Energy Transformed is a short podcast series brought to you from the team at RenewEconomy, Australia’s most read website focusing on clean energy, news and analysis. Energy Transformed is also brought to you by Ashurst, a progressive law firm offering global reach and insight combined with local market knowledge and understanding.
Nick Carter 00:26
There’s a lot of things that a battery can do, and new and emerging things that the batteries can do, but they’re not necessarily contracted just yet. And I think this is where the techno legal element is becoming more and more important because that is the key part of the solution for those new new products.
Paul Curnow 00:46
You’re listening to Energy Transformed, a podcast and webinar series that looks beyond the headlines to take a deep dive into Australia’s energy transition. Hello, I’m Paul Curnow, a Partner with Ashurst based in Sydney and Global Co-head of our energy practice. Welcome. We recently kicked off the first in our series with a webinar that asked the crucial question, Who rules the market?
This followed the final recommendations by the Energy Security Board. It’s a good question because we all know the challenges facing Australia’s energy market over the next 10 to 15 years as we seek to decarbonise the energy sector in order to get to net zero. In his first public address as the head of AEMO, Daniel Westerman set a goal for the NEM to be capable of handling 100% renewable energy for certain periods in the day by 2025. We know the NEM is rapidly transitioning to a low emissions generation profile. If you look at AEMO’s 2020 Integrated System Plan, the step change scenario projects 29 gigawatts of large and small scale variable renewables capacity will be built by 2030 alone. And yet during the same period, our baseload coal capacity is due to decrease by 50%. So getting to near zero means even greater levels of variable renewable energy, which gives rise to a range of critical technology design, and investment decisions that will need to be taken if the NEM has to be fit for future purpose.
And so that brings us to today’s podcast focus – batteries. Given the rapid energy system transformation, there’s a lot of excitement from engineers to market operators, investors, even lawyers, about the crucial role battery energy storage systems can play in our future electricity grid. And with good reason, batteries are increasingly seen as a key technology enabler to high renewables netzero grid. So in a market with higher renewables penetration, it’ll be vital to ensure the ongoing provision of essential system services such as frequency control inertia, system strength, and we’re already seeing a range of battery technologies entering the market that are demonstrating their ability to deliver these services. But deploying and integrating big batteries across the NEM isn’t without its challenges, and raises some interesting but difficult questions. What markets do battery projects currently have access to? Are they commercially viable? Can battery projects be green? Do they need to be? And will batteries ultimately take charge of the grid?
To help wrangle these questions, we invited one of Australia’s leading energy and battery experts Nick Carter, into the ashes locked down studio. Nick is currently principal at Akaysha Energy based in Melbourne, with a long career in the energy technology industry. He’s also worked in energy technology and solutions at Macquarie Capital, and as business development manager with Tesla. Also joining me in our battery discussion is Paul Newman, my fellow partner in the Ashurst energy team who’s based in Brisbane. Welcome to you both – good to have you on our very first Energy Transformed podcast.
Nick Carter 00:16
Thanks, Paul. Thanks for having us.
Paul Newman 00:18
Thanks for having us.
Paul Curnow 00:20
I’ve been enjoying our conversations over the last few months. And every time we’ve had them around batteries, I keep thinking we should be recording this, and finally, we get the chance to do it. To dive into some of the techno /legal issues that we’ve been chatting about for the past few months. So thanks again for your time. Maybe just to start, Nick, I thought it’d be good to get everyone on the same page in terms of batteries as a technology.
When we talk about batteries, what are we actually talking about the range of technologies. So do you want to just walk us through briefly, batteries, obviously we’ve got chemical batteries, we’ve got pumped hydro, and lots of other types in between. If you could just give us a quick overview I think that’d be good way to start.
Nick Carter 01:01
Sure, I might just start with a bit of a chemical battery overview. I suppose Lithium chemistries have been around for quite a while. People are quite familiar with them since the mid sort of 80s or 90s with respect to those chemistries. As times gone on, I think the really big move forward was lithium, nickel, manganese, cobalt, which is also called the NMC chemistry, which is some of the larger initial big batteries were using that chemistry. And then probably the big thing that’s happened more recently, over the last five years is the chemistry often referred to as LFP, or lithium ion phosphate. And that’s been quite a big step forward.
A lot of electric vehicle manufacturers have really been putting a lot of effort into that chemistry. And it’s now flowing across to stationary storage, which has been a great, great feat from a safety and reliability and cost perspective. So that’s probably the biggest change there at the moment on lithium systems. But then, as you mentioned, Paul, there’s also a whole bunch of other things out there in the chemical storage world, including flow batteries, which have not necessarily really taken off at scale, but have quite an interesting use case around very long duration storage.
There’s a few flow battery projects around the world and proposals in Australia. And another one which is very interesting that’s quite new as well, is from Form Energy in the US, which is an iron air battery, which is effectively using the oxidization process of steel or iron to store energy, which gives you multi week or multi month storage depth, similar to I guess, a large hydro, which is very interesting.
And as you mentioned, yeah, we’ve got large hydro, I think most of the listeners will understand that. And then, of course, some of the other things that are happening, not just on the DC side of the battery, but the AC side, as well around new innovations with inverters and those types of things that I think we’re going to also touch on are really where the innovation is happening. So it’s not just the chemical or mechanical side of the energy storage system, but the AC side as well is where the the innovations are really occurring.
Paul Curnow 03:33
Yeah, so I think, as you just mentioned, you know, so then batteries are not all the same. We’ve got short duration batteries, long duration batteries, they obviously play very different roles. And I guess the question there is, why is everyone getting so excited about batteries when you think of the current energy transition? And if you think about high levels of renewables in the market, of course, that creates a lot of issues around the grid stability, grid strength and the role that batteries play.
I guess at the moment, there’s been a lot of focus on batteries as far as energy arbitrage goes, and how you can store that and use that at later points. But I guess just again, to sort of set the scene for our listeners, it’s probably worth just walking through the breadth of the roles and services that batteries can play. I mentioned energy arbitrages. But of course, the provision of ancillary services such as frequency control has also been a big focus of batteries in recent years.
We think of some of the batteries that have come on the market here in Australia. So if you could also just briefly walk us through the range of services that batteries can currently perform, and what are the additional service services that we might see as these battery technologies mature?
Nick Carter 04:51
Certainly. So I think Yeah, as you’ve mentioned, energy arbitrage is probably the bread and butter if you like of battery storage at the moment in Australia and around the world. But of course, we’ve got Frequency Control Ancillary Services and that also includes the new very fast sub two second FCAS market which is coming out in Australia in the not too distant future, which is a very interesting new product for a battery. But also there’s things that I would call emerging markets or services like inertia or virtual inertia. Services via inertia contracts potentially. We’ve got, you know, the potential to have voltage support services at various points in the network. And then you’ve got other things like interconnector protection services.
So in other words, if there’s a really critical piece of kit or an interconnector, you can have as part of the protection scheme for that interconnector, a system whereby the battery can very, very quickly intervene in that piece of critical kit to help protect it. And that also includes other things that you can offer as a product, like ramp control services for wind and solar farms. And then, of course, the other one you touched on, which is not necessarily straightforward, or a product that exists today, but the one that everyone’s thinking about is really deep diving, variable renewable energy firming, or how do you have a contract to firm those assets or fleet of assets is really where it’s at.
So I think, to summarize, Paul, there’s some things there that we we know and love, like energy arbitrage and FCAS . And then as we move down the spectrum, there’s a lot of things that a battery can do, and new and emerging things that the batteries can do, but they’re not necessarily contracted just yet, and I think this is where the techno/legal element that you mentioned before is becoming more and more important, because that is the key part of the solution for those new products.
Paul Curnow 07:10
Yeah, exactly. I think for me, you know, key to unlocking the uptake of batteries, and really to scale it up is how these services are regulated. And you mentioned, of course, contracting, we’ll come to that from a sort of revenue point of view, but certainly the way batteries are regulated within the NEM is going to be critical to unlocking that potential. And if we think of the NEM, as it was written in the 90s, didn’t contemplate the battery technologies as they’ve developed today, or indeed, the proliferation and how they would be distributed across the grid. So obviously, the rules are playing catch up, which is often the case when new technologies are emerging.
So I might bring in Paul here, because it would be good to just also set the scene in terms of the regulatory aspects, in terms of how batteries are currently regulated within the NEM. And I guess it’s fair to say at the moment, it’s a bit like a square peg in a round hole, that maybe Paul, you can sort of just give us a sense of batteries, how they currently fit, and in particular, touch on the AEMC draft rule, which came out last month, which will, of course, clarify some of these issues, but perhaps not all of them.
Paul Newman 08:25
So Paul for me, the fundamental issue is that the national electrcity market was really designed to recognize generation and load quite separately. Pumped hydro was always generation, and I say this, because, unfortunately I’ve been around long enough to pre date the NEM so saw what the issues that were being designed, and I have ringing in my ears, the very first project I did, we had some American power, independent power producer come out and said, the one thing you need to understand about electricity is you can’t store it. So how much we’ve moved in the last 30 years is quite amazing. But the concept of energy storage and energy, time shifting really was a pipe dream, and wasn’t really recognized in the rules.
Secondly, the thing that is the speed in which the battery can actually respond was really never envisaged in the national electricity rules. And sort of contrasting with what we’ve seen is the development of the VRE’s. This is an active facility rather than a passive generator, like the solar and wind. So to date we’ve seen energy storage being recognized as both a generator and a load. And certainly for some of the early battery storage projects the rules just didn’t really deal with it at all. AEMO issued a fact sheet in 2018 that tried to grapple with the way in which you would integrate energy storage with solar and wind and develop a hybrid model which is sort of being developed from there.
And the recent proposed rule change, which is due to start in April 2023, has picked up on that hybrid concept and is looking to integrate that into the national electricity rules, providing for a single integrator result resource provider registration, and would make the hybrid model part of the national electricity rules. There’s still a ways to go. But it’s a certainly a forward step in dealing with what are quite complicated regulatory issues in this area.
Paul Curnow 10:31
Yeah, so the integrated resource provider will, of course, clarify a bunch of those issues as you mentioned. One of the concerns I guess that that’s been raised, speaking to those active in the market is, of course, the proposal as part of the AEMC draft rule that batteries would be charging subsystem charges. And I guess that’s raising a lot of concerns about what it does in terms of the economics of batteries in the rollout. What is your view on that? I mean, how do you see NSPs responding to that guidance from the AEMC?
Paul Newman 11:11
Yeah. So Paul, I look at the rule change and I think there’s three key issues that remain unresolved. And they’re issues that were identified in some of the early battery rollout, particularly the Gannawarra Energy Storage Project, and the way in which you retrofit or colocate.
So the first one, to my mind is the one you’ve just mentioned, which is about the way in which use of system charges are to apply. And this is universal, not just to the colocated arrangements. AEMO, when it actually made the rules request, and suggested that use of system charges shouldn’t be applied to batteries, even though they were a load. And I think to many commentators surprise the ANC recommendations in the draft rules were in fact, the opposite and effectively said that the rules need to be technologically neutral. And therefore, they weren’t going to make any changes of any significance other than deal with the integrated resource provider registration on those part of the rules. And effectively said, as at today, network service providers are capable of charging use of system charges.
To my mind, that’s doesn’t really go to recognize the true network benefits that come from a battery, even if it’s operating as an IRP. Things like power system security, grid stability benefits, the sorts of, and the ability of batteries, in fact, to provide a number of services at the same time. So submissions are due on the 16th of September, so later this week, and it’ll be very interesting to see how many people actually raise issues around this use of system charge.
So two other issues, just to mention, is, on the retrofit side of things, I think the issue of whether the generator performance standard for the existing facility, which is typically a solar or wind facility, needs to be updated and go through a further process when you actually add a battery to that as a retrofit. And obviously, that’s certainly one of the physical goals is to have colocation, I think there’s a real exposure there. And some of the difficulties you having with financing and structuring of these projects where you’ve got multiple types of generation or facilities behind a single connection point, which give rise to embedded networks and create regulation that if you look on the ground, the position exactly the same, but through regulation, we actually inhibit separate ownership behind that connection point. And I think they’re three key things that are going to create limitations with the rollout of the proposed rule change.
Paul Curnow 14:03
So Nick, you’ve been looking at how you deploy batteries. And obviously, looking at how you can do this in the real market. How do you view the draft rules from the AEMC? Does it answer all your questions and concerns about how you would actually make these batteries bankable and economic?
Nick Carter 14:24
Yeah, look, I’m overall net positive about the rule change, because I think it is required and there is a definite need for it. And I think if it’s done, done right, then it will be of benefit to investors and developers, in that context I guess. The part that’s hard and unclear, really is, as was mentioned by Paul, that the use of system charges, I think is a big potential problem.
I think there’s a lot more discussion that needs to happen around that because that could that could be a revenue killer for a battery, as we’ve seen with a couple of other batteries that are connected that need to pay use of system charges. But I think what this rule does do is really open up new ways of thinking about colocated VRE, whether it’s greenfield or brownfield sites. And it also could have quite an interesting use case or impact on some of the thinking around renewable energy zones around the place and how you actually integrate storage into them.
Instead of, you know, what’s happening now to some extent, where people are looking at building separate standalone batteries, that becomes much more of a colocated scenario with VRE. And one of the benefits, of course of that is that you’re starting to leverage connection assets that already exists for the renewable plant itself. And if there is a framework to allow economic colocation of the bears, and I think, Paul, to your to your question, it is a net benefit. But there is a lot of discussion and water to flow under that bridge. I think before we’re there.
Paul Curnow 16:11
Yeah, you raise a good point in terms of, for me, there’s been a sort of a obviously, there’s a sort of a fight within, if you think of the flow of electrons across the chain, where the batteries best fits. And of course, the batteries have a role at all points. You mentioned, raises. And I guess if you think of batteries in that context, they’re really providing a service into the rears, and I guess perhaps are better seen as something that’s coordinated at the whole of grid level rather than just at a single project level. But of course, there’s many options, as many models in the markets and a lot of different players who would look at that differently. And I guess that sort of brings us on to the revenue side, because at the end of the day, these projects only really work if they’re going to make money, and there’s the economic advantage to doing it. So we’ve seen in recent years that, particularly with these additional essential services that have not yet been fully realized, batteries have tended to rely on a combination of grants.
So we’ve seen Arena, we’ve seen state governments and others sort of subsidized capital costs, as well as some form of capacity payments. And in some cases, that’s topped up by FCAS revenue. And of course, the Hornsdale power reserve is probably the best case in point sort of this example there. So maybe just to pick up again, Paul, coming out of that rule change, and if we think about the revenue models that have been tracking the development batteries over the last 12 to 18 months, we’ve certainly seen the emergence of a few new models, tolling structures, as well as network service payment models. Can you just sort of talk us through how those different revenue structures work? And why would a battery operator choose one over the other?
Paul Newman 18:00
So one of the things that strikes me is the sort of structures we’re seeing now are, in some ways, the easiest to implement, and the most bankable at the moment, and we’ll talk a bit later, but there are some limitations as to how many of these there will be in the marketplace, which then means that you need to look at other models. But effectively, I think, as you mentioned, that there’s the government supported models, and I think that that will cease to be really viable other than through something like the Tessa process in New South Wales. But the two that are current, and I think we’ll talk about for a little while now, in the next 12/24 months, is the energy storage services agreement. That is really an infrastructure rental model. So from the point of view of the developer, build the battery, charge a monthly charge to somebody to effectively have all the dispatch rights to an off taker.
So effectively, all of the market revenue and market participation is with the off taker. And the typical counterparty we’ve seen to those are people like Energy Australia and AGL, who then utilize the battery in a way that suits their portfolio, from that point of view, and doing both energy arbitrage and some ancillary services. The second one is a network support model. And this is where you’ve sort of got a mix of some physical obligations, so effectively, obligations that you, as a developer need to provide certain services to the network to provide services that provide support, and that might be only for a limited number of periods in the whole of the year. And then, outside of those periods, that developer or owner the battery’s entitled then to participate otherwise in the broad range of markets that are available. Limited dollars paid by the network service provider for those services.
So then you go into the issue around what other revenue sources you have, and are available. The thing about both of those models is, certainly the energy storage services agreement has been banked, both with government support and commercially without government support, particularly the one down battery developed by VENA is a good example of those. So I think we’ll still see those models. But they do have a, to my mind, a time limitation before other models need to be adopted to replace those.
Paul Curnow 20:30
Yeah, and of course, key to all of these models is if you think about bringing in debt finance, is it bankable? How do the banks look at this? And certainly, as you say, the sort of energy storage services agreement model, that sort of tolling structure, has had the benefit of being bankable from financiers point of view, particularly the credit worthy off taker. And I guess the question is, how do we see batteries such as the revenue models developing over the next few years, particularly as we get greater clarification on the treatment under the rules. And I guess, for me, and things we’ve already been talking about is this holy grail of revenue stacking. So this idea of using a battery across multiple markets, whether that’s energy arbitrage, or different essential services as Nick described.
Obviously, I think we’ve got a way to go in terms of the market and participants being comfortable with that. let alone financiers. But it’s a very interesting area to think about in terms of the way that you can separate the physical operation of the battery, and what you as an owner operator do with the battery across those different markets, versus the financial arrangements that you enter into that drive the revenue. And I think we’re just starting to see the market sort of start to think about how that could actually play out.
And I know, Paul, as you said, you’ve been working in the energy market for some years, and obviously, before the NEM was even set up, and you talk about the way in which coal and gas generators, particularly the beginning of the NEM, started to build up a so called hedge book on the base of forward contracted revenue as a way to sort of unlock that debt financing. And that’s, of course, if you think about revenue contracts, that’s the exact opposite of a long term tolling structure. Because you don’t have that sort of single off take 10 year, 15 year plus fixed price, like we’ve seen, for example, with PPAs in the renewables market. So I’m just keen to get yours, and also Nick’s thoughts on that model and how you see that playing out?
Paul Newman 22:42
Yeah, so I definitely do feel it’s a bit of a case of “Back To The Future”. And maybe I’ve been around too long Paul, but from my point of view, the issue that the ability you have with a battery, which is sort of quite different from a passive wind or solar generator is in fact, what you can do with the battery from a physical point of view, and what markets you can service that are in addition to basically receiving a financial stream for the sale of energy. So, to my mind, I look and say, Well, how do you separate what are the financial arrangements while allowing the owner operator of the battery to actually take advantage of other revenue sources that are available outside of the energy market itself, or in a way to respond to the energy market that’s different from how it contracts.
So a couple of things that I think this really does do is it allows a multiplicity of contracts. So the concept of revenue stacking and revenue slicing is available. So you may well be looking at a retailer, you may be looking at firming some VRE for example, through those arrangements. Secondly, unlike the sorts of banked arrangements we have both for batteries and even for the DRE’s at the moment, they don’t need to be as long term. The banks need to actually then understand that what will happen is they will be replaced over time. And that’s, well, that’s the process that happened from about the late 90s through to about 2005 as the coal fired generators and gas fired generators, initially, you had to be 100% contracted to be able to get banked, and slowly but surely moved to a hedge book type of model, where they were effectively given rules of racing, as to the types of contracting they could do, the sort of spread of longer term and shorter term arrangements. And the extent to which, in fact, the balance of the generation was merchants.
And I think that’s, looking back at those sort of models, it’s actually very adaptable and appropriate for these arrangements because it really allows a sophisticated operator of the battery to sort of lock in revenue contracts, but at the same time, take full advantage of other opportunities in the market. And the thing about a battery with the capacity to actually provide services all at the same time, different types of services, at that millisecond, really, I think, opens up to sort of say, well, then we’ve got the contractual and financial arrangements locked away, but then allow for developer and banks to look at other opportunities to support the revenue.
Paul Curnow 25:23
Yeah. And I think what you highlight there is there’s a level of complexity here. And which is probably no surprise, while we’ve seen the tolling arrangement, so far, under the long term, energy service arrangements as being pretty well favored in the market, because it’s a lot easier from a developer’s point of view, and certainly keeps the banks comfortable. But I guess, Nick, how do you look at this? I know, you’ve been closely looking at how you could potentially revenue stack? Do you see this as something that’s viable in the next sort of one or two years? Or is this further down the track?
Nick Carter 25:59
Yeah look, I think it is viable in the next one to two years. But there is again, quite a bit of thinking that needs to go into this and just picking up on what both of you have just said that, you know, a tolling contract now like the ones that Gannawarra or Ballarat, which are in the public domain, they are bankable, and they’re fairly well understood. But I think, Paul, as you mentioned, it is going to become more complex. And it’s complex in a number of ways, because you start to interweave contracts and whether they are contracts for capacity, or, as we’ve mentioned, you know, an inertia or a voltage contract, or even a cap contract, for example from the ASX, all of those things need to be able to talk to each other and have a physical potential impact via the contract on the battery and acting in those markets. And I think the art form that you’ve mentioned is really around that techno legal view. And having a contract that can have multiple use cases are all on top of each other across all those markets, and the other nuance here, which is often not thought about is that some of those markets, for example, FCAS contingency are autonomous, meaning that the battery responds at a local level to that market. So when you think about the complexities of that plus dispatching and bidding across all of those markets together, that’s where you have quite a bit of complexity. And it really boils down to how that contract looks for that battery sight. So it’s it’s clearly a non trivial problem. But it is doable, it just means that I think it’s going to take a few years for these contracts to slowly walk from a vanilla tolling contract and starting to interweave more and more of these other other elements into it. But ultimately, you’ll end up with a revenue stack that’s got many different components to it.
Paul Curnow 28:16
Yeah, well, I think you make a really good point. Because if you think about contracts that you sign up to, some of those are going to have a whole range of requirements as to physically what you can do to the battery, obviously, in a tolling arrangement, you’re giving all that sort of dispatch rights and how to operate it to the off taker. And I guess this comes back to my sort of earlier point that to get to get to that model, we have to have less physical requirements under those contracts, and really just the sort of financial outcome. But as you say, we’re some way away from that. And I guess it’s the level of comfort in the market to move towards that.
Nick Carter 29:01
I think that’s right, Paul, just probably adding one more point to that is you asked about whether that revenue stacking philosophy that we’ve just discussed is bankable, and I would say, as per Paul Newman’s example around how people in the banks are viewing this, I think over time, what we’re going to see is that as the complexity goes up, you’re going to end up with contracts that are partially merchant still. So they still have some merchant exposure. But they also have a chunk which is contracted. It could be capacity or tolling, so partially tolling a battery, and then possibly having some grid service contracts for inertia or other elements on the side. So that’s kind of the way I see the Venn diagram of a future contracting for the battery, is that bankable? That’s a good question. I think like all of these things, it’s going to take time for the banks to get comfortable, but I feel like if you’ve got a spread between short term/ long term contracts and a bit of merchant in the mix, that’s something that’s quite interesting and potentially bankable.
Paul Curnow 30:09
So let’s come back now, Nick to, I guess the range of services that batteries currently provide. And I guess if you think about some of the ESB reforms, what they will be providing going into the future, and you talked about, obviously, in the high renewables grids, grids with high variable renewable energy within those those markets and the role that batteries can play across some of those other essential systems services. VRE is just another acronym that we all get used to the other one that is creeping in is IBR. So can you just tell us what is IBR? And why is this now such a technical focus for grid operators and policymakers?
Nick Carter 30:55
Sure. So IBR stands for Inverter Based Resource, which effectively means, well, pretty much everything that’s not a synchronous machine. So whether it’s a DC link interconnector or a solar farm or wind farm, with current technologies they’re all classified as IBRs. And the other point here, I suppose, without getting too technical is we’ve got a couple of classes if you like, of IBRs. You’ve got current source and voltage source IBRs. And at a very high level, current sources are grid following methodology and voltage source is really around a grid forming philosophy. And I think, to your point, what we’re seeing now is that the IBRS that are in that gid following mode are really seen potentially as a detriment to the network strength in a particular area, on the whole, as opposed to being a net neutral net benefit to the network, whereas grid forming is starting to be seen as more of a net benefit to the network. And I think, this whole topic around how we deal with this high VRE penetration and grid forming inverters that have virtual synchronous machine modes are going to become really quite critical. I think, you know, the ESOO or AEMO recently released their ESOO for the NEM and one of the big, quite alarming things that leaps out of that when you look at that is the minimum demand on the NEM, forecast. And what thats showing is, you know, we’re basically going to run out of inertia at some point, because we just don’t have enough spinning machines left during these times of peak solar production. And that’s where things like virtual synchronous machine mode on new IBRs with new features is starting to become really critical. And that’s going to help in a number of ways across all those areas.
So I think what we’re seeing is really, virtual synchronous machines providing synthetic inertia, as a primary use case, and those things are going to become more and more important. I suppose the other point to make is that one of the main tools right now for this lack of synchronous inertia is really syncons (synchronous condensers). And, you know, the example in South Australia of putting in syncons is a good one in that context. And I suppose I don’t have anything against syncons (synchronous condensers), per se, but they are a sort of one trick pony, so to speak. Whereas, as we’ve been discussing, a battery can offer that synthetic inertia whilst doing many other things. And therefore, as opposed to being a net cost to have syncons, you’ve actually got something that costs money that can produce revenues in a number of ways and actually help support the rollout of the VRE going forward. So I think this topic of minimum demand and inertia is going to become more and more important. And it should also be noted that other places like Tasmania, even though they’re part of the NEM, in the ESOO main graph are kind of excluded. They’ve also got minimum demand considerations, as does the WEM. So this is not a problem that’s going to go away, whether it’s the NEM or other parts of Australia or even even Asia.
Paul Curnow 34:51
Yeah. So you mentioned the minimum demand issue. And of course the ESOO sort of highlights that around the Industry issues. But if we think of syncons versus virtual synchronous machines, I mean, how does that play out from a cost point of view? I mean, the battery you’re describing, a VSM as I understand it, is really the next cutting edge level of technology around batteries. So where does that sort of stack up from an economics point of view? How commercially viable is it at the moment?
Nick Carter 35:26
So that’s a great question. I think if you do a direct back to back of a syncon versus a battery with these advanced features, like virtual synchronous machine mode, I think and this is very high level and generalized, but the battery will cost more for a given amount of inertia or use case. However, as I was saying, the fact that the battery can actually make money in various markets over and above providing that synthetic inertia means that you can claw back, it’s not just a sunk cost on your balance sheet, you can actually make money out of it. So that’s one point. The other point that you’ve mentioned is what does it actually cost? And I think the really important thing, when thinking about an IBR, with virtual synchronous machine capabilities is that the bulk of that capability is really software.
So it’s not necessarily huge hardware changes. It’s mainly software and the way that the control system works to mimic a synchronous machine is primarily about the software. And whilst it’s not easy, software is generally cheap and doable compared to hardware changes. So I think the Delta Paul, that you were kind of asking you about between an advanced high feature inverter versus a traditional inverter is not that high, because it’s primarily a software focus. So there’s some good examples out in the market, of course, around the Dalrymple Hitachi ABB battery. I think the Tesla Hornsdale extension is also demonstrating some of these more advanced capabilities. So I think the key really here is getting AEMO and others and grid companies to start accepting and looking at what these things can do.
Paul Curnow 37:25
So we’ve sort of been through the different technologies, we’ve talked about the different services that they can provide, particularly as the rules evolve. I guess the other angle to all of this is really the the sort of corporate market. If you think about corporate PPAs, and the appetite that’s grown in that market over the last four or five years in Australia, but also globally, reflecting net zero commitments and corporates wanting to be 100% renewables, we’ve seen in just the last 12 months or so a real progression from 100%, renewables to this concept of 24/7 carbon free energy, which I think perhaps Google coined.
And that’s really this idea that rather than looking at renewables procurement on an annualized basis, you look at it on an hourly basis. And so Google make the point that on an annualized basis they’ve reached 100%, through the procurement program in the last couple of years. But on an on an hourly basis, it’s only 60%, or a little bit above 60% of the global energy load. And so their target is to get to 24/7 carbon free energy. And that’s a huge challenge of course, to get energy grids to net zero.
So I wanted to just pick that up now and talk about the role of batteries in helping corporates reach these clean energy targets. And a question to you, Paul, I guess, in terms of, from a both a contracting and a market facing point of view, one of the issues with that is how do you sort of make sure that the battery is green at all times as it’s being used? And so the so called Green washing issue arises, as we use batteries in relation to corporates procuring energy. So how do you see that being managed by both operators? And also the corporates?
Paul Newman 39:22
Yes, it’s a great question. And I think, obviously, today there’s been the rise of sort of the VRE and as you say that the generation side of things, but with the rise of the need for being more confident about green electrons, and in fact, green hydrogen, you then turn to what are the techniques?
The obvious one is physical connection. We will definitely see colocation. I’ve talked before about some of the issues associated with that, that will form part of it. But I think the vast majority of the way in which you deal with the charging of the battery from the grid and to ensure that that is charged In a green way, will be through financial arrangements and a financial arrangement with the VRE is a clear way in which to support the expansion of the renewable generation, at the same time as dealing with the charging of the battery at those periods, and it sort of is almost symbiotic, because of the capacity later. It’s sort of time shifting for the battery to in fact support and firm the VRE.
The other technique which we have seen used is obviously the use of LGCs, or ACU’s, or other voluntary products, and certainly those have been around for some time going back to the Green Benefits Scheme, where people voluntarily surrender these sorts of products. And we’ve seen those used for other commodities like LNG and the likes. I suspect, we’ll see a variety of those three principle techniques, probably more likely those that are contractual rather than physical.
Paul Curnow 40:57
Yes, certainly listening to some of the remarks from from the head of energy at Google they talk about exactly that. And so corporate procurements, whether that sort of financial PPA only gets you sort of so far in batteries, whether that sort of colocation, physical use of batteries, but within a portfolio, I think it’s going to be well, they talk about that being very, very important.
Paul Newman 41:23
Paul, I think that’s quite important. The obvious thing is that energy storage is not, you know, it’s connected directly to the grid is drawing electrons that are not green. And that’s really how you manage that.
Paul Curnow 41:35
So, Nick, just to sort of close out then our discussion, I want to sort of pick up on that last point around how batteries, and you mentioned this earlier, the way that batteries can provide firming services, particularly if you think of all that VRE in the market. And so if you think about batteries then being deployed, do you see that really playing a role within portfolios? Is that sort of the, commercially, economically, would be one of the biggest opportunities for batteries, the way that they can be a service to those that have the VRE portfolios, or indeed, using batteries in that mix? Or do you see these being very much viable sort of each battery standalone?
Nick Carter 42:23
It’s a great question. I think the evolution in my view is that people, developers are going to continue to do stand alone, one by one, batteries, often not colocated with VRE, partially due to the rule change discussion that we just had around colocation. And that will be the dominant way that people move forward, I would say in the next 24 to 36 months, maybe with a tolling contract. But I really don’t think that’s where it’s going to end up. I think there’s a much more economic and more sophisticated view, which is around that portfolio view that you’ve just mentioned Paul, where you’ve got a fleet of VRE, potentially multiple batteries of different durations, different chemistry, some of them may be colocated with VRE, some of them not, and a suite of different contracts for those batteries, including firming the portfolio, and then the really difficult thing is going to be managing those assets all together to create the lowest firmed cost of delivered energy from the portfolio.
And I think that’s really the holy grail, and where it’s going to end up. And what’s really interesting about that line of thinking, of course, is that if you think about, say, a large hydrogen facility, for example, which which needs the lowest cost, firmed power or energy that it can get, this is where those large loads are going to be served via that philosophy. So I really do see, not sure of the timing Paul, but probably three to five years time this is where this is where it’s going to be. I think. VRE portfolio with multiple different storage devices, and should actually add, it’s not just batteries, of course, it could be pumped hydro, and hydro as well as part of that, that portfolio.
Paul Curnow 44:23
Yeah, well, so many, so many issues to dive into. We’ve run out of time, unfortunately. So we’ll have to leave it there. But so many other things we could pick up. You talked about EVs and integration of that, DC coupled models behind the meter. And then of course, other as you say, other storage technologies beyond the sets of batteries. Hydrogen, of course, being a big future there. But that’s all we got time for today. So thanks again to both of you for joining the discussion, insightful contributions. It was really great.
Paul Newman 44:55
Thanks, Paul.
Nick Carter  44:56
Thanks, Paul.
Paul Curnow 48:35
You’ve been listening to the first in our series of Energy Transformed podcasts, brought to you by Ashurst and RenewEconomy. I’m Paul Curnow, Global Co-head of energy at Ashurst. And today I was joined by Nick Carter, principal at Akaysha Energy, and Paul Newman, also a Partner with Ashurst. The next part of our Energy Tansformed series will be a live webinar on October 13, where we’ll be focusing on how we can get to net zero. There’ll be more details on the RenewEconomy website in coming days. I hope you can join us.
