This article has been co-authored by Rob Passey, Anna Bruce, Iain MacGill, Mike Roberts, Kelvin Say, Baran Yildiz from the Collaboration on Energy and Environmental Markets, at the Faculty of Engineering, UNSW.
The AEMC’s ‘Pricing Review: electricity pricing for a consumer-driven future’, is timely and provides an opportunity to assess the effectiveness, efficiency and equity of current network electricity pricing and services in a rapidly changing world of rooftop PV, home batteries and electric vehicle deployment.
As defined in the National Electricity Objective, these arrangements should put electricity users first and foremost. Many of these electricity users face affordability challenges, many wish to improve energy self-sufficiency and reliability, and many want to help reduce the environmental impacts of their energy use.
Key to all of these aims is facilitating and encouraging household electrification, and the deployment of consumer energy resources (CER), which can help flatten distribution network load peaks (for example household batteries) and, together with controllable loads such as water heating and EV’s, increase network utilisation, which should reduce costs for all users.
Emerging options such as plugin solar and batteries can also provide direct benefits to households unable to access rooftop solar.
CER also places downward pressure on wholesale electricity prices, decreases emissions, and reduces the immediate need for large-scale generation and transmission (which has faced a backlash in regional areas), making the Federal Government’s 82% renewables target for 2030 easier to achieve.
Of course, some CER technologies can reduce revenue to networks, which under revenue cap regulation can increase costs for all customers.
In our view the AEMC Review has justified higher fixed network charges by essentially focussing only on the potential for increased network tariffs.
Their modelling appears to be based on the assumption that the bulk of the benefits of CER are dependent on dynamic network pricing strategies which can only be implemented as a package with the higher fixed charges. This also leads to the claim that the AEMC reforms are the drivers of reduced spot prices and emissions.
There are a number of problems with this approach. Firstly, it assumes that CER only provides benefits in response to dynamic prices.
However, household batteries, even on a flat tariff and so with no dynamic price incentive, can provide significant ‘passive’ benefits by charging from excess solar then discharging during the evening, thereby reducing network peak demand.
In contrast, the Pricing Review’s distributional impact analysis claims that household batteries “do not reduce current or future network costs (e.g. because they are mainly reducing imports in ‘off-peak’ periods…)”, which is clearly incorrect.
The use of time-of-use (TOU) tariffs, especially those that pay extra for evening exports, further enhances CER’s ability to reduce evening peaks.
Secondly, it assumes that additional dynamic pricing strategies, such as virtual power plants (VPPs), which currently orchestrate the batteries of about 80,000 households (about half in traditional VPPs and about half with Amber Electric), will only occur as a result of the AEMC reforms, which is also incorrect.
Thirdly, it assumes that moving 80% of network charges (which make up almost half the average bill) to fixed unavoidable costs would have no impact on the uptake of CER (the modelling uses existing ESOO projections of uptake).
This is highly unlikely because such a change would significantly reduce the financial benefits of installing solar, batteries, flexible demand appliances and energy efficiency options such as heat pumps.
Thus, there is a need to model the counterfactual, which is where fixed charges are not increased but both the passive and dynamic pricing impacts continue to accelerate.
The original modelling should be adjusted to include a reduced rate of uptake and lower response of CER because of the higher fixed charges and less cost-reflective network tariffs (or vice versa, with the counterfactual scenario having greater uptake and response).
The inclusion of passive benefits is particularly important to capture households that do not wish to participate in dynamic pricing such as VPPs (currently about 90% of battery owners do not participate).
This Review occurs in the context of the National Electricity Market being in a particular type of transition, where the installation of one technology can accelerate, or perhaps slow, the installation of others and can influence how they are operated.
This means that technologies should not only be assessed individually, but also in terms of how they impact the overall energy transition.
Although the net impact of an incremental addition of rooftop solar may now increase costs faced by non-solar households, new solar systems are commonly installed alongside batteries which reduce evening peaks.
Of course, as discussed above, batteries can also reduce household payments to networks, so rigorous analysis is needed to understand their net impact.
Rooftop solar also influences the time of day that households charge their electric vehicles (EVs), and in combination with TOU tariffs (that the AEMC recommendations would make less effective) results in only a small proportion charging during peak demand times – again providing network benefits.
Given that the potential of CER to provide network cost, spot price and emissions reductions (which benefit all customers) may be counteracted by their ability to reduce revenue to networks, there is clearly a need for more rigorous analysis of all these countervailing impacts.
Once this analysis has been undertaken, the overarching aim of policies and regulations that facilitate the uptake and operation of CER could be to capitalise on its attributes and so reduce the costs of electricity for all customers, especially for those that don’t have these opportunities to deploy CER.
The focus of this Review should not only be on punitive measures that aim to limit CER uptake driven by assumptions centred around the potential loss of revenue to DNSPs.
This article has been co-authored by Rob Passey, Anna Bruce, Iain, MacGill, Mike Roberts, Kelvin Say, Baran Yildiz from the Collaboration on Energy and Environmental Markets, at the Faculty of Engineering, UNSW.
