Encouraging Potential for Self- consumption of Solar PV in Germany

solar

A report from the independent German think-tank Agora Energiewende(Agora) has concluded that projected increases in self-consumption through solar PV power systems in the country does not mean upsetting dynamics of the nation’s renewable energy surcharges.

The study outcomes have been welcome news to advocates for Germany’s enviable transition to clean power (referred to as ‘energiewende’). Recent figures show German solar PV capacity of over 40 GW (38.5 TWh) — providing 7.5 percent of Germany’s net electricity consumption through 2015.

There is an underlying concern addressed by the study. Matthias Deutsch, senior associate at Agora, told Renewable Energy World: “An on-going controversy in Germany surrounds the potential and consequences of self-consumption. Some people argue that large-scale up of solar PV — this rise in prosumers — means putting at risk the solidarity of the grid, because people are contributing less to the fixed costs of the system.”

A broad effect of this is thought by some to be reflected in increasing surcharges imposed by the German Renewable Energy Sources Act (EEG) on the kWh price of electricity paid by consumers and increases in grid charges, as trends for autonomy from the grid continue.

On the basis of the study’s findings, Agora observed that through 2035, albeit projecting considerable expansion, “self-consumption of solar PV will play only a secondary role in overall electricity consumption.”

The report concludes: “From today’s perspective, self-consumption poses no risk of quickly eroding the funding base of Germany’s EEG surcharge or network charges.”

Dr. Patrick Graichen, executive director of Agora Energiewende, stated: “There’s simply no reason to fear that a solar power boom will have everyone generating their own power. Even if every eligible homeowner installed a rooftop solar array overnight so they could generate their own power, the EEG-surcharge would only increase by a maximum of 0.5 cents per kWh.”

Figure 1: Development of renewable energy capacity in Germany. Credit: Agora Energiewende.

Providing further insights, Deutsch said: “The potential of self-consumption determined by the study is relatively low. Importantly, even if the price of PV energy storage systems continues to fall rapidly, growth of these systems in energy terms will remain gradual, so the impacts on EEG surcharges would not be too great.”

He added that the study is good news for the solar PV industry, and provides substance to the on-going debate about how to support and manage self-consumption in Germany.

“This is important, of course, since more and more PV storage systems for self-consumption are being offered in the market, and as we see in the report, this market is set to continue expanding,” he said.

The study considered solar PV potential over two distinct sectors: residential (single- and two-family homes) and commercial.

It found that potential residential self-consumption amounts to between 4.6-38.6 TWh per year by 2035. The upper figure was calculated with contribution of energy storage systems included; and the authors noted that there are reasonable grounds for adopting this projection.

However, since not all of this energy is conventionally supplied by the grid (notably due to solar PV powering novel heating applications) the amount of energy that self-consumption may offset in terms of grid demand is less, around 20 TWh.

In the second sector considered by the study, commerce, trade and services, the authors concluded: “We found considerable potential for self-consumption: around 3.8 TWh per year, or just under 3 percent of total electricity demand in the sector, is economically feasible.”

Altogether therefore, Deutsch said that “overall, self-consumption may lead to reduced energy use from the grid of around 24 TWh per year. This represents about 5 percent of today’s net electricity consumption.”

Correspondingly, this potential would affect Germany’s EEG surcharge only moderately: a rise of around 0.5 euro cents (US$0.55) per kWh. While EEG surcharges and other components of power prices have risen in recent years (see figure 2), Deutsch points out that the increase wouldn’t be significant.

He emphasised the hypothetical nature of this calculated increase: “This increase refers to an instant realization of the total potential for self-consumption [that] we expect to unfold only gradually in the future. At the same time, other factors will tend to reduce the EEG surcharge.”

Figure 2: A break-down of recent years’ electricity prices in Germany reveals multiple components. Credit: Agora Energiewende.

Figure 3: The future costs of supporting renewable energy in Germany (in billions) suggests that even promising development of solar PV will not overwhelm the national support system. Credit: Agora Energiewende.

Beyond assurances, the report recommends that the German government now look towards delivering a stable regulatory framework that encourages self-consumption via solar PV.

Previous regulatory amendments, comments Deutsch, have been counter-productive and sent mixed signals to the industry and prosumers.

“While the 2009 version of the EEG featured a bonus scheme for self-consumption; [in contrast] the 2014 revision introduced additional charges,” he said.

Contradictory stances have also been expressed towards the nation’s energy storage support schemes.

He concluded: “Instead of such mixed signals from policy makers, we need to develop a forward-looking system of levies and fees, which includes owners of private property and their tenants in the overall costs of the system; and which ensures that future changes in legislation do not retroactively devalue investments in on-site solar power.”

Lead image: The Solar Settlement project in Freiburg, Germany. Credit: SA 3.0

 

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Net-metering Is Dead — Long Live Net-metering!

Residential solar has demonstrated unprecedented growth over the past several years, driven in part by falling equipment prices, rising customer awareness, and supportive public policy. One of those key policies has been net-metering, which provides customers in more than 40 states credit for any excess solar generation not consumed at the customer’s home.

Despite years of encouraging the expansion of solar, many utilities now argue that customers with solar do not pay their fair share and create a cost shift to customers without solar. However, this argument does not address the true issue at hand, which is how does the grid need to change to address the emergence of distributed energy resource (DER) technologies, such as solar and storage?
The current utility regulatory structure was built for a one-way flow of power from large, centralized power plants to end consumers. The original net-metering policies were also established underneath this paradigm, and it is natural that compensation for exported generation will also evolve as the power industry shifts from a one-way communication platform to a two-way communication approach that delivers higher value to the grid and consumers.
As solar and DER adoption increases, compensation for generation and grid services must evolve from its early days as a simple billing mechanism for the one-way flow of power from large, centralized power plants to a more sophisticated platform connecting distributed generation and consumers to the grid.
To accomplish this goal, the grid must be modernized to allow for efficient and effective two-way communications by enabling data to be regularly provided to both utilities and customers. With this architecture in place, utilities can send clear price signals to consumers on the true cost to deliver power, and customers can make more informed decision about their choice to either generate their own power or purchase power from their utility.
One example of where this discussion is already underway is in New York, where the New York Public Service Commission is leading the Reforming the Energy Vision (REV) initiative. The REV initiative is designed to encourage clean energy innovation while improving consumer choice and affordability. To calculate the value of an energy source, New York is looking at the following features:
  • the equivalent kilowatt-hour that the local wholesale generator can earn;
  • the value of the energy power to the distribution system; and
  • the external societal value.
As the role of utilities and the grid changes to allow greater consumer choice and participation in energy markets, utilities and the grid must be enabled through policy and rate reform to integrate technology that can quantify the true value of power, regardless of source, based upon the time and location power is provided to the grid. Until that time, retail net-metering, more than any other policy, provides “rough justice” for the value of solar exported to the grid from DERs, and provides the fairest platform for consumer choice available.

Renewables could lose European power grid priority, documents reveal

Industry concern after confidential impact assessment models scenarios for paring back the ‘priority dispatch’ system for clean energy

The sun reflects off a solar collector assembly at the Andasol solar power station, southern Spain. Retroactive changes to funding rules have caused disputes and cutbacks in several countries, notably Spain.

 The sun reflects off a solar collector assembly at the Andasol solar power station, southern Spain. Retroactive changes to funding rules have caused disputes and cutbacks in several countries, notably Spain. Photograph: Marcelo Del Pozo/Reuters

Paring back the “priority dispatch” system could increase carbon emissions by up to 10%, according to a confidential EU impact assessment seen by the Guardian. But the document goes on to model four scenarios for doing just that, in a bid to make Europe’s energy generators more flexible and cost-competitive.

Some industry sources have told the Guardian they are alarmed and think it highly likely that priority dispatch for clean energy will be scrapped from the EU’s renewable energy directive, which is currently being redrafted for the post-2020 period.

Oliver Joy, a spokesman for the WindEurope trade association, said: “Removing priority dispatch for renewable energies would be detrimental to the wind sector, which would face more curtailment across the continent. It also seems to be at odds with Europe’s plans to decarbonise and increase renewables penetration over the next decade.”

“Investors took priority dispatch into account when projecting revenues in the original investment decisions, and it could have a bearing on existing projects if they are not protected from the change.”

The issue of retroactive changes to funding rules for renewables in Europe has been a cause for disputes and cutbacks in the wind and solar sectors of several countries, notably Spain.

Senior industry sources say they will push for financial compensation and access to balancing markets to help prevent a significant industry contraction, if priority dispatch is ended.

“We have had enough instability and retroactivity in Europe and going forward, the difference between existing and future assets should be well distinguished,” said one industry source.

“I would be extremely worried if they just removed priority of dispatch and did not touch other key issues around market design. It would mean that the commission was taking measures against the same renewable industries that they defend in public.”

Fossil fuel power providers argue that renewables have the lowest operating costs and so would anyway receive priority access to the grid network.

They also say that taking the clean energy sector out of priority dispatch would prevent “negative prices” – where more energy is produced than can be sold – and eliminate anti-competitive subsidies.

The EU’s assessment views the abolishing of priority dispatch as a step towards the creation of a “level playing field” for energy generators.

But without such a system, renewable sources may be the most likely to be taken offline because of the relative ease of switching off a wind turbine compared to a coal or nuclear plant.

The energy source with the lowest marginal cost – almost always renewables – is usually the first in line to be shut down by power grid operators.

As things are, a Europe-wide trend towards ending financial support has constrained the forward march of renewables on the continent, and siphoned off investment to elsewhere in the world.

“Everyone is investing in renewables outside Europe right now,” said one industry source. “If you want to bring investors back you have to send very relevant signals.”

Removing wind and solar power from priority dispatch may be intended to help reform the capacity market system, which currently pays gas generators to remain idle. Ironically though, it could lead renewable generators to demand an extension of the same mechanism to their own sector.

“If priority dispatch is removed, then renewables must be given a fall-back option of access and renumeration in the balancing markets to help stabilise the system, or clear levels of compensation in the event that curtailment is necessary,” Joy said.

Priority dispatch is supposed to be mandatory under current EU rules, although the UK, Sweden and the Netherlands are among countries that do not comply.

The study says that “the biggest impacts on generation [from ending priority dispatch] would be observed in Denmark, Great Britain and Finland, where biomass holds a large share of generation capacity”.

But this would be felt more in terms of bioenergy’s “expensive” production costs than its carbon emissions reduction potential, which is disputed inside and outside the commission.

“The removal of priority dispatch for biomass would indeed, in the first instance, imply an increase in GHG [greenhouse gas] emissions,” the paper says.

The four scenarios for scaling back priority dispatch involve an increase in CO2 emissions of 45m-60m tonnes.

 

View original post on : https://www.theguardian.com/environment/2016/nov/01/renewables-could-lose-european-power-grid-priority-documents-reveal

5 unanswered questions after Tesla’s big solar roof and battery announcement

As the dust settles, the details of Elon Musk’s new solar-plus-storage offering remain unclear

For a while now, Tesla has situated itself as the Apple of the electric storage and transport industries. It streamlines the design of an existing technology, makes it sleeker and sexier, while expertly marketing it to cultivate an upscale, but mass-market following.

The company first did it with its electric vehicles, producing sought-after luxury cars and then gradually moving toward less expensive models. And it brought residential energy storage into the consumer mainstream last year when it unveiled the Powerpack, the first generation of its home battery.

Now Tesla is leveraging its planned acquisition of solar installer SolarCity to do the same thing with residential solar and storage. Last Friday, CEO Elon Musk unveiled a slate of integrated solar roof and battery storage offerings that mimic the design of traditional roof shingles and eliminate the external mounted panel design.

The glass PV tiles, available in a number of common roof colors, will cost “less than a normal roof plus the cost of electricity,” Musk promised, and will integrate with the Powerwall 2, the second generation of Tesla’s home storage system.

That new battery is powerful enough to run the refrigerator, sockets and lights of a four-bedroom house for a day — or indefinitely when combined with the solar system, Musk said, touting a future where everyday consumers have a solar roof, battery and electric vehicle.

But like Tesla events of the past, those general operational and cost promises are about as much detail over the specifics of the battery and the solar system as Musk divulged all night. Details about the panel efficiency, battery life and overall cost were left out of Musk’s presentation, leaving a number of open questions about the sleek new Tesla offering and its potential impacts on the market.

1. Solar roof specifications

Just as Tesla was not the first to offer electric vehicles or home batteries, it is not the first in the integrated solar panel market.

While not widespread for the residential market yet, a number of large buildings have demonstrated the effectiveness of solar technologies integrated into their designs, including the National Air and Space Museum. And Greentech points out there are a number of integrated solar roof installers on the market already, though no runaway commercial successes.

Integrated PV technologies are appealing for their sleek design, but are more expensive than existing rooftop solar models that are simply bolted to a homeowner’s roof. Typically, integrated PV does not generate power with the efficiency of traditional panels, which can more easily be faced toward direct sunlight.

Beyond his promise that the Tesla roofs would cost less than traditional ones over time, Musk offered no pricing or efficiency details on the new solar roofs, as well as no insight as to how power contracts with consumers would be structured. Currently, SolarCity contracts typically guarantee solar output for 20 years, but most roofs are expected to last longer.

Other financial aspects of owning the PV roof, such as its impacts on a mortgage, resale value, homeowner’s insurance and other aspects of property value remain unclear, though those are issues that continue to bedevil the residential solar sector at large.

It also remains to be seen how the glass panels perform in the field. Typical solar panels require regular cleaning to achieve maximum output, and it’s unclear whether homeowners would have to regularly wipe down their PV rooftops to generate energy.

Tesla solar roof styles

 

Available in different styles, Telsa’s solar roofs are designed to mimic traditional styles.

 

2. Battery specifications

A bit more is known about the solar roof’s partner — the Powerpack 2.

At the event, Musk said the new 7 kW, 14 kWh battery will cost $5,500, including a custom inverter. That capacity outpaces both the first iteration of the Powerpack and a larger, 10 kWh model Tesla discontinued last year.

That size battery is likely better suited to the average American homeowner, GTM reports, but little is known beyond its size and price. Tesla did not release details about the expected efficiency or cycle life of the Powerwall 2, or the second iteration of its Powerpack grid-scale battery, released Thursday evening.

Cycle life, or the number of cycles a battery can perform before degrading to a certain level, is expected to be crucial for customers of both the residential and grid-scale batteries. Using a home battery to store and discharge solar from a PV roof typically uses at least one cycle a day, as do grid services such as ramping or shifting renewables generation.

The rate at which batteries degrade determines how long they can be used before needing replacement, and often forms the foundation of energy storage contracts with utilities. But Tesla has never publicly released degradation curves or other performance information regarding their energy storage systems or car batteries, which some companies consider proprietary information.

Tesla currently offers an eight-year “unlimited mile” warranty for its Model S electric vehicle batteries, but makes no commitment to replace the $44,000 car battery after that time.

survey of Tesla owners by EV advocate Plug In America last year showed that the Model S generally loses about 5% of its capacity within the first 50,000 miles of driving, but the jury is still out on how the batteries will perform once they reach the end of the warranty period.

tesla solar roof batteries

 

Tesla’s new Powerwall is more rectangular than its predecessor.

 

3. Solar and storage markets

But even if the integrated PV and storage market is not large yet, Tesla is not without competition.

There are a number of companies installing integrated solar roofing projects, Greentech notes, including names like SunTegra and Solarmass. There’s also a sizeable list of high-profile failures, like SunEdison’s Ready Solar and PV shingle offerings from Dow Chemical and PV.

As impressive as the design of integrated solar shingles is, Greentech’s Eric Wesoff points out that hasn’t been the biggest issue in commercializing it with other companies. Instead, it is launching a pricey, newfangled environmental technology through a conservative roofing industry.

“PV panels and roofing have very different roles, and I’ve observed that combining the two compromises both at a premium cost,” the editor wrote in an open letter to Musk.

If Tesla can succeed in convincing consumers and the broader industry that its roofs are indeed cheaper and more durable than traditional designs, its brand recognition and reputation could help it make inroads. But it remains to be seen how the company will go about sharing the technology behind its new combined offering.

Currently, Tesla makes many of its electric vehicle patents public, but other aspects of its business are strictly vertically integrated. The company does not sell its cars through third party dealerships and even uses a different charger outlet than other EVs.

With the planned merger with SolarCity, Tesla appears to be spreading that vertically integrated model to its energy offerings, creating an all-in-one distributed energy company. If it continues that trajectory, that could see it stop selling batteries to third-party installers like Sunrun, which currently uses Tesla batteries for its residential solar offering and would be a direct competitor with a merged Tesla.

4. The SolarCity merger

Musk’s event on Friday was about more than unveiling a new product — it was also a chance to show Tesla investors the promise of a merger with SolarCity, the largest residential rooftop installer in the U.S.

Since Tesla announced its intent to buy the company in June, some analysts and shareholders have reacted skeptically. Musk is SolarCity’s chair, his cousins run the company, and many saw the move as a bailout for the residential installer, whose business model relies on hefty debt financing to support its model of no-upfront-cost solar leases.

Tesla’s unexpected third quarter profit, reported last week, gave pause to some of the most anxious shareholders, and Musk’s unveiling of an exciting, integrated product could buoy support for the acquisition.

If that goes badly for Musk, the future of the new solar roof option appears in doubt. In a “master plan” for Tesla unveiled in the summer, Musk hinted at a new integrated solar offering and warned that it would be impossible to offer it if SolarCity remained a separate company.

Whether shareholders view the solar roof offering as an exciting new extension of Tesla’s business or a risky bet on an unfamiliar market remains to be seen. They vote on the merger Nov. 17.

5. Utility sector impact

Musk often frames his business moves as part of a larger strategy to clean up the electricity and transport sectors, allowing them to run on renewable energy and modern energy storage.

That broad vision is one shared by a number of policymakers, including U.S. leaders who signed the Paris Climate Accord last year. But just how deep that decarbonization of the power sector affects utilities remains to be seen.

Fossil generators are sure to feel the impacts, and many are already dealing with widespread coal plant retirements. But Musk said that the future for electric utilities in this cleaner future remains bright.

Powering new electric vehicles will increase demand for electricity, making utilities more critical to the modern energy system and assuaging concerns of a financial “death spiral” for the sector. Going forward, Musk predicted the grid will eventually reach an equilibrium with about one-third of power coming from distributed energy and two-thirds from utilities.

“I think it’s a very bright future for utilities and rooftop [solar],” he said.

View Original Post on:   http://www.utilitydive.com/news/5-unanswered-questions-after-teslas-big-solar-roof-and-battery-announcemen/429393/

India Already Has a Problem With Wasting Renewable Energy on the Grid

India ratified the Paris climate agreement this week, officially underscoring its commitment to reduce greenhouse gas emissions. Yet just two years after embarking on an ambitious campaign to scale up renewable energy, India is facing a curious problem: too much solar and wind power in some parts of the country.

In July, for the first time, the southern Indian state of Tamil Nadu was unable to use all the solar power it generated. Later in the month, Jayaram Jayalalitha, the chief minister of Tamil Nadu, wrote a letter to Prime Minister Narendra Modi urging him to speed up the construction of an inter-state green energy corridor that would allow renewable power to be transmitted and used in other states instead of being wasted.

And in August, Tarun Kapoor, India’s joint secretary of the Ministry of New and Renewable Energy, wrote a letter asking electricity regulators to fully utilize solar power following complaints that grid operators were letting renewable energy go to waste.

As developing countries lead the world in renewable energy investment, India’s experience highlights a larger question: Will the grid be a major roadblock for renewable energy development across the developing world?

From India to China to Chile, a significant portion of future renewable energy could go to waste without careful planning.

Solar and wind only accounted for 3.5 percent of the power generated in India in 2015. But if the government achieves its ambitious targets for renewable energy deployment, the amount of solar and wind power on the grid could quadruple by 2022. Yet there are already signs that the grid’s ability to absorb these new power sources could be a major bottleneck for renewable energy growth in India, jeopardizing the country’s energy and climate goals.

Although there is not clear national data, regulatory filings from Tamil Nadu, where the problem is thought to be the most extreme, put the curtailment rate for wind power between 33 percent and 50 percent — an astonishingly high figure.

The problem is, in part, a technical one. Solar and wind power are not as easy to control as traditional fossil fuel plants, so power grids need to become flexible enough to handle last-minute changes in power generation.

Distance is also an issue. In India, six states in the western and southern regions account for 80 percent of all of the country’s currently installed solar capacity, but only 38 percent of power demand. For grid operators used to being able to turn fossil fuel plants on and off at will, these changes can take some getting used to. If new measures are not put into place to accommodate variable renewable energy sources, a situation can arise where the physical grid — or the grid operator — is unable to use solar and wind power when it becomes available.

Other countries have already dealt with this problem with varying degrees of success. Germany and the U.S. have relatively high levels of solar and wind penetration and low curtailment rates, while China has had major issues with curtailment as the share of wind and solar in the energy mix increases.

Indeed, China currently has more wind and solar power capacity than any other country in the world after scaling up very quickly. In the five years between 2010 and 2015, the share of solar and wind power generated in China quadrupled. Yet in 2015, the U.S. still produced more electricity from wind than China, despite having only 58 percent of China’s installed wind capacity. A large reason for this discrepancy is that much of China’s solar and wind power is wasted: 21 percent of wind power was curtailed in the first half of 2016 (with Gansu province reaching a 47 percent curtailment rate), and solar curtailment reached 11 percent in the first three quarters of 2015.

Although China has been able to build out renewable energy capacity quickly over the past decade, it has taken much longer to develop the transmission infrastructure and make the institutional changes required to utilize all of this new power.

How can India learn from China’s mistakes and rapidly scale up renewables without waste?

Luckily, the challenge has not caught Indian policymakers by surprise. There are already a number of initiatives underway to help integrate renewables into the grid. Perhaps most important is that, unlike China, India already has a wholesale power market, which can provide much-needed flexibility for utilities to buy and sell power at short notice.

There is also the aforementioned green energy corridor, a series of transmission lines that will connect states with excess renewable energy to areas where there is demand. And similar to China, solar and wind already have “must run” status, meaning that any power they generate should always be accepted by the grid.

Yet even these steps may not be enough. A recent survey found that 31 percent of senior corporate leaders in Indian solar companies think that grid integration will be the biggest challenge for expanding solar in India going forward.

The first priority for India when addressing this issue is to finish the green energy corridor and other new transmission lines so that renewable power can be transmitted where it is needed. There are significant power surpluses in some states and power deficits in others.

For instance, Uttar Pradesh has a peak power deficit of 9.7 percent (meaning 9.7 percent of demand at peak times cannot be met with the power available in the state), whereas the bordering state of Madhya Pradesh has a peak power surplus of 8.3 percent. Yet the power connection between the two states was at full capacity 73 percent of the time in May 2016, meaning some surplus power in Madhya Pradesh may not have made it to Uttar Pradesh. Nationally, 10 percent of the power supply available on the short-term markets last year could not be used because of transmission constraints.

New investment in inter-state power lines will help balance out such disparities. It is particularly important for India to attract private investment in these projects. The green energy corridor will cost an astounding USD $3.4 billion, and is funded in part by government funds and partially by a $1 billion loan from the Asian Development Bank and 1 billion loan from GiZ. But the public sector can only fund so many multibillion-dollar projects, and many state utilities are already in poor financial conditions.

Private capital is projected to be required for 47 percent of infrastructure investment in India between 2012 and 2017. India’s planning commission has created a framework for public-private partnerships for transmission investment, but land acquisition and permitting are still major roadblocks for private developers hoping to complete a project on schedule. Reducing the time and cost of land acquisition will be essential to making infrastructure projects attractive to developers and unlocking the private capital needed to finance transmission lines.

Second, focusing on deploying distributed energy technologies like rooftop solar can help increase the amount of renewable energy in use where new transmission lines are infeasible or too expensive.

India hopes to get 40 percent of its solar capacity from rooftop solar by 2022, but the market has been slow to take off despite a 30 percent capital subsidy from the government. The barriers to rooftop solar deployment are often more institutional than technical. In China, slow subsidy disbursement and a lack of financing have caused rooftop solar deployment to fall short of government targets. In India, a recent survey found that 93 percent of senior corporate leaders in the Indian solar sector did not think the country would even reach half of its rooftop solar target by 2022, citing ineffective net metering policy, unavailable and expensive financing, and consumer awareness as top issues.

There are a number of potential solutions: Training for distribution utilities unaccustomed to having customers generate their own electricity; streamlining the application and approval process; creating certifications to ensure installer quality; and even allowing rooftop solar systems to serve as backup power when the grid goes down. Quickly implementing such solutions can allow renewables to grow without worsening curtailment.

Energy storage can also play an important role in reducing curtailment. The cost of storage is still a major barrier to mass adoption, but prices are dropping quickly.

Moreover, Germany and Texas have achieved low curtailment rates with minimal energy storage and high renewable energy penetrations through improved grid planning and changes to the power market structure. Still, India is planning on installing 10 gigawatts of pumped hydro energy storage across the country to accommodate increased renewable energy penetration (China is taking similar measures to reduce curtailment). As the price of energy storage drops, it will become an increasingly compelling complement to variable renewable energy.

Finally, India can look to other countries to find grid planning and operational solutions to help manage curtailment as renewable power scales up. One such change, highlighted in a recent Paulson Institute report on curtailment, is to create financial incentives against curtailing renewables.

Currently, Indian solar and wind generators are not compensated for curtailment, and compensation should not be necessary because renewables have “must run” status. However, financial incentives can help reinforce such regulations when mandates alone are insufficient. China has had a similar experience with “must run” mandates: multiple policies have stated that solar and wind should always receive priority on the grid, but curtailment continues to be an issue because there are few penalties for ignoring this regulation.

recent regulation released by China’s National Development and Reform Commission requires that coal plant owners pay wind or solar plant owners whose energy is curtailed, creating a stronger incentive for grid operators to fully utilize renewables. An even simpler solution would be to compensate solar and wind projects for any curtailed energy at a fixed rate. This not only penalizes grid operators that choose to curtail renewables, but also provides more certainty for power producers when trying to forecast revenue.

Even smaller changes to how the grid is operated can make a difference. In Texas, grid operator ERCOT shifted from 15-minute dispatch intervals on the intra-day market to 5-minute intervals, allowing for more granular planning around variable wind and solar power plants. (India currently uses 15-minute dispatch intervals.) ERCOT also shifted from targeting 0 percent curtailment to a maximum acceptable curtailment rate of 3 percent of annual renewable energy production — a more cost-effective solution than trying to utilize every unit of electricity generated at peak times.

Such institutional changes can provide flexibility to the grid without the high risk and cost of major new transmission and storage projects.

India has already set a moonshot goal for renewable energy deployment that would have been unthinkable just a few years ago. Indeed, in the five years between Copenhagen and Paris, India went from being a hindrance to an enthusiastic participant to in the United Nation’s global climate negotiations.

Yet a successful energy transition will require a broader change in the infrastructure and institutions that support renewables — not just targets themselves.

View original post: http://www.greentechmedia.com/articles/read/how-can-india-avoid-wasting-renewable-energy

India Already Has a Problem With Wasting Renewable Energy on the Grid

The country can learn from China, Germany and Texas on how to mitigate the problem.

India ratified the Paris climate agreement this week, officially underscoring its commitment to reduce greenhouse gas emissions. Yet just two years after embarking on an ambitious campaign to scale up renewable energy, India is facing a curious problem: too much solar and wind power in some parts of the country.

In July, for the first time, the southern Indian state of Tamil Nadu was unable to use all the solar power it generated. Later in the month, Jayaram Jayalalitha, the chief minister of Tamil Nadu, wrote a letter to Prime Minister Narendra Modi urging him to speed up the construction of an inter-state green energy corridor that would allow renewable power to be transmitted and used in other states instead of being wasted.

And in August, Tarun Kapoor, India’s joint secretary of the Ministry of New and Renewable Energy, wrote a letter asking electricity regulators to fully utilize solar power following complaints that grid operators were letting renewable energy go to waste.

As developing countries lead the world in renewable energy investment, India’s experience highlights a larger question: Will the grid be a major roadblock for renewable energy development across the developing world?

From India to China to Chile, a significant portion of future renewable energy could go to waste without careful planning.

Solar and wind only accounted for 3.5 percent of the power generated in India in 2015. But if the government achieves its ambitious targets for renewable energy deployment, the amount of solar and wind power on the grid could quadruple by 2022. Yet there are already signs that the grid’s ability to absorb these new power sources could be a major bottleneck for renewable energy growth in India, jeopardizing the country’s energy and climate goals.

Although there is not clear national data, regulatory filings from Tamil Nadu, where the problem is thought to be the most extreme, put the curtailment rate for wind power between 33 percent and 50 percent — an astonishingly high figure.

The problem is, in part, a technical one. Solar and wind power are not as easy to control as traditional fossil fuel plants, so power grids need to become flexible enough to handle last-minute changes in power generation.

Distance is also an issue. In India, six states in the western and southern regions account for 80 percent of all of the country’s currently installed solar capacity, but only 38 percent of power demand. For grid operators used to being able to turn fossil fuel plants on and off at will, these changes can take some getting used to. If new measures are not put into place to accommodate variable renewable energy sources, a situation can arise where the physical grid — or the grid operator — is unable to use solar and wind power when it becomes available.

Other countries have already dealt with this problem with varying degrees of success. Germany and the U.S. have relatively high levels of solar and wind penetration and low curtailment rates, while China has had major issues with curtailment as the share of wind and solar in the energy mix increases.

Indeed, China currently has more wind and solar power capacity than any other country in the world after scaling up very quickly. In the five years between 2010 and 2015, the share of solar and wind power generated in China quadrupled. Yet in 2015, the U.S. still produced more electricity from wind than China, despite having only 58 percent of China’s installed wind capacity. A large reason for this discrepancy is that much of China’s solar and wind power is wasted: 21 percent of wind power was curtailed in the first half of 2016 (with Gansu province reaching a 47 percent curtailment rate), and solar curtailment reached 11 percent in the first three quarters of 2015.

Although China has been able to build out renewable energy capacity quickly over the past decade, it has taken much longer to develop the transmission infrastructure and make the institutional changes required to utilize all of this new power.

How can India learn from China’s mistakes and rapidly scale up renewables without waste?

Luckily, the challenge has not caught Indian policymakers by surprise. There are already a number of initiatives underway to help integrate renewables into the grid. Perhaps most important is that, unlike China, India already has a wholesale power market, which can provide much-needed flexibility for utilities to buy and sell power at short notice.

There is also the aforementioned green energy corridor, a series of transmission lines that will connect states with excess renewable energy to areas where there is demand. And similar to China, solar and wind already have “must run” status, meaning that any power they generate should always be accepted by the grid.

Yet even these steps may not be enough. A recent survey found that 31 percent of senior corporate leaders in Indian solar companies think that grid integration will be the biggest challenge for expanding solar in India going forward.

The first priority for India when addressing this issue is to finish the green energy corridor and other new transmission lines so that renewable power can be transmitted where it is needed. There are significant power surpluses in some states and power deficits in others.

For instance, Uttar Pradesh has a peak power deficit of 9.7 percent (meaning 9.7 percent of demand at peak times cannot be met with the power available in the state), whereas the bordering state of Madhya Pradesh has a peak power surplus of 8.3 percent. Yet the power connection between the two states was at full capacity 73 percent of the time in May 2016, meaning some surplus power in Madhya Pradesh may not have made it to Uttar Pradesh. Nationally, 10 percent of the power supply available on the short-term markets last year could not be used because of transmission constraints.

New investment in inter-state power lines will help balance out such disparities. It is particularly important for India to attract private investment in these projects. The green energy corridor will cost an astounding USD $3.4 billion, and is funded in part by government funds and partially by a $1 billion loan from the Asian Development Bank and 1 billion loan from GiZ. But the public sector can only fund so many multibillion-dollar projects, and many state utilities are already in poor financial conditions.

Private capital is projected to be required for 47 percent of infrastructure investment in India between 2012 and 2017. India’s planning commission has created a framework for public-private partnerships for transmission investment, but land acquisition and permitting are still major roadblocks for private developers hoping to complete a project on schedule. Reducing the time and cost of land acquisition will be essential to making infrastructure projects attractive to developers and unlocking the private capital needed to finance transmission lines.

Second, focusing on deploying distributed energy technologies like rooftop solar can help increase the amount of renewable energy in use where new transmission lines are infeasible or too expensive.

India hopes to get 40 percent of its solar capacity from rooftop solar by 2022, but the market has been slow to take off despite a 30 percent capital subsidy from the government. The barriers to rooftop solar deployment are often more institutional than technical. In China, slow subsidy disbursement and a lack of financing have caused rooftop solar deployment to fall short of government targets. In India, a recent survey found that 93 percent of senior corporate leaders in the Indian solar sector did not think the country would even reach half of its rooftop solar target by 2022, citing ineffective net metering policy, unavailable and expensive financing, and consumer awareness as top issues.

There are a number of potential solutions: Training for distribution utilities unaccustomed to having customers generate their own electricity; streamlining the application and approval process; creating certifications to ensure installer quality; and even allowing rooftop solar systems to serve as backup power when the grid goes down. Quickly implementing such solutions can allow renewables to grow without worsening curtailment.

Energy storage can also play an important role in reducing curtailment. The cost of storage is still a major barrier to mass adoption, but prices are dropping quickly.

Moreover, Germany and Texas have achieved low curtailment rates with minimal energy storage and high renewable energy penetrations through improved grid planning and changes to the power market structure. Still, India is planning on installing 10 gigawatts of pumped hydro energy storage across the country to accommodate increased renewable energy penetration (China is taking similar measures to reduce curtailment). As the price of energy storage drops, it will become an increasingly compelling complement to variable renewable energy.

Finally, India can look to other countries to find grid planning and operational solutions to help manage curtailment as renewable power scales up. One such change, highlighted in a recent Paulson Institute report on curtailment, is to create financial incentives against curtailing renewables.

Currently, Indian solar and wind generators are not compensated for curtailment, and compensation should not be necessary because renewables have “must run” status. However, financial incentives can help reinforce such regulations when mandates alone are insufficient. China has had a similar experience with “must run” mandates: multiple policies have stated that solar and wind should always receive priority on the grid, but curtailment continues to be an issue because there are few penalties for ignoring this regulation.

recent regulation released by China’s National Development and Reform Commission requires that coal plant owners pay wind or solar plant owners whose energy is curtailed, creating a stronger incentive for grid operators to fully utilize renewables. An even simpler solution would be to compensate solar and wind projects for any curtailed energy at a fixed rate. This not only penalizes grid operators that choose to curtail renewables, but also provides more certainty for power producers when trying to forecast revenue.

Even smaller changes to how the grid is operated can make a difference. In Texas, grid operator ERCOT shifted from 15-minute dispatch intervals on the intra-day market to 5-minute intervals, allowing for more granular planning around variable wind and solar power plants. (India currently uses 15-minute dispatch intervals.) ERCOT also shifted from targeting 0 percent curtailment to a maximum acceptable curtailment rate of 3 percent of annual renewable energy production — a more cost-effective solution than trying to utilize every unit of electricity generated at peak times.

Such institutional changes can provide flexibility to the grid without the high risk and cost of major new transmission and storage projects.

India has already set a moonshot goal for renewable energy deployment that would have been unthinkable just a few years ago. Indeed, in the five years between Copenhagen and Paris, India went from being a hindrance to an enthusiastic participant to in the United Nation’s global climate negotiations.

Yet a successful energy transition will require a broader change in the infrastructure and institutions that support renewables — not just targets themselves.

View original post:  http://www.greentechmedia.com/articles/read/how-can-india-avoid-wasting-renewable-energy

A Case for Cautious Optimism: Renewable Energy Auctions in Latin America

renewable energy

Global Trends in Renewable Energy Investment 2016’s list of top 10 developing countries with renewable energy sector investment in 2015 included Latin American countries Brazil ($7.1 billion), Mexico ($4 billion), and Chile ($3.4 billion). IHS Markit sees continued growth in renewable energy investment in Latin America with new solar installations scheduled to reach 2.7 GW of installed PV module capacity this year alone. This trend is expected to continue with Chile and Mexico having held successful auctions that garnered high participation and some of the lowest prices per megawatt hour (MWh) globally. Although these data points are cause for optimism in the region, a relatively young government in Argentina trying to restore a badly damaged international reputation and economic and political woes in Brazil caution against over exuberance.

Two Success Stories in Latin America in 2016: Mexico and Chile

Following sweeping reforms to its energy sector regulations, Mexico’s first renewable energy auction in March rendered 10 packages of 15-year power purchase agreements (PPA) and 20-year contracts for clean energy certificates. The average, overall price awarded in this auction was $41.80/MWh. A total of 69 firms presented 227 projects, but ultimately 10 firms were awarded 16 projects. This high level of interest and competitive pricing was largely due to investors perceiving Mexico as a country that has a vast potential for the development of renewable energy projects, a stable and transparent regulatory framework, and a well-developed project finance sector (which in the case of this auction was attributable to the PPAs having longer terms and being denominated in U.S. dollars rather than Mexican pesos). The awarded projects are expected to generate billions of dollars in investment throughout Mexico, which is holding its second power auction, the winners of which are expected to be announced on Sept. 30.

Equally successful was the Chilean auction, which attracted 84 participants and resulted in the lowest price for solar PV projects globally — $29.10/MWh. The average awarded price was $47.59/MWh. This auction reduced the average energy price per MWh in 2013 by 63 percent and in 2014 by 40 percent. Like Mexico’s auction, this auction’s low pricing and high level of participation was principally due to awarded PPAs having 20-year terms and being denominated in U.S. dollars. Auction participants were also encouraged by Chile’s new transmission law, which permits grid expansion for specific regions and improves connection among Chile’s three grids.

Similar to Mexico, if the awarded energy supply results in projects actually being built, Chile could reap the hefty rewards brought by lower energy prices and increased investment throughout the country. The Chilean government estimates that these projects will help lower electricity costs for families and small businesses by 20 percent within five years and bring approximately US$3 billion in investment. However, many remain concerned that these projects might not be completed given Chile’s aging transmission infrastructure and transmission congestion, as well as exposure to spot price fluctuations in some project locations in Chile.

Major Set-backs for Brazil’s Renewable Energy Market

While Brazil has been the Latin American leader in investment in the renewable energy sector, it appears to be regressing. In the past few weeks, six developers that were awarded PPAs in Brazil’s first energy auction in 2014 have undertaken efforts to terminate their agreements. These developers contend that their projects are no longer viable due to the lack of affordable financing that is attributable to factors such as Brazil’s economic and political instability, including the devaluation of the real vis-à-vis the U.S. dollar and the absence of a local supply chain. Further complicating Brazil’s outlook is its cancellation of a solar energy auction planned in July and the postponement of its October auction until December.

Newcomer Argentina is Trying to Follow Mexico and Chile’s Footsteps

Next month Argentina is scheduled to announce the winners of “RenovAr-1,” its first renewable energy auction. This auction attracted 123 offers totaling 6,366 MW. Like Mexico and Chile, this auction drew significant interest because its PPAs will have a longer term (20 years) and will be denominated in U.S. dollars. Additionally, developers and investors were reassured by the Argentine government’s creation of FODER (Fondo Fiduciario de Energías Renovables), a sector-specific fund which is backed by a World Bank guarantee, and that will provide security for payments under awarded PPAs, as well as project financing assistance. All of these factors seem to indicate that Argentina’s first energy auction should be as successful as those held by Mexico and Chile earlier this year.

Cautious Optimism, Not Skepticism

Latin American countries such as Mexico and Chile have demonstrated that well-planned power auctions have the potential of spurring substantial growth in renewable energy investment in relatively short periods of time. Argentina appears to be heading in the same direction. Brazil, however, will need to undertake major changes to its auction program in order to attract the same level of interest Mexico, Chile, and Argentina have attracted from investors but in a sustainable manner. Optimism in the potential for continued growth in investment in the region’s renewable energy sector should be met with caution, not skepticism given the strides that have been made by countries such as Mexico and Chile.

Kevin S. Levey (left) is a partner in the Squire Patton Boggs Energy & Natural Resources Practice. Kevin focuses on the development of solar, biomass, biofuels and other renewable energy power projects, as well as clean coal-fired power projects in the US and other countries. He has advised large multinational companies on the construction, financing, operation, acquisition and sale of major power generation, liquefied natural gas terminal and pipeline projects in Latin America, including Brazil, Chile and Mexico.

Loana Martín is an associate in the firm’s Energy & Natural Resources Practice, focusing her practice on corporate transactions in the energy and infrastructure sectors, developing natural gas pipelines, solar power plants and other major infrastructure projects in the US and Latin America. Both are resident in the firm’s Washington DC office.

Lead image: The Fan Land, Atakama, Chile. CreditAndrew Kudrin | Flickr

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Massachusetts Goes All-In on Energy Storage

energy storage

The next wave of clean energy policy making will be more focused on energy storage, as evidenced by the release this week of the long-awaited Massachusetts energy storage report, titled “State of Charge.”  The study was co-funded by the Massachusetts Department of Energy Resources (DOER) and Massachusetts Clean Energy Center (MassCEC), and it represents a major new policy direction for the state on how to capture the economic and environmental benefits of emerging energy storage technologies.

In impressive fashion, the 200-page report, supported by detailed economic analysis, lays out how Massachusetts can use a smart combination of procurement, financial incentives, market economics, and economic development strategies to expand storage deployment and help grow the storage industry. It is a road map showing how energy storage can save money, increase penetration of renewable power and address climate change in Massachusetts — and, by extension, in other states.

The report proposes that the state invest millions in storage deployment incentives and market development, with the goal of incentivizing 600 MW of new advanced storage capacity by 2025, resulting in an anticipated $800 million in system benefits to ratepayers. These policy actions would be a big step in moving the state toward the report’s modeled optimal deployment level of 1.766 GW of storage, and may be augmented by the new Massachusetts energy diversity law that empowers DOER to set an energy storage procurement mandate for the state’s utilities.

DOER is supposed to decide by the end of this year whether to establish an energy storage procurement mandate, and if so, for how much additional storage. State utilities would then have until 2020 to meet the mandated procurement target. If established, this would make Massachusetts the third state to create a storage mandate, and the first in the Northeast.

While the study does not recommend an energy storage mandate, it does provide a sophisticated cost/benefit analysis model showing the economic benefits of procuring 1.766 GW of energy storage. According to the study that procurement would cost between $970 million and $1.35 billion, but would yield $2.3 billion in system benefits to ratepayers, plus $1.1 billion in market revenue to the resource owners; and $250 million in regional system benefits to the other New England states due to lower wholesale market prices across ISO New England (ISO-NE). Climate benefits include a carbon emissions reduction of more than 1 million metric tons of carbon dioxide over 10 years — equivalent to taking 223,000 cars off the road.

The study begins by laying out the business case for storage. The state’s electric system is inefficient, it says, with storage capacity accounting for less than 1 percent of the state’s daily electricity consumption. The grid must be balanced by the nearly-instantaneous ramping up and down of fossil fuel generators, requiring the building and maintenance of numerous gas “peaker” plants that only run 2 percent to 7 percent of the time. That means these plants sit idle more than 90 percent of the time.

The report also points to inefficiencies in the grid infrastructure and resulting high costs to ratepayers due to “highly variable” electricity prices. The report claims that from 2013-2015, the top 1 percent most expensive hours for electricity consumption accounted for more than 8 percent ($680 million) of Massachusetts ratepayers’ annual electricity costs, and that the top 10 percent of hours during those years, on average, “accounted for 40 percent of annual electricity spend, over $3 billion.”

The report suggests that energy storage is “the only technology that can use energy generated during low cost off peak periods to serve load during expensive peak periods, thereby improving overall utilization and economics of the electric grid.”

So, if storage is so beneficial, why isn’t there more of it already? The Massachusetts study identifies the single biggest barrier to energy storage deployment:

“While the system benefits alone justify an investment in storage from a ratepayer perspective, the revenue mechanisms that would encourage investment from a private storage developer are insufficient. Without a means to be compensated for the value the storage resource provides to the system, private investors will simply not invest in building storage projects in Massachusetts…. The biggest challenge to achieving more storage deployment in Massachusetts is that there is a lack of clear market mechanisms to transfer some portion of the system benefits… to the storage project developer.”

This is the main problem addressed by the study’s policy and program recommendations, which fall into two broad categories: (1) recommendations to expand deployment of advanced energy storage in the state, and (2) recommendations to grow the energy storage industry.

The deployment-oriented recommendations include grant and rebate programs, such as doubling funding for demonstration projects from the previously-announced $10 million to $20 million; offering $20 million in rebates for customer-sited storage out of state ACP funds; dedicating $150,000 to support commercial/industrial feasibility studies; awarding the remaining $14.2 million in DOER’s Community Clean Energy Resiliency Initiative budget; and allocating $4.5 million in demonstration project grants for utilities and market actors to demonstrate peak demand management.

The study also recommends adding storage as an eligible technology within the existing Green Communities Grant, Alternative Portfolio Standard, and Next Generation Solar Incentive Programs, and allowing storage to be included in all future long-term clean energy procurements.

There are also recommendations that the state clarify the regulatory treatment of utility storage, including the treatment of storage in grid modernization plans; adopt storage safety and performance standards; clarify interconnection requirements; facilitate sharing of electricity customer load data and use cases by facility type; and create an advanced storage working group at ISO-NE to remove regulatory and market barriers that keep storage from participating in regional wholesale energy markets.

Recommendations to grow the energy storage industry in Massachusetts include creating an energy storage cluster and expanding the MassCEC investment programs to support energy storage companies; expanding MassCEC’s workforce training programs; and engaging the state’s universities to support energy storage startups in Massachusetts and invest in research and development and testing facilities to anchor an energy storage cluster.

The bottom line is that Massachusetts — assuming programs and policy making follow this study’s recommendations — is about to throw nearly every tool in its considerable policy toolbox at the problem of how to make energy storage go, and go big, in the Commonwealth.

The study is a landmark product, not just for Massachusetts, but for all states; and it serves as an example of what can and should be done to move our electricity grids out of the 19th century and begin leveraging real and significant support for technologies that will save money, improve reliability and resiliency, reduce greenhouse gas emissions, and support the transition to renewables and distributed generation.

But no report is perfect; so what’s missing from this one? Well, for one thing, there is no mention of how to make the benefits of energy storage accessible to low- and moderate-income communities, which need energy cost savings and resiliency the most; nor is there any discussion of storage in multifamily affordable housing, where it can provide both resilient power and economic benefits.

Given the Baker-Polito Administration’s heralded $15 million Affordable Access to Clean and Efficient Energy Initiative — a cross-cutting initiative designed to focus the state’s multiple energy and housing agencies on expanding clean energy opportunities for low- and moderate-income residents — this omission may be remedied during implementation.

And there is still the open question of whether the state will implement measures to reach the modeled, economically optimal, storage deployment level of 1.766 GW. Between the report’s policy recommendations and new enabling legislation, the state may have the new tools to get there. How far it will actually go, still remains to be seen.

On the whole, though, the report is an impressive piece of work — the kind of thorough analysis other states should look to when teeing up energy storage policy development. And if even half the report’s recommendations are quickly implemented, it will position Massachusetts as a clear leader in the development of meaningful energy storage policy, programs, and deployment. It’s now up to other states to follow Massachusetts’ example.

Clean Energy Group and the Clean Energy States Alliance (CESA) are working to support MA DOER and MassCEC in their energy storage and resilient power initiatives, by providing technical assistance directly to municipal awardees of DOER’s Community Clean Energy Resilience Initiative, and by providing policy and program development support to both agencies, through the Energy Storage Technology Advancement Partnership (ESTAP) and Resilient Power Project. ESTAP is supported by US DOE-OE through a contract with Sandia National Laboratories, while the Resilient Power Project receives foundation support.

Lead image credit: AES Energy Storage

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NEWS: Corporations Take Advanced Energy Into Their Own Hands; Solar + Storage like Peanut Butter and Chocolate

apple-solar-arizona.jpg

Apple’s new 50 MW solar farm, built in partnership with AEE member First Solar, will supply Apple’s data center in Arizona.

They say, “if you build it they will come,” but in the case of advanced energy, they might just build it themselves. Major companies are making major investments in renewable energy development: Amazon, Johnson & Johnson, and Apple are upping their commitments. Plus, energy storage (and particularly solar + storage) continues to change the game. That’s what in the news this week.

The wind blows strong in West Texas. After last week’s announcement from Johnson & Johnson about the purchase of 100 MW of wind generation power from a West Texas facility, this week, AEE member Amazon announced it would be the primary investor in a 253 MW wind farm there. The wind farm is called, appropriately enough, Amazon Wind Farm Texas, and it is Amazon’s largest advanced energy project to date, though certainly not their first. We previously reported on the 208 MW Amazon Wind Farm U.S. East, in North Carolina, which began construction last year, and is expected to go online in December. Additionally, the online retailer has a solar farm in Virginia expected to come online in October, a 150 MW wind farm in Benton County, Ind., and another wind facility in Ohio. Together, these five facilities will generate enough power for 150,000 U.S. homes annually, which, according to Amazon, is slightly larger than the size of Cleveland, Ohio.

Amazon has committed to purchasing 90% of the power generated at the Texas wind farm, which will be owned and operated by Lincoln Clean Energy. The project is expected to start delivering power to the grid in late 2017.

For its part, AEE member Apple reaffirmed its corporate commitment to 100% renewable energy this week. Computerworld reports that the company has joined RE100, which is an international effort to have corporations set public goals to procure 100% of their electricity from renewables by a specified year.

“Apple is committed to running on 100 percent renewable energy, and we’re happy to stand beside other companies that are working toward the same effort,” said Lisa Jackson, Apple’s vice president for Environment, Policy and Social Initiatives. “We’re excited to share the industry-leading work we’ve been doing to drive renewable energy into the manufacturing supply chain.”

The company announced its intention to have its manufacturing supply chain entirely powered with renewable energy last yearWall Street Journal’s Digits blog reported at the time that Apple’s supply chain used 60 times as much power as the company’s facilities. All of Apple’s U.S. data centers and corporate facilities have been powered by renewable energy since 2014. As of 2015, all of Apple’s U.S. facilities and 93% of its global operations are entirely powered by renewable energy. Just this week, the company unveiled a new solar farm (pictured above) that will power its Arizona data center. According to Apple’s press release, its suppliers’ commitments to renewable energy will represent more than 1.5 billion kilowatt hours per year by the end of 2018.

As companies like Apple, Amazon, and Johnson & Johnson sign power purchase agreements, build rooftop solar installations, install energy storage solutions, and develop fuel cell facilities, impressive national growth trends obscure the important fact that, in many states, the options to pursue such projects are limited at best. Earlier this year, Advanced Energy Economy Institute commissioned Meister Consultants Group (MCG) to consider opportunities to increase corporate access to advanced energy through policy changes at the state level. What MCG found is six policies that would give corporate purchasers the renewable energy they are looking for, and 11 states that could reap the benefits of the advanced energy development that would result. You can download that report here.

Meanwhile, in energy storage, AEE member Tesla had a very good week. The company’s first grid-scale Powerpack storage system in Europe was brought online in Somerset, England, to provide ancillary services to the grid. Energy Storage News quotes Chris Roberts, director at Poweri Services, which was involved in the construction, “It’s a great modular technology I must admit. It’s slotted together like Lego really…It’s a very elegant product that’s been very well thought through. There’s nothing that I can see that would cause a problem in deploying these in large numbers.”

Southern California Edison might just agree. The utility announced this week that it had selected Tesla to build a storage system at the Mira Loma substation. The system, which will be able to store 80 MWh of energy, is expected to be operational by December 31. A spokesperson for SoCal Edison said the company was ahead of schedule in meeting its 2016 storage targets. The utility also has a project under development with another AEE member, AES Corp, which is building a 100 MW system at the Alamitos Power Center in Long Beach.

Here’s another saying to close us out: solar + storage go together like peanut butter and chocolate. That one might not be in common parlance just yet, but it’s true; just ask Duke Energy. As Greentech Media reports, Duke’s solar + storage microgrid test site in Charlotte North Carolina has “self-islanded” twice so far this year when the grid was threatened by extreme weather. The test site is a fire station connected to a substation with both a solar array and a lithium-ion battery. In two instances this year, the system was able to detect a threat to the grid, disconnect, and keep the lights on at the fire station until the grid was no longer at risk.

As Tom Fenimore, technology development manager at Duke’s Emerging Technology Office noted to Greentech Media, the grid didn’t go down in either instance, but that’s okay. “We don’t wait for the circuit to go down. We sense that it may go down and act accordingly,” he said. The point is not waiting for a disaster, but rather to be ready for it. Just another case of advanced energy making sure the lights stay on!

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Grid-Connected Energy-Storage Projects in Pipeline to Hit 2GW, Led by US, China and South Korea

Grid-Connected Energy-Storage Projects in Pipeline to Hit 2GW, Led by US, China and South Korea

Bottom Line

Energy storage pipeline advances are led by the United States, China and South Korea – the IHS Energy Storage Company and Project Database – Q2 2016 tracks 2 gigawatts (GW) of grid-connected energy storage projects — a 20 percent increase, since the end of 2015.

Lithium ion’s (Li-ion’s) share of the energy storage market has grown steadily from 20 percent deployed in 2010 to 90 percent forecast for 2016.

Roughly 300 megawatts (MW) — or 500 megawatt-hours (MWh) — of utility-side meter energy storage projects came online during the first half of 2016, for example the 50 MW (300 MWh) Buzen project in Japan, which was developed by Kyushu Electric and supplied by NAS batteries.

Driven by a surge in behind-the-meter installations in the United States, Australia, the United Kingdom, and Germany, IHS has revised our outlook for 2016 upwards to 1.8 GW, from 1.5 GW in our previous forecast.
IHS Insights

Owing to massive cost reductions, Li-ion technology is now leading lead-acid batteries in the power storage category; it is even challenging sodium sulphur and flow for long-duration storage. IHS estimates that 90 percent of the utility-side of meter energy storage projects tracked are based on Li-ion battery technology. Underpinning the rapid cost reduction is the build-up of the supply chain for batteries in the auto and power sectors. Competition between China’s BYD, GCL, South Korea’s Samsung SDI, LG Chem and Japan’s Panasonic is intensifying. In the residential space GCL has launched a battery system at $450/kWh (excluding inverter) in Australia, nearly matching Tesla’s announced price of $3,000 for a 7kWh system.

Li-ion is also gaining traction in the grid-scale market for longer duration, which has been historically dominated by sodium sulfur and flow batteries. IHS has observed grid-scale batteries prices for delivery in 2016 around $400/kWh to $500/kWh, including warranty and management system, with a further 30 percent reduction in the next 18 months. Nonetheless, flow battery manufacturers are scaling up their ambitions and betting on superior lifetime of flow battery technology, as evidenced by the announcement of the 200 MW/800 MWh Dalian demonstration project in China, led by Rongke Power and UniEnergy Technologies.

Although lead-acid technology continues to be used in emerging markets where lack of financing is the biggest barrier, we’re seeing lead-acid market share shrinking in developed countries, owing to the superior performance of Li-ion in terms of response time and longer life.

While equipment costs keep falling, policies favorable to energy storage are being implemented in a larger number of countries, driving up new demand in the power sector. In the United States, after the press announcement from the US administration to commit to 1.3 GW of energy storage deployment, Senator Martin Heinrich (D-NM) is set to introduce a draft bill that would grant a 30 percent tax credit to residential and commercial owners of energy storage. Policies are also announced in South Korea, which is considering mandating energy storage in public buildings, as well as allowing energy storage to participate in the South Korea wholesale power market.

View Original Post on EQ International: http://www.eqmagpro.com/grid-connected-energy-storage-projects-in-pipeline-to-hit-2gw-led-by-us-china-and-south-korea/