Good afternoon.
Welcome, everyone.
I'm so glad that
you're all here.
And moreover, I'm very happy
that we have Professor James
Bushnell here with us.
Professor James
Bushnell is professor
of economics at the University
of California Davis,
and a research associate
of the National
Bureau of Economic Research.
Prior to joining UC Davis,
he was the research director
of the UC Energy Institute
and the Cargill Chair
in Energy Economics at
Iowa State University.
He holds a PhD in operations
research from UC Berkeley.
Since 2002, Professor
Bushnell has
served as a member of
the Market Surveillance
Committee of the California
Independent Systems Operator,
otherwise known as CAISO.
He has also advised the
California Air Resources
Board in several
capacities, and has
consulted on the design and
performance of electricity
markets around the US
and internationally.
I think we'll hear about some
of his work and those capacities
today.
And without further ado,
thank you, Professor Bushnell.
We're excited about your talk.
All right, thank you.
Sound OK?
Good.
Yeah, it's great.
Thanks very much
for the invitation.
As you heard, I got my degree
in operations research,
and shortly after
my PhD, I started
migrating over to economics
and working with economists,
from whom I learned that
the phrase well-trained was
to be used synonymously
with degree from MIT.
And so it's great
to be here with all
these well-trained people.
So can electricity markets
survive deep decarbonization?
We got a late start, so some
of you may have to leave early.
I'll give you the quick answer.
Yes.
The longer answer,
which is going
to be a lot more nuanced, is--
the way I think about is that
I don't see decarbonization
fundamentally changing the
arguments that I've been part
of for the last 10, 20
years, in the sense that,
since their inception,
restructured, liberalized,
deregulated-- whatever
term you want to use--
electricity markets have
struggled to find this balance
between the right kinds
of short-term pricing--
particularly under scarce
conditions, and maybe
excess supply conditions--
providing market
based incentives to try
to improve efficiency,
balancing that with the
need for raising capital
for investment, long-term
financing for plants
on the seller side,
and on the buyer side,
hedging exposure to prices.
And then also, we have to
worry about supplier market
power in this mix, as well.
And a lot of times,
we've really struggled
to try to balance some
of these competing goals.
And I think we're going to
still continue to struggle,
but I don't see high
shares of variable energy
resources, renewable generation
fundamentally changing
these questions.
Although, it is going to
kind of raise the stakes,
as we'll talk about, and really
bring some of these trade
into sharper focus.
So as I go--
I realize I'm going
to end up spending
like 1/3 of the talk just
defining what I my terms
in my title--
so I'm going to talk a
little bit about what I mean
by deep decarbonization here.
Generally, we're going to talk
a lot about renewable generation
of electricity.
And then a surprisingly
difficult topic,
what do I mean by
electricity markets--
there are lots of
different definitions,
so I'll give you mine.
And then I'm going to try
to lay the context here.
There certainly are
some issues about how
one finances renewable energy.
Although, certainly,
where I come from,
in California, that's
the least of the issues.
There are plenty of
contracts out there
for renewable suppliers.
Really, the
hand-wringing concern
in a lot of parts of
the United States right
now has to do with the
non-renewable generation,
and how they are doing in
wholesale electricity markets,
and what the implications
of high renewable energy
are for those types
of generation.
It goes under the rubric
of resiliency of supply
at the national level.
In California, there
is a lot of focus
on the question of
flexible supply,
and whether we can
keep enough of it
around, at least in
the transition period,
to maintain reliability.
So I'm going to
talk about pricing
in the short-term markets
or the daily markets,
the potential role or how
the idea of capacity markets
fits into this.
My underlying theme
here, or punchline,
is that we've
always really relied
upon long-term
commercial arrangements
between large buyers
and large sellers,
kind of underpinning
the operations of things
like markets and ISOs that
get most of the attention.
And we're going to
still need to rely
upon those types
of arrangements.
And really, I view questions
about capacity markets
and related sorts
of environments
as what types of long-term
contracts and arrangements
are we encouraging
or incentivizing
buyers and sellers,
and how do we
get the right amount of
those types of arrangements?
OK, so deep decarbonization,
what I mean by this--
back in my part of
the country, there's
a lot of very ambitious goals.
Now ex-Governor Brown had
an executive order to try
to promote a zero--
I guess this headline
implied less than zero--
but basically certainly a
net zero economy by 2045.
Now, our current
regulator, Mary Nichols,
has admitted that we,
frankly, don't know
how we're going to get there.
And it's interesting.
If you Google California
2050 climate goals,
the first thing that
pops up is a picture
of Ernie Moniz at a
Stanford conference,
basically articulating
similar issues
about exactly how do we
approach a deep, deep, deep
decarbonization.
I get nervous when we talk
about things like zero, or 100%.
They're pretty blunt
numbers, and we don't quite
know exactly where those--
the right targets might fall.
I'm going to phrase this
a little more loosely,
and basically, the
plan in California--
at least right now-- and I've
heard versions of this plan
in a lot of parts of the world
that are pursuing really sharp
decarbonization--
is to basically, step 1, remove
as much CO2 as possible--
maybe 100%--
from the electric sector.
And then transition other
sectors, like transportation,
home heating, commercial
heating, to electricity.
I realize there are other
pathways to doing this,
and I certainly would be open
to maintaining flexibility
in exactly how we
pursue this, but this
does seem to be the current
trajectory that, at least
California is pursuing.
We're pretty far
along on step 1.
We have been expanding
the generation
from renewable resources
massively this decade.
This just represents
the different sources
of grid scale energy that have
been added to the CAISO system.
This decade has been a really
massive expansion of solar,
in particular.
I'm going to talk more about the
ramifications of that, as I go.
We are about 1/3 of
our energy from--
depending on how you count hydro
and other things, 1/3 to 1/2
of our energy from
renewable resources.
We're almost certainly
going to get to 50% by 2030.
There is now a law
targeting 100%.
I think there's still
a lot of flexibility
right now on how exactly
one defines 100%,
so we're not sure
exactly what that means.
But that is, in theory,
the long-run target.
Like I said, I get
a little nervous
about trying to pursue, say,
100% versus some other level,
and the reason--
I'll give you a
scientific rendering here.
Conceptually, I worry that
there is going to be some point
where, as we're continuing to
add renewables to the grid--
particularly variable energy
resources that are available
only when the
weather cooperates--
that you could imagine
during some range,
costs might decline,
but at some point,
the remaining percentages
going-- and we're not sure
exactly where that is.
It might be going from 70% to
80%, 80% to 90%, 90% to 100%,
but at some point,
the incremental cost
of squeezing out that last
5%, 10% of nonrenewable energy
might raise the overall cost
of the system very sharply.
And at least economists
get nervous about pushing
two points where those types
of sharp inflection points
start to happen,
because you start
to think about what
the implications are
for other parts of the economy.
In particular, if we think
about a potential rapid rise
in electricity production costs
happening at the same time
where we're hoping to expand
the use of electricity
to a bunch of
other applications,
we have to think about
the implications are
for making
electricity attractive
to those other applications.
And some work I've been doing
with Severin Borenstein is
trying to think
about that question
and where things
stand right now, which
is how do prices of
different energy resources,
from a retail perspective,
relate to the costs--
both environmental
and private costs--
of supplying those
energy resources?
So I'm going to show you a
couple of maps from that.
This is still a
work in progress.
But the general
idea here is we've
been trying to calculate the
relative retail price that you
might pay--
the dollars per gallon
at the pump, or cents
per kilowatt hour, if you're
an electricity consumer--
the variable price you're
paying for those types of energy
compared to the
cost of consuming
that energy-- both the
private cost of supplying
the actual energy and the
environmental costs associated
with it.
These are actually
just air quality costs.
And we're using a $45 per
ton cost of CO2 in here.
And you can certainly argue with
a specific number choices here,
but the qualitative
story is essentially
the more blue this map
is, the higher the price
you pay for energy
relative to the actual cost
of that energy--
again, including
the environmental cost.
So in California, the
marginal price of electricity
is more than double the cost
of supplying that energy,
where the--
at least the short-term cost
of that energy is quite low,
and it's very clean.
Relative to, say,
gasoline, where
everybody complains about
how expensive gasoline is
in California--
I guess they complain
about that everywhere,
but certainly it is relatively
expensive in California.
But compared to the cost of
supply and the externalities,
the environmental costs
associated with it--
particularly in places like
Los Angeles, the Bay Area,
with the local pollutants--
have a major impact.
Gasoline is still
underpriced, relative to that,
what economists would call
the social marginal cost--
the environmental cost
plus the private cost.
This is a bit daunting,
in the sense of we're
trying to get people to
go from this over to here.
But we're already starting
at a disadvantage,
in terms of the relative
pricing relative to those costs.
And if we continue to push
electricity forward first
by cleaning it up-- even though
it's already cleaner than
the other sources--
and at the same
time make it more
challenging to try to migrate
people from other sources,
then we have to think about
what the overall spillover
implications are.
I have natural gas in here.
I don't really have enough
time to talk about it.
The reason there's a
lot of gaps in that map
is just it's been harder for us
to collect the kind of pricing
data that we would like.
All right, you might be curious
about your part of the world.
It's same story.
Hate to break it to you.
Your electricity
prices are high,
and your gasoline
prices are also high.
But it's also dirty.
So again, in the Northeast,
you have the same sort
of qualitative story-- that
the electricity is overpriced
relative to its
social marginal cost,
whereas gasoline is
underpriced relative to it.
All right, so that's kind
of where I want to go,
in terms of deep
decarbonization.
We're thinking about
what the implications
for the electric sector
are of maybe not 100%,
but of a large scale
up of the amount
of zero-carbon
resources-- particularly,
if they're coming from these
variable energy resources.
All right, so what do I
mean by electricity markets?
This is a more
complicated question
than you might
imagine, because there
are lots of different dimensions
to what one might describe
as an electricity market.
So at one level--
a part that I interact with
a lot, the independent system
operator--
there is the availability
of transmission,
let's call it access, where
in a restructured market,
you have a whole bunch
of potential sellers
of electricity interacting with
a bunch of potential buyers.
And they need a platform to
reach exchanges that doesn't--
where their transactions don't
necessarily burn out the grid
and cause cascading blackouts.
So that's where independent
system operators come in.
They try to
accommodate these kinds
of commercial transactions
between decentralized buyers
and sellers, while
at the same time,
maintaining system reliability.
And they do this by running
things that we call markets.
They have sort of the lingo
and trappings of markets.
I like to call them
balancing markets,
in the sense that there's a lot
of commercial arrangements met
in advance of the day
ahead and the day of.
And as those transactions
are tweaked and adjusted
to real-time system
conditions, the ISO basically
will purchase or sell
electricity on the margin
to try to make sure that
supply is equaling demand
in all the right places
and all the right times.
Like I said, we use
the lingo of markets,
but there's really just a big
optimization program running
behind the scenes here
that's trying to minimize
the cost of operating system.
It's not unlike this kind of
programs that were run back
on the days of regulation.
It's just, instead of a utility
staffer or utility employee's
cost number going
into the software,
it's a bid coming from
some kind of supplier,
or maybe even a consumer.
All right, so that's
the platform, the ISO.
At the customer-facing
level, there's--
in some parts of the
country and world--
retail competition where the
company you are personally
buying electricity from--
you might have choice between
different sources of that.
Unfortunately, I don't
really have any time
to talk about this in detail.
There's some interesting
things going on in California,
with regards to community
choice aggregation.
Maybe we can come back
to that, but I'm not
going to have a lot of
time to focus on that.
So I'm going to focus mostly
on the third component-- it's
my favorite-- definition
of what electricity
restructuring means.
And that's really
the transformation
of how generation
resources are compensated.
Traditionally, under the
regulated vertically integrated
utility, the old
utility company model,
a utility would go out, build
the generation and other assets
necessary to make sure its
customers get reliable supply,
and then, as long as they
didn't screw up too much,
the regulator would
allow them to recover
the costs of those investments
plus the rate of return.
So use the phrase
cost-based compensation.
The mode in which
generation is paid
is based upon their cost of
actually building and operating
the plants.
And the
restructuring/deregulation
movement really was a transition
away from this cost-based model
to one in which it's--
competition's based on markets
or the market value of the
electricity at the time
the electricity is produced.
I've used the analogy
with mixed success
over the years of like shifting
from renting to owning,
in the sense that a rate
payer under the old regime
owned a little share
of the power plant.
They basically paid
for building, owning,
and operating the plant, and
what they got out of that
was electricity.
And as they transitioned
to the current model,
instead of owning the
means of production now,
they're instead buying the
actual commodity coming out
of the means of production
at a market price.
And what's happened over the
years is, as you can imagine,
just as in housing,
the attractiveness
of being an owner versus
a renter kind of moves
with the dynamics of the market.
If you have a market with
a lot of excess supply,
being a renter who can buy
off of this glut of supply
can look pretty attractive.
And in periods when supply is
really tight, being an owner
actually looks pretty good,
and the politics and rhetoric
around deregulation
versus regulation
often move in the cycles of
whether owning or renting
looks like a better
or worse deal from one
side or the other.
All right, so we're
going to think
about how this idea of
being paid based on a market
value of the
electricity, as opposed
to cost of construction,
plays out in the world,
as we're ramping up more and
more renewable resources.
So just to give you a
sense of how this looks--
this definition applies
to the United States--
this is now getting
to be pretty old,
but I don't think these numbers
have changed dramatically.
So the darker red
this picture is,
the higher the percentage of
energy being produced from
resources, according to Energy
Information Administration,
that were classified as
non-utility generators--
which I'm using as shorthand for
they're not compensated under
a cost-based model--
they're compensated
under some kind of deal.
It might not look
very market-like,
but it is some kind
of deal reached
between a buyer and a
seller that's not directly
tied to the cost of
constructing the power plant.
And there's actually a
pretty nuanced picture here.
There are parts of the
country we don't normally
associate with deregulation
that have percentages up
into the 20s.
Some of those are deals
between the utility
and the utility's
affiliate, so market,
is-- in air quotes--
in "some places."
But this part of the
country has gone pretty far
down that road of generation
being largely compensated
at market-based prices.
A lot of this was transition
from a utility company
to a unregulated or
less regulated affiliate
of a utility company.
OK, so the national
context here--
right now, in the
last, say, five years,
there's been a pressure on the
sellers of electricity coming
from low energy prices posing
serious financial challenges.
There's been work out of places
like here and elsewhere trying
to trace the sources of this--
some combination of low
natural gas prices--
mostly low natural gas
prices-- and renewable energy
contributing to these low
wholesale energy prices.
I'm going to correct
myself a couple times.
In the back of your heads, you
need to keep track of the fact
that, when I talk about
prices, most of the time
I'll be talking about
wholesale prices.
These are the prices
on the ISO markets,
and are largely linked to what
these generation resources are
compensated.
And then there's going
to be retail prices that
will come up periodically.
They are not necessarily
the same thing.
In fact, they're
often quite different.
So part of the story here
is, as wholesale prices
have been declining,
retail prices have actually
been rising, and
that's been part
of the added pressure here.
All right, so I'm talking
about wholesale prices here.
These are low
[? opposing ?] challenges,
particularly to baseload
generation sources,
like nuclear and coal.
The federal government has
been, the last few years,
trying through a few
different avenues
to try to come up with
ways to provide support
to what they call resilient
resources that are baseload
generation resources.
At the same time,
many states have
targeted different
types of resources
for different reasons.
There are several states with
aggressive renewable mandates
and renewable support policies.
There are several states--
Illinois, New York, and others--
that have supported
their nuclear generation
through certain types
of direct intervention.
States like Ohio have tried to
support their coal resources.
It's still ongoing.
So different states have
different sets of reasons,
and they're all
trying to support
different types of resources.
The issue, from a
federal perspective,
often is that these state-level
policies, because these states
share pooled
electricity markets,
spill over and
affect both prices
and environmental outcomes
in their neighboring states.
So from a federal
perspective, where
there are laws governing
what is fair interstate trade
and what is reasonable
competitive practice,
they're still
struggling with what
these types of targeted policies
mean for the ideas of what
fair markets imply.
Now, in California, the
context is specifically
on what to do with certain
types of generation
that our system
operator, the CAISO,
deems as necessary-- at least in
the near term-- for maintaining
the reliable operation
of our regional network.
And we use the term
flexibility here.
Yoga's really big in California.
The idea is we need
resources to try
to be very quickly
responsive during periods
in which the renewable
resources are not available.
And there is concern that
these types of resources
are not earning enough
out of the market today.
And they're also having
trouble finding counter parties
on the buyer side that
are willing to make deals
with them, or at least admit
that they're buying power
from a gas plant,
which is not viewed
as a good look for a
California energy company.
And therefore, they
have periodically
threatened to retire their
conventional generation
resources.
There have been
interventions by the ISO
and at the regulatory
level to try to prevent
these types of retirements.
And there's still a
struggle for exactly how
to find enough compensation,
or if the market is
providing enough compensation
for these types of plants.
All right, so that's
all kind of background
to what I'm going to
focus on here, which
is what the implications of this
addition of renewable energy
means for the
dynamics of pricing
in these wholesale markets.
Again, I'm going to think about
this is the wholesale level,
these are the short-term
markets, independent system
operators.
Those of you who worked
in the energy industry
have seen pictures like this,
or have them pop up in your head
whenever you think
of a power market.
How many people are familiar
with an idea graph like this?
Yeah, OK.
So still half the room.
So the general idea, call
this a generator stack.
Or economists like
to think of it-- hey,
it's a supply curve-- it looks
a lot like a supply curve.
If you take all the
generators in a system
and you sort them from
the lowest operating
cost, marginal cost
to the most expensive,
the general idea behind
operating a electric system--
at least cost-- is
when demand is low,
you use the cheap stuff first.
And then as demand goes
up farther and farther,
then you bring on the
really expensive generation
to try to keep the lights on.
But you're using it only
when you absolutely have to,
because it is the
most expensive.
Now, there are other constraints
going on behind the scenes,
so that moving up
and down this curve
is not automatically as
simple as we would hope,
but that's the general
idea behind this.
And the idea behind
turning this into a market
is the observation
that, well, when
we intersect the
actual level of demand
here with the
marginal supply, well,
that looks a lot like a market.
And in an economic sense,
this is the incremental cost
of being able to
meet your demand--
if you flick a light bulb on or
charge your electric vehicle--
and it's the incremental value
that's provided to the system,
if you are able to
generate one more
kilowatt hour to this market.
So setting the price
or rewarding suppliers
at this short-term price
and charging customers
in the short-term price
is, in the economic sense,
the efficient signal
to be sending,
as to the value of energy
at any given point in time.
And we're just used
to these convex curves
where, yeah, sometimes
the price is low.
Sometimes the price is in the
middle-- most of the time.
Sometimes the price
is really high,
but we're just kind of moving
up and down this curve.
Now, the challenge
that a lot of people
have in their head,
when they think
of a world with large
or 100% renewables,
is, well, renewables has a--
wind and solar has a marginal
cost essentially of zero.
It's all capital.
And so in a lot
of people's minds,
they are forming a supply demand
relationship that sort of looks
like this, where
we're going to just
have lots of wind and
solar hitting the system,
and demand is kind of
going to move up and down.
But the incremental cost
is always going to be zero,
and so we're just going to have
a zero price on this market
all the time.
And if we have a zero
price on the market,
how is any supplier
supposed to make any money?
How are they supposed
to recover any costs
towards their capital?
Now, there are still going to
be some issues about recovering
costs, but I want to push
back against this notion,
because this is essentially a--
this would be a mistake,
if we get to a market that
looks like this.
Because this means that the
added value of electricity is
zero all the time.
And so that probably
means we built too much,
if we're in a world
that looks like this.
It almost certainly
means that we did.
Instead, there's
some things missing
from a picture like this.
I've run into people
who've worked on strategy
on the internet, and they
think about this as--
renewables as disruption of the
electricity industry, akin to,
say, how the book publishing
industry or the recording
industry was disrupted.
But the big difference
in electricity generation
is Amazon can crank out
another e-book for me
at zero marginal cost.
So there isn't a quantity limit
at how many e-books Amazon can
make--
where there are limits, there
are capacity constraints
on how much renewable zero
cost generation any given solar
or wind [INAUDIBLE] can
produce at any given time.
So capacity constraints
really matter,
and that's going to enter
into the idea of how
prices should work.
So what's missing
from that picture?
First and foremost is this
idea of scarcity pricing.
When we accept the
fact that we can't just
produce unlimited renewable
energy at zero cost,
then we have to deal
with how we clear
this market in periods
in which we do not
have unlimited capacity.
And we do this now.
So the general idea is,
when supply is tight--
or when just even a specific
type of supply is tight--
prices are set above that
offer price of every generator.
So they are earning a price
above that incremental cost,
and that contributes
to their recovery
of capital cost-- maybe
enough, maybe not enough--
that's where the
debates are right now.
Now, I can draw supply
and demand pictures--
I'm going to show you a
simple one in a second--
but in actuality, the way this
works is through the software.
In essence, the
software is trying
to minimize the cost
of meeting everyone's
demands subject to a whole bunch
of different considerations
like generators can
only ramp so fast,
transmission line constraints
need to be honored,
reserve requirements
need to be maintained.
And none of these constraints
are really 100% rigid.
There are engineering standards.
We know engineers
always like to give
a little bit of wiggle room.
And so a lot of
these constraints,
we can relax without
necessarily threatening--
well, with an incremental
impact not necessarily
an automatic blackout.
So when I say scarcity,
I don't mean we're
causing rotating blackouts.
What I mean is we're relaxing
one of these constraints--
a ramping constraint or a
transmission constraint--
allowing a little
more power to go,
or maybe allowing our reserve
margins to drop a little bit.
And when that happens
in the software,
the software has a penalty
price associated with it.
Anybody who's
solved optimization,
instead of having a rigid
this constraint has to be met,
it can be relaxed, but
when it is relaxed,
there is a penalty
associated with it
that keeps the software
from doing it lightly.
And that penalty
price has the effect
of basically forming
a bonus on top
of the offer price of any
generator that's operating.
I wish I could tell you that
there's a lot of careful
economic thought behind where
these penalty prices come from,
but there isn't.
They're round numbers
like $1,000 or $5,000,
I think motivated as much by
computer science guys wanting
to make sure that this solves
in a quick enough time,
as it is some notion of the
economic damages of relaxing
this constraint compared
to what we think
the pricing implications are.
And maybe we should give a lot--
I think we should
give more thought
to exactly what these
penalty prices should be,
and what they actually
mean in the long run.
In addition, I think
one of the reasons maybe
people didn't think about it at
first is this idea that, well,
the demand side is also going
to be part of the story.
And so instead of having this
just inelastic, perfectly rigid
demand, we will have people
willing to consume less,
when the price
rises really high.
And so these penalty
prices won't necessarily
matter because
people will stop--
they'll drop their consumption
a bit so that these penalties
don't have to be applied.
And instead, demand would
be setting the price,
still be well above the
offer price of any generator.
We've been talking about
this for at least 20 years--
maybe 30, 40 years--
and there are plenty of
examples of it working
to a small scale, but still not
a everyday, fundamental part
of how markets operate.
And increasingly
now, we're also going
to have to think about the
role of opportunity costs,
particularly as storage
is part of this picture
of high renewable penetration.
So the incremental cost of
burning fuel-- or in this case,
the money you pay to
charge your battery--
is not the only cost
associated with what
you would be willing to sell
your charge battery back
into the market at.
There's an opportunity cost
to discharging your battery,
in the sense that, if you put
electricity out into the grid
now, you are unable to do so
later-- at least until you
recharge it again.
And so expectations
about future prices
and what you think
they will look like
are going to be a big
factor in how much
you're willing to sell
your electricity for,
in any given hour.
And so we wouldn't
expect a battery,
even if it charges
that zero price,
to be willing to sell
its charge at zero,
in a long-run, stable market.
All right, so instead
of this picture
in the back of
your minds, I would
propose it's this
kind of picture
that we're talking
about, where we've
got a lot of zero
marginal cost stuff.
It's moving randomly with
weather conditions, day
and night, and so forth.
We've got some slope
to demand, and we've
got some really sharp upward
turning parts of the supply
curve, reflecting both penalty
values, opportunity costs,
and other stuff like that.
All right, so the
upshot of this-- well,
will the price be
zero all the time?
High renewable
penetration-- even 100%
does not imply that the price
will be zer0 all the time.
What it does mean is
that prices should
be zero a lot of the time, and
they will be really, really
high the rest of the time--
thousands of dollars per
megawatt hour, perhaps.
And it's really coming to grips
with that sort of implication
that we need to
reconcile ourselves.
Because this would be the
right short-term price,
in an economic
sense, in the sense
that we need these
types of prices
for the efficient deployment
of storage resources,
demand side, et cetera.
Although, I will, as an aside,
say as part of my world,
trying to figure out what
the right market power
interventions are in
a world, particularly
with batteries
playing a big role,
is becoming really challenging.
I've been at meetings,
we're discussing
exactly what a fair bid
from a battery would be.
It's one thing to look at a gas
generator and say $1,000 bid
is way above your cost,
if gas prices are low.
But when we start talking about
a demand side resource and say,
I think you'd be
willing to curtail
your demand for less than
$500, or you, your battery,
or your hydro plant--
I don't think your expectation
of future prices is right,
it becomes much more challenging
to do that kind of oversight
in a world where these types
of less directly tangible costs
are playing an important role.
All right, now the other
point I want to make
is we'll probably need this
type of price volatility,
if we want to get the
right types of adjustments
and transactions
in the short run,
regardless of how
we're financing
the capacity in the long run.
So if we have
capacity markets, it
doesn't mean we can do away
with the need for high scarcity
prices, for example.
In fact, in the US, where we
do have capacity markets--
which I'll talk about
in a little bit--
we do, in fact, have
scarcity pricing that
does set prices
well above the offer
prices of specific generators--
less high than other places,
but I think there's this
interesting question
about how meaningful
those differences remain.
All right, so let me
give you a little bit--
this has all been conceptual--
I'm going to do a quick tour
through one set of results
here, looking at what's
happened in California.
I showed you that graph
earlier of the ramp up
of renewable supply.
Here is that same
expansion translated
to an hour of day profile.
So the horizontal axis
is hours of the day.
The vertical axis is the amount
of output from utility scale,
so this isn't counting
the rooftops solar.
And it really is a
remarkable short period
of time, massive
expansion of energy.
So between 2012 and 2016--
this is just the average over
the course of those two years
by hour of day--
our average output in
the middle of the day
went from about 1/2 a gigawatt--
500 megawatts--
to over 6 and 1/2.
Right now, it's more like 10.
So three years later, this
is up to about 10 gigawatts
during the middle of the day.
Of course, it's concentrated--
it's solar-- and
it's concentrated
when the Sun is shining.
I've been telling people
during the day here,
one of the obvious points that
became really salient to me
during this project is one of
the differences between wind
and solar is you can put wind
turbines in different parts
of the country, and the wind
blows at different times
in different places.
It turns out the Sun only shines
during the day, in at least
North America.
And so there's less
inherent potential diversity
with solar resources than there
is with wind, which California
has decided not to
avail itself of, now
that wind resources have kind
have already been exhausted,
in that sense.
But also, for various reasons,
we have gone sort of all
in on solar as our renewable
energy of choice this decade.
All right, so this has had a
noticeable impact on prices.
What do you think's happened to
prices in the wholesale market
from this expansion?
[INAUDIBLE]
They collapse in
the middle of day--
good guess.
Yeah, so the blue line
represents-- the so, again,
hour of day, and
wholesale prices in 2012
before this massive expansion.
And the red line represents the
average prices in the day ahead
market-- that's what the--
that's not a cuss word--
in the CAISO system.
So yes, the cheapest time to buy
energy wholesale in California
now is 11:00 AM, noon.
In fact, we've had all
these complicated-- took us
10 years to get
time of use pricing
through our regulatory process,
and by the time they finished,
the times were all wrong.
Because we used to think noon
is when things were expensive,
but now, the really
expensive time is about 8:00,
9:00 PM, when people are home,
air conditioning is still
running, and the Sun has set.
The intriguing thing
from this picture--
this is just raw data, again--
the intriguing thing
is, if you notice,
prices have gone down a lot
in the middle of the day,
but they've actually-- they're
higher during the times
when the Sun isn't
shining in 2016.
Now, there's a lot
of other reasons
why that might be the case.
This is just raw data.
So this paper is
basically devoted to going
through the checks of, well,
what could the other things be,
controlling for them,
and it does turn out
that the simple picture actually
tells the story pretty well.
More solar does
actually increase prices
during the shoulder periods,
as well as decreased prices
during the middle period.
And I bring this up as part of
the earlier discussion, to--
this is heading down
that road of prices
that are getting a lot
lower some of the time,
and getting higher--
short other periods of time.
In fact, underneath that
higher [INAUDIBLE] 17,
18 are some $600, $700
prices bringing that up.
I actually find this comforting.
It means the market
is kind of working,
at least in a qualitative
sense, how we would want it to,
in response to this massive
influx of supply that's
concentrated in a
narrow part of the day.
Now, it raises questions
about whether we--
what our policies that
are giving us only
that middle of the day supply.
But as far as the CAISO's
market and its response to that,
it is what we would
hope it would be.
I mentioned this is
wholesale prices now.
So the people in between
this market and my house
are retail companies.
Until recently, my provider
was Pacific Gas and Electric,
and they are buying power from
these renewable energy sources
under long-term
contracts, largely
under mandates from
our climate policy
to rapidly expand their
renewable portfolio.
And our RPS standards have
been successful in building up
a lot of renewables
very rapidly,
but one consequence of that is
that the utilities, or anybody
who has customers, is ready
to sign a contract with pretty
much anybody who has a plausible
renewable energy project.
And in the early years,
those were rather expensive
contracts.
Prices, as you've
no doubt heard,
have declined very
rapidly, but this period
featured some expensive
contracts, as well.
And partly, as a
consequence, PG&E
is paid above market prices
for long-term contracts that
have added more energy
to the middle of the day,
and ended up sort of suppressing
the wholesale price on average.
Although, that
average, as I said,
masks a lot of heterogeneity
in time of day.
So the black dots here
represent the wholesale price,
and if you imagine a retailer--
we don't really want them to do
this-- but if a retailer just
bought off the ISO market every
day--
they tried that in 2000--
didn't work so well--
that's the prices
they would be paying.
And they are declining,
reflecting the fact
that we've been pouring
additional capacity
on this market--
a market that actually
already had enough capacity,
but because we're trying
to replace the existing
fossil capacity
with new renewables,
we have a glut of
supply, basically.
And that has led to
lower spot prices.
But that new capacity's
still financed
through long-term contracts
that have affected
their procurement
costs, which is
represented by the height of the
blue portion of the bar graphs.
So that bar graph represents the
price I'm paying, on average.
And pretty much every
component has been going up,
except taxes,
surprisingly, I guess.
The distribution and the
transmission component
has been rising, as well.
But I guess what I
want to highlight
here is the difference between
the height of the blue bar
and the height of
the black dot, which
is the gap between the
procurement costs--
the implied average cost that
PG&E is paying for the energy--
and the spot value of
the energy that it's
buying, which is that gap
has been growing over time.
All right, so the upshot here--
renewable energy has been
added rapidly, largely
through long-term contracts
between the industry-- we
use this jargon--
load serving entity.
It's somebody who has a customer
that consumes electricity.
Mandates to buy
renewable energy are
applied to these load
serving entities,
and they are out
signing contracts
to get new renewables built--
selling to them.
It's an interesting
market dynamic,
but if you buy energy
under, largely,
a fixed-price
long-term contract,
as a seller of
renewable energy, you're
earning that price no matter
what the actual value in ISO
is.
PG&E and other
load-serving entities
are sort of the residual
claimant on that value.
And they don't seem to
have focused too much
on whether they want
to buy renewable energy
during other times of the
day through some other types
of projects.
Instead, the dynamic
seems to be to focus
on just maximizing the
number of renewable kilowatts
they can get.
And that dynamic is continued.
We're continuing to add more
solar, which is probably
going to reinforce this
dynamic of depressing the price
in the middle of the day.
So each additional gigawatt of
solar purchased in California
has an incrementally lower
value than the gigawatt
before, because they're
all putting supply
on the market at the same time.
So as a result of that, retail
prices have crept higher.
They've been offset by other
trends that contribute to lower
prices, but overall,
retail prices
have gotten higher,
whereas on the CAISO level,
prices are lower on average,
but higher during some periods
of the time--
which I would argue
is the right response
to the facts on the ground
of having lots of solar.
And one implication
of that-- back to what
the California
context would be--
is, if you're a
flexible generator that
is able to generate maybe
twice a day for a couple hours
in the morning and the evening,
this at least qualitative
pattern in prices is
better news for you
than if you're, say,
a nuclear plant that's
just running all the time.
Lower average prices
are just bad news
for a baseload generation
plant, but a plant
that can take advantage of
those short-term price spikes
is in a better position.
So the peaking plants,
the flexible generators
in this market, they are--
their relatively higher
value to the market
is reflected in the
market pricing--
although, there's a big
debate going on now.
They're earning more-- in fact,
what we document in the paper
is they're getting hurt less
than other types of generation.
If you're flexible, you've
lost a little bit of money
from this renewables revolution,
but a lot less than if you
were a baseload power plant.
So is it enough to
stay in business
and keep around to recover
your ongoing fixed and capital
needs?
And that's where the question
of how we finance investment
comes into this picture.
All right, so I'm going to talk
a little bit about capacity
markets, but I'd intended
to spend most my time,
and then I realized I thought,
initially, I had 75 minutes,
and then I read my
email more closely.
So I'm going to talk
quickly about it.
So one of the interesting facts
that people like Paul Joskow
have documented
over the years is,
if you look at the amount of
money available to a generator,
if they were essentially selling
into a short-term market--
if you build a generator with
your own money and all you did
was sell into a
CAISO or other types
of ISO markets every hour--
which almost nobody has done,
although a couple of companies
tried, and it didn't
go well for them--
you would have, it turns out,
not made enough money out
of the short-term
markets to cover
what we think is the reasonable
all-in cost of owning
and operating a plant.
So this has sometimes been
referred to as the missing
money, this odd gap
between the value signaled
by these short term markets
and the cost of actually owning
and operating a plant.
And the existence of
this missing money,
which is pretty persistent in
all parts of the US at least,
is often referenced
as evidence there
needs to be some other money--
missing money implies
there's other money needed--
I should say missing money
is a somewhat flexible term.
In my experience
with stakeholders,
it means money they
are not getting.
And so depending on
who you're talking to,
it has a different definition.
I'll define it here as
this gap between the prices
in the short-term markets
and what people estimate
the needs for new investment
or ongoing investment would be.
And so this has often been cited
as a need for capacity payments
or other cited payment.
Now, I don't necessarily
disagree with any of this,
but I do want to sort of
push back on the notion
that capacity
markets are even more
necessary in this
high renewable world,
or that they're there the
answer that's a simple way.
Because capacity
markets themselves
face challenges in this
high renewable world,
that I'll talk about
it a little bit.
And do want to point out
a couple of facts here.
So money has been missing
for a long time in all
of these markets, and yet we've
kept building power plants
in all these different markets.
And so this is just, again, from
the EIA additions of capacity.
The stories vary.
We have different types of
markets in the United States.
The blue is the old school
regulation cost of service.
We have some markets
that pay for capacity
through a centralized
market, some
that pay through another
type of mechanism, some that
don't pay for capacity at all.
Others have sort of
gone back and forth.
And they've all added capacity
of one stripe or another
over the years, for
different reasons.
So it's not a necessary
condition for investment.
It might lead to
better investment,
but that's really hard
to try to tease out.
So the point here is that
there's something else going
on that's driving
investment that's
unrelated to the
short-term energy prices,
and there's a lot
of different things
that have continually
buffeted this market.
So there is this long-term
procurement dynamic
between large buyers
and large sellers, which
we hope is based upon
market expectations,
but there's a lot of other
influences playing in,
including regulatory mandates
to build more renewable power
plants, for example.
There's also
vertical integration,
where companies are focused more
on what their retail sales are
than necessarily
the ISO markets.
There are periodic
interventions into markets,
where, if an ISO gets worried
there's not enough capacity,
they'll just make sure capacity
gets added through what
we'll call backstop mechanisms.
So through one way
or another, we've
been able to add capacity
under pretty much every type
of market structure
we can think of.
And one of the
problems this poses
is we want to think about what
the missing money means then.
Well, all this investment
both causes missing money
and is impacted by
the missing money.
And it's really hard
to tease out then
what conclusions we can make
from that measurement of it.
And I look at
different markets--
I was trying to look
at prices can go high
in all parts of the country.
They can certainly go
higher in places like Texas.
But if you look at the average
prices in all these places,
they don't seem to be
sufficient to recover costs.
If all they were doing
was buying off and selling
into the short-term
markets, there
would be problems if there
are other things going on.
One of those other things is
what we will call a capacity
market, and I'm going to use
that term a little more loosely
than a rigorous
definition would apply.
But it's essentially a way
of compensating generation
in addition for the
generation being
paid for that energy
they're selling
at those kinds of prices I've
been showing you pictures of.
They are usually mandated by
some kind of market operator
or regulator.
Anybody who is a
load serving entity,
who has customers
who use electricity,
is required to make a
payment to the suppliers
based upon some estimate of
what their peak demand would
be either next year or
multiple years into the future.
And the idea is this is--
this would supplement
the money that's missing
from the short-term markets
to ensure that there is
enough revenues to both build
and maintain capacity at
levels necessary to meet
these peak demand conditions.
So there's a bunch of different
ways you get to this point.
California, instead of
having a single market,
it has a requirement, a mandate.
If you sell electricity to
a customer in California,
you have to go out
and buy capacity,
just like if you
have a car, you have
to go buy liability insurance.
So it's a purchase
mandate of that kind.
And there's a regulator that
does checkups to make sure
that you bought capacity of
the kind they approve of.
Other parts, like the--
New England here has a
centralized capacity market,
which essentially, the ISO
goes out and buys capacity
for everyone, and
then we'll allocate
costs for that capacity
based upon the actual peak
consumption.
This latter model works better
in places where the capacity's
purchased far in advance.
In New England,
it's three years.
Because it's easier to
forecast total system
demand three years
out than it is
the demand of one specific
load serving entity.
So there are different ways.
There's also a lot of
different types of contracts
that this constitutes.
So I'm going to basically
describe-- or think
of this as this is sort of
a requirement to every load
serving entity that they
sign a long-term contract
of a certain kind.
And you can think of it as a
way to hedge their supply risk.
But it's really a very
weak sort of hedge.
It doesn't really provide
any kind of insurance
against high prices.
And this comes back to the
question that we've struggled
with for about 15
years, particularly
with capacity markets, is, when
you buy capacity, what is it
you're actually getting?
Or conversely, if
you sell capacity,
as a generator, what is it
you actually have to do?
Originally, you would just have
to build a power plant that
could plausibly
generate electricity,
and then your obligations
were more or less done.
In California now, if
you build capacity,
you are obligated to bid it
into the market every day,
if you sold capacity,
but you could bid it
in at a price of
$1,000 a megawatt
hour, if you wanted to--
unless you're subject to
some types of mitigation.
And so it's not necessarily a
mitigation against high prices,
but it is insurance
against there
being in a physical capacity.
But as we're
approaching a new world
where we have all sorts of
different types of capacity,
we're struggling
with how to think
about how to compare a gas
turbine to a wind plant
to a battery, in
terms of the types--
what does a megawatt
capacity of a gas plant?
How does that compare
to a megawatt of wind,
solar batteries,
and how does that
filter through these
types of mechanisms?
All right, so I was
part of a project that
tried to look at what
this means for capacity
markets a few years ago.
We wrote it for the DOE
right before the election,
and it went out with everybody
else at DOE, I think.
So what we saw was
that there's real
stresses hitting the traditional
model of capacity markets here
that are being challenged
by several factors.
The biggest is this influx
of alternative resources.
So for example, in California,
the resource adequacy
requirement, the
capacity requirement,
is being met increasingly
by solar plants.
So the reliable supply that
is procured under a capacity
mechanism is being
provided by solar.
And so that's raised
this question of,
how do you compare a
megawatt of solar capacity
to a megawatt of wind to
megawatt of a gas turbine?
And in places like New
England and the upper Midwest,
the challenge has been,
well, even if you buy--
you may think of gas
turbines as more reliable,
because they're not
reliant on the wind,
but it turns out,
if it's really cold,
it's really hard to get gas.
So there have been
periods in New England
particularly where gas has
been really hard to get.
And gas plants that
have sold capacity,
they have very reliable
physical capacity there,
don't have any fuel.
And so their ability to
provide reliable electricity
was pretty much
curtailed by the fact
that they didn't have
fuel, and there's
a lot of finger pointing
about whose fault that was.
So on both the renewable side
and on the gas turbine side
there's been this question
of, if you sell capacity,
what kind of obligation do
you have to actually generate
electricity with that capacity?
And I'll frame that question
as, do we think about capacity
as an on-demand product, which
basically says, if I'm a buyer
and I bought capacity from
you, and I really need it, you
better damn well produce it?
And that's sort of the direction
that ISO New England has gone.
Or is it an on-average
product, where, hey, you're
a wind turbine.
I can look at your
historical production,
and I know that, on average, if
you build a megawatt of wind,
you're going to be producing
0.65 during the hours
that I usually need it.
And so we'll reward you for
that historical performance.
And markets have kind
of gone back and forth.
You can imagine different
sides of this debate favor
different interpretations.
In New England and
in the Midwest,
the on-demand model
has taken shape
in the form of a
really sharp penalty
for not producing
from your power plant.
If you sold capacity and a
certain type of emergency
condition is in effect, then you
better be generating, or else
you pay $5,000 a megawatt
hour in penalties--
$10,00 a megawatt hour--
a very large number.
That makes it both
riskier to sell capacity,
if you're worried that
you're going to be available,
but also really focuses
performance incentives
on hours of severe supply.
California's
resisted this model.
And one of the things
I've been interested in
is trying to figure out--
it's a new thing,
and I would have
expected renewable resources
to just drop out of this market
altogether once this big
performance penalty was
put into place, but that doesn't
seem to have been the case--
that the percentage of
renewable generation selling
capacity in both
[INAUDIBLE] and New England
hasn't notably declined.
So I think they have some
other types of arrangements
to try to hedge those risks.
All right, so we've
got state support
for these specific
generation resources that's
having the effect,
either intentionally
or unintentionally, of
depressing capacity prices.
And that's forced regulators
to intervene and say,
well, we think your support
for these state resources
has probably led
too low of prices,
and therefore, we're going
to make you bid higher,
and that's led to some issues.
Then lastly, we've got
a lot of new technology
that could probably help
reconcile our notions of what
reliable supply should be
with-- between the economists'
and the engineering concepts.
Our reliability
requirements are still
rather crude engineering
standards that don't really
translate to notions of what the
economic costs of interruption
might be.
We do have the capability
of trying to merge that,
but I'm not sure that our
regulatory structure allows it.
All right, so just to
summarize, the couple of points
that I wanted you to
take away with this
you shouldn't expect prices
to be zero all the time.
What you should expect
are more extreme prices.
And I think efficient operation
in the short-term market
really requires that,
and so hopefully, we
can reconcile our climate
goals with what that implies
for operations and markets.
And evidence from
existing markets
does seem to bear out
this qualitative shift.
And the trend is to
look for allowing higher
and higher scarcity pricing.
So the big issue
in power markets
for as long as I've been
working on it has always been we
need long-term
financial arrangements
between buyers and sellers.
They're still really necessary.
They're probably
even more necessary.
I don't think that capacity
instruments are necessarily
the sole type of
long-term arrangement
that solves that
problem, though.
I think where the
capacity question goes is,
are capacity instruments
going to need
to be strengthened so that
they by themselves are
sufficient to finance
generation and hedge load,
or are they meant to be a
complement to other types
of long-term contracts?
And that leads to the
question of whether a capacity
requirement crowds out other
types of long-term procurement,
or it complements it.
I realized have gone too long,
so I'm going to stop there.
And happy to take questions,
for those of you who can stay.
So thank you.
[APPLAUSE]
I should add these
comments are drawn
from a bunch of
different papers.
The references will be
available online, in case
you wanted to look more.
We have a question up here.
So I just listened
to an hour's talk
by a very well-trained,
clearly knowledgeable person,
and it made me wonder, should we
have electricity deregulation?
When my phone was deregulated,
my prices got much lower.
My reliability got
very slightly worse.
My electricity's been
deregulated for 20, 30 years.
I haven't noticed
any improvement
in the gross national happiness.
We have a lot of
people like you who
try to juggle the markets
to make them work.
20 years ago, we had Enron who
juggled the markets to make
it work for Enron for a while.
And are deregulated
electricity markets really
have any benefit to
the nation compared
to the old regulatory system?
So I can make the case that
yes, they have, in certain parts
of the country.
And some of the work here
has sort of outlined it.
The process of restructuring in
a lot of parts of the country
ended up being a bet
on the natural gas
price over the last decade.
So during the periods where
natural gas prices went up,
places that deregulated
ended up paying
increasingly high prices.
But since 2008, places
that have restructured
have experienced
prices that have
risen much more slowly than
places that remained regulated.
California's a bit of an
outlier because of the crisis
and some other things there.
There's been a lot of
bottom-up focused studies
on what the implications of,
let's call it deregulation,
have been.
The nuclear power
fleets operation
has improved massively
as a result of that--
not enough to keep some of
those plants around, apparently.
The efficiency of other types
of power plants has improved.
But the retail customer
outcomes have been very mixed.
It's true.
But part of that is that retail
prices have been much more tied
to other commodities that move.
When you have a
deregulated market,
the prices are going
to be much more
responsive to whatever that
price setting type of fuel
would be.
In that case, it's been
natural gas in this country.
And when natural gas is high,
deregulation has been bad.
The last few years,
actually deregulation
has been pretty good because
those wholesale prices have
been lower, and that has
been more directly passed
through and in the more
deregulated markets
than the less
deregulated markets.
Now that 50% of the
California population
is on community
choice aggregation,
how is that affecting
the long-term financial
arrangements or contracting
arrangements for the utilities?
Yeah, no, it's a real--
it's maybe the
second California--
oh, I'm being taped.
OK, so I really,
really worry about it,
because one of the
stylized facts--
I've been trying to get more
hard information about this--
is that the CCAs--
these are small community
retailers that--
I guess they have in
Massachusetts, as well--
they, first of all, don't
have strong credit initially,
and that restricts their ability
to sign long-term contracts.
And secondly, they
have been focused
on providing 100% renewables
and stuff like that.
So what that means
is the contracts
they are signing had been
with those solar plants that
are generating during
the middle of the day.
And the net result is they
are pretty much buying off
the spot market, when
the sun isn't shining,
or they're buying
on contracts that
are indexed to market prices.
At the same time, we've
been seeing little hints
of increased market
power in California
starting to creep in, as well.
And I don't think
those two things
are necessarily unrelated.
I think the advent of CCAs
could be a good thing,
in the sense that we had kind of
a monolithic, single regulatory
agency directing procurement.
And to the extent, injecting
different ideas into that,
there's an argument that
there's a benefit there.
I've got some skeptics
in the front row.
The short-run
consequence has been
that there's been a real
shift to short-run procurement
that I do worry, for a
bunch of different reasons,
is leaving the market much more
exposed to short-run prices.
Another weird dynamic is,
because every retailer is
promoting high renewables
as a retail product,
they're willing
to buy renewables,
but no one's willing
to admit that they're
buying from a gas plant.
And so purchases
from gas plants are
coming from more generic
system contracts pegged
to market prices, rather than
any kind of long-term contract
with a gas generator.
We have a question up here.
It's a build upon this
discussion about CCA.
And also, one of
your slide mentioned
about the retail
rate in comparison
with the blue-colored
energy procurement.
With the increasing
disparity, it makes the case
for perhaps more for
CCA-type, and maybe even more
aggressively for behind
meter edge technologies,
transactive energies,
and things of that sort
happening at the retail level.
Well, I would agree, but I
don't think that's necessarily
a good thing, because
the pressure then for CCA
is to the extent that--
a CCA can go by
at that black dot,
but the blue bar, that's a
20-year contract PG&E signed.
When I leave PG&E
to go to a CCA,
I'm leaving PG&E
with that contract.
It doesn't go away.
So the structures that
have been put in place
to deal with that inequity of
customers who are left behind
is to have an exit
fee associated
with migrating to a
CCA, where I still
pay a share of that blue
bar, even though I'm now
a customer of
[? YOLO ?] Clean Energy.
I guess my question is, perhaps,
along this line of saying that,
if you imagine maybe a little
be longer term-- say, 20,
30 years down the road--
when the edge technologies,
behind meter technologies
become really cost
competitive, there
is many, many transactive
activities happening, maybe not
even being accounted for
by the utility companies.
How are we even think about
this whole capacity or planning
problem, when you have lots of
a retail-level transactions?
Well, OK, I'll just say that,
if behind-the-meter technologies
become cost competitive,
that would be great,
but they should be
paid the black dot.
So the problem is, when
you're behind the meter,
you're implicitly
avoiding all of this,
including the grid costs.
Now, it's going to be California
wildfire liability payments.
And those are costs that
don't go away, when you
generate distributed energy.
And so I'm all for having
that technology compete,
but right now, there's a
very strong implicit subsidy
of those types of technologies.
Because the rates in California
are all variable, and all
of those other fixed
costs are lumped in,
and they're avoided being
paid for by the distributed
generation.
So if I could ask you about
the east, and these markets
where we've got capacity
rules, capacity market rules
have changed to put
penalties on underperformance
and performance hours.
You said you thought renewable
energy would be withdrawing
from the market--
haven't seen much of that.
Is this really a problem that
there's not enough performance
hours?
There's an oversupply, actually.
We just have those
renewable generators
riding a wave of oversupply.
But you think there's
a hedge going on?
I don't know.
I started trying to dig up
data on this for this talk.
And this is the very first year
of the performance capacity
in New England, to my knowledge.
[INAUDIBLE] had a
few more years of it.
They bought it three years ago.
This it the first year
it's been in effect.
And so what I've
been able to dig out
is who is selling
it, to some degree,
but I don't think we've
had enough data yet to know
exactly how it's impacting
actual operations.
I personally think
it makes sense.
It's sort of merging some
of the energy incentives
that high energy prices
are meant to provide
into a capacity market model.
I know that there
are some sellers that
don't like taking on
that liability risk,
but it seems like it's an
appropriate level of risk,
in the sense that, if what
you're trying to buy is,
as a buyer capacity, is
actual reliable capacity.
And so it comes closer to
an energy sort of mechanism,
in that sense.
But yeah, I think we should
all be paying more attention
to how well it's working.
I had one question.
I saw the graph
between 2012 and 2016.
And with the
[INAUDIBLE] California,
I was wondering, at
the end of the day,
are people in California
are paying more or less
for the electricity
they're getting,
if you take into account
[? justice ?] for price
commodity and inflation?
And are they paying
more, I'm wondering
what is the weighted average
of the electricity going up
or going down between those
two dates, 2012 and 2016?
Right.
And basically, that kind of
thing is being picked up here.
So the average price
between the hours
that went up in the
hours that go down
does average out to
a little bit lower.
So you can see the black
dots here basically reflect
that the yearly average of
all those hours, and they
are declining somewhat.
But the price I pay has been
going up because those--
basically, those
renewable plants
are not being paid that price.
They are being paid
a contract price that
is being entered into because
the load serving entities
need to sign those
contracts to comply
with the renewable mandates
that they are subject to.
So they're willing to
pay above market prices
in order to meet their
renewable requirements, and--
[INAUDIBLE]
Yep.
[INAUDIBLE] energy market--
Then you get the blue bar here.
So the blue bar is what
PG&E is paying for energy.
What is [INAUDIBLE]?
That's my retailer.
They pay sellers of
energy through contracts
and other things.
My bill breaks out
the sources of cost.
They're paying the
height of the blue bar,
and the value of that energy
on the wholesale market
is the black dot.
And so the gap
between what PG&E is
paying to buy energy
and that wholesale value
has been getting
larger over time.
Professor Bushnell,
thank you for the talk.
Over here on your right.
Yeah.
I really appreciate your simple
mental model of low prices
most of the time, with
some high prices--
or very high prices
some of the time.
But I think you also noted
that those high prices have not
been particularly
popular among regulators
and other interveners
in the industry.
And so as you think about
moving forward into a market
where you have much higher
penetrations of renewables,
can you maybe pontificate
on what types of structures
might work in this
world, if you do
have these kind of constrained
energy prices that we have--
or constrained scarcity
prices that we've seen
and most of our
organized markets,
outside of [INAUDIBLE]
and Australia?
Scarcity prices, even
in markets without--
that aren't called
energy-only markets,
have been relaxed and have been
rising quite a bit over this
decade, and continue to--
there are definitely
issues with operators
that are worried
about reliability,
and maybe unintentionally take
actions that lower prices,
and all sorts of other things.
But we've seen prices in the
multiple thousands of dollars
in every one of these markets.
So mechanically, there's
nothing preventing it.
I think there's endogenous
amount of capacity that
is enough that we're not
hitting those scarcity levels
with maybe a high
enough frequency,
depending on what you consider
the right amount of frequency.
But I'm not sure that
the design itself--
I don't know whether 2,000
is enough or 5,000 is enough.
And part of it depends
upon how often we
hit those levels, for example.
But there's-- we have had
$5,000 prices in California,
if you get enough of these
penalties pancaking on each
other.
So mechanically, there's
nothing actually preventing it.
And politically-- no
one's noticed, actually,
but that's because it's
been for five minutes
and it hasn't really
affected energy prices--
and the utilities have
been fully hedged.
So maybe if back to the
earlier discussion, if we do
have a large amount of it--
but we are in a trend where,
right now, the market designs
are emphasizing more frequent
and higher scarcity prices.
Thank you for this talk.
So I have a question
about energy storage,
and specifically how
energy storage is and will
impact capacity markets--
and then also your
recommendations for changes,
regulatory constructs
that could incorporate
the ability for energy
storage to provide
increased reliability.
I'm glad you asked what storage,
because I had one slide that I
brought, just in case.
So you would think storage
is great for dealing
with these kind of shortages--
particularly the batteries.
The California
experience with batteries
so far has been that they
haven't been engaging
in this kind of energy
arbitrage of buying
low selling high that
I think a lot of people
were hoping they would.
Instead, they're choosing
to basically maintain charge
at a steady level, and serve
short on fluctuations--
which saves the
batter, basically,
and so there is an
economic sense to this.
But it appears that
the cost of being
able to use at least
conventional battery
technologies to do daily shifts
of energy from peak to trough
could be more expensive than
what people really thought,
based on the opportunity cost
of burning up the battery life
and having to replace that.
I think, as far as
the capacity goes,
that's a really tough question.
And I think there have been
two schools of thought,
and California's going
in one direction--
New England the other.
So New England has taken a more
technology-neutral stance that
basically says, we don't care--
I'm overstating it a bit--
but do whatever technology
want, but make sure
you're generating
during these emergency
situations, or else penalty.
The other approach that
California's taking
is to slice the capacity
requirement more and more
finely.
So we had a capacity
requirement,
but it turned out it was being
met with all renewable energy.
And so they had to make a
second capacity requirement
to catch the stuff
that got crowded out
of the first capacity market, so
we now have a flexible capacity
requirement.
But that led to a
huge debate over--
I think, implicitly, it was kind
of like we want to have a gas
requirement, but they couldn't
say it was a gas requirement,
so they needed to define
what flexibility meant.
And storage became
a big part of that.
How do you compare
a five-minute--
ability to do five-minute charge
discharge, maybe multiple times
a day, with the ability to do a
three-hour discharge, but only
once a day?
And the hydro people
and the battery people
have gotten a big
fights about that.
We still haven't
fully resolved it.
And this is one of
the things, I think,
that's a real challenge
for capacity markets,
is the definition of what
capacity is becoming less
and less clear, as we
have all these sorts
of different technologies.
And I think storage is
at the forefront of that.
Because even within
the storage class,
there are very different
types of storage
with very different
types of capabilities.
And that's why the appeal
of the New England model,
which is less
technology dictating,
and more results-oriented,
is appealing,
in the sense that different
technologies can approach this,
but they need to perform--
it's identifying
it more from what
do we want our technologies
to do, rather than how--
which technology we specifically
want to do those things.
[INAUDIBLE]
I've raised it a couple
times, and there has not
been a lot of enthusiasm.
That's part of the
reason why I want
to compile more evidence
about exactly how it's
working, to try to maybe
raise that case again.
I should also add, California
has just a storage mandate
that's equivalent to a
renewable portfolio standard.
So every load serving
energy has to buy
a certain amount of
storage, and so that's
adding storage to the network--
to the market outside of
any of these other sorts
of mechanisms.
Are there any lessons
learned from global markets
where you might have a lot
of hydro, like in Canada
or Brazil, or a lot of nuclear,
like in France, where you end
up having a market like
this, which is essentially
zero marginal cost
for a long time,
and then these peaky
points where you really
need more supply?
Well, I think the lesson
from hydro markets
is life is sure easier, when
you have a lot of hydro.
And market design
becomes a lot easier--
except when there's
a drought, actually.
And so the that's
also been a challenge
in places like Brazil, where,
most of the time, things are--
instead of prices sort of being
like this from day to day,
it's more they're like
this from year to year,
and then every 10 years,
there's a drought,
and prices are just
high all the time
in the hydro-based markets.
So again, it's not zero, because
there's this opportunity cost,
and there's a
scarcity component.
Because when you
have hydro, if I
let the water go through the dam
today, I can't use it tomorrow.
And there's an implicit value,
an opportunity cost associated
with that that's factored in.
Now, when there's
a lot of water,
that opportunity cost
can drop to zero,
and so periodically, when it's
really wet, it will do that.
But in general, what
you see in hydro
systems is the prices is
pretty stable from day to day,
but will have these big
swings hour to hour.
And those markets have
really faced a challenge
because their capacity
instruments, what they really
need is some gas or something to
be around once every 10 years,
when there isn't enough rain.
And that's been a
more challenging way
to try to implement.
People have approached that.
Frank Wallach has
done some stuff
trying to push a kind of
energy contracting mandate
in those kind of circumstances.
France I know less about.
People in the nuclear
industry, there's a lot of--
I hear a lot of opinions about
what the actual marginal cost
of the nuclear generator is, in
terms of actual annual costs,
and so those systems--
I'm not sure France
counts as a market either.
And so I don't know if
I'm in a good position
to comment on that.
Over here.
There's a bipartisan bill in
Congress called the Energy
Innovation and
Carbon Dividend Act,
and it would put a $15
per ton fee on coal, oil,
and natural gas, and increase
it $10 per ton every year
thereafter.
I'm just wondering if
that type of a policy
would change anything
that you had to say today.
No.
One of the things I didn't
get a chance to emphasize
is what I've been talking
about today is more
how electricity markets
react to climate policy.
I do think that we shouldn't
use our electricity markets
to implement climate
policy by, say,
favoring the dispatch of one
type of energy over another
through a non-market preference.
But they are-- the
short-term markets
are well-positioned to capture,
for example, carbon pricing.
They do it in California.
They do it in
[? Reggie, ?] but--
for what it's worth.
And I think the results
would be predictable,
in the sense that you would
see higher marginal prices
in the short run.
And I think in the
long run, you'd
end up in a similar
circumstance,
where it depends on what
that marginal technology is.
If it truly is everything
zero carbon on the electricity
network, then it is true
that carbon pricing wouldn't
necessarily raise
prices anymore,
but that's because reducing
electricity consumption
would not--
or increasing electricity
comes assumption would not
create any more carbon.
And so there being no carbon
price, in that circumstance,
would actually be reflective
of the circumstance.
But I suspect where
we're going to end up
is with some role for
traditional generation
for quite some time to
meet these peak periods.
Carbon pricing would
add to those prices
during that period,
increase the returns
for low carbon resources
in the interim.
I worry about nuclear
plants retiring.
The question of whether
they should retire or not,
if we had a real carbon
price, it's hard to answer.
But we would know the answer,
if we had a real carbon price.
15 is a little low,
by my guesstimation,
but it certainly might
be enough, actually.
I'm not sure where you guys--
where the experts, the
well-trained people
here have come out on that.
One of the perverse things
that people have noticed
is, by layering
all the zero carbon
renewables onto the network, it
has lowered the average energy
price, and it has
made life harder
for a baseload
nuclear power plant--
which is also zero carbon.
And so if renewables are
being supported solely
as a carbon policy,
there is this kind
of perverse, counterproductive
result-- potential result
there.
Is it enough to be
causing the retirements is
an open question, but
if we were doing it
through carbon
pricing, I think we
would know the answer to that.
Thanks again for being here.
I'm up here.
Had a question regarding
Casper in New England.
So with Casper,
it looks like it's
going to be fairly difficult
for sponsored resources
to gain access to the
capacity market at all.
And what that seems to
be likely to result in
is a lot of capacity laying
outside the capacity market,
but being procured on
state mandates anyway.
Does that create any
challenges for capacity markets
or the system overall?
You stumped me.
We should talk
afterwards, because I'm
not enough up to speed on
that interaction to speculate.
[INAUDIBLE]
Well, from what I understand
about the [? moper, ?]
one thing I
definitely worry about
is, if we've got
capacity that's there,
we don't necessarily want
to build more capacity
and pretend that the
capacity that's already there
isn't there.
There should be some other
way to try to deal with that.
I think the only justification
for a moper solution would be
is if it's an actual deterrents
to the subsidies that
are being put in place.
But I think the
subsidies, to an extent,
they're motivated by
non-market motivations.
All right, there's the--
last question.
Thank you for the presentation.
So you actually,
during the talk,
differ about engaging
more the demand side,
and everything was more
focused on the supply.
So what kind of
mechanisms do you
think we can use in order
to start engaging more
actively the demand side?
Well, I think the most
important first step
is to reform retail
rate structures so
that all these fixed
costs aren't part of them.
I do know that,
right now, batteries
have a strong incentive to
go behind the meter to avoid
certain types of fixed charges.
And that actually
makes them less
inclined to participate in the
wholesale market, because the--
everything the wholesale market
does is fudged up by $0.15,
$0.20 a kilowatt hour by
all those fixed costs.
So I think a transition to
more of a larger monthly fixed
charge and a short-term
price that is much more
better aligned to the
wholesale market price
would be a really
important first step.
And then we can have debates
about what the right type
of dynamic price would be.
There are all sorts of
good ideas floating around,
and most of them
of pilot programs
that have been
reasonably successful.
But I do think what's
interesting is,
in markets with retail
competition, it seems like--
you talk to retail
providers, they say,
nobody wants to buy this sort
of dynamic pricing product.
And so there does seem to be--
they believe there's
a lot of customer--
that it's not real
appealing to customers.
And so that's an
interesting thing to try--
if prices start to take
the types of extremes
we've been talking about,
that could certainly change.
Especially if we're
talking about,
hey, zero prices during
10:00 AM to 4:00 PM, that
could get people's attention.
But it won't help.
The zero energy
price won't help,
if they're also paying
$0.15 a kilowatt hour
for the transmission
during the same time.
All right, I've kept everybody
like a half hour late,
so thanks for sticking around.
[APPLAUSE]
