The Aurora CSP Project, South Australia

CSP, with lots of energy storage

The Aurora concentrating solar power (CSP) project will be located 30 kms north of the town of Port Augusta, South Australia, on a vast pastoral station.

It has been planned by US developer SolarReserve, known for bundling CSP towers, solar PV and molten-salt thermal energy storage. Although trough is the more common technology choice for CSP projects, SolarReserve’s tower technology is already operating at large-scale: a 110MW project in Nevada, US, came online at the end of 2015.

The Aurora project’s peak capacity will be bigger, at 150MW. Under normal operating conditions its capacity will be around 135MW, but with the ability to increase output when favourable (e.g. in the evenings). The plant is expected to generate 495GWh of electricity per year (indicating an expected capacity factor of almost 38%).

Storage capacity will be 1,100MWh, or 8 hours at full load. That is big: only a little less than all the world’s operational utility scale batteries, combined (at least at the time of writing). Storage will utilise molten salt, which is expected to have a degradation-free lifetime of 40 years. “Cold” salt will sit in one tank at 288 degrees C. Heated by energy from the sun, it will be moved and stored in a hot tank at 566 degrees C. When energy is extracted using heat-exchangers, the salt will move back from the hot to the cold tank.

The “tower” plant will require over 12,000 dual-axis tracking heliostats (mirrors), each 96m2 in area. The tower height will be up to 240m.

The plant will tap into a nearby 275kV transmission line.

Unlike some CSP plants, Aurora will have no requirement for natural gas or oil back up and will use dry cooling (saving millions of litres of water each year).

A record low energy price (see below) has, by the developer, been put down to advances through receiver and heliostat research, conducted at Sandia Laboratories in the US. These advances have focused on various things in combination, not just a single improvement. They include heliostat efficiency designs (such as thinner glass, lighter steel and less power-hungry drives), lower costs and other efficiency gains in the heliostat field overall, such as pointing accuracy gains, foundation designs and other component weight losses.

The plant is expected to take 30 months to construct, employing 650 construction workers directly and up to 4,000 total jobs (including indirect and induced employment). There will be around 50 long-term jobs during operations (O&M).

For the construction phase, 60% South Australian content is targeted (including assembly of the heliostats/mirrors), supporting what will be an entirely new industry for South Australia.

Following examination of environmental, community, and social impacts of the project by several South Australian Government agencies, development approvals for the construction of the project were confirmed in January 2018. Following this, final approvals for the project were expected to be received “in the first half of 2018”, with the commencement of construction expected shortly after. Construction is expected to be completed in 2020.


It’ll look a bit like this (source: SolarReserve)


“Dispatchable” solar: a survival strategy for CSP?

Ignoring storage, photovoltaics (PV) remains the cheapest solar technology on a capital and levelised cost basis. The gap between PV and CSP widened for a number of years, though Aurora is one example of a project which points towards a dramatic lowering of CSP costs more recently.

In 2008 for example, the first CSP project with thermal energy storage was Abengoa’s 150 MW Andasol, in Spain. That project began producing solar energy at US$310/MWh. Solar Reserve’s Crescent Dunes project with 10 hours of storage signed a contract in 2009 to supplying Las Vegas. That was priced at US$135/MWh. In May of 2017, CSP bids for a tender in Dubai, UAE, made news for being in the US$90/MWh range.

At the price recently agreed (US$60/MWh, detailed below), and operating in 2020, Aurora is considered competitive with a new combined-cycle natural-gas plant and cheaper than battery storage.

Despite recent price falls, CSP developers are realising that their projects can’t compete without storage. As a result, they have started to target markets which have specific set of dispatchability needs (as well as excellent direct solar irradiation). These include Australia, Chile, China and South Africa.

For example, as it closes old fossil-fuelled plants, South Australia is looking to increase its share of “firm” (dispatchable) renewable energy supply. It currently gets around 46% of its electricity from renewables and this share could grow towards 65-70% by 2025 according to various analysts. If such shares remain “variable”, that creates potentially big problems in balancing supply with demand. The problem is particularly acute during evening demand peaks (when the solar resource is poor or absent), but also encompasses backup (reserve) and black-start (grid failure recovery) capabilities.

To encourage “firm” renewables, the government of South Australia recently opened bids to power its own operations, the aim being to procure 25% of its electricity from dispatchable projects. The Aurora project alone will generate around 5% of South Australia’s electricity needs.

In addition to energy, it will be able to provide ancillary services to enhance grid stability.


Revenue generation: the power purchase agreement

In August 2017, SolarReserve won a contract to supply the South Australian government with dispatchable solar energy, at a price from A$ 7.5 cents/kWh to a cap at 7.8 cents/kWh (so around US$ 6 cents/kWh). The power purchase contract covers supply for a 20-year period. Its award followed a tender launched in 2016.

By comparison, the price is even lower than SolarReserve’s planned project in Copiapó, Chile, which bid at US$ 6.3 cents per kWh earlier in 2017.

In detail, the PPA (power purchase agreement) is not a straightforward contract at a set price. It is complicated by the fact that Australia has a merchant trading market. It is also important to understand the market context in which the contract has been signed.

South Australia, in the midst of what has been termed an “energy crisis”, has the highest prices in the world for peak power after dark (at around 7pm). This evening electricity is delivered by dispatchable natural gas plants, with prices never falling below A$100/MWh; and often unbelievably expensive. There is a price cap of A$14,000/MWh, a price which can be reached from time to time. Not only can prices be extremely high, they can be extremely volatile too, varying from A$100 to A$14,000 and back again within 5 minutes.

Even a small amount of dispatchable peak capacity promises to create major benefits for consumers.

Unlike the 20-year contracts that renewable projects can typically sign with off-takers in other countries, Australia has a merchant market. Hence the contract between SolarReserve and the South Australian government is not a simple, traditional PPA.

Instead the contract states that, for 20 years, SolarReserve will deliver electricity to Australia’s National Electricity Market (NEM). The South Australian government will buy from NEM during the day. SolarReserve guarantee that the price it pays will never go above A$78/MWh for 20 years, regardless of the actual market price (by reimbursing the government). That provides the government with stable pricing. The annual load of the government is approximately the same as the expected annual output of the Aurora plant.

Once the sun has gone down, SolarReserve can sell its stored energy to any buyer in the NEM, so selling at higher prices than during the day, whilst still providing a cheaper alternative to today’s prices during these peak periods. It makes money by taking advantage of the price differential between the (off-peak) cap it has promised to the government and its on-peak energy sales. It’s a clever way of devising a guaranteed 20-year contract, with security on both sides, while operating it within a merchant market framework.

SolarReserve will also retain 75% of renewable energy certificates issued for the plant, providing an additional revenue stream. These Large-Scale Generation certificates (LGCs) are issued annually for renewable energy output and sold to electricity retailers (who are required to surrender a set number of certificates each year). LGCs are valued at around A$80/MWh at present, so represent a significant source of income. The programme is only due to be in place for the next 10 years though, and the LGC price is variable and uncertain; but nevertheless helps the project economics.


Spiky prices in South Australia (and it’s not even summer yet), source: AEMO


Impact on the electricity market

From a market operation point of view, other changes from the entry of CSP into the market are envisaged.

It has proven hard to make a financial case for building new dispatchable generation in South Australia, not least because around 25% of homes have defected from the grid via rooftop PV, leaving too little residual load to interest investors. Uncertainty over carbon policy has been another drag on new investment, leading to an overall shrinkage in supply.

As a result, in the absence of any alternatives, incumbent gas power plants have been accused of withdrawing capacity at peak times in order to raise prices (and then generating to gain from them). Even aside from this behaviour, gas prices have risen dramatically as a result of national policies to encourage natural gas (LNG) exports to lucrative Asian markets, thus “internationalising” the gas price.

By contrast, the CSP plant will always have an incentive to push its generation during every evening peak price period. That’s because the hot energy storage tank must be emptied out by the next day, so that it can be ready to receive more solar heat when the sun rises. In other words, the storage capacity really needs to be utilised within a day. To keep back stored energy from the market would make no economic sense for a CSP plant.

It is hoped therefore, that the entry of Aurora (and perhaps others) into the market will help break the stranglehold that gas generators have had on peak prices, bringing them down both in terms of absolute price and price volatility.


Costs & finance

The total cost of the project is estimated at around A$650 million (US$ 505 million).

SolarReserve currently owns 100% of the Aurora project and plans to bring in new equity partners as it fleshes out the project finance structure ahead of construction.

The federal government of Australia has promised Port Augusta $110 million in concessional finance for “solar thermal electricity” through ARENA (the Australian Renewable Energy Association). The stated idea was to replace lost jobs in Port Augusta’s previously coal-powered economy. The equity loan will be at about 3%, representing extremely cheap financing in Australia. However it is not clear though whether this fund will now be divided between multiple, smaller storage projects instead of being used to fund just the large Aurora project.

SolarReserve have stated that their price will not be affected too much if that money goes elsewhere, for two reasons. Firstly, it is for only A$110 million of the total A$650 million cost and secondly, they claim that the project is oversubscribed with finance for the remainder.


Last updated: January 2018


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