Power Purchase Agreements for Grid-Aware Renewable Energy Procurement

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>>Female: – webinar, which is hosted by
the Solutions Center ship – Center in partnership with USAID and the National Renewal
Energy Laboratory. Today’s webinar
is focused on the power purchase agreements for grid-aware renewable energy
procurement. Before we begin, I’d quickly – I’ll quickly
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and selected by technical experts. Today’s webinar agenda is centered around
the presentations from our guest panelists, Barbara O’Neill and Tara Fowler, who have
joined us to discuss power purchase agreements for grid-aware renewable energy
procurements. Before we jump into the presentations, I will
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this service to those in your networks and organizations. Now I’d like to provide a brief introduction
for today’s panelists. First up today is Barbara
O’Neill. Barbara is the grid integration manager at
NREL, where she leads projects and engages stakeholders domestically and internationally
to provide information on renewable energy integration practices and
technology. Following Barbara, we will hear
from Tara Fowler, the manager of renewable energy power purchases for Xcel Energy. Tara provides leadership and directions in
negotiation and administration of long-term renewable energy purchases agreements between
Xcel Energy and power suppliers. And our moderator for today’s question and
answer session is Ilya Chernyakhovskiy. Ilya
is a co-author of USAID and NREL’s Greening the Grid toolkit. And with those
introductions, I’d like to welcome Barbara to the webinar.>>Barbara: Thank you, Katie. Okay. Welcome, everyone. Thanks for being with us. Hold
on a second, please.>>Katie: Just one moment, everyone. We’re having a little bit of technical difficulties. We’ll clear it up and be with you in a second.>>Barbara: I am [inaudible]. Do you want me to – okay. I’m gonna go ahead and start. And we’re gonna be pulling those slides up
in a second. So welcome and thanks for being
present. We’re going to talk about power purchase agreements,
but just to caveat this, we’re not talking about PPAs in general. There’s many provisions in a PPA that address
obligations and risks and all sorts of contingencies certainly on the legal end. We can
negotiate these things for months. We’re gonna be focusing on the provisions
in the PPA that provide services back to the grid for reliability and security considerations
for stability of that electrical system. It’s
important that renewable generators, as they become increasing prevalent, are good
citizens to the grid. And we’ll sort of go through some of the ways
which we can obligate those generators to participate in that way. So for the agenda, we’re gonna start with
the – just sort of an intro or just cover some
basics about PPAs. So when I say PPAs, power purchase agreements,
or purchase power agreements, we mean the same thing. And I also might use the acronym RE for
renewable energy or VRE, which stands for variable renewable energy, implying wind
and solar. So in other words, we’re not gonna be focusing
on services that could come from, say, hydro plants or geothermal or biomass. Primarily the wind and solar plants
will be those variable renewable energy generators. And this is clearly because the sun and the
wind, which are fueling those generators, are
moderating based on weather, based on meteorological conditions. We’re gonna go into
specific considerations of how you might structure your PPA to ask for some of these
services. And then I’m gonna pass it over to Tara, who
will talk about Xcel’s procurement of renewable energy as an investor-owned utility
here. So some of the key takeaways, which I’ll hit
on the back end, as well, are that as renewable energy penetrations increase, you’re
going to have a different system. You’re
going to have more non-synchronous generation replacing synchronous generation. And
I’ll get into what that means in a little bit more detail later. But never fear; we have the
physical ability to provide some of those services with these new technologies. So there have been so many advances in power
electronics that to ask your wind and solar generators to provide some of those
services is not out of the question, and it’s not
uneconomic. And all of this is going to contribute to
keeping the electrical systems stable and secure. Reliability is obviously very important to
all of the providers, all of the utilities globally who are obligated to provide
their customers with a constant supply of high quality power. But keep in mind that there is no set, one
size fit all – fits all approach, and everything is sort of system
dependent. Here’s a slide on definitions. We’re gonna kind of skip through that. I’ll cover these
definitions as we encounter them, but this will be a good reference for you to go back
to with your slide deck. Again, VRE, for variable renewable energy. And when I say IPP, I
mean independent power producer. So in other words, another party who will
be the owner slash operator of a renewable energy
generating plant in contractual agreement with a utility. So as far as PPAs, moving on to this introduction,
PPAs are one of those key mechanisms that utilities use to procure renewable energy. And a lot of utilities when they’re first
getting into the game, they don’t have experience typically on running that kind of plant. They’re good at running combustions turbines
or steam turbines or those sorts of more traditional fossil units. And so it’s a good way for utility to procure
from some other developer who knows how to go out and find
the land lease options and knows how to set up anemometers or paradometers and take measurements
for solar and wind and knows how to kind of develop that type of project. And then the utility can get into contract
with that entity at – in a pretty risk-free position. Because what they’re gonna pay for is the
kilowatt-hours. So it’ll be a dollar – a monetary
unit per kilowatt-hour. So it’s energy only typically contracts, where
they just pay for what they get. The length of the PPAs are long-term. So we’re looking at 20 to 25 years. And that is kind of based on the warrantees
for some of the equipment used in wind and solar contracts. And it’s not to say that these plants won’t
go on running after that. As we have more and
more generators who have been on for a long time – here in the US we’ve got – it’s
late 90s, early 2000s. We’re getting experience with older wind and
solar plants. And there
are things you can do to kind of rehab them or maintain them. And they really do, we’re
finding, last longer than this kind of 20, 25-year warrantee claims. But it’s good to have that length of contract
because your counterparty, your IPP, will have a better chance of getting financing. So they’re gonna go to a project finance
investor, and they’re going to borrow the money to build this plant. And if they have a
good, credit-worthy off taker, IE the utility, and they have a long-term guarantee that
somebody’s going to be buying this power, that will provide a lower debt – cost of
debt to borrow that money. So the savings will ultimately be passed on
to you, the utility. So it’s important to establish long-term contracts
and the legal obligation of all parties in that contract. And I say all parties. Yeah, usually we’re talking about two. We’re talking
about a buyer and seller, an IPP and a utility. But nowadays there’s some more kind of
out of the box, atypical contracts, where you could have a corporate buyer who’s
interested in renewable energy, such – the Googles or the Amazons or kind of the big
data centers. And perhaps they’re going to contract with
an IPP who will dedicate the output of their wind or solar plant to a corporate buyer. But because that data – say a data center
has an obligation to buy power from the utility as
the traditional customer base, and the utility’s obligation to serve that area, the utility
would be a three – it would be a three-party contract, a three-way contract. So utility would buy from the IPP [inaudible]. And the
quarter would be obligated to buy that dedicated power from the IPP. So PPAs do help to overcome some of these
major barriers. For a utility – what they’ve
been dealing with for decades is commodity risk. They’ve been dealing with variable fuel
costs. And for a while back in the mid-90s, Saudis
were producing oil flat-out. Everything seemed stable and mellow. And then we’ve got big swings. Gas prices go
through the roof. And then we’ve got shale gas plays and fracking. And now, at least in the US, gas plays is
too low, it’s too stable. But it’s hard for utilities to bank on those
costs as they move around. And it’s hard for the economies of some of
these areas who can’t guarantee that their price of power for any sort of manufacturing
activity and that kind of thing is gonna stay stable. So moving to a renewable energy procurement
means stability with respect to that variable cost – sun, wind. These are free fuel sources. And so that’s why it’s great for a
utility to get into that game without having to rely on market forces. Now – and I already
mentioned on the other side, on the flip side of that, developers themselves will be able
to secure project financing better if they have
one of these long-term contracts. So PPAs are designed – moving on to the
next slide – with kind of an allocation of risk in
mind. Dispatch risk is one of the key things. And that means whether or not the IPP is
going to be guarantee that the utility will pay for all of the power that they’re producing. And there could be areas of congestion on
the transmission system, which limit the movement of power to the end user, the consumer
of that power. Or some other reason
why – either an emergency or some other reason on the transmission system why the
power might be curtailed. There’s also economic curtailments, where
a utility might not need the power because they have to, say, have a must-run unit, one
of their big basal coal or nuclear units keep running. And within that PPA, you want to specify the
terms of whether or not curtailed power will be compensated. And in some cases it’s not as black and white
as yes or no. It
could be that you have a bank of compensable curtailment, and then beyond that it’s non-
compensable. And [inaudible] to the IPP to assess the risk
of being able to transmit that power. With
respect to allocation of cost risk, certainly that IPP needs to have their tariff cover
their debt and provide the debt service as well
as the return to their investors on the equity side. And you want to set up a 20 to 25-year price
that’s either completely constant and fixed, or perhaps it inflates at some set
rate, some set percentage rate. Or you could index
it to some economic indicator that could be published by the government or that sort of
thing to track, say, producer price index or some cost of labor to reflect changing
conditions over the 20 or 25 years, as long as it’s a widely available and arbitrary
economic indicator. For interconnection, you need to well define
that point of interconnection. So at that
physical point, you’re gonna have two meters. You’re going to have the utility’s meter,
by which they assess how much revenue they’re
giving back to the IPP. And then you’re
gonna have your IPP, who installs their own meter basically to double check the utility’s
assessment of that revenue and to calibrate those meters and make sure they’re in sync. So you want to make sure at that point – at
the point of interconnection, when the power sort of passes ownership to the utility, who’s
responsible for, again, transmitting that power. So there’s two pieces. One is can the project get interconnected
on time? Who’s
responsible for each step of that process? And then who’s responsible for making sure
the power gets transmitted from the POI onto the
end user? Okay, moving on to the key focus of this focus,
is these flexibility and reliability considerations and provisions within a PPI. So grid services – the term grid services
refer to ancillary functions that support these
– the system requirements for stability on the
grid. There’s sort of two categories of those. One would be in steady state, business as
usual, kind of normal operating circumstances, what services are provided. And then
there’s the other category, which is following a grid disturbance, what can generators do
to help the system regain that sort of normalcy or that steady state? So by grid disturbance, I mean a deviation
of frequency or a deviation of voltage. And
those two things do deviate under normal circumstances. And in some systems they move
around quite a lot. The – with respect to frequency, the bigger
the system, the harder it is to get that system to move, when there’s so
many components. With smaller systems,
such as in island communities, small events can have a bigger impact on the frequency. Because if you have, say, one generator that
goes off the grid, has some outage, some unplanned outage, that’s gonna have a bigger
impact on that frequency than if you were operating in Europe or the eastern interconnection
here in the US. So typically,
traditionally, vertically integrated utilities, which own their own generation fleets, have
the generators mostly for free contributing to that reliability. But in kind of the new
world, this new paradigm where you are going to have more renewable energy
generators, more IPPs, and you might have different markets or just different institutional
frameworks that account for these grid services, you’re going to make sure that the
ancillary services are provided. And some of those include the frequency type
services, frequency response, load following, frequency regulation. And some of them are about having enough power
to match that supply and demand for having enough
reserves that are spinning and that sort of thing. You just have to keep in mind that since power
is instantaneous and not – it’s not able to be stored without the use of a battery
or a flywheel or some sort of storage device – pump storage, hydro – you have to match
everything in real time. And the
responsiveness and flexibility of the grid will necessarily be increased as the variability
of that increases with more renewable, variable renewable generation. So as it is right now, utilities look at,
say, a daily load curve. And as folks turn on their
light switches and manufacturing plants start up or change their shifts, there – the load
that they’re responding to is naturally variable. Utilities are good at responding to
variability. They’ve been doing it for decades. But when you have wind and solar
generation as the first off the line, the first off the stack to be dispatched to meet
that load, because of cloud passage and variation in
wind speed, that power is naturally variable. And so when you net the load with the renewable
variable generation, what’s left is that net load curve that utilities have to meet. That’s going to be – it’s going to have
steeper ramps or spikier spikes. So the higher variability requires a more
flexible system in order to accommodate it. The good news is that it’s doable with these
technical capabilities that these plants offer. So it’s kind of interesting that the solar
and wind generators who are part of the [inaudible] and for the increased need for
flexibility can also be part of the solution by
providing those capabilities. Okay, moving on. So I think we’ve covered a lot of this. What I mean by non-synchronous is where a
generator is actually a DC motor that goes through a converter or an inverter, depending
on if it’s getting converted back to DC in order to connect to the system, as opposed
to your traditional thermal units, which are synchronous, which are connected in sort of
an AC mode. And we’ll get into that a little
bit, as well. By institutional measures, in some cases there’s
grid codes in countries; in some cases there’s a framework for interconnection agreements. In some cases there’s nothing. And
all of that technical requirement type language is embodied in the purchase power
agreement itself. But certainly if you have a PPA between two
parties, you want to either contain all of these technical requirements
within that doc or within an appendix to that doc, or you want to reference the appropriate
other agreements or other obligations of the party. And there’s – there are two categories again. There’s the requirements to interconnect a
plant, and then there’s the requirements to be able to transmit that power, or how they
need to operate in that sort of steady state mode. So it’s important to go through those and
spell out all of the things that both parties are expecting. Okay, moving on. So now a little bit of background kind of
from the engineering side. So we talked about
supply and demand having to be in balance. And systems operate at a specific frequency. And this is because they’re alternating currents. So basically the frequency of that
waveform is what determines the frequency of the grid. US is a 60 Hz grid; Europe is a
50 Hz grid. But to be clear, if I plug in a frequency
here in Colorado, and I plug in one over in Seattle, they’re gonna read the same thing. It’s a ubiquitous sort of measure across the
grid. That contrasts with voltage, which is more
location dependent. It depends on how
close you are to the source of the voltage, IE generation source. So this picture here sort
of shows you with that shaft on the right side of the screen that the synchronous
generators are actually connected kind of in tandem with the frequency of the grid. So if a generator falls off and the frequency
dips, then the other generators will sort of
take up the slack. They will sort of speed up to keep that shaft
rotating at 50 or 60 Hz. That’s opposed to solar and wind, which are
not connected in that way because they’re not
synchronous in that way. They don’t provide this automatic, inertial
response. There are
other capabilities, however, that can be utilized to help with that frequency service. Okay, so we’re gonna move on to the frequency
range requirements, which might be a provision in your PPA. So by deadband, I mean a area of frequency
– so 50 or 60 Hz plus or minus a certain amount. That provides a deadband. That provides a delta frequency
over which you want to require your independent power producer to stay connected. And
that’s important because that will help stabilize the grid. And there are some instances where systems
could theoretically be chasing their tail. If
you’ve got generators that are responding by dropping off or ramping up and trying to
get to a certain set point, that it’s hard to
stabilize. So in order to create stability, you
basically want everyone to kind of keep producing power when there’s these deviations in
frequency. Now, beyond the deadband, your grid code or
your PPA could require what’s called a droop response, where the change
of power would be obligated relative to the change of frequency. And we’re not gonna go into that in too much
detail. But the graph on the bottom right
there sort of depicts this droop response characteristic of a generator. Okay. Now moving
on to voltage. Voltage – in my mind, anyway, I think it’s
a little bit harder to kind of grasp. But basically there’s a nominal voltage at
which these generators are connected. And again, the more distant one is from that
voltage source, the lower that voltage gets. So you can see it sort of – let’s see – let’s
look at this graph. There’s a PV system here. And as you move to the left, the green line
decreases away from nominal to the more distant you are from
that PV supporting system, the voltage drops. And even without a source – on radio feeders,
for example, at the end of the line they’re gonna have a lower voltage than at
the beginning because of that natural decline over distance. There are pieces of equipment that you could
use to help that, which is a voltage regulator, to boost the voltage a
bit. But the key is to require your generators
to operate within a voltage limit. So you want to say here’s the nominal voltage. And then plus or minus some percentage
off of that where that generator should remain online and remain operational as close to
nominal as possible. So minimizing the impact of voltage fluctuations
is important because it can actually damage the utility’s
electromechanical equipment. Okay, moving
on to a little bit probably even trickier concept of reactive power. So reactive power is something that is part
of what we call a power factor calculation. A
power factor is in effect a measure of a system’s efficiency. So this illustration of the beer
sort of sums it up, where the beer is actually the real power or the active power on a
system, the power that can actually do work. Whereas the reactive power is kind of the
foam on top. You need it, but it’s not actually doing work. Well, why do you need it? And it’s because it creates an electromagnetic
field for inductive motors to be able to work. So being as we’re on an AC system instead
of a DC system, there are many loads, many motor loads that require reactive power
in order to be able to do their work. And it
creates a stability of the system itself. So we have to keep the ratio sort of as close
to constant as possible. And that represents the power factor. Now, a utility can have that generator operate
in a mode that is unity power factor. In
other words, that same ratio of real power to apparent power. Apparent power is the total
power. Or they could say, “Hey, I want you to keep
your reactive power constant by modifying your real power.” And if a generator is getting paid for the
real power – they’re getting paid for the actual kilowatts that
are delivered, this is potentially less optimal for
them. Because they might be limiting their real
power in order to keep their reactive power [inaudible] and such they could request
a revenue for pushing down their real power in order to keep their reactive power
constant. Another control mode that might be required
is a voltage control mode, where they’re just going to worry about the voltage piece of
the equation by modifying their own associate parts. So basically the power in an AC system is
that vectoral sum of real power and reactive power. So back to sort of the Pythagorean theorem
type thing, where A squared plus B squared equals C squared. That’s the depiction of the total power, are
those two pieces – the real piece and the reactive
piece. And the utility wants to specify how the IPP
contributes to their voltage stability by requesting which mode they should have that
IPP operate in. And they can also request
that that IPP switch modes. So it’d be a provision of, well, how often
are they allowed to provide the IPP with a request to switch modes? So you want to get all those things
spelled out. It’s pretty technical. But you bring the engineers on and sort of
figure out what’s best for the system’s total stability and the local
grid needs. So another piece of the voltage puzzle
is this voltage ride-through. So as an IPP is sensing the voltage on the
system, just like they’re sensing the frequency on the system,
they’re going to feel voltage fluctuations caused by other instabilities, small instabilities
on the grid. And you want to require them
to stay connected. Because they have protective relays that strip
off their equipment when the voltage deviates either high or low outside side of
a band. And they do it because they’re trying to
protect their own equipment. However, again, to contribute to the stability
and not exacerbate the problem that caused the initial
voltage to deviate outside of that range, you
want them to stay on. Well, for how long and at what deviation? And that is very system
dependent. And it depends on, again, the duration. So the graph here depicts – and this is
PU. It
means per unit. Voltage is usually represented as per unit
to get that ratio that we talked about. If it’s gonna be a large deviation, but it’s
only going to last for 150 milliseconds, you want to require, say, that IPP to ride
through it. But if it’s going to be a large
deviation that lasts longer, then you will give them the permission to trip off. So this graph represents the no trip zone. And it varies by system. We show NERC, so
the North American Electric Reliability Council, HECO, that’s Hawaiian Electric
Company, the Puerto Rican electric power authority, the grid of Ireland, and then IEEE
and international standards. So there’s many different sects for this requirement. But the
point is you can require your IPP to remain online during low-voltage conditions, high-
voltage conditions, or even zero-voltage for a certain, limited amount of time. And you
want to do that to prevent that cascading failure that would happen during severe under
or over voltage periods. Okay. Moving on to SCADA. So SCADA is Supervisory Control and Data Acquisition. This is something that doesn’t apply to just
electric utility systems. SCADA systems
operate for gas systems, for oil systems, for water systems. And the idea is that when you
have a centralized dispatcher or operator or controller who needs to have visibility
into flows basically at different geographic points
on their system, then they do this frequently with the SCADA system. And so the SCADA’s going to not only provide
awareness of what’s going on but also provide the controller
or the operator or the dispatcher to pass a
signal to the participants in that system and request them to do something else – higher
or lower flow basically. So the point with SCADA is to make sure it’s
in place but also to make sure that you have some redundancy of that communication system
and that it’s a high temporal resolution, so as close to real time as you can get. Because that will go a long way toward helping
your system’s stability. And you can also use SCADA systems to pass
other information. So getting the communications protocol set
up in advance and figuring out the best way to have that sort of two-way flow of information
between the utility’s central operator and the IPP is really important and certainly
should be mandated in a PPA. So moving on to the next slide. Forecasting is – it’s sort of a different
animal than the things we’ve just talked about in that it’s
not this kind of physical system stability requirement. But forecasting is increasingly necessary
to optimize the system’s flexibility to respond to solar and wind. So with forecasting, a system operator can
know what’s coming down the pipe in sort of the near term. And if they need to ramp up a unit to
provide reserves for a potential decrease in variable generation or ramp down a unit,
take something offline if they know they’re gonna
have a whole lot of free-ish solar and wind power – I say free-ish because of course
there is some small O and M associated with wind and solar plants. It’s almost negligible compared to traditional
thermal units, however. But with the
forecasting, they can minimize their spinning reserves. There’s a couple different names
for reserves and a couple different categories. But point being if they can minimize that
backup power that’s put aside as reserves in case the wind and solar drop off, they
can more economically take advantage of the wind
and solar power. So in order to get good
forecast of the power out – there’s two different ways an operator can do it. They can do it themselves basically – and
maybe it’s themselves. Maybe it’s some
outsourced service that they utilize. But by doing it themselves, they will need
meteorological data points from the various wind and solar farms on their system. And
pretty specific stuff. They’re gonna need the wind speed and the
irradiance; that’s obvious. But they’ll also need the humidity, the temperature. And they need it at not just one point. Giving them a point of interconnection set
of data points is not going to be nearly as useful
as requiring that set of meteorological data points to be taken with geographic spread
over the entire wind farm. And the same is true
for solar because as clouds pass over, they’re going to hit different parts of the solar
arrays. And so if you’re collecting meteorological
data, you want to require it at various points in the power plant itself. And make sure you know, for example, what
height the wind speed is measured at and these sorts of things. So they can take all that data, and again,
they need their communication systems to be really fast. And they take that data at high frequency
and as fast as possible, and they crunch it through
an algorithm either themselves or someone else. And that will provide a power output. Power outputs can be based on the power curve
of the equipment, so that’s another piece of your requirement in your PPA, is you want
to get very detailed information on exactly what turbines they have running if it’s a
wind far or what sets of turbines. And same for
the solar panels. You’ll be needing to understand the maximum
potential of those units based on meteorological conditions. Now, if that seems like it’s a whole lot to
do and you don’t have the capacity staff-wise or the
ability to outsource, you can require that those
IPPs provide power forecasts themselves instead of just the weather data. Say, “Okay, I need you to give me – you,
Mr. IPP, your forecast of what you’re plant’s gonna be producing in the next ten minutes. And I want that updated every minute.” Or
however it is. But you want it specified for how that data
is going to be passed back to the central operator. Okay, moving on. Oh, one other piece before we leave there. Availability. So when you’ve got a power plant that’s made
up of many different wind turbines or many different solar panels, you’re
– it’s not as if the plant is available or not
available. You’re gonna have some planned maintenance
that’s gonna rotate through the equipment. And then there’s gonna be some unplanned outages. And you want to have
knowledge of the availability of those pieces of equipment. So again, that would be great if it could
be passed in high time resolution. Okay, moving
on to the next slide, ancillary services. We covered a whole bunch of them. Frequency
response we didn’t get into too much detail with respect to primary and secondary versus
inertial. But those are sort of time differentiated
frequency response requirements that help the grid. And we talked about voltage stability. Reserves we mentioned briefly. And I just want to say that there is those
spinning reserves, those sort of dynamic reserves,
and then there’s also the contingency type reserves, where this is in response to an
unexpected outage. And again, this is an ancillary
service for which you can either have some requirement on your system, or you can have
some market based incentivization scheme. I feel like with ancillary services generally
or grid services it’s either the carrot or the
stick. You either require it in your grid code or
your interconnection agreement or your PPA, or
you incentivize it by providing some revenue stream based on that service provision. So
there’s two ways to go about it. And as we evolve with more renewable energy
on the systems, I think we’re seeing more market
based mechanisms to bring those grid services onto a system. Black start capability, that’s another ancillary
service that doesn’t get mentioned a whole lot. But if there are blackouts and you need to
fire up a generating unit from scratch, you need
to have some source of power for the controls of that unit, some battery, some unit that
can basically start by itself. And that’s a service that should not be
neglected. Because
that’s gonna be the first way of getting your system back on. So with – if institutional
incentives are not adequate, then, again, PPA provisions could be what you need to
button up those services such that you keep your system stable and reliable. Moving on to the next slide. Just a quick depiction of which of these types
of ancillary services, wind and solar and batteries, can
provide. So they can basically provide all of
the ones that conventional generators can provide with respect to active power control,
which is in response to frequency deviations. And then the reactive power voltage
control. For mechanical inertia, which is the – again,
a frequency response and super short time frame, wind can actually provide
it even though it’s not a synchronously connected generator. It can provide it because it has kinetic energy
in its rotor. So in a cell there’s actual
movement that kinetic energy can be borrowed from to increase the output of a wind
turbine generator briefly to account for a frequency drop in the system. The wind turbine
itself sort of has to pay back that power if it borrows from it. But again, sometimes it’s
reverted to a synthetic inertia, that sort of thing, where the wind turbine is providing
that response. But it’s doing it through power electronics
coming off of the physical kinetic energy of its
machine. Okay, one more slide that, again, this is
part of the frequency response type angle. But automatic generation control is used to
provide a secondary frequency response. So what that means is as frequency moves,
it does it in response to various full load on the grid. And within that time frame, you want the system
operator to be able to tell which generator should sort of step up
or step down the response to this variability. So they do it through AGC, automatic generator
control, which means that they are sending set points to generators, to the IPPs,
to have the output get targeted to a certain set point. So we have a graph here that comes from Xcel
energy. So Tara’s company. She’s gonna be up here shortly. That shows that Xcel accommodates a whole
lot of wind on their system. And they do it through requiring AGC connections
to their wind park. And here we have this measure of ACE, which
is the area control error. It basically
means the difference between scheduled and actual interchange of power. But it’s
basically a measure of how closely you’re hitting your supply/demand balance. And when
the operator in the middle of the night here at 2:45 was seeing the ACE go high, that area
control error go high, he requested the wind park to basically ramp down – so the blue
line – come down off of the red line, which is that wind park’s potential based on wind. So the wind park came down using this AGC
system to remotely and automatically adjust their output and got that ACE under control
and then let the wind farm go back to their full potential there on the right side of
that graph. Okay, so wrapping up here – so the key
takeaway is non-synchronous generation will replace synchronous generation in time as
we get more renewables on the grid. And the good news is that grid support services
can be taken from those variable renewable generators. It’s helpful to require that at the inception
of the project, just like if you’re building a
house and it’s harder to go back and retrofit your electrical because you forgot you
needed a kitchen outlet next to the toaster. This is what you want to do in advance. Specify the requirements. It’ll be cheaper. It’ll be clearer. It’ll be easier for the parties to
kind of kick off the commercial operation to a smooth start. So the reliable, flexible power system operation
can be achieved, but it, again, very system dependent. There is no one size fits all. And you’ll need to consult with engineers,
obviously, to get all of these measures really tuned in. And that’s what I have. Okay. So I
think we’re gonna move right now to Tara Fowler from Xcel Energy to talk about Xcel’s
procurement of renewable energy.>>Tara: Great. Thank you, Barb. Good morning, everyone. As mentioned, my name is
Tara Fowler. And I am the manager of the renewable purchase
power team at Xcel Energy. Today I will discuss what the US utility renewable
procurement process and provide more in depth details as to what we
include within our purchase power agreements, or PPAs. First, a little bit about Xcel Energy. We currently have 3.5 million electricity
and two million natural gas customers in eight different states. As you can see from the pie charts, Xcel Energy
has a diverse energy mix. We are currently projected to have a 30 percent
reduction in carbon dioxide emissions by 2020, based on our 2005 levels. Xcel Energy has been the number one
utility wind provider in the US for 12 years. You can see here the amount of wind capacity
we have on our three largest operating companies, including the max hourly generation
per megawatt, the max hourly percentage of load that wind has served, and
the max daily percentage of daily load served. Hopefully from the numbers provided you can
see that we’ve been very successful at integrating a large percent
of wind onto our systems. Let’s jump right into
the renewable procurement process. For the operating [inaudible] of Xcel, this
process starts with a resource plan. The
primary resource plan components include a current power supply mix, sales and demand
forecast, projection of resource needs, proposed generation technologies to add, and a
competitive procurement process or self-build. All of these components are utilized in a
filing that is made with our regulatory bodies, the state public utilities commissions. The
main objective of the regulatory filing is to take into consideration public interest
as well as the commission’s rules. Those rules require that we maintain or improve
the adequacy and reliability of the utility services, that we keep customer bills and
utility rates as low as predictable, that we
minimize adverse socioeconomic effects and adverse effects upon the environment, that
we enhance the utility’s ability to respond to changes in financial, social, and
technological factors affecting its operation, and that we limit the risk of unforeseeable
adverse effects. Once the resource plan has been completed,
we file it with our state public utilities commission and enter into
a two-track or two-phase process. The first track or phase includes the resource
plan filing. This is a litigated process where
interveners can file a testimony in regards to the resource plan. The operating company
can then file a rebuttal. The PUC will hold hearings. And then the commission will issue
its final decision. Once the PUC has issued its final decision,
the operating company can move to track two or phase two. A request for proposal is issued to start
a competitive bidding process based on the commission’s initial decision. This competitive bidding process is where
developers or other generators can bid in their projects
to see if they are a best fit. The bids are
evaluated during a 120-day bid evaluation period. The initial screening is an economic
screening of those bids by the generators by technology based on a dollar per megawatt
hour localized cost. This includes the transmission, as well. Those bids that show the most economic value
are then advanced to computer modeling program. Within the program, we develop a least cost
and higher cost portfolios from those bids. We then come up with an estimate at the portfolio
costs under various sensitivities. We come up with a select preferred portfolio. And then we report to the
commission our end results. This entire process, phase one and phase two,
can take two years from start to finish. Once a final selection has been made, a purchase
power agreement will be negotiated with those developers that have been selected. A purchase power agreement, as Barbara
discussed, is a long-term agreement between the owner of the electric generating facility
or the seller and the wholesale energy purchase or the buyer. A PPA allows the facility
owner to secure a revenue stream from the project, which is necessary to finance that
project. Typically, PPAs address issues such as the
length of the agreement, the commissioning process, the purchase and sale of energy and
renewable energy attributes, price, curtailment, milestones and defaults, credit,
and insurance. Typically a product developer
will need an executed purchase power agreement to secure financing and will not begin
to develop the site until they have an agreement in place. Our model purchase power
agreement can be found online and is public. You can see the link to that agreement on
the bottom of this slide. Next I’ll discuss the different components
of the purchase power agreement that we use and how those components impact the buyer’s
and seller’s development timeline. Once a
PPA has been negotiated and executed, each party will be required to fulfill the
conditions precedents and commercial operations milestones outlined within the purchase
power agreement. The conditions precedent is an event that
is required before something else can occur. Using – these requirements impact both the
procurement and development timelines. I’ve provided some examples here, such as
the buyer must seek state regulatory approval within a certain amount of days. And if that state regulatory approval is rejected,
then that buyer must terminate within another set of
days. Otherwise they raise their right to
terminate the PPA. The seller will typically not begin to develop
the site until the buyer has received state commission approval and
the buyer has secured financing. As Barb mentioned, most purchase power agreements
are take or pay. Take or pay is a
type of contract where the company or buyer pays for the product that is produced,
whether or not it could’ve been taken or not. With that said, most PPAs recognize that
there will be times in either the purchaser, the transmission owner, the transmission
authority, may curtail the facility’s production of energy because of constraints on the
transmission system, emergencies, or other reasons. The parties must decide who will
bear the financial risks for losses that arise when this happens. Often, the purchaser or the
buyer will pay the seller for energy that the project would have produced as a result
of the purchaser’s ordered curtailment. That is the way that deals get done. The buyer guarantees income so that the independent
power producer or generator can get financing. Another piece of the purchase power
agreement is defining the compensable and non-compensable curtailments. Compensable
means curtailments that will be paid for, and non-compensable means those curtailments
that will not be paid for. Typically for a compensable curtailment, if
there are production tax credits or investment tax credits involved,
they will be paid for, as well. That again is to guarantee the project revenue
so that they can secure financing. Some
examples of non-compensable curtailments, meaning curtailments that will not be paid
for, would include an emergency, an action taken under the interconnection agreement,
a restriction or reduction of transmission service,
the seller’s failure to maintain full force and effect their permits to construct and
operate the facility, and the seller’s failure to
maintain automated generation control capability. Compensable curtailments essentially
would be covered under anything not listed as non-compensable. Again, that’s the way
that the deals get done. The buyer guarantees income so that the IPP
can get financing. The purpose of negotiating and executing a
purchase power agreement is to address the different risks that the buyer and the seller
may have. Here are a few examples of those
risks that the buyer and seller may take. For the buyer, there are market risks in place. There’s a wholesale price risk. That would mean that the buyer could have
purchased power from another source that would be cheaper
than what they’ve locked in for the purchase power price. There are forecast risks, where the buyer
may need to put in a forecast. And if that forecast is deviated from, there
may be penalties associated with that. There’s
also congestion risk, where there may not be enough load to serve at the point of delivery. There are reliability risks, where the costs
or expenses associated with the variability of
the intermittent resources, especially for wind or solar, that they may have to pay
penalties associated with that. There’s also regulatory risks, where the regulatory
body, such as the public utilities commission, could
determine after the fact that this is not something that they see as a valid project
anymore. Different types of seller risks include performance
risk, such as the equipment that they’ve purchased has failed or is underperforming. There’s also construction risks, where
they may miss their deadlines because their construction provider isn’t meeting their
deadlines. There could be transmission outages from where
the project is generating to the point of delivery. Then there’s also meteorological risks. Barb alluded to some of these, where maybe
there’s a low-wind year if it’s a wind resource or there’s cloud cover for solar,
making it so that you’re not able to produce your
goals. In the next few slides, I’ll discuss how some
of these risks are mitigated within the terms of the purchase power agreement. Sellers and purchases face risks associated
with the credit of the other party. Many purchasers require sellers to provide
some form of credit enhancement to cover expected damages
to the purchase if the project does not meet construction milestones or is not commercially
operational by the agreed upon date. This credit enhancement could take several
forms, including guarantees by credit-worthy affiliates, cash collateral, or escrow accounts,
irrevocable standby letters of credit, or performance bonds. The PPA will usually require that seller maintain
at the seller’s expense specific insurance policies, as well,
and name the purchaser as the additional insured. The buyer will also typically require the
seller to guarantee that the project will meet certain performance standards. Performance guarantees let the buyer plan
accordingly in developing new facilities or when trying to meet demand schedules, which
also encourages the seller to maintain adequate records. In circumstances where the output from the
supplier fails to meet the contractual energy demanded by the buyer, the seller is responsible
for attributing such costs. Maintenance
and operation of the generation project is the responsibility of the seller. That includes
regular inspection and repair to ensure prudent practices. Liquidated damages can and
will be applied if the seller fails to meet these circumstances. Typically the seller is also responsible for
installing and maintaining a meter to determine the quantity of output that will be sold. Under this circumstance, the seller must also
provide real time data at the request of the buyer, including atmospheric data relevant
to the type of technology used. These requirements in the purchase power agreement,
as you can see listed above, will help us, the buyer,
to ensure that we can integrate the wind or solar or whatever resource onto our system. As you can see, these are many of the things
that Barb discussed, such as the automated generation control, data collection, and
forecast of turbine availability. Some key takeaways. The renewable procurement of an investor owned
utility, an IOU, is a regulated process. Buyers must guarantee income so that the seller
can get financing. Again, that’s how deals get done. The purpose of negotiating and executing a
PPA is to address who takes what risks. Next, I will pass it on to Ilya so that he
can answer any questions or moderate any questions that you
may have.>>Ilya: Thank you, Tara and Barbara, for those
excellent presentations. We’ll now move
on to a question and answer session. So please, if you have any questions for the
panelists, submit them through the question box in the GoTo Meeting platform. First I’d
also like to mention that you can go to for additional
resources and webinars on other grid integration topics. We have a two-page facts sheet
that you can find there on power purchase agreements and other topics, as well. So our first question is for Barbara. Can wind turbines be retrofitted to provide
grid services? So for example, would it be costly to add
frequency ride-through capability to an old wind plant? And is this common?>>Barbara: So yeah. They can be requested to provide those services
retroactively. Really, most of these – they’re power electronics. And in fact, it’s a question of, in a lot
of cases, software or maybe firmware and not
even hardware. I guess it depends on how old
the system is. But in recent years both solar and wind have
capabilities that are – they need to sort of be modified and set up through
control and algorithms, but it’s not hard physically. Wind is a little bit harder than solar. There are packages, though, on turbines. If you go to
GE, buy off the shelf turbine, you can upgrade to get theses packages. So if you want to
do it retroactively, it’s just a question of negotiating that price with the turbine
manufacturer. And is it common? I don’t think it is very common actually. As systems get
more and more renewable energy on their – in their portfolio, they can rely on those
services from the existing thermal units. Or as they get new ones they can request the
new ones to provide the services. So I
haven’t seen much where they have to go back and say, “Okay. Go ahead and install
that.” And then that certainly would be a question
of who pays?>>Ilya: Thanks. And the follow-up question to that is for
Tara, actually. And that’s about
how easy is it or difficult is it to renegotiate a PPA to include requirements for grid
services that weren’t in the original agreement? And do you have any strategies to support
those kinds of negotiations?>>Tara: Sure. So it’s actually typically very difficult
for us to renegotiate a PPA. For us
it’s a very regulated process. And so either the model PPA itself has been
approved by the public utilities commission or once it’s negotiated
we have to take it to the commission and have it approved. It depends on which state we’re operating
in. So if we want to open up the purchase power
agreement to renegotiate terms, we end up having to go through the entire regulated
process again. Now, we can do things such as
amendments and make additional filings for those if it’s not something that’s a material
change. But if it becomes a material change, then
it becomes a much longer process. I
will say that’s happened in the past. And typically what happens is we need to figure
out who’s gonna have to pay for what costs. And typically we’ll – it brings both parties
to the table. And we’ll figure out, okay,
well, if we’re gonna bear these costs, what are we gonna get in return? And vice versa?>>Barbara: I – if I can add to that, Tara,
I imagine it’s also a problem for the IPP with
respect to whoever’s holding their debt. The investment bank who owns part of that
project, at least in the first ten years if you’re in the US and you’re trying to monetize
a PTC, they have a seat at that table, too. And just like your bank, if you don’t own
your house outright, your bank sort of has a seat
at the table if you’re undergoing some big changes. So it just gets complicated with respect to
the number of parties involved and that renegotiation.>>Tara: That’s absolutely right. And that’s actually a challenge that we face
within the negotiation of the purchase power agreement
itself. So you come to a table to negotiate. And we consistently have to rely on our public
utilities commission and what they’re gonna allow. And then the IPP or developer has to rely
on what their financier or the tax equity partner will allow them to do, as well. So we have to figure out – the buyer and
the seller have to figure out what both of their
interested parties are going to allow and come to an agreement based on that, not just
what they want, as well.>>Ilya: Than you. So we have many great questions coming in
from the audience. And
this next follow-up question is for Tara. It’s about the main considerations that you
look for when awarding bids for a PPA. Is price the main consideration, or are there
other criteria, as well?>>Tara: Price is definitely king. Our responsibility is to get the least cost
projects for our customers because we pass those costs onto
them. And we don’t want their electricity
bills to raise [inaudible] that as can hold as much as we can. With that said, we have to
have a reliable counter party. So we need someone that we can do our due
diligence on and understand that, okay, they’re gonna be
able to get financing once they have a purchase power agreement. Or they’re gonna be able to get the turbines
they need or the solar panels they need within the time required
to get the project built. Because the hardest part is having to go back
after the fact if a project fails and negotiate with another counter party. And then you’re out one, two, potentially
three years. So price
is definitely king. But the counterparty and the reliability that
they can provide is definitely second.>>Barbara: I can comment on that also ’cause
I do some projects in the Caribbean. And
it’s amazing how many bidders come in and throw in a price that is low, and they don’t
account for the difficulty of getting the equipment to some of these islands, that whole
supply chain of shipping in panels or shipping in turbines. This sort of thing is more
difficult than a lot of them reckon. And the utility of course are obligated to
the PUC and their customer base to go with the low bid. And then they get hung up because they can’t
get the project built. Or it’s so low that
they’re not able to get it financed. And like Tara said, it sets you back a year,
two years, three years. So my advice is to go with the best value. And maybe go through a pre-
qualification type requirement for bidders to make sure that they are being realistic,
that they have experience, that they can really
see that project through to fruition. Time is money, and if you set back by a year
or two and have to renegotiate it again with a different part, it just – it doesn’t benefit
anyone.>>Tara: Yeah. And I would continue to add to that. We do have a pretty extensive due
diligence process for those exact reasons. So when we go through a request for proposal
and our bids come in, before we even look at price we have all of our different subject
matter experts digging through those bids, making sure – are they gonna be able to
get their interconnection agreement in time? Are they gonna be able to interconnect to
our system? Have they got the right transmission costs
within their bid? Because especially working
with regional transmission operators, RTOs, there are some times where they have to go
through another transmission provider to get to the ISO or the RTO themselves. And they
don’t realize that. So we try and do a lot of that due diligence
ahead and ask a lot of questions to make sure what they’re – what
they’ve put in their bid is realistic and is
manageable.>>Ilya: Great. So this next question is again for Tara. It’s about Xcel’s model PPA and
whether you’ve found that having a model PPA has actually reduced the cost of obtaining
a PPA with a seller.>>Tara: It has been. And we should actually have a revised version
that will be out here within the next couple of months, which will
reflect some of the changes we’ve made over the last three, four, five years. We – when we go through and update our model,
we’re very cognizant of what it takes for the seller to get financing and to get tax
equity. And we also take into consideration what risks
we’re willing to take and what risks we’re not willing to take. Because if – we don’t want to put our customers
at any sort of risk. So by putting that into a model and saying,
“Here’s the starting point,” and we’ve already run to ground most of the things that they’re
gonna need as well as what we need, it makes the negotiation process a lot shorter. It makes us both come to the table, and it
shows that we recognize what their needs and wants are. And it gives them an
opportunity to see what our needs and wants are. So it makes it a much smoother process. I’ve heard that a lot of other companies use
our model PPA. And they will occasionally
call and ask questions about the PPA itself. Because they’re gonna use that same model
in their negotiations, as well, and maybe make
a few changes to reflect what they need.>>Barbara: And it’s also provides apples to
apples. You need to make sure that the
developers are bidding to the PPA so that when you compare the prices across, you know
what you’re getting.>>Tara: That’s absolutely right. And when we do our request for proposals,
we’ll allow them to make exceptions. And that’s part of our due diligence process. We’ll go through
those exceptions. And if they’ve done something like they’ve
said they would like to reduce the security, well, that’s a non-starter
for us. So we can reach out to them and say,
“Hey, we noticed that you can’t pay this security level or you don’t want to. This is something that’s required by our risk
department. We don’t have a choice. Do you
need to reassess your bid? Do you need to change the price of it? Or are you still willing
to participate in this process?”>>Ilya: Great. Thank you. So we have several questions coming in about
the impacts of wind on Xcel Energy’s grid and also on the
prices for consumers. So I think the next
question will be about the price impact that you’ve seen in Xcel Energy’s territory. How
have rates increased or decreased or stayed neutral over the last several years as wind
has increased?>>Tara: I’m not necessarily sure I’m the most
qualified person to answer that question, but I want to make sure I understand it. So is the question has the cost of wind itself
decreased? Or the cost of wind once you consider congestion
or curtailment?>>Ilya: So I think the question is referring
to the cost for consumers of – in Xcel Energy’s territory. So electricity rates for end use consumers.>>Tara: Sure. Okay, actually, I think I can answer that
question. So one of the big
initiatives that Xcel Energy has right now is called filled for fuel. And this initiative
started with clean power plan. But we actually, even with that being dismantled,
are – we want to be a very green company. And we’re very responsible when it comes to
– or I think our – it’s responsibility by nature
and nature by responsibility, something along those lines. But that’s definitely one of our key drivers
for our company. So what we’ve started to do
is as we’ve been decommissioning our coal plants, we’ve been saying we want to replace
that with low-cost renewables. So a utility earns money by putting projects
into rate base. So as we remove coal from our rate base that
we would otherwise have to put scrubbers on or have to put additional equipment in
to clean it up or to keep them running or prolong their life – because some of them
are coming up to retirement age – what we’ve been doing is replacing that with wind and
solar. Solar is a non-peak resource. It’s gotten much cheaper. It still doesn’t beat coal or natural
gas. But because it’s during peak hours it’s starting
to become more price competitive, especially with the capacity factors that
are involved. And then wind, especially within
the eight states we’re in, we’re definitely in a strong wind penetrated area, the wind
is cheap. And it’s coming in. It’s beating natural gas prices. So as we’re removing coal from our rate base
and putting wind and solar in, we’re lowering the cost for our customers.>>Ilya: Great. Thank you for that answer. So we’ve got time for a couple of more
questions. This next question is for Barbara and possibly
for Tara, as well, based on your experience. Are PPAs that require ancillary services more
expensive in general than those that do not?>>Barbara: Yeah. I think that with all else being equal if
you require extra services, then you’re gonna pay – like the example I gave
before with respect to the package – the add-
on package that GE provides for some of these controls. It’s just like when you buy a car
and you get the leather seat option. It’s a bit of an upgrade. Certainly a lot cheaper to do it
from the get-go. But if you require it – and again, model
PPA or at least a specified requirement on the front end, you get apples
to apples. Then the developers can bid that in, that
sort of extra feature into their price. And it won’t
be much more. It’s – they’re very cheap. Again, the power electronics components are
very cheap relative to any sort of mechanical providers of those services.>>Ilya: Thank you. So this last question is for Tara. And it’s about the risks of natural
calamities. So suppose a wind turbine is broken during
a storm. So who takes the
responsibility for that damage? Is it the seller or the buyer?>>Tara: That’s a really good question. So for natural calamities, we list that as
a force measure within our purchase power agreement. So what that essentially will do will allow
the developer to fix the project without it impacting their committed energy requirements. With that said, they also – so we take that
risk because we’re not getting the energy that
we’re relying on. However, in a force measure event, the developer
doesn’t get paid for what could’ve been produced because there’s nothing that they
can produce. The turbine’s on the ground or
blown away. So it’s a shared risk between both parties,
but it’s one that doesn’t have any sort of damages associated with it.>>Ilya: Great, thank you. So we do actually have time for a few more
questions. And
we’ve gotten a lot of questions about wind, but we also have some questions about solar. And the next question is again for Tara. Does Xcel Energy have a model PPA for solar? And does it require any grid support services
from its solar energy plants?>>Tara: That’s a really good question. We do have a solar energy purchase agreement. The model agreement that’s online is almost
essentially the same. The only things that
change are rather than wind, it’s solar, the different type of equipment that we require. We do require grid services. And honestly, I think from a solar perspective
it’s probably a little bit easier. You don’t – you have the – you have intermittency,
but it’s a little easier to control for us right now because we don’t have the same penetration
of solar on our system that we do for wind. So I guess I should caveat that with it seems
easier now, but as we add more and more solar, we may have to tighten our
restrictions and require more good services within our projects. But as of right now, it’s fairly basic. And the agreements are nearly
the same.>>Ilya: Great, thank you. So the next question, again, it’s for Tara
but also for Barbara based on your experience. For both wind and solar PPAs, do you find
that it’s better to have a long-term PPA or to also allow in parallel
or following a short-term PPA for wind and solar plants to participate in an open
wholesale market?>>Barbara: Again, from my experience, in order
to minimize the finance cost, it makes more sense to have a long-term PPA. There are certain – I see certain deals
that happen or consecrate example, where IPPs go – what
I call going merchant, where they’re just playing the market. Or they do kind of a stringer contract, where
they might have a ten- year obligation. And then they can fly free with respect to
the wholesale market. Another creative way to structure a contract
is to do some portion of the generation as a
fixed rate PPA and then allow the IPP to either take the risk of the rest of the balance of
the generation on the wholesale market or let the utility buy. So there’s lots of ways to
kind of collar that price risk. But I think in terms of minimizing finance,
again, long-term PPA makes more sense.>>Tara: And I would second that. Most of our developers, the longer the purchase
power agreement they can get, the better for them. Especially production tax credits those first
ten years are key. And then they want to continue to be a viable
project. And our PPAs
are all done at a fixed price rather than a variable cost or an LMP, a locational marginal
price. So they can guarantee those revenue streams,
which I think makes it much easier for financing. Now we’ve got – we’ve seen in the industry
a lot of CNI customers who want to do ten to
15 year purchase power agreements to purchase from the developer. And I think the
developers are starting to kind of recognize that if they want that type of business that
they’re gonna have to do the shorter timelines. But I definitely think their preference
would be to do something along the lines of with the utility where they have that 20 to
30 year guarantee.>>Ilya: Great, thank you. That’s really helpful information. This next question is a quick
question for Tara. Do you – does Xcel require AGC on all its
new wind plants? And do
you find that this is a requirement on new contracts?>>Tara: Yep. So we do require AGC on all of our new contracts. And we’ve found
ourselves in a position more than once where we’re operating in MISO or SPP, and
they’ve gone back and required us to get AGC on projects that previously were not
required to. So some of our original purchase power agreements
that wasn’t a requirement that was in place. And now the RTOs and ISOs that we’re operating
in are now requiring it. So we’re – that’s – kind of goes back
to one of the original questions, where we actually
had to go back and ask that. And everybody has to come to the table and
figure out who’s gonna bear what cost and how can we make it
fair for everybody. But yep, going forward
all of ours have AGC protocols. They also have requirements for data collection. So for example, for solar we require that
they provide different sorts of meteorological information, such as the solar insulation
or the solar intensity, the temperature, the inverter availability in their generation. That way we can forecast based on that. And then
for wind we also include wind speed, wind direction, and the barometric question.>>Barbara: So Tara, this is Barbara. If I can ask you a question. Now, when you’re
running a plant on AGC and you’re pulling it down – so you’re – say you’re load
following, and you need to decrease. Are you paying – are you calculating the
park potential and paying them for what they could
have produced?>>Tara: Yes, that’s exactly right. Unless it’s one of the non-compensable curtailments
I discussed. So unless it’s for an emergency or reliability
or the transmission authority requiring us to do it, essentially any other
reason that we’re backing down, such as congestion or any sort of economic curtailment,
the difference between the park potential and that AGC set point is what we calculate
as the – a compensable curtailment. And
then I – so I mentioned it very quickly. But if the project has production tax credits
in place, so for the first ten years, not only
do we pay the amount for the energy, but we also
pay for the production tax credit – I cannot say that, I apologize – the production tax
credit that they would’ve received, as well.>>Barbara: On a gross up basis, I presume,
for anybody who wants to get in the weeds.>>Tara: Yeah. Thank you for that.>>Barbara: Yeah. Not just the value of the credit would be
grossed up for the income that they would’ve had to have netted the credit
against. So.>>Tara: Yep, that’s exactly right.>>Ilya: So our next question – and this
might be the last question – is for both Barbara
and Tara. It’s about requirements for different – systems
of different sizes. Sorry. So we
know that Xcel Energy has a very large amount of wind power, 17 percent I think for the
year last year. What about systems that are just beginning
and that are just starting out? Is
it necessary for PPAs in a new industry to require grid services?>>Barbara: No. I don’t think it is. If you’ve got some smaller CT, some flexible
– whatever they are – flexible generators
on your system, it might behoove you to rely on
those traditional generators to provide the grid services. Having said that, it’s really cheap
for the wind and solar to have the capability. So a lot of times you go and put the
requirement that they have the capability, but you don’t sort of turn it on until down
the road when your system has higher penetration
of variable renewables and you need potentially to call on those services. What do you think, Tara?>>Tara: Yeah. I’ve always worked with a very large utility. So for – our big thing has
definitely been integration and how do we add this much wind penetration to our system
and followed by solar. So it’s definitely extremely important for
us. In a smaller system, I
agree. I can’t imagine that the same services would
be required. With that said, as things
evolve, it could eventually be a requirement. So the same thing for our organized
markets, where previously it wasn’t a requirement, they’re asking us to go back to projects
the size one megawatt, five megawatts, and ask them to start providing these services. So I think it may not be required right away,
but as the market matures it’s something that the organized markets will start to require. And like you said, I think it’s very cheap
for these things to be added. I think a lot of it’s part of the standard
package, at least in the US now. Because so many people do require it that
I think that it – the additional costs for that – the incremental cost is gonna
be very minimum.>>Barbara: Yeah. And take as an example forecasting data, the
meteorological data or the provision of that data. Even if you as a utility aren’t gonna use
it for a while because – for example, I have one project I’m working
on where the country is going through blackouts continually. They don’t have enough power on their system. So they’re not
trying to optimize their spinning reserves. They have no reserves. Everything they have is
running flat out. But still if they’re setting up a new wind
or solar, it makes sense to go ahead and request the data – the meteorological data that
we’re talking about, even though they’re not gonna
be really utilizing that data until they get kind of a beefier system and a better
supply/demand balance. But it’s easier to put the requirements in
place now contractually than to have your counterparty extract money
from you when you request it down the road.>>Ilya: Great. Thank you. I think this was an excellent conversation. Thank you to all the
participants for your excellent questions. We – there were way more questions than
we were able to cover in the time that we have. If you do have questions that you’d like
Barbara or Tara to answer, please feel free to e-mail them. Their contact information is
posted on the slide that you see now. And we’ll work together to answer your questions. Also, I’d like to encourage you to visit
for more materials and for additional webinars and for upcoming
webinars on grid integration issues. Thank
you all for joining.>>Female: Great, thank you again. And on behalf of our Clean Energy Solutions
Center, I’d like to extend a thank you to all of our
expert panelists and to our attendees for participating in today’s webinar. We very much appreciate your time and hope
in return that there were some valuable insights that
you can take back to your ministries, departments, or organizations. We also invite you to inform your colleagues
and those in your networks about Solutions Center resources
and services, including no-cost policy support through our ask an expert service. I invite you to check the Solutions Center
website if you would like to view the slides and
listen to the recording of today’s presentation, as well as previous held webinars. Additionally, information on upcoming [inaudible]
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