A detail in Lazard’s latest levelized cost ofstorage(LCOS) report has highlighted a little-known but potentially major issue for the lithium-ion battery industry.  

The financial advisory and asset management firm downgraded its estimates for lithium-ion round-trip efficiency to account for parasitic losses, GTM has discovered.

“As more battery systems are deployed, estimates of actual round-trip efficiencies are lower, and installation costs are higher than expected and than reported in last year’s LCOS 2.0,” according to the Lazard study.

“Consequently, estimates for total ‘Commercial’ use case LCOS rose slightly, despite [a] lower equipment cost estimate,” it states.

Lazard’s two previous LCOS studies had simply used the round-trip efficiency of the battery and power electronics since there was little reliable data on the heating, ventilation and air conditioning (HVAC) requirements of the system, Lazard said.  

Experience is beginning to show this parasitic load could be significant. By its LCOS 3.0 study, said Lazard, some published reports and estimates were providing a range of 80 percent to 90 percent round-trip efficiency for entire systems, including the cooling load. 

Figures for parasitic loss in lithium-ion battery systems remain notoriously hard to find. “It’s almost impossible to find detailed information on this subject,” said Hugh Sharman, principal at the energy consultancy Incoteco.

HVAC energy consumption levels will also vary between projects as different regions and usage levels require different cooling loads, Lazard noted.

One study of three battery systems in 2014, by experts from EA Technology and Northern Powergrid, hinted that electrical energy storage (EES) losses might be significantly higher than those used by Lazard in its calculations.

“The round-trip efficiencies for the EES systems have been calculated as between 83 percent and 86 percent, falling to between 41 percent and 69 percent where parasitic loads are included,” concluded the study.

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Over the last decade, Sunverge has become a preferred provider of home solar-battery systems to utilities. It rivals Tesla in scope and scale of its deployments, if not in its marketing hype. 

But just like Tesla, the startup has seen its share of struggles, albeit of a different scope.

While Tesla is seeking mass-market acceptance for its Powerwalls (and achieving decidedly mixed results in terms of keeping production on track with its sales) Sunverge has shifted from making its own battery units to providing software to utilities, in hopes of finding a niche as a trusted virtual power plant (VPP) platform provider. 

On Tuesday, the company announced three more utility customers, including two with some advanced interest in solving the solar-storage grid challenge. 

The first, Arizona Public Service, plans a neighborhood-scale installation of Sunverge One battery-inverter units, along with home energy controllers, to help balance the rising neighborhood-level swells and sags in customer-generated solar power throughout the day. 

This pilot is the latest in the utility’s long-running study ofstorage power electronics and communications to manage its rising tide of customer-generated solar power. The first round, a joint effort with the Electric Power Research Institute (EPRI), has been testing megawatt-scale grid batteries, as well as more than 1,600 advanced inverters. This next phase, known as the Solar Innovation Study, involves distributed energy resources at the residential scale, including rooftop solar, load controllers, HVAC systems and battery storage. 

The Sunverge One, the company’s basic 6.4-kilowatt, 11.8 kilowatt-hour lithium-ion battery and inverter unit, has a decidedly low-key feel, suggesting more of an outdoor air conditioning unit than Tesla’s futuristic turtle-shell wall mounting. That’s partly because it’s meant to be installed outdoors, and is rated to withstand the typical utility ranges of heat, cold and rain, and partly because Sunverge seeks to involve the customers as little as possible in the unit’s overall operation, beyond informing them how much it’s earned them over the course of time. 

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The energystorageindustry is set to rise dramatically — for those companies that can play the long game. 

Bloomberg New Energy Finance released a report Tuesday that forecasts the global energy storage market will “double six times” from now to 2030, from a meager starting point of less than 5 gigawatt-hours last year, to more than 300 gigawatt-hours and 125 gigawatts of capacity by the end of the next decade. An estimated $103 billion will be invested in energy storage over that time period.

The trajectory for energy storage mirrors the market expansion that solar went through from 2000 to 2015, when the share of solar PV as a percentage of total generation doubled seven times. 

This rapid global growth rate tracks well with the U.S. energy storage market forecast from GTM Research, which projects a twelvefold growth in the U.S. alone between 2016 and 2022, to reach 7.2 gigawatt-hours, or 2.6 gigawatts, of capacity. 

This growth is going to be driven by both cost reductions for batteries and associated systems, and a rising need for more gigawatts of flexibility to manage the ups and downs of an increasingly wind- and solar-powered grid, according to BNEF energy storage analyst and lead report author Yayoi Sekine. “With so much investment going into battery technology, falling costs and with significant addition of wind and solar capacity in all markets, energy storage will play a crucial part in the energy transformation,” she said.

On the cost side, BNEF sees utility-scale battery systems falling from about $700 per kilowatt-hour in 2016 to less than $300 per kilowatt-hour in 2030. That’s in line with other projections that see stationary storage benefiting from investments into the mass manufacturing of lithium-ion batteries for consumer electronics and electric vehicles.

On the demand side, 70 percent of global capacity through 2030 will be installed in eight countries: the U.S., China, Japan, India, Germany, U.K., Australia and South Korea. The primary driver in each will be managing an increasingly renewable and intermittent energy resource mix.

Earlier this month, BNEF released a report that illustrated how some of the most renewables-rich markets will be pressed to incorporate energy storage at record scale. The report found that “future energy systems in the U.K. and Germany with very high levels of variable renewable generation must be complemented by flexible resources, including energy storage.”

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Powin Energy, the Oregon-based energy storage developer, is expecting to see an uptick in non-recourse financing following a landmark project this month.

The company secured construction financing for an 8.8-megawatt/40.8-megawatt-hour battery plant in Stratford, Ontario, from Brookfield Renewable Partners, one of the largest independent renewable energy businesses in the world. 

“Securing non-recourse financing is a critical step for energy storage assets themselves, as well as the broader market,” said Geoffrey Brown, Powin Energy president, in a press release. “We believe that closing a deal of this nature with a well-respected group like Brookfield is indicative of market maturation and Powin’s future prospects.”

While the non-recourse funding model is commonplace in most renewable energy markets, the track record is more limited in energy storage. Only a handful of deals have made headlines.

Last year, for example, another Ontario project based on flywheels and lithium-ion batteries and built by Convergent Energy and Power was funded through a non-recourse finance package from CJF Capital and SUSI Partners’ Energy Storage Fund I.

“The facility reflects a non-recourse, third-party project financing structure for energy storage assets in a sector dominated by on-balance-sheet financing,” noted Convergent in a press statement.

Previously, non-recourse finance had helped fund Australia’s first utility-scale integrated solar and battery project, built by Conergy with backing from Norddeutsche Landesbank Girozentrale.

And in 2015, half the money for the Jake and Elwood battery storage projects developed by Renewable Energy Systems Americas came from non-recourse senior secured project financing debt.

Brown said he thought many energy storage projects since had been difficult to fund through non-recourse debt because of the nature of their contracts.

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Powin Energy, the Oregon-based energy storage developer, is expecting to see an uptick in non-recourse financing following a landmark project this month.

The company secured construction financing for an 8.8-megawatt/40.8-megawatt-hour battery plant in Stratford, Ontario, from Brookfield Renewable Partners, one of the largest independent renewable energy businesses in the world. 

“Securing non-recourse financing is a critical step for energy storage assets themselves, as well as the broader market,” said Geoffrey Brown, Powin Energy president, in a press release. “We believe that closing a deal of this nature with a well-respected group like Brookfield is indicative of market maturation and Powin’s future prospects.”

While the non-recourse funding model is commonplace in most renewable energy markets, the track record is more limited in energy storage. Only a handful of deals have made headlines.

Last year, for example, another Ontario project based on flywheels and lithium-ion batteries and built by Convergent Energy and Power was funded through a non-recourse finance package from CJF Capital and SUSI Partners’ Energy Storage Fund I.

“The facility reflects a non-recourse, third-party project financing structure for energy storage assets in a sector dominated by on-balance-sheet financing,” noted Convergent in a press statement.

Previously, non-recourse finance had helped fund Australia’s first utility-scale integrated solar and battery project, built by Conergy with backing from Norddeutsche Landesbank Girozentrale.

And in 2015, half the money for the Jake and Elwood battery storage projects developed by Renewable Energy Systems Americas came from non-recourse senior secured project financing debt.

Brown said he thought many energy storage projects since had been difficult to fund through non-recourse debt because of the nature of their contracts.

Following the Stratford deal, though, Brown told GTM he expected non-recourse funding to become the norm for energy storage projects with clear, fixed revenue streams.

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The Indian energy storage industry hopes a 28-megawatt-hour battery plant in the Andaman and Nicobar Islands will kick-start a utility-scale market that has been slow to emerge.

“This will help open up opportunities for such hybrid projects in India,” said Dr. Rahul Walawalkar, executive director of the India Energy Storage Alliance (IESA), after Indian EPC provider Mahindra Susten this month won the project tendered by state-owned coal mining company NLC India.

“With the development of a local ecosystem and skills training, we are confident that solar and storage will continue to have accelerated adoption in India in coming years,” Walawalkar said. “This should also help companies that are considering setting up manufacturing in India.”

IESA has a vision of making India a global advanced energy storage systems manufacturing hub by 2020, he said. Given India’s track record on utility-scale energy storage, the aim is ambitious, to say the least.

Prior to the Andaman and Nicobar project, the Solar Energy Corporation of India (SECI) and NTPC, India’s largest power utility, had already launched three other utility-scale energy storage tenders in the country.

However, “all these tenders, with aggregate capacity of 35 megawatt-hours, have been scrapped without any reasons being given,” noted analyst firm Bridge to India in a blog post.

“Our view is that storage will need three [to] four years of techno-commercial advancements before finding scale in India,” wrote the organization. 

The lack of progress on utility-scale storage in one of the most important renewable energy markets in the world is due to a mix of pricing challenges and lack of technical expertise, according to Bridge to India.

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Battery storage is breaking into an ever longer list of grid-scale configurations, as new business cases arise.

Every major solar developer has begun at least contemplating storage paired with solar, even if few large projects have yet been built. GE has already paired batteries with its gas generators for fast-ramping grid services; it expects the setup to prolong the life of the gas asset.

Last week the roster of possibilities expanded when two companies announced new storage plant combinations: batteries with solar and wind power to provide consistent electricity in Australia, and a hydropower plant-plus-storage to tap the challenging PJM frequency regulation market.

The onus is on the developers to prove these newfangled plants can make money, but they’ve already expanded the range of uses for grid storage technology.

Wind and solar and storage, oh my!

Windlab and Vestas will develop a solar-plus-wind-plus-storage project in Queensland, Australia called the Kennedy Energy Park by the end of 2018. This will include 43.2 megawatts of wind capacity, 15 megawatts of solar and 2 megawatts of storage.

That’s the first system of its kind that’s been publicly announced, said Hong Durandal, a business analyst covering hybrid systems at MAKE.

A single control system will operate all three resources, to optimize energy production and availability. Vestas will provide a 15-year active output management service for the site.

“By pairing two different generating assets such as solar and wind with energy storage, the system is more reliable and flexible than individual standalone solutions,” Durandal said. “A wind-solar-battery system is more resilient against unforeseeable circumstances such as prolonged cloudy days with poor sunlight or days with low wind speeds.”

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California is on the cusp of a dramatic jump in deploying cost-saving, climate-solving technology in the form of customer-sited energy storage, but the industry needs help cutting red tape that keeps the cost of the technology unnecessarily high for customers.

Energy storage helps electricity customers and the electric grid in many ways: It reduces monthly bills; delivers grid services such as peak reduction, emergency backup and smoothing out the increasing share of renewable energy production; and it enables California to keep the lights on while reaching our clean energy goals.

The state has recently passed a number of policies that could deploy thousands of energy storage projects in the next several years, such as the Self-Generation Incentive Program, storage and renewable energy procurement targets for each of the investor-owned utilities (IOUs), and the AB 2868 authority given to IOUs to accelerate widespread deployment of energy storage.   

But most California cities and counties — less experienced with the new technology and the relevant codes and standards — issue permits for energy storage projects in inconsistent processes with a broad range of permit fees.

Developers spend a great deal of time with repeated travel to deliver materials in person, to submit “wet stamps” on minor revisions of plans, and to complete reviews by unrelated agencies — all of which drive up installation costs for the customer. 

Moreover, local jurisdictions are largely unaware that the storage industry and fire protection professionals have collaborated on a comprehensive forthcoming 2018 standard for energy storage fire safety, the NFPA 855, as well as a wealth of product safety standards.

A new bill to clarify good permitting practices and to make permits and related fees more consistent was signed by Governor Jerry Brown September 30. 

The fact that the bill, AB 546, passed unanimously with bipartisan support shows policymakers’ clear intent to give customers access to this valuable new technology and to arm cities and counties with clear information on how best to permit energy storage projects.

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The residential energy storage market is undergoing a transformation this year.

According to a new report from GTM Research, U.S. Residential Battery Storage Playbook 2017, this year will be the first ever in which grid-tied residential battery storage system deployments outnumber new off-grid and grid-independent systems across the United States.

While data has been difficult to come by due to the nature of the deployments, off-grid and grid-independent backup storage applications have dominated the U.S. residential energy storage market to date. GTM Research estimates that in 2016, over 4,400 residential battery systems were deployed across the U.S., representing 127 megawatt-hours of storage. Of those systems, 86 percent were off-grid or grid-independent backup.

This year, however, we’ll see a major reversal of the trend, says GTM Research. By the end of 2017, grid-connected deployments will make up 57 percent of annual deployments. By 2022, that figure will balloon to 99 percent, as annual off-grid and grid-independent backup deployments will remain relatively flat.