,
all but some very diminimous percentage of the time.
And for example no more than one event,
one mild event in 10 years.
So that is something that actually would be helpful
to hear from the Commissioners even sort of a sharpened
description of what that objective is as you comment today.
So that's the first problem, supply adequacy.
The second problem, which is distinct
is operational responsiveness.
And what that means is to always be able to quickly restore
a supply demand balance and maintain system frequency
in the face of sudden unexpected large changes
in particularly in supply and demand.
So whether that's a nuclear plant going out,
or it's the wind suddenly dying the fleet...
We have to be able to position the fleet
to be able to meet that.
And to do that through market products
that reward all of the resources that are helping
to do that rather than just through control room
commands that we're increasingly relying on.
And that brings me to...
So those are the two problems,
supply adequacy and operational responsiveness.
There are a number of principles
that actually we just heard some comments
about them this morning
but some principles that I think are a big part
of how we solve those problems
and the first one is, and that I think actually
I think I hope we all agree on is to do it through markets.
Because if we do it through markets,
then we provide the incentives to invest in the fleet
that we need to meet the reliability objectives.
And we incent performance, both of those things.
And it all comes together really well if we are valuing,
if we are expressing what we value in terms of reliability
through the market.
So that's the first principle.
The second principle that we've heard,
especially from the Commissioners,
is that we wanna be able to operate this system
in a way that is not...
That is avoiding crises, as opposed to depending
on crisis to send a price signal.
So that's gonna be an important part of it.
And then finally another principle,
it's not even a principle,
just a practical consideration is timing.
Because there's obviously a lot of political pressure.
There's an economic need to solve these, to ensure
reliability as soon as possible.
And some solutions are gonna take longer
than others to implement.
So with that framing, what are the problems supply adequacy
and operational responsiveness,
and what are the principles market avoid crises?
I think it'd be really helpful to hear
from all of the proposals today.
First of all, clarify 'cause there a lot of tactics here.
Clarify which problem are you solving?
Which of those two problems are you solving and how much?
Second is what's the time?
How long does it, what's the timing to implement
the solution that you're talking about.
And how does it fit and sequence
and compliment other elements of a solution.
And then third what are the counter-arguments
to your proposal and the biggest challenges
and how would you address those?
'Cause in this tight timeframe
you really don't wanna make mistakes, right?
And we don't have a lot of time to sort
through all the what are the challenges
and things that could go wrong.
And you know for your proposal,
that there it'll be challenged
it's best if given the tight timeframe,
today you talk about the counter-arguments
and how you'd address them.
'Cause I think that'll all make it a productive session.
And I also look forward to hearing,
have enjoyed so far hearing the variety of solutions,
and I look forward to the rest of the day.
Thank you very much for having us here.
-: Thank you Sam.
All right, next up we have ERCOT
to offer some suggestions on near term improvements.
Otherwise, sometimes termed as low-hanging fruit.
-: Yes.
So some of the things that I'm...
I'm sorry for the record (indistinct) Galman with ERCOT.
Good morning, everybody.
So when we thought about kind of the low-hanging fruit,
there are some time variations between those.
So I'll try and highlight those types of differences
that may take longer.
But from a high level perspective,
we've really focused on operational changes
that can help us operate the grid reliably.
And what I would describe those as are changes
to ancillary services
which actually were in the works already.
And these would include
what we call fast frequency response,
which we should deliver near the end of this year.
The other one that we would wanna talk
about and have brought up
is the ERCOT contingency reserve or ECRS.
That one is more of a year and a half to two years
for delivery.
However, we can kinda finish the design
in 2022 is our hope.
However finishing the design or the software side of it.
This is already an approved NPRR
runs up against the freeze that we have on our energy
management system as we are updating that.
So that pushes out the delivery year.
The contingency reserve service addresses, in our opinion,
some of the ramping issues that we see going forward,
it's important that you look at that ramping issue
being solved by a combination of the ECRS
and the existing non-spin reserve service.
So if you think about the two products,
one is a 10 minute ramping product.
We probably will need enhanced duration on that product.
And then non-space comes in as a backup
with a longer duration requirement.
So those are the items that we have laid out
in as far as ancillary services go.
There are other ones that have been proposed
by other parties.
One is the some kind of fuel backup
that is something we could implement as long
as it was a standalone service,
not being procured through our market management system
and a separate auction.
That is something we could do more quickly,
as long as we got the details.
And I guess the debatable principles ironed out,
and it was something that we could move
through the stakeholder process quickly.
The other ones I can talk about is what is expressed
desire to remove the (indistinct) buyback provision.
I think this is something in the IMMS,
the independent market monitors proposals as well.
That is something that we would be interested
in and could implement relatively quickly.
I'm gonna talk about a couple of other items
that are on the demand side now, I think on the fast end,
if y'all decided you wanted to do some changes
to the emergency response service or ERS,
that is something we could do.
It would require protocol changes
and such but that is something we could do.
The main barrier to that is the next contracting period
is coming up relatively quickly.
I believe it's we issued the RFPs in November.
So we would want to reflect the changes
that you want in that RFP,
we are upping the procurement periods
from three per year to four.
So if we were to miss that one,
the next one comes a little bit faster
than what had happened in the past,
but we would be kind of stuck with that.
I think for December, January, February,
and then we could of course change
after that procurement period.
The last one on the demand side
is to me this is relatively straightforward,
but I wanna caution you that the time period
is gonna be I think very long and it's a little bit
outside of ERCOT's purview.
But when...
I'm gonna harken back to October's energy's
presentation before you on demand response.
And the problem that they posited
before you was I wanna do demand response,
but I cannot pull or get the information
I want quickly enough to really know what each premise
is doing.
And they talked about under smart meter Texas,
what the standards are.
To me increasing that polling and allowing
non-ERCOT market driven demand response
is something that certainly should be on the radar.
And that is kind of something
I would very much be interested
in working on but I don't think that fits
into the quick time period.
There's a contract for smart meter, Texas.
There are standards and changing that would take some time.
So that's kind of the packet of items
that we had thought through.
Certainly happy to answer any questions
on anything else that may be on your mind
or anything you'd like to follow up on.
-: Thank you Kanaan.
At this point, any questions for comments
for Brattle or ERCOT?
-: I'm sorry, there is one I forgot to mention.
That was NPRR1093.
This is loads in non-spin.
That is on its way to the board.
I would say that stakeholders have introduced
some concepts that we think are valuable and good concepts,
but they delay the implementation.
So we're trying to work through that issue
and see if we can deliver the loads and non-spin
NPRR1093 for the summer and then bring the additional
functionality that has been raised at a slightly later date.
-: Good point, thank you.
Question yeah.
-: Mr. Chairman, Kanaan thanks.
This is good stuff.
Nodal pricing for load resources.
You suggested that, how long would that take to implement?
-: So that looks like a year and a half
to two year implementation.
We have gone through the exercise
of doing that for distributed generation
and that's been the experience.
I would describe that need as things kinda falling
in line with that kind of a delivery.
There are some really good reasons why you'd potentially
want to get those things,
load resources getting a nodal price.
And one example I'll give you is probably some projects
that you have seen where load sites
jointly with a resource of some sort.
Having a different payment pattern for the two actually
creates incentives where one part of that combination
may wanna deploy yet the other does not.
The other thing that we've started to see
is load responding to a high zonal price,
but being in a location that actually doesn't help
the nodal problem that we're having.
So these types of enhancements would help us operate
the grid more reliable.
-: Great, on from fuel ancillary service concepts.
In the interest of expediting,
some type of redundant safeguard measure
for the upcoming winter.
Not necessarily this upcoming winter,
but the next,
what do you think barriers or downside risks
are to considering allowing a percentage
of non-spin reserve risk
in SRS to be only available to entities
that meet specific firm fuel or dual fuel
or on-site storage requirements?
-: So I think those...
I mean, that is avenue to achieve that goal.
The drawback...
I guess Sam wanted us to bring up drawbacks
that we see, is that will impact liquidity.
There could be a delay and there become some additional
stratification on who's eligible, and who's not.
So from an economic standpoint,
I think we would prefer to build that.
And I think it would take us longer to incorporate
that into non-spin.
It may be better to do the fuel as a standalone service
that I auction off and build separately
and keep out of my market management system
in terms of speedy delivery than having it part of non-spin,
where in the order in which I clear things
or the optimization with which I clear things,
I have to add another factor in.
So I think adding it into non-spin as a requirement
will make it a more complex delivery than say
some kind of standalone service where I do an auction
and award, that to parties that installed-
-: Sure, and so my question
is a leading question obviously,
but it's not an either or option just kinda like
the transmission projects and the RGV
that we were talking about.
So it's just a matter of expeditious employment
of some type of fuel firming system
to compensate some of these folks on a performance basis.
So you're telling me that in order to even take that half
step, it might take a...
By using SRS, it would take longer than just standing
up the standalone ancillary service?
-: Yes as we've walked through this because...
Let me step back a second.
The minute I have to touch some of our core systems,
I start having lots of additional planning
that I have to do and projects that I have to run.
And these core systems also have testing.
I have to make sure that they do everything
else they're still supposed to do.
And this additional component that we added,
if I do just a straight up standalone service
with an auction of some sort,
kinda like the emergency response service or black start,
that doesn't really go into any system except
our settlement system.
That's a more straightforward design for us.
I'm not saying that's the better design,
but that is a more rapid,
we expect to deliver that more rapidly
than trying to roll it into non-spin
-: Okay (indistinct).
-: Like to be on those, there's some operational streamlining
opportunities that I'm sure the new board
will be addressing.
But another topic for another day.
(indistinct)
-: And just to add a thing,
thank you for your feedback on that issue Kanaan.
It may be important that we ask these questions
of some of the companies that we'll be speaking later
that have... That actual provide non-spin.
-: Yep (indistinct).
One more question.
On ECRS as a concept right now,
as an ancillary service, how are you sizing that?
What's the vision on size of ECRS?
-: So the size is in terms of capacity that we procure
is what I'm assuming, you're asking.
So the size is actually built flexibly
because what we do is with all of our ancillary services
is do an annual review of what amounts we may need.
And that varies from year to year.
So our expectation was to procure relatively small amounts
of that initially.
I would say maybe a couple thousand megawatts,
but because we expect the size to vary,
the parameters are built into change.
And so there is flexibility.
-: Okay, so on especially with that type
of performance value,
at least the way you have have defined it.
I'll tell you kinda what I'm a little bit concerned about.
And then this is to Sam's point,
what are the threats?
And if we do nothing else today,
we're gonna have a lot more solar on the system
in two years, which will create
between four and 8:00 p.m
a lot more variability in terms of production.
'Cause that production falls off as the sunsets.
And again if wind has not caught up at that point,
that makes a really dramatic decline
in generation on the system, that duck curve.
And I'm afraid of the magnitude of that curve
with 10,000 more megawatts of solar.
That is a concern for me.
For the purposes of ECRS, it looks like it might be a good
fit to try to cure that problem,
to try to arrest that fall in generation.
But have you considered sizing it on a percentage
of forecasted intermittent variability just as a rule?
So again if me as a Commissioner,
I'm kinda interested in not setting numbers
arbitrarily in terms of this market,
but letting the degree of variability dictate
the needs so that we don't have to get litigated
by all new people all the time.
And what do you think?
-: So that is a possibility,
and it is actually in a factor in our analysis,
our annual analysis.
So I'm gonna speak at very high level,
but when we do our ancillary service methodology
what we do is we look at what is on the grid,
how performance has been historically,
and look at almost every hour of the upcoming year.
And based on that, we procure amounts of responsive
reserve service RegUp and RegDown non-spin service
and once we have ECRS in there that will be driven
by that as well.
Now what I would tell you is I wouldn't meet
the standard that you met solely with ECRS
that might have a shorter duration,
it would be a combination of ECRS and non-spin.
-: Yeah, and so just to drill further on your comment,
what the point you made is an annual contract
or a consideration enough?
Do we need to be doing this on a seasonal basis?
I mean, this generation mix is changing fast.
-: Absolutely, so the way we work
that is, although we study that annually,
we reserve the right to procure more.
That's just the minimum amount that we're gonna procure.
The reason why we try and announce that kind of a year ahead
is to help load serving entities and procure that.
However, just like we ended up procuring more non-spin
this year, we can always expand that amount
when we see issues arise.
So if there were a change,
some kind of a retirement of a certain type of resource
or a generation mix on the system changed
such that we needed to procure more ancillary services
that is allowed in the methodology.
-: Okay.
-: Can I fill in some extra numbers on your comment?
'Cause we've looked at the same numbers.
When you say that in the absence of action,
we anticipate much more solar coming on.
And with that sunset decrease in solar,
just for context for the folks
wanna be in two, three years, 20,000 megawatts.
-: Or (indistinct) about 13 gigs.
-: Yeah or three or more.
So that's, I think depending on how fast
if it's two years or three years out,
ERCOT would re responsible for coming up
with 20,000 megawatts as the sunsets
which on a normal fall day is a third
of our total peak load.
-: In his context that's approximately
the same amount that you had to arrest during URI
when everything froze up.
So we're basically faced with a URI on a reoccurring basis
in the next two years.
-: I mean, so we wanna provide that context
for folks watching at home
and also offer the thought, food for thought
is that why is it necessary...
Why do we necessarily have to be responding to liabilities
that market participants are putting in the market
instead of requiring them to address the broader universe
of market participants to address those liabilities?
Just food for thought.
-: So give me an example of that.
You're responsible either gen side or load side,
you're responsible for a certain series of hours
of generation, if you're going to be offering in.
And just because something...
Just because what you thought you could offer
or promise to offer, doesn't show up.
It's not the 15 folks in the control room
that have to scramble to magically conjure resources.
They're supposed to balance the resources,
not conjure the resources.
It's the responsibility of either the generator
who's being paid for those resources or the load serving
entity who's obligated to their customers,
that they will deliver those resources.
I don't know which one are the precise mechanics,
but I'm very wary of us.
I'm not saying ECRS is not a valid product,
but I'm wary of us getting into band-aids on bullet wounds,
where we're chasing every few years
we find ourselves chasing whatever the latest liability
is that the resource mix,
the ever changing resource mix
dumps on ERCOT.
And I don't, again it's food for thought,
but it's as we all know technology is evolving
so rapidly and the resource mix,
the potential for resource exchange is so fast
that we can't... I mean by the time these things,
these programs are built just operationally,
it'll be a new liability, right?
So I just wanna offer up the consideration
that it's not that we may want to consider
moving that liability to the marketplace
where appropriate there are risks and rewards
and much broader universe of risk management tools
move that liability or responsibility for that liability
into the marketplace,
rather than on the 15 folks sitting in the control room
every day trying- -: Keep the lights on.
-: Keep the lights on when URI happens
every single day.
Just food for thought.
-: If I may,
I just wanna highlight that and everything that the chairman
said is correct.
So these are gonna be costly or interventions by ERCOT.
But if you see...
If there is a ramp on a daily basis
that you see there are ERCOT'S position to manage
that either I have ancillary services
that deploy when instructed
that has a cost or other things
that we have done and could do is also you bring resources
online early.
And some of the solar doesn't is allowed to come online.
In other words, we curtail those resources.
That's how... That's the way we would manage that-
-: With curve ramp- -: That ramp,
that duck curve today.
-: And I would have a few questions.
So I know ERCOT has been preparing for an increased amount
of solar, for a few years now with solar forecasting models
that have been updated and preparation similar
to what ERCOT did to handle the operational challenges
of increased wind generation on the system.
I agree with both of my colleagues here, Chairman
and Commissioner McAdams, we've got to prepare
for the future and the significant increase in solar
that is coming as we expect a significant amount of increase
in the next two, three years.
I would like to understand the duck curve of concept comes
from California, right?
California, as a state experienced a significant increase
in solar and was dealing with operational challenges
associated with duck curve.
In many ways we are different than California,
sunsets later here and there's just a lot of geographical
differences with geographic diversity in the location
of solar facilities
that is different than probably California sunsets later.
I wanna make sure that ERCOT
is looking at that, and I know probably are really studying
what kind of a duck curve or similar curve
we would be facing in the future
as we add more solar generation on the system.
I don't know that we can just say,
we're gonna have a duck curve just like California
and we got to prepare for that, I think as a state
we're different.
We have a different market, we have different resources
and I just wanna make sure ERCOT stays on top of that.
So we are appropriately planning for the future
as we integrate all of this resources,
because I think we're a very attractive state
with or without subsidies probably
because our land is cheap and we've got a lot of wind
and we've got a lot of solar
and a lot of transmission access.
So it's just the reality of our market we're attracting.
So we need to really understand the impacts
of that increased solar.
Now, I'm gonna go back to the new approved AIS products
that you mentioned Kanaan.
FFRS just for purposes of the public understanding,
what is that product intended to do?
What specific resources are you incenting with that product?
-: So that product is a very rapid response product
and fast frequency response.
So it responds to seconds, cycles in terms
of the response time,
where any decay in the frequency
or increase in the frequency,
there would be a response where you either increase
or decrease your output to maintain frequency.
The types of resources that would qualify
for that are a mix
but the new resources that we're trying to accommodate
in that package are batteries
and some additional demand response.
But that the product does not disqualify thermal resources
from participating or other things.
It is a resource agnostic looking for performance,
very quick response. -: We're paying for very rapid
frequency support batteries happened
to be very good at that.
-: Yes.
-: We're not saying it's designed for one resource
and others designed to solve a specific problem.
-: That's correct.
-: And the spirit of we pay for what we want
and let the market deliver the most efficient
effective product.
-: And that product will be delivered
by the end of this year.
Now moving on to ECRS, it sounds about mid 2023.
when that new product would be placed into the market
mid 2023, maybe 2024.
Because that product is currently contingent
on the EMS upgrade.
-: That's correct.
-: Can you speak to it?
When will the EMS upgrade be completed by ERCOT?
-: So the EMS upgrade will be completed.
I believe in 2024.
We may be able to deliver that slightly early,
but right now it's 2024 delivery.
There usually is some additional testing
and things like that, that happened,
but that's our estimate currently.
That doesn't mean I can't start working
on the next market design change
that would have to come in a little after,
after the EMS system.
But that's where...
That's the timeline for EMS.
-: So the EMS system at ERCOT is critically important.
It's been an process of upgrade for maybe...
For a while now.
What are some of the challenges?
Because what I'm hearing just with these initial comments
and probably will continue to hear,
and we'll continue to investigate throughout this workshop
is as we're tasked with coming up with short term,
maybe midterm looking at long-term options,
what are those options that would be impacted
by the EMS upgrade?
Because the reality is we need to start delivering
enhanced reliability sooner rather than later
and my concern is that we will move forward
with market design proposals that will take an extended
amount of time to actually implement
because they may get caught up in the EMS upgrade.
Is there something that we can do as a Commission to help
you speed that up?
Do you need more resources?
-: So just to step back
so the energy management system is kind of the real time
optimization of a kind of energy recognizing
the typology limitations.
So security constraint economic dispatch,
locational marginal prices,
those things all come through EMS.
I think at this point throwing that side,
that development is staffed very well.
If we bring on a new additional resources,
because we would have to train them up.
I think there's not a lot of time gained by throwing
additional resources there.
I would like to reserve the right to check with our IT team
and make sure I got that right.
So if you are wanting some kind of real time optimized
pricing outcome and dispatch outcome with any of the new
proposed changes, or I need to feed something
from that, there could be a reliance or a dependence on EMS,
and that would slow it down.
So the more I can stay out of that, the less I run
against EMS.
When I look at the new proposals,
every single one of them has a settlement's impact.
That is my biggest worry is to our settlement system.
There may be some, there's not.
All the details haven't been fleshed out.
So there might be something that needs to come from EMS
to feed them.
But the settlement changes that we're already doing
with securitization and other projects
that's where I see the big bottleneck right now
in terms of delivering some of these products.
Might be worth talking more about these things after folks
have presented them but for example,
an obligation on load doesn't necessarily impact the EMS.
It could, if there's a penalty or something
that needs to come from actually what happened in that day,
but it doesn't necessarily impact it.
It will impact my settlement systems.
So that's the big bottleneck that I'm seeing now.
But if it pulls anything from EMS
that will also become a bottleneck,
to your point, Commissioner Cobos.
-: So is it a bottleneck in settlements
because of the lack of staff or what...
Can you explain a little bit more about that?
-: Yes, so what we're having to do right now
is very different than the normal staffing
that we have in and around that.
We have actually hired or are in the process of hiring
four new FTEs on that end.
But that was just not the way we were...
The staffing that we needed to do
are normal course of business in the past
did not need as many resources on the settlement.
-: And I know that's something that the new board
will be looking into.
They're meeting next Friday,
would that be something of interest to put on the agenda
for the new board to think of next Friday?
We're running up at our 10:30.
-: Yes, so I think it's important to stay on top
of this issue because both the EMS upgrade
and the settlements systems are critically important
for many important matters as you just mentioned,
securitization some of these proposals.
And I think that that would be a topic that should be raised
because I know ORCOT has a lot of really important
matters on the table right now,
but if there's a way that we can help reprioritize funds
staff to really kind of help with speed up EMS,
potentially, I know we have some funds probably sitting
on the sidelines for RTC
and also just visit more about
what some of the challenges are.
I think that's really important.
So let's continue to visit about that.
-: And I'll make sure to add it to the board agenda
for the New York board they're meeting
they're off to a fast start there'll be meeting next Friday.
-: Absolutely, and just one last thing,
thank you for bringing up the field backup service.
The firm field service is very important for my perspective,
and I am glad to hear that it can be procured outside
of an EMS upgrade.
I think as you stated, I think if we can come up
with a defined path forward on that product.
I think the market will build around it.
I would like to hear from the companies
about Commissioner McAdam's question about non-spin
being or that product being rolled into non-spin.
I understand there's some challenges there.
So I would like to hear a little bit more from them.
And also I think that having it as a standalone product
sounds similar to Blackstar and that procurement
seems to be a reasonable path forward.
And so thank you for your feedback on that important issue
in tackling that proactively.
-: All right, yes Sir.
-: Thank you, Mr. Chairman, if you don't mind
I want to respond to a concept that came up,
which is about the duck curve
and the challenges that, that poses.
But I wanna make sure that to be clear
that those are very different from the URI type challenges.
So in URI, that demand got as high as say 77 gigawatts,
and the most we could squeeze out of the fleet was 45 to 50
gigawatts because there were frozen and there was no fuel.
And that's very different.
The duck curve sounds challenging and it is.
We're very lucky we've got ERCOT to help manage it.
That is totally manageable because you actually
do have enough resources to pick up.
It's just a question of when you turn them on.
Which resources you hold back,
because they're worsening that need for ramping
or cause they've got a lot of flexibility
you wanna use them as you need the ramp.
It's just how you manage the fleet.
What's actually a little harder than the duck curve,
which is kind of an expected diurnal when the sun goes down
problem is the unexpected
when there's a front and the wind might die all of a sudden.
That's harder to manage but in fact
you have to manage both.
And I think a lot of the job of what ERCOT
has to do is to your point Commissioner Cobos
is analyze the specific patterns
that this system might face.
And so to figure out what kind of ramping products we need.
And so that is analysis that ERCOT is already doing.
Again, this is definitely manageable.
It's a question of what products you design
to meet it and do it through a market.
And I think that...
So after analyzing it, one question is
and Commissioner McAdams, you asked about quantity.
That's key, right?
Now, initially you can just even expand existing products
and we've done that.
ERCOT did that this summer.
So you can even just increase the quantity
of existing products, that's easy.
Second thing you could do is increase the quantity
of products that are in development like ECRS,
but that's a couple years later.
For even beyond that you could tailor some really
well-designed perfectly fit to the problem
ramping products maybe an inertia product,
that'll take a little bit longer.
But again, these things are all manageable.
These are the steps that ERCOT has to take I think.
Now what we're gonna hear from the market
participants today is primarily...
'Cause that's all about problem number two
as I set it up this morning.
What we're gonna hear from the market participants today,
just to not confuse things is primarily about problem
number one, which is harder,
not just a technical management problem,
it's sort of a harder market design problem.
How do you make sure you always have enough supply?
And that's largely I think the focus of most
of the stakeholder proposals that we'll hear from today
and to me, it's actually helpful to sort out
those two problems and think about them separately.
-: Well, I'd also heard that those two problems can happen
at the same time.
So having to conjure up 20,000 megawatts every day
as a known challenge is, it's still a challenge because...
Just because resources available may not be offering
into the market at that moment in time
depending on market conditions.
And so that's where ERCOT got a scramble
but if you have a second issue you're wrong.
Now you have a backup sheet.
And so that's where leaving the...
I mentioned leaving the liability in the ERCOT control room
it limits the amount of resources available,
the tools not the resources, the tools available.
And so I wanna make sure we think very hard
about how separate problems can converge
and the liability that we're exposing ourselves to even...
Especially for the days when both shoots don't open.
-: Okay, operational question, Sam.
Is a 20 year old combined cycle gas plant designed
to arrest a drop of that magnitude on a daily basis?
I mean, can it ramp that fast and meet that challenge?
Because we had 16% of our dispatchable capabilities
break in one day this summer.
-: So the answer is maybe in partly.
The key point is the questions you're raising
are the right ones to raise to make sure
we do have that capability in place.
I mean, sure, with a combined cycle,
it's partly a question
of when you turn them on and who you're holding back
and they do have ramping in them.
They absolutely do, but you have to make sure
that you have enough overall to meet the operational needs
for the day.
And again, I think you're asking exactly the right questions
here to make sure that we're set up to do it and to do
it in a way that's in market which not only gets
the job done, the controllers can do that too.
It gets it done in a market-based way that also sends
the right signals for investment.
So, by my comments,
I wasn't at all saying,
we're not asking the right questions.
These are the right questions.
I was just trying to separate out what are the different
threats and the tools for them.
-: So, in the spirit of providing holistic perspective
on an operational challenge,
like the one that we faced in June,
'cause I was examining these operational challenges
a little bit closer and looking at what actually occurred
and just for the sake of providing a holistic picture
on one of the tightest days that we had in June
during conservation week,
we had a lot of solar on the system.
Well, over 50% that helped us get across peak
on the tightest day that we had this summer.
And I know there could be cloud coverage
and that may not always happen but just...
I just want to make sure that we're looking
at all these issues holistically and robustly
as we move forward.
-: Alright, thank you.
Well, let's get started with a panel number one.
Come on up, you brave souls.
Vistra next to hear and LCRA.
All right, the floor is yours.
-: I hope the microphone is on.
Good morning Commissioners.
My name is Julia Frayer,
I'm (indistinct) Economics,
and I will be presenting on behalf of the request
of Vistra Corporation.
We began our analysis by looking at the objectives
of the policy makers, for example, SB3 requirements,
and it was very clear to us at the beginning
that policy makers wish to improve
reliability and resiliency
and I think you've all underscored that.
I have my notes, every one of you said this morning
that is a key objective.
So I think we're on the right track
in terms of understanding the priorities.
We also evaluated historical market outcomes.
Looking back to 2014,
we saw very clear insufficiency of revenues to cover
the costs of developing and operating a new dispatchable
resource under normal conditions in ERCOT.
In the industry we referred
to this as a missing money problem.
So you'll hear me speak about that a bit.
These are the facts that I think explain why new
dispatchable resources have not been built
in recent years in Texas.
And these are the observations that really led us down
the path of our proposal.
To be clear, we do think that the energy market
has functioned well in choosing which resources
should be dispatched, providing a signal
for efficient consumption.
So it's not a complete failure of the energy market design
that we're trying to fix here.
So our recommendations are built upon the basic cornerstones
of the existing real-time energy market
and they had energy market.
What we're recommending are two modifications.
The first one is an improved ORDC curve,
that will basically integrate
with the real-time energy market.
The improvements in the ORTC curve that we are suggesting
will enhance the economic signals for investment
in dispatchable resources and real-time operating reserves.
The second piece of the puzzle for us is a new ancillary
services product which we've referred
to as dispatchable stand-by reserves.
The goal behind both recommended changes
is again to reiterate,
improve reliability and mitigate load shed in the future.
So to Sam's question that is the problem
we are trying to solve,
and I think both changes the DSR and the improved ORDC
should be done in concert,
as we believe doing just one or the other
will not be enough.
If we can go to the next slide.
In this slide, we have laid out how our recommendations
would affect the energy market.
So this is the links if you will and how we anticipate
it will create that investment signal
for supply adequacy.
We'll begin in the top hand side, step A
where there's an announcement of the complete package
of RDC changes and based on practical experience
here in the industry, this will raise forward market prices.
And then we move on.
We expect a DSR auction to be implemented by ERCOT
ahead of the real-time market
and I will try to explain what the DSR product
is in the auction in a bit,
but before we get into the nitty-gritty details,
I just wanted to complete the circle.
So with the DSR auction happening ahead of time,
this would compliment the forward market expectations
being sent by the changes to the ORDC.
And it would also give ERCOT a set of standby resources
they could call upon in the energy market.
Activate is the term we use to meet any emergency events
that cannot be met with energy market offers.
Once we get to the real-time market
and this is a really important piece,
we will have the improved ORDC in place.
It will be triggered depending on supply conditions,
and it will essentially validate the forward market
expectations that had been built up by the announcements.
ERCOT will also have the DSR product in reserve
to protect the market from load shed events,
and we'll use those resources as needed
to ensure sufficient supply.
And then over time we expect that the forward market
energy market signals would trigger new investment
and create a more reliable system.
I think we also expect that with time,
the ORDC parameters that we introduced in step A
would need to be reviewed and adjusted
to ensure that it's really capturing the uncertainty
in the market, the changes in the supply mix contribute
to that uncertainty
and continuing to send that strong economic signal
for investment.
If we go onto the next slide,
let me spend a few minutes talking about each of our two
recommendations in a bit more detail, a deeper dive.
So the ORDC change has three components to it.
First we're going to lower the H cap
and we're recommending $4,000 per megawatt hour H cap.
We're then increasing the minimum contingency level,
the MCL we're increasing it to 2300 megawatts.
And finally step three, we are adjusting the shape
of the curve through an expansion of the standard deviation
that goes into the loss of load probability calculations.
Based on our analysis of historical actual outcomes
in ERCOT since 2014 and consideration of that missing money
piece for a hypothetical new CCGT,
we believe the new multiplier or the rescaler
if you will to the standard deviation should be 1.5 X.
These three parameter changes are related.
For example, you could imagine an H cap
that could be a little bit higher, a little bit lower
than what we're proposing,
but then the other parameters need to be modified
as well to get that economic signal correct.
From the changes we are proposing,
we're actually accomplishing two things.
We are intentionally and quite explicitly targeting
an opportunity for CCGTs to earn sufficient revenues
so that economic signal for investment.
But we are also creating an economic signal for generators
to self commit in the real-time energy market
resulting insufficient operating reserves.
And you can really see that well,
when we look at the zoomed in portion of the graph
on the slide,
we know that ERCOT recently has been trying to operate
to reserve levels around 6,000 to 7,000 megawatts.
And at 6,500 megawatt,
it's very clear that the current ORDC,
the black line is basically providing no economic signal,
no additional revenues to those generators
that are showing up.
ERCOT has had to essentially use controlled room
tools that it has that it's disposable,
the RUC tool to get those operating reserves that it wants.
With the modified or improved ORDC
that we're showing the red line,
we expect that on average at those levels of supply 6,500,
for example, we would be getting a little bit
more than 6000 megawatt or adder to system Lambda
in our real-time price.
And we believe that that is the important key to getting
the right economic incentive
so that we don't have to depend on out of market maneuvers
by the system operator to get those levels
of operating reserves.
And this is really important
because those out of market maneuvers
are actually going against the whole investment signal.
They're eliminating or create...
Eliminating the price signal
or at least depressing it because of how RUC interplays
with the price settlement process.
These ORDC changes are targeting
specifically dispatchable resources.
For example, based on our backcast analysis
that CCGT on average between 2014 and 2021.
And based on those system conditions that prevailed
historically would have earned an additional
$10 megawatt hour on average when it ran.
These changes do not boost the revenues of intermittent
resources like wind generation anywhere near that quantity
or that amount.
And that kind of makes economic sense or intuitive sense
I would say because in hours with high levels
of wind generation,
the level of the supply cushion or the RTO El cap,
the excess supply in the market is much larger,
which then gets us to the tail end of the curve
where we have low or negligible ORDC adders.
And when solar penetration increases over time,
we expect exactly the same thing to happen,
where the ORDC payments will basically be highly correlated
with low wind and low solar conditions operating conditions.
So this remuneration is targeting dispatchable resources,
not just resources...
Not just all resources I guess in the supply mix.
And it's simply because of the pattern of generation
for whether contingent resources.
If we move on to slide five,
in a vacuum if we had just implemented those ORDC changes
that would have triggered additional investment,
that's our objective, that's what we want.
But we would also anticipate in a dynamic world,
a wave of mothballing announcements
or retirements to follow.
Because of the infrequently used resources
sitting on top of the supply stack
and we have adjusted an illustrative graphic
here at the bottom right.
We will never get dispatched in the energy market.
And eventually as a new supply resources
came in, they'd get squeezed out by those new resources
and they would rationally choose to either exit temporarily
or permanently the market.
But existing dispatchable resources
sitting at the top of that supply curve are still valuable.
They can provide significant reliability benefits
to the system if they remain operating.
So that was really the, I think the foundation
to our thinking through an additional
or new ancillary service that could be implemented
to compliment the changes that we would anticipate
out of the improved ORDC payments.
This new AIS product,
and we call it the dispatchable standby
are reserves product or DSR for sure would be completed
through periodic forward auctions.
And I know I may have run out of time,
so I will ask your permission if I could continue.
-: Finish your last slide (indistinct).
-: We have a lot of details that we've thought through
about how the DSR would be procured
and I'm happy to go through
it with you if you have questions on it.
But generally we're thinking that this is a short term
forward auction that is done outside
of the energy management system
as we heard from ERCOT today,
that is a consideration in terms
of timeliness of implementation,
very similar to the competitive markets
they've created for Blackstar for ERS.
We think a simple option could work
and the key piece really here is about how the DSR
resources, once they're self identify
and participate in the auction,
how they're actually used by ERCOT.
Well, they would be activated or dispatched
when extreme events occur.
And when that happens,
they wouldn't affect the realtime energy price.
The key is for us to preserve the realtime energy price.
So they wouldn't be counted for example,
in the calculation of the real time,
adders from the ORDC and that's in order to preserve
that economic signal.
-: Feel free to conclude with Sam's question
about counter-arguments.
-: And actually we can go to the next slide,
that might be a helpful stay about this.
We are solving, as Sam had asked a question,
both a supply adequacy problem that's...
And an operational responsiveness problem.
The supply adequacy problem is an investment signal problem,
and the modified or improved ORDC
we believe will get us there.
We also have a sort of planning problem
and a dispatchability problem under extreme circumstances,
an operational responsiveness
and we believe that having reserves stand-by reserves
that ERCOT can use in the real-time market
really helps resolve that.
And that's the purpose of the DSR product.
In fact, I like to think of it as an insurance product.
-: And the counter arguments.
-: So the challenges I think is your question.
-: Sam identified for all of us who devil's advocate.
What would a opponents of this plan say?
-: Well, before I go to the devil's advocate,
I think there is a sequencing issue.
This slide shows that we do think
that this could be done very quickly
because it's outside of the energy management system.
But I think in terms of devil's advocate or challenge,
I think the challenge is, really goes back
to what is your metric of success for this product?
My metric of success or lack of success
is if we don't get investment
and we don't get the additional operating
reserves committing on their own,
self committing on their own,
or for example we don't get weatherization.
I didn't mention it earlier,
but the DSR product is well positioned to be a market
mechanism to get weatherization
in there and from fuel as well.
So if we don't get weatherization activities,
we don't get announcements of new investment
and we implement the modified ORDC the improved ORDC
with the DSR and we're still not getting those levels
of operating reserves we need, that to me is a challenge.
And I think there is a solution to that challenge.
The solution is twofold, don't do things to piecemeal.
Because the market has a hard time
kind of reacting to piecemeal pieces of information.
And I think another thing is don't try to fine
tune all the details to extreme perfection
because we probably won't get it perfectly, right.
We need to err on the side of quick signals.
-: We know what failure looks like.
What would a counter argument to be why this solution
will not deliver the opposite of failure?
-: Well, I think directionally,
we know that the ORDC as a Stan state doesn't work.
So the counter argument to it is that we are shifting
the ORDC to get us the right level of real-time prices
that should work.
And then we're creating
a safety net with the DSR (indistinct).
-: That's an excellent example of how this is a great idea.
It would not be a counter argument.
Thank you very much.
-: How do you answer to a counter-argument
that your ORDC proposal's gonna provide adders
over a longer period of time
which could actually provide more ORDC payments
to renewable generation.
-: I think ORDC payments in some hours
may also be paid out to renewable generations
that are producing energy in those hours.
But on an average annual basis the ORDC payments
are primarily going to dispatchable resources.
And the reason being is that renewable resources
that are intermittent and we have two general classes
I'm talking about.
Right now, it's wind and time when we get more solar
will be solar as well.
They by themselves create supply situations in the market
that puts us really at the tail end of the ORDC.
So it is about understanding kind of the implications
of when those resources run
and what kind of supply condition it puts us in.
We have some data we could look at where we've looked
at where we look at the correlation
for example of when wind generation
occurs and what the resulting supply cushion levels are.
And generally there is that positive correlation
that I was trying to speak to an intuition.
And as we get more and more of those resources,
that will just be expanded such that those resources
will themselves if they keep generating
all at the same time, will themselves create a situation
with in those hours that they generate
there's very limited or zero RDC payments or (indistinct)
Now let's say there are resources that are added
in specific locations that don't generate like
the rest of the fleet or intermittent resources
co-located storage devices onsite.
Those are all good things,
those make those resources actually improve...
Those types of changes improve overall system reliability.
And I wouldn't be uncomfortable,
for remunerating those types of activities
within the energy market.
-: Could you tell me, how does your ORDC react
to 10,000 more megawatts of solar on the system into yours?
-: So the ORDC modifications as I've presented
and they have been calibrated to historical conditions
rather than potential future conditions,
would generally be in a situation where there's less
payout than what the calibrations to historical
conditions would otherwise suggest.
So in fact to kind of anticipate maybe
what would need to be done.
I had mentioned earlier that we would recommend periodic
reviews of the ORDC parameters as system conditions change.
And that's a great example of where we would need to go back
and take a look at what those conditions
are, and maybe adjust either the MCL
with combinations on the standard deviation
or the average of the loss of load probability,
but there would need to be some adjustments.
-: Yeah and with that the ancillary service product,
the ESR product, how soon do you expect under optimal
conditions to have it implemented?
-: Well, I'm nervous about putting words-
-: I know but- -: For another institution.
-: You've watched this-
-: I believe that the way that we've tried to design
this it's something that with a focus and support,
so concerted effort of multiple staff members,
this type of market could get in place
within a 12 month timeframe.
And the reason being is in terms of figuring
out how much to procure our part already
does a lot of analysis to know that.
In terms of an auction framework and rules
ERCOT has examples ready for other products
that procures through competitive auctions.
So I think that's very possible,
but we also don't wanna rush it in a month
or two because we want to be able to publish
the rules, the cost allocation framework,
and make sure industry understands
that consumers understand it.
Generators who might be interested in participating
understand it.
But I'm thinking 2020, maybe 2023,
if nodal protocol changes take a little bit
of time is a very, very feasible timeframe.
-: And then for clarity for the public,
how do you view cost allocation on this product?
-: Great question.
Didn't spend time today 'cause it's hard to fit it all in.
I believe that very strongly in cost causation principles.
So what does that mean?
If we're looking for example at the Sarah reports recently
and the extreme events and the various drivers
that cause extreme events,
we see very clearly that for example
unexpected high load is one driver.
So higher load causes, higher load that cant respond
and cartel consumption is potentially a causer
of these extreme events and should be responsible for it.
And frankly, load benefits from this type of insurance
and should be responsible for it.
But also there are other drivers,
for example low solar, low wind are listed
as potential drivers of extreme events
where the system might find itself short of capacity.
And I believe that I call them catalysts entities
that cause reliability to worse
than on the system should also be responsible
for some share of those thoughts.
-: Alright.
-: Can I just ask a question on that?
Do cost causation principles apply to dispatchable resources
also in days when you have unforced outages?
-: Well, for example...
And the short answer is yes.
And the example here is that the DSR resources
that commit to be available to provide
this insurance will have performance penalties.
And if they're not performing when our (indistinct)
needs them to perform,
they have to face those performance penalties.
-: Okay and what...
Are there parameters in the DSR?
What is the parameter of the type of resource
you're looking for and the DSR?
-: Great question, it's actually the fundamental question.
What are we buying?
Dispatchability and I think part of that could involve
weatherization and fuel firm.
Sorry firm fuel, I'm getting my F mixed.
Firm fuel requirements because what we want is resources
that will dispatch when instructed
to do regardless of the weather.
And there may be duration requirements and so forth
that you have to produce energy for certain period of time.
-: Right, I struggle with one thing
and that is we all want dispatchability
when we need it, but February showed that we didn't have it.
So the question is how do we make sure that we solve
that issue as well?
And it doesn't just have to be to your proposal
to everybody it's that is a fundamental issue
that I think we have to make sure that we're on top
of it as well.
-: Well and Commissioner, I think there's two elements to it.
We want to have more investment.
We clearly see that there was, I think an investment
problem, a supply adequacy problem,
but we also can't have a ton of spare capacity just sitting
around, waiting for an event that happens once 10 years,
once 20 years.
So I think the most cost effective way of getting
that additional reliability is through a targeted insurance
product and that's how I view this.
It creates kind of a safety net that ERCOT
can call upon resources that are paid
to be operable and available, regardless of whether.
-: And all resources could fit
into that or do you have parameters or that?
-: So we wanna be technology agnostic
because that's actually a fundamental rule
of competitive markets.
If we start trying to be very narrow,
we might not get a competitive market as a result.
I think it's not just a...
It will be up to the resources to choose to participate.
But naturally let's say you have a base load combined cycle
that we generally think is dispatchable.
They might say, I'm not going to give up my energy market
opportunities because I'm expecting to make
a good profit there.
So the DSR is not for me, but then we have perhaps
a combustion turbine that is not expecting to run
very frequently in the next month or two
because of expected energy market conditions.
And instead of being mothballed,
which is an economic rational option for the owner
of that unit, they can offer it into this DSR product.
And that means that capacity is there when needed.
-: Thank you.
-: Oh I have a lot of questions,
but I'm gonna reserve them for the Commissioner questions.
-: Portion of our work session.
-: Thank you.
-: One follow-up question.
And then we'll move on the DSR
other than being procured a month or a quarter
in advance and potential for weatherization.
How is it different than non-spin?
-: I think, it may have slightly different technical
characteristics because we haven't...
Non-spin has very specific requirements
at in terms of startup time and responsiveness.
We don't necessarily need a ton of megawatts
sitting there all with, I don't know 30 minute requirements.
What we need is resources that are sitting
there that ERCOT can activate that won't affect the realtime
price so that it won't undermine
what we're trying to do with ORDC.
And replace what ERCOT is currently trying
to do with just procuring a lot of additional resources,
wrecking them and paying for them all the time.
-: So that's ORDC is the stop rocking
let the market rock, that the DSR-
-: Is an additional amount of reserves
on top of it, but it doesn't have-
-: Ramp requirement, et cetera.
(indistinct) similar to (indistinct).
So it'd be like, sounds like a bigger,
I guess procured further in advance
to provide market signals that doesn't undercut
real-time prices when deployed.
-: Yes.
-: Okay, thank you very much.
Next up, we have NextEra.
-: Thank you Chair Lake,
I appreciate the opportunity to speak with you today
on this important topic.
Before I share our proposal,
let me start with the problem that we are attempting
to solve.
And I think Sam framed it correctly,
we're trying to figure out how to address reliability,
how to deal with the supply and demand equation,
where we have thin operating reserves,
particularly in the summer.
But also how can we avoid a February type event
from occurring as well,
if you go to the next slide please.
Thank you.
So we started by assessing the magnitude of the reliability
issue on the charts on the right,
which we defined is the excess of projected peak
from demand over projected firm supply.
And so we did that calculation and as you can tell
in the illustration for 2022
that would suggest that firm supply
is short about two gigawatts,
and it will grow to about three gigawatts by 2026.
So as we step back and think about the context
of that situation there's certainly an issue
we need to solve.
There's a supply issue we need to deal with.
There's a reliability issue we need to deal with.
But we think it's manageable,
we think we can solve it without disrupting
the entire current ERCOT market design.
And so our solution is there's really four steps
in the solution that's meant to try to address
the supply issue.
And I think our overall objective in designing the solution
to close this gap was really to try to find ways
to support existing at risk dispatchable generation
while at the same time providing price certainty,
that will incent new generation.
So if we can go to the next slide.
And I think just one thing you'll notice
is there's going to be and this gonna
sound very similar to some of the discussion
we just had in the Vistra proposal.
The first step in our proposed solution
is to incentivize dispatchable generation
to secure onsite fuel.
So we can avoid another February event.
Fuel security as we all learned is critical for reliability
and we believe gas generators need
a cost recovery mechanism.
So if plants are unable to secure supply,
they still have the ability to run which will help improve
reliability certainly in those extreme stress conditions.
The second idea we had was to create
a new contingent reserve ancillary
leveraging the energy only market design that ERCOT has.
It is meant to provide revenue into the system
to support that at risk dispatchable generation,
give them a revenue stream,
prevent them from retiring and allow them to continue
to operate in and provide that supply.
We also believe that with investment
in demand response to technology and improved communication,
ERCOT can better manage its low demand
and especially in extreme conditions.
So we'd advocate for expanded demand response programs.
And then finally we would also suggest
reforming the ORDC lowering the price cap to $4,500
and modifying the shape of the ORDC.
Now I think it's important that we believe
that along with the contingent reserve
is what's needed in order to insert new generation
because we believe the combination of both of those items
will provide more frequent higher price signals,
which will be the price clarity that investors
need to put new generation into the system.
So let me explain that in a little bit more detail
on the next slide.
Let me first tackle the contingent reserve,
ancillary product, the way it works
think of it as four steps.
So the first step ERCOT would identify an annual volume
needed of contingent reserve procurement
based on the shortfall.
So they would look at from supply and projected
from supply, projected from demand,
they would stress the supply by looking at P95
low wind resource, low solar resource,
E4, hight E4.
And let's say that results in a shortfall of two gigawatts
for purpose of this illustration.
Next they would procure contingent reserves.
In this example for two gigawatts
on a Ford basis using multiple central auctions.
I think one difference between our proposal
and the Vistra proposal is we would suggest
that, that should be a three-year period.
So begin procuring slices of that two gigawatts
and year one, and year two and year three.
And then as we get close to the season,
right before the time period where we're solving
for you would by the remaining 55%.
So it allows the market to continue to adjust
as demand is supply adjust through time with respect
to that shortfall.
And so then existing generation would compete
in the auction to supply the contingent reserve,
lowest costs would be selected.
And then those two gigawatts in this example
of contingent reserves would be held,
withheld from the energy market
which would improve higher price signals.
And then that contingent reserve would only be deployed
in periods of scarcity.
So when those scarcity events occur
then we would deploy the contingent reserves.
So if we take the shift in the RDC curve
and the change in the curve moving from the yellow,
line to the green line on the slide,
and then we also add the contingent reserve.
We think we'll see those higher pricing,
those which we'll say new generation.
And so when you sort of step back
and look at this all the resulting impact
is at risk generation has given a revenue stream
that will keep them on system, prevent them from retiring
and help improve reliability.
And then by holding out the generation
the contingent reserve from the energy market,
it should send us send higher price signals
that will provide that price clarity
that's needed to incent new generation.
In terms of the beneficiaries and the timeframe
with the four ideas we have from existing generation
will benefit from at risk existing generation
will benefit and then certainly over a longer period
of time it should incent new generation as well.
We believe the implementation timing on this can be fairly
quick as well.
We would agree with the commentary from Vistra
and that the market can see the benefits pretty quickly.
And in our view this should greatly improve reliability
and we believe load will benefit from that reliability.
And so we would be proponents of load bearing
that cost but as you can see on the graph,
we believe that cost is manageable.
It's reasonable in terms of overall market designs
that we've considered another proposals.
On the last slide, this is a comment we've shared
in multiple filings with the Commission.
One of the things that we've looked
at is if a significant amount of ancillary costs
or reliability costs were charged
to non dispatchable generation,
what would that do to the supply stack.
As we brand the economics on existing generation
and new generation that would come online
in the form of renewables.
We believe it would sufficiently,
it would significantly reduce the supply stack
and challenged reserve margins.
And if we go back to the original statement I made,
which is we believe that this is manageable today,
we believe it's possible to use solutions
such as this to help with supply
We are worried that charging renewables
these ancillary costs, renewable costs
would just exasperate the problem
if we're not careful.
Can we go back to slide four just for a moment
so I can address...
One more back please.
So to address what Sam suggested
in terms of counter-arguments
and look this is the reason we like
this idea is it's using the energy only framework
within the orchid market and it's relying on Ford price
signals to send information to instant new generation.
So I think we believe it will work,
but I think we still in terms of what would be the counter
is verifying that actually would result
in new generation coming on system.
-: So the only way to kind of argue
this would be to try it if it doesn't work
that was the (indistinct)
-: Well I think there's...
Again a lot of what we're trying to accomplish is the same,
ideas that Vistra are trying to accomplish
as well.
I think it's very signals we believe
in this market should incent the new generation.
-: Alright, good deal.
Thank you, questions for next (indistinct).
-: I'll reserve (indistinct).
-: I'll ask you one question that I consider important
that I didn't ask Vistra, but it applies.
With the cost allocation on load, generally,
do you consider this to place retailers
with a affiliate generation component
at a competitive advantage
to their independent retailer counterparts?
It's an obligation on everyone.
-: Yeah.
So can you just clarify the question?
-: So the concern is if you impose
and again there's no way to offset the cost allocation.
So it's universally applied.
And we do have a public interest concern.
We've got a reliability concern
but we also don't wanna wipe out 20%
of our retail market. -: Correct.
-: How would you address that concern?
-: Well I think the first point I'd make
is I think we gotta find a solution that we believe
will address the reliability issue,
but also be mindful of the costs.
And I think in this instance,
we believe this cost is manageable
and is not going to maybe create
some of the concerns you're raising.
We've considered a number of different proposals
and a number of different ideas.
One of the things that we've tried to stay
away from is a 50 gigawatt ancillary product, right?
So this is, in this example,
a two to three gigawatt ancillary product.
And I think that helps manage the cost
and would help achieve the objectives
you're referencing.
-: I just have one question.
A lot of what you based this on is from supply
and from demand.
It seems to me like we've always been a supply side system,
but as we are getting into more demand response mechanisms,
that becomes a...
Load becomes a moving target as well.
-: Correct.
-: So how do we pay for something
when we don't know what that firm demand is?
-: Yeah, so in the way we thought
about this, I think you're gonna have to look
at those demand response programs
and try to make an estimate just like you're making
an estimate on the supply side
on and stress it a little bit.
So we're stressing on the supply side,
in extreme conditions, we have low wind resource.
We have low solar resource, we have high outages.
What is in that stress condition?
What is the supply stack look like?
And then we need to do the same thing on the firm side.
-: So you're giving it a capacity
value associate, essentially-
-: Essentially in an attempt to identify the shortfall
that you need to set aside in the contingent reserves.
And again, as I mentioned before this product
is flexible so that with a three-year time horizon
as that firm demand affirms supply,
adjust to new generation coming on system,
generation leaving system, that contingent reserve number
that shortfall that the Canadian reserves procuring
can adjust through those three-year option periods.
-: You may have already answered it.
I'll just ask one question we'll move on.
Same question as Vistra,
other than the Ford procurement
and holding out of the scarcity pricing,
how is this different than AIS/centralized capacity
auction like (indistinct)?
-: Yeah, so one is the number of gigawatts
that we're talking about.
-: Small and centralized (indistinct)-
-: And then second we're attempting to do it outside of EMS,
same thing using the auctions that exists.
And for example,
like the CCR auctions and utilizing
those to help purchase the product.
-: Okay, so I just have one question.
I'll reserve everything else for the afternoon.
So my question is why would your company
be advocating for ORDC reforms
if presumably you don't get ORDC adders
because you're not available.
-: I hope you appreciate that our presentation
doesn't result in additional revenue for NextEra.
Our objective in trying to design a solution
was trying to figure out a way to help the market build
on the construct at the energy only market
bring a solution that we think
could help with the supply issue.
We weren't focused on necessarily,
what did that mean for our book of business?
-: I'm pretty sure.
-: Yeah, and with respect ORDC in the adders,
as I think it was just pointed out correctly,
I mean typically what we've seen
is when low wind resource and low solar resource exists.
That's typically when the ORDC adder
kicks in it's not something that we typically
would receive.
-: Alright, thank you very much.
LCRA you're up?
-: Good morning, Randa Stephenson.
I'm thinking my mic is on.
Okay, thank you.
I'm the chief commercial officer at LCRA.
Nice to be with you here again, to talk about our products.
I just wanna say, I am not an economist.
You have a major amount of brainpower in this room
and a lot of wonderful ideas,
but I am very practical and I manage
a half a billion dollar portfolio.
That is my job day in and day out.
And so when I look at finding the problem,
it really comes down to, there's just a lack
of dispatchable resources.
Obviously nothing's been really built recently,
generation resources have lost money
in eight out of the last 10 years.
So any product or any program
we pick here is gonna cost money.
It's gonna be significant.
And then every dollar you invest in a new Peaker
today lose a 64 cents over a lifetime.
Again, very simple numbers
that's why no one is investing right now.
We're trying to find a financial incentive for increasing
fuel resiliency as another goal
of what we're trying to accomplish with our proposals.
And ERCOT has no form of reliability standard
for a lot of people talk about this.
We believe you need to put a requirement
in where we've been at one in two loss of load events.
It's just not bearable to the state and from an economic
development perspective as well.
So that's another big concern I have.
Next slide.
I talked about the dispatchable reliability service.
This is forward-looking,
that's the big difference than using the current
fleet of AIS.
I'm trying to get price certainty out there.
So you get more peakers or multiple batteries
that can provide the service.
When you wanna know the counter argument
right off the bat, this product does not...
Is not technology agnostic.
This is really focusing on something that can respond
within 30 minutes and provide power continuously
for 24 hours.
-: (indistinct) answering the counterargument.
-: No problem.
And I realize it by all means.
But when we look into the future of our fleet
and what we need for reliability resiliency,
we definitely need the existing fleet.
I don't really discount any of that.
However we're gonna see so much more solar
and renewable penetration,
having batteries and quick acting peaking units,
I think is something we have to build toward.
So that is really one of our qualifications requirements
I'll say.
Pricing, you really need a minimum of $10 a megawatt hour
I'm sure counter argument, it's not really why put a price
floor in, right?
Like competitive markets work.
We are not seeing these units
we built, we're not seeing the prices clear.
You can change the ORDC,
I still don't think you'll get new peaking units on board.
So this is something that really gets you there.
And it doesn't have to get you there for again, 10, 20 gigs.
It can get you there for two to three gigs.
Whatever you really think you need to meet
the reliability standards set.
I agree with Vistra about you have to also be concerned
about real-time energy prices and price suppression.
So whatever you do and reserve the service,
you have to put it at the back of the stack,
whatever you wanna define that as.
And then compliance,
we've been talking over the past few months
about what helps ERCOT from reliability standpoint?
One of the things is knowing in COP
if a unit is going to be available a week ahead of time.
Well, this is a requirement to do this product.
So we are trying to match that up with the conversations
we've had over the past few months.
Obviously incentives and penalties for folks
that aren't there and then this can be a bilaterally
traded market as well.
So there's a lot of ways to use what we call trades
or a capacity trade to provide
this dispatchable reliability service also.
You don't have to just pick (indistinct) from ERCOT.
You could say here, my load, I'm self providing this.
Here's what I have for a contract too.
So I'm trying to see it as a lot of different avenues
to get load, to pay for a service that is very specific
to what happened to winter storm URI.
That's all I'm trying to solve with this product.
The next product is firming fuel service.
I agreed with a lot of what Kanaan had said earlier.
I do think this could be a one-off program that evaluates
bid selects the most effective program
or proposal I should say.
The reason you can't do this within the day ahead,
as fleet and market is because a lot of these proposals,
if you wanna build the resiliency,
we'll have infrastructure capital projects.
That takes time and it takes money.
And so if you're going to try to build
that throughout the grant without...
And trying to find a system that has those fuel backup
supplies which could be.
We've talked about storage,
we've talked about multiple interconnection for field
transport, dual fuel.
These are all things I think we need to hire a qualified
expert to come in, look at the grid,
work with the railroad Commission and some of the other
agencies looking at this and put together a plan.
To me, there's no reason not to move forward
with understanding the weaknesses on our grid right now,
from a field resiliency perspective.
Obviously we would have a competitive bid process,
and like I said earlier, there will be some proposals
that have capital cost requirements.
So that may be something that you want to contract for five
or 10 years, right?
These are why you can't do it just day ahead.
These are some projects that will be longer term in nature
and higher costs.
There could be O&M of existing from fueled capabilities.
Stack has testified earlier about they already...
They continue to have Dual Fuel on their facilities.
And that was part of their success during the winter storm.
Well, there's a cost for that.
They're not recuperating that cost right now.
And so allowing folks that already
have made those investments to play in this market also,
I think is important.
And then as you look at these proposals,
make sure they're coming from generators
who understand the physical limitations of their grade.
And I should say of their supply on the gas perspective,
because there are so many pressure issues,
location of compression stations,
where are you in next to you in a processing plant,
all of those play into a big, big part
of the firming field resiliency that we need on the grid.
So implementation just real quick,
I do believe we could do this all outside the EMS.
We do agree with a lot of the tenants that a lot of folks
are here to discuss on any type of dispatchable product.
As long as it doesn't take us three, four years
to get something done.
That's our biggest concern.
We also recommend a third party come in and put
in a reliability requirement.
We have had a stop do a one and 10 year standard
and look at those types of reliability requirements
through ERCOT processes before.
We should do that again,
make sure we understand what numbers
we're talking about here.
As I really have talked about this near term solution,
one thing to consider is on some of the more complicated
longer-term solutions out there.
We have been working on a proposal
we put in the appendix.
I don't wanna even talk about it, but I do wanna mention
there are different ideas out there.
Ours is a resource adequacy adder.
We have been working on this since even before the storm.
So this is not something that's just based off what happened
to winter storm URI.
-: All right, thank you Brenda.
-: You're welcomed.
-: Questions for LCRA.
One question, as you pointed on the gold star
earning counterargument earlier.
-: I figured that all will say soon or later.
-: The dispatchable reliability services
full version of AIS.
But not as big as a PGM type essentially cleared,
but may have some bilateral features.
If we look at our future fleet makeup,
the 27,000 a wind now 30, 40,000 if in the absence
of other action both,
all of you said that the small size of the reliability,
the insurance product is a feature.
But if the COP has an expectation of 20,000 megawatts
of wind, and that goes to zero,
what good does two or 3000 megawatts
to you as your insurance product?
-: Sure, so you have to maintain that the rest
of the fleet is gonna do that for you, right?
Your current generation fleet is going to be there for you.
I own a motorcycle that's 20 years old, lost bonds.
That facility is always offered into the day ahead market.
It is up to how we offer it in and what clears in the ERCOT
engine deploys that unit.
Once that units align we have ramp rate.
So how quickly can we move up and down, right?
For an old units about 20 megawatts per minute.
All that data ERCOT has, ERCOT is the one that dispatches
us up and down based off those ramp rates.
And that's, to me, part of their reliability
responsibilities is to manage that up and down movement.
And so, I look to them to answer that question
to be very honest.
I'm gonna provide that unit in there.
I'm gonna tell you the parameters.
I'm gonna tell you when it can work and when it can't.
And we have that... -: It's (indistinct).
-: Yes, but I'm saying I offer it today.
I think there's a big concern of many generators
who don't offer into today ahead.
I think it's a panful
and it's because of the type of generation they have.
It is not as big of an issue
as I think it's been made out to be.
And that's something I think,
I don't know the exact numbers,
but that's something that probably ERCOT
could answer for you.
-: So Rhonda, just a point of clarification,
you're talking about day ahead market two.
So you will classify your DRS product as an in-market
product rather than an out of market sort of insurance
policy like Vistra and various proposals.
-: I think so I would, 'cause it goes hand in hand
with a lot of the obligations
of being there in the real time.
And you do not get those kinds of capacity payments
or AIS payments you wanna call,
if you're not there and you're penalize also.
And just with the normal market design,
if you don't show up we're penalized already
because we're buying power at, during winter storm URI
$9,000, right?
Much higher.
So I have every incentive to get that unit they're producing
during that time.
-: So and because it is an in-market sort of AIS reliability
project product.
You're saying that you can get around the EMS upgrade
with having your COP procure this product
sort of like ERs or Blackstar.
-: Exactly.
-: Okay, and with respect to the ORDC,
you mentioned that it wouldn't get any new Peaker build-out
can you explain more?
-: Sure, we've looked at all the proposals
and did a backcast over the last year.
And we ran...
I'm lucky to have John Dumas in my shop.
So he's done this before and rerun the impact
of a lot of these different proposals.
Do they all put more money into the market?
Definitely, maybe except one.
And I think Rhoda will be able to show you that.
Does it incentivize enough generation
to give you the resiliency you need
for another winter storm URI?
My answer is no, I don't think there is enough.
You'll get money and you'll get...
You'll see the scarcity pricing,
but I don't think it's going
to get enough new generation built.
-: So, but with respect to peaking generation
my understanding is and just kind of looking
at this issue and visiting with stakeholders,
it seems that the ORDC reforms have been proposed
would increase adder, ORDC adders operating reserves
over more hours.
So you're not gonna have those peaking opportunities
for your unit.
So it's actually going to potentially negative
and negatively impact your peaker resources.
That's why you would need sort of an alternative
whether in market or out of market concept
to make sure that we're not negatively impacting
our existing or potential new peaking generation investment.
-: Yes, I agree with you.
What happens is a peaker when we look at it right now,
based of a 20 year proforma,
based off where the forward curves,
it's only running 10 to 20% of the hours.
So yes, it's capturing some of this energy value,
but really when I look forward to where...
What's really gonna get peakers built in on the ground,
it's gonna be a steady ancillary service stream
that they can count on.
I think I've talked about that previously, so.
-: All right, thank you very much.
I appreciate everybody on panel one.
We will at least get the first part of panel two
in before our noon stop for lunch.
All right, TIEC.
-: Thank you.
Are we ready? -: Yes ma'am.
Timer starts now.
-: Thanks, so I wanna first address Sam's question
about what are we solving
because I sense that there's a perception
that we're focused more on the day-to-day
operational issues, and that is true at some level,
but I think that, that's a little bit of a false dichotomy.
You can solve long-term investment incentives
through creating the right day-to-day operational
and market incentives.
And I think a really perfect example of that we often forget
because electricity was once regulated.
So it's easy to go back to that mindset
of fixed revenue streams.
Think about my clients.
My clients invest, I mean, you've heard the new Samsung
is looking at a $17 billion investment in Texas.
Any new chemical facility, several billion dollars,
refineries, several billion dollars.
They're responding to market needs
that may change over time.
That may not be there in a few years.
And nobody's sitting around saying,
how do we ensure revenue sufficiency
to make sure we have enough refineries, right?
How do we make sure that we have fixed payments to refining
companies or chemical companies
to make sure that they continue to invest in Texas?
And I would challenge you to try to think about the electric
market in that same way.
That was the whole purpose of deregulating.
The electric market is, we're gonna move away from a world
where we are guaranteeing fixed revenue streams
from customers to generators
and we're gonna put that risk on the generators.
And my concern is that a lot of these ideas that are framed
as ensuring long-term resource adequacy are really designed
to ensure guaranteed payments from customers,
revenue sufficiency.
So I would challenge you to try to think about ways
that we can address what I perceive is the real problem,
which is today, our market is not signaling
that we have an additional...
We have a need for additional supply.
We're not sending those demands signals
and the reason for that is because all megawatts
have been assigned to the same value.
The instances where the supply drops off dramatically,
while it's a very real threat that needs to be addressed,
it's happened so rarely that it's not something
that customers have experienced on a regular basis,
and it's not something that the market
can really invest around, but it is a risk
and it's gonna continue to grow.
However, I think if you address that operationally
by sending more day to day market revenues,
to the resources that solve that problem,
you will get changes in long-term investment patterns
around that shift.
And so I do believe that we are primarily focused
on the operational problem
because that's what the problem has been.
But in addressing that, I do think you will solve
the long-term resource adequacy problem.
So I just wanted to push back a little bit on that being
like a complete red line.
So going through my slides, I thought it would be helpful.
Our written comments focused
on our sort of service proposal,
but there are some areas that I think are consensus
that are maybe low hanging fuel ish for y'all.
Not complete consensus, but I wanted to go through it.
So $9,000 a megawatt hour, that's not a magic number.
Those of us who were around at the time,
there was a value of loss load study that had numbers
ranging from 4,000 to 40,000.
I mean, there are 200,000, I think even for some large
manufacturers, it was just all over the place.
So at some level, this was plucked out of there.
And I think that you could reduce
it if you wanna de-risk the market.
The dynamic there though is the lower you reduce
that penalty that applies when a generator
who said they were gonna perform
doesn't show up and they have to replace in the real-time
market or the demand response incentive,
you're reducing market performance incentives.
So that's the trade off.
We do...
I know from my clients that you lose demand response
between 45,000 and 9,000.
I mean 4,500, Jesus, 4 500 and 9,000.
And that's because they have operations that continue
to be economic at 4,500.
There are many fewer operations
if any that remain economic at $9,000 power prices.
So you are gonna lose some demand response capability.
We would prefer something more like 6,000.
On the ORDC issue, I do think that there is room
for changes there.
Our main focus in that is continuing to keep the incentives
relatively focused around reliability concerns
however you all define that.
It may not need to be EEA as we define it today,
but what is the level
where we start getting concerned, right?
And we would prefer to have the minimum contingency level
extended rather than thickening and flattening the curve.
As you saw in the London economics presentation.
When you get out to like 7,000 megawatts,
you're creating a $6 per megawatt hour adder,
and that's a very healthy level of operating reserves.
And so essentially that's just like a $6 around
the clock adder for customers.
And again, going back to my guaranteeing revenues
versus incentivizing performance,
I think that trends a little too far in that direction.
So we would prefer extending the MCL and not making changes
to the shape of the curve.
Our firm fuel service, I'm not gonna spend a lot of time
on this, but I think there's pretty broad consensus
that that needs to be done.
Next slide.
So this is really the source of the disagreement
and as I said, in my opening remarks,
we view this as an operational problem,
not an installed capacity problem.
Chairman Lake, you mentioned this.
I think Commissioner McAdams, you did too.
This one event in 10 years standards
or even an expected unserved energy standard
those are static snapshots in time
and they're based on a ton of administrative parameters
that are hardly ever accurate on a day-to-day basis.
And so trying to design revenue sufficiency
to meet some static snapshot like that.
I mean, again, we're getting back to like regulated,
integrated resource planning, right?
I believe...
Well, and the other thing is, we've had these predictions
about one event every two years,
one event every 10 years,
we have never had an event where we just ran out of supply
and everything was operating as normal.
All of our reliability events have been driven by unexpected
drop-offs and intermittent generation,
unexpected, forced outages, those are operational issues.
And so that's really what we think you all need
to focus on is creating additional reserves every day
in real time that are dispatchable and paying them.
And we have danced around a bunch of different ways
to do this, including having a minimum amount
of dispatchable that you commit every day.
Commissioner McAdams I know you were looking
at mandatory day ahead obligations.
I think if you look at it that ultimately
sort of all collapses into, why don't we just buy more
dispatchable services day in, day out
and pay them to cover off this operational risk?
And so that's essentially what we're proposing,
but I do believe that it solves the long-term problem
if it's designed correctly,
because it's an additional revenue stream
for those resources that they can invest around,
and there's no magic about a forward market.
If this is something that you're buying every single day
and there's transparency around the quantities
and the pricing becomes predictable,
you can invest around that, just like you can something
that's announced a year in advance
or two years in advance.
And in fact, that's the way most other markets work
as I mentioned.
Next, I'll skip this, let's go to the next one.
So I touched on this, but in terms of quantity,
I think we need a little more data
to know what this is, but as opposed to non-spin,
which was designed to address hour to hour changes
in net load, this would be broader.
And in my defense,
some of this does start sounding like what ERCOT
is doing with non-spin today
but we've had this proposal for a long time.
And ERCOTs are a treatment of non-spin over the summer
has sort of evolved into looking
more like this than it did when when we started.
So the idea would be not just hour to hour load variability,
but across the board.
What have we seen historically season by season
in unexpected forced outages, unexpected high demand,
figure out what that is statistically, and cover that off.
I've got one more slide.
And finally, the other big difference is, I think you guys
have a lot of latitude on how these costs get allocated.
In fact, I think the Governor has said,
look at cost causation, and that's an important piece
of this that we don't do today.
There have been calls to allocate non-spin
to intermittent generation for a really long time
that's never been done.
I think there's a lot of challenges there, frankly,
but one thing that you might consider,
and I think this is sort of like a more dynamic compliment
to what energy is proposing.
We already have a mechanism to allocate across the people
who are capacity short today
through the reliability unit commitment process.
And so that is a technology neutral way
to do these allocations.
If you are an LSE and you're short,
you get allocated those costs.
If you had a day had obligation and you don't show up,
you get allocated some of those costs.
And there are also forecast for renewables
that are used to provide a shore allocation for RUC.
I think you could repurpose something like that to allocate
a new service and create similar hedging incentives,
which would then create an additional revenue stream
for dispatchable resources,
because people will be incentivized to hedge with resources
that don't expose them to those additional costs.
So I think a lot of benefits there.
-: Thank you, Katie.
Before we depart for lunch, counter argument.
-: Counter argument
to our proposal. -: Yes.
-: So I'm gonna say that the counter argument
to our proposal is actually the same
for every single proposal you're gonna hear today,
which is it doesn't guarantee you that anybody
is gonna build anything.
The only way to do that is to re-regulate
and tell somebody to build.
And so, or to do some kind of an auction,
like the proposals we've heard at the legislature
where it's mandated customer payments to fund capital.
I don't think that's the direction that we wanna go,
but this is I can't sit here today and guarantee
you gonna get X number of megawatts out
of this nor can anyone else?
-: All right, thank you ma'am.
All right, we'll do 45 minutes for lunch,
and let's say we'll be back here at 12:40.