Project Finance and Renewable Energy PPAs -Webinar with Adarite Legal

Webinar 

Presented by Pivotal180 and Adarite Legal 

 

In this webinar, Pivotal180 and Adarite Legal discuss core project finance concepts along with structures and risk considerations for PPAs, with a focus on the Australian NEM. We then explore the intersection of project finance lending and PPAs, examining how PPA terms and risks can impact loan terms and project returns.

Power Purchase Agreements, or PPAs, are the most common contracts for buying and selling power generated by renewable energy projects. As such, PPA terms are the major determinants of revenue and cash flow calculations in project financial models. Project finance banks closely evaluate PPA cash flows and associated risks in sizing and structuring their loans. PPAs come in many different shapes and sizes, with common structures and requirements varying significantly around the world. Australia’s National Electricity Market (NEM), in particular, has specific rules which dictate how PPAs may operate, with many terms which can be negotiated between energy buyers and sellers. 

Speakers are Matt Davis, Pivotal180 and Graeme Dennis Principal Adarite Legal

 

Video 

Video Transcript 

All right. Why don’t we go ahead? Thank you. Everybody who, who has joined us here today. And welcome to Pivotal180 and Adarite Legal webinar on project finance and renewable energy. Before we begin, I’d just like to take, a couple of moments. First, to acknowledge the traditional owners of the land on which we meet, where all of us sit today and like to pay my respects to elders, past and present.

And I also feel I’d be remiss if I didn’t take a moment, today, particularly for those of us in Sydney and around Australia, to acknowledge the events of, of last night embody, I hope that hope that each of you, your friends and loved ones are safe and wishing all of the victims their peace and healing in what are sure to be very difficult days to come.

I want to take a quick moment then to introduce your presenters for today. So my name is Matt Davis and I am a managing director for Pivotal180 in Australia. Pivotal180 is a financial modeling, advisory and training firm, and we deliver both online and in-person training globally, including public and in-house courses. And we provide consulting and mentoring to modelers, advisors and investors in the renewable energy and infrastructure space.

I’m joined today by or by Graham Denis from Adarite Legal, and I’ll have Graham introduce himself. I, I’m a lawyer, a specialist in energy law. Well over 30 years experience in energy markets, energy trading and energy regulation. I’ve done a lot of pieces in my life, and other, connection agreements and other contracts around energy projects.

Thanks, Graham. And very happy to, to be doing this with you here today. I appreciate you being a part of it. I guess I should say that aside from aside from training and prior to my time, Pivotal180 have also worked in project finance and project development in the renewable energy and power sector, both in Australia and in the in the United States.

So a bit of experience of what we’re talking about today and very excited to to share a little bit about, both my expertise and Graham’s with each of you. Hopefully you find something useful to use in your own work.

Very quickly, an overview of our agenda for the next 60 to 90 minutes. So we’re going to be combining here in this conversation aspects of things that are important for project finance and how we raise financing, equity and debt for renewable energy projects. And we’ll start by talking about how project finance works, its corporate form, and the allocation of risk to all parties in those transactions.

I’ll talk a bit about the importance of cash flow forecasting as it relates to project finance, and in particular for a non-recourse project financing, which is the most common type. Then Graham will speak quite a bit extensively about different structures and risks for renewable energy PPAs. In particular, we’ll focus on the Australian energy market and the national energy market, or sorry, national Electricity market rather than the NEM.

And talk about different types of people’s different ways that projects can earn revenues and the various risks and opportunities involved there for projects today. And then we’ll bring that back full circle and talk about how choices that might be made in developing projects and in structuring and negotiating power purchase agreements, PPAs for renewable energy projects impact those projects ability and success in raising project finance, debt and eventually impacting returns to equity investors.

At the end, we should hopefully have some time for some Q&A for those on the line. You all should have access within the platform here on zoom to put the type in questions in the Q&A box. If you look at the pop up at the bottom of your screen, you should see a Q&A option. Please feel free to submit questions throughout the session.

Questions that we see there we may answer as we’re going through it, if it’s relevant to the conversation. Or we can, get to some at the end as well. So with that, a lot to cover within the next just under an hour and a half now. As I mentioned, I want to start really by by sort of asking a question.

And that question could be asked in a couple of ways that maybe the simplest way would be to say, well, what is project finance? But maybe in a bit more detail. What I’d like to ask is. If I if it were to present you a scenario where I said you had a project, a solar project, battery project, wind project, and you set up a project company to own that project.

Within typical project finance, we have a concept that we call non-recourse financing. And the idea there is that while we have an equity owner, developer, IP project operator that owns the SPV, that project company, the goal is to raise that often. And we’ll talk about why we why we want to raise debt, but to raise capital and receive a loan from a bank or other lender, a, you know, sophisticated financial institution.

And really critically, the aim is to raise that capital, raise that debt on what we call a non-recourse basis. And what that means is that the lender is going to make this loan to the project company, to the solar project or battery project, or the company that owns that, and that loan will only be paid back, is only guaranteed to be paid back by cash flows that the project company via the project generates.

In other words, if the project company and the project doesn’t generate enough cash flow to repay the lender their capital plus interest, the lender has no ability to go to the owner of the project, no matter who that is, no matter whether that’s Bill gates or the King of England or anyone else and say, hey, your project didn’t pay me enough money to pay me back the rest of the lender’s money, and their loan is only secured by the project cash flows.

And so maybe as a broader question I want to ask is how can you convince somebody, a sophisticated financial institution, to lend or invest millions or even billions of dollars in a project company and a project that has never operated before, never existed before? The project company likely has no employees, just been set up to own this project and really critically, is making no guarantee to repay the loan, right?

Only if the project generate enough cash flow will it repay the loan. And in a nutshell, that is really what project finance is all about, and in particular what we use project finance models of the type that we talk about and teach at Pivotal180 and the contracts that we negotiate in relation to these projects are really designed to enable because for, say, a typical solar or battery or maybe co-located project, there’s all sorts of risks that might exist, right?

All sorts of things that could go wrong with a project and might cause it to not generate as much cash flow as expected, or possibly even cause it to not generate any cash flow whatsoever. And if the lender is concerned about those things, if they’re too concerned about those things, and you can imagine they’d never be willing to make that sort of investment a significant investment in that type of project, where there are significant risks to the cash flows that are going to repay them.

Now, the project company itself, as I mentioned, no operating history, no employees. It doesn’t have any ability to manage the many, many risks that might exist with an energy project like that. And so as a result, what it wants to do or what what the sponsor, what the equity owner of the project needs to do on behalf of the project company is enter into contracts with qualified counterparties who can help to create certainty and mitigate the many risks that go along with these projects.

For example, making of, say, a battery project right? Some things that the lender might be concerned about are what is the project going to cost to build, or how long will it take to build the project? When will the project be built? A project company can enter into an EPC contract with a qualified builder, qualified engineering company that can guarantee the cost to build the project and guarantee the timeline to build the project and guarantee that the project will be built and operating by a certain date, at the cost that is expected of the owners and the lenders.

Another question that lenders might have is what’s it going to cost to operate the project if they’re only going to be repaid by cash flows of the project? Can generate, they certainly are going to care what the cost to operate the project over time are going to be. There could be many costs operate a battery project or a solar project.

One of them could just be simply the cost to maintain the project, to fix things when they break, or to proactively service things so that they hopefully will not break up. The project company is going to need to enter into a contract with an O&M contractor, right? Somebody who provides operations and maintenance services to the project, and that own contractor can provide a guarantee of what it will cost to operate the project.

So there won’t be any cost blowouts that might otherwise, you know, unexpectedly reduce project cash flows. They can also guarantee things like availability. They can provide guarantees of the project will be available to generate electricity as much as possible, or as much as as as is expected in the contracts and in the financial model. Our focus today is going to be on the other side of this sort of limited diagram here on the offtake side, projects very commonly solar battery, other energy projects enter into power purchase agreements or other offtake agreements with a counterparty that is going to purchase electricity or purchase other things so that project might generate.

And that’s important because that’s going to drive the revenue of the project. Probably the number one driver of cash flows of a solar project or battery project is going to be what are the revenues? And it’s very difficult or maybe even impossible to accurately forecast the cash flows of the project in the future. And the revenues of the project in the future.

If we don’t know what the project is going to be paid for the energy that it produces. So we often enter into a PPA or other offtake contract to provide certainty of price certainty. A price is going to be paid for energy for every unit of energy that’s generated by the project, and that can go a long ways toward de-risking the revenue that we expect the project to generate, and therefore the cash flow that we expect the project to generate, which the lender is able to be repaid by.

Now, there’s all number of risks that might come into play when it comes to a typical energy project. But for example, if we’re thinking specifically about people’s power purchase agreements like Gram, we’ll talk about PPA. Typically are very long documents as gram get into and they have all sorts of obligations on the project company. Right. The buyer of the energy that off taker wants some guarantees about what they’re going to receive under the contract.

So for example, the PPA is probably going to specify a required commercial operations date, a date by which the project must be placed in service. Well, thinking back to that chart on the prior page, who can provide certainty of that of the project reaching a certain Cod commercial operations date? The EPC contractor might need that EPC contract, so we know the project will be operating by a certain date, and we want to negotiate that EPC contract such that if the project isn’t built on time, the EPC contractor will be the one financially responsible for it, right?

If the project company is going to owe liquidated damages or other penalties if the project isn’t built on time, let’s make sure the EPC contractor is the one that has to pay for those things and any other costs or losses that the project incurs as a result, so that there’s no impact to the project’s cash flows. If the project is late being built.

Similarly, the project might have a requirement that it is available to generate electricity or provide electricity. Capacity is Gram. We’ll talk about a certain percentage of the time or some sort of minimum delivery of electricity. Well, we rely on the EPC to have built the project to a certain standard. We rely on the O&M contractor to keep the project operating as well as possible.

We can’t depending on the type of technology, solar or wind, we can’t guarantee the sun shining or the wind blowing, right? But we rely on the contracts and on our contractors are qualified counterparties who are equipped to manage these things, to help us make sure that the project will be available as much as possible, we’ll be able to generate the minimum required delivery of electricity and avoid any penalties.

And if they can’t, we want those penalties effectively to be passed on to the counterparty. We want it to pass that risk too, so that again, there’s no loss in cash flows. Otherwise, that’s a risk that the lender might not be comfortable taking, might be very difficult to have our project finance. And in a moment we’ll see why it’s important that we get these projects finance or why we want to raise debt from lenders and therefore need to to mitigate these risks.

Overall goal here, right, is the project which might otherwise. But project company on its own might have trouble doing this. It’s trying to create certainty of cash flow through contracts and credit worthiness. Right. We’re going to need certainty of cash flows if we’re going to convince a lender to make a non-recourse loan to the project, and we do that through these contracts with our counterparties, with creditworthy counterparties that we can depend on to make sure the project will generate as close to the cash flows expected as possible.

Now, we can’t be perfect here, right? We can mitigate the risk of the project being late being built, or the cost of the project blowing out or operating costs blowing out, or the project not being available to generate electricity as much as is expected through our contracts. But there might be still certain things that are very, very difficult to mitigate, right?

For example, what if we have these great contracts but one of them fails, our O&M contractor or our PPA off taker goes out of business or what if what if the project simply produces less energy than expected? Because, as I mentioned, the sun doesn’t shine or the wind doesn’t blow as much as possible? What if there’s a change of law or regulatory standards within the electricity market?

There’s always gaps. There are always things that we might not be able to mitigate via contracts. And in a way, it sort of makes sense, right? Because investors in infrastructure projects, while not expecting perhaps the sort of large scale returns of maybe private equity or venture capital investors are looking to achieve, do expect to earn returns above what we might think of as the risk free rate of return, and that means they’re going to need to take some risks, take some limited risks in in in order to achieve some return above, say, a risk free rate.

There are always gaps. We try to mitigate as many of these risks as possible via our contracts, but there are always things that remain, maybe things that we can think of, like what if the sun doesn’t shine as much as we think? Maybe even things that we can’t think of, like regulations or laws that could change we never could have imagined.

And as a result, both lenders and equity do still expect to achieve some some return right above what they may be able to achieve on a risk free basis. Still, though, we want to mitigate risks as much as possible. We do that through our contracts like the PPA is at Grand. We’ll talk about in just a few minutes.

Now, going one step further. Right. We want to mitigate these cash, these risks and the cash flows. We want to provide certainty of cash flows. And then we need to be able to model these cash flows to forecast these cash flows and forecast them in a well built, best practice financial model that we can share with our financing counterparties like our lenders, and convince them that of what our view of the future cash flows is relatively accurate.

We’ll never be perfect, but relatively accurate and convince them that there’s limited risk to those cash flows. And we think about the cash flows that we might model in a typical financial model for, say, a solar or a battery project. What are we talking about on a very a very high level. Right. We’re going to have some very large upfront construction costs and then hopefully fairly steady and predictable revenues and cost as much as possible, probably very steady and predictable in our model.

Only thing that’s true about all financial models in reality is that they’re wrong. They’re they’re a forecast of what might happen in the future. But we would like to have as little as little variation, hopefully from year to year. And certainly as much predictability as possible in these cash flows. And these are really long lived assets, 20, 30, maybe even 50 year assets with really long term contracts.

Thinking about this, maybe on a simple annual basis over time, what are we talking about? We’ve got some large upfront costs, right? And negative cash flow and investment. The CapEx of the project largely dictated by that EPC contract. We need that EPC contract. So we know what that upfront CapEx is going to be, hopefully fairly steady revenues over time, maybe not exactly the same each year as we see here, but something like that, certainly predictable that revenue dictated or or predicated upon our offtake contract, our PPA agreement, and then hopefully also fairly predictable and steady costs over time that might eat into the overall cash flow, our revenue less, our costs being the projects overall

cash flows dictated by our O&M contract, our other project operating contracts. Again, you can see how these contracts that I talked about are helping to provide certainty of the cash flows we’re going to expect in the future, and that we can share with our lender by our financial model. Now, if we take this one step further. Let’s say that that upfront CapEx, that upfront expenditure of the project was funded, say 40% by equity and 60% by debt.

I’ll talk in a minute, a little bit further about how we might get to those sorts of numbers, how we would figure out how much debt we could achieve for a given project. But for now, let’s just take that as a given. If we have a loan in place to help finance a portion of the project, 60% in this case, that means we’re going to have to pay the lender some debt service over time.

We’re going to have to pay them interest and principal return of their capital on their loan. And let’s say it was a 15 year loan, we’d have to pay them some debt service every year. And that means that during the term of that loan, the time when that loan is still due to the lender, the overall cash flows that are available to equity are going to be reduced, right?

Equity is only going to receive whatever is left over after the project’s cash flows are used to, at least in part, pay debt service the interest and principal due to the lender. Once the loan is paid off, equity will receive all of the cash flows, but equity doesn’t get paid until after the lender gets paid.

And project finance models can, which are based on our contracts like our EPC agreement, our PPA. They’re really, really helpful, well built financial models for evaluating projects and for understanding a few things that probably our typical human brains might, might struggle to, to deal with. Right? One of those is time and again, these are really long lived projects with really long term cash flows.

And it’s very common to see, for example, in a typical solar or battery project, the equity investor not maybe get their money back for many, many years, right. If they might have invested, if this was a $100 million project, investing $40 million might very commonly not see equity get that $40 million back for 1015. However many years, often maybe around the time that the loan is repaid.

One thing that a financial model that is designed in line with our contracts can really help us understand is say, when will we get our money back? When will we break even in our investment? How much of our of our cash flow will come while we’re paying off the loan? Or after repaying off the loan, or before or after things like our PPA have expired?

That’s a very difficult thing to do. In the absence of a well built financial model. And another thing it can really help us to evaluate is dollars, right? We can become very deep the ties in the infrastructure business to large numbers. We say, oh, $1 million. What is $1 million difference in the, let’s say, the cost of the project?

We’re going to be 100 million and now it’s 101. Who cares? It’s only $1 million. Well, it’s important to put that into context, right. In this example, with equity funding, 40 million of 100 million, if the lender or if the cost of the project goes up by $1 million, as we’ll see in a minute, the lender is very unlikely to help pay for that extra million dollars, even if they’re splitting this 160 40.

What we’ll see in a minute is that the amount that the lender is willing to lend to a project generally depends entirely on the forecast of projects cash flows in the future, right? What cash flows it will generate from its revenues, less its costs over time. If the project suddenly costs $1 million more. But the forecast of cash flows remained unchanged, the amount that a lender is willing to lend to that project is likely to be unchanged.

And now we’re not really talking about a 1% change in terms of equity costs, but a 2.5% change right from 40 million to 41 million. And imagine if the lender was providing 90 million in equity, only ten. Now we’d be talking about a 10% change from 10 to 11. Equity would be funding all of these excess costs. Again, why is it so important to have these contracts?

That could cause a pretty big difference, pretty big impact on equity returns. And so with all of that, right, why do we need financial models, the kind of which we are talking about today and that we we train people on at Pivotal180 well get really long lived, complicated project with long life cash flows. We’re aligning the expectations of a lot of parties.

We got to predict our cash flows, both to equity and debt for a long period of time and provide certainty of those cash flows. Convince a lender that is risk averse and doesn’t want too much risk in the cash flows they might be repaid. With that, there will be significant or sufficient cash flows to repay them over time, because that’s going to determine for us how much each party is actually willing to invest at a simple level of project finance can be broken down to something as simple as the more cash flows I’ll receive in the future, the more I’ll be willing to invest in the project today.

And our financial model can help us predict what those are. Our model can help us quantify risks related to the project. What will it really cost us? If the project isn’t built on time? Will it really cost us in terms of lost cash flow or other penalties if the project isn’t available to generate electricity as much as expected?

Our model will help us determine core debt ratios. I’ll talk more about that in a minute, but that’s going to help us understand how the project is performing, and it’ll certainly show our returns. Right? Never see a financial model doesn’t include some expectation of equity returns. We want to see those in our financial models as well. Perhaps more than anything, our financial model, a well built one anyway, can present outputs that we can use to help make decisions.

What are our returns? But what are our risks? Right? What is the worst case scenario and the best case scenario for our project? How do we show the work we’ve done, show our project in the best possible light, and make it relatively easy? Anyway, for those that need to to make a decision on investing in a project and financial model is very much, I like to say, garbage in, garbage out type of tool.

If you have a well built financial model, but it doesn’t match the terms in your project contracts like your peers, well then it’s not worth very much. We’ve got to make sure those things are aligned.

Now, the last thing I want to talk about before I toss it over to gram is why we borrow money in the first place. Because I think sometimes in project finance, we take it as a given that projects will raise debt. But it isn’t quite as simple as we raise. We raise debt because we want to, or perhaps even because we don’t have enough money to pay for a project.

One thing we talk about a lot and people don’t want to do classes is why we borrow money and what we call that, say, the benefits of debt or the benefits of gearing or or I’m from in the US, benefits of of leverage, depending on where you are in the world. And in a really simple example of two simple for for real project finance modeling or real project finance transactions.

If we took an example of a one year project that cost $100 to build and could be sold after a year for $109, if that was built entirely with equity money, then clearly there’d be a profit equity of $9 109 -100. They invested, and on a one year basis, returns are easy to calculate. A $9 profit on a $100 investment would be a 9% IRR internal rate of return, but a levered or geared basis, let’s say we could achieve like I had in the prior example, 60% debt.

So we’re getting 60 of our $100 from a lender. If they were to charge us, say, a 5% interest rate, perhaps a bit lower than market rates right now, but not too far. And the example would hold, let’s say, 6 or 7%. Now, while we’d still make the nine same $9 profit on exit, there would be interest expense of $3, right?

5% times that $60. That investment. So equity would not receive nine anymore. They’d only receive $6 after paying that interest. But now equities only invested $40, a return of six on an investment of 40. Well, that’s a 15% return. And so we don’t just borrow money because we don’t have enough, because we want to borrow money because it was just handed down from on high.

We borrow money for project finance transactions because equity investors achieve higher returns with debt, with higher gearing. And if that’s the case and there are exceptions to that, but in general, that is the case, then we need to know how much debt, how much gearing a project can achieve and how much debt a project can achieve. Really depends on three core things.

The first is something I’ll call Cads or cash flow available for debt service. The second is how much debt service the project has to actually pay, and the third is a ratio called the debt service coverage ratio, or DSR. That last bit is very closely related to GPA terms and to risk related to a project. And I want to quickly talk about all three.

And then we’ll talk about different PPA types and eventually how they might impact these things.

So the first of these Cads cash available for debt service, really, really simply for most projects in Australia as well as in North America, we have something called pass-through entities, which really just means that the project company itself is a does not pay tax. We’re talking about the revenues. The project generates less any cost, right. Maybe there’s a little bit of interest or investment income.

But what revenue to we generate probably via a PPA. And then what costs are there to operate the project? Our O&M, our insurance, our lease? Do we need to put any money away into reserve accounts right for future repairs, or do we need to perform any repairs or make any major capital expenditures? Those are important too. We’re not talking about EBITDA or net income or anything like that, purely how much cash is there available that the project generates and that could therefore be used to pay the lender in some countries that don’t allow for taxable entities, or if the project company does have to pay tax.

The only difference is that sometimes we need to deduct cash taxes paid from those cards and in general really high level, not not difficult to think of or simply talking about. How much cash is the project having its bank account at the end of every, every year, every quarter, every month that can be used to pay the lender?

How much has it generated in that period? That’s our Cads. That’s our first piece of how much we can borrow. The second piece of how much we can borrow is debt service, right? And when I say debt service, I’m talking about the money we pay the lender. And really they’re talking about two things interest expense, interest that we pay on what we’ve borrowed, and principal amortization, repayment to the lender of the amount that we’ve borrowed, how much interest and principal we have to pay them.

Each period is going to depend on the term of the loan, how long we have to pay them back, a really simple example. And that service is just going to be the sum of those two things. Imagine I have a $100 loan with 5% interest that needs to be repaid over five years, with that principal repaid in five straight line or equal installments each year.

I could calculate my total debt service by first calculating my interest as my opening balance times my interest rate. So in year one, $100 times 5%, $5 of interest, and then my principal, if I’m repaying it in five equal installments, that’d be $20 a year, $100 divided by five. That’d be $25 of debt service in year one. The end of year one, I’d have $80 left.

I’ve paid back 20. Year two, I’ve got $80 to start, so I owe a little less interest right now on the interest on the 80 that’s left to repay. It’s still got to pay 20 of principal. Same amount, $24 of total debt service in year two. And we could continue on through the end of year five. Very very simplified example here.

Simply pay interest on what we on the remaining balance of our loan, and we pay principal according to some schedule in this case, a straight line, simple linear schedule of repayment. So why do our cards then and our debt service, the amount we have to pay impact how much we can borrow. But it comes down to this third thing called the DSR or the debt service coverage ratio.

Imagine I have that same debt service from the prior slide 25 million in year one, going down to 21 in year five is I pay the same amount of principal each year and a little bit less interest. And imagine I had cash flows or cards of $60 million a year. My DSR, my debt service coverage ratio is just the ratio of Cads to debt service.

So 60 divided by 25. In year one, my DSR would be 2.4. In year 260 divided by 24 my DSR would be 2.50.

And that raises the question of why do we what is this thing? Have I just made this up? What is this debt service coverage ratio? Why do lenders care about that? Well, if you think about it right, imagine that in year one we had 25 million of debt service. And we knew we didn’t know what our cards were, but we knew that our DSR was just one times 1.00 times.

Right. Well, that would mean that we had 25 million of cards, 25 divided by 25 equals one. And that would mean that the project has just enough money to pay its debt service. It’s generating just enough to pay the lender. If the project actually generates even one penny or $1 less than expected in the model, it will no longer have enough money to repay the debt service.

And when you think of it that way, it kind of becomes clear that DSR really measures the risk of the cash flows or the health of the cash flows relative to the required debt service. Over time. The of one. We’ve got just enough money to repay the lenders DSR of 2.4 like we have in year. One of this example means that I’ve got cash flow to pay my debt service two of 2.4 times, right?

I could lose a significant portion of my cash flow of my expected cash flow. My project could generate a significant, significantly less amount of cash flow than expected, and I’d still have enough money to repay my debt service, right? If I had 200 by 60, I could lose 35 of that. More than half. So much so the DSR really measures the risk to the lender.

How much risk is there that the project won’t be able to pay its debt service, because it measures how many times over the project could pay its debt service. And SCR is going to become very important because lenders use it to adjust for risk. Lenders actually set a DSR that a project has to achieve a minimum DSR that it must achieve based on the risk that they see in the cash flows of the project.

The more risk that they see in a project’s cash flows. Based on the PPA and other contracts, the higher the SCR they will set, because they’ll want more buffer in the project’s ability to repay its debt service. The lower risk they see, the lower DSR they’ll be comfortable with, and they’ll set a lower one. And what will really see is that you could think of it the other way around, right?

If we start with the idea that the DSR is our CAD divided by our debt service, our principal plus interest, if we flip things around here, we could say that our debt service, our principal and our interest just moving some some figures around with algebra would be equal to our Cads divided by our DSR, or in other words, the amount of debt service a project can pay to its lender over time is going to be equal to the cash flow it produces divided by the DSR that the lender sets.

So the higher the DSR, the less the project will be able to pay to the lender. And pretty simply, that means a less it’ll be able to borrow. Or the lower the DSR, the more debt service it’ll be able to pay to the lender, and the more it will be able to pay, right? But the more it will be able to borrow.

Rather, if we wanted to think about the total amount a project could borrow, the total principal it could repay over time, or the total amount it could borrow upfront. It’s cads at it’s forecast to generate divided by that DSR less any interest it has to pay. You can imagine that the more cads the project produces, the more it will be able to borrow, and the lower the project’s DSR as determined by its risk, meaning less risk, lower DSR, the more it will be able to borrow.

Now, as I said a bit earlier, probably the number one driver of a project’s cash flows is going to be its PPA and how it earns revenue that from the energy that it produces. And there’s a lot of different ways PPA is can be structured, particularly in Australia and in the NEM, that might provide different levels of reward, different levels of revenue, but also come with different, different risk.

And lenders might assess them very differently in structuring loans. So I’m going to hand it over to Graham here. And he’s going to share a little bit more about that from his expertise. And what at the end, we’ll think about how the different types of structures he describes might be evaluated by lenders and therefore might impact a project’s ability to raise financing from lenders.

Okay. Thanks, Matt. So looking at renewable energy API’s in Australia, I think it’s first important to understand that Australia is a little different than many other markets and jurisdictions. So let’s just understand that context. Australia has what we call a compulsory growth spot market, and that means that all electric energy entering the grid must be sold by a market participant to aim for the spot price.

So you don’t have a choice about how to who to sell your actual physical power to. If it enters the grid. It’s purchased by Aemo at the spot price. And the corollary to that is that all energy leaving the grid must be purchased by from my Aemo by a market participant for the spot price. Now in the Australian National Electricity Market, there are five regions and five different spot prices at any time, one for each region and the spot price is set every five minutes.

So.

If you’re thinking in historical terms about PPI being the sale of energy, that’s not really the case in Australia. In Australia, the only piece that involves the supply of physical energy from a seller to a buyer are typically those, small rooftop solar pies where the seller is selling from the rooftop to the customer below, behind the customer’s meter, or a sale of an adjoining project to a customer across the fence to a neighbor without the power going into the grid.

And so both of those tend to be very small cases. Almost all grid scale projects, in rely on a different structure. They’re not selling the physical power. The power goes to Iemma. And what we need is to guarantee the revenue for the project and produce that assurance that there’s cash flow available. We need a contract structure that assures the generator of the level of revenue, even though the spot price is fluctuating every five minutes.

So to do this, the most people that you’ll encounter in Australia are cash settled over the counter contracts. I call them over the counter contracts because they negotiated outside the market. They’re outside the spot market and they’re outside an exchange such as the iron six. They are an agreed contract. And so the great difference between a cash settled contract or PPI and a physical PPI is that the seller, instead of delivering a quantity of electric energy to the buyer, the seller pays to the buyer the reference price for electric energy at the required time for delivery.

So it’s a contract to hand over dollars, not a contract to hand over power. And handing over the dollars to the buyer gives the buyer a source of revenue for the buyer to purchase its required power from. From my Aemo in the in the grid so the parties agree some sort of reference price and usually the reference price that they choose for a cash seller.

PPI in Australia is the most spot price at the regional reference node for each relevant time period, which could be if, say, every five minutes. Now there can be variations to this, but typically the buyer and the seller will want to be in the same region of the name, and they’ll agreed that they settle against the same spot price.

So the generator is paying to the buyer the aim spot price, and the buyer uses that to pay for its power to Aemo. Now there’s a special clause in these cash settled PPAs that we usually call the Nip payments clause. And you won’t find that in a physical PPA. And the net payments clause says that there are two amounts calculated is the amount payable by the buyer, which is typically the quantity times the contract price.

And then there’s the amount payable by the seller, the quantity times the spot price. And then the PPA then says you don’t actually make those two payments. What you do is you calculate the net amount of those two payments, and the party with the larger amount pays the net amount to the other party. So under a cash settled PPA, you could find that it’s the seller that’s actually making the net payments to the buyer.

If the spot price is higher than the contract price. And typically in Australia, what happens is these net amounts are calculated every five minutes and then they’re added up and they settled either on a weekly or monthly basis.

So let’s try and look at this thing in a diagrammatic sense. We’ll put in that in this diagram. The cash flows under a typical cash seller PPI. Now firstly I want to identify there are three parties in this diagram. We have the seller or the generator on the left we have the market in the middle which is the spot market operated by Emo.

And then we have the buyer who’s also a market participant that buys its power from the market. Now I want you to look at firstly the brown lines. The seller actually sells its physical power into the market, and the buyer buys its physical power from the market at the spot price. And so the buyer pays the pool or spot price times the quantity of its load to the spot market, and the market pays the generator, the pool price times what it’s generated quantity was.

Now these payments typically they calculated every five minutes at this summed. And they’re paid to and from a Aemo, typically on a Friday for weeks in arrears from the actual settlement, trading interval in which the power was consumed or produced. And there is a proposal that next year this settlement period will be reduced to two weeks rather than four weeks.

And that’s going to go a long way to reducing spot market risk and liquidity issues. But for the present, let’s just imagine then. So the seller is receiving the pool price from the market and the buyer is paying that pool price. The market. Now let’s look at the two lines above the red and the blue line. And these are the two lines that exist because of our contract our PPA.

And under our PPA. The first line, the blue line says the buyer pays a bundle price, times the notional quantity under the contract. And we’ll get to what the notional quantity is in a minute. But that’s basically your contract price for your PPA. The buyer pays, on that blue line, the price they’ve agreed in the contract. And I’ve here called it a bundle price because in addition to getting the pool price paid back, in this case, the buyer also gets the environmental credits from the seller, which is in the green line at the bottom.

So that’s why in this case, it’s referred to as a bundle. Price effectively got two contracts in one sale of power and the sale of environmental credits. Now the second line that occurs under the PPA is the red line. And this is what’s the line that exists in a cash settled PPA and doesn’t exist in the physical PPA.

The seller pays the pool price to the buyer for every trading interval. For the agreed notional quantity. Now the notional quantity is the contract quantity that the parties have agreed. They’ll settle on, and it can differ. You’ll see that the generated quantity is what the seller sales to the market and the load quantity is the what the buyer buys from the market.

And the notional quantity is the quantity that they’ve agreed under the contract. But there will be a, a difference or an arbitrage or a differential if the notional quantity under the contract is different than the JQ or the Q, and that will create different exposures. If you are a generator, typically you’ll want the notional quantity to be as close as possible to the JQ so that your red line liability is matched by the line that you receive from the market.

So let’s then just look at how this structure then can play out in the terms of the PPA. I will mention that there are other names for these arrangements. We’ve been using the term PPA or cash settled PPA, but it’s often called corporate PPA. If the purchaser is someone who’s not a wholesale, a retailer, they’re they’re a corporate acquiring power for their own purposes.

Generically, it’s also called a contract for difference. And often we refer use that term when a government is writing these contracts. But it really is the same contract, whether it’s a corporate or a government. That’s the party to the contract with the generator. Another generic term that people use for these is virtual PPA. So they’re they’re calling it a virtual PPA because there’s no power transferred from buyer to seller.

It’s a cash settled arrangement, a virtual arrangement. Other generic terms which you’ll hear for these include power, price, hedge, power, price swap, power price, derivative. And then all of those terms are really accurate for the cash settled power purchase that I’ve described to you. Now, I mentioned that there was, a critical component for determining the amount of revenue that the generator gets is deciding what quantity is the emotional quantity under the PPA or the contracted quantity under the PPA.

And there’s four main models that are used, for different types of projects and different types of situations. So the first of those common common models is what I’d call a contracted profile. This is where the parties agree in advance what quantity their contract is going to reflect. So they might say this is ten megawatts flat for three years in every hour.

That would be a contracted profile. Or they might say it’s 20 megawatt hours for all the peak hours occurring in every week of the contract. That’s another very common model. But these contracted profiles are really only appropriate for generators who are confident that they can dispatch the contracted quantity of energy. So it might be good for a gas generator or a coal fired generator, and maybe a battery or a hydro.

But it’s not very good for renewable energy projects who have intermittent quantities and quantities that vary according to their energy resource. So the second most common quantity model is what’s most typical for, a a renewable energy generator. And that’s what I call a generation following PPA, where the quantity is set every five minutes according to what the generator actually produced.

In that five minutes. So this presents an exposure for the customer because they might have some certain need, some certainty about their coverage for their power price, and they load, but they’re covering that the PPA only covers the quantity that the generator actually, generates. So often customers who sign up to a generation following PPA have to have a secondary arrangement, some other balance of power arrangement to cover the power that’s not supplied from the generation following.

But the generation following is the most common model we use for wind and solar in Australia. And so the contract operates for whatever is actually produced by the generator. Now the third type is what I call load following contracts. And this is where the buyer has some particular influence. And the bias is I must have a PPA that matches exactly what I’m consuming.

And so that’s difficult for a renewable resource to follow. But it might be possible for a very flexible unit, like a battery or some other dispatchable generation, to write a PPA where they produce the same amount of energy as a customer is producing, and they’ll need a data flow for that. They’ll need to see the customer’s meter in real time.

And the fourth model that’s less common but is around is a model that I call the buyer nomination model. And this is a bit similar to what most gas supply contracts look like, where the biases look here. Here’s what I need for next week or tomorrow. And I want you to produce according to that. So there’s a broad range of power that the buyer could nominate for.

And then it must deliver until the generator in advance typically day ahead. This is how much I want each hour or each half hour. And the generator then has to generate to that structure. So that’s quantities. And the four different types. Let’s now talk about pricing because the revenue for the generator that it receives, it is trying to secure is really quantity times price.

And there are two main pricing models that are used in people’s. The first model is what I call the production price model, where the contract says it’ll be the contract quantity times a dollars per megawatt hour value. So this sort of model is typically used where the contract has fixed profile quantities or where it’s generation falling, and especially for intermittent renewables like wind and solar.

That’s the model. And so you’ll hear you know, I wrote a wind farm PPA at $55 per megawatt hour. That’s the sort of pricing model they’re talking about. But the second model is what I call a capacity or availability and usage charge. And this is a fixed amount per day, often a fixed amount per megawatt available per day.

And then a separate usage charge for the actual dollars required by the buyer and sent out. Now this is typically used where the buyer controls the scheduling of the plan, and this would be in the sale load following quantity model, or a model where the buyer nominates the quantity and this gives the the capacity charge gives the generator revenue certainty that it knows most of its costs are covered, even if the buyer doesn’t order any energy.

So the capacity charge is intended to cover those fixed costs of the seller having the plan available, but not generating typically financing, depreciation fixed on hidden costs, but fuel is typically an excluded cost. The fuel is covered in the usage charge. So that’s that’s typically our common basic PPA model of having quantities and pricing. Now what about the buyer who says, well, I’ve got a generation following model, but what what commitment is that seller making to me about the amount of power I’m going to get.

And so many buyers will insist on a minimum quantity requirement. So this requirement in the contract is usually where the contract applies to the seller’s generation. So it’s generation following. But the bias is I want you to commit that in a year there or a period, there is a minimum amount generated. You can’t just sit back and not produce.

Now how what over what period do you calculate that quantity? I sometimes see monthly calculations and I see quarterly calculations. But in many cases I think, they’re not really appropriate because we have such seasonality of generation in renewables, particularly wind and solar. So, in my contracts, typically the minimum quantity requirement is typically tested annually. And then there is a requirement that the generator pay damages for failing to meet that amount.

And those damages may be a fixed amount. What we call a liquidated amount. Liquidated just means fixed. Per megawatt hour of shortfall. Or it could be unfixed. It could be calculated by some other reference, such as you compare the contract price to the actual spot price that the buyer would have had to pay in trading intervals where the generation was below the full cost profile.

So this is compensating the buyer for having to pay the spot price when the generation was missed. And that’s in a sense closer to the buyer’s real damage. But it also exposes the generator to a higher amount of risk because if spot prices are high, when the generator is not generating and that’s often the case, then the actual payments payable by the generator, potentially higher.

So a liquidated amount is probably more certain for the generator, though it might produce greater payments. A couple of other issues before I wrap up. We often see, provisions in the contract about negative spot prices. Now, most people will cover the buyer against having to pay the spot price all the way up to what we call the value of loss load, or that vol or the spot price cap, which is currently $20,300 per megawatt hour.

That’s as high as spot price can go. And so if you imagine our diagram with the red line and the generator paying over the spot price to the to the buyer, that’s the amount that, the generator could potentially have to pay. And under el caso or PPA, the buyer also has to pay the seller when the spot price drops below the agreed price.

And so most castle picks will settle following the spot price all the way to the spot price minimum, which is about is $1,000 per megawatt hour. I have seen in the market some papers where the buyer says, I’m not going to pay you for the spot price minimum. I’m going to instead, require you to shut down and not incur a minimum spot price.

And so the buyer says I won’t pay you if the spot price or. Well, I won’t pay for the difference if the difference drops below zero, spot price. And, and then the generator is forced effectively to stop its generation during periods of negative prices. Now, I don’t see that’s a very rational or useful way, because it exposes the generator to the risk of negative prices.

And, maybe five years ago, when these clauses were popular, people thought negative prices wouldn’t happen very often, but they’re happening very often for hours a day now, so that’s unattractive. It’s also not very rational because when there’s a negative price, the buyer will actually be receiving money from, from the market. If it has load and so that’s a source of revenue for the buyer to sell to cover the generator against the negative prices.

So my message to generators is, I would argue very hard against a clause which limits your coverage against negative spot prices. And lenders will be, concerned to see if the PPI turns off when the price goes negative, because that’s not giving revenue certainty. Now, just to wrap up a few other, clauses in a PPI, typically that address other risks, there’s the risk of late completion and usually there will be liquidated damages payable for that.

So the that’s an amount where the seller has to pay out the buyer for, late delivery of the plan. Another risk to consider is the scheduling process. Now, I haven’t mentioned this yet, but in the Australian market, all units over 30MW must participate in a scheduling arrangement. They can’t just turn on their plant. They have to submit a schedule to Amo with a set of prices.

And what most units will do is if they do have a PPA, they’ll they’ll try and schedule their units at the at the most negative price, -$1,000, because they want to be sure that they’re going to be on and receiving that, that spot price, some other issues that can impact generators, network constraints, congestion, network failure, preventing dispatch.

If you’ve got a generating generation following contract and the network is out and you can’t generate, then typically that means lost revenue. And, it’s rare that you’ll find a buyer who will compensate you for that. So that is a risk that generators in Australia have to factor in to their revenue. In the UK, generators are paid constrained amounts for being turned off, but that’s not the case in Australia.

You’ve also got the insufficient grid load that even if you bid the maximum, the minimum, price, you may find that there’s insufficient grid load and you won’t be generated. So that’s an issue that we’re starting to see, particularly in South Australia. Of course, you’ve also got the weather resource unavailability. So lack of wind, lack of solar if you’ve got a generation following plan, that’s exposed to renewable, resources.

Then you’ve got an exposure to the weather resource. And the way this is typically dealt with in the financing is that the, finances take, an assurance from a forecaster as to the likely weather resource available. And this these forecasts are done at various levels of probability. I’ve seen forecasts at sort of an average availability, which is called P50.

And then there’s a P90 forecast, which is a high level of confidence that that forecast will be met. It’s typically a lower quantity because there’s a higher level of that being achieved. Other risks for generators include equipment failure, which you address through warranties, and O and M assurances. Your PPA will also have clauses for late payment and default interest.

That’s your credit risk against your buyer. You’ll typically also have a law change clause, especially to deal with environmental constraints. And you also have a tax rate change clause, but probably to cover against changes in the tax rate, such as the GST. Just to touch briefly on the force majeure clause, which is often seen, this is done. This relieves a party from doing what it would otherwise have to do in sudden force majeure events that, beyond the control of the party and the, the relief that they usually provide is to the seller in relation to light completion or commissioning, the ability, inability to operate or schedules, generation or inability to meet minimum generation

commitments, typically to get into relief for force majeure, the event that happens must be beyond control, not reasonably foreseeable, and not due to a failure to operate with good electricity. Industry practice. And for things like minimum generation commitments, it’s very hard to get into, into that, area of protection, because generally, if the plant is being operated properly, it should meet its minimum generation commitments or meet its schedule.

There’s usually a number of exclusions from the force majeure clause that don’t relieve the seller, and they include labor, labor disputes and not industry wide, any lack of finance, lack of really the resource market conditions or prices, breach of law or normal wear and tear because you should be maintaining your plant against normal wear and tear. So force majeure clause does relieve some of the commitments of the generator.

Where unexpected things happen. But, you can’t say that. They tend to be the, extremely unusual. Rather than run up the mill of sort of the men’s the other type of clause, I mentioned a change of law clause. This is also to protect revenue. It allows the generated claim in increasing costs, for changes in law, regulation, license or all occurring after the signing the PPA that went pre-announced.

And it covers you for a change or in direct or indirect costs for operation. And typically the way it works is if there’s a change in law, you look at what’s the extra costs you’ve got over the balance of term of the contract, and then you NPV that back to present day. And then you look at the term of the contract and you apply the increased costs over the term of the contract.

A lot of buyers often insist that this clause works mutually, that a change in law that reduce costs should also reduce the charges under the PPA. And some contracts limit the cost recovery to a market average or spot price. Impact of the law. Change not to the sill as actual position. So for instance, if I’m a buyer contractor in a coal fired generator and the coal fired generator says, I want you to insure me against a new law that imposes a carbon tax on me.

Well, the buyer might say, well, I’m not going to pay all of that carbon tax, because if I didn’t enter this contract with you, I could enter it with someone else and I wouldn’t have that carbon tax risk. So I’m only going to pay you the effect of that, that I would be seeing in my own, in the, in the market generally and not your special position.

So that’s something else that’s negotiated. Last two comments, early termination clauses. I try it usually to try and avoid lots of triggers that would trigger early termination. And instead I try and make contract price adjustments to keep the contract going for next year usually will require an additional notice, an opportunity to remedy the fault. Sometimes extended force majeure can lead to a contract termination, and typically a seller might want to be able to suspend the performance of the contract rather than terminate and lose the contract.

If there is an early termination, you’ve got to put into your model an early termination amount, and I find that those early termination amounts tend to fall into four different events. For the for different calculations, ones where the sellers defaulted, one where it’s terminated because there’s been a force majeure, one where there’s a termination because the buyer defaults, and one where there’s a buyer termination convenience, in the buyer termination for convenience.

A lot of governments want this. I typically would insist that all the costs were paid. For the plan was on a seller default. The seller’s equity would likely not get a recovery in the termination amount. There’s also a concept called two way termination, where when the contract closes out early, either party has to make a payment.

Whichever party is in the money is advantaged by the early termination they have to pay out to the other party. This is very common in cash. So PPIs and other cash sell contracts and it it has the advantage of ensuring that a party doesn’t just rely on an early termination to get out of what would otherwise be an unfavorable contract.

It tends to keep the parties honest. So just to conclude, in a PPI in the Australian NEM is very different to what would be the position of an IPP contract, because an IP in other countries where there’s only one customer available, the generator only can’t readily replace a contract or sell surplus power to another customer. But in the Nim there is a continuous market here available to price excess or shortfall power and a somewhat forward market to price early termination value.

So it’s a very liquid market. The Australian NEM, there’s lots of people to trade with. There’s lots of people to set prices with. It’s very different to the position where you’re a lone independent generator dealing with a mass utility. On the other side. Okay. Well I’m going to hand back to Matt now. And you can continue with, your spreadsheet analysis.

Matt.

Thanks, Graham. Really appreciate the those insights. Certainly. I think the, the Australian, the Australian NEM in particular, a unique market globally, compared to other global markets when it comes to the structures and the risks involved, simply because of the way the, the NEM operates. And that imposes perhaps different risks that both for equity investors as well as, of course, lenders are going to have to consider when it comes to negotiating these contracts and what or how they’re willing to, to provide financing for for renewable energy projects or any project and any energy project in Australia.

So in order to sort of bring things full circle, based on the conversation we had at the beginning around project finance and cash flows, and then all of these details and the different risks that Graham spoke about and structures Graham spoke about with regards to PPA. I wanted to do a very short, sort of simple, high level case study.

Sort of think about why use a financial model or how we might use a financial model to assess the risks or benefits of a couple of different, perhaps PPA structures in terms and what we know from what we’ve talked about so far, right, is that projects want to raise debt. We want to increase debt, increase gearing because gearing increases equity returns.

We also know that lenders care about risk, right? Lenders are going to be willing to finance project or not willing to finance it, or they’re going to adjust for risk using the DSR, depending on how much risk there is to the forecast cash flows. And what I mean by that is, and what does the model say the cash flows are likely to be in the future, and what are the odds that it could actually vary for that, particularly in the down side?

Right. Lender’s not worried about the project generating more cash flow than expected, but worried of course, about the project generating less, not being able to pay them back. And then we also know from what Graham just discussed that there’s a lot of different terms, a lot of different things to be negotiated in a PPA, which might affect how much risk, how much downside potential there is in the cash flows that a PPA backed project is expected to generate.

Now, we could take these things in all sorts of directions. We could look at a million different structures. But I want to sort of look at maybe two, two extremes. Right. Imagine we’ve got a hypothetical project here. I say solar plus battery. But but it really could be could be any type of renewable project perhaps cost just making some numbers up to $350 million to build and has annual operating costs, fixed operating cost of $10 million.

Very very simple straightforward assumptions here. Now imagine you’re developing this project. You’re negotiating some offtake PPA contract, perhaps, just making up here a 15 year tenor. Pretty typical tenor, perhaps for, for maybe on the longer side for a PPA. And maybe you’ve got two options, right? You’ve had two offers on the table or two options that you may be negotiating.

The first of those is what Graham described as a capacity based PPA, right? Where the project is paid a certain dollars per megawatt per day or per month, really just based on availability of the project projects, receiving fixed monthly payments, subject only to the availability of that project to generate electricity. Whether or not the buyer buys it, it’s available to them, and perhaps that that contract might, in our model, come out to expected revenue of, say, $50 million per annum.

Yeah, just just some rough numbers. Then perhaps we have a second option. That’s a generation based PPA. Again for a solar plus battery project. Maybe we could have an option to sell our capacity. We can guarantee there will be capacity thanks to the battery component. Or we could have the option to just sell our energy as it’s produced a generation following contract where the project receives a fixed dollar per megawatt amount based on how much generation it or how much energy it actually produces.

So now our payments depend on actual energy generated and sold. And perhaps, you know, this buyer, the energy buyer wants to negotiate some exclusions within the contract for curtailed or curtailment or congestion losses where there might be zero revenue. Therefore, to the project, if the project can’t produce or they want to and or they want to exclude negative pricing events, right where the seller would receive the negative small price, instead of being able to sell under the PPA, there could be all sorts of other other things that might we might negotiate on there, maybe spot settled, delivery leads.

Of course there’s resource risk when it comes to a generation based PPA that would not exist within a capacity based PPA. But hey, more risk here. We’re getting more return, right? $55 million per annum is the forecast in our model for this contract. Otherwise projects the same term of the contract is the same. I forgot these two options.

How could we use a model to determine which one we should choose? Right? We could look at it two ways, right. First we could start on geared. We could say what are the expected cash flows of this project before worrying about financing. And for option one, right. Imagine 50 million of revenue per year. Apologies trying to show 15 years.

It’s a little bit small. 50 million of revenue per year, 10 million a year of costs. We’ve got $40 million a year of cash flows or Cads. If the project costs $350 million to build, all funded by the investor on an on year basis, that would come out to an equity return, an IRR of 7.64%. That’s for that capacity based PPA.

On the flip side, if we look at that generation, generation following PPA, we get paid on a dollar per megawatt hour basis. Perhaps we forecast revenue at 55 million. As I suggested, same costs. Our cards are therefore higher, right? 45 million of cash flow per year. Same cost to build the project 9.61% IRR with these higher cash flows over 15 years, I might look at that and say, well, 9.6 is a lot higher than the 7.62%.

I definitely would take that option. Two looks better, right? But then we have to remember if we’re going to be financing the project, and probably we are getting because we know that we can achieve better returns with debt. How is the lender going to view these sets of cash flows and the risks associated with them? And what is that going to mean for their terms?

If we think about this on a geared basis, capacity contract, very, very low risk. Right. We’ve simply getting a fixed dollar per megawatt or per month or per year or whatever the payment, whatever the payment terms are, there’s no generation risks. There’s no performance risk outside of the project simply being available to to provide capacity when the off taker needs it.

And in that case, the lender is going to be very confident about what those cash flows are. Those modeled cash flows might be, and therefore they are likely to provide a fairly low debt service coverage ratio. DSR right. That ratio of of the expected cash flows to that required debt service. The low end right lenders might be looking at DSR is in the range of, say, maybe 1.2.

And what they then do is they take those future cash flows, as I showed with the with the formula earlier as forecast future cash flows, they divide them by the DSR of 40 million a year, the 50 of revenue, -10 million of costs divided by 1.2 gives $33.33 million per year. If our interest rate was market ish interest rate right now of around 6.5%, if we calculate out interest and principal.

And by the way, is something sizing and structuring repayments, something we cover in detail in a lot of our, our Pivotal180 project finance classes. What we’d see is it this project could repay a loan within that 15 year period based on that 1.2 times DSR and 6.5% interest rate of $313.4 million. So if we look at the interest in principal over time, we would see that loan payoff to zero perfectly over those 15 years.

So you see same loan size matches the amount of principal that repaid. And if the lender would provide $313 million and the project cost 350 to build, well, then the equity would only need to provide just under $37 million of total capital, right? Whatever the lender is not funding, providing that much upfront capital and then receiving whatever cash flows are left after we deduct that total debt service from the Cads.

That would provide a 16.3% IRR on a geared basis. That’s for that capacity contract with very low risk. We get attractive terms from lenders when we have low risk in our cash flows. On the flip side, option two, which may have looked better in terms of generating more revenue, generating more cash flow, generating a higher return on an UN geared basis.

When we look at that with debt, things might look quite a bit different because if the project is subject to generation risk, if it’s subject to curtailment and congestion risk, if it’s subject to negative pricing risk, if it’s subject to any number of risks that might apply to a generation based contract. And again, all of these are negotiable.

Not to say that every generation based PPA comes with all of these risks, but certain things that buyers might like to do to protect themselves. Suddenly, the lender looks at that same forecast of cash flows and says, I see a lot more risk in that, that, that cash flow per year than I did in the first contract where they saw an expected cash flow of 40 million a year in the first option, but with very low risk.

They had 45 million year expectation. So the second option, but with a lot more risk. Well, how does a lender adjust for risk. They do it via that DSR. They say I need more buffer between your expected cash flows and what you’re going to pay me now we divide 45 million a year. That’s the forecast cash flow an option two by 1.8.

That only gives 25 million a year of cash that we can actually pay to the lender debt service relative to 33 in the first option. So while this this option provided more overall cash flow, the amount the lender will accept per year is a lot less. And that means we’re going to be able to borrow a lot less.

Now we’re only borrowing 235 million. Instead of borrowing 330 million, we’ve lost 80 million, almost of total debt. If anything, we lose in debt sizing is is capital. That equity is going to have to pick up. Now for that project that cost 350 million equities, got to pay for 115 million instead of just 37. In that first option, investing that much more, a lot more money, investing 80 million more dollars is going to hurt equities return, even though they get a bit more cash flow per year in this case, equities return now on a geared basis, 15% a full percentage point lower basically than option one.

Less risk result in a lower DSR debt service coverage ratio and a lower DSR, depending on the difference in cash flows likely to result in more debt and a better equity IRR with a lower risk contract. So there’s trade offs that we face all the time in terms of negotiating project contracts, PPA being a really critical one that impacts both the project’s expected cash flows in the future, as well as what the risks are to those cash flows.

And we have to consider, both in developing projects, if we’re going to be able to finance them successfully and optimize returns as equity investors. Now, a few final takeaways. And again, if anyone does have any questions, please feel free to put them in the webinar chat or in the Q&A if neither of those are working for whatever reason, feel free to email me directly.

[email protected], but two key takeaways from our conversation today. With non-recourse project finance transactions, lenders are really focused, laser focused on certainty in cash flows in order to reduce the risk of them recovering their investment. Higher risk is going to mean that they’re going to need to have higher debt service coverage ratios or at the extreme end, really high risk and forecast cash flows means they might not be willing to finance a project at all that benefits equity, right?

We borrow money because we borrow money, rather because it increases equities return on investment. As we just saw, equity investors usually receive a better return with debt than without debt. Lenders are going to adjust for that cash flow risk via the DSR. Less risk is a lower DSR, and that’s going to mean more debt. And PPA terms are going to very often be the major drivers of expected cash flow and risk for renewable energy projects.

Certainly, there could be risk and operating costs, but typically operating costs for renewables projects are a small fraction of revenues. So risk in revenues, as determined by the PPA structure are going to be the major driver of this. The quantum and the risk of project cash flows. That means project developers and owners should consider not only maximizing expected cash flows, but also minimizing or reducing downside risk.

When it comes to negotiating PPA terms, of course, there’s always tradeoffs to be made there. As you can see, a well built financial model can really help you to determine what are the trade offs that we have, that what do we gain from a riskier structure structure or less risky structure? What do we lose from those structures? And being able to compare and make informed decisions about how we contract offtake and anything else from our project?

So with that five minutes left, I’ll open the floor up to Q&A again. If anyone has any, please feel free to to submit it via the chat or the Q&A. If there’s not any, I’ll give everybody a moment. But, if there’s not any, that’s all right. Ram and I will sign off momentarily.

In the meantime, I do want to thank everybody for for joining today. I really appreciate you taking the time. Hope everybody was able to to learn a bit more about both financial models and risk and the structure of, of, of, project finance contracts as well as PPA contracts and what’s unique and specific to know about them within the Australian National Electricity market.

So things that you can use within within your own work if you’d like to, to learn more. And I’ll have Graeme share the same, please feel free to reach out to Sales or [email protected]. I’d love to chat about our project finance and renewable energy financing, modeling courses, where we cover topics like these and how we how we examine those within financial models in a way that enables us to make informed decisions about the projects that we’re working on.

Graham, anything else you’d like to add before we sign off? No, no, I think, it’s, it’s been quite, interesting to see, how all those issues that I negotiated on the PPA, flow through into the revenue and the returns. Fascinating to see the outcomes. Thanks, Graeme. I just have a question. Belinda, I appreciate that the note I’m at.

Thank you. How how does the capacity investment scheme that size. How is that different from typical EPA also? Yeah. So so on the slides, we will be providing, a recording of this, of this presentation. So everybody that’s registered, whether they’ve attended or not, will receive a link shortly to the recording of this presentation. If you’d like something else, you can reach out to me individually and I’ll see what’s able to be shared.

I would be interested in your thoughts here. You know, at a high level in terms of the SES, what the SES really critically does is it provides a floor on revenues, right. Obviously had to be bid by it, by the, by the project companies or by the investors looking to, to achieve it, but providing a floor on revenues is going to be critical for, for lenders and really viewed favorably by, by lenders, saying if I’ve got a minimum amount of revenue, that I’ve probably got a minimum amount of cash flow and that means at least for that amount of revenue or cash flow, I’m probably willing to provide a very low

debt service coverage ratio and provide a significant amount of debt relative to the amount of those cash flows. And I think the other thing about the size is that it’s you’ve got, government credit worthiness. So most people you’ve got to assess the credit worthiness of your offtake, particularly their ability to sustain that over, say, 15 years.

The CIA’s, because it’s government credit, it reduces the lender’s risk significantly. But it probably still leaves open the resource risk. It doesn’t it doesn’t, drive that one away. And also risks risks like, performance of the plant and, over the long term, which you might cover with warranties, but certainly, the credit risk of the government, certainly enhances the financing.

And then in turn, that means the ability to either get a higher level of, gearing or a, or a better margin on you on your loan. Yeah, I think that’s well put. Credit worthiness is a really important thing. Right? These are long, long dated agreements, partnerships, really a PPA? Certainly wouldn’t I don’t expect that the Australian government will be going out of business.

Not the real risk of a failure of that contract over a long, long period of time. And, you know, this was a very high level analysis that I did at the end of the presentation. But it’s certainly possible that you see contracts with multiple revenue streams, right? Maybe some from capacity. That’s more of a fixed downside flaw as well as some say generation revenue, maybe faster.

Other ancillary services revenues and lenders might evaluate each of those separately. Right. They might say we’ll provide some debt based on the very certain capacity, downside revenues and maybe some higher DSR debt based on some of those riskier revenue streams, like, for example, energy arbitrage in the market or forecast services or things like that.

Or if there’s no other questions, again, I’ll just thank everyone once again for for joining today. Really appreciate your time. If you have any questions, afterwards, please feel free to reach out to either of us via email. Look out for a reminder for the the recording availability of this, this session. If you have any colleagues you’d like to share it with, we really encourage you to do so.

And please reach out if there’s anything else you’d like to know about project finance or and any other topics related to to renewable energy and infrastructure. Have a great rest of your Monday and a fantastic holiday season.