Aurora: What you should know about Port Augusta's solar power-tower

Aurora: What you should know about Port Augusta’s solar power-tower

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Much has been written about the $650m Aurora project, and I set out here to collect together what is known and fill in some of the gaps.

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Time moves a little slower here

The paint peels ’cause the summers here are so severe

And we’re nowhere near nowhere you would know of

Locals here pride, they show up just to show off

(1955, Hilltop Hoods, writing about South Australia)

Carriewerloo Station. A sheep and cattle pastoral lease belonging to Amanda and Scott Michael about 30 km north of Port Augusta.
Carriewerloo Station. A sheep and cattle pastoral lease belonging to Amanda and Scott Michael about 30 km north of Port Augusta.

No doubt they’ve been burning the midnight oil in the office of South Australian Energy Minister Tom Koutsantonis to deliver on the SA energy plan announced Premier Jay Weatherill in March.

It’s hard to believe it has been only six weeks since the SA government signed up Elon Musk’s Tesla to build the world’s largest lithium ion battery. Three weeks later the Weatherill Government contracted APR energy to supply nine GE TM2500 aero derivative diesel-gas turbines totalling 276MW. (APR provided similar generators to Hydro Tasmania in 2016 during the failure of Basslink submarine HVDC cable to Victoria.)

Contrary to the apoplectic rubbish you might have read elsewhere, these state-of-the-art generators will run only when absolutely necessary to avoid load-shedding events and are significantly cleaner than SA’s now-retired coal fleet.

And, of course, the latest news is the signing of a ‘Generation Project Agreement’ (more on that later) with SolarReserve that underwrites the development of what will be the largest solar thermal power-tower unit with storage in the world.

(There are currently seven solar thermal farms globally with higher capacity, but all others either use parabolic troughs or smaller capacity power-tower units.) SolarReserve was founded in 2008 and, like Tesla, is headquartered in California.

This third piece of the Weatherill-Koutsantonis triptych is intended to bring new, independent generation capacity into the state which will increase competition and put downward pressure on prices.

Much has been written about the $650 million project, and I set out here to collect together what is known and fill in some of the gaps.

Aurora, as the project is known, will be situated on Carriewerloo Station, a sheep and cattle pastoral lease belonging to Amanda and Scott Michael, about 30 km north of Port Augusta — not far from the former sites of the Northern and Playford power stations. Aurora is aiming to begin construction in February 2018 with completion expected in 2020.

A field of billboard-sized computer-controlled mirrors (100m2 heliostats) follow the sun and reflect sunlight onto a target at the top of a 227m tower, where the equivalent of 1200 suns heats up a molten salt — not table salt, but an inert mixture of sodium nitrate and potassium nitrate, traditionally used as garden fertiliser.


According to SolarReserve, the initial melting of the salt is a one-time process, after which the liquid salt is recirculated and used for the 40+ year life of the plant – without any degradation, or the need for replacement or topping up. Temporary equipment is brought on-site during plant commissioning to melt the salt, which is later removed after the process is completed.

Just to put a rumour to rest, no natural gas or other fuel is required for power generation, and the plant will have no pipeline feed.

Molten salt starts in the ‘cold’ storage tank at 288°C and is circulated up to the ‘receiver’ — a set of 14 panels of tube walls arranged into a cylindrical vessel approximately 30m high and 20m wide — heating the salt to 565°C. The heated salt then descends the tower and is stored in the ‘hot’ storage tank.

When power is required, the heated salt is pumped through a heat exchanger to transfer the heat energy from the salt to water in order to generate high temperature/pressure steam which is then run through a standard steam turbine generator, not unlike the turbines in many thermal power stations.

Because a solar thermal power plant operates like a conventional power plant, many of the jobs need the same skill sets as conventional energy jobs – from construction through operations
Because a solar thermal power plant operates like a conventional power plant, many of the jobs need the same skill sets as conventional energy jobs – from construction through operations

The salt, still in liquid state, is returned to the ‘cold’ storage tank ready to be ‘charged’ again when the tower is ‘on sun’. The exhaust steam from the turbine is ‘dry cooled’ and condensed into water and then returned to be used again, meaning that water usage is kept to a minimum.

According to Solar Reserve’s Senior VP of Development, Tom Georgis, the gross output of the turbine is 150 MW, however the plant’s auxiliary load during the day reduces the daytime ‘sent-out’ power to 135 MW. “After the sun sets, we are no longer collecting energy from the sun, so the heliostat field and cold salt pumps are not operating, and consequently the auxiliary loads are much reduced.”

In the evening, with lower auxiliary loads and generally when the value of the power will be highest, the plant will be able to increase its net generation. At 135 MW, the capacity factor is 42%, which will curiously place it with the second highest capacity factor in South Australia. (Only the 180 MW Osborne Power Station, a gas generator in north-western Adelaide, achieves a greater capacity factor at 77%.)

The molten salt storage tanks will store up an equivalent of 1100 MWh generation, or about eight hours at 135MW load. The facility is expected to generate in excess of 495 GWh annually, or 3.8% of SA’s 2015–16 annual energy consumption of 12,934 GWh.


On the day the Aurora deal was announced, Tom Koutsantonis tweeted:

My guess is that Tom was referring to three strengths of the project:

  1. Dispatchability — the generator will provide power on demand, especially on hot, still evenings when solar PV and wind generators are idle and wholesale power prices can be up to 150 times higher than average.
  2. Grid services — the generator will provide valuable (but not yet valued) inertia that helps the grid ride through power disturbances, such as the one that ‘blacked out’ the state last September.
  3. Cost competitive — the price is somewhere between very good and excellent, depending on a range of assumptions, and worthy of discussion.

The SA Government went to open tender looking for two power supply contracts to meet its long term power needs:

  • 75% open to any dispatchable technology, to bring new generation into the market
  • 25% constrained to dispatchable renewable energy technologies, to “drive innovation in storage and other technologies”.

SolarReserve managed to beat out all other bidders in both categories, including a number of gas generators that bid for the technology-neutral portion.

The full energy output of the Aurora facility is contracted to the South Australian Government under a ‘Generation Project Agreement’ (GPA) designed by Danny Price of Frontier Economics, and will provide a benefit in favour of the SA government. (More on that here)

The SA Government’s peak loads are typically during off peak periods for the market, thus allowing it to benefit from lower spot prices, however Aurora’s energy storage will allow it to generate during peak market periods and help bring peak prices down with more competition and supply.

One quarter of the renewable energy certificates (LGCs) created will be bundled with the energy, which will be voluntarily surrendered by the SA Government, ensuring that 25% of the Government’s power is carbon neutral, which will go towards the state’s Carbon Neutral Adelaide targets. The remaining 75% of certificates will stay with SolarReserve, who will presumably market them as they please.

The SA government expects to pay a $75/MWh levelised cost for the 20 year duration of contract, but not more than $78/MWh.

For the South Australian government this is a good price — it’s significantly cheaper than the average wholesale price of $108.66/MWh in SA in FY2017 and also below SA 2020 baseload futures price of about $85/MW. The contract also has the benefit of protecting the Government from price rises over the next 20 years and providing the opportunity for price reductions.

Given that SolarReserve will be holding on to 75% of the LGCs, it’s difficult to state with certainty the full project levelised cost of energy (LCoE). By the time the project comes online in 2020 there will be only 10 years of the current RET remaining. Most experienced hands in the sector predict that, in the absence of new policy, LGC spot prices will tank well before 2025.

Energy Minister Tom Koutsantonis has stated that he is “advised that LGCs were not a significant factor in SolarReserve’s ability to offer a capped price of $78/MWh.”

My back-of-the-envelope calculation is total LGC revenue might add no more than $9.50/MWh over all energy generated in the first 20 years. As such the ‘all-in’ value of the contract would be less than $87.50/MWh. Note that the Finkel review, handed down just two months ago, estimated $172/MWh in 2020 and didn’t expect the median price of solar thermal to reach $87 until 2050.)

(Ed: We probably need to factor in the federal government’s “equity” contribution, which would lower the LCOE).

Given that alternative sources of long term electricity in South Australia almost certainly cost more than the combined value of the GPA and future value of LGCs, it is clear that the net subsidy (value of subsidy under the Commonwealth RET minus the value of savings to South Australia) is effectively zero — a far cry from the hysterical claims by the anti-renewables media that renewable energy is costly.

In late 2016 SolarReserve bid the 260 MW Copiapó solar-thermal project at US$63/MWh (A$79.50) without any subsidy into a Chilean reverse auction. However, the Chilean government chose instead to move forward with cheaper, but inflexible wind generation. SolarReserve will be rebidding the Copiapó project into the next Chilean tender later this year, and hopes to start construction by the end of 2018.

The company received an unwelcome setback when its $1bn Crescent Dunes facility in Nevada was taken offline last October for eight months due to a crack in the floor of one of the molten salt storage tanks. The problem was apparently caused by incorrect installation by a contractor and was repaired under warranty. The company says it has learnt from the decidedly low-tech problem.

As The Australian reported on Friday, it is not yet clear whether the project will receive all or part of the $110m ‘investment’ that was included in the 2017-18 federal budget.

(The deal was brokered by Nick Xenophon in what cynics might call a classic Xenophon move. In exchange for his decisive vote enabling the passage of the company tax cuts, a move that was bound to upset the ‘left’ and please the ‘right’, he secured investment in a project that had become totemic for the ‘left’ and popular with the ‘sensible centre’. Moreover, true to form, he secured a win for South Australia — both government and electricity consumers.)

The $110m has been variously described as either a concessional loan at 3% interest rate or concessional equity in line with the federal government’s March 2016 direction to ARENA to move away from grants and into investments with the opportunity for a return to taxpayers.

On Monday morning, SolarReserve’s CEO Kevin Smith told ABC Adelaide that the current pricing structure to the South Australian Government includes the $110m concessional funding, and that the company was confident of receiving the funding as “SolarReserve is the only game in town”, a statement no doubt contested by John Hewson, Chair of the Port Augusta Graphite Energy Company (formerly Solarstor) and others hoping for a look-in.

Smith commented that the $110m assumed is “not a grant, it’s not a subsidy, it’s an equity investment so we’ll have to pay that money back along with the premium that’s associated with the $110 million… if we didn’t get that it would change the price but it wouldn’t be a dramatic change in price.” Smith added that SolarReserve already has commitments and interest for funding that together are 50% more than is required.

In six short weeks, the South Australian Government has signed three very important contracts that underwrite their energy transition. Meanwhile, Prime Minister Turnbull has the temerity to label the SA Government’s efforts as “ideology and idiocy in equal measure”, all the while trying to herd a cabal of confused backbenchers with coal fetishes to arrive at a much needed and overdue federal energy policy.

And while SA moves ahead with new wind, battery, solar PV, solar thermal and a proposed pumped hydro plant, the total capacity of coal fired generation under construction in Australia remains at zero megawatts — for the tenth year in a row.

Simon Holmes à Court is Senior Advisor at the Energy Transition Hub, University of Melbourne.

Listen to our podcast on the Solar Tower power plant with Giles Parkinson, David Leitch and solar thermal expert Keith Lovegrove. Click below.

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  1. Tim Forcey 3 years ago

    During the discussion about alternatives to gas, the words “heat pump” were not used. As Keith Lovegrove’s ITPower report for ARENA showed (link below), heat pumps are a key technology that will provide lower-temperature process heat that previously was supplied by burning gas.

    • solarguy 3 years ago

      Tim, really mate!

      • Tim Forcey 3 years ago


        Oops, I must have had too many windows open. My post above has now been duplicate-posted where it was meant to be… beneath yesterday’s podcast with Keith Lovegrove.

        When Australians think of renewable energy, they need to think of more than just wind and direct-solar. They need to think of more than hydro, biomass, wave, tidal, deep and shallow geothermal, and ground-source heat pumps.

        Australians interested in renewable energy also need to be aware of air-source heat pumps!

        Air-source heat pumps are already recovering heaps of renewable energy in Australia, as they are used to heat buildings (aka reverse-cycle air conditioners), heat water, and, as Keith Lovegrove describes in his report to ARENA, to provide low-level (low-temperature) industrial process heat. (See link to report above.)

        In our University of Melbourne report, we described how reverse-cycle air conditioners alone are already recovering more renewable energy in Australia than all the roof-top solar PV panels. Who knew?? Link:

        Perhaps it is the way that air-source heat pumps seemingly recover free renewable ambient heat out of “thin air”… that makes them seem too much like sorcery… and makes it hard for people to wrap their head around them.

        Fortunately, international surveys like this one (REN21) mention air-source heat pumps again and again, so no blind-spot there.

        • Mike A 3 years ago

          Agree with what you say except you are lumping economic renewables with wave. Need to beware wasting money on experimental possibilities versus tried and proven good investments. Wave has never proven to be economic anywhere. So now and quite possibly always, given global weather trends, wave systems only last as long as a big storm, so not so much energy as an experimental theory. I note you don’t include fusion which is an appropriate exclusion for the same reason.

          • Tim Forcey 3 years ago

            Yes, air-source heat pumps are much more widely applied as a way to collect renewable energy… than are wave energy devices.

        • Mike Westerman 3 years ago

          Air source heat pumps used for heating make good use of RE but for cooling don’t, and if fueled by FF add to GHG emissions. Furthermore, most refrigerants represent an enormous largely unregulated GHG risk, until or unless natural refrigerants are mandated – and that is a major blind spot.

        • solarguy 3 years ago

          Tell me what temperatures can industrial heat pumps achieve?

        • JonathanMaddox 3 years ago

          It’s an excellent academic point but well covered in different (equally valid) terminology: the gains of heat pumps are not neglected, but frequently mentioned and applauded under the heading of end-use efficiency: heating with reverse cycle air conditioning is “vastly more efficient” than doing so with resistive electric heaters or even by burning fuel.

    • Alastair Leith 3 years ago

      Well the last paragraph in the ARENA report under the heading Concentrated Solar just got made redundant I think:


      At a site with a reasonable solar resource, solar thermal is likely to be economically viable for temperatures up to 150°C and possibly viable up to
      around 250°C. Higher temperature systems are not currently economically viable although may become so in future.

      We don’t know the LCOE of Aurora but it’s now cheaper than gas fuel itself in Australia let alone combustion capacity, according to some.

      • Mike A 3 years ago

        Yes when I read that I knew they were well out of date already but even so the low price was a surprise.

  2. sunoba 3 years ago

    Thanks to Simon for this balanced and informative article. I analysed the LCOE for Aurora using my standard methodology and got AUD 149/MWh. My conclusion then (and now!) was that South Australian citizens have got a great deal given that the price the government will have to pay is capped at AUD 78/MWh. Significant factors must be the concessional equity from the federal government and the fact that Solar Reserve retains 3/4 of the LGC. Details of my analysis at

  3. Mike Westerman 3 years ago

    The contract with the SA government is for up to 495GWh/a whereas 135MW x 8h x 365 = 395GWh, that is there is on average 2h/day at 135MW of generation in excess of what is stored. It would be useful to know just how much excess solar thermal capacity there is, so as to get a true picture of the LCOE. Clearly the plant stores and generates simultaneously.

    The article says SA’s peak is during off peak periods: I can’t see how this could be: SA government demand, if SA Water is excluded, is mostly air conditioning of office space and would be strongly biased to peak demand. If the deal includes SA Water then this deal looks like a big loser for the SA government, since SA Water is able to make extensive use of curtailable water pumping demand to secure an average price of power at the lowest end of the market. If they’ve had to give this up for a sake of $75/MWh to the whole of government then this is a bit of a disaster for both demand management as a driver of lower costs and for the SA taxpayer.

    • Alastair Leith 3 years ago

      Jay Weatherill said at the presser that govt load peaks at midday. Market for SA peaks in the evening, and may have a more pronounce duck curve than anywhere in Australia. AEMO forecasting zero minimum demand at midday by 2026/27 and then negative demand in years following. So cheap power will be accessible many days in the year to meet the govt demand. Weatherill and Smith made it clear this was the business model that got this up at $75/78/MWh.

      It actually seems like the Govt will procure in the market, SolarReserve doesn’t even have to do the bidding to meet the supply arrangement. I guess more will come to light over time.

      SA Govt is not the loser I suspect, just getting rid of $14,000 peak demand events is worth it’s weight in PR gold. Industrial users of electricity who fail to hedge will be grateful, even if they don’t show it.

  4. Alastair Leith 3 years ago

    > (There are currently seven solar thermal farms globally with higher capacity, but all others either use parabolic troughs or smaller capacity power-tower units.)

    Can only think of the Brightsource Ivanpah 392 MW currently with zero storage so they burn gas to preheat in the mornings, though being a molten salt conduit storage can be retrofitted and they say it might be one day.

    • Mick 3 years ago

      There’s a few trough plants that are larger than 150MW.. In no particular order.
      – Solana (280 MW, 6hours Molten Salt – United States)
      – Noor 1, (160MW, 3hrs Molten Salt storage – Morroco)
      – Mohave (280MW, no storage – United States)
      – Genesis (250 MW, no storage – United States)
      There’s also the SEGS plants (also no or little storage, gas) – and depending on how you count it ~400MW.
      There’s probably others, add in Ivanpah and the author’s probably not too far off the money.

      • Alastair Leith 3 years ago

        Thx Mick. i misread the line, took Simon to be saying seven tower CSP plants with higher capacity than Aurora.

    • Simon Holmes A Court 3 years ago

      ivanpah uses three towers, each with lower capacity than aurora.

      • Alastair Leith 3 years ago

        yeah, technically, true 🙂

        • Simon Holmes A Court 3 years ago

          seems like 2020 in SA is going to more like 2055 than 1955.

  5. solarguy 3 years ago

    This technology will prove it’s worth a little further in the future, when more plants are built and improved upon, even though it’s already impressive. Storage can be designed for days or weeks if needed at quite low cost.

  6. Ian 3 years ago

    A lot is riding on this project, I hope it succeeds. The technology sounds very simple and , for the most, part similar to other heat-source generators being stream turbines, generators and condensers. The recycling of water is interesting , making the only destructive inputs being land, and equipment. This sort of plant could be placed anywhere where the only resource available is sunlight and land. Presumably there is a minimum sized plant smaller than which there is no profitability. Ideally you’d want to scale these up or down for different applications. For instance , remote centres like Alice Springs , or remote mine sites would require a smaller plant than this Aurora.

    • Mike Westerman 3 years ago

      Ian all boiler plants need to blow down to control iron build up in the recirculating water. So I would expect this one to use 3% or more of the recirculating flow as blowdown which needs to be replaced. A lot less than the make up water in a wet cooling tower for sure. The siting restrictions relate mainly to the number of cloud free days – because CSP uses direct insolation only, clouds result in 100% loss of image and therefore output. This is the biggest disadvantage compared to PV. You also have to wonder where the big breakthrough in cost will come – PV is still on a steep downwards curve, whereas a significant part of the cost for CSP is a) the ST which is 100yo technology and b) mirror and actuators where there is a strong cost v quality payoff.

    • Alastair Leith 3 years ago

      Mining sites tend not to have the life span, or certainty of a capital city. SolarPV and batteries with diesel gen-set more likely.

      They may still use a small amount of water for cleaning the heliostat mirrors even though robots clean them now which reduced much of the water used for cleaning (and on site permanent labour I’ve heard).

  7. Charles 3 years ago

    My biggest complaint – couldn’t they have come up with a better name? Aurora is the most generic name ever – see

    In the electricity industry alone it is a retailer in Tasmania, a brand of solar inverters, and now this.

    • Brad 3 years ago

      That was my thoughts when I saw the article. Im in tassie so thinking thats my power company 🙂

    • Ren Stimpy 3 years ago

      Old Salty?
      Light Fantastic?
      Hot Stuff?

  8. Tim Buckley 3 years ago

    Great explanation thanks Simon

  9. Nick Thiwerspoon 3 years ago

    Simon, excuse my ignorance, but I don’t understand how you get from an LGC of, say, $85/MWh to the $9.50 over 20 years you suggest.

    • Simon Holmes A Court 3 years ago

      the $85/MWh we’re currently seeing is an anomaly — the aftershock of the abbott/warburton renewables investment strike.

      futures markets are pricing 2020 LGCs at ~$50.
      my ‘back of the envelope’ calcs assume:
      • LGCs prices from 2020 – 2029: $50, $50, $40, $40, $20, $10, $10, $10, $10, $10. i contend that these are ‘orthodox’ numbers, but i think they’ll end up lower
      • no LGCs from 2030 (as currently legislated)
      • only 75% are marketable by SolarReserve
      • spread over 20 years
      which works out to be an average price of $9.36

      happy to receive feedback on these calcs.

      • Nick Thiwerspoon 3 years ago

        Oh, excellent. Thank you. Makes perfect sense!

  10. Caffined 3 years ago

    Unless i am reading this wrong…
    # The SA Government get a capped price for all the power they might want (for their own facilities) from this plant,…but are still free to go elseware and buy at cheap spot prices when the market is low.
    # Solar Reserve get a fixed price 20year contract for part of their capacity, but can go to the free market at peak price times to maximiise their returns.
    That sounds like a cosy deal for the SA gov’ , but doesnt actually do much for the open market pricing problems as Solar Reserve will be wanting to keep those peak time prices as high as possible to recover their costs which we know they wont be able to with just the SA Gov contract.
    Sounds like the SA Gov, are screwing the public in order to reduce their own costs. !

    • Mike Westerman 3 years ago

      My concerns as well – it would be interesting to know how much is fixed. Comments like “the price is not significantly impacted on by the size of the Federal loan” make you wonder. $650M capex needs about $140/MWh to wash its face.

      • Simon Holmes A Court 3 years ago

        i agree that some fancy financial / energy market engineering is going on here.

        i suspect that it all comes down to value of dispatchability in the evening hours. i’ve seen analysis showing > $200/MWh for dispatchable solar in SA.

        on the concessional federal finance: even if the project is ultimately awarded all of the ‘xenophon’ $110m, it only represents 17% of project capital.

        i haven’t crunched the numbers, but i’d expect that the concessional cost of capital (say 3-4% rather than say 8-12%) on just 17% of the funds wouldn’t move the needle on the eventual WACC.

        • Mike Westerman 3 years ago

          SR has said the Fed funds are equity. If that is the it would represent a significant proportion of the equity.

          • Simon Holmes A Court 3 years ago

            i did a quick calc using finkle’s assumptions of:
            • cost of equity: 11%
            • cost debt: 4.4%
            and assumed:
            • 50% LVR, and
            • 3% cost of gov funds.

            • $0m gov funds then WACC = 7.7%
            • $55m gov funds then WACC = 7.0%
            • $110m gov funds then WACC = 6.3%

            look right to you?

            yes, gov funds make a difference — i was wrong about not moving the needle — but not enough to make a bad project good.

    • Simon Holmes A Court 3 years ago

      i don’t fully understand your analysis.

      as i understand it SAG won’t be trading in the NEM — SR will be effectively paying for the wholesale costs of SAG’s energy and offsetting the cost against the revenue attributed to their plant.

      SR has every inventive to maximise production during high price events, which will maximise revenue and reduce the price and/or frequency of high price events.

      without doing a whole lot of modelling (which would likely be wrong anyway!) it’s very hard to predict how much effect this will have on the SA spot market.

      • Caffined 3 years ago

        From Giles P’s article..
        “Aurora will provide the S.A. government with some of its needs from other sources in the market when demand and the price is low. Aurora will cover the government for energy and prices when the government’s demand is at its highest, around the middle of the day.
        But because the government can and will get some cheap power elsewhere, Aurora will be able store its solar power in its molten salt storage tanks so it can sell into the market at the system peaks, in late afternoon and early evening, when the market prices are highest, boosting its revenue.””
        That suggests to me SR will be able to bid for peak supply at will with any surplus power they have.
        That seems like a very dubious use of taxpayer funds.

  11. Caffined 3 years ago

    Any reliable reference sources for average actual sunlight hours for PA ?
    The only ones i can find suggest an annual average of about 110 hrs per month (min 60 hrs/month )
    Another site states a recorded average of 4.2 hrs per day over historical records.
    That doesent seem like an ideal location for a CSP plant that needs direct sunlight. !

    • Simon Holmes A Court 3 years ago

      from a 2010 report prepared for RenewablesSA:

      “The long-term average global horizontal irradiance value at the Port Augusta site (Latitude: 32.537019 S, Longitude: 137.813373 E) is 5.191 kWh/m2/day (216.3 W/m2). The long-term average direct normal irradiance value is 5.670 kWh/m2/day (236.3 W/m2), and the long-term average diffuse horizontal irradiance value is 1.631 kWh/m2/day (67.9 W/m2 ).”

      my understanding is that it is not an ideal location for solar radiation, but don’t forget that access to grid, labour, electricity market, PPA etc can be a lot more important than chasing 10-20% more energy.

      • Caffined 3 years ago

        Without knowing in some detail the exact working area of collectors, i am no further forward..but thanks.
        But these CST systems must need clear unclouded sunlight to get anywhere near efficient operation ?
        Sunlight hour Data seems so inconsistent..with averages.ranging from 2 hrs to 9 hours per day,..depending on the month !

      • solarguy 3 years ago

        Correct and how do you deal with a site that isn’t quite optimal…….. you design more collector area and storage.

        This plant is just the start for other plants to be constructed in the future, which will address what I have said above.

        • Caffined 3 years ago

          but the collector area, and storage capacity (8-10 hrs) have been stated..
          So how do you deal with a few consecutive days of cloud ?

          • solarguy 3 years ago

            If CST was the main stay to satisfy energy production for say up to 3days, it could do that if so designed, they would increase collector area relative to supplying a given daily load and design extra storage, up to 3 days without sun to do that.

            E.G. Need 15 MW/day, then design it to have a collector area to produce 45MW. 2/3rds would be saved for 3 cloudy in molten salt storage………. does that make sense now?

          • Caffined 3 years ago

            I understand that the proposed plant doesnt have enough capacity or storage to maintain a continuous 135 MWh supply beyond 8 hours of no sun.
            I also understand that weather statistics suggest that there is the probability of several consecutive sunless days .
            So I assume they will have to maintain a sufficient “thermal reserve” to cover for any forcast sunless period.
            I guess they could restrict the output to provide a 50.0 MWh continuous 24 hour supply, but then they would not be able to profit from the “peak” markets which they need to make the project viable.

          • solarguy 3 years ago

            Sorry, I meant to say in this analogy,15MWh/day total output during sunlight hours. So if you need 3 days autonomy one would have to produce 30MWh/day and store 15MWh x 3 days it would have 45MWh in storage. Or produce 45MWh/ day and send only 15 to the grid.

            Of course in this analogy, the plant is designed to send power to the grid during day light hours only and to store enough for 3 days supply to be used in day light hours during cloudy periods or it could use that stored 15MWh during the night if needed.

            Keep in mind Aurora won’t operate that way, but I think you should be able to work it out. My expertise is PV not CST, but it would have to be very similar.

          • Caffined 3 years ago

            You are mixing up you units (accidentally ?).
            From the above article..
            “”….Solar Reserve’s Senior VP of Development, Tom Georgis, the gross output of the turbine is 150 MW, however the plant’s auxiliary load during the day reduces the daytime ‘sent-out’ power to 135 MW. “After the sun sets, we are no longer collecting energy from the sun, so the heliostat field and cold salt pumps are not operating, and consequently the auxiliary loads are much reduced…..””
            So, the plant ancilliary load is 15MW, but reduced when not collecting.
            ” Reduced” say by 50% ? For the 16+ hours of no sun , (120 MWh) ,or for a full day of no sun 180MWh.
            OK , so if they can predict a bad weather spell and fully charge the store to max (1100 MWh) , they could survive a few days !
            I wonder if they have a feed from the grid to power some heaters for the salt in an emergency ?

          • solarguy 3 years ago

            No I’m not mixing up units MW’s and MWh are different things. In the analogy I gave you, I used MWhs so you could get an idea about the storage.

            Plus I can’t see 15MW would be needed to drive pumps and operate heliostats. For more info I suggest you contact Solar Reserve

          • Caffined 3 years ago

            Did you even read the quote i posted ?
            ..Or the article above ?
            The 15 MW ancilliary load is a direct quote from Solar Reserv’s VP of Development.
            I suspect he is probably better informed to know how much power is needed to drive 10,000+ tracking motors and pumps to circulat 30,000 tonnes of liquid salt, etc etc.
            So , tell me what a “MWh/day” …is a unit of ??
            This system is going to consume 10% of it own production just to operate.
            Now…imagine a partly cloudy day when they have to keep “tracking and pumping” etc (15 MWh) but the sun hours is only out for a total of 2 hours. ..(300MWh collected, 240+ MW hrs consumed !)

          • Mike Westerman 3 years ago

            Not quite that bad Caffined (what’s wrong with a real name on a technical blog?). On a partly cloudy day they would shut the steam set down and just store, and then run a shortened evening. A normal air cooled small steam power station would have 5-8% parasitics – feedwater pumps, condensate pumps, vacuum pumps, condenser fans, oil pumps, oil cooler fans, air compressors, etc then this one has a salt circulation system as well, so a total of 10% is not surprising. The trackers would be powered from PV panels on the heliopads I would expect. When you are storing but not generating then the ST auxiliaries are off. You still have a few percent losses in keeping things warm and in auxiliary power supplies, but the primary parasitic is the salt pumps, and even they are likely to use VSDs to modulate flow to maintain temperatures.

          • Caffined 3 years ago

            Sure, i wouldnt expect them to dispatch power at such a low capture level, in fact i suspect they will be feeding to store for most of the time on a full sun day also, so they can maximise evening/morning peak dispatch options.
            Why do you think the trackers would be PV powered ?..has that been done before ?
            How can you rely on PV for tracking power on a cloudy day unless each one has battery back up ?..That seems an unlikely senario for 10,000+ collectors.
            ..SR certainly stated that the tracking and pumps were parasitic loads on the main output capacity, and actually said that the trackers and pumps were a major part of that 15MW ancilliary load enabling a higher output capacity when not collecting.
            And surely the main salt circulation pumps would need to be operating during any collecting
            So how would they power that ancilliary load for even just collecting if not from the main generator plant…auxilliary generator plant ?
            Either way its all energy used and not available for dispatch.
            ….the “Caffined” tag was not my choosing, somehow it was attached automatically when i logged in to Discus ??? ..and i have not been able to find a way of Changing it !

          • Mike Westerman 3 years ago

            SR has contemplated PV powering the heliostats for a while – it reduces cabling in the field. PV is not affected anywhere near as much by cloud as CSP and is so cheap you simply oversize. There will be some battery back up for each heliostat to power the tracking computers. CSP developers have been looking at “intelligent” heliostats for a while even tho’ you still need centralised control for load balancing and emergency off targetting.

            The salt pumps will be large – several MW each, with multiple redundancy – a failure in circulation is fatal as it takes time to move all the heliostats off target. 1200 suns does a lot of damage very quickly – quite enormous heat flux.

            But your central proposition is correct: self used power is not available for dispatch. Hence why I’m not a CSP convert – PVs plus pumped hydro and behind the meter batteries is my bet.

          • solarguy 3 years ago

            I think it’s obvious you just want an argument and your starting to annoy me. I already advised you to contact Solar Reserve. Go do that!

          • Caffined 3 years ago

            No need,
            SR have already clearly stated what the ancillary loads are (15MW) , and it seems reasonable,
            Why do you not want to accept that figure. ?
   it because it indicates one of the flaws in this type of CSP project ?
            ….Especially when its located in a non optimum location.
            I am amazed how many inteligent people seem unable to to spot the holes in this proposal.
            …let alone the deceptive presentation on the output power cost !

          • solarguy 3 years ago

            Clearly your a FF troll, now Fu%ck off.

          • Caffined 3 years ago

            Clearly , you have your tunnel vision blinkers on.
            I do actually think renewables are the way to go, but this is not the way, at this time, for this situation.
            I guess you do not live or run a business in SA, or you would be a bit more concerned.
            SA urgently needs a stable , affordable , sustainable , power supply.
            This solution is none of those characteristics, and is most likely just a political manouver by a lost state government in a last minute attempt to appear to be taking action .

          • solarguy 3 years ago

            Either reduce capacity or save for later and use other sources.
            More below.

  12. dono 3 years ago

    About 50 years ago – before economics went mad – the governments owned all the power generation and transmission. Then they sold them off and the “market” convinced governments that they should decided what price they could charge. Now we are heading into the same morass with governments still at the mercy of the power plant owners .

  13. Caffined 3 years ago

    Ignoring some of the fine detail,….. LGCs, Equity %, interest rates, etc etc…
    i think i have some “Napkin maths” answers as to how this thing floats financially..
    .. SR, “underwrites the SA Gov supply needs at $75-78 /MWh. , but they can supply most of that from the daytime off peak spot market at say $85-100 MWH,..costing SR $25 /MWh max.
    ..But, SR can then sell their own stored power into the peak price evening market at anything up to $200-300+ /MWh
    Net result is SR are effectively getting more like $175-275 /MWh for their output !
    which makes the whole project viable and attractive to investors
    obviously not quite as simple as that but it seems to be the way the deal is set..
    Neat ! ..SA Gov get a below market capped price for 20 years for all their personal needs, and Solar Reserve get a healthy profit !
    So who is losing out ? …..anyone who is not included in the deal !
    Corrections , comments,.. all welcome .

  14. Gary Rowbottom 3 years ago

    Thanks Simon, covered all the main points very well, complements Giles article excellently. As a Port Augusta resident and campaigner for this technology for over 5 years I am thrilled to see it is now going to happen, good for the SA power network, good for my region, good for the planet.

  15. Nick Thiwerspoon 3 years ago

    Simon, I have another question. Apologies for wasting your time. At the end of the article, you give annual output of the Aurora facility as 495 GWh. But if output is 135 MWh for 20 hours, surely that translates into 985 GWh? What am I missing?

  16. Gold Platinum 3 years ago

    The biggest thermal molten solar tower projects average power output is 15MW = (130,842 MWh_in_a_year / 8760_hours_in_a_year)

    For comparison, Hazelwood Coal powerstation average power: 1369MW = (12,000,000 MWh / 8760_hours_in_a_year) so that’s almost exactly 1% of the power.
    The increasing scientific consensus is that solar-farms that are non-roof top are just environmentally destructive for the amount of land they need and the tiny amount of power they produce. Compared with the land just being used for CO2 sequestration achieved via photosynthesis. All major solar farm projects in the USA have been met with criticism from nature conservationists

  17. Drake Anderson 3 years ago

    Still cost 8 billion to replace Port Augusta.

  18. EnerjiBes 3 years ago

    Thanks Simon. great explanation.

    I write about commercial solar installation and investing in this blog ( (speciality Turkish solar systems).

    Example page:


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