What’s driving America’s uneven battery energy storage boom (Modo Energy)

America is in one market. It's many. That's true for politics. It is true for culture, and it is extremely true for power. Texas plays one game. California plays another.

The Northeast and Midwest play by a different rule book entirely. And that patchwork is the heart of today's story. In many ways, battery energy storage is supposed to be the bridge. It can shift energy across time, storing excess power and feeding it back when demand spikes.

But in the US, a battery in Texas often behaves nothing like a battery in California or New York. It's the same hardware, but with different economics. The same physics with different incentives. Today, I am joined by my colleagues at Motor Energy, Peter Barrini and Brand Vermillion, as we try to map the fragmented reality of America's battery boom.

In deregulated Texas, the market is wild and fast. Anyone can build. You get rewarded for having quick reactions, for being able to respond when prices change, or when the grid needs power fast.

When things get volatile and while price swings happen, there's a lot of money to be made, but there are no safety nets. You live with constant risk. If the weather is mild and power prices are steady, your battery won't make a lot of money. In California, it's the opposite. Policy and regulations set the pace. You get paid for being reliable, for showing up during that predictable evening peak when solar fades.

Four hour batteries are standard there compared with one or two hour systems in Texas. And then there's the Northeast, PJM, New York, New England, where bureaucracy meets ambition.

You can make money through capacity markets. Systems that pay you just for being available when the grid is stressed. But getting connected can take years. On top, federal policy adds to the noise.

First came the Inflation Reduction Act or IRA, hundreds of billions of dollars in tax credits for clean energy projects. Then came a round of reactionary policies, Trump's tariffs, stricter equipment sourcing rules, new paperwork.

Each political swing sends developers back to their spreadsheets, repricing risk. But policy comes and goes. Cost curves do not.

Batteries keep getting cheaper, smarter, more durable. In a free market, economics speak louder than Washington. Still, it's not smooth sailing. The grid interconnection queue, that long waiting list for new projects, is clogged everywhere.

Hundreds of gigawatts are supposedly in development, but actually a fraction of those projects will get built. Contracts are evolving to manage this chaos. One project might be hedged for safety. Another project might be left unrestricted.

This is in order for the project to chase its upside. And through it all, the uncomfortable truth holds. We still rely on thermal generation. Gas plants fill the gaps that batteries can't yet.

The future is arriving, but it is arriving at different paces in different states. And that's what this conversation is really about. How one technology, battery energy storage, is being shaped by and reshaping dozens of different systems. Let's jump in.

Brand and Pete, thank you for joining me today. It's great to have both of you here. Before we dive in, could you each introduce yourselves?

My name is Peter Barrini. I'm the director of industry here for the US at Moto Energy. I come from a power market modeling background. So I've been in the industry for about fifteen years.

Been at a range of management consultancies, leading and driving power market, price forecasting and commercial due diligence.

Okay. Thank you. And you, Brent?

Yeah. Hey. Thanks for having me on today. My name's Brent Vermillion. I'm our US research lead here at Moto Energy.

So I've been with Moto for about two years now kinda building out our research function, really just understanding all things, grid scale storage investment case, whether it comes to maximizing how batteries are operating in the market today or understanding how things are gonna evolve in the long term when it comes to what's gonna make for a sound or not so sound investment when it pertains to a grid scale energy storage system anywhere across the US. I spent a few years actually working at ERCOT, the ISO. I worked in the control room for a couple of years as a support engineer and then did some more work as an analysis engineer supporting protocol revision requests and policy changes and things like that.

And to start looking across the US, what have been the biggest trends or shifts in storage and renewables this quarter?

I'll start here, and then I can let Brent chime in. I think one of the the largest things we're seeing at at a macro level is really a shift between the maturing markets and the, I guess, nascent or emerging markets.

In more of the maturing markets across the United States and particularly, you know, that's California and Texas, you know, said another way, CAISO and ERCOT. And really in that those maturing markets, you're seeing this shift towards heavier reliance on energy ARB.

So pretty much that saturation of ancillary service markets that that are kind of flush on on requirements. And then on the flip side, you have markets like New York, PJM, MISO, and SPP to a lesser extent that are really at the beginning of their battery energy storage story or transition. And in those markets, it's less driven by pure economics and more being driven by policy incentives.

Yeah, right. I mean, I think in those emerging markets, it's been a story of how do we tackle some of the issues with the interconnection queue. I think that have been a key factor here in the last few years along with historically what wasn't as obvious when it came to the investment case for grid scale storage. Right?

So, you know, whether it's, you know, as we'll get into with PJM's capacity market prices rising in the last couple of years or the development of some of those incentive style programs that have come to play in places like New York or or parts of PJM. That that's gonna be a big big piece of the the puzzle going forward for batteries expanding outside of those, as you said, more mature markets. And I think within those more mature markets, yeah, it's a story of really not even just this quarter, but the last twelve, eighteen months, especially on the merchant side. So those ancillary services and the energy arbitrage revenues, just a lower revenue story in in general.

So both in California and Texas, we've seen, you know, storage resources really come in and minimize a lot of the volatility in those markets. Some of that's also combined with just how the weather's played out the last couple of years too. But, yeah, the storage resources themselves have have played a major role in in limiting some of that some of that volatility and, therefore, some of their own revenue opportunities.

You know, I think what goes hand in hand in that, you know, I think there's certainly a level of anxiousness in the market for for existing players.

I think as as Brent was alluding to, part of that is driven by reduced revenues that we've been observing across CAISO and and ERCOT primarily. And then the second fact there is just the updates or or, I guess, directions from a federal policy perspective.

Both of those are compounding uniquely within each market where ERCOT, for example, traditionally one that's driven by merchant revenue opportunities, are really trending more towards, contracted assets, specifically for for new greenfield.

Okay. That's very interesting. We're definitely going to touch upon all the different points that you mentioned right now.

But just to bring an general overview from the federal policy side, what has actually happened, this last quarter, and how is it impacting the the pace of renewable and battery build out? Let's start with the short term, what your view is on that, and then on the medium term.

Well, I guess let's summarize, I guess, a little bit just what's been going on from a federal policy level. So in the last presidential administration, there was the passage of the Inflation Reduction Act, which really opened up the pathway to receiving investment tax credits or production tax credits for different technology types across really all of energy. And that's primarily translated into, I guess, really starting to accelerate the deployment of solar and storage here in the last couple of years or, you know, I guess, helped to continue accelerating it. I think it was already well on its way even before the IRA.

But yeah. And then I think going into, you know, the new presidential administration that we had this year, that's changed a little bit with the passage of the recent federal tax bill this past summer, the OPBBA, which kinda changed the game a little bit for who's able to qualify for tax credits and when, essentially. And that'll depend on whether it's a wind resource, a solar resource, an energy storage resource, or even other technology types too. Right?

So, yeah, I think that just kinda starts to set the scene a little bit. And that has some amount of impact on what we're gonna be seeing here in the next couple years, But, also, some of the the impacts when it comes to deployment of these different technology types are still gonna be regionally dependent. Some of it's already gonna be far enough along that the next twelve, eighteen months aren't quite as impacted as maybe the two or three year timeline.

But, yeah, I think, Pete, do you want to kind of get into maybe some of the specific changes regarding what tax credits are available, who they're available to, and on what timeline?

So I think as as Brian alluded to, really, it's the production tax credit. You know, you're getting a dollar per kw hour of generation.

Historically, that's been most utilized by wind resources. Then you have the investment tax credit. Right? So that's really anywhere from ten percent to fifty percent of a tax credit on your your capital outlay.

And so the two of those, as Brand alluded to, has really helped fuel deployment for the last almost decade and a half. Right? So the the IRA provided certainty for a long much longer tenor than has been passed previously in legislation. And, you know, the industry applauded that because giving certainty for those types of structures is important.

But what we're seeing now is kind of the clawback of those really. So starting in twenty twenty eight, those PTC and ITC credits are no longer going to be available for wind and solar resources primarily. And so in that really short term, you know, what we're seeing on the ground and what's coming out of our capacity expansion modeling is really a pull forward of a lot of those those renewable builds. Now that doesn't mean to say they're all gonna come online before the end of that deadline.

I think a strategy that we've seen play in past around expiration of tax credits has been strategies around safe harboring.

And, you know, treasury, IRS has updated the guidance around really what that means.

But we do still see strong renewable deployment through, let's call it, the end of this decade as projects come online in time for the ITC and or safe harbored or positioned well enough to to have them on deployment, near the end of the decade.

PG has mentioned the potential impact on the short term. What is your view on the midterm impact of these recent federal policies in build out?

So in the medium and long term, the removal of some of the federal policies, primarily the PTC and ITC, we see as having an outsized impact on on wind development, particularly. Part of the rationale for that is really just the fact that you're not seeing the year over year CapEx declines in a more the more mature technology that's been around for several decades versus solar and storage, which are a relatively new phenomena for for power markets.

And that's been reflected in, like, how development has gone in the last few years too. Right? Where really the deployment of wind as a resource across most of the US has has really slowed down in the last five years or so compared to what it was in the late two thousands, early twenty tens, and that's been kinda counteracted by having all the solar and storage really take off here into as we get into the twenty twenties. Right?

Yep. No. Exactly. I think that and then maybe even a smaller pressure there has just been, you know, all the best land for wind has been taken.

Yeah. And as we all know and have seen, you know, building large new transmission lines is a difficult, long process. And so I think to that point, we do see a big impact in the long term deployment of wind, particularly across ERCOT, where solar, the most part gets pulled forward through the end of this decade and then starts to reemerge as we get in about the two thousand and thirty fives, two thousand and forty's when we see that CapEx decline come back in. And really what fills the gap for a lot of this, and again, it's depending what market you're in, is is battery storage.

So we are seeing, you know, irrespective of the repeal of the investment tax credit, that battery energy storage continues to pencil, continues to make attractive IRRs and is an integral part of the the grid moving forward.

And a a lot of that, I think, is just all dependent on cost curves continuing to come down regardless of what happens from a policy perspective. So even if and then we can I guess, maybe a good way to frame this would be to talk a little bit about some of the other aspects of the one big beautiful bill act to being some of the subset provisions being essentially for storage resources? So they didn't have their tax credit timeline sunsetted the same way that solar and wind resources did where all for all solar and wind resources, no exceptions, they're not gonna be able to qualify for any type of tax credit after the first of January twenty twenty eight.

For battery energy storage, in theory, they could still qualify for those tax credits all the way into the twenty thirties. I think it's twenty thirty two or twenty thirty three that their eligibility starts to sunset. However, there is a provision in the bill that says that to qualify after a certain period of time here in the next couple of years, they're going to have have to have an increasing proportion of their total capital costs come from basically these non foreign entities of concern. Anybody that's not on a subset of countries that has been deter deemed deemed ineligible by the US government.

So really, that subset is China, North Korea, Iran, and Russia. So for battery energy storage developers, that primarily is just coming from China in terms of where they're sourcing different components of their overall project cost. So effectively, as time goes on, an increase in proportion of talk project costs have to come from somewhere outside of China to be able to continue to qualify for that investment tax credit. So what that means is, you know, developers are going to have a bit of a trade off that they have to evaluate here in the next couple of years as that change starts to go into effect.

They essentially need to be able to say, alright. Is it still going to be worth procuring a certain amount of our project costs from China to mean that our overall project cost is lower, but we were potentially foregoing eligibility for that tax credit here in the next few years?

Or are we gonna be willing to take a, you know, higher initial outlay on project costs to that and still to be able to secure that investment tax credit? So that's a trade off that people are gonna be asking questions about. But, you know, I think the thing that we've been hearing in the industry is that a lot of the Chinese developers and manufacturers of the actual physical equipment, the energy storage systems themselves, whether it's cells or actual packs, are ultimately taking a lot of the heat of effectively the price difference here. And they're saying that we actually have the pricing power. We have the margin one way or another to bring the prices that we're able to sell to developers at down to a point that is competitive with, I guess, that difference in the investment tax credit for a domestic manufacturer versus a Chinese manufacturer.

Plus the tariffs.

Yeah, that's kind of the unknown component too is how do you balance both because at this point we don't really know how that's going to end up playing into procurement because I mean, think as of last week, there aren't any tariffs for the next week, right, or for the next year, I should say.

So that's a bit of a moving target. But I guess just if we kind of bring it all full circle and put some numbers on it. So if you're thinking about you know, your domestic manufacturer that you're potentially procuring yourselves and your packs from, that secures you that thirty percent investment tax credit. Essentially, if the Chinese manufacturer is able to beat that price by a little bit more than thirty percent, I think the number we have for it is around forty three percent is the way it shakes out.

So if your capital costs outlay from a Chinese manufacturer is forty three percent lower than the domestic manufacturer, then it's actually worth foregoing that investment tax credit. And now I know that's a little bit in the weeds on the numbers, but essentially that's kind of the that decision boundary that developers are gonna be looking at. And it from what it sounds like is that's kind of that sweet spot that a lot of the Chinese manufacturers are trying to establish and say, you know, we can actually deliver at that price point so that it's still worth it for you guys to procure from us rather than, you know, trying to find the workaround to still qualify for that investment tax credit.

You know, over the next few years, that's gonna be the thing that's interesting to watch. And, you know, it could end up actually having negative effect negative downward pressure on actual costs for for storage systems here in the next few years too. So it'll be interesting to watch.

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Enjoy the conversation.

We have been talking now about federal policy, jumping back to what we're seeing in the markets. And and with that, looking into durations of batteries, what are the trends of durations that we're seeing in different markets, And what is driving the difference in different durations for each market?

Yeah. So I think this is one where it very much depends region to region. I think there's different market constructs that incentivize different durations depending on what part of the country you're in. I think if we go back to that idea of maybe more mature markets versus more nascent markets, thinking about, you know, comparing ERCOT and CAISO first as those more mature markets.

You know, historically, in in CAISO, we've seen almost exclusively four hour duration batteries come into play because to actually be able to qualify for the resource adequacy contracts, which is their version of a capacity market, you you need to have that duration for your battery. So that's kind of been a nonstarter from the beginning for batteries there, which has meant that that's been the state of play for really the last five years since batteries became more and more prevalent in California. On the flip side, in ERCOT, what you had was there was no capacity market. So the duration of a battery was just, okay.

Well, how do we best capture returns in the merchant market? So energy and ancillary services. Now a few years ago when batteries are really just starting to come into play, they're primarily participating in just the ancillary service markets. So in ERCOT, especially a few years ago when there weren't quite as many rules established, you were effectively able to earn almost exactly the same returns in ancillary services, whether you are a one hour resource or a two hour resource or a four hour resource in ERCOT.

So essentially, what you you saw is that there wasn't really much to gain by paying that additional amount of CapEx to add that second hour, that four those third and fourth hours of of duration for a battery in in ERCOT. So historically, we mostly saw one hour duration resources. But now that's starting to change here. As Pete mentioned earlier, we've seen that market start to mature.

More batteries have been built. The amount of ancillary services procured are relatively fixed. That's led to what we call saturation of those ancillary service markets. Revenues earned by batteries in the ancillary services have gone down.

They've had to move more so into trying to earn money by buying energy cheaply and then selling energy at a more expensive price during those evening solar ramp hours typically. And we call that energy arbitrage, but what that has meant is, you know, it's you're going to be able to earn more from energy arbitrage by having that additional energy capacity in your battery. You're gonna be able to capture, if the evening peak in prices extends for two or three or even four hours like we've started to see happen a little bit more often in ERCOT, you're going be able to capture that. Or if prices peak in the day ahead market at one time and then the real time market at another time, again, you're going to have the flexibility to capture that.

And so I think just to summarize that, you know, what we've seen in in revenue trends is the ratio of revenue between two hour and one hour resources went from being roughly equivalent a few years ago to here in twenty twenty five, ranging between that fifty percent to eighty percent premium for those two hour duration resources. So ultimately, that's been in in that, you know, merchant only market that that Texas is pushing developers toward those longer duration resources. And I think, you know, one thing we're expecting here is even though we don't actually have much in the way of four hour duration resources yet in ERCOT, I think we're we're expecting here over the next few years to see that become a more and more common thing as developers either augmenting short their shorter duration resources to two or especially even that four hour duration and for newer batteries to be coming in just from the jump with those longer durations.

So I think in the more mature markets, that's definitely what we've seen. In the more nascent markets, I think it's really all, in a lot of cases, driven by either those incentive programs or the capacity markets. And both of those things tend to be designed in such a way that really incentivizes the longer duration resources, whether that's because of in the capacity markets in a place like PJM, you have the way you're accredited to qualify to receive an award of a certain amount in those markets is to have a longer duration battery. Your four hour duration battery has a higher accredited percentage of its installed capacity, typically called effective load carrying capability, to receive a higher proportion of its capacity as a capacity award in those markets.

So, you know, essentially, they can earn more by having those longer duration resources in those markets from the capacity market where that's gonna be a huge part of their revenue stack in in a market like PJM or or MISO or, SPP. But I think even in those other markets like in New York ISO where you actually have, like, an incentive design program too, that's that's specifically targeting those longer duration resources as well.

And just to go back to basics and not lose anyone in the audience, what exactly is a capacity market? What is the objective of that market? And why does it exist?

I think at the end of the day, power markets tend to be constructed one of two ways that that we've seen across most of the developed world.

It's either you are incentivizing new resources by being a price only market, and we see that in regions like Australia. We see it in, you know, Alberta, some regions of Canada. We see it in Texas, and in some power markets in South America as well.

Taking a step back, whether your price or capacity kinda constructed market, the incentive you're trying to create is for new assets to be built.

So in a price only market If they're needed.

Exactly, if they're needed. So in a price only market, you're trying to provide those signals through high pricing or like scarcity pricing events. In markets like California, New York, etcetera, you're incentivizing new resources to meet generally what they call like a planning reserve margin. And so for a utility, a balancing authority, an ISO, the way in which they'll cover themselves to make sure that the lights stay on is they're gonna procure their peak demand plus a little planning reserve margin.

So let's say my peak demand is one hundred gigawatts in September in PJM, I'm gonna procure a hundred and sixteen gigawatts that'll be available online. And that's why I create this like buffer of reliability in case a plant goes out, something trips, something unexpected occurs. And so these constructs are really put in place to incentivize new builds. And so when we see like capacity prices in PJM, the commentary that a lot of people will put on is, oh, that's clearing above net cone.

And what they're saying is the price that you can get paid for capacity is more than you would to deploy a new project, a cost of new entry. And so in effect, the market should resolve itself, new assets should come in to fill that gap and ensure that the system has enough capacity online to meet its peak demand plus that reserve margin component. And then on that kind of spectrum of, I guess, maturity of said capacity market, I think Kaiso is probably leading the front there. So a change that's gone live in twenty twenty five has been this transition from annual resource adequacy well, monthly resource adequacy requirements, which is somewhat traditional across ISOs in the US to hour of day.

And so what that does for a market like Kaizo that's historically built all four hours is it now gives increasing revenue opportunities for longer and longer duration. So whether you're a four hour asset that's already built and can cycle twice or you wanna be an eight hour and just provide more resource adequacy across critical hours of the day, I think we are gonna see that shift even longer duration in CAISO. I think some of the nuance of it that Brent was getting to earlier is how resources get accredited.

You know, one megawatt of installed capacity does not equal one megawatt of unforced capacity, which is usually what you get contracted for in these markets. And so you could think about it even for a thermal plant.

There are some risks that you may not be able to generate. It may be how much fuel you have on-site. It may be how the distance between the natural gas source versus sink, etcetera. So even a thermal plant won't get on one hundred percent rating. Maybe it'll be ninety five percent, ninety percent, etcetera. For resources that are renewable, traditionally, what they've relied on is effective load carrying capability. And what that does is it looks at the output of that resource in the peak day on the peak hour and assigns a percentage that is then placed against the installed capacity.

And so historically, solar and wind have been in the range of, like, twenty twenty percent. And so in effect, what that's saying is for every hundred megawatts of solar I install, I get twenty megawatts of UCAP or capacity accredited capacity.

Thank you for clarifying what a capacity market is. I think many people in the audience will be very thankful for that. And thank you for also bringing the capacity accreditation issue that we're seeing in many markets to the table because last week, I attended a conference, bringing many stakeholders of the energy and storage, industry in the US. One of the biggest obstacles for developers in market to basically complete projects in markets with capacity markets was to have a clear view of what those ELCC values, capacity accreditation values were going to be in the future to have more revenue certainty. Can you bring some light onto that question and basically extend on how different markets have more certainty on less?

The way that I would think about that question is what is the tenure of capacity contracts that you're getting from a market? So if you're somewhere like California, generally, these capacity contracts are done, you know, OTC. Right? So they're done over the counter, counterparty to counterparty for a particular asset. And so what ends up resulting is you get long term capacity contracts that are fixing that value of what whether you're a battery, a renewable, a thermal plant can provide on a monthly basis to support the capacity markets.

Quite candidly in in markets, and I'm thinking about PJM now that do annual auctions, you don't get the same type of security of, a, what that price is. And I would say, b, what that actual ELCC value is gonna be.

They tend to get updated around the integrated resource planning cycles that naturally happen every two years that are staggered across the US. A lot of these ELCC values are are based on forecasted demand coupled with installed capacity.

And as that peak demand hour changes and as your net load changes Or if it's winter versus summer or something like that.

Exactly. That that accreditation value changes. And I think to Brandt's point, that's why as you go further out in the future, the longer duration battery storage assets tend to retain more of that value. And, ultimately, it's because what we're seeing is you push out that peak later and later into the evening, which will, in effect, hurt solar ELCC. It'll hurt wind ELCC. Thermal probably unchanged, and it'll incentivize longer duration storage.

Okay. Thank you for also covering that question.

Now jumping on to build out. We have seen duration looking into build out now. How are the interconnection queues looking in different markets right now? Are there any places where there's a lot of build out expected and some others where there's less?

Yeah. I mean, I think, the short answer is that there's a lot of energy storage capacity pretty much in every single queue across all the ISOs. And when I say a lot, I'm talking about forty, fifty plus gigawatts in in most of the ISOs queues, like, at a minimum. And in some markets like ERCOT, that's as high as a hundred and fifty, a hundred and sixty gigawatts at some stage of the interconnection process. Now, obviously, a very small proportion of that is actually likely to come come to fruition in terms of actually being operating on the grid.

I think, you know, typically what we've seen, but whether it's the analysis that we've done or some external sources have conducted on interconnection queues themselves, usually, there's a throughput of somewhere between twenty or thirty percent of projects that actually reach commercial operations that have entered the queue in some stage. So obviously, you can take a big haircut on those headline numbers. But even with that big haircut, still substantial amount of capacity that we're expecting. And I think what's interesting about that, right, is if especially if we just, again, go back to the idea of mature versus nascent market.

So ERCOT and CAISO, which we've talked a little bit about how revenues have been pretty low in those markets, particularly on the ancillary service and energy arbitrage side of things, to the point where it's been a couple years now where think revenues have generally been below what a lot of participants might have been expecting when those storage resources were actually constructed. And at the same time, we're still expecting, again, just to take ERCOT as an example, as much as, you know, eight, ten gigawatts of new energy storage capacity from a rated power perspective to come online here in the next fifteen or so months.

And so it's an interesting, I guess, bit of cognitive dissonance, where you have maybe the market that isn't necessarily at face value reflective of needing more storage right now, yet all this storage is still poised to come online. I think to some extent, that's a bit of a reflection of the fact that you have a lot of developers that believe in the longer term need for these resources, whether that's because of demand growth that's going to be coming here in the next at some point in the next half a decade or so as well as maybe the further retirements of coal generation, things like that, that are going to create the need to have additional storage resources even beyond what we have today in a market like ERCOT.

I think the only thing I'll add to that, right, ignoring ERCOT and CAISO. I think what we're seeing across, let's call it MISO, SPP, PJM, New York ISO.

I think over by the end of this decade, we're gonna go from megawatts to gigawatts in all of those markets.

As we've alluded to, some are policy driven. Right? Some are supported by external market forces.

The rationale is irrelevant. So I think we're really gonna start to see the storage market come stand on its own feet in some of the deregulated ISOs across the US that have not traditionally seen as much penetration.

Yeah. I think a lot that's in those markets, a lot of it speaks to the idea of there's been interconnection reform across pretty much all these ISOs. You know, that first quarter of twenty twenty three, I think, of kick started some of that, but there was also just a lot of, you know, groundswell for the need for that to happen with how long projects were taking to go from initial interconnection requests to actual commercial operations in a market like PJM or really anywhere outside of, really frankly, ERCOT at this point.

So so I think, you know, we'll see what happens. A lot of it is still early stages. Too soon to tell for sure that it's working, but it does seem like we're poised to start seeing capacity actually start coming online in places like, you know, PJM and New York. And part of that is because of those delays in the interconnection queue, you compound that with actual growth and demand that's been experienced in a market like taking PJM for an example.

And that's part of why going back to the capacity market conversation, prices in that market have been rising. You're starting to actually see the need for more supply come into play. And so there's now an even more of an appetite to get these resources developed. It's a little bit of a feedback loop.

So so now there's there's storage resources that should be coming online here in the next few years in a market like PJM to help kind of try to capitalize on those higher capacity prices and and really be able to meet continued demand growth here in the next few years.

Now a very quick question.

If each of you had to choose one key driver for each market that is driving battery build out right now, which one would it be? And you can split the markets. Maybe, Pete, you can cover Kaizo and PAM.

You, Brent, can cover ERCOT and NISO.

In ERCOT, I think it's just belief in demand growth long term. Yeah.

Okay. For NISO?

NISO is is is probably more so just a lot of it is backed by the the actual mandate to build more energy storage. So, the state government has has a has a program in place that is, effectively seeking to procure actual storage deployment. So we'll summarize that with just the index storage credit. Okay.

What about you, Pete?

Alright. For CAISO, I would say it's it's driven by renewable ambitions. And for PJM, it's driven by capacity shortfalls.

Okay. Great. Thank you for those takes. Now jumping, to the far final section on the commercial side. The last thing that we have been hearing from a lot of stakeholders in the industry is that they don't wanna be exposed to merchant markets anymore. They wanna have some certainty in their revenues, and that's why they're tending towards offtake agreements. For those less familiar, what do they actually involve and what type of different offtakes agreements are we seeing right now being implemented in the market?

So an offtakes agreement typically, know, obviously, it involves two parties. Right? So the first party being the owner developer of a given technology or that's participating in the power grid. In this case, we use storage as an example.

So the owner of a battery. The other person, the off taker, the other party, the off taker. The off taker is essentially just looking to pay that actual developer, the owner, or the resource to help take some of the risk off of the hands of the owner and potentially gain access to some of the revenue upside that that resource may possess. So the owner has outlaid a bunch of capital to actually build this project, but they're not necessarily as certain of being able to make their monthly or quarterly payments on the debt that they've actually taken out to finance this resource.

Right? So they're saying, okay. We need to make sure we're firm at least to some of the revenue here that with this resource could potentially generate in the future to be able to make those consistent debt payments, and we're a little worried about that. The off taker hasn't necessarily outlaid that capital.

They're able to come in and say, we'll pay you guys a consistent amount of money month to month or quarter to quarter to be able to make those debt service payments.

But, basically, what we're gonna receive in return is some portion or maybe the entirety of that asset's period to period revenue stream. And that effectively, you know, you're you're getting the potential upside of maybe there's this huge spike in energy prices in Texas, and all of a sudden you're able to capture some of that revenue upside. It's just that a lot of that revenue, especially in a market that does have that more energy only construct without the capacity market like an ERCOT, tends to have maybe more of that volatility clustered into smaller number of days or smaller number of periods of time.

So that can be a little trickier for when you have to make those consistent debt service payments to pay off the the debt that you actually took out to to finance the resource to begin with. So that's why, you know, I think in a lower revenue environment here in the last couple of years, I think ERCOT is really the place where we've seen this be front and center because there is no capacity construct to help provide some of that consistent revenue stream month to month, quarter to quarter, year to year, where there are a lot of developers that are, you know, starting to have the appetite to secure off take.

But the interesting thing about that is I think it's something that as a topic has been talked about more than we've actually seen it realized in reality. You know, there's only five or six resources that are actively participating in some type of offtake agreement. There's a few more that are gonna be coming online here in the in the next year or two that will come in with offtake in place. However, it's still a small proportion of the overall installed number of resources in in ERCOT.

And I think some of the reason for that is the developers recognize that there is upside that potentially exists with these batteries. That's why they built them in the first place. Right? So they're saying, you know, even though revenues have been, you know, at three, four, five dollars per kilowatt month over the last fifteen or so months, eighteen months in in Texas, they're saying, you know, we want closer to nine or ten or eleven dollars per kilowatt month for these offtake agreements because that represents the ability of a of a resource to have a really big August or a really big December or January that kind of offsets that lower average across the rest of the year or across multiple years even too.

So you kind of have to price in some of those extreme periods that potentially exist down the line is what the developers are saying. But the off takers are saying, okay. Well, we have so much storage built. We have so much storage that's coming in the next year or two.

It's going to take multiple extreme events that are probably relatively low likelihood, at least in their view. So they're saying, alright. Maybe we price this closer to six dollars or seven dollars per kilowatt month. So you have this big bid ask spread, and it just makes it harder for these offtake agreements to get done.

So it's an interesting one that I think we're gonna see those markets kinda continue to start maturing. And I think, you know, over time, if the market kinda stays like it is now, there's probably going to be motivation on both sides to start getting more deals done. But I probably would have said that same thing a year ago too, and it hasn't really budged as much as maybe we would have thought.

Yes. And to bring a bit more color on the different offtake agreements that are available for developed owners and then offtake parties, what different structures have we been seeing? Maybe, Pete, you can give a bit more context on this question.

Yeah. So I think it's helpful to characterize the two extremes. And then we can find kind of the middle ground where we've seen or have been hearing most of the deals get executed. So as Brent was alluding to, on the far, I guess, left in my brain is you have like a fully told asset. And you could think of that as I'm swapping out my resource for fixed monthly payments.

Whether it's with a utility, an aggregator, an optimizer, doesn't matter.

On the other side of that, you're fully merchant. Right? Day in, day out, I don't know what I'm gonna make.

And I'm at the mercy of my nodes LMP.

Somewhere right in the middle of there, which we've where we've been hearing most of the discussion come in in the play is revenue shares.

So a lot of times the way in which we'll see that is you'll you'll agree with a counterparty a floor price.

And to that and to Brand's point, maybe that floor price is kinda just at that level where, you know, you can meet debt debt obligations and kinda sleep sleep easy at night. And then on the upside, there's usually a revenue split. Sometimes sixty forty, seventy thirty between the owner and the set optimizer of the asset. And so that enables, again, assets to be built, credit teams to sleep fine at night, you know, debt debt service payments to be made, but also you're still exposed to those extreme pricing events, which is candidly a lot of the reason that developers are driven towards ERCOT anyway. As Brian mentioned, I think there's a a pretty wide bid ask spread there between what what both parties are expecting. What we've been hearing on greenfield and even existing assets for folks that are just coming online that may have built off pretty punchy forecast. There's been some clamoring to secure some of that offtake.

I think conversely in markets like Kaiso, it's almost the opposite story. You have the certainty from the resource adequacy market. For there, it's more of a discussion of how do we leave a little froth for real time energy arb. And so, again, depending on what the structures are in place, each market is driving kind of different on that spectrum of of offtake.

Yeah. I think the motivation for offtake is is much more it's it's it's there in ERCOT in a way that it very much isn't necessarily in in Kaiso and presumably won't necessarily be there in other markets as they start to become more mature because, yeah, like you said, ERCOT is really unique in the sense that it doesn't have that consistent contracted revenue stream, whether it's through a capacity auction or a bilateral market like in Kaiso. So, yeah, I think what we've heard from investors and financiers is is that in ERCOT, yeah, they almost expect you to come to the table with at least like, you're it might not be the full resource fully told out.

It might just be covering that debt service, they're comfortable with that. But they want you to have something. Whereas in those other markets, I think we've heard people refer to the index storage credit or being able to secure regularly high clearing capacity market prices like in PJM or in Kaiso as being a little bit more bankable. Right?

But, yeah, it's it's it's a tale of two very different market constructs for sure.

Well, thank you. We are running a bit out of time, so I'm gonna jump to the last section of of the podcast, and this is a question that we always ask to all of our our guests, which is, what's one contrarian view you hold about the US energy market right now? Something most people might disagree with. Pete, if you want, you can answer first, and then we can have Brand answer.

I guess my contrarian view is I think we're gonna have a lot more thermal online for a lot longer than states, utilities, or maybe the EIA will have us think. Whether it's coal or pretty old thermal, pretty old natural gas, I think we're just in such a capacity crunch here that regardless of all the storage that we see on the horizon, it's gonna be hard for us to wean off any firm capacity.

That opens a lot of questions, but I'm gonna keep that door closed for today's episode.

My my my other contrary view is I think there's I think there's gonna be a large consolidation within the the energy storage market, particularly in ERCOT with a lot of entrants making less money than they maybe thought they would have.

Okay. Very interesting. Thank you for sharing that, Pete. What about you, Brent?

I think my my primary contrarian view here the last few months is that the OBBBA, at least for energy storage in particular, is it'll be impactful in terms of having to make decisions surrounding it. But in terms of maybe the top line of how much energy storage actually gets built in the long run, I'm skeptical of how much of an impact it actually has.

Because I think, especially the last two years, I've really already been not necessarily predetermined in terms of how much storage gets built, but a lot of those decisions have already been made. And then as you get into the later part of this decade, I think a lot of the potential implications of what the OBBBA means for total all in costs tax credit inclusive or exclusive for an energy storage system is gonna be counteracted so much by, you know, how manufacturers end up pricing their systems or how much more efficient batteries continue to get. And ultimately, the per unit cost of capacity for batteries is just gonna continue to kind of outweigh any, you know, headwinds from a policy perspective, I think.

Well, thank you very much for that answer, Brandt, as well, and thank you for being at the podcast today.

It has been a real pleasure to host both of you, and, I hope to have you soon back here.

Thanks, Alex.

Thanks, Alex.