Could battery storage cut remote grid connection risks?

Energy storage is helping Australian power firms do something anathema to most utilities: kick their customers off the grid. Companies across the country believe that giving remote customers a mini or microgrid setup, based on solar power with battery storage, could be cheaper and less risky than a grid connection. 

Remote customers are particularly at risk from blackout problems, not just because they are joined to the network by long lines that are prone to damage but also because it can take utility teams longer to locate and repair power line faults. 

To safeguard against such challenges, utilities in Western Australia have long looked at exchanging remote customer grid connections for standalone power systems (SAPS), which typically comprise a mix of solar, battery storage and diesel generation.

Perth-based Western Power, which started piloting the concept in 2016, initially found that six SAPS customers had a total of less than five hours of power outage in a year, compared to almost 70 hours on the network connections they had previously been using. 

The pilot revealed customers were happier with their utility service and were relying on solar and storage for more than 90% of their energy needs. Beyond the customer benefits, SAPS are attractive to distribution network operators because the systems are easier and cheaper to maintain than poles and wires.

In 2019, Horizon Power of Western Australia became the first electricity provider in the country to begin moving customers onto SAPS on a commercial basis. 

By October that year, it had pulled down more than 60 km of poles and cables and moved eight customers off grid, with plans to install another 17 SAPS by the end of 2019. 

“For these customers, having stand-alone power and going off-grid costs no more, but delivers cleaner power and greater reliability and safety in regional and remote areas at the fringes of the electricity grid,” said Energy Networks Australia at the time. 

But the company that has embraced SAPS the most so far in Australia is Western Power. At the start of the decade, the network operator had identified 15,000 sites that could benefit from moving to SAPS. That’s equivalent to 1.5% of all the customers in Western Australia’s Wholesale Electricity Market. 

Currently Western Power is aiming to have 4,000 SAPS installed by 2032 and had used the microgrids to do away with 48 km of power lines as of 2022. 

The company has had a head start in the SAPS market thanks to an absence of regulatory restrictions, although in 2022 the Australian Energy Market Commission changed its rules to allow standalone power systems to be installed in the National Electricity Market as well.

Doing away with power lines is a startlingly simple response to the costs and risks associated with network connections, which until recently were the only way for utilities to provide electricity supplies to remote communities. And it is one that is not just catching on in Australia. 

In the US, PG&E is installing solar and battery microgrids in areas such as Pepperwood Preserve, which have previously been affected by grid-related risks. PG&E installed four such standalone power systems in 2022 and is aiming to have 30 up and running by 2026. Pepperwood is the first to run on solar and batteries alone. 

As well as improving electricity supply, the microgrids can help slash utility costs—for example by reducing the need for scrub clearance. At Western Power, the cost of such types of grid maintenance equates to AUD$200 million a year.

And in the US, “PG&E saves money either by getting rid of grid connections altogether or by delaying the construction of new lines,” reported Canary Media in September 2025. “Microgrids can also improve reliability for customers when utilities must intentionally de-energize the lines.”

Clearly, the value of SAPS will depend on factors such as the size of the community covered and the extent of demand coverage required. In 2020, an Australian study found that SAPS might not be cost-effective for remote towns but could have a positive business case for individual energy customers. 

However, the analysis assumed a 4% likelihood of annual hazards and the authors noted that at twice this level of hazard, “there is likely to be a compelling resilience-based business case for provisioning some remote towns with either islandable or islanded SAPS.”

With climate change projections suggesting the probability of grid-damaging events could increase beyond 8% before 2050, it is clear the business case for SAPS is set to improve. And another factor affecting the viability of SAPS is the cost of the microgrid equipment. 

Solar power is already the most cost-effective generation technology available in many parts of the world, and further cost reductions are expected across the photovoltaic module value chain. 

Battery prices, meanwhile, have fallen between 10% and 40% across global markets in the past year, according to the analyst firm Wood Mackenzie. 

Improving economics could see growth in the size of SAPS installations, from the kilowatt-scale setups required for single households or buildings to multi-megawatt projects that could serve entire communities. 

This echoes a trend that is already being seen in industry, with mining companies, for example, increasingly developing multi-megawatt microgrids to power remote or off-grid locations. 

The Agnew Gold Mine in Western Australia, for instance, gets up to 60% of its power from a microgrid combining 18MW of wind and 4MW of solar with a 13MW, 4MWh battery system. 

Back in the US, PG&E’s use of SAPS was given a boost in 2023 when the state regulator allowed the utility to rate base the microgrids as if they were grid upgrades. The caveat is that the SAPS installation must be cheaper than the grid upgrade it goes in place of.

But with falling equipment costs and growing microgrid installation expertise, a positive financial case for SAPS looks increasingly likely. This means lower costs for utilities and their customers. And, much more importantly, it will also mean a real reduction in the likelihood of grid-related risks that will only get worse in the coming years.