How quickly things change, and sometimes for the better.
Amid the ongoing controversy over the emissions component of the National Energy Guarantee, at least it can be said that the Energy Security Board has finally got smart about reliability.
In doing so, the ESB has effectively rejected the push by conservative elements to insist that all wind and solar farms be saddled with storage, in a half-baked attempt at trying to fit them into decades-old thinking about a centralised grid.
Instead, the ESB’s thinking on reliability is now focused on moulding the grid to fit around what are clearly the cheapest form of power generation – wind and solar.
Forget “baseload”, the idea for the future is base-cost renewables.
Remember, less than a year ago, energy minister Josh Frydenberg took this slide above – among others – to the Coalition party room to argue the benefits of the Finkel Review, and particularly its proposal for a generator reliability obligation.
The idea – in those intense days of the energy culture wars – was for renewables to “pay for their intermittency”. It was an attempt to try to jam wind and solar into old-fashioned ideas about the grid, that if they couldn’t act like “baseload” then they didn’t merit a place in the system.
That thinking was embraced in the first two versions of the National Energy Guarantee, which threatened to impose a cumbersome, complex and ultimately costly contracting requirement on both reliability and emissions.
That has now been more or less abandoned. Indeed, it is arguable that the NEG exists in name only.
The emissions component is abandoned because the Coalition effectively has no target that is greater than business as usual, and the proposed physical contracts will be replaced by financial ones similar to those that already exist, if they are needed at all.
The reliability component is effectively made redundant, because the ESB recognises that there is no pressing problem on reliability now or in the near future,
And any issues that do arise – such as from the sudden departure of several coal-fired generators – is best managed centrally (by the market operator) and mechanisms outside the NEG.
The reliability assessment will be done 10 years out, updated each year, and only if, within three years of a potential issue arising, is the reliability guarantee triggered.
This is a huge development. In a sense, you could call it a victory of the futurists over the traditionalists.
We will have to see exactly how the market operator carries out its mandate, but the focus now is clearly on embracing new technologies, rather than penalising them, and forming rules and mechanisms that recognise their speed and flexibility.
Of course, it remains to be seen if the final rules established by the AEMC and AEMO will be the most efficient. ITK analyst and RenewEconomy contributor David Leitch, for instance, argues that auctions should be the most efficient mechanism.
The AEMC has called for comments on various mechanisms that will be linked to, but remain separate from, the NEG. These include demand management, day-ahead markets, and strategic reserves.
If you ever wanted a clear indication of the transformation that is going on inside energy institutions, then this quote from the AEMC document sums it up:
“Demand response is our future. It can help keep costs down by avoiding unnecessary investment.”
Still, the reliability component remains hostage to the government’s hopelessly inadequate emissions reduction targets – 26 per cent by 2030 for the electricity sector – and is, in effect, worse than if it had no policy at all.
This, of course, is the great weakness in the scheme, because it means little or no new investment in renewables, and therefore storage, apart from those mandated by state schemes, the corporate sectors, or behind the meter by households and smaller business.
One thing we do know is that no new “baseload” is needed.
The issue for market operators is not having enough power for general day-time and night-time use, there is plenty of that; it is for those demand peaks that occur in hot weather spells, that also cause trouble and put stress on the existing fleet of coal and gas generators.
This was illustrated by AGL economist Tim Nelson, in a presentation to the (appropriately named) Smart Energy conference last week, with this graph above.
It makes quite clear that NSW – probably the state with the biggest issues because it faces the most coal plants closures in the coming 10-15 years – has more than enough baseload.
For those occasions when there is not enough coal to meet the peaks, the system will use what it has for the past few decades: gas generation and other peaking plants.
And now there are more alternatives, because the peaks are narrower, thanks to rooftop solar, but they may be getting more acute as climate change takes hold.
The ESB speaks of demand management, and demand-side options, rather than new supply-side options like gas generators.
AGL’s Nelson suggests that in the medium term it will be a mixture of demand management and fast-response gas generators, and over the longer-term, battery storage and pumped hydro.
It was interesting to note that Morgan Stanley analysts also looked at this in a separate report last week, which was focused on Australia’s status as a “global test case for disruption” of the conventional utility industry.
In one of its many interesting observations, it reports on the so-called “merit order” for dispatchable power solutions.
Morgan Stanley rates these – from the cheapest to the more expensive – as:
(a) demand response (especially where demand curtailment comes at a low opportunity cost to the user);
(b) supply portfolio optimisation (noting that wind and solar production has a very low correlation);
(c) increased interconnection between regions (an extension of portfolio optimisation);
(d) new dispatchable plants (e.g., gas-fired OCGT or reciprocating engines);
and (e) storage solutions (e.g., pumped hydro, chemical batteries, and hydrogen).
This underlines the AEMO and AEMC passion for demand management, and it’s also interesting to note the second option, supply portfolio optimisation.
More and more renewable energy developers are looking to combine wind and solar, some with a little storage, others with a lot.
And while AGL have rolled out contracts for “wind firming” – i.e. pairing with a gas generator – others are looking at how the combination of wind and solar can do the same thing, with a minimal amount of third-party firming, or storage on site.
Still, the ESB does note that while some wind and solar farms are adding storage, it wants more dispatchable options over time, particularly when those ageing coal plants come out of the system.
On the subject of battery storage, now considered to be one of the costliest “firming” technologies, Morgan Stanley noted that this does not include the value of all the other services that battery storage can bring to the market.
These include grid services, of the type being delivered by the Tesla big battery in South Australia, and other new batteries to by installed near Wattle Point wind farm, the Ganawarra solar farm in Victoria, and a Bendigo grid facility.
Once these value chains are recognised by the market operator and rule maker – and it now appears there is every intention to do so – it’s hard to imaging that anyone would think of building anything other than a scaleable, modular, and quickly installed piece of machinery such as a battery storage, with a few pumped hydro projects for longer dated storage.