Storage, markets and blockchain
I recently attended a presentation of the proposed Cultana Pumped Hydro Project in the Spencer Gulf South Australia, using sea water. Specifications are 225 MW power, 1,770 MWh storage capacity. It is conceptually similar to the Japanese Okinawa project. The proponents are optimistic that the project will be economically viable and proceed. It it proceeds, it will be important for understanding the engineering and economics of these projects.
Since Australia’s NEM is an energy market, most of the revenue will be derived by arbitrage, but other ancillary services will contribute to the revenue stream. There is the possibility of entering into various contracts, such as to provide firming for intermittent renewable generators. Some of these will be a result of the recent Finkel Review.
One of the interesting outcomes of dispatchable storage is that, in an energy only market, it cannibalises its own revenue stream. Unlike ordinary generation, which derives revenue from supplying energy, storage relies on the economics of arbitrage – the absolute price does not matter, it is the difference. A more volatile market is favourable but supplying power into a volatile market ipso facto reduces the volatility. I discussed some of the traditional roles of PHS in an earlier post. Figure 5.7 from the Cultana report shows that increasing plant power capacity reduces the specific revenue.
At the end of the presentation, Andrea Bunting posed the question as to how the NEM market could facilitate further storage projects. Andrea was really thinking about how this type of project fits into a longer term 100% renewable scenario. This project would seem to be nearly exhausting economic arbitrage at the multi-hour level (batteries are going to operate mostly at the sub-hourly temporal scale) for South Australia. If so, then how much storage is going to be required in a national 100% RE scenario and is an energy-only market up to the task? The figure above suggests no.
This is where the possibilities of peer-to-peer (P2P) networks and blockchain enter. Some distribution network service providers (DNSPs) and retailers have been exploring the role of peer-to-peer energy trading, including the use of blockchain to provide real-time clearance of energy trades. The DNSPs are in the box seat because they own the meter and network infrastructure. Whether they chose to simply apply a per-trade or per-access fee or actively participate in trading is an open question. In principle, the internet could be used to facilitate trading separate from the electricity infrastructure but physical separation also makes the system more vulnerable.
I’m pretty skeptical that P2P of rooftop solar without storage can offer much value to the incumbent system. Most of the value would be in bypassing retail margins, which would certainly be popular, but it’s not obvious to me that the reward would be worth the effort. Retailers like the idea because it provides a way to retain edgy customers. Furthermore, the asymmetry of knowledge works out mostly in the retailer’s favour. But the real potential will come from the capability of dispatchable storage. But storage will be mostly limited to a couple of hours storage and mostly relevant for network support rather than support for the bulk generation system. This is an interesting space.
Back to Andrea’s question, the scenario literature suggests that multi-week storage is going to be required for 100% RE. This storage is usually modelled as either stored sunlight in the form of biomass; prehistoric stored sunlight consisting of retention of fossil fuel plant running gas or coal; hydrogen or methane based storage charged with RE; or variations on electricity-based storage including pumped hydro or batteries.
To give some examples, Palzer and Henning used 45 days of methane storage (equated at full-load electrical capacity for average annual demand) for Germany. Aghahosseini et al. used around 14 days of methane storage for North America. Lenzen et al used biomass equating to 21 days of full-load electrical capacity and Elliston et al. used biofuels, equating to 50 days full-load electrical capacity. Preston used 21 days of electrical storage. Concentrated solar offers a half day of storage but unlike other storage, only charges when there is clear sunlight and surplus power, leading to the ‘big gaps’ problem in winter.
To get a sense of scale, the NEM supplies about 600 GWh of energy per day and the Cultan project is 1.8 GWh. This suggests that a radical re-examination of markets that can accommodate storage are going to be required.
Since Australia’s NEM is an energy market, most of the revenue will be derived by arbitrage, but other ancillary services will contribute to the revenue stream. There is the possibility of entering into various contracts, such as to provide firming for intermittent renewable generators. Some of these will be a result of the recent Finkel Review.
One of the interesting outcomes of dispatchable storage is that, in an energy only market, it cannibalises its own revenue stream. Unlike ordinary generation, which derives revenue from supplying energy, storage relies on the economics of arbitrage – the absolute price does not matter, it is the difference. A more volatile market is favourable but supplying power into a volatile market ipso facto reduces the volatility. I discussed some of the traditional roles of PHS in an earlier post. Figure 5.7 from the Cultana report shows that increasing plant power capacity reduces the specific revenue.
At the end of the presentation, Andrea Bunting posed the question as to how the NEM market could facilitate further storage projects. Andrea was really thinking about how this type of project fits into a longer term 100% renewable scenario. This project would seem to be nearly exhausting economic arbitrage at the multi-hour level (batteries are going to operate mostly at the sub-hourly temporal scale) for South Australia. If so, then how much storage is going to be required in a national 100% RE scenario and is an energy-only market up to the task? The figure above suggests no.
This is where the possibilities of peer-to-peer (P2P) networks and blockchain enter. Some distribution network service providers (DNSPs) and retailers have been exploring the role of peer-to-peer energy trading, including the use of blockchain to provide real-time clearance of energy trades. The DNSPs are in the box seat because they own the meter and network infrastructure. Whether they chose to simply apply a per-trade or per-access fee or actively participate in trading is an open question. In principle, the internet could be used to facilitate trading separate from the electricity infrastructure but physical separation also makes the system more vulnerable.
I’m pretty skeptical that P2P of rooftop solar without storage can offer much value to the incumbent system. Most of the value would be in bypassing retail margins, which would certainly be popular, but it’s not obvious to me that the reward would be worth the effort. Retailers like the idea because it provides a way to retain edgy customers. Furthermore, the asymmetry of knowledge works out mostly in the retailer’s favour. But the real potential will come from the capability of dispatchable storage. But storage will be mostly limited to a couple of hours storage and mostly relevant for network support rather than support for the bulk generation system. This is an interesting space.
Back to Andrea’s question, the scenario literature suggests that multi-week storage is going to be required for 100% RE. This storage is usually modelled as either stored sunlight in the form of biomass; prehistoric stored sunlight consisting of retention of fossil fuel plant running gas or coal; hydrogen or methane based storage charged with RE; or variations on electricity-based storage including pumped hydro or batteries.
To give some examples, Palzer and Henning used 45 days of methane storage (equated at full-load electrical capacity for average annual demand) for Germany. Aghahosseini et al. used around 14 days of methane storage for North America. Lenzen et al used biomass equating to 21 days of full-load electrical capacity and Elliston et al. used biofuels, equating to 50 days full-load electrical capacity. Preston used 21 days of electrical storage. Concentrated solar offers a half day of storage but unlike other storage, only charges when there is clear sunlight and surplus power, leading to the ‘big gaps’ problem in winter.
To get a sense of scale, the NEM supplies about 600 GWh of energy per day and the Cultan project is 1.8 GWh. This suggests that a radical re-examination of markets that can accommodate storage are going to be required.
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