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21 January 2021

California gives sparse funding to set blueprint for smart microgrids

The quest to solve California’s wildfire problem and resultant blackouts has been boosted with a $200 million strategy from The California Public Utilities Commissions (CPUC). The regulator has now approved a plan for utilities to deploy microgrids which will protect consumers from disruption during fire-prevention blackouts, although funding may not stretch far enough for the required supplementary infrastructure.

In the deal signed last Thursday, rates, tariffs and rules have been drawn out for utilities Pacific Gas and Electric Company (PG&E); Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E). While nothing should have stopped these from deploying microgrids in the past, a new range of standards and protocols should reduce barriers to statewide deployment.

The term microgrid usually gets associated with developing countries, where connection to a centralized transmission network is unfeasible or economically unviable. However, the essence here is that distributed energy resources (DERs), including technologies like rooftop solar, will be connected into “complex multi-property microgrids,” which can act as standalone electricity networks.

For California, this will be most imperative for communities that are most vulnerable to utility-enforced blackouts, during the state’s wildfire season.

Just a month ago, the state was once again ablaze. There is little doubt that climate change is having a significant impact on the frequency or the intensity of wildfires, which tore through a record two million acres in 2020 – surpassing the previous record set in 2018. This is hardly surprising considering that the highest temperature in Earth’s recorded history was measured in Death Valley in August; a scorching 130 degrees Fahrenheit.

During these conditions, with strong Santa Ana winds blowing from the North West, downed power lines must be disconnected, or they may spark flames that will spread out of control. As a result, utilities are increasingly forced into enforcing deliberate, but unplanned, large-scale blackouts.

Failure to do so also poses significant financial risk to utilities. In May last year, PG&E was forced into a $13.5 billion payout to compensate victims for their uninsured losses from a series of wildfires blamed on the utility’s faulty equipment. Legal actions could have amounted to $30 billion and would have forced PG&E into bankruptcy. The reduced amount will see it keep its head above water – but only just.

However, the blackouts themselves do not come without cost. Instances in 2019, when PG&E had to shut off power to nearly 2 million customers, were estimated to cost the region over $2 billion in knock on economic effects: schools shutting; hospitals relying on back-up generators; loss of frozen goods.

In this regard, California’s citizens feel both ends of the stick. To compensate for protectionary measures, the state’s electricity prices are more than 70% higher than the national average, despite the fact that its population use around half the electricity per capita.

The combination of these issues is pushing a rhetoric from the state’s oil and gas lobbyists that California’s ambition to electrify everything, from buildings to transports through a grid powered by renewables, will increase exposure to wildfire risks and push energy prices up even higher.

Sadly, while the state cannot protect its people from blackouts, this could well be the case. But if utilities can implement smart microgrids, driven by distributed energy resources, then costs will eventually settle back down.

CPUC had previously stated plans to provide cost-effective microgrid alternatives to diesel back-up generators by 2021, but limited progress has been seen so far. The ‘Track 1’ mandate in 2018 calling for low tariffs, hasn’t caused commercial microgrids to flourish as intended. Tight timelines saw utilities fall short of targets that had been set, and with PG&E in disarray, it even ended up contracting for hundreds of megawatts of diesel generators as a stopgap measure.

The new ‘Track 2’ decision, will aim to streamline development further. Interconnection rules will be adjusted to allow behind-the-meter backup systems to be brought online more quickly and store more grid power. However, with pressure to keep spending low, the fifteen projects that will benefit from the $200 million grant incentives are unlikely to cover more than a fraction of the state’s demand for backup power.

Part of the new plan will see each of the involved utilities create a microgrid tariff that prevents cost-shifting within their territories. CPUC has published guidance for these tariffs, suggesting that payments for aggregated DERs are treated the same as a single utility scale plant. However, ensuring that storage facilities are kept reserved for blackouts provides an investment problem that has not yet been resolved.

This is where having the option to initiate a decentralized system on demand has its benefits. With more DERs in the system, transmission can be operated more flexibly. Technological advancements are enabling system operators to troubleshoot problems before they occur and get systems back up and running faster after an outage – often in under 30 seconds.

Such an environment also provides further incentives for those hoping to install residential solar panels or energy storage, building on the California mandate that all new-build properties should include renewable generation, which started in 2020. With electricity being traded locally, the need to invest in large-scale, long-distance transmission upgrades is also largely reduced.

However, much of the supplementary infrastructure to support such a system will need further investment. Household-to-household trading will benefit largely from blockchain-based ‘smart contracts,’ where excess electricity produced by a ‘prosumer’ household will be sold locally. Prices will be defined based on supply and demand to match that available from the grid, while excess production on a community level can be sold back to the centralized network.

Such schemes have been piloted in countries like Switzerland, by Quartierstrom and the Water and Electricity Works Walenstadt (WEW), which tested a blockchain project that created a local energy market between 37 homes for a year.  The goal was to see how homes that produced rooftop solar electricity could trade with other participants, and the role that the central grid would play in the process, using a blockchain system to keep track of these transactions – acting as a digital ledger.

For such microgrids to be as inclusive as possible, this will demand significant volumes of real-time data transmission across areas that may not always be reliably served by fixed-line broadband, especially during periods of power outage. Wireless networks such as LTE and 5G, provide a key opportunity to optimize the deployment of such smart microgrids and facilitate cost and efficiency savings on a national level.

High speed wireless networks, which can be powered through outages by battery storage will also allow these decentralized microgrids to provide self-healing when faults occur, with blackouts kept as localized as possible. Through projects like SliceNet in Portugal, Efacec, EFA and Altice Labs, are hoping to prove that 5G technology can be deployed in a system that can identify faults more rapidly and that ‘self-healing’ will allow for minimal homes to be disrupted.

Current iterations of fault location, isolation and service restoration (FLISR) technology, the minutes of customer interruption have been reduced by as much as 51%, with the number of customers interrupted falling by up to 45%. The frequency of interruption events also fell by up to 58%, while the number of miles travelled by service trucks was significantly reduced, as grid operators deployed maintenance teams more effectively.