A smart grid and seven clean energy sources | RenewEconomy

A smart grid and seven clean energy sources

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The Grattan Institute’s study into Australia’s energy future canvasses seven technologies that could help deliver an 80 per cent reduction in emissions by 2050 – wind, solar PV, solar thermal, geothermal, CCS, nuclear and bio-energy. And then there is the grid, and it’s need to be smart and play fair, and not just favour the incumbent coal and gas plants.

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The Grattan Institute’s study into Australia’s energy future – “No easy choices: Which way to Australia’s energy future” – canvasses seven technologies that could help deliver an 80 per cent reduction in emissions by 2050. They are wind, solar PV, solar thermal, geothermal, CCS, nuclear and bio-energy. And then there is the grid, and it’s need to be smart and play fair, and not just favour the incumbent coal and gas plants. Here is a synopsis.



Grattan says wind power could provide more than 20 per cent of Australia energy needs (it currently provides just 2 per cent) and is the only low emissions power technology that is ready for rapid scale up in a short period of time, and within the benchmark range of $100-$150/MWh. It says wind power costs may continue to fall, but at a lower rate than other technologies. It says in good wind areas in WA, costs are around $90-$130/MWh.

Grid access is a major issue for remote resources , and grid capacity is also a factor, causing some less favourable areas to be developed rather than stronger wind areas in South Australia for instance. And it is notes that community concerns have had an impact. The renewable energy target plays a critical role in its deployment. It notes Australia has is capable of substantially expanding the amount of wind power that is fed into its electricity systems – (South Australia has 22 per cent wind, one of the highest in the world) – but ultimately it will meet some sort of constraint without storage capacity. Wind can be relatively easily absorbed up to around 25 per cent of the grid, but beyond 30 per cent is uncertain.

Solar PV

Solar PV is probably the most contentious and least understood technology, simply because its costs are falling at such a phenomenal rate. Grattan says solar PV could comfortably provide for more than Australia energy needs, but in practice is likely to account for around 30 per cent with grid integration management, and significantly more with storage – it contributes just 0.9 per cent of generation now. It notes that costs are around $220-$400/MWh, but costs are falling rapidly, and its trajectory will be influenced by the level of deployment support from governments.

On the issue of value, it will be worth more in some contexts than in others, depending on how it affects supply. It notes that PV generation aligns well with commercial sector and industrial peak demand (which is why the solar industry believes this will be the hot spot of development in coming years), but far less so with residential sector demand. It says installations for industrial and commercial customers will be economic before small-scale residential systems.

It notes that AECOM’s analysis of potential large- scale solar precincts in NSW suggested a levelised cost of electricity (LCOE) of between $230-$270/MWh, Bloomberg New Energy Finance suggests tcosts will be around $US150-$US230/MWh in 2020, while the US Department of Energy’s ‘Sun Shot’ program is seeking costs of $US100/MWh. Storate options will include on-site or distributed batteries (such as in electric cars), sodium sulphur cells and compressed air storage, sophisticated storage devices, such as the 10kWh RedFlow units used in Australia’s Smart Grid, Smart City program (costly) and simpler invertors.

Solar thermal

In theory, there is ample solar thermal energy to meet Australia’s needs – an array of 50kms by 50kms should do the trick nicely. However, thermal storage and gas co-generation is needed to overcome intermittency, and its costs are currently not commercial, but with those it could closely match demand, and be more valuable to the market. Costs are likely to be addressed through more deployment (of which there is none in Australia), better engineering and more efficient components and fluids. It suggests solar towers would be likely cheaper in the long run (none even made the Solar Flagships shortlist). And it needs changes to regulatory barriers for transmission networks.

It says estimates of its LCOE in around 2015 are still high, at about $200-$250/MWh, though even in the short term the range of estimates is large. “The great advantage of CSP is that its generation aligns with peak demand, and that it is dispatchable with storage. If these features are valued appropriately in electricity prices, or through other policies, the economics of CSP generation become more appealing.” And because development would be limited to only a few areas in the world rich with solar resources – such as the Middle East, north Africa, and parts of north America and China, deployment in Australia could have a big effect on global technology costs.


Another resource that could easily account for Australia’s energy needs in theory, but delays and problems in early development raised questions about reliability and costs. There had been minimal deployment in Australia, due to funding issues – hot sedimentary aquifers may offer better short term prospects than deeper and more complex hot dry rocks. Because of the uncertainties, the scale and timing of geothermal generation remains uncertain and there are big divergences in projections of Australia’s future Australian generation mixes – from 1.5 per cent in 2030 in one case to around one quarter of its energy needs by 2050 in another.

The major problem for geothermal energy is that it is capital intensive, with drilling the greatest component – around 50-80% – of capital costs. In granite, drilling costs $10 to 15 million for a 5 kilometre deep well – and most of the companies involved in exploration and development are small. Cost estimates range from $130/MWh to $220/MWh, and some see geothermal facing similar challenges to those facing the coal seam gas industry 15 years ago. “It took that industry eight to 10 years to develop commercial tools and achieve commercially viable flow rates,” it says. The geothermal industry would be very happy if it got to the scale of CSG in Australia in that time frame, possibly without the flack.

Carbon capture and storage

Grattan says CCS could contribute very significantly to a clean energy future and extend the life of existing coal and gas plans. But while costs appear competitive, they are not proved at scale, and the absolute size of investment will be a major barrier for early mover projects. It notes that technologies such as CCS and nuclear will require an investment of $1 billion or more, even for a demonstration plant, and very few substantial companies will “bet the company” on a project that is also high risk. “There are few energy companies globally, and none in Australia, that can afford to invest this amount without a very high probability of success.” There are also very few companies in Australia with the scale required. It noted a report from the Climate Group and Ecofin that estimated that given the relatively high risks of CCS, a company would need an enterprise value of over $140 billion to take on the risk of financing a 1,00 MW commercial CCS plant. There are not many of those in Australia.


Grattan says nuclear could meet a large proportion of Australia’s energy needs, however there is a great question over costs. It says that generation 3 plants are well developed but costs uncertain as there is limited experience in actually deploying them in western nations such as Australia, and there will be increased regulatory requirements. Gen 4 plants may be cheaper and more efficient, but they are unproven. There is also the question of financial risk and who is prepared to shoulder it. Citigroup analysts concluded that development risk of nuclear power were “so large and variable that individually they could bring even the largest utility company to its knees financially”.

“Nuclear power could be very cost-competitive with other low- emissions technologies. But the private sector may struggle to finance nuclear power plants without government support,” the report notes. “The long-run cost estimates for nuclear power broadly match current estimates for several other low-emissions technologies. However, major credit analysts consider that private companies are, at present, unlikely to accept the full risk of building a new nuclear plant. If they do, finance is likely to be high cost.” It says China could be a game-changer on costs.

It says it would take 15-20 years for a nuclear plant to be developed in Australia, but it also questions whether nuclear would be able to play a constructive role in the local grid, noting that it is relatively small, and nuclear is not capable of responding to peak demand. “Given that there is sometimes vigorous competition in electricity generation, and that nuclear power plants need to consistently sell 80% or more of their total generating capacity, it may not be viable to build many plants of this size (1000-1600MW) in Australian electricity markets.” It says this constraint could change, if re small modular reactor technology that could create units of less than 300MW, becomes economically viable. And then there is public resistance. And waste disposal.


Grattan says there is significant bioenergy available in Australia, although unlikely to be more than 20 per cent of demands given the competing needs of food. Indeed, if bionergy were to supply more than 10 per cent of Australia’s energy needs, it would require use of agricultural residues or dedicated bioenergy crops that do not compete with food production. And there is little experience of this in Australia, and this could take more than a decade to acquire.

Bionergy has advantages in that it could be deployed easily, though, to help meet daily peak demand. Improvements in supply chain needed, and efficiency of scale needed to encourage more plants for 5MW or less. But it notes that current network connection practices and expertise are not conducive to a scenario of connecting a large number of relatively small power stations to the grid in regional areas.


Whatever the technology cost developments of individual energy sources, the grid will play a decisive role. Grattan says regulatory reform is essential if the grid is to integrate sources such as solar, wind and geothermal, and not merely serve to protect incumbent gas and coal generation. Right now, the grid is designed essentially to connect major coal basics to capital cities. It needs to evolve to include wind and solar and other sources, and it needs to get smarter. It says Australia needs to build skills and knowledge in grid integration through greater research and experimentation.

Grattan says transmission infrastructure does not represent a significant constraint to any of the low carbon technologies within the short term, but for wind, geothermal, large-scale solar and possibly biomass to provide a very large proportion of electricity supply over the longer term would require substantial new transmission capacity, including greater interconnection capacity between state regions to cater for variability in wind and solar.

“While overcoming these transmission constraints is technologically straightforward and the need for major new capacity is not immediate, we can’t afford to be complacent,” it writes. “The long-life of transmission infrastructure, its high cost, and long lead times involved in developing new transmission corridors, mean that decisions about its layout in the near term have implications for the relative viability of our technology options decades into the future. The current set of regulatory frameworks for how we manage the development of transmission capacity are not well suited to a situation where there is a wide range of options around generator locations, as is likely if renewable technologies become economically attractive. The characteristics of the current framework could act to frustrate efforts to decarbonise electricity supply in an efficient and timely manner.”

In other words, reform. And do it now. And do it smart.


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  1. Martin Nicholson 8 years ago

    Giles – I hope Grattan didn’t say 50 sq km for CSP. I think you will find it meant a square 50km x 50km = 2,500 sq kms. 50 sq km would require an energy density of over 500 W/sm.

    • Giles Parkinson 8 years ago

      Thanks Martin. fixed now.

  2. Martin Nicholson 8 years ago

    Another possible correction. Nuclear is just as capable of providing power at peak times as CCS plants. This notion that nuclear cannot load follow is actually nonsense. People sometimes forget that there are many nuclear powered submarines and ships. They seem to be able to change direction without much difficulty which requires significant variability to the power system.

    • Jake 8 years ago

      Martin, given the long-term unreliability of our river flows for cooling nuclear plants, wouldn’t they all have to be situated along the coastline, susceptible to freak weather events?

  3. Martin Nicholson 8 years ago

    The amount of water used by any thermal plant (coal or nuclear) is a function of the thermal efficiency of the plant. Nuclear plants can be slightly less efficient than coal plants but using recycled water (with cooling towers) the additional water use will be moderate.

    Most of Australia’s coal plants are inland using river/lake water. I would expect nuclear plants to be built close to the coal plants they are replacing. In any event, thermoelectric power generation accounts for only a very small fraction of freshwater consumption most of which goes to irrigation so a switch from coal to nuclear is unlikely to be seriously impacted by river water availability.

    • Jake 8 years ago

      I was under the impression that this has precedence as recently as the summer in France, when they had to shut down a reactor due to concerns for its natural water source.

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