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Transmission: We need to start building now to deal with wind and solar boom

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Ground control to Major Tom, take your protein pills and put your helmet on” David Bowie 1969

Why read this?

Even if there was a war on, it takes time to get new transmission built. As renewable investment is accelerating way faster than most anticipated a year ago with more than 40 projects under development it’s likely that parts of the transmission grid will become constrained.

Transmission is typically less than 10% of final bills but can make a huge difference to system reliability. We argue there is more bang for the buck in upgrading transmission than just about any other part of the system.

A series of studies by the Jacob Group, the Blakers Report and a significant number of other studies all identify that lots more transmission will be required to support high renewables penetration. That’s even allowing for lots of distributed energy.

AEMO itself notes that putting a portfolio of transmission upgrades in place will deliver a portfolio benefit. Nevertheless….

A combination of fear of gold plating, a confusion of roles between the AEMO and the AER in regard to transmission expenditure, and an overly cautious and insufficiently ambitious approach to transmission development means that there hasn’t been much in recent years, outside of the Hazelwood upgrading (which still took too long) and augmentation within Queensland to support the electrified CSG industry.

Queensland has also very recently announced its $350 million Northern Queensland transmission development program.

The 2016 National Transmission Network Development Plan [NTNDP] – Australia’s fundamental transmission planning document prepared by AEMO – didn’t see any major developments happening before 2021, and mostly not until 2025.

The 2017 plan under development has five separate scenarios with various combinations of renewables policy and economic growth.

However, in the end a scenario is not the same as an action plan. So the fundamental flaw that we identify with the NTNDP is that it is reactive rather than proactive.

We contrast the planning process that AEMO undertakes with the proactive, solutions oriented approach taken by ERCOT in TX with its CREZ development.

Essentially ERCOT built the transmission and wind development then proceeded rapidly. This is no different to, say, building a new airport or train line. Build it and they will come.

We note that the Finkel report called for the development of Renewable Energy Zones, seemingly very similar to the ERCOT model.

These zones are supposed to be developed over the next 12 months.

Based on the Jacobs modelling there is a clear case for starting the second Bass-link connector today and, in our view, some of the intra-NSW contingent projects should also be started without delay.

Transmission remains at the heart of the grid

The revolution in electricity has two main themes:
(i) behind the meter developments and associated changes in the role and pricing of the “last kilometre” distribution grid;
(ii) the replacement of a few centrally placed thermal generation units with a more distributed but still centrally run portfolio of renewable fuelled generation units.

Transmission represents the arteries that carry this utility-scale power to where it’s consumed.

Most of the time the best place for wind and PV plants is (i) remote from thermal plant location and (ii) often remote from load.

Therefore it seems as if full development of renewable resource requires significant transmission development.

The argument is that if we have many wind and solar PV plants, electricity generation will become statistically more predictable. Wind in Northern NSW is only partly correlated with wind in South Australia.

If one PV farm at Moree has cloud over it, other PV farms in QLD or Victoria will not. Transmission is the means by which the system can realise these portfolio benefits of lower volatility.

Interconnectors form the part of transmission carrying electricity from one NEM defined region to another.

For instance if there was more transmission to South Australia from, say, NSW, electricity prices in South Australia would be lower than they are today, as NSW transmission would set the marginal price rather than gas.

RIT-T test – in the end it’s too bureaucratic in a dynamic situation

The RIT-T is a cost-benefit process that is applied to all new transmission network investments that have an estimated cost greater than $6 million. It was designed to replicate investment outcomes in a competitive market environment.

It does this through identifying the costs and benefits associated with a new project, along with any alternatives.

The test was recently reviewed by the COAG energy committee and, as usual, the status quo was affirmed. That is, in the Committee’s opinion, the test was still the appropriate way to justify new transmission investment.

The committee did ask that the AER application guidelines be reviewed “to better reflect the net system benefits of options including those relating to system security and renewable energy and climate goals.

This is, of course, a joke. What are the climate goals – officially, that is? Are they federal or state goals? How is the AER to take account of them? It’s a complete ducking of responsibility.

However ITK believes that, in any case, the test is too narrow a way to think about a major reconfiguration of the electricity grid as is likely to happen in Australia over the next 10-20 years.

For instance, a new transmission link to Tasmania will likely cost between $1 billion and $2 billion.

That could only be justified if Tasmania was to play a substantially enhanced role in meeting the electricity supply needs of the NEM, and basically could only be part of a much bigger plan.

Similarly, indications are that if Snowy 2.0 proceeds, up to $2 billion of extra transmission would be required across Victoria and NSW.

This could only be justified by a longer-term view of the required reconfiguration of the electricity system.

National Transmission Network Development Plan [NTNDP]

Each year AEMO goes through a transmission planning and development process. The summary of the 2016 plan stated:

The NEM is moving into a new era for transmission planning:

  •  Transmission networks designed for transporting energy from coal generation centres will need to transform to support large-scale generation development in new areas.
  •  Transmission networks will increasingly be needed for system support services, such as frequency and voltage support, to maintain a reliable and secure supply.
  •  A new interconnector linking South Australia with either New South Wales or Victoria from 2021.
  •  Augmenting existing interconnection linking New South Wales with both Queensland and Victoria in the mid to late 2020s.
  •  A second Bass Strait interconnector from 2025, when combined with augmented interconnector capacity linking New South Wales identified above, although the benefits are only marginally greater than the costs.

Modelling shows greater total net benefits when these developments are combined, creating a more interconnected NEM. These benefits are projected to increase as the energy transformation accelerates.

  •  Geographic and technological diversity smooths the impact of intermittency and reduces reliance on gas-powered generation (GPG). Greater interconnection facilitates this diversity and delivers fuel cost savings to consumers.
  •  A more interconnected NEM can improve system resilience.
  •  Contestability in transmission should make development more competitively priced, reducing costs for consumers

ITK’s comment is that this plan seems slow and insufficient, and insufficiently linked to a more comprehensive plan for large-scale reconfiguration of the grid.

Naturally it didn’t contemplate Snowy 2.0 because that hadn’t been dreamed up a year ago.

As an analytical document it is fine. As an action plan – it’s a failure.

Blakers Study had $8.5 billion of DC high voltage transmission

The recent 100% renewables with focus on balancing cost provided by pumped hydro envisaged a broadly 2500 km high voltage transmission network that might cost around $8.5 billion. There doesn’t seem to be any scope whatsoever for the potential value of such concepts to be fit within the NTNDP.

Figure 1 Australia's wind resource with notional HVDC backbone. Source: Blakers Report

Figure 1 Australia’s wind resource with notional HVDC backbone. Source: Blakers Report

Jacobs Study for CEFC

In November 2016 Jacobs published a study financed by the CEFC:

Benefits of Transmission Upgrades in a Transforming Electricity Sector

This study looked at the transmission implication of three separate studies Jacobs had previously done for the Climate Change Authority, the Energy Networks Association and the Climate Institute.

We quote somewhat liberally from the Jacobs report:

“First, they all examined scenarios where substantial emission reductions were required by 2030 ranging from 28% reduction to more than 45% reduction from current levels.

Second, the studies examined a variety of policies to meet the target but under all policies there was a requirement to retire a high proportion of the existing coal fleet by 2030.

Third, under most studies examined, interconnect upgrades played a material role in the transformed electricity sector.

Large amounts of interconnection were required over the study period, with up to 3,500 MW of additional interregional capacity over the whole NEM by 2030.

The faster the rate of closure of coal capacity the sooner the interconnect upgrades were required. Under most emission targets examined, a second link between Victoria and Tasmania was required by 2025

In all studies, there was marked change in the generation mix by 2030:

  • For the 28% target scenario in the ENA study, coal generation in the NEM fell from 155 TWh to 82 TWh to 100 TWh. Gas-fired generation increased from 20 TWh to 76 to 93 TWh in 2030 and renewable energy generation increased from 55 TWh to around 80 TWh. Brown coal generation in Victoria reduced by over half.
  • For the 48% target scenario in the ENA study, coal generation fell from around 155 TWh in 2020 to 39 TWh to 54 TWh in 2030. Only one brown coal power station remained in operation by 2030. Although gas generation increased, renewable generation had the largest increase, going from 55 TWh in 2020 to 99 TWh to 120 TWh in 2030 requiring substantial increases in renewable energy resources across all regions.
  • For the two degree scenarios in the CCA study, the entire brown coal fleet was retired by 2025 and the black coal fleet in the NEM was retired by 2031. For Victoria, this meant replacing over 55 TWh of brown coal generation with other forms of generation in less than 5 years. Although additional black coal and gasfired generation played a role, the study found that renewable energy played a significant role in this replacement.
  • Similarly in the TCI study, which examined mixes of policy approaches to reduce emissions, the brown coal generation in Victoria fell within a decade, with Yallourn closing before 2025 and Loy Yang A/B commencing closing before 2030 under the policy scenarios with a mixture of regulated closures of coal plant (by age), higher renewable targets or suboptimal carbon prices. Higher gas prices were assumed in this study than for the ENA studies and so more renewable generation was need to replace the brown coal generation.
  • The studies found that significant interconnection upgrades were required. The extent of the upgrades was as follows:
  • In the CCA study, the level of required upgrades ranged from 3,500 MW to around 7,000 MW with higher upgrades required for the higher the level of renewable generation. Around half of the upgrades were required by 2030, reflecting the severe reduction in coal fired generation in that period.
  • In the ENA studies, only around 1,000 MW of upgrades were required in the period to 2030 for the 28% target. Around 1,750 MW of upgrades were required for the 45% target scenario.
  • In the TCI studies around 2,200 MW of upgrades were required to the period to 2030 in the scenarios were there was a mix of policies to achieve the emission target.

The order of upgrades was consistent across the studies. In all studies examined, a doubling of the import /export capacity from Tasmania was required by 2025. Upgrades to the Queensland/NSW and the South Australia/Victoria interconnects were also required by 2030.

The principle reasons for this were the low cost of the renewable resources in Tasmania and South Australia, and the exhaustion through development of the available low-cost wind resources in Victoria in particular.”

ERCOT TX Competitive Renewable Transmission Zones [CREZ]

(based in part on 2014 Quarennial task force presentation and Wind association presentataion on CREZ to Californian conference)

In Texas, ERCOT realised that the potential of wind in the State couldn’t be realised without a more integrated approach. As far back as 2008 wind was being curtailed.

The CREZ concept was developed over 2002-2004 and a law passed in 2005 with a final order in 2007. There was a CREZ transmission optimization study, and a wind integration study, which were put together with dispatch priority.

So the CREZ proactive approach like all good plans had three simple elements.

  1. Identify the “best” resource zones;
  2. Develop a transmission master plan;
  3. Begin building transmission to zones.

25 zones were identified and 10 selected as focus for further studies based on estimated potential capacity factors of 40% or higher for the best 2GW of development in that zone.

The transmission was developed over the following five years and by 2011 about 3600km of largely double circuit 345 Kv lines were developed at a budgeted US4.9 bn.

The actual cost as of 2014 to facilitate 18.5GW of new wind or other generation was around $US7 billion for 5700km (measured by easement) Some of the transmission was built by existing providers and some by new entrants. This let wind in Texas grow from around 2.8GW to an estimated 20.4GW in 2017.

Why was CREZ a success.

  • World class wind, and load
  • Few barriers to land development
  • Combined economic development, development of in State energy resources and development of green energy
  • Regulatory and planning processes moved forward in tandem
  • Wind integration is facilitated by a large fleet of flexible natural gas and by system wide dispatch at 5 minute intervals.

ERCOT comments that CREZ planning and development required several industry leading technical studies;

  • Reactive device optimisation
  • Sub-synchronous interactions
  • Stability studies.

Point is they built it and as a result are in excellent shape.

Finkel report picks up on ERCOT Model

Chapter 5 of the Finkel report dealt with system planning. It recommended

  • By mid-2018, the Australian Energy Market Operator, supported by transmission network service providers and relevant stakeholders, should develop an integrated grid plan to facilitate the efficient development and connection of renewable energy zones across the National Electricity Market.
  • By mid-2019, the Australian Energy Market Operator, in consultation with transmission network service providers and consistent with the integrated grid plan, should develop a list of potential priority projects in each region that governments could support if the market is unable to deliver the investment required to enable the development of renewable energy zones.
  • The Australian Energy Market Commission should develop a rigorous framework to evaluate the priority projects, including guidance for governments on the combination of circumstances that would warrant a government intervention to facilitate speci c transmission investments.
  • The COAG Energy Council, in consultation with the Energy Security Board, should review ways in which the Australian Energy Market Operator’s role in national transmission planning can be enhanced.

NSW

The historic and “desired” forecast capex of Transgrid is shown below.

Figure 2 Transgrid capex. Source Transgrid

Figure 2 Transgrid capex. Source Transgrid

The requested capex relates to the 2018-2023 period. Most of the proposed capex is maintenance with some for augmenting capacity in the Sydney region. No capex has been allowed for “contingent” projects.

Yet there are more than 8GW of committed and proposed new renewables generation in NSW, some of which is indicated on the map below.

Figure 3 Transgrids view of generation 2026. Source: Transgrid regulatory proposal

Figure 3 Transgrid’s view of generation 2026. Source: Transgrid regulatory proposal

Transgrid have developed 5 contingent projects but don’t propose doing any of them until the trigger is reached.

transgrid AER proposal

Excluding the South Australia interconnect, we are only talking an upper end $1 billion to upgrade the NSW network in the North, South and South West to cope with much larger quantities of renewable capacity.

At a rough approximation this might add $1.30/MWh to customer bills before allowing for the downwards pressure caused by increased supply.

If COAG spent more time focusing on these basics and essentially declaring them as project worth doing, stuff the RIT test, then NSW, the epicentre of the NEM network could get transmission for more renewables progressed in short order.

In our view this is a typical example of where process is over emphasised relative to potential outcomes.

Victoria

The transmission system is owned and operated by Ausnet and has 6,500km with a 500kV backbone running from the Latrobe Valley to Heywood and a 220 kV ring around Melbourne. Victoria’s transmission system is more controlled by AEMO but essentially there are no firm plans that I am aware of beyond the Heywood upgrade for augmentation to allow more renewable connection. That’s despite the closure of Hazelwood and the construction (just completed or underway) of 1200MW of new wind and some PV, mostly in the West and Northwest of the State.

Queensland

Queensland has its “Powering North Queensland” plan, of which the key element is spending $150 million to upgrade transmission around Cairns and Townsville providing scope for 2GW of new renewables. Other than that, it is basic maintenance of the Queensland transmission network in its current state.

David Leitch is principal of ITK. He was formerly a Utility Analyst for leading investment banks over the past 30 years. The views expressed are his own. Please note our new section, Energy Markets, which will include analysis from Leitch on the energy markets and broader energy issues. And also note our live generation widget, and the APVI solar contribution.   

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  • trackdaze

    Great article David,

    As you allude to actions speaks louder than words.

    Its a no brainer that both interconnectors to tasmania and south australia have some level of redunancy.

    A bird in the hand is worth two on the air. There is however a risk that a tasmanian interconnector is a overcapitalision. Something 1/3 of the size of the existing at half the cost and speed of rollout would suffice.

    • Mike Westerman

      Tas could put several GW of pumped hydro on existing reservoirs and without doubt is the best candidate for seasonally secured wind. A GW or more of interconnect would be justified on that basis, apart from redundancy.

  • WR

    Eventually they’ll need to upgrade transmission for:

    1. Tasmania hydro and wind power to Victoria, with smaller amounts heading in the opposite direction.
    2. SA wind and solar to Victoria and NSW, with smaller amounts heading in the opposite direction.
    3. Inland solar to the coastal cities, especially the capital cities and Canberra.
    4. If a significant amount of pumped-hydro storage is developed, that’ll need transmission to the coastal cities.
    5. If off-shore wind is developed along the eastern Victorian and southern NSW coasts, that will require some extra transmission lines.

    • juxx0r

      Eventually it will be rotting and decayed like an abandoned train line.

      • John Ihle

        You may be right.. in addition the ratepayers may be left with billions in stranded costs vs a scenario where there could’ve been more effort on policy regarding distributed generation.

        • juxx0r

          People shelled out $500/kWh/day for 20kWh a day for a solar system.

          I reckon they’ll shell out $200/kWh to store a few of them overnight?

          Then what for transmission?

          • Alastair Leith

            Not every house has great insolation profile. Not every energy user is a house, there are blocks of flats, hospitals, schools, commercial buildings all shading each other with multiple tenants, many just don’t have the roof space with foreseeable conversion efficiencies in panels (even at 100% many still wouldn’t be able to self generate with infinite storage). They all need winter power. If FiTs go lower and lower as they have been (exception Victoria nudged it back up a bit to have parity with WA) there may well not be enough on the local network to provide for them. Also large industrial users.

          • juxx0r

            So energy consumption is going down. Local solar production is going up, local storage is going up, and we need more transmission?

            You and everyone else haven’t convinced me of the need to transmit all over the countryside a magical number of extra electrons.

          • Alastair Leith

            Consumption has started rising again in last FY (perversely).

            The magical numbers seem to be on your side. The modelling I’ve read uses quantifiable 30 minute data. You seem to know what is going to happen in the future with PV installed capacity in every demand centre of Australia. You must know more than you are prepared to put data against, maybe it’s just a hunch?

        • WR

          Transmission is relatively cheap when compared to distribution. The ratio is about 1:4 on your current bills. That is, the local distribution (substations, transformers, and poles and wires along the streets) costs about 4 times as much as the high voltage transmission wires from the generators to the substations.

          • John Ihle

            you still need the distribution system and some studies have shown that it’s cheaper to invest in distribution upgrades and renewable energy vs long distance generation and transmission. it depends on the circumstance and an honest evaluation should be done taking into account many aspects. you likely won’t get that, an honest evaluation, from billion dollar corporations that need investments to grow. the world doesn’t need more fossils or old business models designed 100 years ago.

          • Malcolm M

            The Blakkers study showed that the levelised cost of balancing was $20/MWh cheaper if there was a HVDC line from North Queensland to SE Queensland than if the HVDC connections were only between Brisbane, Sydney, Melbourne and Port Augusta. I presume this is because the North Queensland connection provides solar in winter, and that without it the system needs a lot more solar panels and storage in the south.

            This analysis will need to be redone with more recent prices for solar panels, and the higher capacity factors that are now achieved with tracking panels. But there are limits to the extent that tracking, more panels and batteries can overcome short days, a low sun angle and cloudier skies from SE Queensland south.

          • hugh grant

            Not sure about cheap – the transmission networks’ levels of profligacy and waste are similar to the distribution networks

  • juxx0r

    When individuals and companies realise that it’s cheaper to go off grid than continue to endure ever higher prices, these grid upgrades will themselves become stranded.

    This website whilst being great at bringing us the news has been very poor at drawing conclusions. The logical conclusion of it being cheaper to take a house off the grid, is that it’s even cheaper to take a block off the grid and a suburb off the grid.

    All you have to do is read every third article on this website and onestepoffthegrid to see that homes and businesses are and increasingly will take care of their own needs. Right now in the dead of winter, there’s 2GW of behind the meter solar, almost 10% of the countries needs. That’s 10% that doesn’t get transmitted. As we get subjected to 10% electricity price rises every year and solar and storage is coming down at 14% and 20% respectively, pretty soon there will be an avalanche of customers giving the old one finger salute.

  • George Darroch

    What happened to Australia? This was the country that built the Snowy and got things done.

    • Alastair Leith

      Snowy has been described as a white elephant in economic terms of ROI. Sure, it was a grand “nation building” project that inspired national pride in so many, and integrated “new Australians” from Greece and Italy etc into the racist white Australian idiom and showed how we (anglo-celtics and southern Europeans not Aboriginals or Asians yet) could all get along together when the money was good, but on sheer value for investment was questionable. Certainly came at a severe environmental cost for the Snowy and other rivers.

  • Brunel

    HVDC?

    It needs to be UHVDC.

    And so I was correct all along.

  • Mike Westerman

    David I shouldn’t have been gobsmacked by the numbers in the table for Northern NSW, but I was: Transgrid thinks its right and proper to put $2B+ of new investment at risk for the sake of $63-142M??!! Any wonder Harwin was pissed off dealing with this sort of foolery.

  • David Hurburgh

    Can we assume the cost of these dedicated transmission lines for wind/solar will be factored into the real costs of renewables ?

    • of course, if we do the same with the dedicated transmission lines built for coal and gas. Oh, wait, that’s already in the bill, which why you paying $400/MWh at the socket.

    • juxx0r

      Don’t worry bro, you can put solar anywhere and everywhere. Oh wait, we already are.

      • daw

        You forgot, or deliberately avoided adding, that solar isn’t available all the time, not even most of the time, so it adds up to being a nuisance rather than an advantage.

        • juxx0r

          As an engineer instead of a negative Nancy, one asks how can we do this. And we can, cheaper. Turns out the main nuisance is people like yourself.

          • Alastair Leith

            While other engineers ask how we can do it with utility scale renewable generation which in all models I’ve studied wins out on an optimized cost evaluation over a zero transmission or zero grid solarPV and storage solution. Or maybe you have exclusive rights on engineering knowledge and positivity?

            You do have a point that price gouging by retailers and fossil generation owners will encourage more and more energy users to invest in BTM generation and storage. Whether that amounts to grid defection remains to be scene, I dont think anybody can make that call given all the options for peer2peer, DSM rewards, virtual EV recharge sockets on the other side of your meter, etc to keep users on the grid. And who can say what political decision will be made on fixed price and Feed-In tariffs over the next two decades?

            And their is definitely going to be some level of over-capacity some decades from now, perhaps we’ll put it to good use like drawing down CO2?

          • juxx0r

            The cost of solar is going lower than the cost of transmission.

            The cost of grid energy is insane. It’s not just high, it’s a failure.

          • Alastair Leith

            So your solution is to decentralise everything and eliminate economic benefits of the sharing economy. Every single battery and solar cell paid for at retail prices in non-optimal locations. Sounds genius, just perhaps there is a middle path between throwing the baby out with the bath water and doing nothing with utility generation.

            Importantly, we don’t have time to wait for every house, school, hospital, commercial building, industrial complex and anything else to become totally self sufficient in energy production. The climate is already in a disastrous state of 1.6º C of committed warming, a 4.0º C of warming world is to be expected, even with the Paris Agreement commitments or better. Industrial scale RE can move us along much faster.

          • juxx0r

            No, no, no.

            I’m telling you that it will be financially beneficial for people to do this. They will recognise this, do it and you and I will have no say.

  • juxx0r

    I dont get how people don’t see that transmission will be the first to fall when the revolution comes.

    • Chris

      Explain this revolution a little more? I honestly dont see how running an entire country without a transmission grid is even remotely possible. You obviously dont sound very technical minded, or in a realistic manner anyway

      • juxx0r

        Residential and small business power is 20-30c/kWh. It goes up at 10-18% a year paying for silly things like transmission upgrades and artificial must run gas set restrictions.

        Solar is 5-7c/kWh delivered.

        Batteries are currently $666/kWh residential (about 20c/kWh), about $400/kWh commercial (about 13c/kWh) Large commercial about 11c/kWh.

        https://uploads.disquscdn.com/images/653ce7cb220add869935f2a0e02666102e6e27d59f22ebadaefc5a501a289bf5.png

        Give it a couple of years, power will be 35-40c/kWh on the grid, DIY will be 10-20c/kWh.

        Which will mean most of the demand for power will disappear from the grid. Then you wont need to move it around.

        • Chris

          As much as it may work out economically for some households, by 2030 Victoria for example is predicted to have 5500-6000MW of solar installed which is a majority of households. Yet AEMO predict this will provide around 5000gwh annually compared to annual total demand of 46,000gwh in Victoria. FYI a majority of grid demand isn’t residential but rather commercial such as shopping centres, hospitals, skyscrapers etc. And for such large customers, who would self consume all of any solar they’d generate, storage is just not worth it for them.

          • juxx0r

            Once you work it out economically, people find a way to make predictions look ordinary.

            Commercial users it’s economic for too.

            hold onto your hat.

          • Chris

            For some commercial users it may be economical, but it comes down to technical limitations. And what I’m saying is a majority of electricity demand won’t be possible to take off grid. Take the Melbourne CBD for example, it’s the size of a small suburb yet contains 300,000 customers and has an average demand of 600MW.

  • Peter F

    David
    Great work as usual. I need to read it again to fully understand it but there are alternatives.

    Assuming we keep the existing gas plants, all the generation required for any population centre in Australia can be located within 200 km of the city. For example on Germany’s current renewable trajectory they will be close to 45% of power by 2020 i.e. 240 TWhr or 610 MWhr per sq.km. The land area within 200 km of Melbourne is around 90,000 sq.km i.e. a potential of 55 TWhr. Because of superior wind and solar resources compared to German averages, the Melbourne region potential is closer to 70 TWhr about double the annual demand.

    AS for peak power demand which is around 6 GW, Hydro and small generation within the region is around 1 GW gas is 2.3. Properly managed demand response 0.5-1 GW, licenced backup generators perhaps another 200 MW Existing connections from the Snowy, SA and Tasmania can bring in a little over 2 GW. so storage, and or new inter-connectors have to have about 2-3.5 GW capacity including reserves.

    Three new inter-connectors to the Melbourne region will probably cost around $3-4b based on pricing suggested for various options. To make them reliable additional generation will have to be built anyway. A standing high pressure zone over the eastern half of the country may mean zero wind in SA and some wind in NSW/Qld but not a lot and even if the lines are DC there will still be 5% or more in losses

    Assumptions:
    25% of solar customers in the Melbourne region install batteries by 2025 we will have 1.2-1.5 GW of batteries.
    Based on US DOE modelling it is probably economically feasible to upgrade existing hydro by about 200 MW for $400 m and add 600 MW of pumped hydro for $1.5 b. Adding six distributed 150 MW reciprocating gas plants provides grid reinforcement and resilience at less cost than duplicating transmission assets, about $1,1 b leaving Alternatives, batteries CHP plants, solar thermal etc. 1-1.5GW Batteries at $600,000/MW seem to be able to complete the system for about $1b

    Thus total cost of localised system is about the same as additional inter-connectors. It is not apples for apples of course. The inter-connectors might outlast local storage but that depends on how much load generation imbalance there is in the source region.

  • hugh grant

    Australia has invested billions of dollars on interconnectors since the NEM was formed, yet their benefit/cost ratio is highly debatable. While interconnectors can provide frequency control ancillary services (FCAS), FCAS needs to be available within individual regions or sub-regions in the event of becoming separated from the NEM (islanded) For example, the two Victoria to South Australia interconnectors were unable to prevent the recent South Australian blackout.
    The recent South Australian outages have created a perceived ‘sense of urgency’ to improve energy security, with some vested interests claiming that additional interconnectors are the most obvious solution – despite interconnectors being very expensive and having very long construction lead times.
    It is important that the current perceived ‘sense of urgency’ is not used as an excuse to rush through approvals in potentially stranded network infrastructure that current and future generations of consumers will be required to fund.
    Rather, it is important that such proposals are subjected to robust independent assessments of their costs and benefits, and that all viable options (including non network solutions) are appropriately considered.
    Such assessments will need to involve critical evaluations of the increasing risks and costs associated with expanding large-scale network infrastructure, including:
    • The stranded asset risks arising from the structural transformation of Australia’s electricity system from a predominantly centralised to a predominantly decentralised system
    • The costs and impacts of physical risks from climate change
    Reforms to network planning, including the long overdue implementation of a national transmission planner together with contestability of network extensions need to be implemented to ensure the independence and transparency of such interconnector proposal assessments

  • Malcolm M

    Re Victoria, AEMO released an upgrade plan in late June, which takes into account a higher renewables share. They also issued a call for non-network solutions (such as batteries and demand response) to address constraints in the north-west of the State, but expected that constraints between Ballarat and Horsham would need additional transmission lines.

    There appears to be a lot of “low hanging fruit” within the existing network, with many lines at times of peak transfer operating well below the line thermal limits. For example, the import capacity from NSW could be increased by 200 MW by quick-acting demand response within Victoria.

    http://aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/VAPR/2017/2017-VICTORIAN-ANNUAL-PLANNING-REPORT.pdf

  • Peter F

    for Victoria to replace 55TWhr it would require 8 GW of wind. 7 GW of tracking solar, 1.5 GW of waste/biomass 100 MW of small hydro and and 4 GW of fixed solar.
    That is
    One wind turbine a day for 6 years. That is what Scotland has been doing for the last 4 years. Scotland’s economy is 2/3 rds the size of Victoria and its area is 1/3rd ours. doesn’t sound too difficult.
    Tracking solar 30 Nowingi size plants. Doesn’t seem to be a big problem. one crew the size of the Nowingi crew moving around the sate should knock that off in seven or eight years.
    Victoria is installing about 16-18 MW per month on rooftops. that will take a while probably 18 years at the current rate to add 4GW, but if measured in panels rather than kW. If we kicked the rate back up to what we achieved at the peak a few years ago we can easily halve that time.

    Net result if we wanted to we could replace all our coal plants in 8 years without anyone noticing any strain on the supply chain or labor force