No man is an island – even in a future of stand-alone power systems | RenewEconomy

No man is an island – even in a future of stand-alone power systems

Consumers might get paid to have batteries that will “island” from the grid, and EVs that can deliver power when needed, as part of plans to make networks more resilient.

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Imagine getting a rebate from your local electricity network to cover the cost of your solar and battery system becoming “islandable” — that is, being able to keep working even when the grid goes down. (Many batteries, and almost all PV systems, currently can not do this.)

Further down the track, things could get even more wild. You could get a rebate from a network towards the purchase price of an EV with vehicle to grid (V2G) capability in return for guaranteeing to make it available to help supply power to your neighbours if a bushfire or cyclone takes out the main grid for days on end.

Even homes and small businesses that don’t have solar and batteries could benefit from reforms aimed at increasing the resilience of the energy system in the face of accelerating climate change impacts, cyber attacks and “black swan” events like the coronavirus that come out of nowhere and potentially wreak havoc on business as usual.

These consumers could be paid to reduce their normal demand if the local grid goes down for an extended period in, say, a country town which is forced to rely for partial backup on a community battery or a diesel generator which can only supply part of the whole town’s normal load. Or they could get a rebate to invest in more energy efficient appliances to reduce the overall load in high-risk areas.

These are just some of the local energy options that may need to be considered in the near future — alongside undergrounding more power lines and de-energising lines to prevent fires starting — as alternatives to hardening the transmission system to make the energy system more resilient.

For now, though, the focus is on stand-alone power systems (SAPS) and microgrids as the most obvious and cost-effective options to increase energy system resilience at the local level, especially in rural areas serviced by long skinny lines which run through forests.

A new study by CutlerMerz (funded by ENA and ARENA and due for release any day now but the subject of a public webinar last week)* modelled four theoretical case studies to assess the business case for off-grid or stand-alone power systems (SAPS) and microgrids to replace poles and wires connections to isolated towns and properties which might be affected by bushfires.

Naturally, the results depend on multiple assumptions and vary according to the sensitivities tested for. But in short, this is what they found:

– It already makes financial sense to move some individual properties, particularly where existing lines traverse heavily forested areas, onto SAPS, but the business case improves markedly when you factor in the potential for more frequent bushfires.

While standalone or islandable microgrids do not currently pay for themselves, due primarily to the high capital costs, they are likely to do so as bushfires become more frequent.

This is without factoring in the non-economic benefits of SAPS and microgrids, which include the ability to share energy with neighbours, the peace of mind that comes from knowing your energy comes from onsite or nearby, and the tangible sense of community that is fostered by local projects with local ownership.

It is also relevant to consider the costs and benefits of localised versus large scale, transmission level resilience. In other words, what’s the optimal combination of centralised, localised and off-grid resources?

Resilience is maximised when you can meet your needs through both localised and centralised supply, so that if one goes down, the other is still available.

That flexibility comes at a cost. In the short term, networks need to spend more to build more resilient grids, so this spending will need close scrutiny. But in the long term, building in resilience should be cheaper than rebuilding like-for-like more and more often after severe weather events.

It’s also a question of where you spend. Distribution networks are collectively spending less than $1 billion on the integration of DER over the next five years,** whereas AEMO’s 2020 integrated system plan (ISP) recommends investment in centralised supply of nearly $20 billion between now and 2040.***

With DER likely to supply up to half of all capacity by then, it doesn’t exactly look like a level playing field at the moment, even if network DER integration spending increases over the next decade or so.

Recognising the role of DER in increasing energy system resilience depends on two things. One is better climate data and a risk assessment framework. These should come out of the Electricity sector climate information (ESCI) project being undertaken by CSIRO and AEMO with the Bureau of Meteorology (BOM). This will enable networks to identify the assets under threat from extreme weather events.

The other element is regulatory reform. Despite resilience having become an industry buzzword over the past year or so, there is currently no recognition of it in the national electricity rules (NER). This would start with a definition. CutlerMerz refers to “the capacity of communities to prepare for, absorb and recover from natural hazard events and to learn, adapt and transform in ways that enhance these capacities in the face of future events.”

(This definition, which is derived from the work of the Bushfire and Natural Hazards CRC, emphasises the social and adaptive nature of resilience. Older definitions, especially those derived from the electricity sector itself, tend to tend to view resilience in engineering and defensive terms, as a matter of withstanding shocks to the system.)

Also important is a way of quantifying resilience. The AER recently had a crack at developing a metric for widespread and long duration outages (WALDOs) but it went nowhere. Many impacts of severe weather events like bushfires and cyclones do not affect widespread areas, so would have been excluded in any case.

What is needed above all, though, is a mechanism to incentivise distribution networks to invest in assets and services which increase the resilience of the grid to the benefit of consumers. At present, there is no positive requirement under the existing framework for networks to make investments to increase system resilience.

In fact, there are disincentives to investing in resilience (eg, the regulatory regime rewards networks for underspending on capex and opex).

The Total Environment Centre and partners are intending to submit a rule change request to the Australian Energy Market Commission early next year to remedy this problem. This is one of the recommendations of the CutlerMerz study. Our proposal will require networks to consider the long-term impacts of more frequent and intense severe weather events in their five yearly revenue proposals, and to plan accordingly.

While regulators will need to be vigilant about giving the green light to another round of network goldplating, this should lead to lower electricity prices in the medium to long term, for two reasons.

One, distribution networks will invest in assets and services which are less likely to be damaged by severe weather events and require repeated rebuilding.

And two, if resilience services are more cheaply obtained from DER than from centralised assets, this is likely to stimulate a long-term shift away from replacing transmission level poles, wires and substations with like for like assets at the end of their lifespans.

The shrinkage will not stop there. Western Power is reportedly considering decommissioning up to half of its distribution network poles and wires over the next decade as it moves isolated customers and communities onto standalone systems and microgrids.

In a reversal of the old top-down energy supply paradigm, when every customer or community becomes a power station and trader, the old centralised system may eventually be there mostly as a source of backup supply for when local generators or individual systems are offline.

Then the question that arises will be, how much are we prepared to pay for what is effectively a form of insurance? With governments falling over themselves to invest in or underwrite large scale generation and transmission assets, consumers might not have much choice but to pay through the nose over decades for a string of very large white elephants, while local communities go about the business of adapting as best they can to a rapidly changing world.

  • *This article is based on the webinar slide pack rather than the project final report.
  • **Author’s guesstimate of total forecast expenditure related to DER integration in the most recent round of distribution network revenue proposals.
  • *** Approximate total of modelled costs for network investments in the 2020 ISP optimal development path.

Mark Byrne is Energy market advocate at the Total Environment Centre (aka #rulechangesrus). 

Disclosure: TEC had a minor role in the CutlerMerz project, reviewing the regulatory framework.

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