A National Electricity Grid For Australia

This is a guest post from Neil Howes. Neil is an Associate Professor at the University of Sydney. The post describes a response to the “Carbon Pollution Reduction Green Paper” (27 August 2008).

Executive Summary

We are proposing that the Government of Australia facilitates the replacement of 50% of Australia’s base-load coal fired electricity generation by financing the building of a high capacity National Electricity Grid (NEG) by 2020. This will interconnect high value renewable energy sites for wind, solar and geothermal energy to enhanced hydro electricity pumped storage capacity enabling these low CO2e energy sources to provide base-load power to major retail and industry consumers.

The objective of the plan is to :

(1) Link the East Coast and Tasmanian electricity grids (known as the NEM - National Electricity Market) to the Western Australian electricity grid via a 1500Km high voltage DC (HVDC) connection between Norseman, WA and Pt August SA,

(2) Build a new 1000 Km HVDC connection between Leigh Creek SA and Roma, QLD to link the SA and QLG regions within the NEM, in order to access solar and geothermal sites in WA, SA, VIC,NSW and QLD.

This would also require;

(3) A high voltage AC (HVAC) extension and upgrade of the WA grid north of Norseman, via Kalgoorlie, to the proposed Pilbara local grid to access stranded natural gas (NG) power in WA mining communities and solar thermal sites in the NW of WA

(4) A HVAC interconnection from Norseman to Esperance and Albany wind power sites with increased capacity HVAC connections along the SW coast of WA t4 Perth. This infrastructure project will assist the development of all renewable energy resources, starting with developing wind resources along the SW coast of WA, West Coast of Tasmania, and coastal and highland wind sites in SA, VIC, NSW and QLD with an installed capacity of 28GW by 2020.

The second component of the plan is an expansion of the existing 1.2GW hydro pumped storage capacity to 6GW, to be located in the at existing Snowy and Tasmania hydro sites and additional sites in WA,NSW and QLD. As a start on replacing the remaining 50% coal fired base load beyond 2020 the development of other renewable energy sources should be started with the building of at least 4 concentrated solar thermal (CST) sites, each of 250MW capacity, and each with the capability to be expanded to 2GW capacity, and two geothermal sites in the Eyre Basin. These sites would be connected to the expanded NEG, with the aim of having more than 2GW solar and geothermal capacity by 2020 and the long term aim of replacing some of the remaining 11GW coal fired base-load capacity by 2035, if geothermal and CST can deliver lower cost power than coal fired power using carbon sequestration.

The third component is to increase the supply of renewable energy sources by tying “free” carbon pollution reduction permits given to high carbon intensity export industries to the financing of new renewable energy capacity per year equivalent to 2% of the total carbon permits, and a 5% per annum decline in the number of “free” carbon permits not auctioned.

Details of Proposal

Renewable energy targets of 20% for 2020 will require more than 1GW of additional renewable energy electricity production capacity to be installed per year, and would allow 70% of the carbon reduction targets to be met if this replaces 50% of coal consumption at existing coal fired power plants. The traditional use of coal burning electricity generation plants has been to provide a low cost base load capacity of 22GW, with less than 5GW flexibility, for a total coal-fired capacity of 27GW. The balance of the 49GW capacity is provided by peak gas turbines using NG (12.5GW capacity) and hydro-electricity (8.5GWcapacity), but 78% of the electricity produced is from coal-fired generators.

Carbon capture and sequestration (CCS) may be possible to be retro-fitted to existing coal fired power plants, but the costs are unknown, and the time to install such CO2 abatement devices is uncertain. If retro-fitting is implemented net electricity production will be reduced by about 40%, and it is unlikely that new coal-fired capacity will be build until the costs of carbon capture and sequestration are known. The industry may choose to convert to NG as an energy source, or modify generators to reduce power generation during off-peak low priced periods. All of these scenarios will result in a reduction of base-load electricity capacity by 2020.

Wind power electricity production is a proven low CO2 renewable electricity source, but point sources are intermittent, requiring back up power generation. Interconnecting wind generation sites over a 3,000 km geographical region greatly enhances reliability. As an example it has been estimated that wide geographic dispersion ensure more than 20% of capacity most of the time and reduce maximum peak production to about 50% of capacity. Wind power is price competitive now with nuclear, NG fired thermal but not coal-fired thermal generation. Solar energy matches peak power demands, but the best solar sites are distant from consumption. Prices for concentrated solar thermal(CST), based on overseas experiences are presently higher than wind power but few sites have been operating and costs are expected to rapidly decline as more solar thermal sites are built world-wide.

Australia has exceptional wind, solar and geothermal potential resources. The best wind resources are along the SW coasts of WA, W coast of Tasmania, the southern coasts of SA and VIC and the far N coast of QLD. More localised good sites are also available on the NSW tablelands. The best solar sites are located in the low rainfall regions of central Australia and especially in the WA Pilbara plateau, a region using considerable diesel and NG energy for mineral and LNG exports, but lacking electric grid capacity. The WA government has announced plans to develop a local grid in the Pilbara region and expects that power demand will exceed the present 3GW used in the SW region of WA. Large geothermal resources are present in the SA Eyre Basin, but distant to present electric grid connections.

Australia has exceptional pumped storage hydro resources and could expand this capacity to absorb energy during off peak periods, but most of this infrastructure is located in SE Australia and Tasmania. Presently hydro provides 6.7% of electricity generation but up to 18% of short term peak capacity (8.5GW). This could be expanded to 13.5GW by the addition of 5GW pumped storage capacity, to the existing 1.2GW capacity, if improved transmission capacity was available.

WA presently generates most electricity by NG, duel coal /NG fired gas turbines and some coal. It also has considerable power generation by stranded diesel or NG gas turbines, located in the gold fields and at NW shelf oil and gas fields especially the LNG facilities at Karratha. Expansion of wind power is limited in WA to the South-West Interconnected System (SWIS) grid off-peak load of 1.7GW. An expansion of the SWIS grid to the gold fields and Pilbara, interconnecting Albany and Esperance grids to Norseman and Perth and a 2 GW HVDC link to East Coast and Tasmania via Pt Augusta, could allow an expansion of WA wind resources to 6GW capacity, provide a saving of peak NG use and increase the security of supply in case of a NG supply failure( as occurred at Varanus Island).

The wind resources of SW of WA are considerable and geographically isolated from East-Coast locations. Interconnection of west-coast and east-coast grids would enhance overall wind-power reliability. WA has very little opportunity for hydro-electric pumped storage but does have limestone caverns in the SW suitable for developing compressed air / NG assisted gas turbine generators as a off peak energy storage. If successful this capacity could be expanded to make better use of WA’s NG resources and reducing CO2e from NG used for electricity production. Other pumped storage systems such as tidal-assist could be explored on the NW shelf region.

WA has the best solar resources in Australia, but the locations in the NW of the state are isolated form the SWIS grid. Worley Parsons in collaboration with major mining companies located in the Pilbara region of WA are investigating the feasibility of building multiple 250MW CST sites. If one or more CST stations were sited along the northern Gold fields NG pipeline, and connected to Perth and Eastern Australia grids, CST stations in Western and Eastern Australia would extend the solar power generation time by 2-3 hours, matching peak power demand and avoiding the need for any solar energy storage.

The Federal Government could use some of the funds obtained from the proposed Carbon Pollution Reduction Permit Scheme, to assists in the financing and building of a high capacity National Electricity Grid including a 1,500 km HVDC(>1000Mw) transmission link between Port August and Norseman. An interconnected 1000Km HVAC line(440,000 volts) running NW from Norseman via Kalgoorlie, parallel with the gold field NG pipeline, and increase capacity between Kalgoorlie and Perth could be funded by private operators, as could an increase in the existing 500MW capacity HVDC of the Bass Straight Link. Additional HVAC capacity would be required to connected the local Esperance and Albany grids to Norseman and to Perth via the high wind potential sites along the SW coast.

These upgrades would be to enable financing and building of an additional 5GW total pumped storage input capacity at Hydro Tasmania , Snowy Hydro and Brisbane-Gladstone locations(total 6GW input). This would not involve the building of any additional dams, but may require the raising of lower dam structures, and the building of additional generators. Present pumped storage at Tumut 3 power station(600MW) is only used in 3 of the 6 250MW generators, and would allow pumped storage input capacity to be increased from 600MW to 1200MW.

The Tasmanian west-coast has high quality wind power resources, but limited capacity to use more than 1GW peak power. Tasmania has many interconnecting storage reservoirs, but only limited capacity (500MW) to absorb off peak power from the mainland via the Tasman-Link. Existing generators have 2000MW capacity, but this is used at only 50% of capacity due to water availability. The building of 3GW of pumped storage capacity in Tasmania would enable 5GW wind capacity, including local base load use, export of up to 1GW by expanding the 500MW Tasman-link.

The Far-North QLD coast has high wind power resources, but these are distant to major energy consuming industries at Gladstone and the SE of the state. An expanded HVAC capacity of the QLD grid and interconnection via Roma to Leigh Creek would enable 2GW wind capacity in the Far-North to either displace QLD NG or coal-fired capacity or to supplement SA and WA demand.

A national maximum of 28GW wind power capacity would be required to replace 11GW of coal fired base-load power(assuming a 35%capacity factor for wind). This would require an additional 6GW in WA, 5GW in Tasmania, 2GW in QLD and the balance 15GW from SA,VIC and NSW . There would be no capacity problems to add 2GW of solar and geothermal capacity by 2020 as solar will always be generated at peak power demand times, provided the local peak demand load and export grid capacity is not exceeded. Until a demonstration plant has been built and operating costs determined we should not anticipate more than 2GW solar capacity could be built by 2020.

At the lowest off peak demand period (3-5.30am local time) 20GW of power is presently consumed from 20GW coal fired production (27GW capacity). If this capacity is reduced by 50%( 14GW) it would be possible to reduce coal-fired base load by 11 GW and would have the ability to absorb 6GW from pumped storage regeneration, and 10GW from remaining coal, giving the maximum that could be absorbed by wind of 16GW. However the 2-3 h W-E displacement of the off peak (3-5.30am) low, would allow an additional 2GW to be absorbed by flattening the off-peak low. Expanding wind capacity at the most dispersed sites( SW of WA, west coast Tasmania, eastern tablelands of NSW and far NE coast of QLD) will give the most improvement in wind reliability and especially reduce peak wind loads. The peak of wind production WA and SW Australia are likely to occur on different days as weather patterns take 2-4 days to travel across the continent. Peak 5-7pm loads in summer are also displaced by 3 h differences in summer time zones. An expansion of the pumped storage in-put capacity from 1.2GW to 6GW, would enable hydro to supply at maximum levels ( 8.5GW) for longer periods, providing lower level reservoirs have sufficient capacity. During rare prolonged low wind periods, and low hydro dam levels, off-line coal fired reserve capacity could be activated and some industry use curtailed as was done in WA following the Varanus Island interruption.

This plan will require the building of 3GW wind capacity or the equivalent solar and geothermal, per year. With the existing 6.7% of electricity by hydro generation we would expect about 40% of electricity production would come from renewable sources by 2020, but most importantly coals contribution declining from 78% to 40%, with a smaller reduction of NG generated power. High intensity CO2e export industries such as aluminium refining and smelting assistance could be tied to the financing and building annually wind or other renewable energy, representing 2% of their power consumption. Assistance in the form of “free” permits would be reduced by 5% per year, so that in 10years the CO2e intensity of high CO2e emitting exports would drop by 50% without any decrease in export volumes.


Australia has one of the lowest wholesale electricity prices in the world, the present off-peak power prices are as low as 1.2cents/kwh, and average less than 4c/KWh. With a carbon permit price of $20/tonne CO2e(equivalent to 2cents/KWh), coal-fired generators will have incentives to reduce production in these periods, saving coal consumption up to the free permit level. This is difficult in many power plants, although some reduction is possible. If coal-fired plants are able to be modified to economically generate power for less than 12h per day, the existing infrastructure could be maintained for peak and shoulder load power. Carbon permits or cash incentives could be used to pay some of the costs of these modifications. While these costs are unknown, they should be easier to model and implement than carbon capture and sequestration.

NG is a more expensive fuel and would increase by an additional 1cent/KWh due to a $20/tonne CO2e permit price. A very large pumped storage capacity would flatten the demand curve increasing off-peak prices by 1-3cents/Kwh, and lowering peak prices. Thus we expect at least a 2cents /Kwh increase in base load electricity prices to 4cents/Kwh, and peak costs also rising due to NG price increases, costs of pumped storage and CO2e costs, by 1-2 cents/Kwh to 5-10 Kwh. This will greatly benefit the economics of wind generation which cannot match production to peak demand. The building of 28GW wind capacity will change the shape of the power supply curve.

It would be more difficult to reduce the remaining 13GW coal capacity but this would still give a 40% reduction in actual coal CO2e, since this 13GW would not all be used as entirely base-load. If all coal burning was replaced by wind would need at least 60GW capacity, and would have a problem with absorbing >30GW during high wind and low demand periods, or meeting peak power demands in low wind periods. Replacing the 13GW coal capacity(10GW base load) with solar and geothermal would only require 12-15GW capacity as night-time low peak of 20GW could be replaced by 12GW NG and the balance by geothermal and hydro in low wind periods.

Is it realistic to project the building of 28 GW wind and 2GW solar capacity by 2020? At an estimated installed cost of $2000 per kWh capacity, building 3GW per year will cost $6Billion per year. A large part of the materials required are structural steel which can be sourced locally. In 2008 it is estimated that the US will add 8GW wind capacity from a mixture of locally manufactured and imported wind turbines. Several years would be required to increase wind capacity to 3GW unless most turbines were imported. When completed, 28GW of wind capacity will save each year the combustion of >20million tonnes of coal (export value >$2.5Billion), saving 100million tonnes CO2e at a price of $1.5Billion (that doesn’t have to be paid by another emitter). The cost of additional 2,500Km HVDC transmission lines would be an additional 2.5 Billion with 5GW pumped storage financed by electricity supply insurance. The present wholesale value of this power would be 7500 x10,000,000 kWh x 4cents =$3Billion per year. Carbon permit costs are going to raise coal fired base load costs by 2cents/kWh, to 6cents/kWh, so would still need a small subsidy for wind and CST. However prices of thermal coal have risen by $80 a tonne implying an additional price rise of 2cents/kWh, so wind power may be competitive at 8cents/kWh.


Australia needs to reduce its reliance on coal-fired electricity before 2020, by replacing a significant portion of the coal-fired base-load generation with renewable energy sources. While Australia has excellent wind, solar and geothermal resources they are dispersed and long distances from present electricity consumption. A truly Nation Electricity Grid connecting the CST resources and industry of the Pilbara region of WA, and the wind resources of the SW region of WA, with the SE and NE of Australia and Tasmania will allow these renewable energy resources to be developed to reliably provide 40% of Australia electricity production by 2020, reduce CO2e, and provide additional options to CCS to further reduce carbon dioxide pollution by >50% in 2050.

A bold idea, though only partially achievable.
The HVDC line length is comparable to the Pacific Intertie which connects southern California with the Bonneville Power Administration.
There will be a requirement for redundancy in route of the HVDC lines. Incidents such as bushfires underneath the power lines from the Snowy scheme caused blackouts in Melbourne several years ago. No sane energy regulator would allow a dependency on one power line for an entire state. So multiple routes with multiple costs for redundancy and reliability will be needed. These can link up with otherwise isolated grids, such as Esperance or Olympic Dam.

The linkage to the north west integrated system (NWIS) in the Pilbara would also have to contend with cyclones. The Horizon power reliability report of 2006 shows that power losses of 20-100hrs do occur after cyclones. The impact on mining operations, not to mention households, of interruptions of this length are severe and would require additional local generation to offset. In the north west, this would be open cycle gas turbines which are already in use in mine sites, with low costs due to close proximity to gas suppliers. So why build a power line when the load will be met locally.

Given there are existing wind farms in all the air regions mentioned in the proposal, would it be possible to perform a statistical analysis of the independence of these air regions. Taking a years worth of hourly power generation numbers and crunching them to determine how reliable a network of dispersed wind farms can be in the real world would boost your case. Statistical proof that the wind will be blowing somewhere all the time would take the wind out of detractors sails.
There are superb wind farm sites in the south west of WA, with 45%+ capacity factors in real life wind farms. The problem is that there isn't the ability to adsorb the power variations in the grid. The HVDC link across the Nullabour would allow these resources to be exploited fully.

So in conclusion, the Nullabour link to enable increased wind penetration and increased pumped storage capacity makes sense. The northwest link makes much less sense and could be delayed to a second phase of the plan.


Lachlan the Accountant.

Thanks for your link to the Pacific intertie. I was not familiar with this but when living in Manitoba Canada in 1980's a very long HVDC( I think 1million volts) was built, connecting Nelson Rivers hydro sites to N Dakota.
All of the proposed lines go through desert or low scrub, which is easy to maintain fire-breaks and is of little hazard. No major fault lines.
It is beyond my expertise to model correlations between wind sites, but note that in UK its about R2=0.2. Australia's weather systems usually go West to East and take 2-6 days to travel so would expect a low correlation between West Coast, Tasmania and Eastern Australia.
Why I was proposing a NW link within WA is that power demand by industry especially LNG and iron ore is expected to become as large as the demand in the SWIS, and the NW region also has the best CST sites.
WA also has the highest costs of power because it uses so much NG, which would be better kept for peak demand. NG prices are also higher in WA than Eastern Australia, lower cost wind power would allow NG used in LNG compression to be saved for export.

I'm mildly optimistic that the recent (and ongoing) Varanus Island gas outage will make the various stakeholders in the Pilbara a lot more interested in backing Worley Parsons' solar thermal plant project concept than they might otherwise have been - even Woodside would seem to have an interest in selling more LNG and less gas into the local market (at least as long as there is a price difference between the domestic market and the international market).


Interesting article but I don't know why carbon capture/sequestration even got a mention.It is off-with-the-fairies stuff.
Obviously the problem of renewable source power supply has to be tackled on multiple fronts to ensure reliability and cover problems with new technology.The idea of a national grid is excellent.

The comment above about bush fire risk to trunk power lines is only valid,just barely,in areas of tall eucalypt forest where a bad fire can crown.Most of the proposed trunk routes are through areas of sparse vegetation.

The article gives little space to geothermal which is probably the best chance to take the bulk of base load away from coal.Geothermal is a proven technology and it appears that Australia is well endowed with the resource.Given that a lot of geothermal prospects are in Central Australia it should not be too difficult to include NT in the national grid.It also should be possible and desireable to electrify both trans-continental rail lines.In addition,the proposed inland line from Melbourne to Brisbane and points North should be built as an electrified route.

However,all this is pissing into the wind if the Powers-That-Be don't get off their shiny bums and get cracking on real action instead of arguing about silly accounting(? Ponzi)schemes re carbon trading etc ad nauseum.Talk is cheap.That is why the vested interests are bent on prolonging the talk fest.

A first small step would be a complete moratorium on the construction of new coal fired power stations.This would put the coal and power industries on notice that they have to adapt to changing circumstances or perish.

Hi thirra,
You have raised several good points. I raised CCS because this appears to be central to Garnaut report and white paper thinking. No investment of $$ billions is going to occur without considering "what if" CCS does work! The point I was trying to make was that this technology has not been proven and will take until at least 2020 to know if it works at a reasonable cost, so new coal fired plants are going to be risky, hence the need for renewable energy.
The point about geothermal energy using hot rock, is that it shows great promise, but until 100MW capacity is built and running its going to be hard to know the costs and to finance 1GW let alone 10GW capacity all in 12 years.
The risk of power lines to fire is a lot less in the low rainfall regions, and even 2GW capacity is still only a small part of overall power. Note that power plants in gold fields rely on one pipeline, so a grid electricity supply is adding a second back-up.
As far as I can see the carbon trading scheme is aimed at making coal fired power much much more expensive. The most recent Garnaut report that very few seem to have read, indicates that carbon price may go to $60/tonne CO2e, costing coal fired electricity 6cents/kWh just for the pollution permits, about 300% higher than present costs, making it more expensive than wind, solar or geothermal.

Thanks,Neil.The sticking point with the carbon price as applied to coal power generation is whether the sods get exemption and to what degree.It appears to me as a casual observer that they are pushing all the appropriate government/union/industry/consumer buttons to achieve a next to free ride.

Also the government has not commited to implement Garnaut,even the watered down version which he seems to think/hope might be accepted.I am rather sceptical about their courage in this and other matters.

Sorry for my cynicism but looking back on the last 10 or 20 years it has been a long road to perdition as far as convincing these meatheads on environmental concerns.

I realize that CCS is still a live issue but it is just a diversion by the aforementioned coal interests.

Overall - a good article and good ideas - Best wishes.

Petrol is getting a 3 year exemption, some export sensitive industries are getting 90% exemptions, that leaves coal and gas fired electricity to shoulder most of the costs.
If Garnaut's 17% reduction from 2010 levels( 10% from 1990 level) is taken up, that will mean at least 24%(7%existing, plus 17% new) of energy will have to come from renewable sources by 2020. Most of that will probably come from replacing coal plants( especially brown coal) or mothballing, with additional wind generation, and building new NG plants, but only using during peak demand or low wind conditions.
I don't see how we could reduce total carbon emissions by 27%(20% reduction of 1990 level) by 2020, unless all coal was replaced by NG and some wind, then we would have a peak NG crisis, because NG would have to be base load.

Wonderful article!

I vaguely remember that the lines from the Snowy power scheme are at the moment limited to 1 GW to Sydney and Melbourne each because of overheating problems. Obviously, these problems would need to be addressed as well.

What gives me great optimism is that we are discussing national power grids already and we are able to put numbers on the costs of upgrading Australia's infrastructure. And these are not totally unrealistic prices to pay.

The next step is, of course, to start connecting Australia's grid with other countries. New Zealand is an obvious and easy one. Indonesia is much more interesting as it could help wean our nearest neighbour of coal power in the future.

Regarding the SNOWY links to the NSW and VIC NEM regions, the limits are explained on a regular basis by the NEMMCO MT PASA (medium term supply predictions) Interconnector quarterly reports. The March 2008 description was (from http://www.nemmco.com.au/psplanning/200-0146.pdf ) was:

The limits used in MTPASA for the Snowy – New South Wales interconnector are:

The limit for flows from Snowy to New South Wales varies between 3500 MW in winter and 2800 MW in summer and is dependent upon line ratings, Snowy generation profile and the magnitude of loads in southwest NSW.

The limit for flows from New South Wales to Snowy is determined by thermal and transient stability limits. This limit is highly dependent on loads in southwest New South Wales. When the transfer from Snowy into Victoria reaches 900 MW TransGrid arms an emergency control scheme to allow higher transfers. The limit for flow from Snowy to New South Wales in MTPASA is largely limited by the restriction that no more than 1946 MW is supplied to New South Wales from neighbouring regions via interconnectors. This restriction is modelled to ensure that the assumptions used to develop minimum reserve levels for New South Wales are maintained in MTPASA. TransGrid has advised NEMMCO that due to the implementation of an automated control scheme, provided by Snowy Hydro Limited, short-time ratings on transmission circuits north of Snowy can be utilised at certain times. When the short-time ratings are available the transfer limit on the SNOWY1 interconnector will be increased by up to 200MW in the Snowy to NSW direction. (See also NEMMCO Communication No. 2356).

The limits used in MTPASA for the Victoria - Snowy interconnector are:

The limit for flows from Victoria to Snowy is determined by thermal and transient stability limits. The thermal limit is due to the rating of the South Morang F2 transformer. The transient stability limit reduces as the Victoria region demand increases. The limit for flows from Snowy to Victoria is around 1900 MW. On hot summer days this limit will reduce below 1900 MW unless a load shedding Network Control Ancillary Service (NCAS) is enabled to allow use of the 5-minute thermal rating of the Dederang – Murray 330 kV lines. Without NCAS, the limit reduces to 1700 MW at 35 o C and 1600 MW at 40 o C. The National Electricity Code clause 3.11.3 (b) requires NEMMCO to monitor whether it is economic to enable NCAS services to increase interconnector capability. As MTPASA is a reliability assessment the NCAS is assumed to be available. With the NCAS service enabled the Snowy to Victoria limit is 1900 MW at 40 o C. The upper limit is determined by voltage stability considerations and is typically 1900 MW in summer.

How much would an interconnect to NZ cost (using the Basslink cost as an indicator) ?

Links connecting the various continents have been part of long term visions for years (the most prominent example being Bucky Fuller's GENI proposal).

Why link to NZ? 2000km is a very long distance for an undersea cable and NZ has a near shortage of power most of the time. You could build plenty of variable wind power over there without need for importing it from Australia.

The East-West link may be a bit too pricey too but the slightly lower sunshine hours in Western Queensland would make it viable to have the Queensland to South Australia link in place. Maybe a combination of solar and geothermal in that region?

The extra solar incidence provided by a connected grid will be a real boon for thermal solar..

With huge arrays positioned across the nation reliable power can be provided to industry for an entire working shift... say from 9.30am to 5pm, in the east and from 11.30 to 7pm in the west.

The beauty of HVDC is that you can put it underground.

When the Eastlink proposal was put forward in the early 90's I think -TPTB refused publicly acknowledge HVDC -I heard that this was due to cost considerations.

All the very best in your endeavours.

Neil, refreshing to see this kind of submission, talking infrastructure for getting large-scale renewables into the grid. By coincidence I just submitted a “Carbon Pollution Reduction Green Paper” response proposing almost exactly the same as your submission, based on my beliefs and involvement with DESERTEC and DESERTEC-Australia who have such ideas as their underpinnings.

My submission asked for :

"initiation of a national, federally-supported program for the extension and development of Australia’s grid and electricity interconnect system, allowing central Australian renewable energy riches to be tapped and integrated into the national electricity grid"

I hope these submissions are accompanied by many others similar until the voices for this bleedingly obvious direction result in it becoming reality, and SOON.

There's little doubt too that with the courage to commit to these kinds of infrastructure upgrades, Australia can easily reach reduction targets far higher than the 10% by 2020 reductions recently proposed by the Garnaut Review (Targets and Trajectories).

The more backing this argument gets, the better off we'll all be.
Would be a perfect opportunity for the Rudd Government to make a gutsy national-building move,
(also trump Garnaut's weak targets) and put Australia forward as serious, not just a lame follower.

Congratulations on a great submission that gets to the heart of the issue.