The Integrated System Plan being put together by the Australian Energy Market Operator will put a marker down about how Australia will go about organizing its generation future.
It will effectively represent a challenge to all the vested interests in the current system because it will explicitly and implicitly become a formal document that models a very different electricity system to the existing thermal dominated model.
No matter the form of regulation, the NEG, a specified renewables share, carbon tax (my favorite), EIS, CET, it’s the physical design and capacity of the system that will end up driving price.
In this sense we have long seen the ISP as more important than the NEG. Transmission investment is a 5-8 year time frame, getting this right is AEMO’s No 1 task.
In this note we focus on the possibility that there may be significant advantage in a renewables centric grid to using DC for transmission as opposed to AC.
Right now most believe that consumption growth to 2030 will be flattish.
So new investment – whether in transmission or generation – will likely require retirements of existing capacity.
We note if consumption is flat and yet we keep investing it will be difficult to manage final consumer prices down. It may be possible but it will be challenging. Prices are less important than total costs.
In California prices are much higher than in Texas but household customer bills are lower because Californians are more energy efficient.
The background challenge, and part of the ISP is coordination of behind the meter with in front of the meter.
Finally, we note that the key bone of contention will be the RIT-T test. This test basically requires that transmission proposals show a net economic benefit essentially looking at the change in consumer costs at both ends of the transmission line.
It is a fact that little new transmission has been built in recent years and that satisfying the requirements of the RIT test have been difficult.
It’s also a fact that the main transmission lines that connect the coal generation in the Hunter valley and the La Trobe valley were never built using the RIT test.
We simply do not see how renewable energy zones [REZ] can be established without significant transmission investment and that a more efficient process than the RIT is required if these zones are to be established in a timely fashion.
The plan had its genesis in the Finkel Report, recommendation 5.1. “to facilitate the efficient development and connection of renewable energy zones across the National Electricity Market”
The concept has grown to include interconnected infrastructure and energy developments including transmission and generation.
The key point is it’s a plan for delivering INFRASTRUCTURE to facilitate an “orderly system transition”.
The first plan is to be released in June 2018.
As renewable developers are quickly finding out, transmission issues can be the life and death of wind and PV farms. Recent revisions to marginal loss factors [MLFs] has shown that project economics can be driven by difficult to foresee changes in network utilization.
More importantly its been obvious for years, blindingly obvious but still the AEMC has turned its blind eye against it, that significant development of renewables is going to require transmission links that could never be easily justified under the existing RIT-T.
Transmission takes 5-8 years to get built, even when everyone thinks it’s a good idea. And not everyone does think it’s a good idea.
Vested interests don’t want new competition, the question of how transmission is paid for, the difficulty of forcing new investment into a market seeing flat consumption for another decade are all thorny issues.
Nevertheless, my strong view, based on the success of the ERCOT investment in Texas and the obvious fact, to me, that lots of coal generation has to be replaced over the next 10-15 years makes it imperative that the ISP is a success.
A strong transmission network provides security, flexibility and optionality. Easy access to transmission will incentivize otherwise marginal wind & pv projects to get the go-ahead.
AEMO has published some scenarios and assumptions to be used in the plan, and has run a consultation process. Stakeholder submissions to the process have been received and AEMO has published a summary.
The next step will be publication of Version 1.0 of the plan in June. After that the arguments will start.
The first argument will likely be about changes to the Regulatory Investment Test [RIT-T] that will surely be required.
We assume that argument away because in our view of the world new transmission is going to be required.
What we see as the key discussion that needs to be held is whether the new transmission should be AC or DC.
Two, in our view, key submissions to the consultation were from Siemens and UNSW. We award the Siemens submission an ITK gold award with the UNSW submission a worthy contender.
Do yourself a favour and read the excellent Siemens paper. Of course, like every submission it talks its own book. In this case it’s a really good book.
Broadly speaking at least $3 bn of transmission investment is proposed, but if this was to be done in a DC rather than AC form the initial cost would be higher.
In addition, the Powering North Queensland $1bn of investment, vital to the future of that region and maximizing the diversity of power source in the NEM is generally not included.
Most of the debate is in the NSW-Victoria-South Australia axis, but augmentation of the QLD- NSW interconnection, perhaps by converting the main line to DC is also under consideration.
The following map from the SnowyHydro submission shows the Southern renewable energy zones.
Most of Australia’s electricity transmission network is AC. Australia has one of the longest, if not the longest, interconnected transmission grids in the world.
Historically, the debate about AC v DC has simply been about costs. Simply put, DC connection has higher capital costs but lower line losses.
Siemens provided the figure below in their submission and noted that the current economic cutover distance, depending on load, was around 500-800 km.
The figure shows that the DC terminal station costs are more than twice the cost of AC terminals.
Factors other than cost are becoming important. Siemens notes that DC can do:
The UNSW submission notes all the above advantages and adds that DC transmission can operate under “low short-circuit ratios”
Your analyst is about as far from being a power engineer as it’s possible to get, but surely there must be some cost saving for PV farms that initially produce DC electricity to connect to a DC transmission line without having to go through an initial AC conversion process.
Most readers will be aware that the Blakers pumped hydro work also talks to, and costs a DC transmission network.
Your analyst has assumed that PV farms, in particular, can connect to an HVDC line cost effectively.
However the Powerlink submission noted in connection with the option of a Parallel HVDC network along the Queensland coast, that although it might be cheaper on a capacity equivalent basis, “the ability for generation to connect into a HVDC circuit along its length is limited due to the high cost of HVDC converter stations”.
Siemens points to
UNSW pointed to:
The Siemens submission went on to mention its MVDC concept. Potentially, Siemens states in 33KV to 132 KV networks MVDC is advantaged because it allows “seamless control of the active power flow”.
We think this means in practice its better suited to bidirectional or omni directional power flow than the traditional one way AC approach. Siemens claims it may offer higher capacity at lower voltage.
In the Siemens world an efficient DC backbone is connected to lots of micro grids (I define a micgro grid as a load that can operate independent of the main grid for some time interval).
Siemens notes that the thermal efficiency of centralized coal generation is around 33% but that the overall efficiency of microgrid power can be as high as 80%. Siemens therefore claims that distributed power has a higher value.
As such Siemens states that even strongly connected regional demand centres, eg Newcastle or Ballarat or Gladstone or Murray Bridge might develop their own resources and be managed as a microgrid.
The figure below is very futuristic as today, in my view, hydrogen electrolysis and storage is clearly uneconomic but the concept is clear.
Various submissions to the AEMO process questioned the internal validity of the scenario assumptions.
The point we want to make is that even in the “strong” in front of the meter scenario the cumulative increase in demand by 2030 is 21TWh which would require around 7 GW of new wind & PV – not a lot for 12 years.
The neutral scenario, which tends to be where the average policy maker or reader ends up, assumes a very small fall in consumption over the next decade.
The weak scenario for in front of the meter demand, sees about an 18% cumulative fall in in front of the meter demand.
Net demand for renewables then is likely to heavily influenced by thermal retirements.
Forecasting is a mug’s business.
Human judgement tends to use recent experience as the best guide to the future, I guess it’s the availability heuristic also anchoring. In any case it may or may not be correct.
There is money to be made and lost by making a different call but it’s a big bet.
One great advantage of wind and PV is that they are an excellent investment in times of high uncertainty because investment is modular and short time frame.
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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