Back in April 2015, Rocky Mountain Institute and partners including Global X and HOMER Energy published a study, The Economics of Load Defection, that examined how grid-connected solar-plus-battery systems will compete with traditional electric service.

The findings showed that declining costs for such systems, combined with retail price hikes for grid electricity, would make grid-connected solar-plus-battery systems economically optimal for customers in many parts of the country by 2030. Furthermore, solar-plus-battery systems can offer other important benefits to customers, such as backup power for critical loads in the event of a grid outage and cost savings via peak-demand shaving and time-of-use shifting. However, at the time, RMI’s study did not detail the exact nature of energy storage costs. 

Figuring out how to compare apples to apples

To break down the installed costs of PV-plus-storage systems today, RMI and NREL first analyzed data across a variety of existing studies from sources including Lazard and GTM, in addition to our own experience in the RMI Innovation Center. 

One challenge to analyzing component costs and system prices for PV-plus-storage installations is choosing an appropriate metric. Unlike standalone PV, energy storage lacks a standard set of widely accepted benchmarking metrics, such as dollars-per-watt of installed capacity or levelized cost of energy. Energy storage costs can vary both by the total energy capacity of the system — expressed in $/kilowatt-hour (kWh) — and the rate at which it charges or discharges — expressed in $/kilowatt (kW).

Some consumers may prefer to optimize their system for longer-duration discharge, while others may have high peak demand and want to optimize their storage solution for power (kW) rather than energy capacity (kWh). Given the diversity of household preferences and load profiles, using a single metric can artificially distort reported costs, making it difficult to compare across varying systems. Therefore, we used the total installed price as our primary metric, rather than using a metric normalized to system size. 

To analyze component costs and system prices for PV-plus-storage installed in the first quarter of 2016, we adapted NREL’s component- and system-level bottom-up cost-modeling approach for standalone PV. Our methodology includes accounting for all component and project-development costs incurred when installing residential systems, and it models the cash purchase price for such systems, excluding the federal Investment Tax Credit (ITC). 

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A distributed energy storage network of 8,000 batteries located at 7,000 telecom facilities in France has reduced utility demand by 10 to 15 MW during two demand response events. And now the company that managed the program wants to bring it to the U.S.

Actility, which provides IoT-based grid balancing and demand response programs, wants to launch its program in the US by partnering with utilities and energy providers in the same way it does in Europe. In addition, it is seeking to work with companies, like France’s Orange Telecom, that have distributed battery networks, said Cedric De Jonghe, the energy business manager for Actility.

Orange Telecom has batteries in the 10- to 20-kW size range at 7,000 locations in France, and was one of Actility’s first partners, “lending” the batteries–and getting paid for it–during critical peak periods on the grid system. Actility aggregated the batteries to respond to the high peak periods.

“In 2017 we have experienced two activations thus far during moments when the electricity grid in France was facing a critical situation,” said De Jonghe.

Actility in 2010 began offering demand response services and started searching for ways to implement non-traditional demand response programs, De Jonghe said.

“We were looking for flexibility in highly distributed sources” in industries such as the telecom industry, he said. It launched its green demand response program in 2016.

In its first green demand-response project, Actility partnered with Orange, in addition to RTE, the largest Transmission System Operator (TSO) in Europe, and Enedis, the largest French Distribution System Operator, to create a “clean demand response” program that responds to spikes in energy demand.

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Speakers from 22 countries will be gathering at the 10th Energy Storage World Forum and the 4th Residential Energy Storage in Berlin May 8th-12th at a critical point for the industry. Tesla’s recent pledge to build a 100MWh battery plant in Australia within 100 days, or give it away for free, has put the industry under unprecedented pressure to deliver on its promises. Tesla energy division boss Lyndon Rive offered to install between 100MWh and 300MWh of battery capacity at breakneck speed in South Australia when he introduced Tesla’s new Powerwall and Powerpack systems in March.

The seemingly throwaway comment was picked up in local news reports and prompted Australian software tycoon Mike Cannon-Brookes to reach out to Tesla CEO Elon Musk over whether the offer was for real. Musk said it was, and added the Australians wouldn’t have to pay for the system if Tesla failed to deliver it within 100 days of a contract. The exchange led to a flurry of calls between Musk and Australian dignitaries, up to Prime Minister Malcolm Turnbull, as well as requests for similar projects elsewhere, including one from Ukraine’s leader, Volodymyr Groysman. Under pressure from other storage players, including some based in Australia, the South Australian administration put the proposal for a 100MWh plant out to tender. At the time of writing, around 90 companies from 10 countries had lined up to match Tesla’s vow of achieving a cost of $250 per kilowatt hour for the project (it is unclear whether the Tesla price is in US or Australian dollars).

What happens next is likely to be the biggest test for energy storage since Tesla proved it could deliver residential batteries for less than USD$5,000. Typically for Musk, the spotlight is once again on his company above all others. But the apparent publicity stunt that Tesla staged in Australia is starting to look like a crucial turning point for the industry worldwide. It has pushed already soaring expectations about energy storage to new heights. “Tesla’s interest and enthusiasm in this goes beyond just the Australian market. It is proving a concept and providing a solution,” said Gero Farrugio, managing director of Sustainable Energy Research Analytics, in a Reuters report. Whichever company ultimately wins the South Australian tender will have to provide a record-breaking battery system in record-breaking time, for a rock-bottom price.

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40MWh (megawatt hours) of battery systems will soon be installed at 27 Walmart stores across Southern California.

Advanced Microgrid Solutions (AMS) has announced it will design, install and operate its Hybrid Electric Building systems for the company. AMS says these will improve energy efficiency, guarantee the retailer electricity savings and provide grid services to local utilities.

The addition of energy storage will also help Walmart further boost its green credentials.

Walmart is listed on the US EPA Green Power Partnership National Top 100. Based on the latest figures (February), its annual green power usage is 826,343,726 kilowatt-hours.

The company has set a goal of powering 50% of its operations with renewables by 2025 (currently 4% according to the EPA) and is a member of the RE100; a group of large firms that have committed to 100% renewables.

To date, Walmart has made significant inroads with on-site generation, including solar power systems installed at 350 of its stores.

“Adding energy storage capabilities to our clean energy resources reduces the capacity needed from the grid and is part of our commitment to increase reliance on renewable energy,” said Mark Vanderhelm, vice president, Energy for Walmart.

It sounds like a pretty sweet deal all round for Walmart, which won’t have to outlay any capital for the batteries and will also be receiving revenue from providing grid services.

Reducing peak electricity demand is becoming a more pressing issue for companies around the world, including Australia, with commercial demand charges on the increase here – and residential demand tariffs are also appearing.

A demand charge is one applied based on the highest electricity demand recorded during a certain timeframe in a specified period.

For example, a business may have a low load throughout an average day except for a brief period where it spikes due to whatever activity is taking place at the time. The demand charge may be based on that brief load spike – and the bigger the load, the higher the cost. To make matters worse, the daily charge may be applied at this level over a full quarter or even a year.

Demand charges can make up a significant percentage of a commercial electricity customer’s bill and really eat into a company’s bottom line.

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Power management company Eaton today announced a contract with Powin Energy to deliver a 2-megawatt energy storage project in the Los Angeles Basin to support regional electric capacity and grid reliability. The project is part of the Southern California Edison 2016 Aliso Canyon Energy Storage Resources Adequacy (RA) Only solicitation, which procured fast-responding energy storage resources. Eaton is the single source provider for the energy storage inverter and balance of system equipment.

“Powin Energy and Eaton worked together to help expedite and simplify the deployment of a dynamic energy storage system,” said Danny Lu, Vice President of sales and marketing at Powin Energy. “The solution combines Powin’s Stack140 energy storage system that includes our proprietary bp-OS software with Eaton’s Power Xpert storage inverter. Plus, Eaton’s electrical solutions, with real-time communications and diagnostics help reduce operation and maintenance costs while enhancing system responsiveness.”

Under the contract with Powin Energy, Eaton provided a utility-scale energy storage inverter, transformer, grid interface switchgear, low-voltage switchboard, B-Line^® series cable tray and commissioning services. The project will incorporate a 2,000-kilowatt (kW) Eaton Power Xpert^® energy storage inverter, which provides some of the highest power ratings for grid-tied, utility-scale storage projects and an 8,000-kilowatt hour (kWh) Powin Battery Energy Storage System. Eaton’s Power Xpert energy storage inverters and transformers are assembled in the U.S. Eaton’s Western U.S. regional manufacturing facilities and local technical support services are helping expedite the power distribution solutions.

“The energy storage projects in Southern California are a key part of a broader initiative that will help develop next generation energy infrastructure to enhance grid reliability and stability across the entire L.A. Basin,” said Chris Thompson, grid power business unit manager, Eaton. “With a fast-tracked timeline, the energy storage system deployed by Powin Energy and Eaton demonstrates how quickly such systems can be brought online to address our energy challenges.”

Eaton is leveraging more than 100 years of experience and expertise in utility and industrial environments to bring to market its Power Xpert energy storage utility-scale inverters. The inverters are part of Eaton’s portfolio of energy storage solutions and services, which also include: AC switching and protection, customized packaging, metering, monitoring and control systems. For more information, visit www.eaton.com/energystorage.

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Maryland on April 10 became the first state in the nation to pass legislation enacting a tax credit for residential and commercial energy storage installations.

The measure passed unanimously in the state Senate, and with a 101–11 vote in the House. Gov. Larry Hogan (R) is expected to sign SB 758 into law.

The bill offers up to $5,000 for residential installations, $150,000 for commercial installations, or 30% of the total cost of installations. Credits can only be claimed for systems installed between January 2018 and December 2022. The tax credit applies to all energy storage technologies.

Earlier this week, Maryland also passed HB 773, which calls for an energy storage technology study to determine how Maryland can use energy storage to open the path to a more reliable electric system.

According to the Energy Storage Association, in 2016, commercial deployment of energy storage systems grew more than 100% over the previous year and installed system costs plummeted another 30%.

A series of states have recently implemented measures that will boost energy storage installations. California, which enacted a mandate in 2014, requires utilities to procure 1,325 MW of energy storage by 2020. Oregon’s Public Utility Commission earlier this year issued guidelines under the 2015-enacted HB 2193, a law that requires Oregon utilities Portland General Electric and PacifiCorp to have a minimum of 5 MWh of energy storage in service by January 2020.

Massachusetts, in August 2016, meanwhile, became the third U.S. state to enact an energy storage mandate, though the exact volume that must be procured by January 2020 won’t be decided by the state Department of Energy Resources until this summer.

New York City in September 2016 unveiled the first citywide mandate, aiming for an energy storage goal of 100 MWh by 2020. Hawaii, which recently passed a 100% by 2045 renewable energy mandate, saw its state legislature introduce bills on energy storage tax credits and infrastructure loans.

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Energiewende (energy transition). That’s the name of the German government’s ambitious goal to transform their energy landscape over the next few decades. By 2025, they want 35-40% of their electricity to come from renewable energy sources. By 2035, they’re targeting 55-60%. And by 2050, they hope to hit at least 80% renewable energy, coupled with an overall reduction in energy consumption of 25% (compared to 2008).

To get anywhere near this goal requires a huge investment in wind and solar energy generation, as well as a step up in their use of biomass and hydropower, and improving the overall efficiency of natural gas power plants. So far, signs are good, at least in terms of their energy mix. In 2015, renewable energy made up 32.5% of Germany’s total electricity demand.  On one day in 2016, renewable technologies generated 55 GW of energy – that was 87% of Germany’s electricity demand on that day. As reported in Quartz at the time, there was so much electricity available, “Power prices actually went negative for several hours, meaning commercial customers were being paid to consume electricity.”

Alongside the environmental argument for renewables, there are also economic reasons a region might want to move away from coal and oil. A 2015 report from Bloomberg New Energy Finance showed that in Germany, coal and gas were more expensive than onshore wind – $106 and $118 versus $80/MWh – and the same was true in the UK. In China, coal was still cheap in 2015, coming in at just $44/MWh. But solar power there was cheaper than gas ($109 versus $113/MWh). With China now taking a leading role in the fight against climate change, the prices of renewables are likely to drop further.

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The results of the National Grid’s Enhanced Frequency Response (EFR) tender published in August 2016 have come to be seen as something of a pivotal moment for the fortunes of energy storage in the UK – especially for battery technology.

The statistics will be familiar to many: 61 of the 64 EFR bids related to the use of battery storage, offering over 4311MW of capacity, and battery solutions dominated the 200MW of capacity accepted by theNational Grid. “Battery storage” and “energy storage” are used increasingly interchangeably.

One successful bidder (and the only bidder to be awarded two EFR contracts) was Low Carbon, which was awarded contracts for 50MW of capacity. On 1 March 2017, Low Carbon announced that it was forming a joint venture – VLC Energy – to exploit the commercial opportunity presented by EFR contracts.

The announcement catches the eye because Low Carbon’s joint venture partner, VPI Immingham, is owned by the oil trading giant Vitol group. In addition to battery storage dominating the EFR tender and commercially “coming of age”, was this also the moment when the business case of a “green and clean” project became commercially viable without Government subsidy?

Of course, Vitol is not alone when it comes to oil companies investing in renewables. Statoil, Royal Dutch Shell, Total and Aramco each announced the making of investments in the renewable energy market in 2016. Total is reported to have acquired a 90% stake in battery designer Safte Group, building on earlier acquisitions in the solar sub-sector.

These investments are significant, but represent only 2% of net operating income for Statoil, Royal Dutch Shell and Total. Aramco’s CEO said recently that oil and gas will continue to play a significant role in the future energy mix for decades to come. Oil remains the staple product of core business of these energy giants.

The investments in batteries and battery projects do however demonstrate that project sponsors are developing business cases which are credible investments in their own right, or at least worthy of early adopter speculative investment. Evidence of early adopter behaviour is positive as it suggests there is optimism that there will be a market in the near to medium term.

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In a famous children’s fable, a stuffed rabbit becomes real when its owner believes in it.

The nation’s utilities may now be similarly transforming battery energy storage.

The U.S. utility-scale battery storage installed capacity grew by another 221 MW in 2016 as costs continued to drop, according to a recent report from GTM Research and the Energy Storage Association.

More importantly, the sector last year doubled the amount of megawatt-hours (MWh) of battery capacity deployed compared to 2015.

This, analysts say, shows growth in the use of long-duration batteries and an increased confidence that the large energy storage facilities can be used to help manage peak demand.

“Growth remains steady, but 2016 was a turning point because the PJM frequency regulation market faded while demand for 4-hour duration storage capacity grew,” said report co-author Dan Finn-Foley, a GTM Research senior energy storage analyst.

The longer duration capacity growth was largely from California battery storage projects, Finn-Foley said. They were brought online in 2016 to address power grid needs created by the shutdown of the Aliso Canyon natural gas storage facility due to a methane leak in 2015.

Those batteries were rushed online to provide peak demand electricity that local power plants could not supply without natural gas from the Aliso Canyon facility. They represented 60 MW of the 221 MW added last year, but accounted for 168 MWh of the total 336 MWh deployed in 2016, according to Finn-Foley.

“With a 4-hour duration battery, a 20 MW energy storage system can deliver 80 MWh of capacity to meet a peak demand spike,” he said.

The fast deployment of those California grid-scale batteries — all sited, constructed and put into operation in nine months — has a number of analysts and sector insiders touting 2016 as a “turning point” for energy storage. But other say the true storage revelation is yet to occur as utilities discover how to better capture the multiple values of storage.

“The watershed event for energy storage will be when we can unlock multiple value streams from batteries,” said Stuart Laval, director of technology development at Duke Energy.

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