What does the PV glut mean for energy storage?

Solar panel pricing is at an all-time low due to overcapacity in the market. Image: SunPower.

Solar panel pricing is at an all-time low due to overcapacity in the market. Image: SunPower.

By Jason Deign

Present forecasts of PV-and-battery adoption could end up significantly underestimating true adoption levels by not taking into account a massive glut in solar capacity.

Josefin Berg, senior analyst for solar demand at IHS Technology, told Energy Storage Report there are currently “several gigawatts’” worth of new solar panels worldwide that nobody wants to buy because of excess supply.

IHS alerted to the potential for manufacturing overcapacity in the PV market back in June, and has forecast there will be a shakeout among what few manufacturers are still left from previous oversupply and consolidation periods.

For now, however, as EnergyTrend noted: “Prices across the PV supply chain have collapsed to new lows in the second half of 2016 due to plunging demand.”

What will happen to the excess PV capacity currently sitting on the shelf is unclear, but in Australia CleanTechnica earlier this month predicted it would lead to a “big solar boom.” 

Tripling utility-scale PV

The forecast came just days before the Australian Renewable Energy Agency announced 12 new large-scale PV plants, tripling the country’s utility-scale PV capacity overnight.

Meanwhile RenewEconomy reported on Curtin University research indicating that solar plus storage could become cheaper than Australian grid suppliers as soon as next year. Could the same happen elsewhere?

It seems eminently plausible if PV panels are being sold at cost or less.

Whether the customer is a large-scale PV project developer or an environmentally conscious homeowner, being able to buy high-quality panels for next to nothing will not only help cut the cost of energy but also free up cash.

For large-scale plant developers, cutting the cost of energy may be all that is needed, particularly in highly competitive markets such as Chile or Dubai. 

Adding battery storage

In many other instances, however, a significant cut in the budgeted cost of solar panels might allow the asset owner to consider adding battery storage into the equation.

The storage option is even more attractive given the fact that battery costs are plummeting, too.

Earlier this month Tesla, which already has one of the cheapest battery systems on the market, cut the price of its commercial and utility-scale Powerpack product by 5%.

There are reasons to suspect the main impact of record-low PV prices will be in the distributed energy market, though.

This is partly because utility-scale developers tend to be pickier about their modules, since they need to be sure they can maximise the profitability of a project over its full lifespan. 

Residential solar market

Hence they may still be willing to pay a slight premium for higher-quality PV panels, leaving the very cheapest products to find their way onto the residential solar market, where customers might not be quite as choosy.

An unexpected boost to residential solar generation could add impetus to a growing trend for distributed storage, highlighted by Bloomberg earlier this month.

And the distributed storage market is likely to be further helped by an increasing influx of cheap second-life batteries from electric vehicles, although admittedly this is not expected to happen for a couple of years.

Taken together, though, the price reductions that could come about from today’s PV oversupply plus ongoing cuts in the cost of batteries seem increasingly likely to remove financial barriers to solar-plus-storage adoption.

Any faster-than-expected reductions in solar-plus-storage pricing could put pressure on regulators. 

Legislation is still challenging

Although some markets (most notably Germany) have put in place support mechanisms for solar-and-battery adoption, in many places the legislation around distributed energy storage is still challenging.

Legislators may want to keep it that way since, as the Curtin University research makes clear, once solar plus storage costs fall far enough below the cost of grid power there is a real risk of users cutting their utility bills to a bare minimum.

The Curtin University researchers estimate this could slash AUD$100m off annual utility revenues in West Australia alone, effectively reducing the funds available to maintain the grid.

However, it is difficult to see how obstructive regulation could benefit energy markets in the long run, particularly if there is a need to increase renewable penetration as part of carbon reduction efforts.

Thus regulators will need to think carefully about how they adjust legislation to cope with increasingly decentralised energy production and storage, while at the same time safeguarding the grid. And they may not have much time to do it.

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Could the grid stymie India’s storage plans?

Pumped hydro might not be the best option for long-term storage in India (pic: animam.photography).

Pumped hydro might not be the best option for long-term storage in India (pic: animam.photography).

 

By Jason Deign

Doubts over the strength of the grid have called into question a USD$17.2bn plan to build 10GW of pumped hydro storage in India.

Central Electricity Authority chairman SD Dubey unveiled the five-to-six-year pumped hydro programme last month.

The administration would be adopting pumped hydro to store excess power from India’s growing renewable energy sector because the storage medium is cheaper than batteries, he said.

But being able to store energy in pumped hydro reserves depends upon getting it to the dams in the first place.

And observers have questioned whether India’s grid is up to the task, particularly since it is already groaning under the impact of solar energy. 

Curtailing solar power

Last week, for instance, reports surfaced of the Tamil Nadu Generation and Distribution Corporation (Tangedco) curtailing solar power because the grid could not cope.

“The Tamil Nadu Electricity Regulatory Commission has asked the Tamil Nadu Generation and Distribution Corporation to technically justify why it asks solar power plants to back down from the grid,” The Hindu Business Line reported.

“Tangedco argued that it had only asked solar plants to back down when grid stability was affected,” said the report.

“Recently, the Solar Power Developers Association had also written to the MNRE [Ministry of New and Renewable Energy] and Tangedco expressing concern over 50-100% ‘generation curtailment’ during peak generation periods.”

The weakness of India’s grid could end up being a powerful argument for installing distributed battery storage instead of relying on large pumped hydro projects, said a respected Indian energy analyst.

“Pumped storage will be idling”

“For pumped storage, the power generated from solar plants has to be first evacuated to the grid, after which it can be converted to hydraulic head,” said Madhavan Nampoothiri, founder and director of RESolve Energy Consultants.

“In a country like India, where the ‘backing down’ happens because the grid infrastructure is not sufficient, pumped storage will be idling since this solar power is getting wasted and not reaching the grid in the first place.”

In contrast, he noted: “Battery storage can be sited within the solar power plant. In case of in-situ storage, the power can be stored in the battery during peak hours, and gradually evacuated when the grid can handle it.

“In this sense, battery storage has a distinct advantage over pumped storage, as long as evacuation constraints remain.”

Pumped hydro has several other apparent disadvantages compared to batteries. The first is that it is highly location-specific. 

Suited to the mountainous northeast

From a purely geographical perspective it would seem pumped hydro would be most suited to the mountainous northeast of the country.

This would potentially put it some distance away from India’s top solar and wind resource areas in the west and south, exacerbating the stress on the national grid.

Such distances could also lead to major transmission losses, reducing round-trip efficiency.

Even assuming a solid grid and relatively low transmission losses, however, the fact remains that the capital costs for pumped hydro are currently about as low as they will get, while batteries are predicted to get significantly cheaper.

In particular, the second-life battery effect is expected to slash the cost of lithium-ion batteries significantly in the next three or four years. And India has the world’s biggest lithium-ion battery right on its doorstep, in China. 

Cheap second-life batteries

Given the scale of lithium-ion production in China it is entirely likely the Indian market could soon be swamped with cheap second-life batteries from its northern neighbour.

How far second-life products could eventually decrease the cost of batteries remains to be seen, of course.

However, it is possible that in a couple of years battery costs in India could reach a level that makes solar-plus-storage a option not just for plant owners wanting to avoid curtailment but also for industrial and commercial-scale users.

If this happens, batteries could easily pull ahead of pumped hydro as a large-scale storage medium since the planning, permitting and construction process for battery plants is potentially much easier than that for reservoirs and pipes.

Given this mid-term outlook, there are good reasons to suspect that India’s big plans for pumped hydro could end up joining a list of other major development programmes the country has failed to bring to fruition.

The main difference between this and grand schemes such as India’s national broadband rollout is that if it fails then at least there might be an alternative that allows the country to still enjoy the benefits.

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Study: distributed storage is going to take over

Residential solar could become energy storage's heartland in a few years, according to research from Bloomberg New Energy Finance. Pic: SunPower.

Residential solar could become energy storage’s heartland in a few years, according to research from Bloomberg New Energy Finance. Pic: SunPower.

By Jason Deign

A major study published last week not only forecasts massive energy storage growth but also predicts a seismic shift in the structure of the market.

The Global Energy Storage Forecast, 2016-24, from Bloomberg New Energy Finance (BNEF), predicts about 45GW and 81GWh of storage could be installed by 2024, representing an investment of USD$44bn.

The figure excludes pumped hydro capacity, of which there is currently 104GW according to 2012 US Energy Information Administration data cited by the American Energy Storage Association.

Perhaps more importantly, though, the Forecast shows worldwide behind-the-meter storage overtaking utility-scale applications between 2020 and 2021.

By 2024, predicts BNEF, 66% of all storage will be behind the meter, compared to just 16% at present.

This estimate may prove conservative

Energy Storage Report can reveal that even this estimate may prove to be highly conservative since the Forecast does not take account of the impact of second-life batteries likely to flood the market from 2020 onwards.

The second-life effect, which could reduce lithium-ion battery costs to as little as $49 per kWh in a couple of years, was only uncovered in a separate BNEF study a fortnight ago.

Forecast author Logan Goldie-Scot told Energy Storage Report that this factor had not been incorporated into his global market sizing calculations and would be included in a second phase of the research.

Second-life batteries could further skew energy storage market dynamics to behind-the-meter applications.

Colin McKerracher, manager for advanced transport insight at BNEF, said “behind the meter is the most promising application” for second-life batteries, “so residential will play a big role.”

A clear swing towards behind-the-meter storage

Even without taking into account the multiplier effect that second-life batteries could have, a clear swing towards behind-the-meter storage within the next half decade could carry profound implications.

The first and most obvious one is that future energy markets would seem increasingly unlikely to resemble those currently seeing a boom in grid-scale storage, such as California or the UK.

And they are even less likely to look like markets where the legacy energy model still prevails, which equates to most of the world.

Instead, a mere five years from now an increasing number of electricity markets will start to take after Germany and Australia, where a growing proportion of power customers are partially or totally disengaging from the grid.

The Forecast makes it clear that the move to behind the meter is all about energy independence.

“64% of all commissioned capacity in 2024”

“Behind-the-meter PV plus storage goes from being a niche application in 2016 to making up 64% of all commissioned capacity in 2024,” it says.

This trend threatens the energy sector status quo. Utilities could face a powerful new competitor in the shape of customers’ ability to service their own energy needs. And dealing with this competition might not be easy.

Consumer buying habits are hard to predict because they are only partly based on price.

In many parts of Australia and Germany, for example, the business case for residential PV and storage is still marginal at best, but that has not deterred homeowners from installing systems for a range of other reasons.

Hence utilities may find it hard to predict with certainty if and when a stampede towards solar plus storage might hit the market. Nevertheless, how they deal with the situation could be important for their future success.

Distributed generation with storage

In Spain, for instance, the major utilities have earned the contempt of many consumers by seeming to have a guiding role in national laws clamping down on distributed generation with storage.

But in Germany and Australia, a handful of far-sighted utilities such as E.ON and AGL Energy are attempting to head off the grid defection trend by providing solar-plus-storage systems of their own.

This seems like a smart move, potentially allowing the utility to maintain its customer relationships and deliver other value-added services down the line.

Maintaining that customer relationship could emerge as a critical task for utilities since one of the big problems with partially disconnected customers is that their grid requirements will be difficult to predict and control.

For the sake of grid stability, most utilities and network operators would want to have a say in how behind-the-meter storage assets are used, ideally for example aggregating them to form virtual power plants.

Storing excess solar energy for customers

Some could even go as far as MVV Energie in Germany, and create a grid-scale battery plant to store excess solar energy for residential customers. And it is not just utilities that could be affected by the behind-the-meter trend.

If the future of energy storage lies in homes and commercial or industrial installations, rather than on the grid, then that calls into question the prospects for a host of current start-ups commercialising grid-scale battery products.

“There will be swathes of lithium-ion batteries deployed,” said Goldie-Scot. “The challenge for alternative technologies is how do you compete with the large lithium-ion manufacturers if you can’t compete on scale.”

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The second-life threat to non-lithium batteries

Second-hand batteries from electric vehicles such as buses could drastically cut the price of lithium-ion-based storage, research predicts. Photo: www.animam.photography

Second-hand batteries from electric vehicles such as buses could drastically cut the price of lithium-ion-based storage, research predicts. Photo: www.animam.photography

By Jason Deign

Lithium-ion’s potential to dominate the stationary storage battery sector may be stronger than previously thought, according to the implications of a new study.

Research published last week by the analyst firm Bloomberg New Energy Finance (BNEF) shows a glut of second-hand lithium-ion (Li-ion) batteries from the auto industry could cut battery storage costs significantly.

By 2018, says Used EV batteries for stationary storage: second-life supply & costs, the cost of repurposing batteries for second-life applications could go down to as little as USD$49 per kWh.

This compares to a cost of roughly $300 per kWh for new batteries at the moment, and $160 for lowest-cost battery chemistries such as the zinc hybrid cathode technology being commercialised by Eos Energy Storage.

Given that BNEF expects around 10GWh of capacity from used electric vehicle batteries to be entering into the stationary storage market by 2025, second-life applications could deal a real blow to the prospects for non-Li-ion chemistries.

“This does move the goalposts”

“This does move the goalposts for what an energy storage technology will have to compete with,” admitted Colin McKerracher, manager for advanced transport insight at BNEF.

“The sheer scale of manufacturing puts [Li-ion] pretty far ahead for quite a while. We believe it will significantly lower the average cost of stationary storage projects.”

Currently, BNEF estimates repurposing second-hand batteries costs about $100 per kWh, or a third of the cost of new batteries. This cost will roughly halve in the next two years due to economies of scale and improved learning.

Present second-life volumes are low, however, and will remain so until a significant number of electric vehicles are on the road with batteries that need replacing.

Nevertheless, between now and 2015 BNEF forecasts 95GWh of storage capacity will come out of the electric vehicle market. That is 60 times the world’s current installed electrical energy storage capacity, McKerracher said.

Volumes affecting price by 2020

“Around 2020 we do expect volumes to come on and affect the price of batteries going into stationary storage,” he said.

Ultimately up to around a third of all used electric vehicle batteries could end up being used for stationary storage, BNEF predicts.

Just how significantly this cut-price capacity might affect the dynamics of the stationary storage industry will depend on a number of factors.

The first is that the price reductions will only apply to batteries, which themselves are only a part of total energy storage system costs.

This means technology developments in other areas, such as inverters, could also have a similar or greater impact in overall system costs.

Acceptance of second-life batteries

All other things being equal, though, second-life batteries would still contribute to significant price reductions. Potentially more important is what kind of acceptance second-life batteries will have in the market.

This depends not just on cost but also on factors such as performance and warranties. On performance, said McKerracher, the current generation of electric vehicle batteries is exceeding expectations.

“So far batteries have held up well, with reduced degradation,” he said. “Most of what we are forecasting is reduced capacity, not catastrophic failure.”

Regarding warranties, it is still too soon to tell what kind of guarantees manufacturers will offer on second-life batteries.

However, McKerracher hinted that carmakers would most likely play it safe in order to avoid problems with products carrying their brands. This could mean some manufacturers might shy away from repurposing.

Tesla, for example, is most likely to prefer recycling batteries to feed demand for new Powerwalls. A number of other car firms, though, seem more committed to going down the second-life route.

The price of new batteries 

None of this would seem a major barrier to second-life battery adoption in stationary energy storage. The one thing that could ultimately stymie the second-life market, though, is the price of new batteries.

Beyond around 2022, it is possible that reductions in the price of new batteries might wipe out the cost advantage of using second-life units. But there is a great deal of uncertainty over exactly when that might happen, BNEF notes.

And the decision over whether used batteries should be repurposed for second-life applications or recycled into new units may depend on the evolution of commodity prices for materials such as cobalt and lithium.

“If commodity prices do not rise, recycling would remain a cost for battery owners and the second-life market could grow significantly, with repurposers being paid to take batteries,” said the BNEF report.

For now, though, “the second-life industry must establish itself soon before new battery prices drop even lower and begin to compete,” said BNEF.

Most auto companies are indeed taking an active interest in second-life applications. “In the last six months there have been a lot of announcements,” McKerracher said. “I expect we will see a lot more of that.”

Also in this week’s newsletter headlines: National Grid, Origin Energy, Fraunhofer Institute and more. Get your free copy now.

 

The nuclear plant powering debate over storage

Artist's view of the Hinkley Point C nuclear plant. Image: EDF Energy.

Artist’s view of the Hinkley Point C nuclear plant. Image: EDF Energy.

By Jason Deign

A surprise U-turn over a UK nuclear power plant has ignited debate over whether renewables, backed by storage, might not be a better alternative.

Last month the UK’s new, post-Brexit administration raised eyebrows after announcing a further review of Hinkley Point C, a controversial nuclear power plant that was supposed to have been given the final go-ahead on July 29.

UK officials rushed to issue assurances after the postponement threatened to spark tensions with China and France, the international partners in the GBP£18bn project.

“The UK needs a reliable and secure energy supply and the government believes that nuclear energy is an important part of the mix,” soothed Greg Clark, business, energy and industrial strategy secretary, in press reports.

The government said it would now make its final decision “in early autumn,” he said.

A backtrack on the nuclear commitment?

It is unclear whether the setback is an indication that the UK government, now led by Theresa May, intends to backtrack on the nuclear commitment made by the previous administration.

Although May is said to be less enthusiastic about the project than her predecessor and French partner EDF Energy has wobbled over the benefits of moving forward with the plant, a final ‘no’ could sour trade relations with China.

It would also nix prospects for the creation of 25,000 jobs and £100m a year for the regional economy of South West England, which lags significantly behind that of the UK.

However, the delay in moving forward with the plans has heightened debate over the cost of the project… and whether renewables with storage might not be a better option in the long term.

Hinkley Point C was originally set to benefit from a contract for difference guaranteeing £92.50 per MWh of energy produced.

Wind and solar to be cheaper

But the UK government itself expects wind and solar power to be cheaper than this by the time the plant is built, coming in at around £50 to £75 per MWh.

Meanwhile Bloomberg New Energy Finance has calculated that “Britain could scrap the … nuclear power plant at Hinkley Point and get the same amount of electricity from offshore wind turbines for roughly the same investment.”

The analyst firm’s calculations predict the nuclear reactor’s price tag could buy 5.7GW of offshore wind, almost twice the generating capacity of Hinkley Point C, which would provide roughly the same output a year.

Getting the same output from onshore wind, a more mature renewable technology, would be much cheaper.

Bloomberg said: “The … assessment includes only the capital cost of erecting various forms of generation, not operating expenses or the price of fuel.

Sidestepping the question of storage

“It also sidesteps the question of what would have to be invested to create storage at a giant scale capable of smoothing out power delivered from renewables when the sun isn’t shining and the wind isn’t blowing.”

But an opinion piece in influential business daily The Telegraph this month pooh-poohed the idea that storage costs might be a barrier to renewables integration on the UK grid.

“Research into cheap and clean forms of electricity storage is moving so fast that we may never again need to build 20th Century power plants in this country, let alone a nuclear white elephant such as Hinkley Point,” it said.

Other observers have expressed similar views.

Writing in Energy Post, University of Exeter MSc Energy Policy course director Bridget Woodman said the Hinkley Point C decision delay was an opportunity to re-think UK energy policy.

Measures to encourage renewable systems

“Now is the time to start considering … measures to encourage more flexible, smaller-scale, renewable systems incorporating demand-side measures and new technologies such as storage,” she said.

The debate has profound implications for the future of energy storage in the UK and elsewhere.

While Hinkley Point C has attracted significant criticism because of its potential cost to the public, energy storage has never benefited from subsidies in the UK and support for renewables generally is rapidly being phased out.

If it can be shown that renewables and storage can deliver large-scale, base-load generation at a cost that beats nuclear, then there could be serious doubts about whether new reactors will ever be built.

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Azores project key for island microgrid credibility

Gorona del Viento: poor performance means other island microgrids are under scrutiny. Photo: www.animam.photography.

Gorona del Viento: poor performance means other island storage projects are under scrutiny. Photo: www.animam.photography.

By Jason Deign

A project on Graciosa, Azores, has become key for the credibility of island-based storage following concerns over another plant more than 1,500km away.

The Younicos project on Graciosa is set to go live within weeks amid speculation that another attempt to power an island off renewables, in El Hierro, Canary Islands, has failed to meet expectations.

El Hierro’s Gorona del Viento plant, which combines an 11.5MW wind farm with a pumped hydro storage system, was launched with much fanfare in 2014. Its initial aim was to replace 80% of diesel generation needed for the island grid.

Last month, the plant operator revealed the EUR€82m Gorona del Viento had allowed El Hierro to run continuously off nothing but renewable energy for 55 hours.

And last week Gorona del Viento said the plant supplied 67% of the island’s power throughout July and had set a new record of 76 hours with 100% renewable production.

Covering between 70% and 80% of demand

“The hydroelectric plant is a system that can cover between 70% and 80% of El Hierro’s annual electricity demand,” said Gorona del Viento’s CEO, Juan Pedro Sánchez, in a press note.

Some observers dispute this claim, however. Two years ago, engineers linked to the project warned it would never be able to cover more than 55% of island electricity demand.

And Hubert Flocard, named as an ex-director at the Nuclear Physics Institute of the French National Scientific Research Centre (Centre National de la Recherche Scientifique), recently called the project “a technical semi-failure.”

Based on data from last year, he said: “The renewable fraction for the three most favourable months, July to September, has been 42%. For the half year, the figure is even more disappointing, with only 30% renewables.”

The figures meant Gorona del Viento’s energy production was costing several times more than the diesel it replaced, he said.

Limited wind resource

As well as “limited wind resource, which according to data could not have allowed a renewable fraction larger than 50%,” Flocard said the plant’s government contract could stop it from optimising environmental performance.

Overall, Flocard predicted Gorona del Viento would only be able to cover 46% of El Hierro’s electricity demand.

The respected blog Energy Matters, which Flocard is a collaborator on, has echoed this research with regular updates on Gorona del Viento and an ongoing analysis of data from network operator Red Eléctrica de España.

In July, Energy Matters contributor Roger Andrews called Gorona del Viento a “failed project” after reviewing the first full year’s worth of operational data on the plant.

The whole project was based around a volcanic crater “which it was believed would provide enough energy storage when filled with water and linked to a lower reservoir to smooth out fluctuations in wind generation,” he said.

“No one bothered to do the sums”

“Unfortunately no one bothered to do the sums and check the wind records,” he surmised.

“Had they done so they would have found that the storage was adequate to fill El Hierro’s demand for only about two windless days and that low-wind periods on El Hierro can last for months.”

Gorona del Viento is not known to have responded to the research carried out by Flocard or Energy Matters. Nor did the company respond to a request for further information from Energy Storage Report.

However, for Rogers, who has also questioned the economics of the Eigg island microgrid project in Scotland, the results of the Gorona del Viento project are a damning indictment of renewable energy’s potential overall.

“Intermittent renewable energy is not going to replace dispatchable fossil fuel generation without adequate energy storage backup,” he said.

A prohibitive amount of energy storage

“And since the amount of energy storage needed is almost always prohibitive it follows that an energy future based entirely on intermittent renewables is not a realistic prospect.”

It is against this backdrop that the island of Graciosa in the Azores is preparing to launch another project that aims to replace diesel generation with intermittent renewable energy.

The Graciosa hybrid power system, for island utility Electricidade dos Açores, will feature a 4.5MW wind park and 1MW solar plant connected to a 2.6MW lithium-ion battery system equipped with Leclanché cells.

Project developer Younicos claims: “Diesel generators will only be needed for back-up in weeks with very poor weather conditions.

“This means we can cover an annual average of up to 65% of the island’s power demand with renewables.”

More of a success than El Hierro

Younicos is confident Graciosa will be more of a success than El Hierro because of the choice of storage medium.

The company told Energy Storage Report it believes battery-based systems are the most easily deployable, cost effective option for producing clean power today.

Younicos spokesman Philip Hiersemenzel said: “We already proved that we can keep a grid stable using up to 100% intermittent renewables for hours and indeed days in our technology centre in Berlin.

“As soon as Graciosa becomes operational in autumn, we’ll be proving it every day in real life. Our main challenge with Graciosa was financing. We knew the technology would work 10 years ago and we proved it three years ago.

“Today I’m confident we could build similar systems anywhere in the world in under 12 months, provided that the financing is there.”

A payback of under 15 years

At €24m, the Graciosa project is just over a third of the cost of Gorona del Viento, giving it a potential payback period of under 15 years, according to Younicos.

It is also aiming to serve a smaller level of demand than the project on El Hierro.

Graciosa’s 4,500 inhabitants use about 13.5GWh a year, compared to the 46GWh or so of consumption on El Hierro, which has a population of more than 10,000. This lower bar may help Graciosa in achieving its targets.

But it can hardly afford to miss them, either. With island microgrids now under scrutiny, it is key for the Graciosa project to achieve the level of renewable energy coverage its backers claim… and at a cost that beats diesel.

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