Independent power producer Neoen Australia said an expansion of the world’s largest lithium-ion battery system has completed its network connection, bringing the Tesla-supported Hornsdale Power Reserve, adjacent to a wind farm in South Australia, to a rated size of 150 MW/193.5 MWh.

It’s the latest in a series of projects being developed worldwide to add energy storage to solar arrays, at wind farms, and even thermal power plants as growth in battery energy storage systems (BESS) continues. The industry is moving forward, even though growth will likely be slowed by the coronavirus pandemic.

“This was expected to be a banner year,” said Kelly Speakes-Backman, CEO of the Energy Storage Association, in an April 17 interview with POWER. “We’re going to see a real hit on that, especially with behind-the-meter projects. People don’t want workers coming to their home, and businesses are closed.”

Speakes-Backman acknowledged the problems that storage and other energy industry sectors are facing from COVID-19, with equipment shortages and supply chain issues, along with a struggling economy, impacting project financing and construction. But she said the pandemic is highlighting some of the issues that make energy storage so important.

“The things that are pushing us forward have to do with resilience and making the grid stronger,” she said. “A lot of people that are going in for solar, are also going in for storage. On the commercial and industrial side, as opposed to a diesel backup generator, now they’re looking at providing for resiliency with storage. We certainly can see the importance of adding resiliency to hospitals and other critical facilities.”

Hornsdale Is Largest, but Not for Long
The Hornsdale project (Figure 1), adjacent to the 315-MW Hornsdale Wind Farm in Jamestown, South Australia (a POWER Top Plant in 2018), is an example of a storage project with several benefits. Neoen Australia reported work on the Hornsdale expansion network connection was completed earlier this month.

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Utility PG&E finalized its contract with a battery project slated to displace a jet-fuel-burning power plant in downtown Oakland, California.

The Oakland Clean Energy Initiative models a pathway for removing decades-old power plants in dense urban settings while keeping the lights on with new lithium-ion batteries. But the project’s collaborative business model also makes it potentially groundbreaking for energy storage development, by formalizing the use of the battery for discrete grid services on behalf of two different clients.

PG&E, which is working to emerge from bankruptcy by the end of June, has experience building batteries and contracting with third parties for the use of their batteries. Battery owners often contract services to an offtaker while playing in merchant markets themselves. But the Oakland project marks a new foray into an owner sharing a front-of-meter battery plant with multiple customers.

Independent power producer Vistra Energy, which owns the 165-megawatt jet-fueled plant in question, signed a deal with PG&E to build a 36.25-megawatt/145-megawatt-hour battery at the existing site in Jack London Square. The facility will provide “local area reliability service,” helping the utility with its job of transmitting power to residents in Oakland. Doing so avoids a far costlier investment, like running new wires over the hills from the Moraga substation.

But those consumers now buy their power from a community-choice aggregator called East Bay Community Energy, a locally administered group dedicated to rapidly scaling up clean energy. EBCE contracted with Vistra last year to use the same battery as a capacity source to fulfill its resource adequacy requirements, which provide power to ride out extreme peak events. The battery originally was going to deliver 20 megawatts/80 megawatt-hours, but the planned capacity has expanded since then.

The double-dipping addresses a structural challenge facing the rise of storage technology on the grid: Batteries can do all sorts of useful things, but it’s often hard to find one customer that needs all of those capabilities. A world that constrained batteries to single uses for single customers would result in redundancy and inefficiency compared to a system where multiple stakeholders use the same equipment for different purposes.

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Among states with established climate change mitigation and carbon reduction goals, one of the first issues addressed is peak energy demand, with New Jersey being no exception to this trend. In this pursuit, the New jersey Board of Public Utilities (BPU) has developed a straw proposal on energy efficiency and peak demand reduction programs.

In short, the proposal looks to reduce statewide energy costs, give all residents access to energy efficiency upgrades and create jobs through programs administered by the state and the state’s utilities.

Yet with these goals laid out, there’s one glaring omission, one that Luis Davila, a consultant with the Distributed Generation Advocacy Coalition claims could set the state back nationally: there’s no mention of the benefits of storage technologies for peak reduction and efficiency in the entire proposal.

“It’s baffling that Jersey hasn’t taken advantage of [storage], even though others have done the analytical studies and have started to implement the non-energy benefits of battery storage – the efficiency benefits.”

Industry responses

Davila is not alone in this opinion, as during the proposal’s comment period, Sunrun issued twofold recommendations, with one calling on the BPU to establish “bring-your-own-device (BYOD) programs that leverage customer sited energy storage assets” as a core peak reduction program offering.

The company went on to outline how Green Mountain Power, Public Service Enterprise Group of Long Island and the state of Massachusetts have all established BYOD programs and how such programs could be used to evaluate New Jersey’s proposed peak demand reduction strategy.

The Energy Storage Association (ESA) also filed comments, focusing on how the state already has an energy storage target of 600 MW by 2021 and 2,000 MW by 2030. With such a goal already laid out and with storage’s proven ability to provide overall system reliability and drive down the peak — the strange exclusion of storage from the straw proposal is magnified.

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Nevada became the sixth state to adopt an energy storage procurement goal on March 12. The Public Utilities Commission of Nevada (PUCN) adopted a regulation in Order No. 44671 that establishes biennial energy storage procurement goals of 100 MW by December 31, 2020, and increasing to 1 GW by 2030. The new regulation is consistent with a 2018 Brattle Group study commissioned by the PUCN that determined a 1 GW level of deployment by 2030 would be cost-effective for Nevada. Nevada utilities will now have to include a plan to meet the biennial storage targets as part of their integrated resource plans and submit progress reports to the PUCN starting in 2022. NV Energy is already on track to meet those targets with the utility’s plans to bring nearly 1.2 GW of new solar energy projects to Nevada and an additional 590 MW of energy storage capacity by 2024.

Nevada became the sixth state to adopt an energy storage procurement goal on March 12. The Public Utilities Commission of Nevada (PUCN) adopted a regulation in Order No. 44671 that establishes biennial energy storage procurement goals of 100 MW by December 31, 2020, and increasing to 1 GW by 2030. The new regulation is consistent with a 2018 Brattle Group study commissioned by the PUCN that determined a 1 GW level of deployment by 2030 would be cost-effective for Nevada. Nevada utilities will now have to include a plan to meet the biennial storage targets as part of their integrated resource plans and submit progress reports to the PUCN starting in 2022. NV Energy is already on track to meet those targets with the utility’s plans to bring nearly 1.2 GW of new solar energy projects to Nevada and an additional 590 MW of energy storage capacity by 2024.

Just a few weeks later, on April 12, Governor Ralph Northam signed the Virginia Clean Economy Act (the Act), which requires Virginia utilities to generate electricity from 100% renewable energy sources by 2045. In furtherance of Virginia’s goal for a carbon-free electric grid by mid-century, the Act sets an ambitious 2.7 GW deployment target for energy storage by 2035. The Act directs the Virginia State Corporation Commission to approve new energy storage projects up to the 2.7 GW capacity target, provided that 35% of the energy storage capacity procured by utilities comes from energy storage facilities owned by nonutility parties.

Procurement targets and mandates for energy storage are emerging rapidly across the country. The current state goals are summarized on our energy storage tracker. Please follow our blog for the latest developments on actions states are taking to deploy energy storage within their borders.

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The US state of Massachusetts has issued an emergency regulation to its Solar Massachusetts Renewable Target (SMART) programme, that includes doubling the PV capacity it seeks to help deploy as well as mandating the addition of energy storage on projects over 500kW.

In a move that national trade body Solar Energy Industries Association (SEIA) said will “help stabilise the solar industry” during the difficult period of the COVID-19 crisis, Massachusetts Governor Charlie Baker and other policy makers announced on 14 April a set of revisions to the existing programme. SMART will now support 3,200MW of new solar generating capacity, instead of 1,600MW, the revised document reads.

Under the SMART programme, solar power system owners in the Commonwealth of Massachusetts receive fixed rate payments for the solar energy they produce based on the kilowatt-hours of power produced. Those agreements last 10 years and vary based on system size, with owners of smaller systems receiving a little more than double what larger systems get, per kilowatt-hour.

Electric distribution company service areas are each set an amount of capacity eligible for awards. This was originally set in proportion to the electrical load served to customers in their services areas in 2016, but the revision now states that the energy department may update that capacity based on updated data as becomes available.

The emergency revision includes various other provisions, including set-asides for at least 5% of available capacity in each awarded ‘capacity block’ to go to low-income community areas. Low-income area projects also receive the highest compensation rates under the programme. Also added were provisions to enable mid-sized and community projects of between 25kW and 500kW, as well as provisions favouring floating solar installations and solar canopies.

Under the SMART programme, an extra ‘energy storage adder’ incentive can be triggered if solar projects – described as Solar Tariff Generation Units for the purposes of the scheme – are co-located with an energy storage system that has a nominal rated power capacity of more than 25% of the solar system. Perhaps most striking of the other revisions is the requirement that Solar Tariff Generation Units >500kW that apply for the SMART incentives now have to be co-located with an energy storage system.

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Europe is sinking billions of dollars into research in an attempt to overturn Asia’s dominance of the battery market, but analysts believe it could be in vain.

Along with various national initiatives, the European Union has put half a billion euros ($550 million) into battery projects within its Horizon 2020 global competitiveness program, which had a total budget of €80 billion ($88 billion) from 2014 to 2020.

And last December the European Commission approved €3.2 billion of state funding under its “important project of common European interest” (IPCEI) rules. The investment will support battery research and innovation across Belgium, Finland, France, Germany, Italy, Poland and Sweden.

The project is scheduled to run until 2031 and is expected to unlock a further €5 billion in private investment. French oil firm Total and German automaker Opel will receive €1.3 billion of public funding on IPCEI terms for a major manufacturing program. It could see as much as 48 gigawatt-hours of capacity added across sites in France and Germany.

“Battery production in Europe is of strategic interest for our economy and society because of its potential in terms of clean mobility and energy, job creation, sustainability and competitiveness,” Margrethe Vestager, the European commissioner for competition, said in a statement.

Given the array of various support programs, “it is difficult to calculate the exact amount of funds currently invested” across Europe, said Doriana Forleo, communications and events manager at the European Association for Storage of Energy. But Bloomberg last July reported that total battery supply-chain investments from European governments, manufacturers, development banks and commercial lenders could top €100 billion.

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