AMHERST — The state has awarded the University of Massachusetts Amherst a $1.14 million grant to build a large battery together with the company Tesla Energy.

The funding is part of $20 million in state grants awarded last week to 25 communities. The grants are part of a state initiative meant to improve the energy storage market in Massachusetts.

“The development and deployment of energy storage projects will be vital to the Commonwealth’s ability to continue leading the nation in energy efficiency,” Gov. Charlie Baker said in a statement. “Funding these storage projects is an investment in our energy portfolio that will reduce costs for ratepayers and help create a clean and resilient energy future.”

Tesla will design and construct the one megawatt/four-megawatt-hour lithium ion battery storage system at UMass as part of the 15-year project. The company will also provide $80,000 of educational opportunities for UMass students such as paid internships, career mentorship and curriculum development around the issues of solar and energy storage.

The battery will be located next to the campus power plant, and is meant to lower peak energy demand on campus, thus reducing the university’s reliance on the outside power grid.

“We’re very excited to be able to integrate a 1 MW lithium ion battery into our utility infrastructure on campus,” Raymond Jackson, the university’s physical plant director, said in a statement. “This project will help us optimize our on-campus renewable energy generation, increase resiliency and further diversity our utility portfolio.”

Currently, the campus receives 15 megawatts of power from the university’s central heating plant, which has a 10-megawatt solar combustion turbine, a 4-megawatt steam turbine, three natural gas boilers and a heat recovery steam generator. The campus also gets around 5 megawatts from solar panels around campus.

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California is considering energy storage to replace two peaking plants and one larger facility, the 580 MW Metcalf plant. It is not the first time the state has turned to batteries for a grid solution, but shows how the solution is becoming increasingly viable.

The Yuba City and Feather River plants are each about 47.6 MW, and are needed for capacity and high voltage sub-area shortfalls, respectively. Last month, CAISO determined that the entire Metcalf Energy Center was necessary for local reliability needs in a sub-area of the Bay Area local capacity area.

The CPUC proposal would order PG&E to hold at least one one solicitation to address “two local sub-area capacity deficiencies and to manage a high voltage issue in another sub-area.” The utility can solicit bids for energy storage and other alternative energy resources individually or in aggregation. 

Regulators have embraced energy storage in other recent situations to replace capacity, such as the Aliso Canyon gas leak. 

In May 2016, the CPUC directed Southern California Edison (SCE) to conduct an expedited procurement for both utility-owned and third party storage resources to address the Aliso Canyon gas leak and resulting generator shortages.

It’s not the first time SCE was asked to consider energy storage as an alternative capacity resource: in 2013, the CPUC required the utility to procure a minimum amount of energy storage and other alternative resources, related to the closure of the San Onofre nuclear plant, and wound up far exceeding it. For storage alone, SCE’s target was 50 MW and more than 260 MW were procured. 

Gas plants, and proposals to build new ones, are increasingly drawingregulatory scrutiny, especially after the Los Angeles Times investigated whether the state was overbuilding the resource. Earlier this year, NRG Energy asked the California Energy Commission to suspend its application to build the 262 MW Puente natural gas facility.

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2017 has been a big year for energy storage projects — Aliso Canyon, California’s six month rapid-fire deployment of 100 MW of storage in response to gas leaks, Tesla’s record breaking big battery bet in South Australia. Utilities across the globe are commissioning more and larger energy storage installations, from backup power supplies in island locations like Nantucket to E.ON’s most recent large project in Texas.

These big projects have been making big waves — but big profits are proving trickier. UK battery energy storage investors Foresight calculate that battery storage costs need to fall a further 30% to be truly competitive. Forging ahead, energy storage developers have had to seek other ways to make their projects economically viable.

The Rocky Mountain Institute in their 2015 white paper “The Economics of Battery Energy Storage” identify 13 value drivers in the sector — but the fast-paced nature of new developments and rapidly falling costs of technology mean the figures are already out of date. So how are developers making bankable projects in practice?

Solar developers SunRun in California have been seeing both profit and growth, using energy storage to add value to their rooftop solar systems. Anesco’s Clay Hill development in the UK, the first to forgo subsidies, also credits its success to energy storage. Leasing solar-plus-storage systems allows for both an ongoing income stream from consumer contracts and grid-balancing opportunities — Germany (SonnenFlat), Australia (GridCredits) and the UK (GridShare) are seeing promising early results.

Adding energy storage to existing generation sites (such as with Tesla’s South Australia installation) is another way to reduce overall costs. By taking advantage of existing transmission and distribution infrastructure, initial capital expenditure is reduced and revenue generating activities can start on an accelerated timeline.

Utilities are finding that the cost of energy storage is measured as much in what you don’t spend as what you do. Energy storage can be used to defer or avoid upgrading electrical transmission and distribution equipment (T&D deferral), as in the aforementioned Nantucket example. This value proposition is especially interesting for remote sites or emerging markets where reliable grid connections are not or cannot be established.

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Energy storage proved itself in 2017.

The industry stepped up with two major high-speed deployments to resolve grid emergencies. Utility-scale projects got bigger and longer-lasting. Major international conglomerates bought up storage startups. And all the major solar developers started getting into the game.

Much of the action remained at the pilot stage. But some projects showed that storage economics already make sense without subsidies, grants or other interventions — in the right circumstances, of course.

GTM will be diving deep on these themes at the Energy Storage Summit in San Francisco December 12-13. In the meantime, here’s a roundup of the key developments from 2017.

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State regulators want Pacific Gas & Electric Co. to replace three natural gas plants with energy storage, a move that represents another significant step toward a clean energy future.

The California Public Utilities Commission will vote Jan. 11 on the proposal that would require PG&E to seek clean alternatives to replace the three fossil-fuel plants.

Houston-based Calpine, which owns the plants, and the California Independent System Operator, which runs the state’s electric grid, argue that the gas-fueled plants are needed to ensure reliability in the local areas they serve.

The three Northern California plants — in Feather River, Yuba and Metcalf — don’t have long-term contracts with utilities, but have been identified by Cal-ISO as facilities that should remain in operation to support the electric grid when needed.

Regulators said in a press release Wednesday that any potential needs the natural gas plants provide can be met with clean energy, particularly battery storage.

“Energy storage is a clean energy resource that can be fast-responding, reliable and constructed in a short time frame,” the commission said in its statement.

In January, Tesla Inc. and Southern California Edison unveiled one of the world’s largest energy storage facilities, which was ordered up and installed in three months.

The Rosemead-based utility uses the collection of lithium-ion batteries, which look like big white refrigerators, to gather electricity at night and other off-peak hours so that the electrons can be injected back into the grid when power use jumps.

The facility at Edison’s Mira Loma substation in Ontario contains nearly 400 Tesla PowerPack units on a 1.5-acre site, which can store enough energy to power 2,500 homes for a day or 15,000 homes for four hours.

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The latest confirmed initiative supporting the restoration of power in Puerto Rico is the donation of 6MW of batteries from AES, which has suggested microgrids and large-scale solar could be the answer to long term stability issues.

The US island territory has been hit hard by hurricanes over the past few months, leading to controversy regarding various aspects of rebuilding, from Donald Trump’s twitter row with the mayor of the capital San Juan to the award of US$300 million in grid repair contracts to Whitefish Energy, a mostly unknown US company which brought an army of linemen and other subcontractors to Puerto Rico.

Amongst all of this, clean energy and energy storage companies including Tesla, Sonnen and Tabuchi America have been prominent in making equipment donations and contributing time and labour to local efforts. Energy-Storage.News was recently also contacted by PBES (Plan B Energy Storage), a company servicing the marine sector (powering boats), which has branched out into energy storage systems. PBES said it was in discussions with the governments of Puerto Rico and Barbuda “regarding the creation of resilient renewable power plants, using retractable solar panels and battery storage”.    

AES chief technology officer Chris Shelton confirmed to Energy-Storage.News recent reports that the company, one of the US’ biggest independent power producers (IPP) and an existing supplier of energy in the island territory, is making its own donation.

“We are in the process of shipping 6MW of transportable batteries in shipping containers to help stabilize renewable facilities and form microgrids where they can have the most impact,” Shelton said.

“Our goal is to deploy these resources where the power is likely to not come back anytime soon because of the damage sustained from the storm.”

According to Shelton, AES, which makes the Advancion grid-scale lithium battery energy storage platform via AES Energy Storage, will determine where the units, thought to be a megawatt each, will be deployed through consultation with regulatory authority PREPA “and other stakeholders”. Shelton said AES is committed to approaching potential communities once identified and working with local leaders.

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Sunverge Energy has deployed dozens of energy storage units at geographically dispersed locations across the service territory of Tokyo Electric Power Company (TEPCO) while managing them as a single virtual node on the grid.]

The net aggregated power flow at the virtual node level is controlled through coordinated operations at the individual unit level based on the predicted load, PV generation and available storage capacity. The project aims to demonstrate how centrally managed distributed resources on the Japanese electricity grid can help ensure greater reliability, an issue that received widespread attention following the Great East Japan Earthquake of March 2011.

The project, operated in cooperation with Mitsui & Co Ltd, connects multiple storage units into a Virtual Power Plant (VPP) managed by Sunverge’s energy management platform. This in turn provides the grid operator with an energy control system that can be adjusted within 15 minutes, or less, of major changes in demand. It will demonstrate several important abilities of the system:

Site Demand Target – The ability to maintain a target wattage reading at the individual meter level, dispatching power if the net load is greater than the target (i.e. load minus PV generation) or importing power if the net load is below the target.

Demand Charge Reduction – The Sunverge Demand Charge Reduction algorithm will set a Site Demand Target for the unit based on the forecasted load for the site, the forecasted PV for the site and the current battery stored energy. The resulting Site Demand Target value protects the unit from energy depletion due to dispatch and from reaching maximum stored energy capacity using power imported from the grid.

Virtual Power Plant (VPP) Demand Charge Reduction – Similar to the single unit Demand Charge Reduction use case, with the addition of certain operations performed in aggregate over multiple units rather than for an individual unit.

Sunverge’s energy management platform provides the energy control system required for the operation of the VPP. The VPP will function as an adjustment and supply source of the energy, addressing the demand for increased grid reliability.

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Two California energy storage providers say they are deploying networks of systems in Japan to help the country use more renewable energy.

Stem Inc., a California firm that provides energy storage solutions, said it’s deploying a network of systems with Mitsui & Co. Ltd., marking its first foray into Asian markets. The companies, which gained an endorsement from Japan’s Ministry of Energy, Trade and Infrastructure, will install a “virtual power plant” made up initially of aggregated storage systems that will supply 750 kilowatt-hours of capacity to the grid.

Sunverge Energy Inc., based in San Francisco, said it also is partnering with Mitsui to install dozens of energy storage units. The systems have been deployed in the service area of Tokyo Electric Power Co. and will use Sunverge’s energy-management service.

The projects are designed to help even out the fluctuations in solar and wind power in Japan as the country works to deregulate its electricity markets and ramp up renewables. Stem said it already has battery systems in California, Hawaii, Texas and New York.

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Energy storage deployments are growing rapidly, propelled by regulatory action, improving economics and utility moves to include the resource in their long-term planning. 

A total of 41.8 MW of energy storage projects were deployed in the third quarter, marking a 46% year-over-year increase from third quarter 2016, according to the latest Energy Storage Monitor from GTM Research and the Energy Storage Association.

There were also 10% more energy storage deployments in the third quarter than in the second quarter, which saw a total of 38.2 MW deployed, the report said.

Utility-scale projects lead

Utility-scale projects led the market in the third quarter, with a single 30 MW storage project in Texas accounting for about two-thirds of the quarter’s total. That also resulted in behind-the-meter installations taking a smaller share of the market, 26%, in the third quarter, compared with 42% in the second quarter.

In terms of duration, deployments dropped quarter over quarter as many utility scale projects had discharge durations of less than one hour. There were 42.5 MWh of energy storage projects deployed in the third quarter, a 5% increase year-over-year, but a 17% decline compared with the second quarter.

The Texas project put the Lone Star state at the top of the list for utility-scale deployments for the quarter. California topped the list for the non-residential market with 6.5 MW of deployments, and for the residential market with 1.87 MW of deployments. Hawaii ranked second in residential deployments in the quarter with 1.21 MW of projects and was third in non-residential deployments with 5 kW.

GTM expects a total of 295 MW of energy storage to be deployed in 2017, a 28% increase from the 231 MW deployed in 2016.

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Building solar, wind or nuclear plants creates an insignificant carbon footprint compared with savings from avoiding fossil fuels, a new study suggests.

The research, published in Nature Energy, measures the full lifecycle greenhouse gas emissions of a range of sources of electricity out to 2050.

It shows that the carbon footprint of solar, wind and nuclear power are many times lower than coal or gas with carbon capture and storage (CCS). This remains true after accounting for emissions during manufacture, construction and fuel supply.

“There was a concern that it is a lot harder than suggested by energy scenario models to achieve climate targets, because of the energy required to produce wind turbines and solar panels and associated emissions,” explains project leader Dr Gunnar Luderer, who is an energy system analyst at the Potsdam Institute for Climate Impacts Research (PIK).

Luderer tells Carbon Brief: “The most important finding [of our research] was that the expansion of wind and solar power…comes with life-cycle emissions that are much smaller than the remaining emissions from existing fossil power plants, before they can finally be decommissioned.”

Carbon debt

Critics sometimes argue that nuclear, wind or solar power have a hidden carbon footprint, due to their manufacture and construction. This large “carbon debt”, and the related debt of energy, must be paid off if they are to cut emissions over their lifetime.

Factories churning out solar panels use large amounts of electricity, often sourced from coal-fired power stations in China. Wind turbines and nuclear plants need a lot of steel and concrete. And the centrifuges that separate nuclear fuel also rack up a big electricity bill.

Yet zero-carbon sources of electricity are not the only ones to have a hidden, indirect carbon and energy footprint.

For coal and gas, these lifecycle energy uses and emissions come from extraction machinery and fuel transport. Significantly, they also come from methane leaks at pipelines, well heads or coal mines. These lifecycle emissions continue, even if coal or gas plants add CCS, which also may not capture 100% of emissions at the power plant.

What’s more, the indirect energy uses and emissions of each technology will shift over time, due to changing fuel sources, advances in manufacturing and the evolution of global electricity supplies.

The new research, from lead author Michaja Pehl and colleagues, comprehensively measures the lifecycle energy use and greenhouse gas emissions of different sources of electricity, between now and 2050.

It then compares these hidden footprints in a world that cuts emissions in line with a 2C climate goal and a world that stops further climate action.

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