We note that an absolutely key assumption underlying the Integrated System Plan unveiled by the Australian Energy Market Operator this week is that Queensland and Victoria will achieve their respective renewable targets.
We note that other forecasters such as BloombergNEF make no such assumption. Of course, you get completely different conclusions about what will happen in the market based on those fundamental differences.
As we have written several times, Queensland’s 50% renewable target by 2030 has profound implications and the first thing any investor interested in price forecasting must do is take a view on that policy and how to minimize the risk of getting a judgement wrong or maximise the return from getting the call right.
That said the immediate recommendations of AEMO flowing from the ISP are:
Group 1 investments
- Increase transfer capacity between NSW, Queensland and Victoria by 170-460 MW. Specifically:
- Vic to NSW increase 170 MW’
- Qld to NSW by 190 MW;
- NSW to Qld by 460 MW;
What does this mean? In my view it will increase pressure on NSW thermal (coal) generators. NSW has higher thermal costs, even after adjusting for transmission losses than either Victoria or Queensland.
The increasing growth of renewables in both States, but particularly Qld will increase the incentive on coal plants in those States to export at times of high renewable generation.
This will result in a loss of market share to marginal price coal plants in NSW, specifically Vales Point and Eraring, and maybe Mount Piper . These minor transmission developments are expected to be completed around 2020.
NSW could export more to Queensland but this is rarely a profitable choice now that Queensland Government has managed price down.
It will also reduce the incentive for say EnergyAustralia to build a new combined cycle plant in NSW. How much of a reduction is impossible to say.
- Increase transmission investment in West and North West Victoria.
This will simply incentives more VRE in that region probably resulting in more wind and PV investment there than would otherwise be the case.
Group 2 investments slated for the mid 2020s
The real value of the ISP is in its Group 2 investements which are to be built by the mid 2020s. It’s these developments that will really shape the landscape. They include:
- South Australia to NSW bidirectional transfer of 750 MW
- Another 370 MW coming to NSW from QLD
- Snowy 2 transmission development (this was certain anyway, look who’s asking for it) and
- Potentially another Basslink. However, AEMO says initial analysis says this isn’t scheduled/needed until 2033. However, they also say they haven’t taken account of the potentially lower cost of storage in Tasmania v other regions and this is a topic for ISP 2 next year.
Once again we see these developments as bad for NSW thermal generation revenue. More renewables will come directly to NSW. In return NSW coal can displace gas in South Australia but this is a smaller opportunity. Once again new transmission from QLD will simply mean QLD energy displacing NSW energy.
Is AEMO underestimating the revenue pressure on coal generators?
AEMO models a fall of 40 TWh in thermal generation between FY19 and FY30 in its neutral case. We have eyeballed the numbers from AEMO’s figure 13.
Revenue reduction may not be as severe because the thermal generation can perhaps increase prices when VRE (variable renewable energy) is not operating. However, doing that will also incentivize storage and can only provide a short term win. If coal prices in NSW remain high there will continue to be real pressure.
AEMO does not provide a regional break up but it should be obvious that QLD is going to see a large reduction based on its renewable generation target. This will increase pressure on both the Tarong and Gladstone power stations.
Tarong closure will not, in our view, cause many ripples in the system but planning for the closure of Gladstone and the opportunity that simultaneously unlocks for renewable generation in the Queensland hub is something that will likely be a discussion point for Queesnland policy makers.
AEMO modelling and how it will guide policy
The ISP is the most extensive modelling exercise I can recall from AEMO. One of the key outputs from the model is and we quote the entire paragraph:
“The cost components of conventional generation and the cost and performance of renewable generation and energy storage are key inputs to the ISP. Changes in these input costs are also forecast over the plan period, projecting trends observed over recent years and expected cost reductions over time based on the maturity and potential of the technology.
Based on these costs, the delivered cost of energy from wind and solar in combination with storage from pumped hydro and batteries is anticipated to be lower than generation based on new coal or natural gas when the existing coal generators retire.
This is an evolving trend from previous plans, but the ISP is AEMO’s first plan in which utility-scale solar generation is projected to be lower-cost than wind generation. This change in cost relativities impacts on the generation forecasts, the preferred REZs, and the identified transmission developments.”
The document states that the key cost input data is taken from the CSIRO.
A summary of selected technologies and years is shown in figure one. For my money the wind capital costs are a bit on the high side and utility PV is running ahead, again, of the projections.
Other points of note is that the CSIRO shows rooftop PV as cheaper than utility PV, but of course the capacity factors are vastly different, bit still it’s interesting. The CSIRO’s projections are heavily driven by learning rates, the unit cost reduction for a doubling of the installed capital base.
Other assumptions can be found in the ISP assumptions worksheet on the AEMO web site.
High DER is $4 bn cheaper than alternatives and more than double transmission savings
One seemingly little noticed outcome of the modelling was that a high distributed energy scenario has a $4 bn higher NPV than other scenarios. This saving is additional to but more than double that available from extra transmission development.
The High DER scenario shows the potential for even greater use of DER to lower the total costs to supply, with the NPV of wholesale resource costs reduced by nearly $4 billion, compared to the Neutral case. Page 6
Even in this scenario though there is still value in more transmission capacity. If the modelling is correct it suggests that policy development that both nutures DER and works to integrate it with the bigger system is worth pursuing.
Contrast this with the heavy handed work of the ACCC which simply recommends getting rid of the SREC without considering the overall impact. Household storage is again just being pursued by consumers entirely on the basis of self interest.
AEMC chairman John Pierce would approve, but it may be there is a better way to do it when network and other costs are considered. We have seen little work on interuptability tariffs for instance despite the ENA/CSIRO/ENERGEA work showing their potential value.
Renewable energy zones [REZ] are mostly not going to be developed in a hurry
Despite all the work done on assessing REZ no conclusions were presented on the savings expected from their development. The identification of the REZs seems to have only been for the purpose of prioritizing transmission investment.
Further the possibility of offshore wind, particularly off the coast of Victoria seems to have been ignored. We argue than an offshore zone should also be contemplated.
We understand again that too much onshore wind development in one region will start to cause land access community issues. Farmers don’t want endless new underground lines through their farms.
In general AEMO’s conclusion is its best to develop renewables next to existing transmission rather than build new transmission to high resource potential zones. This is an important conclusion that bears more thinking about.
Transmission development and REZ priorities were developed on the basis is of four main criteria and two sub criteria.
The main criteria were:
- Resource potential, how much Sun and wind quality (that’s 2 of the criteria);
- Distance to market;
- Transmission investment required
We note that in contrast to Transgrid’s NSW study the REZ selection process doesn’t seem to have taken land value into account.
In the real world one of the reasons why Australia has a global comparative advantage in VRE development is access to land. Lower land access costs, ie payments to existing owners or purchase costs, is a driver of cost and arguably should be factored in. Never mind.
The sub criteria include the portfolio benefit, notably wind in Queensland and wind in Tasmania are less correlated or in Queensland to an extent negatively (good) correlated with wind in other States.
Also particularly in Summer daylight savings in NSW, Victoria and South Australia reduces the correlation of demand between States and indirectly improves geographic diversification of PV
Another sub criteria is system strength issues.
This approach to REZ development is different to that in say Texas. In Texas the regulators simply identified the areas with the strongest resource and built transmission to it. Full stop, job done. Ten years later the benefits were obvious to most.
Just for interest I used AEMOs resource grading of wind & PV (A to E) and scored A 5, E 1 added up all the scores and came up with the following figure.
The figure clearly shows that Queensland and South Australia have the best combined wind and solar resource potential. Only the Broken Hill region in NSW is able to get into the top 12.
The figure also shows that there is a relatively even distribution of scores. So for many zones, ifyou value wind and PV together and not separately then it may not matter where you prioritize but again we would argue that development close to population has higher land costs and this should be factored in.
If we look at some of the top zones, none of the top 4 in Qld are selected by AEMO’s model for transmission upgrades prior to 2040 in the Neutral scenario. In South Australia Roxby Downs is a 2037 upgrade but Leigh Creek is after 2040. In NSW Broken Hill is after 2040.
In short AEMO’s REZ modelling means that the areas of highest resource potential won’t have the transmission required prior to 2040.
Big picture outcomes
The plan envisages 70 TWh of power retiring by 2040 and expects this to be replaced by 28 GW solar, 10.5 GW wind, 17 GW of storage and just 0.5 GW of gas. Capital cost has an PV cost of $8 bn to $27 bn. The AEMO states this is a NPV but we are only talking resource cost.
If 8% -15% of the capex is moved from generation to transmission the overall delivered price of electricity is lower. This is the portfolio benefit and is currently forecast at $1.2 bn to $2.o bn.
Forget about North Queensland REZ until Gladstone closes
AEMO states that Northern Queensland has excellent quality renewable resources, both solar and wind. However further large scale generator connections are unlikely to be efficient in North Queensland until existing thermal generation in Central Queensland (read Gladstone) retires.
Upgrading the connection to the North Queensland Clean Energy Hub by building a 275 kV line to Kidston still only allows 200 MW of new generation to be added before the MLF (marginal loss factor) drops by 5%.
Essentially large scale renewable energy development in North Queensland can’t progress until there is either a very significant transmission investment or Gladstone closes.
This has implications for Windlab’s Kennedy project Stage 2 but also has policy implications.
David Leitch is a regular contributor to Renew Economy. He is principal at ITK, specialising in analysis of electricity, gas and decarbonisation drawn from 33 years experience in stockbroking research & analysis for UBS, JPMorgan and predecessor firms.