There was a brouhaha recently over the development of safety standards for home battery installations in Australia.
Meanwhile, behind the scenes a raft of other regulatory changes has been gathering pace that will have just as big an impact on the development of the battery market.
It’s been a bit of a free-for-all up till now, but the regulatory regime seems to be developing in a way that should benefit consumers and renewables in the long run, even if it involves some restrictions in the short term.
This is a big deal given the projections for the likely future uptake of a range of distributed energy resources (DER) – not only solar and batteries but EVs, smart homes, and all the unknown unknowns.
The ENA/CSIRO Network Transformation Roadmap projected that over 40 per cent of customers will use DER by 2027, and two-thirds by 2050.
As the figure below from the AEMC shows, batteries and other DER have multiple value streams that can only be fully captured by different players in the market working together. Anything less would be inefficient: anathema in a market run (in theory) according to the mantra of economic efficiency.
What happens, for instance, if you have just spent over $10,000 on a shiny new battery and want to export some of that energy during those evening peaks when you have spare capacity to recoup some of your investment, but the network or a big retailer has effectively captured the market in your area with a much larger battery, so no-one will pay you for your relatively measly export?
Or if there is no energy in your battery because the network has the right to suck it dry to meet peak demand in your area?
There are two main dimensions to this issue. One is who gets to own, control and profit from the value streams associated with “behind the meter” batteries in homes and businesses.
As reported previously in RenewEconomy, networks and retailers are engaged in a turf war for this burgeoning market. AGL’s virtual power plant trial in Adelaide is an example of its attempt to get a foothold in the home battery market.
The aim is to aggregate the output of large numbers of home batteries to sell the excess capacity into the wholesale market during peak demand periods.
Meanwhile there are various trial projects involving networks (such as TasNetworks on Bruny Island) which aim to use home batteries to manage peak demand, reducing the need for expensive network augmentation, as well as helping with local voltage and frequency control.
The reach of distribution networks has traditionally stopped at the meter (or the connection point, to be more precise).
Because they are monopolies earning guaranteed revenues from consumers, regulators and consumer advocates have been uneasy at the prospect of networks extending their reach beyond the meter, because they could use their power to restrict competition.
Regulators and advocates would rather see more, rather than less, competition, on the grounds that it is more likely to deliver lower prices, more innovation and ultimately more renewable energy in the grid.
The response has been twofold. In its draft determination on two rule change requests relating to the contestability of energy services, the AEMC is proposing to prohibit a network “from including in its regulatory proposal and regulatory asset base, capital expenditure for assets that are located behind a retail customer’s connection point.” Translated, they are effectively banning networks from owning consumer-side batteries.
It’s not a blanket ban, though. The regulator can grant exemptions where a network can justify why it is best placed to provide this service.
And it has developed a ring fencing guideline that – if it works as intended – should enable networks to compete for consumer-side DER on equal terms with third party companies through affiliated but arms-length companies.
What happens on the grid side of the customer’s meter is just as important.
Consider Energy Queensland’s (formerly Ergon’s) excellent GUSS (grid utility support system) grid-side batteries. The network is rolling out 20 of these 100kWh units on long skinny feeder lines in isolated parts of the grid to reduce the need for augmentation and for voltage control.
This is just one of about 20 network battery projects underway around Australia. All are trials, but before too long some will turn into business as usual propositions and either be added to networks’ asset bases or procured from third parties with the revenue recovered through their opex allowances.
When a project like this becomes business as usual (which is only matter of time), installations like these will be able to take advantage of other value streams including arbitraging (charging from cheap solar or offpeak grid energy and discharging for a higher price when demand is high in the wholesale market) and the burgeoning FCAS (frequency control and ancillary services) market.
The question then arises: who should own, control and benefit from these multiple value streams – especially when the direct network benefit (managing peak demand) may be worth less than the other value streams but the cost of the battery has been added to the network’s asset base and already recovered over a decade or more from consumers?
We would prefer to see competition in this grid-side battery market too, but that is less certain. The AEMC has proposed incremental changes to the labyrinthine service classification system that determines what networks can own and add to their asset base and what they must go to market to provide.
I’m not convinced that this will lead to third parties being able to tender for midscale (100kWh-1MWh) batteries providing network support.
In practice this may not turn out to be a major problem. Since arbitraging and the FCAS market are likely to be more valuable than network support, networks may be obliged to contract with third parties (with the benefits divided up via the shared asset and cost allocation mechanisms).
But if that turns out not to be the case – if, say, networks can avoid regulatory investment tests (RITs) by keeping their planned investment under $5 million to install batteries on their own terms and add them to their asset bases without involving third parties to capture other value streams – then this rule change may not encourage competition in grid-side DER.
The other reform process currently underway was prompted by WA network Western Power’s desire to take isolated customers offgrid where installing a combination of stand-alone solar, batteries and maybe backup diesel gensets would be cheaper than replacing poles and wires.
Western Power forecast this could affect 2,700 customers and save $388 million over 50 years. NSW’s Essential Energy went further, suggesting it could affect over 8,000 of its most isolated customers and save up to half a billion dollars over only a decade.
Western Power proposed a change to the rules to allow networks to continue to be responsible for customers where it has taken them offgrid. (This doesn’t conflict with the AEMC’s contestability proposal because the former only covers customers who are already grid-connected).
As long as the consumer protections are similar to those with grid connections, this reform is generally supported by consumer advocates.
However, its implementation will be delayed because it turns out that the National Electricity Law as well as the rules will need to be amended, and that means going through the COAG Energy Council. But it is coming.
It is early days, and efficiently and equitably capturing the various value streams offered by batteries may prove to be horrendously complex.
Still, unless I am suffering from Stockholm Syndrome, it is heartening to see that in this context the regulatory regime is not completely broken but rather appears to be capable of incremental reform to accommodate the boom in DER. Appendages crossed.
Mark Byrne is Energy market advocate at the Total Environment Centre