September 2021
September 2021

There's no doubt that electricity markets across Australia are in the midst of a profound transformation with aging coal and gas fired power generation leaving the market and being replaced by large scale solar and wind capacity. The pace and scale of this change has and will continue to be rapid, with various ambitious state targets further accelerating this change. Such as:

  • New South Wales, which aims for 12GW of renewable energy capacity and 2GW of storage by 2030:
  • Queensland and Victoria both have 50% renewable energy targets by 2030.
  • South Australia has a 100% renewable energy target by 2030; and
  • Tasmania has a 200% renewable energy target by 2030.

There are going to be many challenges as we seek to manage all of this additional generation, often generating at coincident periods of the day. On Sunday, 22 August, between 12:00 and 1:00pm, a new record was set for minimum operational demand. At the time instantaneous renewables contributed around 57% of total generation across the NEM. Linked to this, and also a couple of weeks ago, Origin Energy announced that they expected to turn off generation units at their Eraring power station for extended periods of time. Eraring is the largest coal fired power station in the mix and they are needing to do this, they say, to keep their generation business profitable amid a flood of cheap renewables.

In a podcast discussion led by Mark Asbjerg, Principal Consultant in our energy markets team, the implications of this additional renewable energy are considered. Are we going to have too much? How can generators continue to make a return on their investment in such a market? And what is the value of storage moving forwards? Mark is joined by Gilles Walgenwitz, Energetics’ Head of Energy and Carbon Markets, and a close observer of Australia's energy transition for many years now. He is also joined by Anita Stadler, Head of Renewables Investment at Energetics.

Listen to our podcast.



The following is based on the transcript of the podcast episode.

Do we have too many renewables?

(Anita Stadler) What a great problem to solve Mark! I thought a couple of years ago when the Abbott government was in charge that we'll never get there. Now I wish we had enough, but we haven't arrived yet!

(Mark Asbjerg) It’s a fascinating space to be working in at the moment. If I focused on spot markets, we had this combination of generator outages, the explosion at the Callide power station, the flooding at Yallourn, and increasing wholesale gas prices. Yet we had one of the highest priced Q2’s on record! What stood out to me when you looked at this high price was the amount of volatility that was focused on the morning and evening peak periods, and prices during the daytime hours actually remained quite suppressed. I know from a recent AEMO report, spot prices during the middle of the day in Queensland, through Q2 of this year, were actually below zero for nearly 30% of the time. That's right in that period where you have all that coincident solar generation.

What has been the impact of the increasing penetration of coincident renewable generation?

(Anita Stadler) It is more than just increasing penetration of coincident renewable generation. You also need to consider the relatively low or at best flat levels of demand. These drivers combine to gradually erode dispatch weighted average prices. Consequently, we observe a downward trend in run of plant renewable PPA prices to compensate the buyer for the decreased value of the spot prices they are expected to receive.

Beyond, financial PPAs, corporates are exploring ways to increase the utility of their renewable electricity hedges. However, they will also find that many retailers do not attach significant value to additional generation during the middle of the day, even if there's a good correlation with the corporate buyer’s load shape.

The middle-of-the-day is when most negative price events are observed and expected to occur with increased frequency. However, given the resource mix in each state, the time periods and magnitude of this trend will vary across jurisdictions. You called out Queensland, However, just looking at Q2 2021, there has been an increase across the NEM from 4% in Q2 2020 to 5.1% over the same period this year. Tasmania has also been called out with 6% of the volume in negative price territory during Q2 2020. In contrast with much of the NEM negative prices were between 17:30 and 20:30 due to the dominant wind generation profile in that state. The financial impact of these negative price events is still subdued - in Queensland for example during Q2 it was $1.30 per megawatt hour and in Tasmania 50 cents per megawatt hour. This is because when prices moved into negative territory, they seldom stay lower than minus 100 for prolonged periods of time. Nonetheless, there's an increased risk of the frequency of these events occurring and these events may start becoming more prolonged. This requires more accurate sell forecasting and sophisticated bidding capabilities from the generators that are participating in this market.

It's riskier than ever for a renewable developer to be taking merchant spot exposure, with the increased frequency and duration of these negative pricing periods. What can generators do to avoid the spiral of lower PPA prices and merchant revenue?

(Gilles Walgenwitz) Anita highlighted the increasing covariance risk due to the high dispatch of coincident variable renewable energy generation and, in this context, what we are seeing is that some generators are reassessing their revenue strategy. Beyond the sale of generation-following (or run-of-plant) contract-for-difference, the question is whether these generators could sell firmer products and get a greater value for such less risky products from the buyers. If so, what is the right mix of power generation assets or contracts for them to enter into, to reduce their own market risk?

I can talk here about the ability to offer long-term renewable energy flat swaps or shaped offtake agreements to better align with an offtaker’s own load shape, for example. Such an arrangement provides added value to a sophisticated buyer seeking to improve the utility of a power purchase agreement as a hedging instrument. Let's say I am a large industrial end-user with a relatively constant, 24 hour, seven day operation. It could be more attractive for me to enter into a renewable offtake agreement with a constant volume rather than a run-of-plant arrangement. Even so the strike price will obviously be larger, it gives me a much easier hedge to include in my overall contracting strategy for my load. This added value with lower volume risk can be sold by the generator at a higher price and more in line, I would say, with standard exchange-traded or over-the-counter, firm electricity financial contracts.

With the cost of energy expected to decline in an energy-only market, the value spread between generation following standard financial PPA, a constant volume PPA, or a shaped PPA and even more so, a load following swap, is expected to increase. The more covariance risk you have, the more attractive it would be to purchase at a premium, a flat swap, or a load following contract rather than enter into a generation following contract.

Having said that, the ability for a renewable energy generator to offer such products requires a portfolio approach to project development and management, rather than an asset specific approach. You can offer such firmed product with a combination of assets, risk management instruments or insurance products, but it could be risky for you to offer such a flat swap based only on one asset or even one technology. Take February 2020, in Texas in the ERCOT market during nearly five days of extremely cold weather. Gas pipelines were not available. You also had a number of wind turbine generators that were not weatherised and were not able to operate during the extreme weather conditions. On the other hand, a number of wind generators in Texas were selling bank hedges, P99 hedges. They were taking the volume risk, but not being able to dispatch when actually the market was at the cap of 9,000 US dollars per megawatt hour. So, they lost the equivalent of nearly one year of expected revenue in a matter of five days.

In Australia we have seen some renewable energy generators leveraging a retail electricity licence, adding firming capacity, such as open cycle gas turbines to their portfolio to offer load following retail products. We’re also seeing, when we tender ourselves for our clients, some generators offering firmed products with no volumetric risk and especially flat blocks, backed by a mix of wind, solar and battery storage. So, in summary Mark, I believe that as an alternative volume risk strategy, we will see an emergence of long term base and peak renewable energy swaps supported by portfolios of renewable energy and firming assets being proposed in the market.

(Mark Asbjerg) It really sounds like dispatchable capacity is what's going to be needed to unlock all that additional value. That's sort of the missing piece. But we've got an energy only market, which really only rewards that energy sold. So, it doesn't, to my eye, it doesn't look like you have the long-term investment signal that you need to promote more dispatchable capacity being built.

Comments on long-term investment signals – what is there for dispatchable capacity?

(Anita Stadler) As Gilles pointed out, given the current market design the signal is rather muted for long-term investment in capacity. However, there's definitely signs that this will change, but more importantly, is a recognition that transitions are always challenging and it requires forward looking organisations to invest in new capabilities and skills to actually flourish in this new and emerging market. I agree that you need to balance the hedging benefits with the hedging costs at all times, if you were to develop structured and firmer products to offer the market. However, if you're investing in short and long duration storage assets, or as Gilles also talked about, using gas as a firming generator, it will actually open up new markets for renewable energy generators in time. I think there are strong signals that these markets will become much more lucrative as the design of the post 2025 market starts emerging. This is particularly important if you start moving towards multi portfolio level constructs, which is also increasingly I think, necessary for renewable energy generators to survive, to optimise their revenue. It's very important to invest in these new capabilities. It's not only the physical capabilities, but also people’s skills to optimise their revenue and to actually minimise cause-of-pay charges as well, which is increasingly something that generators need to deal with. It's no longer a market where they can sit back and just dispatch.

(Gilles Walgenwitz) Energetics has been using portfolio performance evaluation methods to support some of those renewable energy generators interested in reviewing their offtake strategy and portfolio constructs. So the idea is to allow renewable energy generators to assess generation investment and risk management instruments targeting a specific offtake product. When doing so, we take into account the risk-return trade-offs in the spot and in the forward markets as well as the risk tolerance of the specific renewable energy business. We consider a technological and geographical diversity when we're doing this type of analysis. For example, which mix of wind solar and firming capacity to consider? Where to ideally locate this capacity, to get complementary generation profiles depending on the resource you invest in, or contract with. We assess net short and long positions, as well as spot exposure and possible risk management instruments to reduce such spot exposure. We gauge the hedge benefits or the hedging benefits against the cost as Anita just reflected.

To your specific comment, Mark, about the increasing value of dispatchable capacity, very clearly, the ability to firm intermittent generation through aggregated demand response, a storage capacity - being battery storage or pumped hydro energy storage - or the support of gas peaking capacity, is fundamental in my view to manage such transition. This support can be provided directly within your own portfolio or contracted with a third party. One of the key questions in my view, is whether we will have some competition in firming services in the future or end up with quasi-oligopolistic position with as small number of providers, such as Snowy Hydro for example.

(Mark Asbjerg) It's clear that governments and AEMO are seeing the importance of dispatchable capacity in the mix. I know a few months ago, we saw the New South Wales government announce a new one hundred megawatt battery to be built in the Riverina to support its own retail electricity contract on a 10 year term. The contract I know is the second biggest in the state and the numbers are… larger than your average electricity contract. You're looking at 1.8 terawatt hours, a $3.2 billion contract value. I just can't help but suspect that it gives us an indication of the general future direction, which retailers and generators are looking at when they're trying to future-proof their portfolios.

What advice would you give to a generator looking to future proof their portfolio, given the significant changes that we're expecting across the NEM over the coming decade?

(Gilles Walgenwitz) The first short-term option potentially is to lobby against the ESB capacity market option! But let's start with something more realistic. We know that the long term investment signals for new power generation capacity in an energy-only market will not be sufficient due to decreasing value of energy in the market with increasing penetration of low marginal cost renewable energy generation. This is nothing new, and you can find extensive literature on the limits of an energy only market to support new generation capacity investment when you have higher penetration of variable renewable energy.

At a high level, this is the missing money problem. We could allow higher scarcity pricing than the current market price cap at $15,000 per megawatt hour; a move that we know is politically risky. Except, if you start saying, we cap what retailers can charge customers, but then you end up with retailers potentially going into liquidation.

We could set up a permanent strategic reserve, basically paying coal fired generators to mothball rather than shut down, which is not too different from what we're seeing in Germany, especially the coal fired power stations in the eastern part of Germany. Once again, politically risky and not really efficient as a non-market mechanism.

Alternatively, we could set up a parallel capacity market. The Energy Security Board is currently pushing for a decentralised capacity market, not a centralised one like the reserve capacity market in Western Australia. The expectation is that such a decentralised capacity market would allow generators to claim credits as a function of the firmness and dispatchability of the assets and retailers to acquit the obligations related to the load that they sell during system peak by purchasing such credits. If a capacity market mechanism was in place through an expansion of the retailer reliability obligation scheme, a renewable energy generator that invested in firming capacity would be able to consider generating revenue from both the energy and the capacity markets - without talking here about revenue from the frequency control ancillary services market or other systems services that could be marketed in the future. So, when seeking to future proof renewable energy generation assets, there is clear interest in a firm portfolio. The question is then whether to own the first response firming dispatchable capacity or whether to contract for it.

We could spend more time talking about the key challenges and implications of such a decentralised capacity credit market, but it's probably best to keep this to another podcast.

(Anita Stadler) I think regardless of whether or not we have a capacity market, the bottom line is that renewable energy developers need to become more sophisticated in managing their portfolios to maximise returns and minimise risk. In this regard, scale matters not only in asset management, where we believe that generators that retain their projects and grow their portfolios will be better able to compete in these markets that are emerging. But we also see collaborative models emerging that will support innovation in the management of risk. For example, aggregation models for non-energy services and over the counter market for financial products specific to renewables to back structured products, we believe will become much more common. But that will require renewable energy developers to grow in sophistication, to interact with these products and manage their risk accordingly.

(Mark Asbjerg) A few key takeaways for me. The first one is really that for renewable generators, straight merchant exposure will become increasingly risky and generators will require sophisticated forecasting and bidding capabilities, just to be able to optimise their revenue strategies.

There's clearly an opportunity for renewable generators to further reduce risk and optimise returns by taking a portfolio approach, rather than an asset-specific approach to managing their renewable energy assets.

The last takeaway is that integrating storage into a portfolio approach could help future-proof your investments by giving them the opportunity to sell firm electricity, derivative contracts, rather than straight spot market exposure.

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