Covid-19 slow-down could sting consumers in shift to distributed energy market

A Covid-19 driven slow-down in Australia’s uptake of solar, batteries and electric vehicles could wind up costing consumers, a new report has warned, by wiping out billions of dollars in network savings promised by the transition to a two-way distributed energy market.

The report, a position paper published on Wednesday by Energy Networks Australia, is the latest instalment from the ENA’s Open Energy Networks Project (OpEN Project), an in-depth study of how the national electricity market can best support the growing uptake of solar PV, batteries and electric vehicles.

The idea is to maximise the potentially significant benefits of these behind the meter resources – for the consumers that have invested in them, for consumers that haven’t, and for the grid – while also minimising the potential downsides, including the need for curtailment or for costly grid upgrades, or possible destabilisation of supply.

A cost-benefit analysis included in the paper shows that significant upfront investment is required to achieve this balance, and that net benefits are only delivered shortly before 2039 and only at very high levels of DER deployment.

The analysis finds that the costs of the transition range between $2.5 billion and $3.5 billion on a present value basis. And under a step-change scenario – that is, rapid uptake of distributed energy technologies – promises to deliver significant potential gross benefits of up to $6.5 billion by the end of 2039.

These benefits come largely through avoiding network investment associated with the electrification of transport, the report explains, while also harnessing new EV demand to resolve solar export constraints at residential level.

However, if the uptake of DER follows a lower trajectory, the corresponding benefits are also materially lower.

“The costs and benefits of developing a distribution market are highly sensitive to the DER deployment rate, with benefits demonstrated only at the very high deployment rates of the step change scenario,” the ENA report says.

“Under the central DER deployment scenario, the costs outweigh the benefits for all four OpEN frameworks, leaving consumers to face material costs in developing a distribution market, without any concomitant benefits.

“If, as a result of the COVID-19 pandemic, Australia follows the slow change scenario, the risks of consumers incurring negative net benefits from the development of a distribution market are high.”

The OpEN project – a team effort of the ENA and the Australian Energy Market Operator – proposes four possible models for the effective integration of distributed energy resources into the future grid, including an Independent Distribution System Operator (IDSO), a Single Integrated Platform (SIP), a Two-step Tiered (TST) model, and a Hybrid model.

The ENA notes that the first model – the IDSO – has been ruled out as an option, after being identified as too expensive and inefficient.

The SIP model, envisions a single market operator – in this case, AEMO – as operating a single centralised platform to optimise the dispatch of DER and manage all distribution and transmission-connected generation and storage.

As the report explains it, the platform would link with aggregators for the provision of DER services, providing direct access to the market. Aggregators would provide bids and offers directly to AEMO via the platform.

ENA says that while this model was shown to provide an efficient way to maximise DER access to the wholesale market, it risks centralising all capability to manage all DER down to the small scale or household level in one organisation, leading to complexity and inefficiencies.

The TST framework involves DNSPs taking responsibility for optimisation of DER dispatch within their own networks. The distribution level platforms
 would have responsibility for the organisation and operation of the local market for DER and for the development and operation of the distribution network.

Aggregators would provide bids to the DNSP and the DNSPs would aggregate bids from all DER in their networks and provide them to AEMO. AEMO would include these aggregated bids in wholesale market dispatch optimisation. The idea is that this model would represent ‘co-optimisation’ of both distribution and wholesale markets.

The Hybrid model, which the ENA says was included after consultations with industry stakeholders concerned about either the AEMO or DNSPs having too much control, and about the frameworks being too complex and unwieldy.

In the hybrid framework, the DNSP would manage and communicate distribution network constraints (operating envelopes) to DER participants, via aggregators and retailers, and AEMO. AEMO would manage a market platform that optimised all DER bids for wholesale electricity and system support services.

Ultimately, the conclusion seems to be that there is no clear “best” way forward. The TST framework is noted as an effective way to quickly maximise network access to facilitate DER participation in markets at local/regional level, but potentially too costly if DNSPs don’t collaborate.

The Hybrid model is evaluated as “a natural evolution” for both the DNSPs and AEMO, but questions are raised over how it will operate in practice, and whether it might become overly complex.

The report recommends that a range of hybrid frameworks be tested, in a series of trials which AEMO and DNSPs with the support of ARENA and the DEIP are already in the process of establishing. And ENA stresses that any trial should be co-developed with consumers to “place them at the heart” of any policy and technical developments.

And as Baringa Partners – who carried out the cost benefit analyses of the four frameworks – put it, with the recent Coronavirus-connected uncertainty about the scale of DER uptake, any new functionality (and its associated cost) should be implemented in an incremental way.

“Long-term, we are likely to see distribution markets where households can sell their generation,” said ENA chief Andrew Dillon in a statment on Wednesday.

“What we need to consider now is what changes can deliver maximum customer and system benefits at the most efficient cost.

“It’s clear we need to trial a variety of structures, and that’s why networks around the country are working with a variety of partners to test the best technologies and approaches to deliver the smart grid of the future.”

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