Black & Veatch has been selected to serve as owners’ representative for an energy storage facility at the San Vicente Reservoir near Lakeside in San Diego County, California. The project owners, the San Diego County Water Authority and the City of San Diego, are assessing the potential to develop the 500 MW San Vicente Energy Storage Facility to increase the availability and efficiency of renewable energy for the region. It will provide enough stored energy to supply approximately 325,000 homes annually.

As the owners’ representative, Black & Veatch will help evaluate proposals, select the full service team and negotiate the project delivery agreement.

The SVESF will store energy by pumping water to an upper reservoir when energy demand is low and releasing water from the upper reservoir through turbines when energy demand is high. The pumped hydro energy storage solution would support power grid operations and enable significant and sustained integration of renewable wind and solar energy into the power supply mix. It would also generate revenue that could help reduce upward pressure on water rates driven by aging infrastructure.

The SVESF project involves the establishment of a small reservoir above the existing San Vicente Reservoir as well as a tunnel system and underground powerhouse to connect the two reservoirs. The powerhouse would contain reversible pump-turbines that would lift water to the upper reservoir or generate energy as it flows down.

During peak energy demand, water would flow downhill to turn hydroelectric turbines. During off-peak periods, including daytime when renewable energy supplies exceed demand, water would be pumped to the upper reservoir.

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What are energy storage projects under federal law? Are they eligible for certain favorable long-term contracts with utilities? Or are they subject to less attractive rules and regulations that apply to solar energy?

That’s the question that Franklin Energy, which develops distributed energy resources, is asking in Idaho, where it has proposed four energy storage facilities, each 25 MW.

In doing so, Franklin Energy is raising fundamental questions about how energy storage, a relative newcomer on the energy scene, fits in with a 40-year-old law known as the Public Utility Regulatory Policies Act, or PURPA.

PURPA requires electric utilities to buy power from other producers, if the cost is less than or equal to the utility’s avoided cost rate to the consumer. Right now, most energy storage projects are developed by utilities, businesses and for pilot projects. However, as prices for energy storage drop, more and more energy companies like Franklin Energy are expected to propose projects and seek contracts with utilities. That’s most likely to happen in areas where energy storage is less expensive than the utility’s avoided costs, or the marginal costs of producing power.

Now before the Federal Energy Regulatory Commission (FERC), the issue involves four energy storage facilities, each owned by a different entity. They meet the standards for being qualifying facilities (QF) that, under PURPA, are eligible to seek contracts with utilities.  The question is: Should they receive Idaho Power’s more attractive long-term contracts and rates?

The precedent-setting case raises interesting questions about the definition of energy storage projects as qualifying facilities, said Richardson.

“This is the only PURPA battery storage project in the country that I could find,” he said. All the other battery projects he could identify are utility-owned, developed for companies’ own use, or pilot projects.

Franklin Energy knew it was taking a risk when it proposed the projects as qualifying facilities and waded into unknown territory, he said.

“We’re making this a shotgun wedding under PURPA. We knew what we were getting into,” Richardson said.

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NEW DELHI–(BUSINESS WIRE)–AES India, a subsidiary of The AES Corporation (NYSE:AES), and Mitsubishi Corporation today started construction on India’s first utility-scale energy storage system, a 10 megawatt (MW) solution that will serve the electric grid operated by Tata Power Delhi Distribution Limited (Tata Power-DDL). AES and Mitsubishi Corporation will own the Advancion storage solution, which is being supplied by Fluence. The solution is being deployed in Rohini, Delhi at a substation operated by Tata Power-DDL. Once completed later this year, the 10 MW solution will enable better peak load management, add system flexibility, and enhance reliability for more than 7 million customers in the Delhi region.

Fluence, an energy storage technology and services company owned by Siemens and AES, will supply its Advancion technology platform for the project. Tata Power-DDL and its customers will benefit from Fluence’s proven and industrial-strength storage technology, which was designed for long-term dependability. Fluence brings more than a decade of grid-scale battery-based energy storage experience to the project, with nearly 500 MW deployed or awarded across 15 countries.

“AES has always been an innovative company, providing safe, reliable and affordable energy to the markets we serve. The deployment of cutting-edge energy storage technology in India shows the commitment we have to the country. Adding Fluence’s Advancion energy storage solution will allow us to continue to contribute to the modernization and enhancement of the electricity system in India,” said Mark Green, President of AES’ Eurasia Strategic Business Unit.

“Tata Power-DDL has introduced several firsts in the distribution sector and implemented various smart grid technologies. We are privileged to implement India’s first utility-scale storage solution in collaboration with AES and Mitsubishi Corporation. The first of its kind system will help to create a business case for the deployment of storage in India, to address challenges in the areas of peak load management, system flexibility, frequency regulation and reliability on the network. This project will provide a platform to demonstrate energy storage as a critical distribution asset and help to balance distributed energy resources, including rooftop solar,” said Mr. Praveer Sinha, CEO and Managing Director, Tata Power-DDL.

India’s renewable energy sector is experiencing remarkable growth and India recently expanded its renewable energy target to 175 gigawatts of solar and wind generation by 2022. Deploying energy storage will help network operators mitigate solar and wind resources’ variability and reduce congestion on the region’s transmission system, delivering more affordable, clean energy and enabling new sources of revenue from frequency regulation and other grid services.

“We are happy to have the opportunity to work alongside Tata Power-DDL and AES in launching this emerging and critical technology in India. Together with our partners, we look forward to demonstrating different applications in which battery-based energy storage can add value for both the power grid and the people of India,” said Tsunehiro Makabe, General Manager of Mitsubishi Corporation’s Environmental Energy Business Department.

“The Fluence team has delivered the first grid-scale battery-based energy storage systems in ten countries over the last decade, and we are proud to continue that trend in India in partnership with AES, Mitsubishi Corporation and Tata Power-DDL,” said Stephen Coughlin, CEO of Fluence. “With our Advancion platform, Tata Power-DDL will be adding a valuable new resource for flexibility, reliability and efficiency in its system.”

The deployment of its first grid-scale energy storage represents the latest step forward in modernizing India’s power system and improving grid efficiency. AES, Mitsubishi Corporation, Tata Power-DDL and Fluence look forward to demonstrating the benefits of battery-based energy storage to India and its government with this groundbreaking project.

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New government funding totaling £42 million ($58.5 million) has been released today to the newly founded Faraday Institution to support further battery storage research.

The monies are part of a wider £246 million Industrial Strategy intended to boost the U.K.’s battery know-how and scale-up capabilities. Four U.K.-based consortia will receive funding to support their application-inspired research aimed specifically at overcoming current challenges in acceleration of the electric vehicle (EV) industry.

The Faraday Institution is an independent national battery research institute that will utilize government funding to help establish Britain’s fledgling battery storage industry. From education and training to R&D and commercialization, the aim of the scheme is to place the U.K. at the forefront of global battery technological excellence.

Initial focus is to be on EVs and developing bespoke batteries that can expedite the growth of this sector as part of the U.K.’s decarbonization drive. “With 200,000 EVs set to be on U.K. roads by the end of 2018, and worldwide sales growing by 45% in 2016, investment in car batteries is a massive opportunity for Britain and one that is estimated to be worth £5 billion by 2025,” said Business Minister, Richard Harrington.

The minister added that government investment through the Faraday Institution will help to deliver the necessary research to allow the U.K. to seize economic and commercial opportunities in battery technology.

The four projects that will receive the funding were settled upon following consultation between the Faraday Institution and industry, so as to ensure that the needs of the commercial sector will be met. In addition to the government-backed funding, a further £44.6 million is expected from industrial partners to help support the research.

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The automakers’ efforts share several common concerns. They are looking to extend the life of batteries that are no longer useful in an electric vehicle but have enough juice left to store power for a household or provide residential backup power. They are working toward energy systems that allow for a more sustainable energy ecosystem for electric vehicles. And, by increasing the market for batteries, they hope to improve the economies of scale of battery manufacturing and drive down costs.

Audi, for instance, said its recent announcement will help it move closer to providing “emission-free premium mobility.” That could also be a strong selling point among customers looking to purchase an electric vehicle as an EV is only as green as the network that provides the power to charge it.

Overall, most auto makers’ participation in the stationary storage market takes the form of pilot projects. There are exceptions, such as Tesla, which has a separate energy storage division, but most auto makers are trying to find ways to generate more revenue through electric vehicles, or make those revenue streams available to their customers, Chris Robinson, an energy storage analyst at Lux Research, told Utility Dive. In most of the pilot projects, the manufacturers “are trying to find a way to make EVs more affordable,” he said.

Recent announcements by Audi and Nissan follow earlier plans unveiled by Tesla, BMW and Mercedes Benz. Tesla, in April 2015, became the first auto maker to enter the energy storage market with the introduction of its Powerwall system. Last May, Tesla said it would combine Powerwall installations with its commercial scale Powerpack batteries as a way of aggregating storage capability and make it more useful for balancing the grid.

In June 2016, BMW said it was entering the market for home storage by making its i3 high lithium-ion batteries available to households. The car maker said it could potentially expand the program to include its re-purposed 2nd Life Batteries, as they become available in the market. The systems can be used to store power from a rooftop solar system or they can be used as a source of backup energy for a home charging station for electric vehicles.

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France-headquartered multinational utility ENGIE has followed up acquisitions in smart energy by incorporating three companies, including commercial energy storage provider Green Charge, into its parent brand with the explicit aim of furthering its position in North American markets.

The three, all headquartered in the US, are: Green Charge (also sometimes known as Green Charge Networks), a Washington-based energy data analytics and optimisation company, Ecova, and Opterra Energy Services, which installs energy efficient solutions for customers, including solar panels and LED lighting.  

ENGIE said the rebranding of the three “is designed to amplify ENGIE’s voice in the North American market” and raise the visibility of the parent company in each of the acquired subsidiaries’ fields. It appears the utility is happy with its profile in the utility-scale and distributed generation sectors, but wants to “build an even more comprehensive portfolio of energy offerings in North America”. In a 2016 corporate blog, ENGIE said that all three acquisitions had been “strategic transactions aimed at delivering broader value to energy consumers”.

Green Charge will now be known as ENGIE Storage Services NA, continuing to be headquartered in Santa Clara, California. The company was recently identified by research firm IHS Markit as one of three leaders in commercial and industrial (C&I) energy storage in the US, with a value proposition based around lowering business clients’ energy costs through peak shaving – managing the expensive demand charges levied onto commercial electric ratepayers that can constitute as much as 50% of a company’s power bills. Green Charge also accrues further revenues through provision of grid services, particularly in helping reduce the network’s peak load. ENGIE took an 80% majority stake in the company two years ago.

As with the other two leaders in the US C&I space, Advanced Microgrid Solutions and Stem Inc, I.H.S Markit analyst Julian Jansen said that critical to their success so far has been the offering of energy storage “as-a-service” – in basic terms, creating long or medium-term agreements with customers to save them money through something akin to a subscription model, as opposed to selling equipment outright to customers to operate the assets themselves. Green Charge has executed dozens of projects on this basis, mainly in California, although the company is also the supplier of 13MWh of aggregated small-scale systems for a project in Brooklyn-Queens, used to mitigate peak demand in the New York neighbourhoods for utility ConEdison. 

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In December 2016, Panasonic and Tesla finalized an agreement to begin manufacturing solar PV cells and modules at the “Gigafactory 2” in Buffalo, New York.

Under the arrangement, Panasonic agreed to cover the capital costs associated with the factory and Tesla agreed to purchase Panasonic’s custom-manufactured solar products.

“These high-efficiency PV cells and modules will be used to produce solar panels in the non-solar roof products,” according to Tesla’s statement. “When production of the solar roof begins, Tesla will also incorporate Panasonic’s cells into the many kinds of solar glass tile roofs that Tesla will be manufacturing.”

Production of Tesla’s Solar Roof product did not begin for months after the initial announcement. But one year later — following delays and a brief trial run — Panasonic reports that cell manufacturing for the solar roof is now officially underway.

“Panasonic is already inside that factory making solar panels. That started in October of last year,” said Peter Fannon, vice president of technology policy at Panasonic Corporation of North America, in an interview at CES. “Also, we are just now beginning to manufacture cells.”

The Japanese multinational made an initial $260 million investment in the Buffalo facility, where it makes HIT (heterojunction with intrinsic thin layer) solar cells for Tesla. With the plant now up and running, Panasonic is prepared to invest more.

“We expect that investment, along with Tesla, as it grows, will grow with it,” Fannon said.

But it’s unclear how much growing is going on. 

Tesla completed the first solar roof installations on the homes of executives and employees in August. Little was heard about the solar roof after that, save for reports of several more installations for employees. The tiles were initially produced at small scale at the former SolarCity pilot production line in Fremont, California.

Last summer, Tesla CTO JB Straubel said solar roof production at Gigafactory 2 would ramp up “in a substantial way” by the end of 2017, and increased the company’s goal to achieve 2 gigawatts of solar panel capacity per year. But as the new year arrived, the status of Tesla’s solar tile production was still murky.

Tesla confirmed today, however, that solar roof manufacturing began in Buffalo in December. The company also said that it is now starting Solar Roof Textured and Smooth installations for non-employee homeowners.

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Energy storage’s unique operating characteristics — it can be load or supply — have made market participation a complicated problem. But California now has interim rules designed to address some of the difficulties and to ensure storage resources are providing all the services they can while also being properly valued. 

In the order, the CPUC acknowledged that current market rules, including utility standard contracts and program tariffs, fail to support the ability of an energy resource to access more than one service. Known as “stacking,” it would include incremental values to the wholesale market, distribution grid, transmission system, resource adequacy requirements and customers.

“As a result, energy storage cannot realize its full economic value to the electricity system even though it may be capable of providing multiple benefits and services,” according to the CPUC order.

The order adopted 11 interim rules, which state that “resources interconnected in the customer domain may provide services in any domain.” Resources interconnected in the distribution domain may provide services in all domains except the customer domain, with the possible exception of community storage resources.

“Resources interconnected in the transmission domain may provide services in all domains except the customer or distribution domains,” the rules continued. Resources interconnected “in any grid domain may provide
resource adequacy, transmission and wholesale market services.”

A report from Brattle Group last year identified regulatory barriers that needed to be addressed to realize the full potential of value stacking. The report, titled Stacked Benefits: Comprehensively Valuing Battery Storage in California, was prepared for Eos Energy Storage with funding from the California Energy Commission.

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On islanded (or isolated) grids with growing renewable penetrations, grid operators often struggle to maintain system stability. Operators in places as diverse as Ireland, Puerto Rico and Australia frequently rely on inertial response from thermal power plants like coal or gas-fired generators to balance sudden mismatches between supply and demand.

However, recent research from Northern Ireland’s Queens University Belfast (QUB) finds that battery-based energy storage can provide inertial response for system reliability much more efficiently, at a lower cost and with substantially reduced emissions than a much larger quantity of thermal generation.

QUB’s research found that just 360MW of battery-based energy storage could provide the equivalent stabilisation to Ireland’s All-Island electricity system as would normally be provided by 3GW of conventional thermal generation. That shift to batteries could save up to €19 million (~£16.9 million) annually and could achieve approximately 1.4 million tonnes of annual CO2 savings.

Inertia: A blink-of-the-eye grid balancing service

Inertia is a system-wide service that responds to fluctuations in electricity frequency in the first fraction of a second of an imbalance between supply and demand – for example, when a power station suddenly drops offline. Traditionally, this stabilising hand has come from the kinetic energy provided by the spinning mass of (synchronous) generators that produce electricity from fossil fuels.

All this occurs well within the first half a second of an issue – literally, the time it takes a human eye to blink. Traditionally the electric power sector has not thought of it as service. It’s just part of the physics of synchronous generators; and we don’t miss something until it’s gone.

As the proportion of energy from (non-synchronous) wind and solar grows this source of traditional ‘analogue’ inertia is in increasingly short supply. The typical solution to this has been to hold back wind and solar output during such times, but this is growing increasingly costly as renewable penetration grows. Let’s face facts: paying not to use zero-fuel cost and zero carbon renewables isn’t a tenable solution in the long run; and would require a significant overbuild of renewable capacity to achieve the same decarbonisation targets.

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