Project Finance Modelling for Renewables – Webinar with HSF Kramer

Webinar 

In this webinar, Pivotal180 and HSF Kramer discuss the nature, risks and drivers of debt sizing for renewable energy deals, including thoughts on how lenders and sponsors are adapting to the increasing complexity of offtake structures and portfolio financings for solar, wind, battery and hybrid projects. We examine how both traditional and emerging debt structures are reflected in project financial models and contracts, and identify must-have items to include in a best practice financial model that can enable a successful debt capital raise.

Combining Pivotal180’s world-class project finance modelling training and HSF Kramer’s experience advising both lenders, borrowers and government organizations, the webinar explores practical considerations for renewables projects and companies looking to raise debt and the existing and new structures available to them, with examples and tips from experts with real transaction experience.

Webinar speakers are:

• Matt Davis, Managing Director at Pivotal180
• Gabby Herron-Cartwright, Partner at Herbert Smith Freehills Kramer

Video 

Video Transcript 

Transcript: Renewable Energy Project Finance Modeling
All right. We still have a few people trickling in. Great to see. See that number? Keep going up. But a lot to get through in our session today. And 90 minutes. So why don’t we go ahead and kick things off? So hello, everyone, and welcome to today’s webinar on project finance modeling for Renewable Energy. My name is Matt Davis.

I’m a managing director for Pivotal180 here in Australia. Very very excited to be here with you all virtually today. We’ve had, I think, over 600 people registering to attend, today’s session and I see just about over 200 almost now already on the call. And many more are trickling in. So really fantastic to see so many people interested that may get an echo from a lot of people or, that they’re just seeing a comment and echoing.

Yeah, we do have that echo to you. Not to me. Okay. Okay. Yeah, maybe just try resetting that. Does anyone else getting that?

All right. Sorry if that’s happening. If I remember, it seems to be just one off. Maybe try resetting that audio setting. Is there. Okay, great. Thank you everyone. But, Yeah. Great. Great to see so many people interested in talking about and learning about project finance for the renewable energy sector. I’d like to begin today by by quickly acknowledging the traditional owners of the land on which I and all of you and all of us are meeting today, wherever you may be.

Pay my respects to elders, past and present. And I’m very fortunate to be joined today by an outstanding cohost by Gabby Heron Cartwright, from free from Herbert Smith Freehills. Cramer. Gabby is one of the most experienced and knowledgeable legal professionals in the renewable sector, particularly here in Australia, and she’s been invaluable and and helping to put together this event today.

We’ll, we’ll get to our agenda in just a moment. But first, just want to give Gabby a chance to to introduce herself. So take it away. Thanks, Matt. And thank you for having me here today. I’m excited to be talking to everyone about a topic that is near and dear to my heart, which is renewable energy and project financing.

And I’m also sort of excited to learn a bit from Matt around the, the modeling side of things and how all the work that we glorified documentary document monkeys do kind of feeds into into the, the, the nuts and bolts of the, the modeling and the financial side of things. So, I’m a partner at, Herbert Smith Freehills.

Kramer. And, in our project finance team and I focus on, on energy transition projects and renewables is a big part of that. Thanks, Gabby. Anything else you wanted to share about Freehills? Happy to. Or just move along? Yeah, sure. I mean, I think most of you will have heard of us. Energy is a huge part of what we do.

We’ve worked on, if not all, a significantly large number of the renewables projects in the Australian market in some fashion. So, we really do sort of know the sector and know these projects and, and how they, they work. Thanks. And if anyone else have any audio issues do apologize for that. Hopefully hopefully most of you working okay.

We will this we I’ll mention in a minute again but we will record. We are recording today’s session. So if anyone isn’t able to, to make it today or has to leave for any reason, we’ll send it out in a couple of days once it’s up. But we will have a video of this session available to to everyone afterwards as well.

For, for posterity and to to be able to watch whenever you’d like. So really great to have have Gaby here. It’s funny you said you know, a, a document. Mark. Yeah. I often think I’m a I’m a spreadsheet monkey. So we all, we all fill our own roles within this space, and and it’s good to have people with different skills and different backgrounds here.

As I said, my name is Matt. I’m a managing director here for Pivotal180 in Australia. I have been running training programs in project finance with pivotal in 80 for about two and a half years now, but prior to that worked for over a decade in a variety of roles spanning project development, M&A and project and corporate finance, with mostly a focus on the renewable energy sector.

For those of you who are new to Pivotal180 and I do see a number of folks here from from organizations we’ve worked with in the past. We are a global financial modeling, training and advisory business. We provide training and mentoring to to lenders and investors around the world in project finance, in energy, infrastructure, resources, mining and a number of other sectors.

We train professionals, both both new analysts and experienced professionals from some of the biggest energy and infrastructure investors and lenders around the world, and said, really great to see some people on the call today from companies that we train with every year. Great to have you here. Now, some of you may have done some financial modeling training in the past.

It’s something that that hits all of us or many of us eventually in this space. I think what sets pivotal and these training a little bit apart and what we’re going to really try to focus on today versus a lot of other options out there, is that while what we’re running is and what we’re going to talk about today is related to financial modeling and financial modeling, training, our courses and our webinar today focus on much more on than on just the formulas and the shortcuts that you need to build financial models of course we do.

We do teach those things and those are important. But the real emphasis of our trainings and on what we’ll talk about today goes a bit deeper than that, right? We’re teaching not just what formulas you need, but the concepts and the theory, not just sort of the how, but the why behind project finance models, how they work and and the reason for that is so that we can teach our students to build, review, analyze critically, and then make decisions based on those models.

Right. Building a financial model is great, but the purpose isn’t to build the model. That’s not the end goal. The goal is to be able to use that model to inform smart investment decisions and execute transactions. And that’s really the focus of what we teach and what we’ll talk about today. Pivotal180 is fairly new to Australia as a as of late last year.

But as I mentioned, we do work with investors all around the world and our team of trainers like myself have worked on energy and infrastructure projects around the globe. So we’ve seen how things vary around the world based on how different markets operate, particularly in the space of renewables and increasingly battery storage, seeing different structures and how they’re evolving around the globe, some of which we’ll talk about during today’s session.

And no matter the size of your team or where we sit, where you sit, rather, we offer in person, live streamed like this and online only training options, and we can customize those to meet. Meet your needs and your budget. So hopefully you will learn a bit from today’s session. And if you do, while it’s short, if you enjoy the program and would be interested in learning more about financial modeling, training programs for for your team really would appreciate it, please do reach out after the webinar.

Would love to talk about that with you. In terms of our agenda for today, we’re going to start really basic talking about what project finance is not just for renewables but in general and what drives that sizing both why we borrow and how we borrow in the renewable sector, how we’ve done that traditionally, and then we can build up from there to some more complexity.

Gaby will take us through how things are getting a lot more complex or have things have gotten. We’re really in the midst of it now as we move away from sort of vanilla, so to speak, large scale, maybe solar and wind projects to hybrid projects, to projects that have a lot more complexity and potentially risk in terms of how they’re generating revenue and cash flows and therefore how they need to be financed.

We’ll also talk a bit about portfolio financing, how increasingly assets are being funded across across collateralized portfolios, and what that does in terms of changing the calculus on debt sizing and financing and repayment. And then we’ll have a little bit of time towards the end to talk about how all of those things fit into best practice financial models.

What are the things we need to be thinking about when we’re building models in order to reflect this increasing complexity in the space? We’ll have time both at the end and throughout the program. For Q&A. If you’d like to use either the chat or the Q&A to ask questions, encourage you to do that at any time. We may answer some of those in the flow of the conversation, or save some of those answers for the end as well.

And as I mentioned, we are recording this session so everyone will be able to have future access to that once it’s available on our YouTube channel. So with that, to get into the real meat of the discussion, what I’d like to start with, and this might be familiar to some people who have participated in some of our courses before, maybe some of our prior webinars.

I want to sort of actually start with a question that gets at the heart of what we’re talking about today, in terms of how renewable energy projects are financed, because the typical structure for project financing for a solar wind battery hybrid sort of project looks a little bit like this. This is probably a bit simplified, but we have a project company, typically a special purpose vehicle, SPV that owns the project, owns the project assets and contracts.

And really critically, they’re looking to be funded by a lender on what’s called a non-recourse basis. And what that means is that if the project company does not generate enough cash flow by selling energy and or energy services, auxiliary or ancillary services, whatever else it’s generating revenue from and cash flow from to pay its debt service, the lender cannot go to the equity owner of the project and say, hey, I didn’t get enough money, you need to pay me more.

The loan is only recourse to the project company, and the lender or lenders who lend to it will only be able to be repaid by the cash flows that that project company generates. And that seems a little crazy when you think about it, especially when you know that this project company, this SPV, is generally a brand new company that’s been set up just to own this project.

Right? It’s never operated before, it’s never existed, has no employees. And as I just said, is making no guarantee to repay. And on its face, that sounds like a completely absurd structure. But really, that is what project finance is all about. And no matter how simple or complex we get when we’re talking about different project funding structures, we need to start with that understanding and understand what that means around risk.

Risk to the project company and risk to a lender. If you have a project company that does nothing and has no experience except for the fact that it owns this project, it is not set up to manage risks and I’m sure all of you can imagine many, many, many risks that might come along with a typical solar battery, wind.

What have you project right? So what does a project company need to do? The lender is not just going to lend to a project company. It says, oh, don’t worry, we’ll take care of things. They’re going to say, you don’t know how to do that. You’ve got to sign contracts with partners. The kind of things that Gaby helps negotiate all the time.

You got to organize those with partners that can help you manage those myriad risks that might come along with these types of projects for example, going to need an EPC contract with a qualified EPC contractor that can provide certainty of things that are important to the project, certainty of the cost to build the project, certainty of the time to build the project, when’s it going to be built and when’s it going to start generating cash flows are going to need to sign contracts with with, you know, creditworthy and, well known equipment providers, turbine manufacturers, solar panel manufacturers, battery suppliers.

We’re going to deliver the equipment to the project and that the lender can rely on that that equipment will operate properly and be able to generate the cash flows it’s expected to go. I need to sign contracts with counterparties like an owner contractor who can make sure the project is operating properly, and that we’ll know what it will cost to operate, and probably some offtake contracts as well.

Right. What are we going to sell energy for? What are we going to be paid for our energy or our capacity or ancillary services or things we’ll talk about down the line today. We need these contracts, not just these aren’t just things we do because we do them or because it’s normal, but because they help provide certainty of cash flows.

If we’re lending asking for a loan on a non-recourse basis, we need certainty of cash flows to de-risk that loan. And we do that through these contracts with these qualified counterparties that can provide certainty of what those cash flows are going to be in the future, right. All sorts of things that could go wrong when it comes to a project like this and all sorts of requirements that they might have under its various contracts.

For example, if we had just a simple solar project that has maybe a power purchase agreement, a PPA to sell energy, that PPA is going to have all sorts of obligations, like, for example, a requirement that the project be operational by a certain commercial operations date, that it be operating by a certain date, generating electricity, selling electricity, generating revenue and cash flow so that the lender can start to be repaid.

There’s no way that the project company themselves could get that done. That’s why they need their EPC, so they can have certainty of when that project will be built and generating cash flow, and that if it’s late being built, then if the project isn’t built on time, and if perhaps under that PPA there are penalties, we often call them liquidated damages, right where the project company might be liable to pay.

Who knows. Making up a number $10,000 a day for every day. The project isn’t built and operating and generating electricity that the EPC, who was responsible for building that thing? Building the project is actually going to end up being the ones responsible for paying those liquidated damages and maybe even more. Right? What’s the true cost of the project being late?

Being built? Certainly those liquidated damages, but maybe also other costs. What if there’s extra interest expense that’s being incurred because the project isn’t built on time? What if there are operating costs that the project is incurring and it isn’t operating yet? What if about just the fact the project isn’t generating revenues when it was expected to a good financial model can help determine what are the actual costs of the project not being built on time, and make sure that under our contracts that we help, that we negotiate, that the EPC who’s supposed to be responsible for those things, truly is financially very similarly.

Right. We might have a guarantee that the project must be available to generate electricity or provide capacity a certain number of hours a year, a certain percentage of the time we rely on or EPC, we rely on our equipment suppliers. We rely on our own M providers to help make sure we achieve those availability requirements. And we want to make sure that our contracts are set up in such a way that if we don’t meet, if the project doesn’t meet those availability requirements and and faces penalties and or loses revenue because it operates less than expected, that those counterparties will actually be the ones who have to pay for these costs.

Make the project whole, and have as little impact on cash flows on on what the actual cash flows are relative to what was expected as possible. So that’s the aim here, right? We’re trying to reduce volatility and uncertainty of future cash flows via contracts. Because if a lender is going to make a loan on a non-recourse basis, they’re going to want very limited risk.

That’s the only way they can get repaid. They can’t have too much risk here sitting in these project companies, Gaby helps negotiate all these contracts to reduce that risk to the project’s future cash flows. Now, with all of that, right, even if we sign the most perfect EPC agreement and we have the best turbine or panel or battery supplier, and we have a fantastic on them contract and a great creditworthy offtake agreement, right.

There are still some risks here, right? Lenders look to achieve returns, charge interest rates that are above the risk free rate. Equity investors certain equity sponsors certainly aim to achieve returns. Even above that with risk or with with risk comes return. There are still some risks here, no matter what we do in terms of these contracts that exist with these projects.

Right? For example, what happens if, if the climate that’s the climate continues to change, how will that impact the operations of our project? What will the actual quantity or volume of energy that we generate be? What if there are changes in laws? What if there are market shocks like the types that we’re experiencing right now with what’s going on overseas?

What if interest rates change? There are always things that will change that we, some of which we may be able to predict and some of which are sort of unknown, unknown. So we couldn’t even think of in the beginning. And that’s where investors, both lenders and equity are finding that a little, little bit of additional return. Right. There’s as much as we try to de-risk these cash flows and make it safe to invest in for lenders and equity, there are always some risks that remain.

And that’s why these investors can expect to receive some kind of return above, as I said, that that risk free rate, we do the best job we can do our contracts to reduce risk to future cash flows, some risk we can model, some we can’t. So in non-recourse project financing, cash flows are critically important. So the next thing I want to talk about then is what cash flows.

We’re modeling. Right. What are the cash flows that we might see in a typical renewable energy project. And if we think about it in a really basic standpoint, we’re going to have some probably very large upfront construction costs. We do expect these projects to cost a lot of money to build upfront and then hopefully fairly forecast double and and stable revenues and costs over time as much as, as much as they can be.

Right. And that does vary across projects as we’ll get to. These are really long lived projects with really long term contracts. So if we look at this on sort of a simple annual basis here, some really big upfront costs likely determined by our EPC contract and our various equipment supply agreements, the negative cash flow, right, an expenditure and then hopefully fairly steady revenues over time determined by our our offtake agreements, a PPA tolling agreement, maybe merchant energy sales or arbitrage, ancillary services could be very flat, could be variable from year to year and then some cost as well, right?

OpEx costs, insurance costs, O&M costs and things like that, that eat into those revenues a little bit and reduce long term cash flows. But the margins are pretty high here because the upfront cost is so high as well. We’re trying to model these things over 20, 30, 40, maybe even 50 years, depending on the technology, to figure out how much cash flow we expect the project to generate and eventually then how much we can borrow.

And if I take this a step further, we’re thinking about things. Maybe if I split that upfront CapEx into equity and debt, imagine maybe a lender is funding, say, 60% of that upfront cost to build the project. How we’ll get to that number, we’ll talk about in a minute. But just making that up for now, let’s say 60% debt, 40% equity.

And let’s say that loan is going to need to be repaid over 15 years. Well, now every year for 15 years, some portion of that project cash flow, probably a significant portion, is going to need to go to the lender to repay that debt and interest on the debt as well. And that means that the cash flow that equity receives is just going to be whatever’s left over after paying the lender.

Once the lender is finally paid off, once a loan is finally paid off, then equity will get all of the cash flows. But until that point, say 15 years in this example, equity cash flows from the project will be reduced by whatever they need to pay the lender. And when we think about why we need project finance models and why they’re so important, a couple examples here that I think really make it really explain what we use them for, right?

There’s a couple of things or several things, but to really big things that are really hard for us to do sort of back of the envelope or for our brains to sort of wrap our heads around here, right. One is that really long dated projects, as I mentioned? Right. And it’s very common if we have, say, a loan on a project with a ten or 15 or 20 year tenor, it’s very common when we’re looking at, say, cumulative cash flow to equity over time, how much they spent upfront and then how they get that back over time to see equity not even earn their money back until ten, 15, 20 years, maybe some time around when the loan is paid off. Right. The IRR, the return to the equity investor might look great over a 30 year period, but often a lot of that positive IRR positive cash flow comes, say, after year 15 or 20. The hard to get somebody to invest in something like this where they’re not getting their money back for so long unless they could really see it, with some, some specificity and with some precision.

In a financial model, financial models really help us to understand when do we get our money back, how much of our return comes before or after a certain date? And they also help us to really understand the impact of changes in dollars. It can be really easy within project finance to get sort of desensitized to to dollars in project finance.

People will say it’s a $100 million project. Looks like it’s going to cost an extra million dollars, but it’s only $1 million on 100. Who cares? First of all, I think we can probably all agree $1 million is is a lot of money. And if you have an extra million dollars lying around, that sounds like a pretty good thing.

But more importantly, right when I talked about that being this funding here being 60% debt and 40% equity, as we’ll discuss in a minute, that’s going to be largely based on what the future forecast cash flows are, has, most of the time, nothing to do with how much the project actually cost to build. So the project was going to cost 100 and now it cost 101 million.

It’s very unlikely that extra million is going to be split by debt and equity 6040. It’s very likely, in fact, that equity will have to pay for all of that million. Million on 40 is a lot more impactful than a million on 100. What if it was 1090? Right now? We’d be talking about a 10% increase in how much equity is going to need to fund.

Might be a big impact, might be a small impact. But a model can really help us understand what the impact is going to be of any number of changes. And we’ll talk about in a little bit the importance of having models that are flexible and able to run different scenarios and sensitivities and determine the impact. What matters a lot, what doesn’t matter so much in terms of all the things that might change from, say, our base case expectations.

So with all of that, why do we have project finance models? What’s the point of them? And what are we going to talk about in terms of how we build them today? We need these models to align the expectations of the parties involved. Right. We’ve got to predict these cash flows to debt and equity holders over the life of the project.

How much cash flow will the project generate, how much will need to go to the lender, and how much will be left for equity? Because that’s going to determine how much each of them is willing to invest in the project. Certainly an important thing to figure out models can help us quantify risks related to contracts and other factors.

Remember when I talked about those liquidated damages, or how much we need to be willing or able to charge our EPC or O&M if they don’t meet certain obligations under their contracts, our model can help us determine, hey, how much is the actual economic impact of a day or a week or a month of lost performance or delayed operations?

We use our model to determine core debt ratios, things like our DSR debt service coverage ratio that I’ll talk about in a lot more detail here in a minute. Certainly we want to show our returns, but probably a lot more than just returns. Models are about more than a simple IRR or Mo or NPV or some one number right there about making decisions.

We need a model that can not just calculate our returns, calculate the value of our investment, but can present these things for decision making, can go into an investment committee paper, can show upside and downside possibilities and risks and opportunities, and help an investment committee or help an investment board make a decision around whether or not they’re going to invest or how much they are willing to invest in these types of projects.

Building a good model is not just about getting to the right answer, whatever that is at the end, but about showing the project and the work you’ve done in building that model in the best possible light. And it also needs to allow us to compare upside and especially downside scenarios, because the only thing that’s true of every financial model is that it’s wrong, right?

Every model is wrong. Some models are useful. Things are never going to work out exactly the way you thought they would in your project from day one, either your development costs or your build costs, or your revenues, or your operating expenses. All of them will be different than what you’ve expected. The job of your model is to help you understand when that happens.

What will be the impact of that on our returns, on our cash flow, on our ability to pay debt, on whatever is important to your investment. These things can get really big and complex. I’m going to show some really simple models today to get started, but when these things get really large, it can get really easy to sort of lose control of what’s driving it, where the inputs are, where the outputs are, all the calculations, what’s flowing from where to where.

Really important to use best practice modeling and create models that are as simple and easy to follow as possible. Given the complexity of the projects and the contracts that we’re dealing with.

Now, the last thing I want to talk about before I hand it over to Gabby to talk about this newer sort of new age renewable projects that we’re dealing with and financing these days is why and how we borrow money when it comes to renewable energy projects and in fact, not just renewables, but really any type of infrastructure that is funded on a non-recourse project finance basis.

I think it’s important first to recognize why we borrow money in the first place. It’s not just something we do because we don’t have enough money, right? The biggest, most well capitalized investors in the world still borrow money to help fund their projects. And they do that because borrowing money usually hopefully helps increase returns. I had a really simple, way too simple for real project finance example of a project, let’s say cost $100 to build and you could sell it after a year for $109 if you built that with no debt, totally on geared unlevered capital structure, you’d invest $100 of equity.

You’d earn a $9 profit, nine on $100 investment would be a 9% return. IRR is really easy to calculate right on a one year basis. But if instead we borrowed just like in that last example, 60% of that money from a lender, the charges say a 5% interest rate, perhaps a little bit low right now, but varies from from time to time, even though we would have to pay 5% of $60 or $3 of interest, and that would reduce our total profit right from that nine, we would have only invested 40 if equity and $6 profit on a $40 investment is a 15% return.

So maybe sometimes we borrow money because we don’t have enough to fund the project. But largely equity investors borrow money because they can achieve higher returns with debt, with gearing, with leverage. Whichever term you’d like to use. And if that’s the case, we can say, hey, equity investors achieve higher returns with with debt, it’s generally going to be the case that equity investors can achieve higher returns the more they can borrow.

So how much can they borrow? Well, that depends really on three key things that we’ll talk about. One thing called cash available for debt service or CFDs. Debt service. How much we’re actually going to pay the lender each period. And then finally, a ratio I mentioned before, the DSR, the debt service coverage ratio. Now what are each of those things really briefly, Stefan’s cash flow for debt service.

Often you see models that get to EBITDA or free cash flow or net income, whatever it is, don’t care about any of those things here. All of those things allow for sort of fudging what the numbers say. What are we excluding? What are we including here? When I talk about CFDs or CAD, sometimes cash available for debt service, what we’re talking about here, right, is simply the project revenues.

Maybe some investment income. Probably not very much. Maybe some interest on some money in reserve accounts perhaps. Right. And then less the things it cost to run the project, the operating costs, O&M, insurance, land lease, whatever else you got to pay to operate the project. Any money you’ve got to put away into reserve accounts for future expenditures or any actual expenditures you’re making, right?

EBITDA, for example, usually excludes capital expenditures, but it would reduce how much cash flow you have. Simply talking about how much cash flow does the project have that they can use to pay the lender? The lender does not care whether it’s operating income or whether it’s impacted by CapEx or anything else. They just care about how much cash flow there is.

Depending on where you are in the world, you might also have to back out. Cash. Taxes paid in the US and Canada, for example, don’t typically need to do that. More common in Australia and other parts of the world depends often on whether or not the project company is a taxable entity. But that’s really just an optional thing as to whether or not the lenders require that.

But still, does it impact cash flow? It will impact RC fed simply talking about how much cash flow the project generates. That’s the first piece. Second piece, as I mentioned, is debt service, right. What are the things we need to pay the lender. And that’s determined by the interest expense and principal amortization. When I say debt service, I’m simply talking about the combination of those two, the two things we pay the lender and how much interest in principal the lender is paid.

Each period depends on the term or the tenor of the loan. How long do we have to pay the loan back? In a really simple example of a straight line, an amortizing loan, a $100 loan, for example, with a 5% interest rate that needs to be repaid over a five year period in year one. If I had borrowed $100, 5% interest on, that would be $5.

And if I had to repay this loan over five equal installments annually, I need to pay one fifth of that $20 in principal. In year one, I’d have a total of $25 of debt service. Year two, I’d start the year with $80 of that. After paying 20 down in the previous year, my interest would be a bit less 5% of A.T. still 28 principal that service of 24.

And we could just do that every year. This is a straight line example. We’ll get a bit more complex in that in a minute. But all we’re talking about, again, in terms of debt services, the total amount we pay, the lender interest and principal, we’ve got to pay interest on what’s still outstanding on the loan. And we’re going to have to repay some of that principal every year, every quarter.

However often we’re paying the lender. Now, the third piece I talked about before this debt service coverage ratio, this is thing I think people see in models all the time, and they often don’t really think about what it means, but it’s actually really, really critical in terms of figuring out how much money, how much gearing or debt a project can actually achieve.

If I take that debt service from our last slide 25, 24 or 23, right. Principles that were staying the same, but interest was declining each year. And I just put some made up see fads on top of that $6,060 a year making it up right. All of DSR debt service coverage ratio is is has the name sort of implies the ratio of the project cash flow or CF adds to the debt service required.

So in year one, 60 divided by 25 would be 2.4. In year five, 60 divided by 21, 2.86. But it’s worth thinking about what this actually means, right? What does a DSR really mean? Well, imagine in year one I didn’t know what my debt my fads were, but I knew I had debt service of 25, and I knew I had a DSR of one times, right?

If you think about that, it would mean that all $25, that would mean that I had CF adds also of 25. Right. And all of that needed to get paid to the lender. And there was nothing left for, for equity, which A is bad for equity, not getting any cash flow, but more importantly, if things got even $1 or $0.01 worse, there wouldn’t be enough cash flow to pay the lender, right?

The project would be in default of its loan. Meanwhile, a 2.4 times the score means that the project could actually pay this $25 of debt service 2.4 times, as the name sort of suggests, right? You could pay 25 and 25 again, and then 40% of 25 again. I still have enough cash flow to do that. And when you think about it that way, it really shows that the DSR is a measure of the health of the cash flows relative to the debt service.

It’s required to be paid to the lender under the loan agreement one times DSR we’ve got just enough money to pay the lenders. 2.4 we’ve got a lot of buffer, a lot of leeway in what we’ve got to pay the lenders. In this example here, I’m just showing DSR as an output and that is something we will show on financial models.

Hey, after I divide the actual CF as I achieve by what debt service I need to pay, how much extra space did I have to do that? But this is also really important because lenders use DSR to help size debt. They will look at a project’s forecast cash flows in a model and based on the contracts that underlie those cash flows, how much risk or lack of risk there is, how certain those cash flows are, they will actually set a minimum DSR, and that will very largely determine our future debt service and our loan size as well.

So the less risk there is in your project’s cash flows, the lower DSR you can expect to receive from a lender, because they’ll need less buffer, right? They don’t see so much downside or risk in the cash flows. They don’t need 2.4 times buffer. But if you have a lot of cash flow risk, if you’ve got a lot of merchant or uncertain energy revenues and cash flows, suddenly lenders are going to require much higher DSR.

And as we’ll see in a moment, that’s going to reduce our debt size.

Now, more modeling debt. We’ve got to think about a lot of things right. We’ve got to think about the tenor of the loan. When do we need to pay the loan back? Buy. We got to think about cost of borrowing interest and fees and how we’re going to pay the loan back. And I want to touch on those.

And then we’ll talk about how we adjust some of these things for some of these new types of projects. Timing on a loan. Not too complicated, but certainly we need to know the tenor of a loan. Right? When do we start borrowing the money at financial close. And when does it need to be repaid by maturity? Being when that loan is to be repaid by some loans may have something called a grace period, a period where we pay only interest on the loan construction pretty much always like that, but maybe some early period of uncertain cash flows might be interest only as well.

Most of the time project is going to be paying both equity or, sorry, both both principal and interest on the loan at all times. And we’ll call that the repayment period when we’ve borrowed the money project is generating cash flows, and we’re paying both interest and principal on the loan. Timing is really important in financial models. And flexibility is really a flexibility of timing.

What happens if the project is delayed by six months? Well, we need to see what happens when I need to push our repayments back by six months. And one best practice tip that we talk quite a lot about in pivotal one eight training courses is flags using flags, little ones and zeros in our models to help calculate that those timing related things make your model a lot simpler and easier to work with.

Cost of borrowing I mentioned those, there’s probably going to be some costs, always going to be some costs that we need to pay lenders for administrative services, like maybe who knows what the number is. These numbers sort of made up here, but they have cost to administer the loan. There’s going to be some fixed cost from period to period that we need to pay.

But primarily when we talk about the cost of borrowing, we’re talking about interest rate. That interest rate times the outstanding balance each period. That’s the main cost that needs to be paid to lenders. And in our models, we do typically assume that cash flows occur at the end of each period, say, if we’re generating if we’re paying our debt service quarterly, we get our cash flow at the end of the quarter and we pay interest based on the opening balance on the loan.

But the biggest thing we’ve got to figure out is how much total debt service we can pay to the lender each period, and then how that affects the loan size. And there’s a few different ways that alone might be repaid. Right. Different ways loans are repaid in mortgage style. People are pretty familiar with that. We’ll talk about that.

Linear principal amortization, like the example I showed a few slides ago. And then this third option, SCR sculpted. And since I’ve already talked about DSR, you probably have an idea already that that’s going to be the structure we use most often. But what I want to get to is why, again, not just the how do we do it, but why do we do it this way in models that help us to understand not just simple projects, but when things get a bit more complicated.

So a mortgage style or annuity style loan is a loan that’s repaid with with constant debt service every period, right? The same exact principal plus interest, same amount of debt service every period, whether this is annual or quarterly or monthly, every month they pay the exact same amount on my home. What that means that as we pay down the loan over time, we can pay less interest because we pay interest on the balance of the loan, and therefore we can pay a little bit more principal over time, keeping our total debt service constant each period.

If we looked at the cumulative balance of the loan over time, we would see a declining loan balance, right? We’d be paying down a lot more principal towards the back end of the loan. Then in the front end. That’s one way we could repay the loan and not often seen in project finance, but certainly very common in home lending.

We might also have a loan that’s set up with straight line amortization. That’s where we keep the principal component of debt service constant each period. But the interest component can vary as the loan is paid down. We hopefully pay less interest each period, assuming interest rates aren’t moving too far in the wrong direction. And that means our total debt service is actually declining over time.

That’s what we saw in that simple example. I had a few slides back. The nice part of this structure is it’s really easy to calculate any time in the future. How much of our loan will be left outstanding. Right halfway through the loan, half of the balance will be left 80% of the way through the loan, 20% of the balance will be left.

But the thing is, going back to that idea of non-recourse financing, if lenders are only promised to be repaid by the cash flows of the project, what they’d really like to make sure of is that the cash flows of the project sort of have a similar shape to how they can expect to be repaid. Right? And very few renewable energy projects or any infrastructure projects for that matter, out of cash flows, or at least expect to have cash flows in a model that are either totally flat over time or that are downward trending over time.

Right? So neither of these structures matches that those shapes, for example, we know that in renewables we have a lot of seasonality, right? Wind doesn’t blow the same every quarter. Sun doesn’t shine the same every quarter. Very simple example. We might expect to see fads that go up and down from quarter to quarter, as we have more or less expected or actual resource.

And if we had to pay exactly the same debt service every period, like we would with a mortgage style loan, we’d have a DSR bouncing all over the place right? We could either sell our debt service here, and then half the time we wouldn’t have enough cash flow to repay the loan in that period. Or we could set it down here and we’d always have enough, but sometimes we’d have way more than we needed to pay our debt service in each period.

We might also see regular maintenance impacting cash flow on a quarterly or an annual basis. We might see, say, every three years, just making a baby. An extreme example, some big annual maintenance, whether that’s significant CapEx or just having to take the facility offline for repairs, taking a big chunk out of our our cash flow each year. Again, non non-constant cash flows over time.

They’re going to go up and down from maintenance. Inflation could affect cash flows right. Maybe we have a PPA where we expect to get a higher price each year. Maybe we just expect energy prices to increase over time or the value of other things we’re selling from our project to go up over time. Taken altogether, it’s just very unlikely to have a project where we would expect constant flat cash flows from year to year that would be shaped like a mortgage style, or even less likely, downward trend in cash flows over time.

If I layer these things on top of each other again, maybe an extreme example. And this isn’t even looking quarterly. So I’ve taken seasonality out of it, but just on an annual basis, maybe I’ve got generally upward trend in cash flows in my model for my project. And every few years I’ve got some big chunk taken out of the cash flows for maintenance.

If I overlay this with what a mortgage style repayment structure might look like. So my green now is my CFDs and my gray is my debt service, my principal and my interest. If I know the DSR is is CF divided by debt service, I could tell very clearly that my minimum DSR would occur right here in year three, right?

That’s clearly where there’s the smallest gap between cash flow and debt service. Maybe this is a 1.3 times DSR, a pretty common DSR for, say, vanilla, highly contracted renewable energy projects. But in every other period my DSR would be a lot higher sometime, sometimes a little higher, sometimes a lot higher. This gray area, while it represents total debt, service, principal and interest and only principal, represents what we can borrow upfront, that’s what we repay right?

It’s a good proxy for how much we’re borrowing in the first place. The more gray area I have, probably the more I’m borrowing. And if I want to borrow as much as possible, because borrowing money increases my returns as an equity investor, this structure isn’t working for me very well. The lender might say, hey, my minimum DSR is 1.3.

This is fine with me. You’re never below 1.3. But as an equity borrower, I’m sitting here going, man, I wish I could pay more debt service to the lender in these other periods because if I could, that would mean I could borrow more upfront, right? The more I’ll pay you in the future, the more you’ll want to me today.

Pretty straightforward. And there’s just a lot of slack, for lack of a better term with this structure. Periods where we could be paying a lot more debt service and therefore borrowing more upfront. But we can’t because this mortgage style structure limits us to paying the same amount every single period. If we look at a straight line structure, even worse right now, we’ve still got that minimum DSR 1.3 and one.

The minimum cash flow period are slack gets even worse, even less, even even worse alignment between cash flows and debt service even further limiting how much we could borrow. So neither of those structures, while they’d be okay to a lender, they’d say, sure, as long as you maintain that minimum DSR, I’m okay to a borrower. You’re saying these are not letting me borrow as much money as I like, because they’re not allowing me to repay or to pay as much debt service as I possibly can.

How can I maintain a lender’s requirement for a minimum DSR and borrow as much as I can? That’s how we got to the idea of what we call DSR sculpted debt we most commonly do in renewables, and it’s certainly can be get more complex in this. And that’s what we’re going to build up to. We look at our forecast cash flows and our model better our model so important forecasting what those cash flows will be into the future.

And every year or quarter ever. Often we’re repaying our debt service. We divide our future cash flows, our forecast cash flows by our DSR that’s assigned by the lender, maybe 1.3. Right. And that determines how much debt service we’re going to pay. Now we get a 1.3 times or whatever our DSR is in every single period. No more of that slack.

And most critically, look how much more gray area there is here. Therefore, how much more we’re paying the lender and how much more we’ll be able to borrow upfront versus say, this example could not even close, right? We are paying a lot more debt service while maintaining our minimum DSR. In each period, we’re going to be able to borrow a lot more money using this structure.

And that is why because it maximizes the amount that sponsors can borrow to fund their projects, and that borrowing money increases returns. That is why DSR sculpting is the most commonly adopted approach. It helps borrowers borrow as much as possible while maintaining the lender’s requirement for a minimum DSR, based on the risk of the project. Now in formula shape, it looks something like this.

And for those that are familiar with how these models typically work, this will look familiar to you. But if we know that the DSR debt service coverage ratio is the ratio of project CF adds to total debt service principal and interest. If we want to figure out how much a project can borrow, we can move the terms around a little bit, take you back to sort of eighth grade year eight algebra, maybe, and that may be a good flashback or bad flashback, depending on how much you like this stuff.

Rearrange the terms a little bit. I can say my total debt service over the life of the loan will be equal to all my CF adds divided by my SCR, and if I want to know how much I can borrow, right, the amount of principal I repay has to be equal to how much I borrow in the first place.

Lenders don’t like what they don’t get paid back. All their principal B equal to my CF adds divided by middle SCR less all the interest I pay from this I can determine a bunch of things right. I can figure out how much I can borrow, first of all, how much our debt size is going to be once we run it through a model, it’s simply going to be the present value, the value today of all of my future debt service.

I see fads item in my DSR when discounted at the interest rate, and we can see the things that will impact our debt size, right? Our CF fads impact our debt size. The more CF ads I have, the more I’ll be able to borrow. Whether that means I can borrow for a longer period of time or my project generates more cash flow, I’ll be able to borrow more.

If my DSR changes, it’s going to impact my project. What does that mean? Risk impacts debt size. The more risk I have, the higher my DSR the lender will require. Probably, and the less I’ll be able to borrow. If I can reduce risk more through contracts, I can get a lower DSR. I can borrow more. An interest rate obviously impacts debt size.

Every dollar of interest I pay is one less dollar of principal I can repay. Right is a trade off 1 to 1 there and therefore one less dollar I can borrow upfront. So those are the three main things. But the thing is things are getting a bit more complicated. What else could impact these things. Right. This is this idea simply principle is our debt size is cash flow divided by DSR minus interest is how these things work.

But things might break down a little bit or start to break down or require more complexity as projects and the contracts that those projects earn, revenues and cash flow under get more complex, right? Because historically, when we thought about like just large scale, simple legacy renewable solar wind projects with simple, take or pay people for example, we usually had energy supply only contracts, really long term fixed price PPAs with creditworthy counterparties.

Pretty forecast resource estimates. We had a pretty good idea of how much energy we’d get and at what times a day we’d get that from, say, a solar or wind project. And largely we were financing single assets, didn’t have to get too far into looking at multiple assets or how they maybe even interacted with each other. But more and more today.

So we’re getting into, I’ll call the modern renewables era and a market that requires something more complex than simple solar projects. We’ve got to think about a lot more. You might have projects with multiple revenue streams, not just selling energy, but perhaps getting paid just for capacity or for ancillary services. We very often have much shorter term off tax or more merchant arbitrage, energy exposure.

We have increasingly dispatchable projects, particularly battery storage projects. And hybrid projects aren’t just generating energy as the sun shines or as the wind blows, but might be making actual choices about when the dispatch, the energy that they’ve stored. And we’re seeing increasing interest and availability of portfolio financing. And when we’re talking about multiple assets, things get a lot more complex.

So modern renewables financing, while they still start with all those concepts I just talked about and took a little bit too long. So sorry to eat into your time. Agave. I still want to start from that basis, but they are going to by by design necessitate a bit more complexity. So Gaby’s going to talk a little bit about what she’s actually seeing and working with, with sponsors and lenders in this space as we deal with what modern wind, solar battery and hybrid projects and financing look like.

Thanks, Matt. And super interesting going through all of that. I particularly love slide 37 because I think on, you know, as Matt was saying, every renewables transaction we, you know, financing we do the DSR is sculpted and you know that the sky is sculpted because it increases that the debt that you can put into a project. But seeing that, sort of put into sort of, you know, visual form was really striking for me.

I was like, wow. It all suddenly, makes sense. So it’s it’s it’s very interesting. And I think also as you know, as, as Matt was saying, ultimately with, with these projects, the, the sort of the key messages, the lower the risk, the less buffer that you need means the lower the debt service cover ratio you need.

Therefore, the more debt you can borrow and and the more returns that it, that it, you know, available for equity. And that is really why, we are seeing the evolution that we’re seeing towards these sort of modern renewables projects. So, I’m going to talk about sort of four different categories of sort of these what we call, I guess the the emerging asset classes in the renewables space.

And I’ll do it sort of quite quickly. So we’ve got some time to go through the model examples at the end of the session. But I think you’ll get your slides afterwards. And feel free to reach out if you do have questions on, on any of these things. So I’m going to talk about, large scale wind, and then standalone batteries, the sort of advent of the hybrid project, mainly solar and Bess is what we’re seeing at the moment in the market.

And then I’ll also have a little bit of a chat about portfolios and what we’re seeing in that space, which is sort of very active and fast evolving. So to start with large scale wind, you know, large scale, when when we talk about large scale, typically when talking about the projects that are either at or in excess of one gigawatts, of capacity.

So they’re, they’re pretty big. The turbines are pretty big. And so, you know, in terms about sort of trying to shift towards renewable generation, the scale and the size means they give us our best prospect of, achieving large scale renewable generation. But they do come with their, with their challenges. So, you know, the challenges are that the additional technical complexity and in large part that we see from these projects, they’re, they’re very big, the blades themselves are very big.

The towers are very big. So that comes with additional sort of construction risk. The larger turbines typically at the moment still have higher failure rate, than somebody else might smaller turbines as well, which then adds into sort of the risk assessment that lenders are having to do on, on the blades and on the projects and, and what sort of actual sort of generation capacity is going to be and what, what sort of downtime it’s going to look like.

Because of the size, and the complexity, most of these projects are being delivered on a split procurement basis rather than a traditional, EPC trap. The split procurement means that you’ve got multiple contractors under multiple different contracts, and therefore that introduces high prospects of gap risk between those contracts and therefore more risk that may, if you don’t structure your contracts properly, end up sitting with the project.

And as we see here, more risk, sitting with the project ultimately then leads to impacts on your your DSR and how much you can borrow and therefore equity returns. Because of the technical complexity, we’re also seeing sort of the delays in construction and reaching operations are more complex, not only because of the construction complexity, but also around the commissioning complexity.

Getting these projects, you know, connected and actually generating electricity and sort of exporting into the grid. And bigger is but by definition harder to bring on that additional load. And then also, you know, the, the further complexity from a technical perspective is because these projects are so big, they tend to be in quite remote locations.

And so what that means is you’ve got grid connection challenges because a lot of your, your existing grid infrastructure, isn’t of the size, you know, capable of dealing with, with, you know, wind farms of this size and that additional sort of generation. And so you’ve got that sort of grid instability. It’s one of the reasons why, you know, we’ve got the renewable energy zone projects, particularly in New South Wales, was because, you know, your large scale wind resource was out where there was very skinny grid capacity.

And so we’ve had to upsize that and build new grid infrastructure to, to allow these larger projects to come online. Also because of this, the this the size of these, these projects, a lot of them are being built as staged assets. For example, you look at Clock Creek in Queensland, stage one that’s been built. They’re now doing stage twos.

You know, Golden Plains is similar. And then you’ve got, you know, the likes of Valley of the winds, which is being going to be built in all areas, and that’s got three stages. And, and we’re expecting that this will become par for the course for large scale wind projects that will be in multiple stages, just to try and bring something to market more quickly and to address some of the technical complexity that that I was just talking about.

If you break it down into bite sizes, it does remove some of that risk. And therefore overall you end up with a less risky project, even if you do end up with the same, you know, 11. three gigawatts of generation capacity by the end of it. But staging also has risks that come with it, like having multiple connection points that you have to deal with, but which are all kind of closer together.

You’ll also typically then have unless you are doing a portfolio, which we’ll talk about later, you’ll have multiple financings that you have to do. And then, you know, staging assets, not all of the assets, at each of the stages will have their own sort of infrastructure for the whole wind farm. There will be shared assets and shared infrastructure, that is used by all of those stages, some of your substations, transformers, even sort of connection into the grid.

And so that also brings with it additional complexity, particularly where you have multiple financings, multiple lender groups, multiple security packages. And that’s where sort of some of the the financing structures that are quite common in the LNG world, where you have sort of multiple chain projects with, with your shared assets, become really relevant in in this space is, is those sort of financing structures to continue to make sort of the shared asset structure bankable and therefore, you know, maximizing, usability and use of all of the bits of the project.

So you’re minimizing CapEx ultimately, and therefore boosting, boosting returns. Again. One of the biggest complexities that we see from the staged asset piece, which is something that is is being worked through on a number of projects and continues to be an evolving area is around the dispatch Preferencing where you’ve got staged assets or, you know, projects owned by the same people right next to each other.

When it comes to dispatching in the NEM lenders in particular are very concerned about, which of the projects will be dispatched when. And so where it gets complex is if you have different, offtake mixes. So if you’ve got, for example, one project which is fully contracted at 100%, so very de-risked from a lender perspective, that certainty of cash flows, but then it might be sat next to another project which has 40% matching, so higher debt service cover ratios because, it’s a risky, riskier project, but also the potential for upside for your equity is much higher because they can take advantage of merchant pricing for 40% of a project returns

ultimately. And so what that means is if you’re sat there as equity, you’re looking, well, I can dispatch my 100% contracted project into the market. I know what I’m going to make, and there’s no real sort of, upside there. Or I can dispatch my project that has, significant upside, particularly with current prices and so great for equity.

But from lender’s perspective, there’s then that nervousness around the sort of the not the project being the one that is preference. And so that’s something that is, being being dealt with on a lot of these projects at the moment. And then I just thought I’d touch on a few of the additional challenges we’re seeing in large scale wind, as well as sort of the regulatory and environmental hurdles, particularly in Queensland, with the the current government and state of play.

There’s a lot of uncertainty, and these projects just take a very long time to, to come to market. But hopefully that process, you know, a lot of state governments, New South Wales in particular, have been taking steps to try and, improve the planning process and, and bring these projects to market more quickly. But it’s definitely something to be aware of when you’re when you’re looking at at large scale wind and the risks, involved.

The other sort of challenge we see with, you know, with wind farms typically is, you know, the risk in wind droughts, and that is obviously only amplified when you’ve got sort of, you know, size and scale of really big one gigawatt wind farms all in the same area, the risk, you know, and the, the effect of, of not having any wind is going to be more pronounced on, on a project of that size.

And so it’s for sort of this reason that we’re seeing the, the cities in particular sort of capacity investment scheme agreements with the federal government, being really valuable and beneficial to large scale wind because they provide that sort of almost underwrite or insurance project product, to ensure that the projects have that base level of, of revenue, should they need it.

So I think move on now, Matt, to the to the next slide. So we’ve talked about we’re just going to ask actually around especially around those the staged assets. And they said like so a sort of, preferencing dispatch, aside from telling a lender, well, well, why don’t you just finance all of the projects and then you won’t have to worry about that?

How have you seen that? You know, maybe it maybe I said, that’s the easy solution, right? But but what else? What else have we seen? Maybe to try to get them comfortable with that sort of maybe set some requirements, put on dispatch or how how was equity managed to get them comfortable with that and arrangements with equity around dispatch and and sort of dispatch protocol ultimately is, is is where that gap gets to in making sure lenders have comfort that they won’t be, adversely disadvantaged by, you know, timely lending into sort of a project that is less risky from that perspective by definition.

But maybe not as favored in high market price environments. But that’s also why, you know, these sort of multi assets and stage assets. Oh. We’re starting to see more of the portfolio financings in the market because it provides that ability. Which of cross Collateralization if you’re nervous about one asset, why not just lend to to more.

And then you’ll be covered right. And yeah easy easy. So we’ve seen lots of problems. Yeah. There are lots of benefits with large scale wind. But then there are also sort of risks and issue issues with it. And one of those is, you know, we’ve talked about a lot of them and, but, you know, the wind drought situation, the fact that there is no, you know, dispatch is little dispatch ability, comfort around wind, notwithstanding that it does blow at nighttime in a lot of places means that, we, you know, need to look for other solutions in terms of sort of both reducing risk and also providing grid stability that helps support,

you know, new renewable generation. And so that’s where, standalone batteries come in as an asset class. You know, they’re everywhere in the market at the moment. I think most of the project financings that that we closed last year were battery projects, you know, and, and they really do provide in the current market environment, sort of the answer to, to nearly everything.

So, you know, there is that dispatch ability, element to them. They’ve got the ability to, you know, mop up that sort of excess renewable generation in the middle of the day and then dispatch it at nighttime. So it’s helping to flatten that curve. And, and they’re also, what we’re seeing as well, you know, when, when batteries first came to the market, most of them were, grid following.

So they just took power and then they dispatched it, you know, times when, when they beat into the market, but they weren’t really doing anything else. But now we’ve seen sort of a shift to more and more a grid forming, which what that means for those who aren’t familiar is effectively, they also provide system strength, and other stability to the grid, which is now very skinny, very long and increasingly unstable grid is a huge benefit, which is part of the reason why there have been so many of them coming to market is because of this, grid sort of system strength capacity that they have.

And that means also from a sort of a financing perspective, that the grid forming batteries are able to generate revenue from other sources. So it’s not just your PPA who’s providing the offtake of the the electricity. They can also provide sort of the ancillary services in times of grid instability and kick in to help make sure that we’ve got that equivalent of sort of the spinning frequency that, that traditionally your sort of gas, and coal turbines have provided to provide that stability in the market.

So they are providing a very important service while we’re in this transition phase. And then I guess thinking about sort of the the other piece, design and construction with these batteries is, is whether you’re getting an EPC wrap or if it’s going to be split procurement. We see both in the market, and, and sort of, you know, EPC rap so obviously beneficial from a, from a risk perspective.

But there’s a premium that comes with that. And so then that increases the CapEx process and therefore costs and therefore depresses returns. And so we’re seeing a number of sort of equity investors looking at split procurement as an alternative, to that, but at that, similar to what I was talking about with large scale wind comes with its own, risks as well around sort of any sort of risk not being properly backed out amongst the contracts and ultimately sitting with your project.

I would say one other point on this in the market, which goes to the next point we’ll talk about is there some contractors who are ostensibly offering, an APC wrap. But when you get into the documents, it looks a lot more like a split procurement. But not as immediately obvious. And that can also it’s something to be alive to because that can really shift the risk without, parties necessarily realizing.

So in the contract market, many will be familiar with the, you know, the contract to market is has been in a bit of flux in, in the battery sphere. It is it has been narrowing and, and we have seen sort of a few key players, who are sort of becoming dominant in the Australian market. And then we’ve seen others that have sort of gone to the wall, given sort of, you know, global geopolitical, political circumstances.

And so that that also adds a sort of, additional level of risk and focus from, from your banks around the creditworthiness of your contractors and whether they think that they’re going to be there and capable of delivering, the project. And, and then it also means that the contractors that are there that are creditworthy, pushing, much more challenging risk positions from a project perspective simply because they can because there isn’t the broad competition in the market.

So that’s definitely something that we’re grappling with increasingly on, not only on battery projects across the noble space, but it’s particularly felt whether it, best suppliers involved in the projects. And then finally, sort of the biggest thing we’re seeing in batteries is the evolving offtake structures. You know, we the first few that we financed in the market, were all sort of done on physical offtake basis.

So effectively you had a retailer which was, you know, getting the right to operate the project and despatch it as and when they want it into the market for, you year long contracts, they took 100% of the capacity, because of the nature of the contract. And they were sort of seen as, you know, very bankable, low risk contractual structures, provided that lenders were comfortable with the credit of, the off taker.

Increasingly, we’ve seen, a shift towards virtual tolling or revenue swap arrangements. And this is really to cater with the fact for the fact that, there are only so many players in the market who who as an off taker can take on that physical, offtake role. And so, the ability to move to virtual tolling or revenue swaps has sort of opened up the off taker market, and we’re expecting to see more and more of those types of offtake structures coming to market.

And then the other thing that that we’re probably going to see more of, in which the virtual structures allow for is is an increasing, merchant pricing risk and, and merchant risk being taken by best projects because with the virtual tolling or revenue swap, off takers can take a portion and not the full 100% capacity of the battery.

They can take much smaller amounts. And so there’s then that merchant component, which allows for equity to be generating more upside for the project. And so provided that you’ve still got sufficient coverage for your debt, under your contractual arrangements, that’s definitely, you know, it’s something that we are seeing more and more of in the market, but there is a question mark.

You know, batteries are all the rage at the moment. And they do have a very important role to play, in the current sort of transition period. But there is a question mark as to how future they will be as a standalone asset, going forward, because as the grid changes, as our mix changes, there will be only so much access.

Generation in the market to, to mop up, for standalone batteries, that are only capable of sort of, you know, charging from the grid and then and then discharging. I think maybe that mix of sort of and those evolving offtake structure, as you mentioned, really goes back to that question of risk right around how much merchant exposure are lenders comfortable taking, and that trade off that, that equity has around?

Maybe they feel an opportunity to, to leave more of their, of their generation on contracted. But there’s going to be a hit certainly there on at the SR standpoint, if you have too much risk even in some of these virtual, you know, tolling agreements and revenue swaps that, compared to the sort of safer, so to speak, physical arrangement, the lenders at a certain point maybe can’t even adjust, enough for the DSR, but might need some some other restrictions in place or some other sort of repayment structures.

Yeah, that’s that’s right. Matt. And I guess the other thing with, with these sort of these new, sort of offtake structures, the then the credit worthiness of the off takers also becomes a massive focus because they’re not your traditional off takers, and they’re a little bit speccy and so lenders can get a bit, a bit nervous about them.

But one of the things going to DSR that we’re seeing in these projects that that do have these slightly, less physical sort of offtake, and where there’s a portion that’s, that’s covered by a virtual tall or a revenue swap, and the rest is open to merchant that, we’re seeing sort of step, step downs in DSI Oz and other sort of financial covenants.

If they get another offtake. So as the risk profile for the project goes down, the, the DSR then also goes down as well. And that’s sort of becoming a very common feature in those, those types of projects. Right? Almost an ability to upsize the debt as it’s the, as the project is directly over time. Right, exactly. Yeah.

So we’ve talked about wind, the risks with wind. We’ve talked about, batteries. And while there’s a lot of benefits also there limitations. One thing we haven’t talked about which has been in the press, and I’m sure those familiar with renewables will be aware is all of the trouble that a lot of your standalone solar projects have been in, particularly the early stage projects that were built down in Victoria in the in the Rhombus of Regret.

And they’ve sort of suffered a combination of, you know, evils around curtailment, negative pricing conditions, meaning, you know, that they they just weren’t able to generate returns, and have been struggling to meet, you know, the, the Dockers, among many other issues. And so where we have seen the market increasingly move to, to sort of solve these sort of multiple generation issues around curtailment, negative pricing and then also dispatch ability.

Is the the hybrid model where you pay your renewable generation with your best at a co-located location? Most of the ones that we’re seeing in the market currently are solar paired with Bess. Just because they’re sort of a little bit quicker and easier. But, there are a number of sort of high, wind projects in the market that will also have would be best hybrids as well.

So those will sort of start coming to the fore in the next, I’d say 12 to 24 months. Hybrids. There’s a theme here with renewable generation typically, but then generally but hybrids are technically very complex. In addition to all the other technical complexities that you have with, with, you know, batteries or with, generation, satellite generation, you’ve also then got other questions you need to answer around.

For example, how will the two assets be coupled? Are they going to be AC coupled? Which means that you can retrofit a battery onto an existing solar farm, for example. So a viable option for some of those currently challenged solar projects, if, you know, if the money’s there to do that. And then and I see coupling also allows for, for recharging of your battery.

But AC coupling comes with increased energy lost. So then, you know, the other sort of options are you’ve got DC coupling, which is sort of the cheapest option, most economically advantageous for the project. But it does mean that you’re limited because your Bess can only be charged by your connected generation asset. It’s not able to be charged from from the grid directly.

So you’re losing that sort of ability that you would have with AC coupled. And so what we have seen and we’re seeing recently on a couple of projects is, is the next evolution, which is what they’re calling reverse DC coupling. And that ultimately means that you’ve got the sort of economic advantages and efficiencies to be gained from DC coupling.

So you don’t have the the energy losses that you get from AC coupling. But, you can also charge the battery from the grid standalone, even if, for example, the sun’s not shining or the wind’s not blowing, which is, which is a huge sort of benefit for those projects and can still then have the advantage of doing what a standalone battery does in the system, which is mopping up any excess generation that might be anywhere in the NEM.

At a given point in time, even if it’s not exactly where your asset is. And the, the sort of the other piece for reverse DC is, it also allows for more easy expansion of the asset over time. If you wanted to add to it. Other technical complexities that you get with these projects is, you know, whether because they’re effectively two different assets, whether you’ve got a single sort of dispatchable unit identifier that sits behind the meter or if there’s two separately, which, you know, having them separately means you can optimize your assets separately, which is, you know, hugely beneficial, but then comes with additional complexities as well.

And so it’s really these assets in particular, you need to have quite sophisticated sort of partners, operators who really know what they are doing and are able to properly optimize these kinds of assets. And then the sort of final point around technical complexity, and particularly for developers looking to develop hybrid assets to be aware of is around the grid connection challenges and and doing a GPS and remembering that when you’re doing your GPS, you need to do it for both the generation and the the best asset, not just one of them.

And you’ll have to go back and do a separate GPS if you haven’t covered them both. So always something to to remember. As is to be expected, these hybrid projects then come with, you know, additional contracting complexity. You’re highly unlikely to get an APC wrap because you’ve got multiple different, pieces of kit, you know, often from different suppliers.

And then you’re also going to have your sort of balance of plant civil contractor in the mix as well. And so it’s not even it’s sort of split procurement in the case of these projects, often it’s multi, you know, multi contract procurement, which then adds an additional layer of risk around your, your gaps risk analysis and making sure that the maximum amount of, of risk for the project is backed up to the contract as rather than sitting left with the project.

And so that’s why I sort of on these projects that gaps risk analysis and understanding, how everything fits together is, is really important. And then just quickly so I’ve got a couple of minutes to talk about, portfolios, the sort of the offtake structures or hybrids. You know, we’ve seen some where you’ve got the physical offtake, which is obviously the most straightforward option.

We’re also sort of seeing your sort of like standard run of the meter PPA for set periods of time, which works very well for these assets covering both sort of the, the best plus the solar component. We haven’t yet seen any, virtual tolling or revenue swap hybrids, bank yet in the market. But I’m sure that that will come as those contracts sort of become tried and tested in the best world.

It’s only a matter of time until we’ll we’ll find a way of sort of, making them sort of bankable in the hybrid sense. And then there’s sort of finally around the offtake structures is the question mark around how bankable match risk is for these hybrids, and what proportion of the projects you can, you know, lenders will accept being pushed through on merchant, and a lot of that sort of, sort of,

Being aware, like conscious of that merchant element is because of the forecasting complexity that comes with hybrid projects. You know, wind and solar forecasting is quite well established. But how do you, you know, costs for the things like solar plus space and wind plus, Bess, when there’s not really a market for it there yet? And so your market report is really integral.

And lenders have been very focused on the market reports for these projects, even more so than sort of standalone, projects. But there is the question of what is market until we get a sort of a critical mass of these projects that will be probably, a little bit less merchant risk appetite, on those projects. And so again, it becomes really important that you’ve got a sophisticated bidding platform and that you’ve got a really, you know, strong power system controller to make sure that the project can really take advantage of.

Oh, that’s sort of dispatching into the into the grid.

And so that’s certainly a lot, a lot harder than in the days of just taking simple sort of IEA reports for, for solar and wind generation, when you suddenly have to build in actual decision making about when some of this energy is being, being exported to the grid. Exactly. That’s right. And particularly then when you’ve got projects where they are reverse DC coupled, and it’s not just about their co-located solar and what that looks like as well.

It’s a very I wouldn’t want to be a market, model grid with those, but it might be safer to be a market model than an actual asset owner sometimes. I suppose that’s true. Yeah. And so finally, we sort of referred a bit about the sort of the as we’ve been talking about the, the benefits that can be gained in a variety of spheres from, you know, cross collateralization between projects.

And that’s where portfolios come in. And they themselves have been undergoing their own evolution, you know, the traditional ones that, that we worked on, a few years ago were mainly sort of, portfolios being created from, operating assets or brownfield assets that had been previously, project financed on a standalone basis. They then sort of, you know, reached complacent completion, had some sort of operating track record, and were then flipped into a broader portfolio structure.

And so were largely sort of de-risked and fully or, or mostly contracted assets as well. And what those structures involved was, was ultimately retrofit. They were retrofitting a portfolio structure over the top of existing project finance structures from the construction phase. So you ended up with multiple security trust levels because you don’t want to reset all your trust focus, you know, various reasons, including tax and stamp duty.

And so they became, you know, great the owners in terms you could for once you’re operating, you could maximize, you know, leverage and maximize your returns and boost, cover ratios, through a set of across collateralized and therefore largely de-risked portfolio. But you were still, there was just multiple inefficiencies in, in that structure because you’d had to take your, you know, greenfield standalone project to a project financing and then and then flip it in.

And so what we are now seeing come to market is, is these greenfield portfolio contexts. And that’s where you’re doing a single financing for multiple greenfield assets, either, all of the assets are being concurrently developed or being sequentially developed. We’ve seen this in the best space a couple of years ago. And now we’re also seeing it for, for hybrid projects.

And so you have sort of fully crossed collateralized construction risk project from the, you know, portfolio from day one. And those projects might have multiple sort of different, offtake structures. So some of them might be partially contracted or fully contracted or those even might even have some in the, in the portfolio that emergent risk. But because it’s cross collateralized and spreading the risk, lenders are willing to take a, but you know, whole of portfolio view of the assets and therefore what it means, you know, from your coverage ratios is that you are getting, you know, cover ratios more akin to what you would see for a standalone asset on

greenfield asset, you know, project financing, but you’re seeing it across, the whole portfolio, even where you have slightly riskier, from a lender perspective, the merchant matching projects. One of the things we’re seeing in greenfield portfolios that’s, that is a is a challenge is how, you know, a lot of these are being set up so you can bring in future projects to decrease the sort of the, the financing burden for the equity going forward.

But the challenge then becomes, will, how do you set your debt sizing criteria for these future projects that you can bring in? Because there’s so many unknown unknowns, what’s the offtake going to look like? What’s the project going to look like? And so that’s a real challenges is trying to come up with, with parameters that a broad enough, to actually allow this structure to be used and to have that flexibility, but also making sure that that the risk is, is properly sort of catered for.

And then finally, very quickly, we’ve got, know what a lot of developers, sort of aiming for is the, the goal, which is the idea of this operating energy company as, as the portfolio itself, not, you know, maximum complexity, but they’re we’re talking about sort of multiple geographically disparate, just, you know, disparate assets, a big mix of generation storage hybrid, different off takers, potentially different offtake structures or even potentially, you know, large corporate structures where they’ve got their own off taker as part of the corporate group who’s writing the purpose, for their different assets and then sort of backing that out on its, on its own sort of contracts into the

market or even potentially taking sort of the merchant much of risk itself. And there it’s still the goal that these will be you know, single cross collateralized platforms potentially multi source. So you might have some USP issuances or you know, Asian timelines in the mix as well. So bringing sort of maximum flexibility to to these, these assets and the ability to bring assets in and out of the portfolio a bit like your sort of corporates do with their financing structures.

So it’s an interesting time. There’s there’s lots happening. And it is constantly evolving. There is sort of no sort of steady state at the moment. Yeah. Really interesting to see that that happening. And kind of neat to see that one way we can deal with the additional risk of, of these, you know, hybrid and battery heavy portfolios with less certain cash flows as well, if you have financing a bunch of them together, especially with some, geographic disparity and hopefully not too much correlation between the generation or operation of, of multiple assets that you can sort of take what might individually be quite risky cash flow assets and turn the entire portfolio

into something that looks a lot safer. You know, maybe not quite, a single connection point, solar or wind asset, but something that that lenders can get their heads around a little bit more easily. Yeah. That’s right. One question that came in, Gavin, maybe just before, jump into a sort of wrap up here is it around virtual tolling for Solar and Bess hybrid projects?

I think you said you sort of seeing those on the horizon. Is any any thing you’ve noticed or anything you see about whether or not those can work? Or should we be able to work for that type of asset, or is it just come down to how they’re structured? I think it just comes down to how they’re structured.

I don’t think there’s we were talking about this, at each of the last week. There’s no reason why it wouldn’t work. And for, you know, in the context of a solar and best hybrid, you can still have, you know, ultimately, you know, the fixed fee being paid to the project and then the right for the for the off taker to nominate, you know, charging and discharging schedules.

So, you know, from the project for their portion. But it’s really just around, that sort of product coming into the, into the hybrid space, the hybrid market that long. But I’m sure I’m sure it will come as a sort of the the more straightforward, more vanilla of takes get mopped up by projects, it’s inevitable that we’ll move into those sort of more complex models that I’m sure once it’s done once and then it’ll be, be repeated as we see, have you seen also this one just came in, like upfront fees, sort of one off or, arrangement fees increasing where, where these structures get more do they vary

with, with complexity or is that more of a sort of lender based, structure in terms of what they charge upfront? They’re pretty standard, to be honest. I mean, most of these deals are syndicated as well. But there’s there is a tab. I mean, they’re typically, you know, a percentage fee, said the more the bigger the debt, the bigger the fee ultimately.

But yeah, it’s pretty, we don’t see a huge variance in those. Maybe, nothing to get it getting too crazy for super bespoke, bespoke stuff. Yeah. Not for these assets. Yeah. I think you see, like if you have projects where you have private credit debt in the mix, then the fees can start to look quite different.

But we don’t see a lot of a credit in the renewable space.

Got it, got it. Well, I know we’re a little short on time here, and then I’ll take the blame for that one. But but really appreciate you walking us through all of those, just very quickly before the end. And as I mentioned early on, if you have questions afterwards, please feel free to reach out by email.

You can reach me through through the pivotal on any website on LinkedIn, I’m just Matt, [email protected]. But very quickly, right. Thinking about all these things, we’ve got to be able to reflect in financial models. I’ll put this up without reading through all of them. I think the biggest thing to think about, given the way these markets are evolving, the way assets are evolving and offtake structures are evolving, certainly we need clear models and we need logic that flows through and can be followed by somebody when they open the model.

But flexibility is is more important than ever in these models, right? We need to be able to run sensitivities upside downside around what happens when actuals are different from the base case. Because there’s more risk of that than ever. Things are going to vary by more than ever because there’s simply more variables than ever before. It’s no longer just energy and PPA price, but it’s capacity and ancillary services.

And it’s what what are the peak and off peak prices and charging and discharging hours and prices? We’ve got all sorts of different things that that might impact performance. So many more things when it comes to batteries and when it comes to to solo projects, for example, augmentation and CapEx costs for batteries changing all the time. One thing someone said to me recently was, you know, they were struggling with getting the cost of a win project.

Saying it to pencil was, well, what if you could just build a solar and battery project that had enough battery capacity that you could create wind shape from that sort of, that sort of technology? Maybe that would be preferable. Maybe you could build that for less. But being able to to check these things, to see what makes more sense in a given market is really key.

And so a couple of other questions that came up, and wasn’t ignoring these, but saving them for the end. A couple people asked about how say, like more variable cash flow forecasts, right. That does DSR sculpting only work for really highly contracted, very predictable cash flows? And the answer is not necessarily right. There’s all sorts of things.

And this is just a quick preview of some of the the training models we use in our renewable energy project finance and, and advanced, project finance debt courses at pivot 180. But there’s all sorts of things lenders might do or try to do. And then that equity might want to negotiate with in terms of adjusting for riskier.

Right. And a basic level, we simply got cash flows divided by a DSR discounted at the interest rate to get to a debt. But where things get riskier, right. We might see things like gearing limits, like a low standing hey, because of the risk I see in the cash flows, no matter what the present value looks like on a DSR basis, I’m going to limit you to say 60% or 70%, or maybe even 50%, especially for highly merchant projects, battery projects of the total cost, not borrowing more than that, making an adjustment and having your model able to adjust between a cash flow based debt sizing and a loan to value, say, type of debt

sizing, and then possibly even then, adjusting your repayments something you’ll need a model to be able to be able to do multiple DSR as to be talked about, whether it’s from multiple projects, different offtake structures, merchant versus fully contracted, even contracted differently between physical and virtual tolling agreements, often seeing projects with two, three, 4 or 5 different revenue stack.

Structure pieces. Each of those might be treated differently by a lender, and being able to incorporate multiple DSR on those multiple cash flows is going to be really important. And especially as batteries, more and more, I’d say maybe merchant appetite for batteries coming into play. And to those questions that came up around debt repayments or we’re starting to see maybe less.

So I think fairly new, in the Australian market, but probably growing at something. We’ve seen, on some projects in the US and Europe, that I’ve worked on is a structure where we sort of combine the worlds of the SCR based sculpting and more sort of, cash sweep, performance based repayment. One thing we’ve been talking about quite a lot with folks struggling with these sort of, merchant battery projects is structures where we size loans based on a cash flow forecast, but then where repayment, rather than being totally fixed based on a DSR, if we know that we’ve got a battery project where cash flows might vary pretty significantly from

from quarter to quarter and year to year, we’ve seen structures where more of the payments are pushed towards towards cash sweep. So when the project performs better, has a great quarter, a lot of opportunity for arbitrage revenues and ancillary services revenues. For example, we might see, some proportion of that cash flow be paid in repayments instead of having it be sort of a fixed structure where we see our might see our DSR bouncing all over the place.

Great quarter, we’ve got a DSR four, and then the next quarter is a leaner quarter and the DSR is under one or even even negative. So lots of different structures. And I think the key thing here is building any one of these takes a lot of thinking through how would, how do I adapt my, my sort of basic vanilla, the SCR sculpted structure for this component or for this structure that my lender is requested or acquired?

Having a model that can do all of those so you can compare different, different options. And then also when you see, for example, hey, the lenders requiring this covenant. But when I do that I get to a DSR of six, for example, something we saw in a project we worked on recently, an output DSR. Is that really something they need, or is that something I can push back against and I think if you don’t have this a model that is this flexible, it’s really difficult to say, well, when I looked at this, to go back and push back against some sort of lender requests and requirements.

So just an example here of a few different things you might see in terms of gearing limits, multiple DSR and policy. We haven’t had a lot of time to dig into these in detail. These short sessions, don’t allow a ton of time for that, but all sorts of different, flavors and, and flexibilities in debt financing and debt sizing that you might be able to consider, depending on the complexity and the contract structure for your assets.

Now, I know we’re over time. Really appreciate, so many people joining today, an awesome audience. As I mentioned, the video will be available soon, and I’ll send you everybody who has registered. We’ll get an email letting you know when the video of the session is available. Please reach out to us if you’ve got any further questions. Beyond this session.

Always happy to answer those and also talk about how this sort of stuff, whether it’s on the contractual side or when it or as it relates to the modeling training, could be helpful for your team and put together something that works really well. We do have a couple of, programs coming up, a renewable energy project finance modeling course coming up in a couple of weeks, or we’ll cover a lot of these topics as well.

If anyone’s interested, please reach out. And would love to, to talk about what’s most important to your teams and what you’d like to learn as you’re developing and financing projects. Gabby, anything else you’d like to add before we wrap it up? No. No, that was great. Thanks very much, Matt. Thanks so much, everyone, for joining. For those that put in questions, I will hang on here at least to answer some of them, by typing.

If I don’t get to all of them, I’ll try to get to you via email. Thanks everyone for for being a part of it and hope you have a great rest of your Monday and a great rest of this, short holiday week.