36 - How to develop a storage project with Andy Willis (Founder & CEO @ Kona Energy)

[MUSIC PLAYING]

OK, Andy. First thing to say is congratulations.

You guys closed a pretty big deal recently, and I am looking forward to unpacking that.

So firstly, hopefully you've got some sleep, since I know these things can be pretty hectic.

Yeah. Who are you, Andy, and what are you doing on our podcast?

Yeah. Firstly, thank you for having me on, Quentin.

So Andy Willis, founder and CEO at Kona Energy. So we're an energy storage development company, and yeah, as you alluded to, we recently completed a sale of our first project up in Middleton in the northwest of England and with Gore Street Energy Storage Fund.

Cool. So Gore Street bought a site from you guys, and they're going to build it, are they? Or are you going to build it and they're--

how does that work?

Correct. So we're the development company, so basically we've put together the project but we haven't constructed it. So we're getting it to a stage where it's construction ready, and that's what we've been doing over the last year or so. And then Gore Street will be responsible for investing the money to construct that project, and then they'll be operating it for the life of the project going forward.

Awesome. OK. We're going to get right into the details on that in a minute, but before we get started, let's just find out a bit about you before this. So you've been out on your own doing Kona Energy for a while now.

Scary stuff. I'm looking forward to hearing about that. And before Kona Energy, you were also doing battery stuff, right? So do you want to start from the start?

Yeah, so I left university in 2015 and it was always a motivation and a passion to work in the clean energy space. I initially joined a renewable heating company back in 2015, and we were focused--

Before we knew that heat was cool, by the way.

Before it was cool. So this was the early days. It's obviously still a very hard to decarbonize sector of the economy but incredibly important.

Yeah, so I joined a renewable heating company back in the day and we were looking to roll out heat pumps on a domestic scale across the UK. There was a government subsidy, the RHI, which stimulated the growth of that market.

But back then, and I think it's probably fair to say even now, it's still a very difficult area of the economy to decarbonize and multiple governments are really trying hard to work out, how do we do this on a large scale? How do we make it fair? How do we do it in a cost effective manner? So that was my first foray into the clean energy sector.

What did you do at uni? Were you engineer, economist?

I'm not. I studied human geography, so there was a very big energy focus within that course up at Durham University. But it was very much--

it was quite a broad degree, so it was sociopolitical, touches on economics as well. But I'm not an engineer by trade, so I've always been more involved in the kind of policy side and the commercial side of the renewables industry.

Cool.

But yeah, I was always very interested in moving into energy storage. And I think back in 2015 or '16, BEIS, at the time, after BEIS took over from the Department for Climate Change and they put out a statement that said the UK wants to be great in eight technologies, and one of them was DSR and one of them was energy storage. And at that time, obviously, there weren't any kind of batteries on the grid.

Tesla was around rolling out its first cars, and it was clear within the economy it was going to be a big sector going forward, but no one really knew how that was going to play out going forward. So I was very fortunate to join a company called Arenko back in about 2016, early 2017 right at the start of the UK industry for energy storage. So around the time of the Enhanced Frequency Response Tender run by National Grid, and yeah, managed to get into Arenko quite early.

I was one of the first 10 employees. They had four senior managers at the time. Rupert Newland was the CEO. And yeah, they hired a lot of people fresh out of university, basically, who, obviously it being a new industry, weren't, perhaps, experts in the space, but were willing to really work hard and try and unpick that industry.

So that was my first--

well, that was how I started within the UK battery storage space.

And Arenko did something very different back then, right? Arenko was a different kind of company and business model.

Exactly. So when I joined, we were, in effect, a project development company looking to develop projects and build out those projects as well. And I joined, yeah, on the back of EFR, which Arenko were unsuccessful in. And as we saw, that market, that first tender cleared at a very low price.

What was your price, by the way?

I was at Centrica and we submitted at--

I think it's 13 pounds 10? And I think the highest accepted was 12-ish. And in the end, EDF was 7, I think.

ANDY WILLIS: It's crazy looking back on it, isn't it?

QUENTIN SCRIMSHIRE: Well, what did you guys put in?

I don't know exactly and I probably can't say exactly what number we put in, but it was higher than that and clearly we were unsuccessful at that tender. And it was a bit of a sign of things to come, actually, with those, how National Grid ran these tenders and then what those market prices would clear at. So suddenly the company thought, what do we do next?

Because the finance community, the investors were focused on winning this EFR contracts. But Arenko were at a good place that they were always very nimble, very pragmatic, very forward thinking, and so we continued to develop projects and actually built out one of the first big batteries back in the day in about 2017, which was a project called Bloxwich.

Never heard of it. What's Bloxwich?

ANDY WILLIS: Never heard of it? 41 megawatt project in the West Midlands. I'm sure all over the Modo leaderboards.

QUENTIN SCRIMSHIRE: Wow. We love Bloxwich because it was--

I always say this. I mean, Arenko did a year in the BM just hammering away at it before it was even profitable. I don't want to say before it's profitable, but it didn't make sense to do that financially, but it did make sense to do that strategically for them. And they sort of battered down the door of the BM, so big kudos to them.

Anyway.

ANDY WILLIS: Yeah. 100%. And just the engineering of that project as well was so complex it was actually--

it wasn't one of these early containerized systems, it was actually retrofitted into an existing warehouse. So looks very different to a lot of the batteries within the UK, and that brought its own engineering challenges, which Arenko worked with General Electric on that project and, yeah, built a really interesting and first of its kind project.

And as you said, Quentin, the markets were very different then. There wasn't dynamic containment. The FFR market was around, but it was slightly boom and bust. We had some very high prices and then some very low prices. And Arenko, as a company, thought, actually, we've built this first project that's very impressive, but new players are entering the market who potentially have lower cost of capital than we do and their business is funding projects and building things.

Our expertise is actually probably more on the software side and operating these batteries. So they'd already performed in the frequency response markets. They knew what they were doing there and thought, what's the next big thing for batteries? And moved into the Balancing Mechanism as one of those very early battery players within that.

Obviously, potentially very deep, liquid markets. And as the market of--

I wouldn't say last resort, but that last step before real time settlement, very relevant to batteries because of their speed of response as well. So Arenko performed well in that early market, and that's all well considering they could have made more money, perhaps, in the frequency response markets.

And that's what really drove them to become more of a software player rather than thinking, let's develop projects, build them out. Actually, from a business perspective, their view was that we can do better rolling out our software platform and operating other people's assets because we've got that expertise. We're the first mover in the markets and everything like that.

So when did you leave Arenko and go out on your own? And how did you make that choice?

So there was actually a gap, one other company in between--

Zenobe Energy in between Arenko and Kona.

So as Arenko made that pivot, at the time I was working mainly on the development of their projects. So Bloxwich got sold to Gresham House eventually. Some of our development portfolio, which I was working on at the time, that got sold as well. And as much as I enjoyed my time at Arenko, I was personally a lot more interested in the development of these assets, the funding of these assets slightly less on the software side.

So I had ambitions to set up a company at that point in time, but COVID came along. I knew the guys at Zenobe very well and they offered me a role in their team. And so I joined Zenobe who, again, are, I guess, one of those early players in the market. They've done incredibly well both on the grid scale side of things, but also on the EV and the electrification of transport on the other side of the business as well.

Also quite unusual because they develop their own sites as well. They're not just buying sites. I'm not saying anything wrong with that.

But if anyone knows how to develop sites, it's Zenobe. And cutting your teeth there as well was a--

well, a great experience, no doubt.

Yeah. 100%. They've got a great team there.

Yeah. My manager at the time, Semih Oztreves, he came from Wartsila.

Very smart guy. They both had the development expertise, the construction expertise, the funding expertise, and the operational expertise going forward as well. So I was only at Zenobe for just over a year, but at the time we were looking at some of the National Grid Pathfinder projects.

So obviously all in the public domain, but Zenobe built a project in Cape and Hurst which was 100 megawatt project, one of the biggest at the time to be built, and that secured a reactive power contract with National Grid to basically absorb vars from the system. So not only providing frequency services or trading in the wholesale energy markets, but also providing reactive power services, a very stackable service.

I'm really interested in--

I want to ask someone at Zenobe. Maybe you know about how many cycles that battery has to do to do that kind of--

it's a cross between--

yeah.

It's sucking up vars or voltage support, however you want to describe it, and how many cycles do you have to do for that? I'd be interested to know whether the business case and the actuals are where they thought they were going to be.

Yeah, it's a great question. I think one of the benefits of providing a reactive power service or reactive power absorption is it's very stackable with providing other services such as frequency response or trading in the wholesale market, so operating on the Balancing Mechanism. So you can't quite do 100% of your active power compared to reactive power, but you can get very close.

So what I mean by that is you can provide a reactive power service for, let's say, eight hours of the day while still pretty much being able to do your full active power service on top of that. So it's a very stackable service for batteries and doesn't really impact your cycling much. It has wear and tear on the inverters, but it is--

batteries can provide that service at very low cost, and they can do it independently or simultaneously to active power services.

Which means for, say, the National Grid running the system, if they were going to get those services from a synchronous generator, a gas fired power station or something like that, they'd have to physically instruct them to turn on and produce active power. But the beauty of batteries is that they can just do that service instantaneously without potentially distorting the energy markets on the other side. So yeah, it didn't actually have a huge impact on the cycling, to answer your original question, Quentin.

OK, cool.

And then let's talk Kona. So uni, then Arenko during the early days, then Zenobe during the COVID year. And then at this point you'd got itchy feet because you were thinking about starting your own business anyway, and once you get that in your head there's no turning it off. Man.

It's just--

it's great. And so when did you decide to jump, and what's the vision for Kona?

Yeah. So I set up the company in about June 2021, so about a year and a quarter old now, so still a fairly young company.

And we're an energy storage development company. So I kind of felt over the last few years I'd really built up a bit of an expertise in developing these projects and being able to deliver projects that would receive investment and get built and provide a long term service to both the National Grid and the end investors. Probably similar to you, I think when you get that buzz and drive to start a business, it's very hard to shut that down, so obviously I was apt to--

QUENTIN SCRIMSHIRE: It just gets louder. In between your ears it just gets louder.

Exactly. I was at two great companies beforehand who were doing very well, and the temptation is to stay and see them grow, which they're both very much doing. But I had that buzz and that bite, I guess.

Yeah, and set up Kona. So yeah, an energy storage development business--

What does that mean?

To folks who don't know. People know developers as software engineers who write stuff on screens with a lot of black on it. So what is a developer?

Good question.

So in the UK obviously we've got about 1.5 gigawatts of projects operational at the minute with a huge pipeline behind that. And if we think about those operational projects, they all start somewhere, and that's the role of the developer.

So the development company traditionally will start by, in very simple terms, securing land to actually build the site. Physically these batteries are, of course, located somewhere. They'll secure the planning permission and secure the grid connection with the relevant DNO or TO. And what they're fundamentally doing is setting the, I guess, base business case and getting all the consents and rights for a project to be built going forward.

So there's three things. Somewhere to put it, a bit of land, a grid connection that makes sense, and planning permission. You got to get those three things together.

ANDY WILLIS: They're the fundamentals of the--

yeah, of what a developer puts together.

And so let's go through each one in its own way. So getting land.

Do you have to buy the land? Do you have to have a promise from someone that you can rent it? How does all that work? Do you have to go around in fields knocking on people's door? How do you find the land?

Yeah. So I guess to take a step back, how we start our development cycle is actually from the business case angle first. So we work out where on the grid, if you were, say, National Grid, would you actually put a battery? And we try to think about it from a systems perspective.

Once we work that out, and I'm sure we can come on to that in a minute, then it's a case of physically finding land. In terms of that land negotiation, you'll go and speak to a landowner and you'll negotiate what's called an option to lease. So generally with batteries to date, you lease land rather than buying, say, the freehold land underneath it.

Why is that?

I think you can buy, and I think it's kind of how it's been done traditionally to date. Potentially investor feel a lease is a safer option. You're not taking on a land for a lot more money, which could theoretically be a liability going forward. It's not to say one is better than the other, it's just the way it's been done to date, basically.

And how long do you need to lease the land for?

So yeah, the way it works is generally you'd have an option period first, which might be a few years, basically, where you say to the landowner, we have an option to lease your land, and in that time we'll undertake our development process. Obviously, all at risk that you're trying to get your planning permission and everything like that.

And the reason you don't lease it at day one is, of course, if you lease it at day one and then planning gets so rejected after 12 months, you're stuck with a long term lease which you can't do anything with. So that's the reason for the option period. Once the actual lease, it's generally 30 to maybe 40 years in length, and that generally coincides with kind of the asset life of these projects or what they're expected to do going forward.

That's interesting. So it used to be 20, 25 years, right? In the solar days it was 25 years because I think the idea--

well, 25, 30 years. I can't remember now, but it's because of the feed in tariff and how long that lasted for, and then the design life of the inverters was usually 25 years. And now it's getting longer. It's at 30 and 40 years.

And what do you have to pay for a lease? How does the land owner get paid?

Does he or she get a cut of the money you make or do you pay them a fixed amount? How do you figure all that out?

Yeah, it's generally a fixed amount. So we might negotiate that ourselves or you might get agents to do it, and generally you negotiate on a pounds per acre or a pounds per megawatt lease.

I can do megawatts. Acres? Wow, you lose me on acres.

ANDY WILLIS: Acres is a, yeah, interesting. Interesting one. And it really depends on where the market is at the moment in time.

How do you do pounds per megawatt? Because if you're going to put a one--

say you can one or two hour system in now but you're leasing for 40 years, and let's say 10 years time you want to put a three or four hour system in. Does the landowner just have to give you that and you--

the megawatt thing feels like it's--

yeah, there's pros and cons of each, isn't there?

There are pros and cons of each, and I think acreage is far simpler to do. And on the megawatts it's more proportional to the size of the project you're building, but theoretically you could build a four hour duration system. But then on the inverse, those batteries are, of course, degrading over time as well. So should the landowner be getting paid less each year as the batteries degrade and theoretically you make less money, and it's really swings and roundabouts.

Well, what else can the landowner use that land for? I guess for them it's an opportunity cost question, right? So what are you competing with? If you go into a land owner in saying, I want to build a battery on your land.

Let's get an option . Agreement and the landowner, which might be a farmer, let's say, says, well, I can make X pounds doing whatever a farmer does. Growing stuff or rewilding. What's the trade off for them?

Yeah, good question. It depends on where the land is, what that land is being used for traditionally. So farmers are often the people you deal with when negotiating these agreements. So they might be using that land for agricultural purposes for crops or whatever it may be.

So naturally they're thinking, I'm getting X amount from my crop yield each year. I need to justify a high return through a battery lease or solar lease, or whatever technology it may be.

And of course, batteries can provide a much higher cost on a per acre basis than what you might get through, perhaps, a crop yield, for example. So if you're a farmer it's actually a very good way of diversifying your income because you have a fixed asset on your land which will sit there for 30 to 40 years and you're getting a fixed income over that time period. Whereas, of course, crops, for example, you could be impacted by commodity cycles or weather cycles. So perhaps the risk there, it's fundamentally more uncertain.

And you might have been screwed by Brexit, right? Because you used to get these subsidies and now you don't. I don't understand it. I live in a city. But what I know is that some guys have got less money now than they used to.

Hey, exactly that, Quentin. So it is a good way of diversifying your income and bringing in that solid baseline, which they can then spend on other things on the farm, other innovations to improve the rest of their farm, for example.

Cool. All right. So we've done land. And then let's do good connection and then planning permission.

Planning permission is probably the most contentious one, isn't it? Because you're relying on humans to make a decision. So grid connections. You've gone to your farmer.

You've got a lease. You've got an option to lease and the option lasts, what? Two, three years, something like that?

Yeah, two, three, four years. Yeah.

QUENTIN SCRIMSHIRE: And so you've got that piece of paper, one third of the way there. You're already spending the money in your head. And then you go to the grid operator to the DNO, perhaps, and what do you have to do with them?

So generally once you've identified where you want to build the site, it will be, ideally, in close proximity to a substation. Whether that's owned by the DNO or the TO, so the National Grid or Scottish Power Transmission, whoever that may be. And then it's likely you've had some kind of dialogue with them to date of, if we apply for a battery connection here, firstly, is there capacity on the network? What's that actually going to cost to connect into their network? And you have to work that all out in tandem to doing the property side.

Are there any rules of thumb? So if there is a--

I don't know, a transformer that looks like X, don't go near it? Or is there, if it's longer than two miles to the substation, don't go near it. Are there some things you can share with the people who are listening?

Share your wisdom. Come on.

ANDY WILLIS: Give away all the secrets.

Give away all the secrets, yeah.

So at Kona Energy we're firm believers in scale. So the market's really matured in recent years. There's a lot more money being invested into this asset class, so we generally target projects of 100 megawatt plus.

QUENTIN SCRIMSHIRE: OK.

So that immediately reduces where we can place these assets on the grid.

And for example, you're going to connect at, say, a minimum voltage of 132 keV, which is the kind of top end of the DNOs. That's the top end of their voltage level. Or the transmission network where the voltage levels are 275 keV or 400 keV--

Which is with National Grid ESO. Big stuff.

ANDY WILLIS: Big stuff. And very simple--

and I'm not an engineer, so this is incredibly simplistic. But the higher the voltage level, basically the more megawatts you can put into that substation. So for example, if we were looking to do 100 megawatt projects on an 11 keV substation, you'd simply blow out that substation.

So if you applied for a connection of that scale, the DNO or the National Grid would come back to you and say, sorry guys, that physically doesn't work. If you want to make it work, they're obliged to give you a license offer. They might say, we have to build a new substation for you which could cost tens or hundreds of millions, which clearly is going to ruin the economics straight away.

Yeah. We'll do it for you, but we're going to financially ruin you in doing it. Yeah, it's funny, actually, over the years because 10 years ago solar developers wanted 11 and 33 keV connections, and all the best ones got snapped up. This is for smaller sites. And as we've gone bigger we've gone for these higher voltage connections. And there was a dash for tertiary windings at one point. Pivot Power got a lot of those.

A lot of the 50 megawatt standard sites have gone now. And so we're going further up the chain, and I'd imagine that National Grid have got a lot more connection requests from batteries than they've ever had before because the DNOs are--

well, the whole system's gone a bit awry, hasn't it? But let's talk about that for a second. What on Earth is going on? We're going to come back to a planning permission.

What's going on in connections? You know this because you're on the ground. It sounds like it's nonsense.

Yeah, so it's a very interesting time in the connections industry at the minute, and anecdotally we're hearing that development companies are putting in grid applications to connect to, let's say, the National Grid network, and they might get a connection offer back in the three months that's the time period which says you can't connect it until 2035 or 2037. And of course, if you take that to your investors, they're going to laugh at you because they're not going to wait 15 years for a project to be built in a fundamentally uncertain market.

And net zero will not wait until 2035 either.

Exactly. So it is a big issue, and National Grid are looking to address this. I think the issue they've got at the minute is that a lot of technologies are trying to connect to the network. So we've got, obviously, the 50 gigawatts of offshore wind by 2030 and a huge amount of solar that's planned to be built over the coming years, a lot of batteries.

Now we've got all the hydrogen bonds turning up, and they want to connect as well.

Hydrogen. Still a few, unfortunately, big gas plants in the mix as well. So what that means is that when National Grid model, your connection onto their system, they're not only modeling, say, your battery. They're modeling everything else in the area that's looking to connect. And what that means is that they say, actually, let's, for simple terms, say we've got 1 gigawatts of capacity in this particular area.

We've actually got 10 gigawatts of capacity looking to connect into that. So then they do a modeling exercise where they say, to get you online, actually, we're going to have to rebuild an overhead line or put in a new overhead line, and that's obviously a long term infrastructure project. And that's what's causing these very much--

these very delayed connection dates, and it is an issue.

I think if you go to a lot of big conferences where--

even with the likes of Aurora, I think the CEO of Shell was there and he was asked, what issue do you have when looking at the UK market to invest your money? And grid was the first thing he said in terms of grid capacity, grid connections, being able to build assets quickly.

Who'd have thought that this is the thing that was going to get us tripped up?

I don't know. Three, four years ago when everyone was running around shouting merchant is never going to work, it was all about the business case, and then it was all about funding and it was all about--

it was about financing. It's got all these complicated things, and then the thing that's holding us up is pieces of wire.

Yeah, it's fascinating. And as you say, I think the funding community has got a lot more comfortable with battery technology over the last few years. We've got the proven track record a lot of these assets on the grid, so those kind of questions will be--

I wouldn't say solved, but mostly mitigated. But now we've got an issue where you can't actually connect to the grid often in reasonable time frames.

What's reasonable? So you said two--

I can sense that 2035 is unreasonable. But what does good look like? If I am, say, Gresham House or Gore Street and I'm looking--

I know you don't work for those guys, but you must speak for them all.

And we want to deploy a lot of megawatts.

I'd imagine a lot of 2023 connections have already been bought up. 2024, 2025, 2026. What kind of sites are on the market, and what does good look like right now?

ANDY WILLIS: Generally the sooner--

Let's timestamp this. This is Monday, the 7th of November, 2022.

Generally the sooner the better.

So obviously, whatever site you have it's going to take time to build. So let's say, as a rule of thumb, it's going to take you 12 months to build a project from first spade in the ground. So if you can secure, say, a late 2023 connection or an early 2024 connection, that's generally the most attractive for these big investors because they want to deploy that capital they've raised and see a return on it as soon as possible.

I'll caveat the answer to that slightly because obviously cell prices are very high at the moment. So some investors are actually thinking, should we hold on, and would a, say, 2025 connection actually be more optimal because we'll wait for those kind of sale prices to come down?

What does very high mean?

I don't have the kind of numbers to hand, but we've seen in the last two years that prices have increased massively due to supply chain issues.

So it used to be two, three years ago, you used to be able to buy a site for 30, 35 grand a megawatt, and that's spade ready, ready to build. And I'm assuming the 35 grand a megawatt doesn't exist anymore. So are we 50, 70, 100, 150, 200, 250? What kind of range are we in these days?

The premiums have definitely gone up. I think the point on cell prices is that that's the physical battery cells, which means it obviously impacts that whole project rather than the money that a connection might cost you. But yeah, premiums have shot up, and when we ran our process we did that all internally. But there's a lot of bespoke M&A advisors that run transactions, and we are hearing numbers of 100K plus a megawatt, so very high figures.

So yeah, three times plus what it was two or three years ago, and that is directly impacting the IRRs of these projects because we've got--

the CapEx has gone up because cells cost more because supply chains and inflation and all of that, plus premiums on sites. I mean, there is a point where you've got to think, well, yes, the cost of capital is going down--

when you're in a low interest environment, by the way, not necessarily right now. There is a point where this doesn't really make sense anymore, right?

Yeah. And I think one of the really interesting things at the moment, to bring it back to that kind of grid connection position, is a lot of people are trying to develop projects all over the network, and we've seen numbers that the pipeline in the UK is in gigawatts in gigawatts. So you'd expect a lot of the investors would be in a strong position and some investors have bought lots and lots of sites all on good terms, I'm sure. But there is still this scarcity value within the market, that if you have a project with a quicker grid connection date, that is valuable.

Yeah. So on the top trump's cards, it looks like a buyer's market. But then it's not if you want good sites and sites now, which most people do. All right.

Let's go back to--

you were explaining very well how the whole process worked. Last thing. Planning permission. Is it difficult to get planning permission for a battery?

Good question, and it's kind of a how long's a piece of string question because it really depends, obviously, where you site these batteries and the local conditions and everything like that. I think, again, Kona, we're looking at scalable projects, so generally 100 megawatts plus. And we've benefited from some very forward thinking policy back in--

I think it was November 2020.

So there used to be a 50 megawatt cap on batteries, and just to provide a bit more information on that. So if you were below 50 megawatts you could apply for planning through the Town and Country Planning Act, basically the local designation. And if you went above 50 megawatts you'd have to go through the DCO route, which is a very long process.

DCO stands for?

ANDY WILLIS: Development Consent Order.

So that's big power station stuff? That's like national level as opposed to just a faster normal planning permission thing.

ANDY WILLIS: Exactly that. It's the same process as, say, the offshore wind farms or a new CCGT might have to go through.

And I think the government rightly thought that actually, even though the megawatts might be 100 megawatts, that sounds like a huge amount of power, which it is, actually these batteries are probably in a couple of acres in a field. So from a planning policy perspective, they're not having huge detrimental impacts.

So before, if you wanted to go above 50 megawatts, you had to go down this long, painful DCO route, which is a couple of years, wasn't it? And don't you need the Secretary of State to sign off on it, it's that big?

Exactly. It's that big. So you had this--

again, this interesting conundrum in the market where everyone would try and go for 49.9 megawatts--

QUENTIN SCRIMSHIRE: 49.9. Yeah.

--to keep below that cap so. And again, fair play to the government that they rightly saw this as an issue. We need a policy change to amend this, and basically, they relaxed that megawatt cap.

But you also got--

if you're less than 50 you could be in the gray area where you can have a generation license, so you're license ABOL, but also license exempt and a license holder at the same time. Which there's a Venn diagram somewhere that'll blow my mind, which meant you've got embedded benefits but you also didn't pay all the non-commodity costs, which is insane.

Which is why you got these sites with generation licenses. Anyway, there's a few reasons why there were 49.9s. But again, what an odd situation. So you--

ANDY WILLIS: What an odd situation. And I think one of the sites, Minety, where there's this 100 megawatt plant, technically split into two projects with two different SPVs and two separate planning applications--

So two different SPVs, so that's two different companies, special purpose vehicles, limited companies that own half each?

ANDY WILLIS: Exactly.

QUENTIN SCRIMSHIRE: Bonkers, isn't it?

Yeah, it's the same overall end investor, and everyone could see it was pragmatic to put, say, 100 megawatts on that site, but they had to--

they couldn't just put in one planning application, it technically had to be two, which is very--

it is just bonkers, as you said.

QUENTIN SCRIMSHIRE: It just can't be efficient. Anyway, so coming back to getting planning permission. So you focus on the big stuff, and now you can do the big stuff through a normal planning application, not the DCO, which is great.

How do you get planning permission for a big 100 megawatt site?

Let's start with some examples. How many containers is it for 100 megawatt site, and let's start backwards from there.

Yeah, so as you say, these batteries predominantly are containerized system on greenfield or brownfield sites. And for 100 megawatts, again, it depends on your duration, but there'll be a lot of containers, probably 100 plus for that kind of site. So how they actually look is you'll have your transformer, your substation, your balancer plants, and then often it's just lots of these containers in a field, in effect.

They're normally around 2.4 meters high. So from a visual impact, you're taking up a few acres of land, but they're not, say, anywhere near as big as, say, CCGT or anything like that. So they are less intrusive than a lot of big infrastructure that's built in the UK.

So what you would initially do is that you'd apply to the local authorities, so their council where you're looking to build this battery, and you would say, we're going to build a system of this size and these are all our--

these are our plans. This is how big it is. This is how many containers. You'd have to do a lot of studies, say, ecology studies, visual impact studies.

Check for some newts.

ANDY WILLIS: Check for some newts. That's always a big one.

Check for bats.

ANDY WILLIS: Check for bats, badgers.

What else would you have to do? Noise studies, of course, especially if you're within an area that's close to where people are living. And eventually you submit this big pile of information.

QUENTIN SCRIMSHIRE: Yeah, so you've got this big folder that you submit and then you've ticked all the boxes. And then what are the chances that it gets rejected? I know it's a difficult question.

ANDY WILLIS: It is, yeah.

If you had to put a number on it.

I'd say we're probably about 70% to 80% are getting approved at the moment, which is good. It's a fairly high number. And a lot of councils in the UK have declared climate emergencies so they are very aware that we need a lot more clean energy, renewables, batteries to really help us decarbonize as quickly as possible, so they are aware of that and that factors into all their decision making.

I think naturally you need to site these batteries in the right locations. But if you're in a community where people are potentially living close to the battery then there is going to be more kick back because not many people want a battery in their backyard, and realistically. So as a developer, you'd often--

I can't imagine it. Oh, I'd love one.

ANDY WILLIS: You'd run a consultation process where you'd actually go out and run an event where you'd actually speak to a lot of the locals, you'd address their concerns, everything like that. You'd explain to them the technology because we're obviously pretty familiar with batteries, but to a lot of people it is very new and it is still very nascent. So you'd explain that to them and kind of explain the benefits, how the construction process works, and everything like that, and try to get them comfortable with what's actually happening on these sites.

OK, cool. So those are three things you have to try to get there. It sounds easy, right?

ANDY WILLIS: Very easy.

Developers always get this. They get told that what they do is easy, and it's very, very difficult. And so you get all these sites together. Let's talk about the deal you just closed. Where to start?

This is huge because I think this is your first one that you sold, and not only did you sell a big site or multiple sites, you sold it to one of the biggest funds in the UK or one of the biggest funds in Europe, Gore Street, who I'd imagine go through everything with a fine tooth comb because they're professionals. So what was that like? What was the deal? What did you sell? What did they buy? And what was the process like?

Just before we get onto that process, I'll give you a bit more information--

allowed to talk about it.

A bit more information on the project as well. And again, I'm probably sidetracking slightly here, Quentin.

QUENTIN SCRIMSHIRE: Go for it.

In the UK market today it's the business case for batteries has been governed by the frequency response markets, so EFR, FFR, dynamic containment more recently. And ultimately, those markets are quite shallow. So when enough batteries are built the price of those markets will collapse, and I think a lot of investors have moved into the markets on the back of these kind of quite lucrative frequency response markets.

So when we developed or when we develop our projects, we try to look beyond those markets and really locate areas of the grid where we can connect where you're solving not just--

you're not just going to be delivering a frequency response issue, you're going to solve a local constraint as well. So our first project that we recently sold to Gore Street Energy Storage Fund, it's in the North of England.

The substation we're connecting to is the landing point for six offshore wind farms, so obviously they're putting in a lot of energy to the system. So when we started developing this project, we looked at how much those projects are, those offshore wind farms getting paid, and some of them are--

or one of them, in particular, is on one of the very early CFD contracts, so round one.

It's on an index linked contract so the price it's receiving per megawatt hour is about 180 pounds now, which is very high. Potentially not actually at the minute considering everything that's happened in the last six to nine months with energy markets, but it's receiving a lot of money for each megawatt hour it produces, and rightly so. I think the CFD has--

it's a great policy in all, but naturally the first--

QUENTIN SCRIMSHIRE: Even 180 quid, they're probably still giving some back to the government.

ANDY WILLIS: I think they are now, exactly.

And as we know, the recent price of the CFD auctions is 40 pounds, and it just shows how quickly the price of offshore wind has come down.

But what we also looked at was the curtailment of these assets. So what that means is how often these wind farms were asked to basically turn off when perhaps there was an oversupply of energy and the local grid infrastructure couldn't take that energy. And we actually realized in that part of the network it was very, very high, so there was a lot of curtailment at these offshore wind farms.

And when they get curtailed, because they've got CFD, they have to get paid to curtail, right?

Exactly. Because for the offshore wind farm operator they're thinking, we've done our part of the job. We're producing clean, free energy when it's windy. It's not our problem that we're being curtailed. That's a network issue further down the line. So they still need to have that CFD paid to them so they can justify and pay off their initial investment.

So our very simple logic, thinking about the offshore wind, is if you have a large scale battery at a facility like that, rather than curtailing the wind and bidding off those wind farms, you can use that battery to store when there's an excess of energy, hold it, and obviously give it back to the grid at times of need later in the day.

QUENTIN SCRIMSHIRE: So if I understand this correctly, your thesis is develop battery sites in places located where there is a benefit, and one of those examples is where there is offshore wind that's getting paid to switch off, something's broken there. So let's put a battery there and hopefully some of that--

rather than paying them to switch off we can pay to use the battery instead, and then we're still keeping the renewable energy from the wind. Is that right?

ANDY WILLIS: Correct. Yeah, that's one of the local constraints we identified in the northwest of England at this place called Heysham where we're connecting.

QUENTIN SCRIMSHIRE: Heysham that also has a very large nuclear station, right?

Yes, and that's another very interesting point because there's two EDF nuclear plants next door to each other there, Heysham One and Heysham Two.

I used to work in Heysham, by the way, just a side point.

I spent a year--

almost a year living in Lancaster working in Heysham when I worked in offshore oil and gas. And if you stand from--

from the West Coast, if you look out to sea you can see some offshore gas platforms that are owned and operated by Centrica. So I used to play with those.

ANDY WILLIS: It's a fascinating part of the world, isn't it--

Heysham's a cool part of the world.

ANDY WILLIS: --from an energy perspective. Yeah. You've got the nuclear plants, the offshore wind, the gas as well.

And for us, both those nuclear facilities are coming offline in, I think Heysham One is meant to be 2024 and Heysham Two is 2028. And those plants obviously provide baseload energy to the system.

And there's so much power infrastructure around there. There's overhead lines everywhere. There's massive subs--

it just feels like somewhere which is asking for more generation and more electrical stuff.

Exactly. And one of the things we did was we looked at what else are these nuclear power stations--

these nuclear plants doing, and what's going to be the impact when they come offline? And Heysham One and Heysham Two, through the merchant reactor power markets that National Grid offer, they get paid more than any other asset on the system to absorb vars from the system.

So again, predominantly caused by the increase in renewables in the local area. So one of our hypotheses was, what happens when those nuclear plants come off in the next few years? There's, again, going to be a big hole for, say, reactor power absorption which, again, is a service the battery can offer.

So when we were taking this project out to market to the likes of Gore Street, we weren't pitching it as a frequency response battery. This was a battery that could manage multiple grid constraints in terms of those energy constraints from the wind, but also solving some of those more system issues through reactive power issues, lack of inertia when the big thermal plant comes offline.

QUENTIN SCRIMSHIRE: This is smart. So you're saying, I don't know what the future looks like, but there's some big, almost macro-y impacts on this local area with the new wind and the nuclear coming off and all this power infrastructure. I don't know what the future looks like in revenues, but I do know that if we put a battery here, it's going to be top of the pile to access those revenues.

Correct. And again, it's an interesting sell to the investors because some people would ask us, OK, that sounds great, and we totally agree with the hypothesis.

I'll put it in a spreadsheet.

ANDY WILLIS: Yeah.

Give us the contract that aligns with that so you get the guaranteed income.

And you can't, ultimately, because there isn't a long term contract to provide those services. So we would do a lot of analysis on the orbs market, reactor power market, what the price is to date, what theoretically it's going to be going forward, and--

QUENTIN SCRIMSHIRE: It's a murky old market.

It's a murky market. You show that to the investors and I guess you want to work with people that hold that same belief, that these batteries can provide multiple services and manage multiple system issues. But again, we try and look at the market as holistically as possible to use batteries to manage multiple areas of the grid.

QUENTIN SCRIMSHIRE: As an aside, my hope is with all this wind, because the wind is connected behind an inverter, that the wind will be able to adjust power factor themselves so we don't have as many reactive power issues on the network. It's my idea. It would take a lot of coordination from National Grid.

I know this kind of goes against what you were just saying, and batteries will play a role in it too. My hope is that we've got so much power electronics connected to the grid through wind and solar that we manage it a bit better and we're not stuck up unity power factor or 0.95 and that's it. Anyway, that's an aside.

ANDY WILLIS: No, and I agree there.

It's an optimization problem we need to solve, really.

It is an optimization problem, and National Grid ran another Pathfinder contracts about a year ago for voltage managements. And one of the winners of that contracts was an off day, so an offshore transmission owner which connects wind farms into the mainland grid so they can use those--

that power electronics to provide that service as, well as batteries or whatever the other technology may be. And ultimately, it's about managing this in the cheapest way possible for the end consumer, whether it's batteries or wind farm in effect.

Absolutely. And then let's talk about the deal, right? Let's finish up on the deal.

What's it like to finally sell the project? Who's involved? I'd imagine there's lots and lots of smart people who come in and say, that's not right, or.

When you're first involved in a deal you're both looking at each other and you're saying, you know, I really like the site. You're very pretty. Everything's wonderful. And then you get into it and the game is to say, well, that bit's not right. That bit's not right. We're going to adjust this. So what's that like and what's the emotions of doing that like?

Yes, it's you run a process where you speak to a few different investors who are interested in the site, and ultimately they want to buy it.

Obviously it's public that we've gone with Gore Street Energy Storage Fund for this first transaction, and they were the first UK energy storage fund. They'd been around in the market for quite a few years. They own quite a few assets in the UK, but also assets in the US and Europe as well so they're a very good, credible counterparty that really know how to build these projects, to finance them, to operate them.

And so naturally they're a great party to go with, but they're going to really scrutinize and review all the documents you're putting forward to them. So these processes take a long time because they're putting their technical advisors to really scrutinize what's in the grid docs, what's in the planning docs, what's in the land docs. And as a developer we need to make sure all those documents are in tiptop condition, that there's nothing the project's going to fall over on.

So how it works in very simple terms is once the fund, the buyer are comfortable from a due diligence perspective, they'll produce a number of reports confirming they're happy and what the potential risks are and pitfalls and everything like that. Then you physically draw up the legal documents, and Gore Street are buying a subsidiary company owned by Kona Energy Limited which holds all the rights to the project, so then they will be responsible for ultimately building that project out going forward.

So the product is in its own limited company and you're just going to sell that. All the rights and everything's in there, in that--

you call it an SPV, right?

Special purpose vehicle. And then they buy that company from you and that's it. You're done. Your baby's gone.

So we have a role going forward with Gore Street in a form of services agreement where it's mainly stakeholder management through to construction of the project. But for all intents and purposes, they're the party with the big money to actually build out this project. They'll obviously reap the rewards of the long term revenue the project makes.

And starting out, it's that temptation of, do you look to raise the money to try and build out the project yourself? But especially at our scale and at this point in time I thought, we don't want to reinvent the wheel. There's people who know this stuff a lot better than we do, have much cheaper cost of capital, so it makes sense to work with a party like Gore Street.

I guess you've got some money in the bank now that you're going to invest in the company and do more stuff. Is that right?

That's correct, Quentin, yeah, and thank you. So we've got a pipeline in development. So we've got a few sites, again, all of similar scale across the grid, about one gigawatt in all. So we're developing projects across the grid. We'll be looking to accelerate those in the coming months and grow the team, as you say, because I've been doing a lot of the work with various consultants in the last few months. But it'll be great to actually-

QUENTIN SCRIMSHIRE: Get some sleep.

Get some sleep. Go on holiday, maybe.

No, you've got to wait a few more years before you can go on holiday.

But it'd be nice to bring in a team as well to initially focus in the UK, and we will be looking at some international markets going forward as well.

Awesome. Awesome. So last thing to ask. Have you got anything you want to plug? So I guess if anyone's listening in here looking for sites they should probably get in touch with you, or is it too early for that?

How does that work? And secondly, is anything you want to plug that you're working on that you think we should talk about.

In terms of plugging we're working on a couple of actual joint ventures with other development companies, some trusted partners there, so we're always willing to work with other development companies looking to develop our projects.

In terms of, yeah, what needs changing, perhaps. I think National Grid is doing a good job looking to introduce a form of queue management in the connections register. So they're looking--

Queue management?

ANDY WILLIS: So going back to that grid connection issues where people are getting, say, late 2030 connection dates. One of the issue is that a lot of people are contracted to connect, but theoretically they might not be doing anything with those sites, but those sites are holding up. So holding tech or holding capacity, which means if you are, say, a battery or a solar project behind them, you can't connect until those projects work out what they're doing.

And at the minute, the way the market works in contracting structure is that those projects can modify that application and push back year on year until--

they might be waiting on planning to come through or funding, which might have taken a few years, and National Grid is trying to incentivize projects that can be built quickly to get online as quickly as possible. So they've been jumped up the queue, basically, or the projects in front of them would be downgraded or perhaps terminated if they've been sitting there for a number of years not doing anything.

So a bit of intelligence looking at the queue of people trying to connect, saying, all right, who's actually going to do it in the near term, and let's prioritize those guys.

In effect. So National Grid will say to those projects that are at the front of the queue but perhaps not doing anything, you have to hit certain milestones by certain dates, i.e. get your planning permission, start construction, everything like that. And if those projects don't hit those milestones they'll, in effect, be removed from that queue, which will mean projects behind that will be able to come online more quickly.

Cool. How do we read about this?

It sounds wholly pragmatic and sensible, yet I imagine can cause quite a lot of--

I imagine it's fairly contentious when you start kicking people out of queues, right? So how do we read more about this and learn more about that? So I believe it's going through a CUSC mod called CMP376.

QUENTIN SCRIMSHIRE: CUSC being the? There we go.

Connection and use of system code, I think. Yeah, we'll have to get someone to check that one. So that's a modification which goes through that code which National Grid are trying to introduce, which I believe is CMP376.

QUENTIN SCRIMSHIRE: 376.

So they are running a consultation on that, or they will be in the coming month or two where industry participants can write in supporting or not supporting it. Naturally, with all these things, it's people that perhaps have a load of connections ready to go now but aren't building them will be potentially annoyed that they're getting shunted back. But I think we have to look about the bigger picture here.

QUENTIN SCRIMSHIRE: Yeah, yeah.

Yeah. We need assets, whatever they are, solar, wind, batteries, that can be built quickly in the current environment should be online and getting built.

Just got to get moving.

ANDY WILLIS: Exactly.

So frustrating. That's great that that's happening. What about on the DNO side? Is there any move to do the same kind of thing for DNOs?

It's kind of all tied together, and the DNOs have already been very pragmatic with their active network management scheme if there is a constraint in the local area to work with, say, the battery provider to try and get them online more quickly. So they're on top of it as well, and I think everyone, both the TOs and the DNOs are aware that customers want to get things online as quickly as possible, the government does, investors. They need to try and solve it as quickly as they can.

But it all relies National Grid anyway, doesn't it? Because of the statement of works process and all of that. I mean, the DNOs are just further down the chain, but we need to go right to the top.

Exactly. And you've heard a few stories where these statement of work processes are taking a very long time to get through, and then, again, you might have the same issue where you can't connect into--

We should do a competition to see who's had the longest connection date.

ANDY WILLIS: Yeah.

I would like to see--

if anyone's listening to this and you've got, like, a 20--

you said 2035. Anything after 2035, let's see it.

ANDY WILLIS: Post below.

Let's see it. Let's frame it and see whether that actually gets built.

All right, cool. I think we've gone well over time, but I love that conversation. I want to say thanks for coming on.

It's been a blast, and we'll put a link to the notes--

in the notes to your website and all the stuff you're working on. And once again, huge kudos in getting the project over the line, and we want to see you do many, many more. So awesome.

Thank you for having me, Quentin.

Thanks for coming on.

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