Alan Kohler: Well, this week our guest on the KGB interrogation is the CEO of Origin Energy, Grant King. Thanks very much for subjecting yourself to an interrogation by the KGB.
Grant King: Alan. I look forward to it.
AK: Now, perhaps you could start with the government’s decision to cancel the hot water service subsidies at five o’clock on Tuesday. What do you think of that?
GK: The broadest answer to the question is that I think there’s been a very large amount of subsidies put towards various forms of renewable; solar, wind, throughout the world. Understandably, people want to see our economy decarbonised. I think with current economic times governments are looking to balance their budgets and to save money and I think a lot of those programmes throughout the world have been withdrawn. So, I don’t think there’s actually anything hugely unusual about that. As I understand the programme was always to terminate in 2012 anyway.
AK: You’re such a diplomat, Grant. Rheem is getting stuck into them.
GK: Well, that’s understandable.
AK: And what do you think of the fact that they just came out and did it without warning anybody?
GK: That’s a bit like companies issuing profit warnings on the day and everyone says why didn’t they tell us yesterday? I mean there is always a day when a piece of information breaks and it always seems like a surprise. New South Wales went through the same process following the change of government in New South Wales with the withdrawal of subsidies for solar rooftop PVs, but I just think it’s part of a broader trend that sees people far more questioning about the level of their subsidies than the, if you like the public good that’s been achieved by them.
AK: Do you think in general the renewable energy targets and certificates and all that stuff are an inefficient, expensive way to achieve renewable energy?
GK: Well, in a similar vein there’s been discussion about the solar flagships programme and the fact that two major projects that were going through the review process and those flagship programmes have also not proceeded to finalisation and that was a million dollar programme targeting support for two projects, each project receiving around four or five hundred million dollars of public subsidies. Now, at the end of the day there’ll be a whole series of judgements. People have different views about, as I say, the public good of these things – but that is a lot of money in the current circumstances.
AK: We’re asking for your view. What do you think?
GK: Look, if I take the two solar flagship ones and if I take solar hot water installations. One of the two programmes was really trying to demonstrate something new, something different. It was a thermal solar project. One was a solar PV project. In my view, enough money has been put to solar PVs on rooftops, not to need to demonstrate that we can also do it in paddocks, and effectively the size of the subsidies simply reflected the different value of electricity in a paddock versus on a rooftop. You know, wholesale cost of energy versus the delivered cost of energy and the difference was just a bigger subsidy. So, I don’t believe one of the projects was demonstrating anything new and therefore doesn’t in my mind pass that test of public good in relation to the amount of money that’s been invested. Solar hot water systems have been installed throughout Australia for a long time. They’re very effective. We’ve provided a lot of solar hot water systems in our business, I think we’re probably the largest installer of solar PVs as well. But we should be moving towards these things being economic in their own right. And solar hot water in particular would be in that category.
Stephen Bartholomeusz: If the subsidies are removed or not taken advantage of, what happens to the 2020 target; 20 per cent by 2020?
GK: So, if I answer that question a little bit in reverse, what happened through ’09, ’10 when there was a very significant state-based move towards feed in tariffs that essentially over-stimulated the solar PV industry, they actually flooded the markets with RECs and those RECs were very cheap because they were long…
AK: Which stands for Renewable Energy Certificates.
GK: Renewable Energy Certificates, and that’s what you have to acquit in order to meet your liability under the renewable energy target. So, a somewhat ironic situation is the market’s awash with REC certificates and, acquitting the target, we would say we’re covered through 2015-2016 because we have certificates that we bought as part of that process and I think our competitors would say, certainly AGL I think would say, they’re also largely covered. So, in respect of the REC scheme, broadly the liability’s probably covered through to 2015 already. That leads to noise around why aren’t we building more things? And the answer is they’ve already got built through all the solar PVs that went on the roof because that part of the industry got over-stimulated. So, this is an area – and I think we would say and I think business at broad would say – there’s been too many of these programmes sort of thrown into the short term with the view that they would create, in aggregate number, that they would all work together. So, the RET target is there for 2020, a lot of that’s now going to have to be satisfied through a bill probably squashed into 2015, ’16, ’17.
Robert Gottliebsen: If I could change the subject, Grant, is it true that the electricity generating companies have had to pay almost four billion dollars in carbon tax after the rebates? And if that’s true, what effect is that going to have on profits and prices?
GK: So, to answer that let me give you some sort of factual basis for that discussion. At $23 a tonne and the average carbon intensity in them is about a tonne per megawatt of electricity produced, the number will be big. You know, if those sorts of numbers are true.
AK: What? Four billion? Is that right?
GK: Well, for example, from a larger power station which could produce 20 million tonnes of carbon a year, so 20 million times $20, [that’s] $400 million straight away for just one power station. So it’s not hard to get to a number like three or four or five billion dollars, so I would imagine that’s in the ballpark of a correct number. Now, that’s remembering that for the first three years the scheme is a tax. Bob, in dealing with your question, obviously, everybody will pay $23 a tonne in the first three years through to 2015 and the generation sector is the biggest emitter of carbon. It will pay a very significant bill and that in the normal course would be what ends up on a consumer bill and that’s why I imagine the government has said we’ll also adjust tax to try and keep the average consumer roughly whole. And we would formally agree with their analysis that they will be kept roughly whole. And just to put that into perspective, the four or five billion dollars is a big number, but the average household uses about seven megawatt hours of electricity, so seven times $23 is about $150, so that’s where that sort of household compensation number comes from. So just be a bit careful, because at an industry level lots of megawatts get generated and it’s a very big number, but we only use, as I say, on average seven megawatts to live in our homes.
SB: For generators though it’s a big issue, isn’t it? MacGen said that it turns them being a profitable generator into being an unprofitable one instantly, and that there were cash flow issues associated with that.
GK: So, let’s then go through the phases. What happens is in the initial phase, so when it’s implemented on July 1, the scheme I think is reasonable in that you incur your liability, but you only pay 75 per cent of it at year end and then the balance post that, so you’re getting the revenues through the year and you’re actually settling that liability. Basically, you generally pay your tax through the year and the year end as well. So, it’s actually okay when you implement it in that fixed price period. 2015-plus we enter this trading period, so it’s not a fixed price anymore. It’s not a tax in the literal sense of the word. It’s going to be whatever the price will be. And the government is trying to deal with the working capital issues there by quarterly option of permits, so not making everybody pay upfront in one big hit and having a regular release of permits to smooth the cash flow effects. The issue that the industry is very focused on is however that between probably a year or so out in that period 2015 when it becomes traded, the industry will start to think about how do we bring certainty to our long term contracting activity because we’ll now also have to acquit that carbon liability to our contracting activity and in that period we may have to buy permits two or three years forward and that is the issue. It’s this transitional period. So for the first year, for example, it’s not such a big deal because the government is allowing effectively a settlement at the end of the period. Normal trading beyond 2015 we have a situation where it’s quarterly, so you’re trying to reduce the working capital impact, but if the industry wants to write long term contracts that span that transitional period, it could have to outlay very, very large amounts of money to back its contracts. Now, the industry hasn’t a choice and that is not to write long term contracts and trade almost entirely spot, but that would bring a lot of instability to the industry as well and that is not the way the industry has historically operated because of course it increases everybody’s risk exposure to short term prices and that’s not the way the national electricity market’s worked.
SB: And presumably they could be gamed, so you could see price spikes?
GK: Well, if you entirely have a spot market, you will see the underlying volatility in the market and the reason we write long term contracts and hedges is so our companies don’t blow up if we see underlying volatility. Now, gaming is just a function. You know, game is just another word for commercial behaviour in the market. I mean at the end of the day electricity has been bought and sold now for ten years and there have been days where it’s been $12,500 a megawatt hour. If you have a naked exposure to that, that breaks companies, that breaks retailers or it breaks generators, counter parties, and that’s why we write long-term contracts. So, if we continue to write those contracts, we need also to hedge the carbon price and that’s the big issue for the industry. How do we manage through that transition?
RG: But Grant, you’ve been warned by Tony Abbott, you and all generators, that the rules will change after the election if he wins, so that if you have written long term contracts and you lose by them, then he will declare that your own fault and you have to pay for the loss.
RG: But Grant, you’ve been warned by Tony Abbott, you and all generators, that the rules will change after the election if he wins, so that if you have written long term contracts and you lose by them, then he will declare that your own fault and you have to pay for the loss.
GK: Well, at the end of the day I respect the policy differences the various political parties have, but our first obligation is to comply with the law – and the law is from July 1 we’ll have a carbon pricing scheme. Now, I entirely respect the party’s position to say we will change the law, but like every change of law in Australia they’ll have to look at the legacy impact of that on organisations that have complied with it. But if the consequences of that position is to say no one should write long term contracts or hedge away that risk, then I think we will bring upon our market and our customers a far greater discomfort than is necessary.
AK: Just taking you back, you said that the $23 a tonne carbon tax from July 1 won’t be too bad because of the way it’s operating – you have to pay at the end of the year like a tax. Can you explain that in a bit more detail?
GK: So, if you operate a power station that’s got a carbon liability, you’ll need to buy permits to offset that liability, but the settlement of that acquisition of permits will occur at year end, so you pay I think 75 per cent at year end and then the remaining 25 per cent, I think, in a subsequent period. And to the extent that you’ve been able to, you’ve already priced through the cost of those permits in the electricity you’re selling, so your revenue is ahead of your costs. That means the working capital impact through that period is minimised or it certainly should be manageable. Everybody will be exposed to their ability to pass that carbon price on, but of course that’s what, like it or not, that’s what a carbon price does. Some would have more or less ability to pass that carbon price on, but that big working capital effect is ameliorated or somewhat moderated through that initial period because of the deferred settlement on the payments.
AK: And how do you feel about the ability to pass it on? What’s going to determine that?
GK: So, each entity incurs its own specific liability. It’s a phenomenon of its own carbon intensity, so a brown coal power station has a much higher carbon intensity than a black coal and a gas and, say, a renewable and wind farm which has none. Now, each of those entities will clearly, and should, act in its own economic interests. It will seek to pass through the cost it’s incurring, but the market will determine what that clearing price is and therefore the ability of everybody to pass it on will depend on, if you like, the clearing price in the electricity market which is the way the current market currently works. So, if I could just perhaps take one second I will try and explain it better than I might have done –
AK: I’m trying to get a view of as to will you be able to or will the companies be able to pass it on?
GK: So, in the detail it’s got a lot to do with where it changes every power station in what we call the merit order, so at the moment brown coal fired power stations are the cheapest power stations to run and they’re therefore low in the merit order and they always run, so they’re base load and they always run. Now, their costs will go up substantially. Their costs will go up by maybe $30 a megawatt hour, $23 a tonne by something like 1.3, and their coal cost is something like six dollars. So, their cash cost will go from $6 to maybe $36, so clearly their position in the merit order will change and therefore their ability to recover that cost will be different than it was before that cost was incurred, but it does depend on the clearing price and it does depend on demand for electricity. When we need all our power stations running for example, then they should all be able to recover their costs.
AK: But there are some of them might be still be first up in the merit order.
GK: They may well be.
AK: In which case they’ll be fine.
GK: That could well be the case.
SB: And you might even if fact get a cash flow benefit?
GK: From a timing point of view, because we’ve got these three different periods of time, it is actually possible that you might actually have a benefit in that first period. If you’re able to fully pass it through and defer the payment, that’s the way the system works. If you settle up and towards the year end, it might actually be a benefit.
SB: How does it affect Origin?
GK: Look, the carbon intensity of our portfolio is much lower than [National Electricity Market] average. We’ve got a lot more gas in our portfolio than coal and the coal in our portfolio is NEM average. You know, its carbon intensity is about NEM average. So, at a sort of simplistic sort of overview level, broadly you’d expect the electricity market to recover its costs at the average intensity of the whole market and those with intensities less than the market might recover a bit more and those whose intensity is more might recover a bit less, and that’s exactly what should happen because it should force a change in the merit order and that’s what causes steel substitution, so that’s the way a carbon price is supposed to cause a change in the amount of carbon emissions.
SB: Independently of the carbon price index, consumption of electricity has actually been falling for the last two or three years. Why so?
GK: Yeah. Well, there are two good points perhaps that can be made in response to that question. Firstly, we think it’s maybe a three per cent over three year-type effect and it’s all happened since 2008, so I think as an industry we feel there are three or four things packaged up in there. There’s probably some economic effect, mainly in what we call the SME segment, so small to medium enterprises. That’s where we see as a business that the economic circumstances of the last few years have had the biggest effect, [on] the smaller business enterprises, so we think there’s some economic effect, particularly in that segment. We think there’s some efficiency and price effects coming through, so there have been some pretty substantial increases in electricity prices and that, together with some of the efficiency initiatives, is having a bit of an effect. Clearly in the back part of that period last year there’s a weather effect. There’s no question the weather has been more benign, so effectively we haven’t called for as much air conditioning or as much heating, so there’s a bit of a weather effect in there. And there’s also been a solar substitution effect. So, that ’09, ’10 period again where a lot of solar rooftop PV was brought into the system doesn’t mean that people are using less energy, but they’re of course getting it from a different source, so there’s a bit of a solar PV effect in there as well. That comes back to the earlier question you raised about the good of these schemes. It’s hard to tell whether they’re using less energy for efficiency or they’re just drawing more energy from sources like solar PV. So, generally those are the four areas, but it’s very difficult to prescribe a particular proportion of that three per cent to any of those areas. And I think the important other point to say is that having had a mild summer, we really don’t know where peak demand is, so if we were to have a hot summer again next year, peak demand may still well be a record peak and I would actually probably place a bet today and say that come next January, even though average energy consumption is on a bit of a decline, we’ll still find that the next peak is probably still a record because people are still putting air conditioners in their homes. They’re still putting more flat screen TVs and computers and we’re building bigger houses, probably not quite at the rate that we used to. So, my bet is when you have that next really hot day which is probably next year now, we’ll probably still see demand for electricity hit a record even though electricity consumption is declining.
GK: So, that follows from the last question. That little bit of demand moderation, as distinct from capacity – in other words the requirement for energy across the year as distinct from at the peak –continues in our mind to push back the need for base load generation. So, in our view, we probably don’t need to see a new base load power station built in Australia much this side of 2020, towards the end of the decade.
AK: Wow. That’s incredible.
GK: Yeah. We will need peak built and I’ll just take you through why that’s the case. So, essentially, there’s plenty of energy – you know, there’s the ability to generate plenty of energy and meet energy demand. And what that means is that when you take the mandatory effect, and you asked the question previously about renewable energy target, it so happens that the amount of energy that’s necessary to be brought forward by that scheme, in our view, roughly equals the growth in demand for energy through to 2020. So, in fact the primary investment in generation, once the base load, it will be renewable to meet the mandatory renewable energy target. And just to give you some benchmarks in your mind, currently something like 10 or 12 per cent of our energy is coming from renewable sources, but it’s important to remember that it was 8 per cent just from roughly the Snowy hydro scheme, but the last five or six years we’ve added four per cent maybe and then we’ve got to add another eight per cent, twice that much again, in renewable energy to get to that 2020 target. So, primarily the major investment in generation will be renewable to meet the 2020 target, which is mandatory, and that sort of crowds out a new base load investment. But the problem with the renewable energy, most likely wind and solar and more wind than solar, is it’s what we call somewhat contradictory ‘interrupt of the base load’. So, this provides energy, but it doesn’t provide firm capacity in the system. And so the other form of generation that will probably still require some further build is open cycle generation to be there when you need it, you know, to provide that capacity on those very hot days. Now, in our view, the state that will soonest meet that extra capacity is Queensland because it’s the strongest growing state, particularly in terms of its energy economy. New South Wales doesn’t need power for a long time. And I think in Victoria quite a bit depends on what happens around whether there’s effectively a capacity withdrawal around Hazelwood as part of this broader carbon policy. If there’s capacity withdrawal in Victoria around, say, Hazelwood, it doesn’t require another base load power station to be built because you’ve got this energy coming from wind for example, quite a bit of it in Victoria.
AK: Would that replace Hazelwood? That’s a lot.
GK: And they need to firm it with open cycle.
AK: So, we’d need to build a new open cycle?
GK: Yeah. Well, the power station we’re just in the process of finishing Mortlake in Western Victoria is being built in some respects because of that direction of things that we need more open cycle. And I think the important thing to understand is that Victoria has historically been an exporter of energy in the national electricity market and it’s exported its cheap brown coal generation effectively north. So, if someone decides and, you know, Hazelwood goes through this capacity withdrawal process, Victorians won’t run out of power, but it will essentially export less to the north. But it will need to have within the state the capacity to make that electricity supply firm, which is why you’ll need more open cycle in Victoria to firm that. That’s the case if it was to be withdrawn. If it’s not withdrawn, you just go back to that underlying diagnosis. You just don’t need base load for a long time.
GK: So, there’s no question a blend of 20 per cent renewables will add to power and you could do the maths because of the RET penalties around $60, so if you have 20 per cent of 60, you’re adding maybe $10 or $12, because it was 20 per cent of the $60 across the whole market. You know, maybe you’re adding $10 to something that should be roughly around $50. Now, to take that through to a consumer level, a consumer pays around about $150 to $200 a unit in their bill for their energy, so at the consumer level, the mums and dads and households, it’s a bit like the carbon price coming through, it’s not that big. You know, it is, but it’s two to three dollars a week and I’m not disrespectful at all as to every dollar for a consumer, but it’s probably not that big a change. But if you’re a big consumer – if you’re an aluminium smelter or if you’re a big industrial consumer of energy – the price you pay looks a lot more like that wholesale price, so it’s much more material, much more material for large industrial consumers and that’s where the change will occur, Bob. That’s really where I think you’ll be getting people saying this is quite a material change for us.
RG: And this is going to change our industrial base, isn’t it? We’re going to do a lot more work overseas as a result of this?
GK: Look, it’s not as simple to make that statement. I say that in part because the nature of the Australian economy will change. If I could digress to go back to this question about demand, and why has demand stopped, and I could add just one element that might be a little bit relevant to this discussion and that is that the other thing we’re seeing probably in the last six months is a bigger conversation about manufacturing in Australia and whether manufacturing is going to close and the impact that might have on energy demand as well because manufacturing uses quite a bit of energy. Now, that’s not a GFC type conversation. That’s not one that’s been happening for four years. It’s one that’s been happening more so in the last twelve and six months in particular and our view of that is that that’s more a competitiveness of Australian industry conversation. You know, how competitive can Australian manufacturing be? Now, when we look at that into demand forecasts, we see some erosion there and that’s a little bit to your question, Bob, but we also see growth, so for example in eastern Australia the LNG projects and the coal mines will probably grow power demand more than it will shrink by virtue of these effects. So, across the whole economy, competitiveness issues to me are part of the normal evolution of an economy, from one particular mix to another particular mix and it’s perhaps reflective of the broader Australian story at the moment that it’s actually the resource development that’s happening across Australia, but in particular in Queensland for example and eastern Australia and a lot of that’s grid connected. It sounds a funny term to use, but it’s happening where there are electricity transmission assets, so a lot of it is adding to the demand on the grid. In the northwest of Australia it tends to be more that the generation is built specifically for the projects and so we sort of see that as being probably not a major change in demand for energy. So Bob, if you go back to your question, it’s very difficult for us to say what will determine the competitiveness of Australian manufacturing. There are a few industries like aluminium which are extraordinarily energy intensive, but for many, many manufacturing industries, energy is one of a number of input costs and I couldn’t give you an informed comment about the relativity of that change versus the impact of the Australian dollar for example and I’d caution against drawing a direct line to energy costs and saying that the linkage is as direct as perhaps you’re probably suggesting.
SB: The other dimension to that LNG energy landscape is as the LNG projects in Queensland come on stream, and those in Western Australia but particularly the ones in Queensland come on stream, including yours, increasingly gas will be priced on an export parity basis. You’ve been saying recently that in fact coal will also shift quite rapidly towards export parity pricing which is another sort of structural shift in the pricing of energy in Australia.
GK: Yeah. So, I’ll give a view of how it plays out and you can agree or disagree with the view. If we go back to the earlier diagnosis, we don’t need any base load before 2020 broadly – I mean ’19, 2020 – so we’re not going to use gas or coal because we just don’t need it at all the power stations. The role of gas is open cycle to firm the interruptibility that comes with renewable. It doesn’t matter really what the gas price is because if you look, for example, at our own half year results, you’ll see that those open cycle power stations run maybe two per cent of the time or three per cent of the time and they don’t use much gas and in the case for example of Mount Stewart which operates in the same place in Queensland, in Townsville, we run that on aviation fuel, very expensive, but it just doesn’t matter because when the market is at peak power prices are $1000, or $2000, or $12,000.
AK: Aviation fuel?
GK: Yeah. So, the important thing to understand is that when you’re firming that supply the fuel cost really doesn’t matter that much because of the way the market works and the fact that the price spikes. The question then becomes where is the next big source of energy in Australia beyond 2020? That’s the big question. Is it going to be coal? Is it going to be gas? I could tell you at current carbon prices it’s more likely to be coal in the absence of any change because at $23 that’s not fundamentally changed the relative competitiveness of coal versus gas as a fuel, so on current settings coal will still play a major role in power generation in Australia for, you know, the long, long term.
GK: So, one game changer, and the reason I say no, is that if we did sit back and say we want the best of both worlds, we want still to have competitive advantage around our energy, but we want less carbon intensive energy, and you expect me to say this in this conversation but you know the project we’re working on, which is a long-term project, the best resource in our view, the next resource in Australia is hydro in New Guinea. Base load hydro. And technology is moving away. If you look around the world, you’re seeing some of these more competitive renewable energy resources are now being moved because you can’t move the fuel. You can move coal and you can move gas, but you can’t move wind and you can’t move hydro, so you’ve got to build transmission and the cost of transmission is changing dramatically with this HVDC technology. So, you’re seeing in Brazil and Russia and North America, very long transmission lines being built to connect very cost competitive renewable resources. And the vision we have and, Bob, perhaps goes back in part to your question… You know, my view is North Queensland – New Guinea, North Queensland area – has an extraordinary opportunity post 2020 to be one of the most competitive energy intensive manufacturing zones in the world off relatively cheap base load hydro and it’s an extraordinary opportunity if that was to be developed, so that’s the sort of 2020-plus view.
AK: What a fantastic vision on which to end, Grant.
GK: So, we can keep our manufacturing and we can keep our aluminium.
AK & SB: In North Queensland!
AK: Fascinating. Thanks very much.