Alexandra: What are the implications for debt that might be more suited to these new types of much larger portfolios?
Andrew Pickering: Well, we are seeing shorter-term debt at the moment.
Longer tenor debt to match the PPA profile of a particular business is being sought to manage that side of the equation more easily and more predictably.
We are going to be a very different type of business, even if we have the same number of megawatts out the door as an AGL or an Origin. But I think the large businesses of that size in the future will have a much more complex array of generation available to them, which in our case I think we will own.
And customers. In our case I don’t think we will be with consumers because some of our key counterparts will be those companies starting to grow large customer bases, such as the Shells and BPs of this world.
From our perspective those counterparts, the people providing us with PPAs (we will have a mix of merchant but mostly contracted), I would be surprised if firms in truly competitive industries can justify providing 10 or 15-year contracts, at least for the full amount of their requirement. So, I would expect to see a whole range of different credits on the customer side, tenors, types of supply they are looking for - firm, they may need battery backup - and we are going to have to be sophisticated enough to offer those products right across the board. And that’s without even touching the residential consumer market.
It’s going to be a very different type of business and one of our focusses will have to be managing it effectively and not just treating it as a series of assets we pile up and hope the financing works out.
Alexandra: Jeremy, do you think that banks are ready to finance these very complex portfolios with very varied counterparties?
Jeremy Hasnip: That is a really good question. I think the typical outcome at the moment is the use of project finance to get access to a reasonably decent high-level of gearing in projects, to bring down the weighted average cost of capital. The issue then becomes with the contracts that have enabled you to put that position on start to expire, then the ability to support the same level of leverage reduces. So, you have got to amortise during the term of the foundation PPAs. And then the debt chart becomes a bit like the roof of the Sydney Opera House, where you try to extend the contracts, or get new ones, and re-lever as you get further periods of contracted output and build on the book at the end.
It will start to look, perhaps, a bit more like the thermal generators did in Victoria after the first round of privatisation. They were sold as vesting contracts that gave three years of revenue certainty, and then they had to develop channels to market: whether they sold large relationship contracts to retailers; whether they sold spot; or whether they built their own industrial and commercial sales marketing division to try and sell to customers that had at least the size of a major hospital in terms of power consumption - a minimum sized customer of say 4 GW/hr a year. And so they built up a more complex wholesale operation and dealt with risk management products to be able to handle breakdowns in the coal plant.
We’ve been talking about innovation. The type of workforce in renewable companies is going to shift over time to be more like marketing, trading types; putting together different routes to market and different products that financiers can then bring the right amount of capital to support. I think there is a lot of innovation going to take place on the marketing and customer-facing piece.
Alexandra: Sieuwert, what innovation do you see on the way for debt financing in this scenario?
Sieuwert de Zwaan: We have quite a large group of projects approaching the markets for refinancing soon. Portfolios might be a way to re-lever and to make use of the value that they couldn’t get pre-construction. Having a portfolio with a vast variety of off-takers is complex but also provides diversification risk and is really financeable.
In terms of increasing or recycling capital at shareholder level, we expect to see some acquisition financing that will enable developers to recycle capital invested and to continue to grow their business here and internationally.
We also see potential for holdco financings of project finance portfolios. What is important there is that you have a proven cashflow from, preferably, contracted assets and then you can look at equity-to-loan value and other concepts not necessarily used in project finance, but which are already applied on global portfolios for certain developers.
So, with developers building portfolios of assets, you’ll see a move to group refinancings with different structures.
Alexandra: Another question on debt. Do you think the downward pressure on project finance pricing to continue?
Sieuwert de Zwaan: That’s a bit of a macroeconomic question. We are in a period where we expect interest rates to rise at the same time as Central Bank Covid support is dropping off, so funding costs for banks are increasing just as commodity prices are increasing.
You could argue that margins should increase in this economic environment but given the scarcity of very high-quality projects, I think they will still be able to get away at very competitive prices.
Jeremy Hasnip: The term-funding facility from the Australian Government that we benefited from over the last three years is coming to an end and that’s a real structural change. That was helping banks with their funding costs so, as that unwinds, it will feed through into margins.
Alexandra: Will that have any impact on the ability to source long-term debt?
Jeremy Hasnip: Five-year money seems to be the most common term in the market. On large, high-grade assets we sometime see a mixture of three-, five-, and seven-year funding solutions. There is a little bit of liquidity at the 10 year and beyond, but it’s not significant
Sieuwert de Zwaan: There is no real change in the tenors we see; generally it’s five years. There is a switch point beyond that term where capital costs rise significantly. Below that, well, no projects can really prove themselves in that time, so the refinancing risk increases.
In Australia, we also don’t have projects that are contracted for 20 years like we see in Europe. So, given the market risk and PPAs dropping off in 2030, a five-year tenure is the norm.
Alexandra: We are starting to see more individual projects coming through in newer technologies, such as batteries and hydrogen.
What risks are investors willing to take in funding these new technologies, and what structures are emerging?
Adam Pegg: If we look at batteries first, then equity is taking a view on what the network service revenues are and what arbitrage exists in the longer term. We’re seeing battery life now extending out beyond 10 years, so you can take a longer-term view.
But it really comes back to the same simple principles we use on solar: making sure of the quality of the off-taker and doing the right development activity, planning correctly, making sure of a good connection, picking a good location in the grid, and sourcing reliable equipment that does what you need it to do.
I’m sure it’s the same in the debt market for battery projects: quality of the off-take, quality of the project, etc.
Hydrogen is interesting because, in the medium-to-long term, it has got enormous potential to unlock an incredible amount of renewables in Australia. But it still comes down to the quality of the off-take in the markets into which we are supplying and exporting the product, the quality of the developer and how well the project is put together, choice of equipment, reliable supply chains, etc.
It may be different technology, but the fundamentals of a good project stay the same.
Alexandra: What projects using new technologies does Lightsource plan to develop in Australia?
Adam Pegg: Just about all the battery projects in our pipeline have planning approved – we’ve got a number of them in Queensland, New South Wales and Victoria. Some of those will support the solar projects we’re developing while some will just be nice add-ons to current facilities.
We see batteries as a real facilitator of solar. As soon as you can make solar dispatchable then it becomes a much more attractive proposition. So, we’re doing a lot of development activity in the US and the UK on batteries at the moment. We’re watching costs come down, we’re increasing our expertise globally on how to put these projects together and how to make sure they perform how we need them to.
It’s the same with hydrogen. We have a project in Geraldton, Western Australia, where we’ve got funding to do a pre-feasibility study. The next stage of the project will be a demonstration plant, and then it will be a much larger commercialisation plant towards the end of the decade.
It’s a really exciting project. We’re effectively making sun and wind transportable and exportable.
Alexandra: Andrew, could you share how and where Infrastructure Capital Group is looking to make its entrance in these sectors?
Andrew Pickering: Yes, in the past we’ve looked more at the traditional large wind opportunities, but batteries are now in the portfolio through the Meridian acquisition. We have development approval for a battery project that we are looking to resize at one of the hydro facilities on the Victorian/New South Wales border. Not only will it have the ability to store power, but it can despatch it into either market. We think that is a very powerful and valuable product and we would like to make as much of the site and opportunity as we can.
On a smaller scale, we have acquired a solar business which has a number of sub-5 MW projects and one of them is trialling a small hydrogen production electrolyser to provide some firming capacity onsite. We are quite interested in seeing how a smaller scale hydrogen production facility may fit into some of these opportunities. It’s clearly not for export purposes but does provide a nice bolt-on storage feature for the generation opportunities we are looking at.
That’s the two innovative proposals we’ve got in front of us right now and we are seeking to develop them as fast as we can.
Alexandra: Paul, what is the appetite for batteries in the lending market?
Paul Curnow: I have been surprised at how quickly batteries have mushroomed, but I guess that when you look at the ISP, at the amount of additional firming capacity required in the grid transition, then I guess it’s not surprising. It is interesting because not many of these battery projects have got through to financial close - whatever shape or form that takes. So, I think there are still a few question-marks about appetite.
With batteries, unlike solar and wind where they may have been contracted over longer-term PPAs, you need a team that can manage revenue generation.
I think it ties into the earlier points raised around where the corporate PPA market is going. If you think about what Google calls 24/7 carbon-free energy, which is where we have to get to be properly Net Zero, you can’t talk about corporate PPAs on an annualised average basis – you need to think of corporate PPAs delivering green power on an hourly basis matched with actual hourly consumption. That is what 24/7 carbon-free energy is all about.
When you start to look at corporate PPAs in that way then the role of batteries within the mix becomes, I think, much more important. And for storage in general, not just batteries. So, I think there is a real nexus here between the evolution of corporate PPAs and the role batteries will play, and I think it also picks up on this theme of aggregation and how you look at the role of portfolios that sit behind the products you are going to sell.
When you look at what is happening with batteries, then I think you are seeing the first stages of that. So we have seen, from a revenue model point of view, the first batteries or capacity payment structures from governments and others. Then we have seen the evolution of a tolling off-take where you give all dispatch rights to the off-taker. We’ve seen retailers there. We have also seen NSPs looking to buy network services from batteries.
But for me, the really exciting innovative thing around batteries is the ability to separate physically what you do with the battery from how you have structured it financially. We are going back to the future where we saw baseload generators in the early days of the NIM having hedge books with different tenors and different off-takers. We have started to look at the way that batteries can be contracted but also remain sufficiently uncontracted in order to benefit from playing in those markets.
To me that is separating what the battery does physically with what you have committed to financially. We are starting to see that happen although I wouldn’t say anyone has done that yet.
We have seen a preference for tolling off-takes for batteries because they are the easiest to get banked if you have a good credit on the off-taker over the next 10 or 15, 20 years. But a lot of our clients also realise that you leave a lot of money on the table as a developer.
A lot is happening in that space and it’s moving quickly.
Alexandra: Jeremy, could you give us a banker’s view as to what tolerance you have for some of that merchant exposure.
Jeremy Hasnip: Batteries are only just getting to the point where they are big enough to be worth project financing, not just in Australia but in the US and Europe as well. A lot of battery projects to date have been around 25 MW to 30 MW in size, which is just not big enough to justify project financing. Many of them came about because they were providing some network support or a system reliability product, particularly at the distribution level.
But now we’re getting 100 MW, 150 MW to 300 MW scale batteries, and that starts to be something banks are interested in. At that size, the costs of procuring project finance - the due diligence and documentation, etc, start to be justified.
The tolling deals are very straightforward and are very keenly sought after. I think the issue is going to be very similar to what happened in wind where banks were brought up on a diet of 15-year PPAs. But then PPAs started getting shorter and then PPAs stopped filling the entire size of the plant. You were faced with the question of whether you are happy financing a project that is 80% contracted, or 60%, or . . .
Some banks stuck on the 100% level, while we have done quite a few deals down at the 40% contracting level, but we haven’t really seen a lot done at the fully merchant basis as yet. I think it’s only a matter of time before bank tolerance levels to market risk increases as contracting levels on batteries come down. But you do have to think of the two pieces to it: the market risk on the price and volume you are selling your electricity at, and the purchasing side.
People’s experience in renewables is that the resource is free. In thermal power plants, you know the price of gas or the price of coal that is contracted and you have got long-term certainty.
Are we going to continue seeing large negative prices where we get paid to charge the battery? Probably not. If LGCs disappear or there is no tradeable carbon price in Australia, then there is no reason to support a negative price in the longer term.
Can you get energy very cheap? Yes, you can. By building DC connecting batteries within a solar farm and taking the clipping losses. That gives you certainty around your costs, although some other locations for batteries don’t get that.
So, you need to think about the appropriate level of debt sizing for a battery that needs to purchase power on the market.
As banks get more comfortable with the trading history of batteries, as revenue from operating assets comes through, we will start to see risk tolerance increase.
Sieuwert de Zwaan: That is a pretty good description of all the different elements you need to think about in financing batteries. More broadly, ING is strongly committed to energy transition and net-zero and we’re also looking to steer our book towards net-zero by 2050. What that means is that when we look at battery projects, we don’t just look at the project in isolation, but the full supply chain.
The off-taker is easy because that is the market you supply to, but ING has also been very active in supporting battery manufacturing capacity in Europe where we have done a very large battery manufacturer financing in Sweden, for example.
ING was also one of the banks that financed the Vena 100 MW standalone battery in Queensland. That one was contracted but we had our hands-full on the contract structure, looking at the quality of the EPC provider, and the quality of the manufacturer behind the battery. We are still finding out how this will work out in practice. ING is very keen to work with clients to find bankable projects, from a technical perspective.
In terms of market cashflows, batteries are not a generating asset, per se, because you need to purchase power and then sell it at another time. The first movers in this market will have an advantage as they can still benefit from FCAS (grid services) income which is currently high but expected to drop when more supply for these services comes to the market.
As Jeremy said, we will get to 80% contracted projects or ones that are 10-year contracted but have a merchant deal, and we are going to have to develop a view of an arbitrage market in 10 years’ time.
As long as there is a significant difference between the capture price of renewables and the average market price, then there is a market for batteries and that is, currently, certainly the case.
One last point. Batteries are really beneficial in the larger solar projects where they can be a real mitigant in capturing a higher price for the generation of your solar farm, thereby adding value.
Alexandra: What is the evolution in off-take markets for renewable generation?
Steve Symons: Originally, off-takes were long-term from retailers to meet their obligations. The State Governments came in and filled the gap after that. In New South Wales we have also seen the introduction of commercial and industrial (C&I) customers for off-takes. And we are seeing a lot of companies committing to carbon neutralities.
At Tilt, we have signed corporate off-takes with Aldi and Newcrest, and we are regularly speaking to other customers looking at doing similar deals.
The next evolution of the C&I space is the ability for them to have a ‘firm’ product. And this is relevant to the previous discussion around battery financing in that, when Tilt develops its first battery, we will be uncontracted because we will use battery as part of the wind or solar portfolio in such a way that we can provide a firm offering to the customer. That could mean an industrial, commercial or retail offering or it could end up being some other type of contract. It could even be a short-term contract for trading over the market.
The other thing to note is that, as off-takes have evolved over time, we have seen a number of the risks change. In the early days, negative pricing, even Marginal Loss Factors (MLF) risk was taken by the off-taker. Grid containment is now a risk that generally sits with the project. Tenors of off-takes have also gone up and down and are currently becoming shorter. The challenge there is that we generally assess the life of, for example, a wind farm to be 30 years rather than the 20 years we expected when we first started doing those things. That means the merchant tail as a percentage of the project becomes longer as we assume a longer lifetime for the project.
So, off-takes are evolving, and they will continue to evolve. The products offered to the market will change to meet the evolving needs of the customer and the form off-takes will adopt will ultimately be determined by the needs and buying preferences of the customers.
Alexandra: Tenders are coming soon for the New South Wales Long-Term Energy Service Agreements (LTESA). Paul, how are we going to see this banked? Or explain the benefits of this new LTESA structure as a new form of off-take?
Paul Curnow: Just to pick up on a point made by Steve. I don’t agree about his point about the evolution of the corporate PPA market. What I’ve seen is much more of a swing back towards a sleeved model. But I think, to Steve’s point, there is a lot of opportunity for generators to offer firm, financial hedges within that corporate PPA market and I think that is the future. What that probably means is that a corporate PPA in 10 years is really just a retail contract that is 100% green, but not as expensive as current Green Power pricing.
LTESA is an interesting one. I am still on the fence as to what that means for liquidity in the PPA market. The New South Wales Government’s objective is to provide a degree of certainty to generators against low wholesale prices. It is certainly not envisaged that LTESA is the only contracting you do in order to make the project bankable, you can still sign other PPAs. I think that is evident in the fact that the bid and strike price for the four tenders is expected to cover your debt repayment, not a return on equity - at least for the generational LTESAs. It’s different for long duration storage.
There are question marks as to how LTESA is going to build or support a PPA market. I can certainly see that if you can offer a solar or wind PPA to a corporate where you have taken away the wholesale price risk with the option under the LTESA, then it is a more attractive proposition to the corporate. But it means a much more complex PPA structure for banks in terms of when to expect the LTESA option to be exercised, depending on what the wholesale price is doing and what you are bidding in.
I expect there will be lots of interest in the LTESA because it is more or less a free option, at least until you choose to exercise it and there becomes a repayment obligation. We have seen a much clearer articulation in the RES paper separating access rights in the RESs from the LTESA, so maybe we will see less projects as interested in that.
Adam Pegg: We are just waiting to see how it works. We’re getting more understanding of how the access arrangement is going to work, how to fund, how to get enough critical mass to get the REZ away and so on.
But I think that, overall, it’s fantastic that the New South Wales Government is throwing itself behind the LTESA and, if it can get the mechanism right, there is a real opportunity to get more development.
Alexandra: Another topic I was hoping to ask about was current trends in EPC contracting given issues with supply chains.
Steve Symons: Our observations come from closing the Rye Park Wind Farm in August. This was a multi-contract rather than EPC contract, but the observations still hold. Commodity prices have been high: steel plate pricing doubled before Christmas, and resin price levels were up 2½ times. We’ve also seen shipping costs increase, primarily due to congestion.
I think some of the increases are short-term in nature, part of the commodity cycle, and we’ll probably work through some of those hurdles. Nevertheless, we’ll have to wait and see what the next 12 to 18 months bring, but hopefully some of the shipping backlogs will ease and Adam will get his panels.
We mentioned grid before. I agree with the observation that the pathway to connection is a lot clearer now the Australian Energy Market Operator (AEMO)has done a pretty good job wading through the problems.
And turbine suppliers, having been caught with previous contracts, are factoring-in and pricing-in a lot more risk whether that is a price associated with cost, or whether it be for schedule. All those considerations impact on the project.
Hopefully, that’s also a short-term effect that will be addressed once we get the next round of projects through and we see connection play out in a better way.
On the flipside, technology continues to improve, which is helping bring down the levelized cost of energy. As an example, we thought we are at the cutting edge when we developed Dundonnell with 4.2 MW turbines a couple of years ago. Rye Parks has 6 MW turbines. It’s amazing, we thought that solar was going to take over as the ‘cheap and cheerful’ source of renewables, but the turbine manufacturers haven’t allowed it.
As the other technologies come on line then the cost of energy will continue to fall.
Alexandra: A question from the floor. What is the effect of the low Australian dollar value having on new deals?
Sieuwert de Zwann: Having a lower Aussie dollar compared to the US currency can potentially have some benefit to a local business case because, ultimately, there is a linkage - although not direct - to cost prices that are quoted in US dollars, which can result in higher merchant prices projects can capture.
On the flipside, a lower Aussie means that the foreign currency component of your EPC will be more expensive and, along with the already challenging prices in EPC, those costs will either be pushed into the project risk or factored-in as an additional expense of procurement.
The market is a bit slower at the moment, but I think it will come round and projects will continue to be built. Certainly, last time we went through some Aussie weakness, there was very little impact on the market.
Alexandra: Another question. What it the view on split contracting versus fully wrapped EPC in Australia?
Jeremy Hasnip: We have been very lucky in Australia in that we have seen a very high level of EPC compared with other markets. We’ve got used to that delivery model, one where the contractor was essentially providing a financial contingency for costs not going according to plan - managing the subcontractors and their work, as well as its own. But also bringing a strong project management capability, well-resourced with engineers, production planners and technical people.
When you move to a multi-contract strategy, the project company needs to take that function in-house and that doesn’t come free. You really need to determine whether you have the capabilities and then how you are going to accommodate the internal organisation to manage the work. Then you have to decide on the appropriate amount of additional liquidity required in the project to compensate for not getting the service from your contractors. It can be done, but it is no free lunch.
Paul Curnow: On the batteries coming through, we’re seeing a tendency to have split contracting, certainly from the equipment suppliers. We’re starting to see less willingness to provide a full wrap.
So, to Jeremy’s point, I think banks are going to have to find a greater level of confidence with split contracting on batteries, certainly standalone but even hybrid ones, at least when I look at the position equipment manufacturers are taking on this point.
Adam Pegg: We’re very used to the free-issue model in the European markets, and we have been doing it for years. And as a solar developer we want to make sure that we capture the benefit of being a global player and having big pipelines. We are buying 25 GW of panels by 2025, we want to make sure that we are getting the cost benefit of that.
As more global players come into this market, you will see more free-issue. It is the way things are done in the Northern Hemisphere. The risks can be managed, the supply chains can be managed better by a principal with a global footprint. And so can the performance. The performance can be wrapped by one party as well.
You will probably see more of it in the Australian market in the future.
Alexandra: Someone said it might suit balance sheet financing better to have the split contract than project finance, would you agree with that Sieuwert?
Sieuwert de Zwaan: Potentially. It depends on the balance sheet of course, but yes, only project financing your project at completion has benefits because you don’t have to deal with pesky reporting requirements to the project financiers.
But coming back on the EPCs, I agree with Adam that potentially certain parties are better suited to take certain risks than others. As long as there is very good project management, good experience and good counterparts on each and every contract, and a schedule that allows for an interface between the different deliverables, then that would be something to consider.
So far, as Jeremy mentioned, we have been able to hide behind the investment grade credit of EPC counterparties. We also saw that in this market at some juncture, joint and several wasn’t necessarily in these parties’ benefit. So, we have to work with the market.
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