Thank you for coming.
I'm very happy to have
Abby Krich here today.
So I'll just read you
Abby's bio in brief.
Abby is founder and president
of Boreas Renewables,
which is a Boston-area company.
It's a consulting firm
that stands in between us
as energy providers and
renewable energy generators,
so one of the people that
actually makes renewable energy
happen.
And she has a lot of
practical experience.
We're looking forward to
her sharing with us today.
She also actively advises
within the New England power
pool and the New England
Independent System
Operator, the NE-ISO,
and currently serves
as vice-chair of the NE power
pool Variable Resource Working
Group.
And variable resources
are something
that those of us who work in
renewables think a lot about.
She holds a masters
of engineering
and a bachelor of science and
engineering, both from Cornell.
So without further
ado, thank you, Abby.
All right.
Thanks.
Thank you very much, Raf, for
inviting me to speak today.
Is my volume OK?
Can everyone hear me?
Great, OK.
Good.
So I'll be talking about the New
England wholesale electricity
markets, and why it is that
they're basically incompatible,
as I see it, with achieving
the region's long-term carbon
emission reduction goals.
So the usual disclaimer--
these views that I'm going to
talk about today are my own.
They're no one else's.
They're not my clients'.
They're just my
observations that I've
seen from working in the field.
Also, another
disclaimer that I like
to start with when I talk
about the energy markets--
they're a bit complex.
We're going to pretend we're
in a frictionless vacuum here.
I'm going to
simplify things, just
to try to focus in
on some key ideas
that I want to talk about today.
So what I'll start with--
I'll start by talking about
the wholesale electricity
markets in general.
What are they?
And then I'll talk about
policy requirements
that we have in the
region to decarbonize.
And then I'll talk
through some things
related to the energy market,
and then the capacity market.
So wholesale
electricity markets--
the areas in this figure that
you can see that are shaded,
they are each a wholesale
electricity market.
So in general, in
each of these markets,
there are regulated
utilities that own the wire.
So here, for example,
that would be Eversource.
There are, then, generators
that are independently
owned by independent companies.
And those generators-- those
independent companies--
compete in the wholesale
electricity marketplace
without any
centralized planning.
So instead of centralized
planning, the market
itself sends a
signal to indicate
when and where to build
or retire power plants,
and when those power plants that
are built should either run,
at what levels, or when
they should sit idle.
And so the market is run by
an independent entity that
has no ownership interest in any
particular part of the market,
called an independent
system operator.
And in New England, this is
called the independent system
operator of New England.
And just for reference,
the gray areas on this map
are the areas that are
still vertically integrated
and don't have these
competitive marketplaces.
But for today,
we're going to focus
on that green market in the
upper right, the New England
wholesale electricity market.
So for some background--
some context--
on the ISO New England,
the market size
is about 121,000 gigawatt hours
of energy per year, last year.
And it's made up of--
about 85% of that
is supplied by generators
located within New England.
43% or so of the total comes
from fossil generation,
but 42% of the total comes
from either low- or no-carbon
generation resources.
And then a little over
16% comes from imports
from neighboring
regions, so either
from New York, New Brunswick,
or the majority from Quebec
to the north.
There's also-- we have quite
a bit of pumped-storage hydro
in New England.
So when they're pumping water up
the hill so that they can then
provide energy later,
that uses energy,
and so that's added on here.
You'll notice that, until
you add that minus 1.4%
for the pumped-storage hydro
pumping load, were over 100%.
So all of that
energy is supplied
by a fleet of generators that
is about 35,000 megawatts
in nameplate capability.
So that gives you
some background
on the size of the market
overall and its makeup.
Now, the market
in New England has
seen some fairly significant
emissions reductions
over the past 15, 20 years.
In 2000, ISO New England
market coal and oil
provided 40% of the
energy in New England.
Natural gas, on the other hand,
there wasn't very much of it.
Natural gas generation, it
only produced 15% of the energy
in New England.
Fast forward to 2016, and
coal and oil are down to 3%
in that year, and natural
gas is up to 49%--
so a huge transformation
in that time.
And because of
that, air emissions
dropped pretty significantly.
So the figure that
you see to the right,
the green shows the carbon
dioxide emissions in 2001--
it's slightly different years.
Carbon dioxide emissions in
2001 dropped to the blue bar
in 2016.
So a fairly sizable
drop in carbon emissions
going from the coal and
oil over to natural gas.
So that's good.
That's a good start.
But it's not enough.
We have 32 years left to
decarbonize our electricity
system in Massachusetts.
So Massachusetts has the
Global Warming Solutions
Act, which requires-- it's
not an aspirational goal.
It requires greenhouse
gas emissions
from each sector of the
Massachusetts economy,
not just the electricity
sector, to be 25%
below 1990 levels by 2020.
We're in good
shape, based on what
I showed on the last slide.
We're in good shape
to meet that target.
That's not terribly
concerning right now.
But then, in 2050, we
have to be at least 80%
below 1990 emissions levels.
So how do we get there?
That's a very sizable
emissions reduction.
We basically need
to have a fully
decarbonized or near-fully
decarbonized electricity
sector by 2050.
And it's also going to be
a much larger electricity
sector, because in order
to get to that 80%,
we need to largely
electrify the transportation
and heating in
Massachusetts, as well.
So a much larger
electricity market--
almost no emissions
can come from it,
if we're going to
meet this requirement.
And actually, it's not
just Massachusetts.
It's New England as a whole.
So every state in New England
has a similar emissions
reduction target.
So the dark gray are our
legislatively binding mandates.
The light gray are
targets that don't
have the same binding nature.
But we're going in
this direction, right?
All of New England
has similar targets
for massive
emissions reductions,
around 80% from 1990
levels, by 2050.
So 32 years sounds
like a lot of time--
plenty of time.
We just need to deal with
the system now-- the market
and reliability now,
and we'll figure out how
to decarbonize in the future.
We'll get there.
Actually, in the
electric world, 32 years
is not actually that much time.
So in 2010, ISO New England--
the grid operator here,
the market operator--
they did a study.
They looked at which generators
on the system were coal-
and oil-fired
generators on the system
were at risk for retiring.
They wanted to know, what risks
do we face in this market?
And they found that there
are about 8,000 megawatts
of coal- and oil-fired
generation at risk
of retiring because
of their age,
because of economic trends.
And those plants, at the time,
were between 32 and 58 years
old.
So these are
long-lasting assets.
If you invest in a gas
plant, or a pipeline,
or infrastructure
related to them today,
the expectation is
that it will be around
for 30, 50, 70 years from now.
So if we have to
decarbonize by 2050,
I think that raises a
question about whether we
should be building more fossil
fuel infrastructure today.
So just for a sense of what's
happening on the system,
from 2013 to 2021,
about 3,600 megawatts
of that at-risk generation has
either retired or committed
to retiring by 2021.
And in addition, about
1,300 megawatts of nuclear
has either retired or
committed to retire.
So altogether, that's about 10%
of the New England generation
fleet.
There's a big turnover
happening already,
and a big opportunity
to be replacing
these outgoing resources
with clean energy sources.
But when I look at
the current markets,
that's not what the
current markets are doing.
That's not what the current
markets are driving us towards.
And that's what I'll
be talking about.
And so I said previously,
we've seen a big growth
in gas-fired electricity
production and emissions
reduction, but I said that
that doesn't make sense
to keep doing.
Why not?
It's not going to get us to that
80% emission reduction goal.
So the 2016 ISO New England
emissions rates are shown here.
You can look at it.
You can cut the data a
couple different ways.
The average emissions
were 710 pounds
of carbon dioxide
per megawatt hour
of electric energy produced.
That was the average
across the year.
If you look at the average of
just the marginal generating
units-- and I'll explain in
a few minutes what a marginal
generating unit is--
it was about 842 pounds
per megawatt hour.
So that's our benchmark
for where we are today,
in terms of emissions rates.
Then you look at emissions
rates for new, efficient,
natural-gas-fired power plants.
So the last one to reach
commercial operation
in New England was the
Kleen combined cycle
plant in Connecticut.
And its emissions
rate reported in 2016
was 850 pounds
per megawatt hour.
So that's not really lowering
our average emissions
by adding a plant like that.
Footprint Power combined cycle
plant in Salem, Massachusetts--
it's under construction now.
As I understand
it, it's basically
the most efficient combined
cycle plant out there.
Its projected emissions
rate, depending
on how it operates exactly,
is about 835 pounds
per megawatt hour.
So it's a little bit
lower, but again, this
isn't getting us to 80%
emissions reductions, right?
There's diminishing returns
at this point, where we are,
to adding more
gas to the system.
So really, if we're going to
meet these emissions reductions
requirements, we need to
reduce demand for electricity,
and we need to transition to
producing more-- or actually,
eventually nearly all
of our electricity--
with low- or
no-carbon resources.
So let's talk about that.
So energy efficiency--
that's the first
stop-- reducing the total
demand on the system.
So New England states are
very aggressive on this,
and they spend over
$1 billion a year
on energy efficiency measures.
I don't know if any of you
own your home or rent a home,
and if you haven't had your
Mass Save Energy Audit yet,
I highly recommend it.
They'll give you
free light bulbs.
They'll help you
insulate your house.
That's all part of these
energy efficiency programs.
And the result of them
is what we see here.
So the gold trend line
that you see there--
the solid gold is the
gross total demand
for electricity in New
England, starting in 1990,
going up to present.
And it's been climbing.
And then the projected
demand over the next 10 years
continues to climb,
but that's gross.
If you take that gross demand,
and then you subtract out
the impact of all
of the rooftop,
behind-the-meter solar
that's being installed,
and then you subtract out
from that all of the energy
efficiency-- so the impact of
all of those LED light bulbs
and things like that that
people are installing--
you actually get
to that blue line.
That's the net
energy that actually
is what needs to get served by
the generation and the imports.
And that blue line--
be careful-- the
axis doesn't start
at zero, in terms of scale.
But that blue line is quite
a bit below the gold line,
and most importantly,
it's trending downwards.
So the amount of
energy that we are
expecting to need
over the next 10 years
is actually going down.
In terms of decarbonizing,
that's the right direction,
although I expect it will
have to go back up once we
start really, seriously
electrifying transportation
and heating.
OK, so energy efficiency-- we're
going in the right direction
there.
I described, in terms of the
generation in New England,
how much energy comes from
different fuel sources,
but what do the
actual generators look
like that are producing them,
because they don't all produce
the same amount of energy?
So 68% of our generator
fleet in New England is
fossil-fuel-fired--
vast majority.
76% of that is either
gas or dual-fuel
that can burn gas or oil.
So if the remaining coal and oil
is replaced with all gas, which
is what the market is
really driving towards,
that will barely help
with emissions targets.
Instead, what we need to do
is build clean generation.
So what we see on
the left-hand side,
the left-hand bar is the
existing generation fleet
in New England, and the bottom
of that is the fossils--
so that the black, brown
is the coal, oil, then
you have the gas
and the dual-fuel.
That's our fossil component
of our generation fleet.
The right bar shows
the generation
that is in what's called
the interconnection queue.
They've submitted applications
to connect power plants
that people are trying to
develop to the transmission
system.
So when you look at
those applications,
a good chunk of it is
still fossil-fueled.
It's still natural gas.
But then a very large
part of it is solar--
is the yellow.
Green is wind.
So there's a lot of
projects under development
that people want to build a New
England if the conditions are
right to actually build them.
So what kind of growth have we
seen in wind and solar so far,
and what do we expect coming up?
We have about 1,350
megawatts-- just a little
more than that-- of onshore wind
operating in New England today.
That's up from about
375 megawatts in 2011--
so quite a bit of growth.
Not dramatic, not
as fast as I think
I had hoped we would be growing,
but quite a bit of growth
in wind in New England.
But we have over 8 gigawatts
of wind in the interconnection
queue right now, so we could be
installing massive amounts more
if the conditions were right--
if the market were signaling
it.
We have 30 megawatts of
offshore wind operating off
of Rhode Island.
It's actually the first
offshore wind project
operating, I believe, in
the Western Hemisphere.
So go us-- that's great.
It's a small
project, but there's
Massachusetts
legislation that requires
the solicitation of 1,600
megawatts of offshore wind
by 2027.
And the first of
those projects, we're
actually expecting the
selection of that project
and their contract to start
negotiations in a few weeks.
So things are moving
on offshore wind.
And then solar has grown
really dramatically
in the last few years.
So we have about 2,390
megawatts of solar operating
and installed in New England,
up from about 250 megawatts
in 2012.
So that's this
figure to the right,
showing the solid trend lines--
what we've seen since 2012.
And ISO now
forecasts every year,
based on existing
policies that are driving
the solar development,
how much solar we expect
to see over the next 10 years.
So that's the dashed line
that you see to the right.
And we're expecting the solar
to grow up to 5,750 megawatts
by 2027--
so quite a large growth in
solar that we're seeing here.
Even so, with what
we have today,
the wind and solar
that's installed
is producing enough energy
to be equivalent to about 6%
of the load in New England.
So it's not nothing, but
it's not a huge portion
of the generation yet.
Now, if all that offshore wind
and PV that I talked about
is built, that gets our
total up to about 10%--
so going in the right
direction, but again,
not going to get us
80% carbon reductions.
If all 8 gigawatts
of onshore wind
gets built-- which would
be a lot for New England,
but that is the
direction we need to go--
and if all 8 gigawatts
of onshore wind is added,
that gets our total up to
about 30% from wind and solar.
So if that displaces
all fossil generation,
it still leaves 19%
of our load being
supplied by fossil generation.
So we still need more than that.
That's not enough.
So then you start
looking at other options.
There's hydro from Canada.
So there's Massachusetts
legislation for that, as well.
So Massachusetts
legislation calls
for the procurement of about
9,450 gigawatt hours per year
of clean energy-- and they
consider hydro imports
from Canada to fit that
definition, by 2022.
So that's a little
over 1,000 megawatts
steady throughout the year.
A transmission project to import
that amount of hydro energy
from Quebec into New England
has just been selected
and is negotiating its
long-term contract right now.
That would be enough for
about 8% of New England load.
So that's a really big deal.
That is one big project
for New England.
And if it displaces
fossil generation instead
of displacing other
clean generation,
then that still leaves 11% of
our load coming from fossil.
So still, we need more.
So we have a great start here.
We're chipping away at
things, but it's still
just the beginning.
And these numbers
that I'm saying--
they're assuming this 8
gigawatts of onshore wind
actually gets built, and
there is no clear path forward
for that to happen right now.
So those are all projects
that could be built,
but there's no path
for them right now.
And as I said,
electric load is going
to rise with electrification
of the other sectors,
so we actually need more
than these numbers here.
So what I'm trying to
paint a picture for you
is that we need to have a
massive fleet changeover
in the next three decades.
We need to retire and probably
stop building new fossil fuel
power plants, and
we need to bring
on a huge amount of no- and
low-carbon energy resources.
So what we've seen so
far is that contracts
and regulated rates, and not the
wholesale electricity markets,
have been driving this growth
in clean energy development
that we've seen and that we're
expecting in the coming years.
I'm not aware of a single
wind or solar project that
has been built in New England
without a long-term contract
or a regulated rate
supporting that project.
I don't know a
single project that
has looked at the wholesale
electricity market and said,
yeah, I'll invest
my money in this,
and I'll see if I
make my money back.
That's not what's happening.
I would prefer to see
the electricity markets--
I like markets.
I like the electricity market.
I would prefer to see them
driving this transition,
but it's unfortunately
just not--
this, what I've
described, is not
what they're designed to do.
So it won't send
the price signal
for the entry of these
clean energy resources.
It's actually sending
counterproductive signals,
saying that we need to
be building more gas.
And yet, our policy requires
that we decarbonize.
So the growth of these
clean energy resources
has to keep continuing.
Whether the market
is doing it or not,
it has to keep continuing
to meet our public policy
requirements.
So something's not
matching up here.
This is actually a dominant
discussion at ISO New England
and nationally, in how
markets and public policies
interact with each other,
and how the markets can--
the catch phrases are--
either accommodate or achieve
public policy goals,
or whether they should
do either of those things.
And either we figure
this out or, I'd
say, the markets will be
gone in under 32 years,
because something's
not matching up.
So now I'm going
to transition, now
that I've given that
background, to talking
about the electricity
markets and why
it is that I say
that they're not
working for these clean energy
resources and this transition.
So there are three
key components
to the wholesale
electricity markets.
There's an energy market,
which, in 2016, was a little
over $4 billion in New England.
And that's the price that gets
paid for actual electric energy
that gets produced, so dollars
per megawatt hour of energy
produced.
There is a much smaller
reserves market,
which is about $0.1
billion in that same year,
which is the price paid for
the ability to produce energy
in a short amount of time--
so talking 10 minutes,
30 minutes--
in case there is a
contingency on the system.
If we lose a power plant,
if we lose a tie-line
to a neighboring market, these
power plants or these resources
are able to step in very
quickly to make up that power.
They're the backup
supply that's available.
So they're paid to just
sit there and be available.
And then there's
the capacity market.
So the capacity
market fluctuates
pretty significantly, but in
2016, it was a $1.2 billion
market.
So the capacity
market pays a price
for a commitment
the resources make
to be able to be available to
provide energy and reserves
multiple years into the future.
So it's not paying for the
actual energy production.
It's just paying
for the commitment
that your resource will be
available to produce energy
to meet demand in the
future, to make sure
that we have enough resources
to keep the lights on,
to meet our peak demand.
So the intent of the wholesale
electricity market and all
of these different
pieces of it is
to use competition to
procure and operate
the most economically efficient
resource mix that we can,
subject to maintaining
reliability.
So I'll gloss over
the reliability piece,
but all of this is always
subject to reliability
and actually keeping
the lights on.
And then some background on
economics of fossil generation
versus carbon-free generation--
in general, a new
natural-gas-fired generator
is--
this is all relative here--
but inexpensive to build.
It has low capital costs,
but it is expensive to run.
It has to pay for its
fuel, so it has a high cost
to operate and produce energy.
In comparison-- flip that--
new carbon-free resources
are higher cost to build--
higher capital costs--
but generally, they
are low costs to run,
or even free to run,
because they don't generally
have to buy their fuel.
Now, let's look at the energy
market and energy market
pricing.
So the way this works,
it's a competitive market.
Each supplier that wants to
offer energy into the market
offers its variable cost
of producing energy.
So it's fixed its
capital costs to just
be available on the system.
They don't get to offer
that into energy market.
They're just offering their
variable costs of producing
the next megawatt hour.
If their fuel is free--
if they're a wind plant,
for example--
then they basically
have no variable cost.
They would offer
a price of zero.
If they're receiving, maybe,
a production tax credit
that pays them a tax credit for
each megawatt hour that they
produce, then maybe their
marginal variable cost
of producing electricity
is actually negative,
because they're getting paid
something from something
other than the energy market.
So the ISO New England
auction for energy
will take all of
these offers that
had come in from all of
the different suppliers
and select how much energy
each different supplier should
produce, based on
their offer costs.
So they'll take the
lowest price offers first.
They'll line them all up and
take the lowest price offers
first, until they have
chosen enough energy
supply to meet the demand.
And then the-- subject to
physical and reliability
constraints--
and then the last
offer accepted,
that sets the clearing
price for the auction.
So this process is
called economic dispatch.
And it's a uniform
clearing price auction,
because that last offer
accepted sets the price
that all of the accepted
offers get paid.
So even if you offer
zero into the market,
if a natural gas plant sets the
price at $50 per megawatt hour,
you'll get paid $50
per megawatt hour.
So I'd like to walk
through a very simplified
example of an energy
action, to show you
some things that happen in it.
So let's imagine
now that we have
two generators in our system.
So we have generator
A and generator
B. They're the only
generators on our system.
And we have 100 megawatt
hours of load in a given hour.
So generator A is
offering 50 megawatt hours
at $100 a megawatt hour.
It's a fairly
expensive generator.
Generator B is a
little less expensive.
It's offering 70 megawatt
hours at $80 per megawatt hour.
So we have 100
megawatt hours of load.
We take the lowest
cost offer first,
so generator A is selected for--
sorry.
So all 70 megawatt hours of
the less expensive generator B
get selected, and then only 30
of the more expensive generator
A get selected.
And because generator is
the last offer accepted,
it sets the price for both of
them at $100 per megawatt hour.
So that's how the
market has historically
worked in the past, except
with hundreds of offers,
instead of two.
So let's look at costs
and profits here.
So let's look at the
production costs first.
Based on the megawatt
hours that were selected
and the price that
each of them offered,
which would have been their
variable production cost,
generator A had
a cost of $3,000.
Generator B had
a cost of $5,600.
Now, what did they get
paid by the market?
So the market clearing
price was $100.
So generator A gets paid
$3,000, and generator B
gets paid $7,000 from
the market, which
means that generator
A made zero profit.
So it set the price at its cost.
It breaks even, but it
doesn't make any profit.
It was what's called
the marginal generator,
the marginal unit.
Generator B, on the other hand,
it makes $1,400 in profits,
because it was inframarginal.
It was below the marginal price.
So now let's add
a third generator,
a clean energy
resource with free fuel
that's offering $0 per
megawatt hour into the market.
So we'll stack our offers up
in low to high price order.
And now let's
imagine that we have
40 megawatt hours being offered
by this clean energy resource.
The market only needs 60
megawatt hours from what's
now the more expensive
generator, B,
which is less than
the prior example,
and we don't need any
energy from generator A.
So now generator B has
become the marginal unit,
and it's setting the price
at $80 per megawatt hour.
So again, let's look at
costs and revenues here.
So generator A went from
being the marginal unit
and earning no profits
to not running at all,
being out of merit, and
also earning no profits.
So it's indifferent
to the situation.
Generator B went from being
inframarginal and earning
$1,400 of profits to
now being marginal
and earning $0 in profits.
So it's not particularly
happy with the situation.
Generator C, our new
clean energy resource,
it's inframarginal, and it
earns $3,200 in profits,
because there was a big
difference between its costs
and the clearing price
in the energy market.
So with low levels of
renewables in the market,
like what we have today,
what we've seen so far,
these renewable generators
that come into the market
can earn very large profits
in the energy market
to pay for their fixed costs
to build these projects.
But then what happens as we
keep building more and more wind
and solar, and bring
in hydro, and have
our nuclear plants running?
Let's imagine in this example
that we add another 70 megawatt
hours of zero-cost fuel supply
of clean energy resources.
So now we have
110 megawatt hours
being offered of clean resources
offering at a price of zero,
but the market only needs 100.
So nobody earns any profits
in this energy market.
The market price gets set at
$0, because the clean resources
are marginal.
These clean energy
resources, C and D,
they're not losing money, but
they're not making any money,
either.
They're not earning
any profits that they
can use to pay off their fixed
costs of actually building
their project.
So they're not particularly
happy with this situation.
And then, in a clean energy
future, what do the energy
market profits look like?
So today, natural
gas is marginal
and sets the price in the energy
market about 80% of the time.
So almost all the
time, natural gas
is setting the
price for everyone.
This chart on the right
that you see shows--
in green, it shows
the natural gas price,
and in blue, it shows the
wholesale electricity market
price, and they're almost
right on top of each other.
So natural gas, which is
quite volatile in price,
is driving the cost of energy.
The more fossil fuel resources
we add to the system,
the more often they're
going to be setting
the marginal price
in the market at $0,
or maybe even at
negative prices.
So if solar is marginal
when it's sunny,
if wind is marginal
when it's windy,
if nuclear is marginal in
the middle of the night,
there's very little money
left in the energy market,
and possibly no money
left in the energy market,
and no profits for anyone
in the energy market
if you take this
far enough, which
is where we need
to take it to meet
the legislative requirements.
So if there's no money in
the energy market anymore,
how do you pay for
new power plants?
How do you finance power plants?
How do you keep existing
power plants going?
And if there's no
money in the energy
market, what's your incentive
to actually produce energy?
What's your incentive to do
your preventive maintenance
on your system, to actually
run when you're called on,
to staff your plant
appropriately?
If there's no money
to be made, that's
a question for another
day, but that is an issue.
So I want to focus on
the question of how
do you finance your
power plant, if there's
no money in the
energy market anymore,
because the marginal cost
keeps getting set at zero.
So that brings us to
the capacity market.
So in New England,
we have what's
called a forward capacity
market, FCM for short.
And the FCM procures resources
with sufficient capability
to meet the forecasted peak
demand for energy and reserves
about three years
into the future.
So this is a market
that makes sure we
have enough resources
available in the future
to meet demand in the future.
Like the energy market, it's a
uniform clearing price auction,
and the forward capacity
auction happens once a year.
So new resources that
come into this auction,
they offer their price that
they need in the capacity market
in order to be
built, and then they
can actually lock in
that price that they
get in that first year.
They can lock that price in for
seven years, if they want-- up
to seven years.
And the whole point
of this market,
and the whole point of
that seven-year price lock,
is that that is a financeable
market commitment.
So that is enough revenue
that they can go to a bank.
They can go to a lender and
get financing to actually build
their generator.
That's the point of this market.
Existing resources come into
this market as price takers.
They just take whatever
the price is each year,
and that's enough--
that's supposed to
be enough-- to cover
their fixed costs of keeping
their generator up and running.
But if it's not, then
they might withdraw
their offer and what's called
de-listing from the market.
So if the market
price is too low,
and it's not covering
their fixed costs,
then they would de-list and
withdraw their offer capacity
from the market, and
either mothball their plant
for a while or
retire it completely.
So this market is
really intended
to drive those
investment decisions
in building new plants
or deciding when it's
time to retire existing plants.
It's meant to provide
the missing money
to cover those fixed
costs that aren't
covered by the energy and
ancillary services markets.
But again, like
I've been saying,
the price signal from
this capacity market,
which is really what's supposed
to be driving these investment
decisions and determines
what our fleet is supposed
to look like in the
future, it is driving us
towards building more gas,
not building more clean energy
resources.
And there are multiple
aspects of the FCM design
that are causing
this, and they're
working against the
very policy requirements
that we have to
decarbonize our system.
So I'll talk about a few of
those aspects of this market
and why they're fighting
these public policies--
or how they are.
So the first is that
the capacity market,
it's really complex,
it's very risky,
and it's getting
more so every year.
And that's why I have a job,
so in one sense, that's nice.
But that's not what
I'm in this for.
So it's very complex.
It's very risky.
For a large
generator, it's fine.
They can invest in figuring
out how this market works
and figuring out how to
manage the risk in the market.
But if you are very small
distributed generator,
the cost-benefit of trying
to deal with this market,
versus just forgoing
that revenue,
it's not obvious
that it's worth it
to even bother to participate in
the market if you're too small.
And so there's actually
a significant build-out
happening just outside
of the capacity market.
So this figure over here shows
ISO New England's projection,
again, of the solar
build-out that's
expected to happen over the
next 10 years, cumulative.
So the orange bars there,
that's your rooftop solar
in New England.
So that's your
behind-the-meter solar.
And it's actually--
what it's doing,
it's reducing demand, like
I talked about earlier.
And that reduced demand is
reducing the amount of capacity
that the capacity market
needs to purchase.
So it's getting recognized
in the market that way,
without actively
participating in the market.
The gray bars on the bottom--
if you can squint and see them--
those are the solar projects
that are actually participating
in the capacity market that
are offering, and getting
commitments, and supplying
their capacity towards the need
that we have in New England.
The green bars between
the two, that's
the solar that is completely
ignored by the capacity market.
It's neither reducing load and
reducing the amount of capacity
we need to buy,
nor is it actually
actively participating
in the market
and getting recognized
by the market.
So by 2026, ISO New
England projects
that there will be 1,250
megawatts of solar--
that's AC nameplate-- built in
New England that is completely
outside of the capacity market.
And when we look at the
capacity value of that,
that's equivalent to 500
megawatts of capacity market
value, because solar doesn't
produce at full output
all the time.
500 megawatts, that's
a large gas plant.
So that's a large gas
plant that the market
is going to say we
need to build to meet
our demand for capacity, or
that's a large gas plant that
is going to want to retire that
the market is going to say,
we can't let it retire,
because we still need it,
even though, actually,
we have the solar there.
It's just being
ignored by the market.
So that's a tricky
one to figure out,
but it's a reality
of what's happening.
I get a lot of
solar projects that
want me to help them
with the capacity market,
and the first thing I
say is, how big are you?
And most of the time, the answer
has been, it's not worth it.
Sometimes, if they're
big enough, it is.
And more and more,
these projects
are getting bigger, so more
of them are getting in,
but it's still not clear that
it makes sense for most of them.
So that's a byproduct of just--
the market's
complicated and risky.
But then there are some actual,
fundamental market design
features that are intended to
keep clean energy resources out
of the market.
So one of them is called
the minimum offer price
rule, MOPR for short.
And so as this gets a little
bit wonky and into the weeds,
but I'll try to explain
what it's there for
and what it does.
So because the FCM is
so important for driving
these investment
decisions and maintaining
resource adequacy in
the region, the market
has been protected from what's
called buyer-side market
power that could cause price
suppression in the market.
So if you imagine a buyer
in the market subsidized
some otherwise uneconomic
resource that wouldn't have
cleared in the capacity
auction, but with this subsidy
is able to offer a lower price
and bring the whole capacity
auction clearing
price down, then that
could lower the capacity
auction clearing price
that gets paid to everyone.
And so if you're a
big buyer, maybe it's
worth it to subsidize a few
small uneconomic resources
and bring the price
down, so you save money
on all of the other-- the
market's 35,000 megawatts,
roughly, so if you subsidize a
few to save on the other 35,000
megawatts, maybe that's
worth it for you as a buyer.
But then the market price that's
being sent out to the market
by the capacity market
wouldn't actually
be the competitive price
to build a new power
plant without these subsidies.
So there are questions about
whether you can actually
finance competitive
projects if they're
competing against these
subsidized projects,
and that's a concern.
So the MOPR was created to
prevent that type of action
in the market.
Can you just give
an example-- who
would be a buyer in this case?
So the classic example--
they're not directly
the buyer, but they
might be acting on behalf
of buyers-- would be states.
So a state that decides
that they are going
to provide subsidies for--
OK, so there were
some cases where
there were some
states that thought
they could lower the
capacity price by subsidizing
some new gas plants.
And so they provided
subsidies for some new gas
plant that then
came into the market
and brought the price down.
This is in another market.
And the regulator
stepped back and said--
the federal regulator-- said,
wait, wait, wait, wait, wait.
You can't do that.
That's not fair.
So they said, you can't do that.
You can't subsidize
a couple gas plants
in order to bring the
price down for everyone.
We're going to prevent
you from doing that.
So the state wasn't
directly the buyer,
but they were acting on
behalf of all the people
who lived in the state,
who were the end users.
So the federal regulator
said, no, no, no, no, no, you
can't do that.
We're going to create this MOPR,
this minimum offer price rule.
And what the MOPR
is going to do is
it's going to set
a minimum price
that every new resource coming
into the capacity market
can offer in the auction.
And the MOPR--
the example I just
gave-- this all came up because
of subsidizing fossil fuel
plants, actually, but it doesn't
differentiate between subsidies
that are provided for the
purpose of suppressing
the market price, versus
subsidies that are put in place
for what's referred to as
legitimate public policy
reasons, like decarbonization.
It lumps them all together.
So how do we do this?
So ISO New England,
they periodically
calculate what they call an
offer review trigger price,
ORTP, and that is
their estimation
of the minimum
unsubsidized price
that resources of a
different technology type
would need from
the capacity market
in order to break even and make
those projects financeable.
So it's meant to be the minimum
that these projects would
need in the capacity market
to make their projects work.
And it importantly excludes
any out-of-market revenue
they're getting.
So if they're getting any--
it's called
out-of-market revenue--
any of these subsidies outside
of the market from, maybe,
a contract that's above market
prices or, for example, solar
in Massachusetts that gets
special incentives for solar
located in Massachusetts
that not everyone gets,
those revenues get ignored
in this calculation,
and they come up with what
they think a resource that's
not getting those
subsidies would
need from the capacity market.
And that becomes the ORTP.
And so the ORTPs were calculated
for the most recent time
in 2016 for the twelfth
forward capacity auction.
And that's what's shown
on this table here.
So natural gas combined cycle
plant, for that auction,
they determined should need
$7.86 from the capacity market
to break even,
basically, given all
of the costs that they
assumed and the revenues
that they were expecting from
other parts of the market.
A simple cycle gas plant was
expected to need $6.50 from
the capacity market.
Wind was expected
to need about $11.
Solar was expected
to need about $26.
Now, everyone can nitpick
whether these numbers were
calculated correctly, but
these were the numbers
that were calculated.
So let's talk about what
they do in the market,
and what they mean.
So even if you have a new
resource that's viable
and can be built below
those ORTP prices,
they're not allowed.
The minimum offer
price rule says
that they're not
allowed to offer a lower
price into the market.
Once the market price
gets to that level,
their offer just gets
kicked out of the auction.
If there's a project
that's viable because
of out-of-market
revenues, they don't
get to offer below their ORTP.
That is their floor price.
So that means that
the capacity market--
what it's going to
do is it's going
to procure the least-cost
resources that it
sees in the action.
So it'll procure the lower-cost
new resources like gas plants
first.
We see their ORTPs of $6, $7.
It'll procure those first.
It will only procure those
higher-cost resources that have
that minimum offer
price of $11 or higher--
it will only procure
those if there aren't
enough lower-cost resources.
If there aren't enough gas
plants being offered to meet
the demand in the market--
to meet the requirement
in the market--
that's the only reason that it
would clear at a higher price
and accept those resources.
So that leads to
over-procurement,
because those resources
are getting built anyway
for policy reasons,
so then you're
building capacity outside of
the market and more capacity
from the market.
And it's building
the very resources
that the policies are
trying to replace.
So there are some
accommodations in the market
for public policy, to try
to bring these resources in.
So there used to be what's
called a Renewable Technology
Resource Exemption,
which let up to 200
megawatts of clean renewable
resources into the market
each year they could offer at
any price that they wanted.
But that has just
been eliminated.
It is now phasing out,
and is being replaced
by a market mechanism
called CASPR
that creates a secondary
substitution auction that's
meant to match up resources
that want to exit the market
and retire with these new
resources that want to come in.
And then they'll go into
this secondary action,
and they'll match
up with each other,
and the existing
resources will leave.
The new resources will come in,
and everyone would be happy.
Except this market
that's been created--
the auction will happen next
year for the first time--
this CASPR auction is
extremely illiquid,
the way it's been
designed, and I'm
skeptical that many, if any,
new clean energy resources
will actually be able
to come into the market
through this auction.
So we've set up this
very complicated auction
that I don't think
is actually going
to allow clean resources
into the capacity market.
So again, they're going to
get built and just operate
outside of the market,
completely ignored
by the market.
And the market is going to
keep procuring enough resources
to supply the need.
So the costs have been
coming down, right?
So wind is becoming
more cost-competitive.
Solar-- prices have
been coming down.
So what happens if a
project can actually
show that it's viable
in the marketplace,
that it's cost-competitive,
even without subsidies outside
of the market?
So those projects
are cost-competitive.
That's actually been
the case, oftentimes,
in recent years, for
onshore wind projects that
don't need major new
transmission built.
Solar has been inching
closer to that each year.
It's still not there, but it
is trending in that direction.
So those resources, if
they offer into the auction
and clear, just
like a gas plant,
they can lock in that
first year's auction price
for seven years, which is
meant to make them financeable,
and then they float
with the market.
But unlike a gas plant,
that's still not enough.
So even though these projects
are completely cost-effective
in the market--
cost-competitive, when you
look at the big picture--
you still can't finance
them from the market.
So here's why.
So a gas plant in
the capacity market,
at the break-even capacity
price, the ORTP value that
was calculated, if it locks that
price in for the first seven
years, what this
shows on the bottom--
so that gas plant will recover
about two thirds of its capital
costs from the capacity market--
from that locked-in revenue
that it knows it's going to
get for the first seven years.
So only a third of
its capital costs
need to be recovered
from revenue sources that
are subject to market price
volatility or regulatory risk--
so the energy market,
ancillary services
market, or the capacity
market after year seven.
So two thirds of the
revenue locked in--
sorry, of their capital
costs locked in.
They can go to the bank
with that and get financing.
Wind and solar,
on the other hand,
even if the market were to
clear at their break-even cost--
so they're cost-effective
at that point--
they're only earning 10% to
16% of their capital costs
from the capacity market
that are locked in.
I can't go to the
bank and say, I
know I'm going to be able
to pay you back 10% of this.
Will you lend me the money?
That's not going to fly.
So even though these resources
are becoming more and more
cost-effective, even
though some of them
are completely cost-effective
and competitive now,
and may even be the
low-cost resource,
they still need a contract.
They still need a contract
outside of the market,
because the market
isn't giving them
what they need to
actually get the loan
to finance and build their
new clean energy resource.
They're not necessarily
more expensive,
but they don't have
any market certainty
from the market the way
that a gas plant does,
or the way a gas plant could.
And then let's take
it a step further now.
So I talked earlier
about what happens
if we get to that 80%
reduction in carbon emissions,
and there's no profits
left in the energy market.
These resources are making most
of their money in the energy
market today.
So what happens if there are no
profits in the energy market?
So these zero-fuel-cost
resources,
the price disparity
in the capacity market
gets even larger, because
they have no revenue left
in the energy market.
So they need to get
all of their costs paid
for by the capacity market.
So if you take that
same financial model
that ISO used to
create the ORTPs,
and you zero-out the
energy market revenues,
and leave everything
else untouched,
you come up with
what's shown here.
So the simple cycle gas plant
with energy market revenues
that are expected--
the ORTP was $6.50.
If we assume no energy
market revenues whatsoever,
they only need $6.75.
They're not really depending
on the energy market
to finance that project.
It's the capacity market, and
so it doesn't change very much.
But the wind and solar--
wind goes from $11 to $55.
Solar goes from $26 up to $68.
So now, if you imagine
a capacity auction
like this in the future, where
you have gas plants being
offered at $6 and wind
being offered at $55,
the market's not
going to buy the wind.
It's going to buy the gas.
So people talk about
carbon pricing.
If we just had carbon pricing,
it would fix this problem.
And it-- maybe temporarily.
Maybe temporarily.
For a few years,
it'll fix the problem.
So you put a price on
carbon, the fossil plants,
they have a higher
cost now to operate.
When they're marginal, it
raises the energy market price,
and so the clean
energy resources
make more money
when they operate,
because the price
for energy is higher.
But it's only temporary.
What happens when those
clean energy resources that
don't have a cost for
carbon emissions--
when they start setting the
marginal price for energy,
the carbon price doesn't
do anything for them,
and we still end up with
zero price for energy.
So carbon pricing, maybe
it's a temporary fix.
Maybe it's a temporary
Band-Aid, but it doesn't solve
what I'm talking about here.
There are a lot of other ideas
for achieving public policy
requirements
through the markets.
So one option is recognizing
the actual policy requirements
as explicit constraints
in the auction.
So you take this
clearing algorithm
that's been written
for the auction,
and you put in as
a hard constraint
that it needs to purchase a
fixed amount of clean energy
resources, or no more
than a certain amount
of fossil resources.
The market can clear
against that constraint,
and it will procure the
right mix of resources
to meet that requirement.
But who determines what
that requirement is?
We have a six-state market here.
So there's a California market,
there's a New York market.
Those states get to
decide their requirements,
and maybe they can put
them into their markets.
But here, we have six
states sharing one market.
Which state's policy
goes into the market?
How do you reconcile who
pays for any increased costs
or savings that
might occur, based
on trying to implement
policy through the markets?
The states do not see
eye-to-eye on this.
It also raises
states' rights issues.
So the ISO New England market
is a federally regulated market.
I don't know if
anyone here thinks
the states are ready
to cede implementation
of their public policies
to the federal government.
I don't think they're yet.
So we hit a roadblock there.
So wrapping up,
the energy market
has less and less money
in it as we really
move towards decarbonization,
which is what we need to do.
And even if it did
have more money in it,
it's too volatile to
provide financing, anyway,
for new clean energy resources.
The capacity market
is and will continue
ignoring many, or even most,
clean energy resources that
are built for policy reasons.
So we'll be building
redundant systems,
which doesn't make sense.
It doesn't provide a
financeable revenue stream
for these clean
energy resources.
Even if they're
cost-effective, and even
if it's clearing at the price
that they need to break even,
it's still not financeable.
And the more clean energy
we add to the system,
the more the market
will drive us
towards the very
fossil resources
that we're trying to
replace with these policies.
But yet, the policies do
require more clean energy
and less fossil energy.
So that forces the states to
achieve their policies outside
of the markets, as they've
been doing through contracts,
and regulated rates, incentives.
And those, in turn,
distort the markets.
So then the markets get
changed to protect themselves
against and correct for the
impact of those policies
on the markets and
the price suppression,
and that's where we are.
And it sort of works today.
Some accommodation may work
in the market temporarily,
but if the policy resources
get too large compared
to what's left in the
competitive marketplace,
there's not much of a market
left there to protect.
So as I started, I like
the idea of markets.
But as I see it, this
market system that we have,
it's just not going
to work much longer,
the way we've designed them.
So it will work for some
number of years more,
but at some point
between now and 2050,
it's not working anymore.
And so there are a lot
of people who think--
for whatever reason,
they're not sure
if this transition is happening.
And if you've ever
been able to see
Gina McCarthy, the former
EPA administrator, talk,
she has this phrase that I like.
She says "the clean energy
train has left the station."
There's no question about it.
It is happening.
We are on this path, and
get with the program.
So if we're going to
have markets that last,
and there are a
lot of people who
work in the markets who
want to see them last,
my message is that we
need to figure this out.
So I don't know what
the solution is.
There are a lot of
bright people here
at MIT who are working
on questions like this.
And if you have
ideas, fantastic.
Work on them, develop
them, and maybe they'll
solve this problem.
All right.
Thank you, Abby.
That was great--
really walking us
through the real-world
implications of some very--
at least to a boffin
like me-- arcane market--
the fact that-- we have time
for a number of questions,
so I saw-- maybe back there was
the first visible hand to me.
I'm staring into the light,
so if I miss you, wave.
Yes, I'm wondering if you've
done the thought experiment
or even analysis of the
implications of low-cost energy
storage.
Does that ameliorate or
exacerbate the problem?
I haven't.
So energy storage will tend
to even-out the market--
so even-out that volatility
and those fluctuations.
But it's not going to solve--
when there's no money
left in the energy market,
adding storage won't
create energy profits.
So I don't think it solves the
problems that I'm describing.
It does help with a lot of
other issues, but not this one.
Does ISO New England
either understand or agree
with what you're
saying, and if so,
might they be motivated
to change the rules?
And if they don't agree,
what would you say
is the reason for that?
Are their political
or economic interests
militating toward their not
understanding or agreeing?
I think there are a
lot of people there
who understand this.
Whether they agree with
it, I can't speak for them.
I don't know.
I think the status
quo is hard to change.
I think there's a constant
process of incremental changes
to the market being made, but
I think something fundamental
might be needed.
And that's a hard change to
make from inside the system.
Their number-one priority--
so they operate the system
as efficiently as they
can economically, always
subject to reliability.
So their primary interest
is in keeping the lights on,
and operating a system
that's decarbonized is
something people haven't done.
So it's a scary idea.
It's a hard problem.
And so I think there's also,
on that reliability side,
a lot of hesitancy about
what that shift looks like.
Could you speak a little
bit about dispatching?
Anything in particular about it?
The ordering of
dispatching, because I've
seen finances of wind
farms get messed up
by being shut down at times
they weren't expecting.
Yeah, so the economic
dispatch processes
I described-- so all
the suppliers will offer
their marginal costs
of producing energy
into the auction,
and the auction
will take the
lowest-cost offers.
Is there chalk here?
So you have all these
offers that look like that.
So from lowest cost
up to highest cost,
you stack them up.
And the market will say,
I need this much energy
to supply my demand, and
so this becomes the price.
So as you start adding more
and more zero-cost energy,
this curve shifts to the right.
So maybe the curve
looks like that,
and then this becomes the
price, or maybe the curve shifts
like this.
Or maybe the demand in
the middle of the night
is over here, and so
then there's a zero-cost.
And this clean energy
resource that's offering zero,
it thinks, I'm free to operate.
I'll be able to operate all
the time, but not all the time.
So if you have more of
this zero-cost resources
available than the demand
on the system, some of them
are going to get shut down.
Thank you.
This was a great explanation.
I've been trying to suss
this out for a while.
I know this is about
ISO New England,
but do you have an
opinion about some
of the other
multi-state markets,
and have they been
able to address this
at all, like PJM or MISO?
Everyone is trying to
figure this out right now.
Everyone has a slightly
different approach to it,
but everyone is trying to
figure this out right now.
And nobody has an answer yet.
Right in the middle there.
How does this system or
any of its proposed changes
deal with time of day?
So for example, you could
have all the renewable energy
you need in the
middle of the day,
but that still
doesn't do anything
for peak, evening period or
getting you through the night.
Right.
So there are a few
ways to address that.
One is storage, as
somebody else asked about,
to shift it around.
There's a small amount
of storage on our system,
but not enough to sort of
shift everything around.
One of the ways you deal
with that is fuel diversity.
So in a system of looking
at clean energy resources,
generally, wind and solar are
complementary to each other,
and then hydro can used to fill
in the gaps and firm things up.
And the more diversity
you have of resources,
both in technology type
and geographic dispersion,
so that when a wind
front comes through,
or when a cloud
mass comes through,
it doesn't hit all
of the solar panels
at the same time, that helps
with the types of issues
that you're describing.
So this is based on not having
storage for the energy--
so this is based, I'm
assuming, on the fact
that, right now, we
don't have large storage
capability for renewable
sources like wind and solar.
We do have storage solutions
coming down the pike,
as the expression goes.
And wouldn't that
change the picture
and make the pricing approach
become different, because now,
as a supplier, I couldn't
know what my capability is
to provide without
having to guess
on what the weather is like?
Yeah, so what I was
describing here--
there are many issues
that storage does solve,
but what I was describing
here is not solved by storage.
So at the point where our system
is almost entirely made up
of resources that have zero
costs to actually operate
and produce a megawatt hour,
if you can store some of that
and provide it at
another time, there's
no money at any time of day--
or basically no money
at any time of day--
so shifting it around, which
is what storage can do,
doesn't solve that problem.
But as a business guy, I look
at it from that point of view.
I know, with storage,
what I can provide,
and what I can supply, and
guarantee that I can do that.
So when I go for financing,
I can go, and I can say,
I have the capability
of supplying reliably
x number of megawatts, and
I know that it is there,
because here's what we have.
Yeah, so what he was
asking was, if I'm storage,
and I know what I can produce,
I can provide reliable supply.
Can I go and get
financing with that?
And only if you're
getting paid for it.
So what are you
getting paid for?
If you're getting paid the
energy market price of zero,
no.
If the market changes and
provides you a price signal,
and provides you profits
or revenue for that service
that you're providing,
then yes, you
can go and get financing
and build that storage.
But that's part of the
problem, that the markets
that we have right now don't
necessarily properly value
that and properly pay for that.
I'm getting the
great signal there.
We actually have time for
maybe one more question,
and then-- so who's really
been waiting a long time?
Right up in there.
You have been waiting
quite a long time.
Gentleman in the
light-blue shirt.
Thank you so much
for the presentation.
That was really excellent.
So why can't renewables just
bid their levelized cost
of electricity?
Is there a regulatory
requirement--
OK.
Yes.
So that as fairly simple.
You want to take another
question from someone else,
perhaps--
or why don't we
design a system where
they're permitted to bid their
levelized cost of energy?
Obviously, there's challenges
in forecasting that, based
on how many megawatt
hours you'll actually
be able to provide over the
lifetime of the project,
but that seems like a solution.
So the main problem here
is that the marginal cost
isn't actually the only
price signal that we need,
or the primary price
signal that we need.
So the simplest
solution seems to me
to be to shift it to a market
where the price signal is based
on the levelized cost of energy,
rather than the marginal cost.
Thoughts?
Yeah, so you get into
difficulties there.
So let's say your
levelized cost of energy
is just below or just above
what the market price is.
And maybe you've already
built your plant,
and so you're trying
to recover your costs,
and so why not shift your
offer just a little bit
below the market price,
so you can actually
produce your megawatt hour
and operate, so that at least
you're recovering
some of your costs.
But then the next guy, they're
going to shift their price
a little bit below that,
and everyone's just trying
'm shift--
Economics.
--so then you end
up back down at--
what's my break-even
point where,
if I produce this megawatt
hour, I'm going to lose money?
So that's what ends up
happening with that.
But if you look at it
on a long-term basis,
you look at the
requests for proposals
that the states run for
long-term contracts, that's
what they're doing, but
on a long-term basis.
So this RFP that
Massachusetts just
ran that selected this
import from Canada,
there were over 8 gigawatts of
resources bid in to provide--
they were looking for just
over 1 gigawatt of energy.
So over 8 gigawatts of resources
bid in for a 20-year contract,
I think it is.
So they're all trying to give
the most competitive price
that they can for
what they actually
need to build their project.
So in some ways, maybe
that's our market.
But that's out of the market,
and that's a state contract,
separate from these
wholesale markets.
But that's what
you're talking about.
Thank you.
I'm afraid we--
this has been great.
Thank you for coming,
and thank you, Abby.
[APPLAUSE]
