Is Timeshifting PV’s Post-Incentive Future?

Timeshifting. The ability to store something for consumption at a more convenient time. Great for watching your favourite television shows. Ideal for solar PV, too, but sadly we are not at a stage where solar energy is widely timeshifted via a programmable box. At least, not yet.

Battery manufacturer Saft is actively working towards such a solution. The French firm is participating in a number of projects aimed at merging solar PV with energy storage systems (ESS) from feasibility in the laboratory to feasibility on an industrial scale.

One such project is a Franco-German affair named Sol-ion, which also involves solar PV manufacturer Tenesol, string inverter specialist Voltwerk, German utility E.ON and a number of academic institutions including Zentrum für Sonnenenergie- und Wasserstoff-Forschung (Centre for Solar Energy and Hydrogen Research, ZSW).

The project, which has financial backing from the French and German governments, was initially conceived with the German federal government’s decision to augment its national feed-in tariff regime with a ‘self-consumption’ tariff from 2009. This incentive was axed during the latest amendments to the Renewable Energy Sources Act (EEG), but the timeshifting concept remains pertinent as many nations move towards a ‘post-incentive’ solar world, where exporting power to the grid becomes decreasingly lucrative and self-consumption makes more economic sense.

The project will see the installation of a total 75 solar PV + lithium-ion battery ESS units in France and Germany, which makes it the largest such R&D project in Europe. Ten of the units have already been installed in the various institutes and partners participating in the project, while the remaining 65 will be deployed in individual households. In Germany, they will be mostly installed in the Bavarian town of Schwandorf, where there is a high penetration of solar power. In France, they are mostly going to the islands of Guadeloupe, as well as mainland France.

The Sol-ion systems comprise four of Saft’s Synerion 48E lithium-ion modules, rated at 48 V and with a capacity of 2.2 kWh; a 5 kWp string inverter and a battery converter. The Sol-ion unit’s EMS (energy management system) controls the overall system state and chooses the mode of operation: to use PV for self-consumption, to recharge the battery on each unit, for storage or for export to the grid.

Promising Early Results

The French systems are configured to prioritise backup power, as Guadeloupe suffers from frequent power outages. Only when the batteries are at least 70% fully charged is any solar energy consumed by the household.

The systems deployed in Germany, however, are optimised for self-consumption and are therefore configured to prioritise household loads. Surplus energy is sent to the batteries until fully charged, and only then is any excess power fed to the grid.

Initial test results from one installation at ZSW’s site in Widderstall, Germany, showed a fairly consistent boost in self-consumption of approximately 40% during 11 days of testing in November. On 18 November, for example, solar PV self-consumption with storage was 85%, of which 45% was delayed use. By comparison, the site self-consumed just 45% of solar PV output with an identical set-up minus the ESS on the same day.

These early results are in line with projections, according to Michael Lippert, head of Saft Energy Storage. ‘In our calculations and simulations we expect to shift self-consumption by 30-40% to 70% overall over an entire year,’ he says. ‘This includes what we call natural self-consumption — when production coincides with consumption — which is around 30%.’

Self-consumption will naturally vary in different months of the year. ‘You would probably have 100% self-consumption in January due to shorter days. If you produce just 2 kWh a day in January, most of this will be used.

‘On other days, the capacity of the energy storage system will be inadequate and the battery system will be fully discharged and recharged in a day, while other days may see only a 10% discharge. Over the course of a year, the batteries will cycle at 60% per day on average. This is why we think lithium-ion is the best technology for energy storage batteries, as it can cope with this high variability of discharge.’

Of course, they say the same thing about lithium-ion for electric cars. And even with billions of dollars in government funds, electric cars have struggled to find a market, mostly because of the high cost of lithium-ion batteries.

Lippert says costs will come down once the systems are mass produced. Saft’s recently commissioned manufacturing plant in Jacksonville, Florida will make up to three million cells a year, but it will be some time before the cost will come down to the company’s target price of ‚Ǩ400/kWh for ESS lithium-ion batteries.

Saft is not the only company planning to bring to market time-shifted solar power via lithium-ion batteries. In July, solar PV manufacturer Kyocera began shipping its solar PV + ESS system to households in Japan. The package, which features a 4.03 kW PV array with a 7.2kWh lithium-ion ESS made by Samsung retails for the tidy sum of ¥4,926,000 ($60,825).

Distribution and Investment

Lippert acknowledges that the uptake for ESS from solar PV producers will be limited in the short and medium terms due to the high cost. Furthermore, large scale solar power producers have so far shown little interest in storage, as due to feed-in tariffs (FiTs) they are incentivised to export as much power to the grid as possible.

So while the Sol-ion test results have shown some promise for residential users for self-consumption, the primary takeaway from the project for Lippert is the drastic reduction in power fed into the grid, which on some days fell to zero.

Grid stability is key to the adoption of energy storage for large-scale solar and other renewables, and is the reason why leading power equipment manufacturers are developing their own grid-scale ESS.

GE Goes Big on Storage

Energy storage batteries do not start and end with lithium-ion. GE has placed a large bet on sodium nickel chloride being the winner in the race to provide cost-effective batteries for the global energy storage market, which it estimates could be worth $65 billion by 2020.

The US firm has built the largest non-lead acid battery manufacturing plant in its home nation in Schenectady, New York, to manufacture its Durathon system. GE’s global research centre looked at all the available battery technologies and decided on sodium nickel chloride as the most viable.


Firstly, while lithium-ion has a higher power density, sodium nickel chloride has a higher energy density. For power needs over a longer period, GE decided that sodium nickel chloride is the best bet.

Secondly, sodium nickel chloride is seen as an inherently robust and simple chemical technology. While more expensive than lead-acid batteries, sodium nickel chloride has greater cost-effectiveness on a mass-produced scale than lithium-ion, GE says.

For large solar applications, GE sees a niche for Durathon as a 1 MWh energy storage system with the capability to produce that power between two and four hours a day. Rick Cutright, GE Energy Storage’s director of product management, says: ‘If you go through the trouble of installation, the cost of the breakers, the switchgear and the inverter, then I don’t see too much logic in connecting grid-connected battery systems with a capacity of less than 1 MWh.

‘Two hours capacity gives you a battery storage system of reasonable size with black start, load levelling, uninterruptible power and other functions. With a four-hour capacity you can start thinking about time-shifting.’

To bring down the costs rapidly, GE is focusing very hard on a modular, scalable architecture using the same cells, battery modules and control systems across the range of system sizes that it will install. Cutright states the market for energy battery storage systems starts at $1000/kWh, which GE can achieve, more or less, at present but at $500/kWh the market will really take off.

Eyeing Opportunities

German giant Siemens has so far steered clear of offering commercial energy storage products for renewables. It believes the only way to provide large scale energy storage other than hydropower is by converting renewable energy to hydrogen via an electrolyser. Siemens has begun testing a demonstration unit, housed in a soccer field-sized plant, which uses wind power to split water into hydrogen gas.

The idea is to mix the hydrogen with existing natural gas and pipe it to gas-fired power plants, or store it. Salt caverns used to store Germany’s strategic oil reserves could also provide a storage option for hydrogen gas, the company says.

Lately, however, Siemens seems converted to the lithium-ion cause. This interest has been boosted by Italy’s power grid operator Terna, which plans to develop 130 MW of batteries to store renewable electricity in the next three years.

In February, the German firm installed a lithium-ion ESS, with batteries supplied by a third party, with an output of 1 MVA and capacity of 500 kWh, in Italian utility Enel’s medium voltage distribution network in Rome. Enel will use the ESS to integrate renewable energy and electric vehicle charging stations into its network, as well as to study black start capabilities.

French power equipment manufacturer Alstom believes there is a good business case to install ESS to manage demand in cities which have a shortage of power capacity and where the installation of new cables is problematic and expensive. Laurent Schmitt, vice president of smart grid solutions at Alstom Grid, says an increasing number of distribution network operators (DNOs) and other grid companies are exploring installing ESS at critical grid nodes.

In tandem with national grid operator EDRF and power generation utility EDF, Alstom is currently undertaking a three-year demonstration project in southern France, called NiceGrid, which will integrate residential solar PV in a low voltage microgrid, which features a 1 MW ESS using lithium-ion, Saft-manufactured batteries.

Alstom has examined the size of the grid connected battery storage market and has concluded that it fits well with its current power electronics offerings in its portfolio, such as power converters. Schmitt believes that within 10 years a strong competitor within the sector will be able to install around 100 MW of grid-connected energy storage systems per year.

While Alstom has no intention to build batteries, it is currently in discussion with five strategic partners in the US, Europe and China, all of which are purely battery manufacturers, in order to develop storage products. ‘We plan to offer different technologies at a size of between 1 and 10 MW, or two to eight hours capacity,’ says Schmitt.

‘We believe that both sodium sulphur and lithium-ion have a role to play in the grid, as well as vanadium redox flow in the future. The technology deployed depends if you want to shift demand on a daily basis or whether you want to stabilise power quality at various times of the day.

‘Each grid and each node will require different technologies. We intend to package various battery technologies with our power electronics on a turnkey basis to high and medium voltage grid operators consistent with their specific grid codes.’

However, warns Schmitt, the problem with grid-connected ESS at the moment is that the business model is not clearly defined. ‘Current projects are merely technological demonstrations,’ he said. ‘While solar and wind farms have had an impact on price volatility, at the moment the price spikes are not regular and therefore easy to predict in terms of cash flow.’

Price spikes themselves will not be sufficient to justify their installation, adds Schmitt. Furthermore, additional benefits of such systems, such as power quality improvements, need to have a recognisable revenue stream to be viable.

As much as technological improvements and cost reductions, Schmitt believes the success of grid-connected ESS depends on regulators deciding whether it is the role of regulated grid companies or deregulated generators to be mandated to install them.

‘Like with smart meters, it would be more natural for grid operators to install ESS because the benefits can be shared across the entire grid. However, it would require some recognition that regulated DNOs can be a market participant in intra-day transmission system dispatch, which is normally managed by the market. This is something new.’

Dave Openshaw, head of future networks at regulated DNO UK Power Networks, believes that ESS installed at major power stations to help meet peak demand could avoid expensive investments in network reinforcements such as transformers.

Clearly there are a number of challenges to overcome before ESS are integrated with the grid, not least the cost. But the world’s largest OEMs are backing it. And they can’t all be wrong. Can they?

Tim Probert is a freelance journalist focusing on the energy sector.

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