California needs to deploy up to 55 GW of long duration energy storage by 2045 and 2 GW to 11 GW by 2030, in order be on track to achieve the state’s 100% clean electricity goals, according to a new report from the California Energy Storage Alliance (CESA).

To put those numbers in context, 55 GW is more than 150 times the amount of energy storage that has been deployed in the state since 2010. Including planned storage development, it is nearly 12 times all storage currently contracted or in development within California.

While it would be easy to dismiss these figures as a storage-focused organization trying to advance its own goals, it’s not just CESA recognizing the need for exponential deployment figures.

The California Public Utilities Commission (CPUC) has put together models outlining that as much as 70 GW of energy storage will be needed to achieve the state’s goal of 100% renewable and zero-carbon electricity resources by 2045. The CPUC also determined that “all storage needed beyond 2030 will have to have discharge for durations of six to eight hours or longer.”

Environmental benefits and industry response

Deploying the level of storage that CESA is modeling for would allow the state to retire 10 GW of fossil fueled generation, reduce system capacity costs by $1.5 billion per year from 2031-2045 and increase renewable energy utilization by 17% while decreasing in-state fossil fuels usage for electricity generation by 25%.

The study has been met with positive reactions across the storage industry.“The latest CESA study clearly shows that long duration energy storage needs to be deployed now to meet the near-term as well as long-term needs of the energy market… It will take a strong commitment to long duration energy storage technologies to enable a 100% clean energy future,” said Javier Cavada, CEO of Highview Power.

“We commend CESA for bringing a spotlight to the long duration energy storage issue and it’s vital importance to creating a zero-carbon electric grid,” said Joe Zhou, CEO of Quidnet Energy, a provider of modular pumped hydro technology for long duration energy storage. “The level of effort required to transition to a carbon-free power system is substantial and requires solutions that can deploy cost-competitively and at the necessary scale… This report highlights the urgency of the need for long-duration storage in the state.”

In 2017 the University of Minnesota released a study – Modernizing Minnesota’s Grid: An Economic Analysis of Energy Storage Opportunities – projecting that solar+storage would be more cost competitive than a natural gas peaker plant in 2018 (a quick reminder that it is more than halfway through 2018).

In the document (page 42) Connexus Energy put forth their logic for solar+storage to offset peak demand. The utility found that a majority of members were willing to pay up to 5% more for their electricity for efforts to reduce greenhouse gas emissions. When they combined this with the demand charge offset that comes from solar+storage, the economics made sense, specifically for the utility. And now, as a result of an economic analysis, the utility has broken ground on two solar+energy storage facilities.

Connexus Energy is based in Ramsey, Minnesota and serves 130,000 customers in portions of seven counties in the central part of the state, particularly Anoka and Sherburne Counties. The cooperative utility began looking at batteries in 2016, but found they didn’t yet pencil. However, since then the economics have changed and now the utility projects savings of around $4 million a year through peak load reduction.

The Connexus projects consists of two solar gardens, one each in Ramsey and Isanti County’s Athens Township. The Connexus solar project is being developed by Engie, a French energy firm, while Florida’s NextEra Energy is taking care of the storage system.

The new, world-class system is part of a $3.65 million trial led by the University of Adelaide in collaboration with SA Power Networks and system supplier PowerTec. The project is supported by the Australian Renewable Energy Agency (ARENA) on behalf of the Australian Government with $1.44 million in grant funding.

The mobile battery energy storage system and its specialised control system reduces peak load of the local substation, stabilises the electricity network in the area, and supports a number of nearby customers in the event of a power interruption – all without manual intervention.

The battery receives control signals from high-voltage electricity infrastructure more than 5km away at the main powerline to the town of Cape Jervis, and makes its own decisions about how best to support local electricity delivery.

“This technology is novel because the mobile battery energy storage system’s operations are now completely autonomous,” said Associate Professor Nesimi Ertugrul, from the University of Adelaide’s School of Electrical and Electronic Engineering.

“If an outage occurs, our mobile battery system automatically runs a range of safety checks before providing back-up power to nearby houses until the main grid is restored.

“This feature means that residents can also share residential solar power with neighbours during an outage.

“This autonomous battery system has many unique and advanced features. We can monitor the system and intervene if necessary, but the system can operate safely in all kinds of situations without the need for any operator instructions,” Associate Professor Ertugrul said.

“It also allows us to understand the technology under real operating and weather conditions, and gives us the potential to create a knowledge base for industry and system developers.”

The South Australian Minister for Energy and Mining, Dan van Holst Pellekaan, welcomed the commissioning of the battery as an example of how energy storage can be help make our system more affordable and reliable.