The first quarter was the biggest quarter ever in terms of energy storage installations, but it could also be the biggest quarter of the year, according to the latest version of the U.S Energy Storage Monitor released by GTM Research and the Energy Storage Association.

The first-quarter Energy Storage Monitor recorded 234 MWh of storage installations in the first quarter, a 944% increase compared with first-quarter 2016.

In terms of power rating, 71 MW of storage projects were deployed in the first quarter, a 276% increase over first-quarter 2016 and the second highest quarter since GTM and the ESA began tracking energy storage in 2013, beat only by installation in the fourth quarter of last year.

Much of the growth in the first quarter can be attributed to “the shift from short-duration projects to medium- and long-duration projects in the utility-scale market, along with a surge of deployments geared to offset the Aliso Canyon natural gas leak,” said Ravi Manghani, GTM Research’s director of energy storage.

The Also methane gas leak jeopardized the flow of fuel for gas-fired generation, so the California Public Utilities Commission in May 2016 granted fast track approval for 104.5 MW of battery-based storage systems Southern California Edison and San Diego Gas & Electric’s service areas to offset the possible curtailment of gas-fired generation.

While the speed and scale of the Aliso Canyon storage deployments is impressive Manghani says the industry “shouldn’t get too comfortable” with that scenario because there are not that many 10+ megawatt-hour projects in the 2017 pipeline, indicating that the first quarter may be the largest quarter this year.

The completion of large storage projects is also reflected in the fact that 91% of all deployments in the first quarter were front of the meter projects. Front of the meter installations also grew by 591% on a year over year basis, boosted by large projects in California, as well as Arizona and Hawaii.

In Arizona, Tucson Electric Power signed a power purchase agreement for a low cost solar-plus-storage project that features a 100 MW solar array and a 30 MW, 120 MWh energy storage facility.

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The DOE’s SHINES program is part of the agency’s Grid Modernization Initiative that aims to improve the resiliency, reliability and security of the nation’s power grid. SHINES itself is the first DOE funding program that looks exclusively at connecting renewable power to storage.

Austin Energy’s $4.3 million SHINES grant is the largest of six projects that have won a total of $18 million of awards the DOE program. The utility must also meet its renewable energy target of 55% by 2025.  

Younicos, working with the Austin project’s prime contractor, Doosan GridTech, is deploying its Y.Q software platform, which will communicate with Doosan’s Intelligent Controller using the Modular Energy Storage Architecture (MESA) open standard. Younicos says the seven Y.Cubes and Y.Converters represent being deployed on the project represent the company’s largest Y.Cube deployment in the U.S. to date.

The battery system will be sited in an east Austin neighborhood near both residential and commercial buildings and has been designed with multiple thermal management subsystems for maximum safety.

“Integrating energy storage with solar is becoming essential as we achieve our utility’s goal of 55% renewable energy by 2025,” Karl Popham, Austin SHINES principal investigator and manager of emerging technologies at Austin Energy, said in a statement. “The Austin SHINES program is more than a technical pilot; it is phase one of a larger rollout to maximize the value of distributed energy resources for our customers and the utility.”

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As battery costs decline and new control technology allows more value to be captured, the storage sector is expected to undergo rapid growth. 

8minutenergy points out that its move “aligns with industry forecasts,” including GTM Research estimates predicting U.S. energy storage capacity will reach 655 MW in 2018 and exceed 2 GW in 2021.

The company, already the largest independent renewables developer in the country, is working with manufacturers to offer lithium-ion and flow batteries, flywheels, and other storage resources. And 8minutenergy said it has also expanded its existing solar research facility by adding energy storage facilities to test performance innovations and grid balancing capabilities.

“We are working on storage solutions that are already cost-competitive across the board, improve energy yield, and maximize renewable incentives. Now with fully dispatchable renewable energy, we can complement any existing utility portfolio,” said 8minutenergy Vice President of Storage Integration Carl Stills.

8minutenergy boasts that members of its team have “initiated and/or managed” several of the country’s largest energy storage projects, including a 30 MW lithium-ion energy storage project in the western U.S., and the first utility-scale wind and storage project in Hawaii.

In April, the company announced it had received approval on a power purchase agreement to develop the 90 MW (AC) Springbok 3 Solar Farm, located in Kern County, Calif. 8minutenergy signed the Springbok 3 PPA with the Southern California Public Power Authority on behalf of its participating member, the Los Angeles Department of Water and Power.

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Just over a year ago, Wartsila entered the solar power business, offering solar PV plants of 10 MW and higher and hybrid generating plants that combine solar panels with internal combustion engines.

The company has now added energy storage to its portfolio. The company says the storage can be used for spinning reserves, allowing the generating plant to be operated at higher loads with better fuel efficiency and lower emissions.

The storage capability also allows the hybrid facility to sell grid stability services thereby generating additional revenue.

The new hybrid plant offering comes on the heels of the first completion of such a facility — a 50 MW gas turbine with 4.3 MWh of energy storage operated by Southern California Edison. 

Wartsila sees a growing market for storage, especially in the U.S., U.K. and Eastern Europe and particularly in regions where both fuel prices and renewable energy penetration is high.

Wartsila in July 2016, entered into an agreement with Greensmith Energy, which will provide energy management system software to control its storage devices.

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The notice for next week’s Federal Energy Regulatory Commission (FERC) conference on the intersection of wholesale energy markets with state energy policies says that there is an “open question of how the competitive wholesale markets, particularly in states or regions that restructured their retail electricity service, can select resources of interest to state policy makers while preserving the benefits of regional markets.”

This is an intriguing understatement for a conference that provides at least a starting point for the hard discussion the energy sector must have about the need to catch wholesale market rules up with the reality of this country’s changing power generation mix.

How did we get here?

The states of wholesale energy market design and FERC, the federal agency that regulates that design, are in flux. Regional wholesale energy markets, intended to increase competition in the sale of energy and related services like capacity and reserves, were designed around the marginal cost of predictably dispatchable central station power plants with variable fuel costs.

During the several decades that most power plants exhibited these similar operating characteristics and natural gas prices were at least meaningful, coal and nuclear power plants proved successful in clearing markets to provide competitively priced energy. The last decade’s sustained plunge in natural gas prices, however, along with declining demand due to energy efficiency and an exponential increase in zero marginal cost wind and solar power plants coming online, and, to a lesser extent, the cost of environmental compliance for outdated fossil-fueled power plants, has dramatically altered the equation.

Coal and nuclear power plants that reliably cleared the markets have found themselves failing to recover costs, while natural gas rules the margin and wind and solar power and customers’ demand response contribute to lowering energy prices. The relatively rapid change has led to countless specific changes by regional market operators (buyer side mitigation battles, anyone?) trying to manage the transition as well as attempts by states like Maryland, New Jersey, and more recently, New York and Illinois, home to some of these failing power plants, to enact policies that protect their resources – with varying degrees of justified reliability and cost concerns.

Stepping back, it is fair to say that an increasingly severe disconnect exists between the services wholesale markets are designed to provide and the grid services necessary to reliably and cost-effectively support an electric grid increasingly powered by renewable energy resources. Determining and then monetizing the value of grid services necessary to support a renewables-dominated electric grid is critical to ensuring cost-effective reliability in our new world. (FERC and regional grid operators are by no means oblivious to this disconnect – next week’s conference is exhibit A, with B and C being efforts by regions like New England and PJM to get at the bigger market design issues, at least to the extent politically realistic.)

At the same time, pre- and post- presidential election events have FERC down to two commissioners, one short of quorum from a potential full slate of five. Acting Chairman LaFleur and Commissioner Honorable obviously recognize the urgency of the market reform need, but cannot act until at least one more Commissioner is appointed and confirmed.

It is at this crossroads from which the next stage of market reform must take form.  

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As part of its REV program, New York regulators recently issued an order on new structures for compensating distributed energy resources.

The order’s main focus is on community solar projects, but could eventually encompass the integration of standalone energy storage and small, local clean energy resources.

REV has already spurred a variety of projects, including a 1 MW, 4 MWh demonstration storage project in New York City being developed by Consolidated Edison in partnership with NRG Energy.

The state has also been funding other types of pilot projects as part of REV. Last month NYSERDA announced awards of $11 million for 11 microgrid projects in the state. In the first phase of that program 83 municipalities were awarded $100,000 to conduct feasibility studies for microgrids.

For the energy storage awards, NYSERDA will select the best projects to submit follow-up proposals for feasibility studies or for full demonstration projects. Initial concept papers will be accepted through March 1, 2020, or until all funds are committed.

NYSERDA is looking for papers that highlight technologies that are already commercially available and have the potential for replication throughout the state. The proposed projects must be able to demonstrate how they can support the state’s energy goals, including renewable generation and greenhouse gas reduction.

New York is targeting that 50% of the state’s electricity to come from renewable energy sources by 2030.

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In a famous children’s fable, a stuffed rabbit becomes real when its owner believes in it.

The nation’s utilities may now be similarly transforming battery energy storage.

The U.S. utility-scale battery storage installed capacity grew by another 221 MW in 2016 as costs continued to drop, according to a recent report from GTM Research and the Energy Storage Association.

More importantly, the sector last year doubled the amount of megawatt-hours (MWh) of battery capacity deployed compared to 2015.

This, analysts say, shows growth in the use of long-duration batteries and an increased confidence that the large energy storage facilities can be used to help manage peak demand.

“Growth remains steady, but 2016 was a turning point because the PJM frequency regulation market faded while demand for 4-hour duration storage capacity grew,” said report co-author Dan Finn-Foley, a GTM Research senior energy storage analyst.

The longer duration capacity growth was largely from California battery storage projects, Finn-Foley said. They were brought online in 2016 to address power grid needs created by the shutdown of the Aliso Canyon natural gas storage facility due to a methane leak in 2015.

Those batteries were rushed online to provide peak demand electricity that local power plants could not supply without natural gas from the Aliso Canyon facility. They represented 60 MW of the 221 MW added last year, but accounted for 168 MWh of the total 336 MWh deployed in 2016, according to Finn-Foley.

“With a 4-hour duration battery, a 20 MW energy storage system can deliver 80 MWh of capacity to meet a peak demand spike,” he said.

The fast deployment of those California grid-scale batteries — all sited, constructed and put into operation in nine months — has a number of analysts and sector insiders touting 2016 as a “turning point” for energy storage. But other say the true storage revelation is yet to occur as utilities discover how to better capture the multiple values of storage.

“The watershed event for energy storage will be when we can unlock multiple value streams from batteries,” said Stuart Laval, director of technology development at Duke Energy.

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North America has well over 20 GW of utility-scale PV with hundreds of MWs coming on yearly. Energy storage can help maximize the production of both existing and new utility-scale PV installations. In this free guide, Dynapower — the leading manufacturer of utility-scale inverters with over 350 MWs installed worldwide — provides a comprehensive overview of the three systems for coupling solar with storage — AC-coupled, hybrid plus storage, and a new approach DC-coupled with a converter. In addition to a system overview of each solution, Dynapower provides an analysis of the value streams each system type can bring online for installation owners to boost production and revenues.

All told Dynapower provides an overview of six energy storage enabled value streams — Clipping Recapture, Curtailment & Outage Recapture, Low Voltage Harvesting, Capacity Firming, Energy Time Shifting, and Ramp Rate Control.

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The list of automakers entering the market for stationary energy storage seems to get longer by the day.

The most recent entry is Daimler, the German manufacturer of Mercedes-Benz autos, which in November launched a separate unit, Mercedes-Benz Energy Americas, that plans to begin selling its stationary storage products to residential, commercial and utility consumers this year.

With its new North American business unit, Daimler is looking to leverage the entry it made into stationary storage in 2015 with its Deutsche ACCUmotive unit. In fact, in April 2016,  Daimler spun off Mercedes-Benz Energy GmbH from ACCUmotive in order to concentrate on energy storage applications.

The new unit will have plenty of competition. Daimler joins BMW, Nissan, Tesla and VW, which have also all entered the market for stationary energy storage.

All of those companies have at least two concerns that are driving their interest in storage: What to do with batteries that are no longer useful in an electric vehicle but still have plenty of useful life left in them? How do they improve the economies of battery manufacturing and drive down costs?

Stationary storage presents possible answers to both questions by opening up new markets for new batteries and for recycled or repurposed batteries.

The underlying theme is how to make the most of an asset—in this case the battery in an electric car—which can serve more than one use.

That is a theme touched on by Boris von Bormann, the new head of Mercedes-Benz Energy Americas, in an interview with Utility Dive. “How do we use the car’s capacity that is driving around? How do we monetize it in the energy markets? How do we make it available to the grid operator, a utility, a city?”

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