Tesla’s (NASDAQ:TSLA) ability to raise capital should mitigate fears over solvency. The $350 million equity and $850 million in convertible notes offers improved operating leverage with minimal dilution of approximately 4.6 million shares or 3% dilution. Not too bad considering expectations of generating futures revenues of over $12 billion in EVs.

In the big picture, let’s focus on how Tesla is positioned to leverage the additional capital and build the infrastructure to effectively compete in the EV, energy storage, solar and in particular, what IP can be gained from competencies in self-driving vehicles. Tesla’s position in energy storage is a differentiator in EVs where it commands the lead in battery efficiency and vehicle range. Tesla can gain a cost advantage by continuing to drive lower battery cost per kWh.

Tesla Vision can generate substantial value because of the competencies extended through image and sensor processing that are also a catalyst for AI. Tesla Vision is leveraging testing and data compiled from its relationship with Mobileye (NYSE:MBLY), recently announced target of acquisition by Intel (NASDAQ:INTC) for $15 billion. Image and data processing of numerous data points from RADAR, LIDAR, and cameras are complex requiring graphic floating-point intensive operations and neural network architecture. The capabilities gained through autonomous driving offer substantial competitive advantages that create additional value for Tesla.

Energy Storage and EV Performance

Tesla has improved its EV positioning as the leader in the EV market by extending the EV range battery efficiency can be measured by energy density or kW per kilogram of battery weight power duration. In practicable measures the vehicle range relative battery kWh size is a relevant measure. However, vehicle size and weight will have an impact on the range metric. To compensate for vehicle weight a measure of distance and weight may offer a more impartial performance metric. The following chart shows the battery kWh size relative to vehicle ton-miles similar to comparing freight costs.

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Many consider the sun the energy source of the future. But one challenge is that it is difficult to store solar energy and deliver the energy ‘on demand’.

A research team from Chalmers University of Technology in Gothenburg, Sweden, has shown that it is possible to convert the solar energy directly into energy stored in the bonds of a chemical fluid — a so-called molecular solar thermal system. The liquid chemical makes it possible to store and transport the stored solar energy and release it on demand, with full recovery of the storage medium. The process is based on the organic compound norbornadiene that upon exposure to light converts into quadricyclane.

‘The technique means that that we can store the solar energy in chemical bonds and release the energy as heat whenever we need it.’ says Professor Kasper Moth-Poulsen, who is leading the research team. ‘Combining the chemical energy storage with water heating solar panels enables a conversion of more than 80 percent of the incoming sunlight.’

The research project was initiated at Chalmers more than six years ago and the research team contributed in 2013 to a first conceptual demonstration. At the time, the solar energy conversion efficiency was 0.01 percent and the expensive element ruthenium played a major role in the compound. Now, four years later, the system stores 1.1 percent of the incoming sunlight as latent chemical energy — an improvement of a factor of 100. Also, ruthenium has been replaced by much cheaper carbon-based elements.

‘We saw an opportunity to develop molecules that make the process much more efficient,’ says Moth-Poulsen. ‘At the same time, we are demonstrating a robust system that can sustain more than 140 energy storage and release cycles with negligible degradation.’

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Energy storage lies at the heart of grid digitisation and is part of a larger trend of technologies that is disrupting South Australia’s network for the better, according to Terry Teoh, General Manager of Engineering at ZEN Energy.

Ahead of his presentation on monetising storage at the grid edge in Adelaide’s CBD at the Australian Energy Storage Conference, June 14 – 15 2017 at the new International Convention Centre Sydney, Mr Teoh said battery storage currently has strong market potential in South Australia and the National Electricity Market (NEM).

“Energy storage and the ability to perform peer transactions lie at the heart of grid digitisation and will drive the democratisation of energy, just as we are seeing the democratisation of services, media and R&D,” Mr Teoh says.

“Global experience shows that commercial behind the meter storage is challenging. Yet the market potential in South Australia, and more broadly in the NEM states, is significant.”

Mr Teoh and Zen Energy are undertaking a groundbreaking project demonstrating real-time optimisation and monetisation of battery storage in the NEM by connecting four high-profile Adelaide CBD buildings to 513kWh of behind the meter storage.

The four sites – the Art Gallery, State Library, Adelaide High School and the Adelaide City Council works depot in Thebarton – were chosen for their contrasting load and occupancy patterns, and their potential to apply battery storage in conjunction with solar and demand response.

In his interview for the Australian Energy Storage Conference, Mr Teoh said the $1 million project will play a defining role in opening up the commercial storage market, starting in South Australia.

“It will provide real implementation experience and benefit quantification of batteries located in commercial sites, monetising multiple value streams,” he says.

“It will turn a theoretical concept into a commercially executable reality for commercial and industrial customers looking for a lifeline to alleviate their energy price distress in South Australia.”

Zen has also been working on other battery storage projects including the ‘Big Battery Project’ which proposes installing a battery in Port Augusta capable of storing between 50-150MWh of energy. This is one of the projects aiming to address South Australia’s grid instability and the need for a backup if power is lost.

The South Australian Government has also recently released a $550 million comprehensive energy plan for the state that includes the construction of Australia’s largest battery.

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The City of Summerside has partnered with international tech giant Samsung to test a massive solar energy battery.

The pilot programs’ proponents are touting it as a first in Canada.

Samsung Renewable Energy Inc. and city made the announcement Thursday. The project will coincide with a solar energy project the city had previously announced for Credit Union Place (CUP) in an effort to shrink the facility’s massive electrical bill. The city pays more than $380,000 annually to power the facility and the battery and solar panels are expected to save the CUP a little more than $100,000 annually.

Thursday’s announcement was the culmination of a lot of hard work by a string of people from P.E.I. to Korea, where Samsung is based, said Summerside Mayor Bill Martin.

“This was a year in the making … our agreement for this project is 510 pages long, for Phase I. So it took a lot of work, a lot of back and forth. So I would say (I’m) a combination of extremely excited, proud and relieved,” said Martin.

Martin also said that this is phase one in what could be a three-part project with Samsung. It all depends on how this initial pilot project goes, but the two parties have signed a memorandum of understanding regarding all three phases.

Phase one involves constructing a shipping container-sized battery and integrating it into CUP’s electric system. The battery will be fed power from 1,300 solar panels the city plans to build on a portion of the facility’s current parking lot. The battery will store excess energy and pump it into the building during peak use hours.

To accommodate the build, one of the outdoor beach volleyball courts will be moved. The city does not expect to lose any parking spaces as a result of the solar panels.

Phase 2, if it happens, will include the construction of a new solar/wind farm. This phase would bump the percentage of electricity the city gets from renewable sources from 46 per cent to 70 per cent.

Phase three would include investment in more electric pilot projects, such as infrastructure for electric vehicles and a smart grid system.

Martin said he expects Phase 1 to be completed sometime this fall.

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Lithium-ion batteries are best positioned to meet the demand for energy storage over the next five to 10 years, but in the long run, other battery storage technologies will be needed for long-term energy storage and larger- scale applications.

That’s the word from Lux Research, which recently outlined up-and-coming battery storage technologies in a teleconference.

Right now, the need for storage is prompted by the growing use of renewable energy on the grid, said Chris Robinson, an analyst for Lux.

The amount of wind and solar on the grid has doubled, he said. Half the electricity added last year was wind or solar, driven largely by cost reductions. “Even just in the last 15 years, we have seen a big drop in the cost of solar modules. We don’t expect this trend to change,” he said.

However, the large amount of renewable energy being added to the grid is causing grid instability, Robinson said. With solar, there’s instability in the morning when there’s often too much solar coming online. And in the evening, the grid becomes unstable when the amount of solar decreases.

“Energy storage can play an important role,” he said.

The use of Lithium-ion batteries is growing quickly because prices have dropped due to increased economies of scale and larger production capacities. But Lithium-ion batteries can’t solve all problems, and are often not appropriate for large-scale and long-duration applications, he said.

For example, a large solar project in China capable of powering 2,000 homes would need massive-scale storage, in the gigawatt-hour range, a task not suitable for Lithium-ion batteries, Robinson said.

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SDG&E is unveiling a new vanadium redox flow battery storage pilot project in coordination with Sumitomo Electric, which stemmed from a partnership between Japan’s New Energy and Industrial Development Organization and the California Governor’s Office of Business and Economic Development.

During the four-year demonstration project, SDG&E will be researching if flow battery technology can economically enhance the delivery of reliable energy to customers, integrate growing amounts of renewable energy and increase the flexibility in the way the company manages the power grid.

“SDG&E is continuously at the forefront of delivering clean energy solutions and championing innovative technologies to assess the long-term benefits for our customers,” said Caroline Winn, SDG&E’s chief operating officer. “This pilot will advance our understanding of how this flow battery technology can help us increase the reliable delivery of clean energy to our customers and align with state and local carbon emission reduction goals.”

The vanadium redox flow battery storage facility will provide 2 MW of energy, enough to power the energy equivalent of about 1,000 homes for up to four hours. Like other battery storage systems, the battery will act like a sponge to soak up renewable energy harnessed from the sun and release it when resources are in high demand.

Flow battery systems have an expected life-span of more than 20 years, and could have less degradation over time from repeated charging cycles than other technologies. SDG&E will be testing voltage frequency, power outage support and shifting energy demand.

“We are delighted to see our first flow battery system operating in the U.S. through the multiple-use operation of the battery system in SDG&E’s distribution network, we would like to prove its economic value and potential use on the electric grids,” said Junji Itoh, managing director of Sumitomo Electric.

“California continues to lead the nation when it comes to growing the economy and decreasing emissions,” said Sid Voorakkara, Deputy Director for External Affairs at the Governor’s Office of Business and Economic Development. “GO-Biz is proud to partner with NEDO to bring this demonstration project to life and increase opportunities for economic growth powered by renewable energy.”

SDG&E has been a leader in bringing energy storage options into the region with the recent unveiling of the world’s largest lithium ion battery storage facility in Escondido and a smaller facility in El Cajon. To date, SDG&E has about 100 MW of energy storage projects completed or contracted.

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Earlier this year we saw Maryland’s legislature stand for solar and other renewables with the override of Governor Hogan’s veto of the Clean Energy Jobs bill. This allowed for an increase in the state’s renewable portfolio standard to 25%.

Maryland has long been a national leader in renewable energy, but could the state become the next frontier in energy storage? In the current legislation session, Maryland’s House and Senate are now looking to encourage the adoption of energy storage technologies, which will be key to the future growth of renewable resources. There are three promising bills under consideration which seek to better understand and grow the market for this emerging technology.

The Bills

Of the three bills currently on the table, two of the bills seek to incentivize storage while the third hopes to better understand the technologies implementation and the best way to facilitate its growth.

1. HB1395 – Solar Energy Grant Program

HB1395 seeks to incentivize residential owners to purchase storage technology by allowing the Solar Energy Grant Program to award grants to certain energy storage equipment, effective as of October 1, 2017. The bill does the following:

• Defines storage technologies to include electrochemical forms of storage alongside compressed air, pumped hydropower, hydrogen storage, thermal energy storage, flywheel, a super conducting magnet, capacitor, or superconducting magnet.
• Sets a capacity standard for eligible technologies at a minimum of 5 kWh, with an applicable solar photovoltaic property defined at a capacity of 20kW or less.
• Establishes that the grant amount eligible to energy storage equipment will be the lesser of $3,000 or 30% of the total installed cost of the energy storage equipment.

2. HB0490/SB0758 – Income Tax Credit – Energy Storage Systems

Joint House and Senate bills HB0490 and SB0758, if approved, would allow for a credit against the State income tax for certain costs of energy storage systems on both residential and commercial properties; commercial properties is not defined. The credit would apply to systems installed between January 1, 2017 and December 31, 2021, coinciding with the ramp down of the federal Solar investment tax credit. The credits, as proposed, are as follows:

• For commercial properties, the credit would be the lesser of $150,000 or 30% of the installed system cost for commercial properties.
• For residential properties, the credit would be the lesser of $5,000 or 30% of the total installed cost of the energy storage system for residential systems.

3. HB0773/SB0715 – Clean Energy – Energy Storage Technology Study

Unlike the previously mentioned bills, which will jumpstart the market with incentives, joint bills HB0773 and SB0715 will require the Maryland Clean Energy Center to conduct a study on energy storage. The purpose of the study would be to understand what would be the most effective regulatory reforms and market incentives to increase the use of energy storage devices in Maryland in a way that is fair to all stakeholders, including the State government, electric companies, environmental organizations, providers of energy storage devices, developers, and other interested parties. The final findings of this report would be due on December 1, 2018 with an interim report due on December 1, 2017. Some of the key components of the study include:

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ComEd launched a pilot project to test the use of battery energy storagetechnology to reduce the impact of power outages in residential areas where customers experience service interruptions, particularly in extreme weather events.

ComEd’s Community Energy Storage pilot is being conducted in Beecher, Ill., about 40 miles south of Chicago. The pilot will focus on improving power reliability for customers experiencing multiple interruptions.

One of the first utilities in the nation to install CES, ComEd will also evaluate the potential of this technology to serve as a proactive tool to drive continuous improvement in service reliability.

“Through grid modernization and smart grid investments, our reliability performance has been best on record for five years running, and we’re committed to continuous improvement,” said Michelle Blaise, senior vice president, Technical Services, ComEd. “We want all ComEd customers to experience great reliability and that’s why we’re innovating and piloting emerging technologies such as energy storage to bring new value to communities and help improve service for our customers. We’re excited about the potential that battery storage offers to minimize the impact of a power outage while we continue to make progress in preventing them.”

ComEd is using the PureWave Community Energy Storage system from Chicago-based S&C Electric Co. Featuring a 25kWh lithium-ion battery, the CES unit was installed near the existing ComEd equipment that provides power to the homes of Beecher customers selected for the pilot. In the event of a power outage, the energy storage system will automatically restore power and has enough capacity to supply power to a group of customers for the duration of most typical outages. The momentary power outage when the battery storage takes over is barely perceptible while crews take the precautions needed to ensure a safe and seamless return-to-normal.

Blaise said that additional CES pilots are planned for the ComEd service territory. ComEd is also exploring the potential of energy storage to support the integration of renewable energy sources. The company received a $4 million grant from the Department of Energy to develop and test a system that integrates solar and battery storage with a microgrid, which is a small energy grid that can power a local, defined area in times of emergency.

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AGL has commissioned the first phase of what it claims is the world’s largest virtual power plant (VPP).

The project, in Adelaide, South Australia will be ramped up in three stage with 1000 Sunverge batteries installed across the city. The total storage capacity will reach 5MW/7MWh.

The AU$20 million (US$15.4 million) trial is one of a number of measures being undertaken to improve the security of the electricity network in South Australia. The state has been hit by price shocks and blackouts with extreme weather, reliance on one interconnection and even the large volume of renewables blamed for the problems.

“The VPP will deliver benefits for multiple groups, including: customers by reducing their energy bills; the network by lowering required capital investment to upgrade infrastructure; for AGL by providing another source of generation to deploy into the network with the balance used in our portfolio; and, the environment through reduced emissions,” said Andy Vesey, managing director and CEO, AGL.

According to the utility, customers taking part in the trial will save AU$500 a year.

Sunverge is also participating in an ARENA-backed VPP trial in Queensland.

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Of all the great initiatives that came out of South Australia’s energy plan on Tuesday, one thing doesn’t appear to make sense: why spend so much money on a peaking gas generator when storage options are clearly cheaper?

The big question was over these two sums: The $360 million in government monies set aside for a 250MW gas plant that might rarely be switched on, and the $20 million that treasurer Tom Koutsantonis says could be enough to get a 100MW battery storage facility built by the private sector before summer.

Surely, analysts and pundits say, spending more on battery storage is going to give a bigger and more immediate bang for the buck than the gas generator. And they won’t become a redundant asset as the gas peaker threatens to be in as little as five years time.

In theory, those sums suggest, South Australia could cause some 1.8GW of battery storage to be built for the same taxpayer funds as a gas generator. Of course, it is much, much more complex than that.

The reality is that the $150 million set aside in the new Renewable Technology Fund is probably going to support more battery storage than can be sustained under current market rules. (Indeed, some of it is earmarked for solar thermal, pumped hydro or even hydrogen).

Battery storage – in current market rules – will trade only on energy market volatility and the arbitrage between high and low prices (fill it up with cheap excess wind and solar and sell it at high, peak demand prices).

The more storage that is added, then the less volatile the market will become, and the less money that can be made.

So storage will probably not be fully economic and widespread until the overall market rules are changed and battery storage technologies can access its multiple value streams.

This will come from rule changes such as dumping the 30 minute settlement in favour of a 5 minute settlement, and the introduction of a new ancillary service market, and maybe for grid augmentation.

Then there will be nothing stopping it, although longer-dated storage such as solar thermal, pumped hydro or even hydrogen will also be needed at various points in the transition to 100 per cent renewable energy.

But it is the volatility that the South Australia government wants to kill as soon as it can. The state has always had a volatile electricity market, courtesy of its stringy network, daytime manufacturing and high air con use.

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